Liquefied Natural Gas Plant Research Articles

Corrosion resistance in LNG plant design: Engineering lessons for future energy projects

Corrosion resistance is a critical consideration in the design and operation of liquefied natural gas (LNG) plants, where harsh environmental conditions and aggressive chemicals can significantly impact asset integrity and safety. This paper explores engineering lessons learned from past LNG projects, emphasizing the importance of corrosion management strategies to enhance the longevity and reliability of energy infrastructure. The study highlights key factors contributing to corrosion in LNG facilities, including materials selection, environmental exposure, and operational practices. By employing advanced materials such as corrosion-resistant alloys and coatings, engineers can mitigate corrosion risks, leading to reduced maintenance costs and extended equipment lifespan. The paper examines successful case studies where proactive corrosion management has been implemented, showcasing innovative engineering solutions such as cathodic protection, corrosion monitoring systems, and design modifications that enhance resistance to corrosion-related failures. Furthermore, it addresses the role of regular inspections, predictive maintenance, and risk-based approaches in identifying potential corrosion issues before they escalate into significant problems. As LNG plants continue to proliferate globally, the integration of corrosion resistance into design and operational frameworks becomes increasingly vital. This paper also discusses emerging technologies and materials that hold promise for improving corrosion resistance, including nanotechnology and smart coatings that provide real-time monitoring capabilities. By learning from past projects and embracing a proactive approach to corrosion management, future energy projects can enhance safety, reduce operational risks, and achieve greater sustainability in their operations. Ultimately, the lessons derived from this research will contribute to developing best practices for designing and operating LNG plants and other energy facilities, ensuring that they meet the challenges of a rapidly evolving energy landscape.

Value-of-Information Methods Assess Surveillance Data From Fields to LNG Plants

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215318, “Assessing the Value of Reservoir Surveillance Data From Gas Fields Producing to LNG Plants Using Value of Information,” by Daniel I. O’Reilly, SPE, Zhi Qui Xia, and Andrew R. House, Chevron. The paper has not been peer reviewed. _ A set of examples is shared in the complete paper for calculating the value of reservoir surveillance conducted in gas fields tying into liquefied natural gas (LNG) plants. The objective is to use existing value of information (VOI) methods to provide a means of justifying this reservoir surveillance, given that management of operating companies often is more inclined to agree to reservoir surveillance when its value is calculated clearly. Introduction The main objective in supplying gas to an LNG plant is to ensure that sufficient gas feed is available at all time scales (short-, medium-, and long-term). To forecast future gasfield performance, surveillance of producing reservoirs is required. The surveillance data are considered highly valuable by petroleum engineers, but a quantitative value is not always calculated. Oil and gas engineers have considered VOI when gathering field-appraisal information for some time. Many concepts were originally borrowed from the financial industry. Two potential decisions can be identified when deciding on reservoir surveillance in producing fields: what surveillance data to obtain and, if applicable, how frequently the data should be obtained. This may influence the total cost of obtaining the data, along with its reliability. Problem Statement LNG plants normally are designed with a lifespan of several decades, and gas fields must supply at the plant capacity over this period. It is common for different fields to be developed sequentially over the life of the plant. It is crucial that new fields are brought online before producing fields can no longer meet plant demand. In the medium to long term, continuous withdrawal of gas from the reservoir means that its pressure and gas deliverability decline. Initially, gasfield potential is much higher than plant demand, and often this allows for reservoir surveillance at no cost. Many operating companies favor bringing online a new field once minimum excess wellhead capacity is met (i.e., earlier than when gas supply equals plant demand). The offshore gas-rate potential normally is not directly measurable because production is constrained at the maximum rate of the LNG plant; it is a calculated value and subject to uncertainty. Well potential is calculated after the hydraulic performance of the reservoir and wellbore are fully characterized. Reservoir surveillance data are required as inputs to these calculations. In the short term, problems may occur with the near-wellbore formation, well, tree, or subsea infrastructure that could cause reduced flow rates or require the well to be shut in. The likelihood of all production risks can be estimated using reservoir surveillance data. Commonly, reservoir surveillance events are executed during planned or unplanned plant downtime. This avoids a situation in which plant capacity is underused because of a well being shut in for surveillance. However, many situations exist in which surveillance may require an investment or production well downtime. In these cases, an actual cost is incurred that must be evaluated. The objective of the complete paper, therefore, is to use VOI to quantify the value of reservoir surveillance data.

LNG density measurement by gravimetric method

Density is a critical parameter in the liquefied natural gas (LNG) industry, which necessitates the study of measurement methods. Standard methods for calculating LNG density are employed in downstream LNG custody transfer, but it still faces challenges in density measurement in the upstream, such as in LNG plants and LNG refueling station. In this paper, a gravimetric density measurement method was established for LNG plants, which is SI-traceable as it relies on volume and mass. A home-made sampling device was developed and employed to obtain the LNG volume and mass. The principle involves trapping LNG in a known-volume quantitative tube within the sampling device. The LNG is then transferred to a vacuum sampling cylinder and weighed using a mass compactor. This approach not only provides representative samples but also enables compositional analysis while performing density calculations according to ISO 6578. Feasibility and practicality tests of this novel method were conducted in an LNG plant. The test results indicate that the reproducibility is 0.6 %(RSD), and the relative expanded uncertainty is 2.0 % (k = 2). Compared to the revised Klosek and McKinley method (RKM), it shows a relative difference of −0.3 % to 1.5 %, demonstrating the applicability to LNG plants.

Neighbourhood watch: the future of Asian LNG demand growth

The global liquefied natural gas (LNG) market has returned to a semblance of calm after a tumultuous 2022. European and Chinese demand is on the path to a slow recovery, while a nuclear power renaissance is underway in Japan and South Korea. This paper will detail our expectations for LNG demand growth, discuss demand drivers and market development opportunities for Australian LNG between the late 2020s to early 2030s. We see LNG demand in the region increasing from 260 Mtpa in 2023 to 479 Mtpa by 2035. The largest source of growth continues to be China with demand growing from 68 to 150 Mtpa, driven by uptake of LNG in the industrial and buildings sectors. We will also see South Asian demand growing from 33 to 100 Mtpa, and Southeast Asian demand from 24 to 103 Mtpa. Even in legacy markets of Japan and Korea where we see demand declining in this timeframe, we will see the emergence of new buyers and the impact of market liberalisation measures. The expiry of legacy contracts and the rising influence of US LNG is set to complicate market dynamics further. We discuss the challenges of the energy transition in a region that must balance emissions considerations with energy demand. We conclude that Australian projects with their proximate location and legacy relationships will remain an attractive proposition for Asian buyers. Ullage at existing LNG plants will support backfill economics, with decarbonisation measures taken under the Safeguard Mechanism demonstrating genuine emissions reduction action.

Case Study on Decarbonization Strategies for LNG Export Terminals Using Heat and Power from CSP/PV Hybrid Plants

The race towards decarbonization is driving major oil and gas companies to explore means to use renewable heat and power for their plants as part of their commitment to reduce their carbon intensity by 80% to 100% by 2050 [1]. In terms of greenhouse gas (GHG) emissions, natural gas is considered the cleanest fossil fuel option available, and decarbonization of new liquefied natural gas (LNG) projects is on the radar of many LNG projects developers. In addition, LNG cargos will have to be certified in the future by accredited authorities to meet defined GHG emission levels [2].
 This research study investigates a concept of providing both heat and power from a photovoltaic (PV) and concentrated solar power (CSP) solar tower hybrid plant to meet the energy demand of LNG export terminals. Two locations have been investigated for potential future LNG projects: Karratha in Australia and Ras Laffan in Qatar. Both locations have direct normal irradiance (DNI) values higher than 2000 kWh/m2/year, which is the minimum level required for CSP technology [3]. A techno-economic assessment was carried-out taking into consideration the electricity price, the grid carbon intensity and the carbon dioxide (CO2) tax in the region.
 The results indicate that the CSP/PV hybrid plant significantly accelerates the decarbonization of energy supply to the “All electric” LNG Plant. The quantity of CO2 emitted between 2025 and 2050 is reduced by 81% for Karratha (Australia) and by 88% for Ras Laffan (Qatar) compared to a grid connected LNG plant.

A novel approach for optimizing the natural gas liquefaction process

The conversion of natural gas into liquefied natural gas (LNG) requires substantial energy consumption. This study proposes a deterministic mathematical model to find the optimal operation conditions for an LNG plant to minimize the energy consumption for turbomachinery and the total thermal conductance of the heat exchangers. General Algebraic Modeling System (GAMS) linked to a Dynamic Link Library was used to calculate the thermodynamic properties of the working fluids. A derivative-based optimization algorithm is used. Results indicate that the novel optimization approach allows the satisfactory management of the model nonlinearities associated, for example, with the bilinear terms involved in the energy balances and the mathematical functions used to calculate the thermodynamic properties. A preprocessing phase for initializing process variables is developed to facilitate model convergence. In comparison to an optimal design reported in the literature, which was obtained by integrating a well-established evolutionary optimization approach with the Aspen HYSYS simulator, the results indicated that the net electrical power could be reduced by up to 10% when the derivative-based optimization algorithm is used. The proposed deterministic approach, consisting of a mathematical model, an initialization phase, and an optimization algorithm, can help process engineers overcome the challenges associated with LNG process optimization.

Study of the underwater soundscape in coastal waters of Hsinta Power Plant

This study investigates the acoustic environment surrounding the Hsinta power plant, situated in the southwest coastal waters of Taiwan, in proximity to Xingda Port, Yongan Port, Yongan Liquefied Natural Gas Plant, and an artificial reef area via passive acoustics monitoring (PAM) and Automatic Identification System (AIS). Shipping noise (including 45% fishing boats, 20.8% large ships, and 6% tug) generated by inbound and outbound ships significantly affects areas within a range of 2 to 10 km from the study site. Notably, mechanical signals at 60 and 120 Hz, not originating from PAM, have been observed, likely attributed to the Hsinta power plant. Moreover, a distinct series of periodic biological signals within the frequency range of 500 to 800 Hz is consistently recorded near the artificial reef area between 8 p.m. and 10 p.m. Assessing the impact of local ship noise by comparing ambient noise levels below the 100 Hz band before and after the coal shipping seasons (April to September), revealing a difference of 5 to 10 dB. These findings provide valuable insights into the acoustic characteristics of the study area, emphasizing the importance of understanding soundscape dynamics amidst industrial activities and maritime traffic. [Work supported in part by the National Science and Technology Council, Taiwan under Grant NSTC 112-2222-E-130-002-.]

Improving energy efficiency during LNG plant turndown operation

The Karratha Gas Plant (KGP) is one of the most advanced, integrated gas production systems in the world, producing liquefied natural gas (LNG), domestic gas, condensate and liquefied petroleum gas (LPG). The KGP has an export capacity of 16.9 Mtpa, with five LNG processing trains, two domestic gas trains, six condensate stabilisation units and three LPG fractionation units. Following more than 35 years of production from North West Shelf (NWS) fields, the KGP has entered an operating phase where it is more frequently operating in turndown operation. The energy intensity of an LNG production train is often the lowest at maximum production capacity. Should the LNG train become feed gas constrained for extended periods of time, energy intensity increases due to baseload energy required to run the process equipment and physical constraints on equipment turndown. A structured approach has been applied at the KGP to realise improvements in energy intensity in turndown operation through building a strategy, identifying focus areas, energy accounting and benchmarking, data presentation, review and improve cycles, and leadership. The strategy and focus areas are linked to specific actions across different operating timeframes. Review and improve cycles, and leadership help to cultivate an energy efficiency-focused culture and continuous identification of opportunities and barriers to the strategy. Central to all pillars of the strategy is energy accounting, benchmarking and data visualisation which provide value, performance and materiality insights. The benefits can often be realised with limited financial and resource investment, can provide high value return on both emissions performance and reduced fuel consumption.

The Problem of Utilization of Liquefied Natural Gas Vapor at Large-scale LNG Plants

The liquefied natural gas (LNG) is stored under low overpressure in a saturated state in large-capacity tanks with multilayer thermal insulation. Owing to the input of heat from the environment through thermal insulation, LNG is continuously evaporated. Since natural gas is a multicomponent mixture, LNG vapors are enriched with its low-boiling components, then the supply of heat from the environment reduces the amount of liquid in the reservoir and changes its chemical composition. Similar phenomena occur during LNG transportation. The present paper deals with the problem of LNG vapor utilization during its storage and transportation. Information is presented on the causes of the LNG vapor formation (boil-off gas) and methods for its disposal during storage and transportation to consumers. A numerical experiment was performed based on the data of LNG storage in large-capacity storage facilities at the Yamal LNG plant. The technique consists of the estimation of material flows toward the system of accumulation and extradition of LNG. The results show that the vapor flow generated from the inflow of new LNG portions into the storage significantly exceeds that generated from the heat supply from the environment.

Case study on decarbonization strategies for LNG export terminals using heat and power from CSP/PV hybrid plants

The race towards decarbonization is driving major oil and gas companies to explore means to use renewable heat and power for their plants as part of their commitment to reduce their carbon intensity by 80% to 100% by 2050 (Holbrook, 2023). In terms of GHG (Greenhouse Gas) emissions, natural gas is considered the cleanest fossil fuel option available, and decarbonization of new LNG (Liquefied Natural Gas) projects is on the radar of many LNG projects developers. In addition, LNG cargos will have to be certified in the future by accredited authorities to meet defined GHG emission levels (Stern, 2019).This research study investigates a new concept of providing both heat and power from a PV (Photovoltaic) and CSP (Concentrated Solar Power) hybrid plant to meet the energy demand of an LNG export terminal. Two locations have been investigated for potential future LNG projects: Karratha in Australia and Ras Laffan in Qatar. Both locations have DNI values higher than 2000 kWh/m2/year, which is the minimum level required for CSP technology (Lovegrove and Stein, 2021).The LCCA (Levelized Cost of CO2 abatement) was used to compare the various solar configurations to select the option that will bring the greatest amount of CO2 reduction for the same investment cost (CGEP, 2020). The solar configurations technical parameters were defined based on the surface land available, natural gas feed composition and LNG plant design characteristics. The techno-economic assessment was carried-out taking into consideration the electricity price, the grid carbon intensity, and the CO2 tax in the region.Whilst in Australia a collocated single plant is favourable in terms of land availability and DNI (Direct Normal Irradiation) level, in Qatar, heat and power production have been separated into two distinct locations. Next to the LNG plant, a CSP plant provides heat only, whereas 130 km away, the hybrid PV/CSP plant located at Qurain EL Bawl provides electric power.The results indicate that the PV/CSP hybrid plant significantly accelerates the decarbonization of energy supply to the “All electric” LNG Plant. Depending on the solar field size, the quantity of CO2 emitted between 2025 and 2050 is reduced by 78–81% for Karratha (Australia) and by 82–88% for Ras Laffan (Qatar) compared to a grid connected plant.In addition, the economic assessment indicated that buying electricity from the grid during the period 2025–2050 would be more expensive for Australia then investing in a PV/CSP plant. In Qatar, the LCOE range of 93–110 US$/MWh is not competitive with the price of electricity in the region Qatar, mainly because of energy subsidies, however both the carbon tax and electricity price will need to be raised to the same level as in Australia to diversify and expand the power sector in the region.

Synthesis of N2-hydrocarbon refrigerant composition for maximum LNG production in PRICO processes

• Cryogenic technologies mitigate pollutants from NG flaring derived from fracking. • An optimized small LNG plant is a cost-effective approach to NG recovery. • Proposed physics-based approach optimizes LNG plant performance. • Application of thermodynamic principles contributes to accelerated convergence. • The proposed approach selects refrigerant mixture for optimal LNG production. Several technologies are being researched to address the challenges of cryogenic heat transfer in liquefied natural gas (LNG) production. Single mixed refrigerant (SMR) or dual mixed refrigerant (DMR) systems have advantages vs. pure refrigerant-based systems (e.g., cascade or inverted Brayton cycle with nitrogen) due to compact design suitable for small-scale units. However, the selection of mixed refrigerant composition is a challenge. Several methods have been published, typically using heuristic and computational techniques; with power consumption, efficiency, and/or exergy as the figure of merit. This paper presents an alternative approach for the determination of optimum refrigerant mixture composition based on nonlinear thermodynamic equations relating heat exchanger composite curves and mass flow of LNG produced. Three case studies demonstrate the effectiveness of the approach, indicating that single mixed refrigerant systems can be used for cost-effective LNG production while improving LNG production per unit of refrigerant flow rate by as much as 6.5% vs. conventional approaches. The research is applicable to current needs of the gas extraction industry because it helps increase LNG production in small-scale cryogenic systems, thereby enabling economic gas recovery and reducing flaring during fracking operation, as is typical in e.g., the Bakken formation of North Dakota.

Freezing-Based Acid Gas Removal and Its Integration with the Cold Section in an LNG Plant

Natural gas (NG) feed undergoes a series of liquefaction and upgradation processes to produce the final liquefied natural gas (LNG) product that meets customer specifications. LNG processes have a significant capital investment and a high energy requirement, and hence many researchers have focused on process improvement and optimization. While much of the previous research has concentrated on the development of more energy-efficient processes (such as acid gas removal unit (AGRU), liquefaction, natural gas liquid (NGL) recovery, and nitrogen removal), reducing the energy consumption of the whole LNG plant has received little attention. Moreover, the power needs of the LNG plant and LNG product and fuel gas quality constraints remain briefly addressed. The present work proposes an integration between the acid gas freezing unit (FAGRU) with the cold section and suggests multiple structural changes to the cold section. The results showcase that the proposed integration and structural design changes lower the total energy requirement by 16.6% and increase the production rate by 60 kt/a (1.76%). Both these reduce specific energy consumption (SEC) by 17.98%. The feed-to-fuel (FFF) ratio decreases from 6.94% for the base process to 5.7% for the integrated process.

A critical review on the practical use of lithium cycle as an upfront nitrogen removal technology from natural gas

AbstractThe increase in energy demand as the world population grows, as well as the competition in the liquefied natural gas (LNG) market, force producers to work hard on developing cost‐effective production technologies. Upfront nitrogen removal (UNR) before the LNG plant's cold section is considered a promising option to save energy that would otherwise be wasted to cool down a large volume of unused nitrogen in the gas stream. In this study, the use of the lithium cycle (Li‐Cy) as a cost‐effective method for UNR is investigated. The Li‐Cy is compromised of three stages: lithium chemisorption of nitrogen (), hydrolysis of lithium nitride (), and electrowinning (Elec.‐w) of the final product to precipitate lithium metal for further reuse. The relevant chemistry, applicability, economic, and future challenges of Li‐Cy as a UNR technology from natural gas (NG) were explored and discussed. The main challenges that required further investigation to apply Li‐Cy to large‐scale applications were highlighted for future works. The literature review revealed that Li‐Cy can spontaneously remove nitrogen from NG even at low temperatures and produces ammonia as a valuable hydrogen storage material. The used lithium can be regenerated via and Elec.‐w and reused again many times. The cost of the Li‐Cy can be compensated by energy savings, the increase in production rate, and by selling the generated ammonia. Calculations showed that selling the produced ammonia from LNG plants with capacity in the range of 1–5 MTPA would not only offset the costs of Li‐Cy but would generate a net profit of $21MM to $103MM, respectively.

Review of Unconventional Natural Gas Liquefaction Processes

Liquefied natural gas (LNG) has become an important part in the energy industry on account of its high energy density, low carbon emission, and convenient transportation. In recent years, with the discovery of unconventional natural gas resources, the situation of the world’s natural gas liquefaction plants using conventional natural gas as feedstock is changing. Unlike traditional LNG plants, unconventional natural gas liquefaction processes require special considerations in design and manufacturing. This review summarizes and analyzes the characteristics and differences of several typical unconventional natural gas liquefaction processes compared to traditional natural gas liquefaction processes, including coalbed methane liquefaction, synthetic natural gas liquefaction, LNG-FPSO, and PLNG (pressurized liquefied natural gas). Moreover, a state-of-the-art review of the recent progress on design and optimization of unconventional natural gas liquefaction processes is presented.

Stages of development of LNG production and sales

In 1895 Carl von Linde developed the technology for liquefying natural gas, but only in the early twentieth century commercial production of liquefied natural gas was begun. Liquefied natural gas (LNG) is natural gas, primarily methane, that has been artificially liquefi ed by cooling to minus 160 °C for easy storage or transportation. It is a liquid that is colorless and odorless. Pure LNG is not fl ammable, does not ignite or explode on its own. There are several stages of development of LNG production and sales. The fi rst stage (1917–1941) — the first LNG plant was built in the USA. In 1917, an LNG plant was built in the US. The second stage (1959–1969) was the beginning of LNG exports from the US to Europe. The third stage (1969–2020) was the development of the world LNG market. As of early 2010, there were more than 30 large-capacity plants in the world aimed at LNG exports. The fourth stage (2020-present) is the impact of the coronavirus on the world LNG market. Since 2010, global LNG exports have increased from 302.4 billion cubic meters to 487.9 billion cubic meters in 2020. LNG already accounts for more than 40 percent of global gas trade. Leading LNG exporters include Qatar, Australia, the USA, Russia, Malaysia, Nigeria, Trinidad and Tobago, Algeria and Indonesia. Russia accounts for 8 % of global LNG exports. The pandemic situation in the world has caused oil prices to fall and remain low, so suppliers with low costs or high margins are in an advantageous position. Nevertheless, several LNG projects are planned to be launched in the near future, which will allow Russia to become one of the leaders in LNG production. The article outlines the stages of development of LNG production and sales, analyzes the current state of global LNG production, and also lists various LNG projects in Russia.

Study Details Management of Mercury for Production Facilities

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31465, “Management of Mercury Offshore for Onshore Production Facilities,” by Mohamed Sopiee Saaibon, Zainab Kayat, and Fatimah A. Karim, Petronas. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. The objective of the complete paper is to provide an approach to mitigating the adverse effects of mercury found in production fields. It includes an evaluation of treatment-facility requirements and suitable technologies for production fields and facilities. The evaluation covers assessment of pipeline integrity and managing unexpected increases in mercury content to ensure that mercury removal units (MRU) can treat gas within design specifications. Introduction Mercury is present as a contaminant in many oil and gas reservoirs; southeast Asia is a well-known for high concentrations of mercury. The presence of mercury poses a threat to the operator’s integrated upstream value chain. The primary concern is exposure of mercury to downstream aluminum heat exchangers for liquefied natural gas (LNG) production. The production lines and risers, although made of carbon steel, are exposed to integrity threats and, consequently, risk deferment of production. Initial Problem Concerns regarding mercury’s presence in hydrocarbon processing systems arose when substantial liquid mercury was detected at the operator’s downstream onshore LNG plant at levels three times beyond the design of its existing onshore MRU within the plant. Such high mercury concentration in feed gas was not expected because the wells had been operational for only 1 year. Immediate measures taken to handle these high quantities of mercury to protect the plant and its aluminum equipment included the following: - Reduction of feed-gas intake and production slowdown - Closing of wells with high mercury content - Mixing of that gas with low-mercury gas - Preparation for MRU adsorbent changeout No method exists to predict mercury production, and thus mitigation and equipment design—particularly that of an MRU across an integrated oil and gas production system—cannot be based on subsurface production data alone. A holistic approach to determine reservoir mercury concentrations from geology by on onsite sampling and mapping, from the wellhead to the production facility along the pipeline to the plant, was initiated.

Towards time-effective optimization: Enviro-economic study of the C3MR LNG process

Liquefied natural gas (LNG) is an important energy carrier and one of the pillars of secure energy supply in many countries. However, energy requirements and the associated carbon footprint of its production are substantial. This, incombination with the rapidly growing production capacities, calls for efficient process design and operation. Arobustmulti-objective optimization study of a3.5 MTPA propane-precooled mixed-refrigerant (C3MR) LNG plant has been done employing the genetic algorithm (GA/NSGA-II), with 18 process parameters varying in a ±75% interval. The study has been performed in a novel Aspen Plus – Matlab interface for parallel flowsheet simulations which exploits the full computational capacity of a desktop computer. An over seven-fold increase in calculation speed has been achieved, allowing for a significant increase in the GA/NSGA-II population count (up to 1000 individuals) without the computations being excessively time-consuming. To choose the most suitable individual from the 1000 individuals in the final Pareto front, four decision making methods: Euclidean distance, fuzzy non-dimensionalized distance, and two statistical methods have been used and the results have been compared and discussed. As a result, amore than 12% reduction in LNG processing costs and a 14% cut in carbon dioxide emissions was achieved. This roughly translates into approx. 76 mil. USD/year decrease in the total annual processing costs and an over 76 KTPA decrease in the carbon dioxide emissions. In addition, the in-optimization behavior of process parameters was studied. Out of the 18 studied parameters, only six exhibited significant changes throughout theoptimization process while the others converged to a seeming overall optimum already in the first two runs. This implies a possibility of using similar parameter analyses in future optimization studies. Finally, results of the single- and dual-objective optimization were confronted with similar studies in the field and compared between each other. As the single-objective optimization yielded only marginal decrease in the respective objective function while significantly increasing the other one, the dual-objective optimization is favored.

Interfacial tension measurements of methane + propane binary and methane + propane + n-heptane ternary mixtures at low temperatures

The interfacial tension (IFT) between a liquid and a gas is essential in the design of liquid-gas separators as it determines the size of liquid droplets which can become entrained in the gas phase. In liquefied natural gas (LNG) plants, the scrub column is designed to remove components heavier than propane. However, if this column is poorly designed, these heavier components can carry over in the top product and potentially cause a solids formation problem in the main cryogenic heat exchanger. Therefore, accurate measurements and predictions of IFT are required to ensure good separation of heavy components prior to the liquefaction of the natural gas. In this work, reference-quality IFT measurements of methane + propane binary mixtures and methane + propane + n-heptane ternary mixtures were conducted at low temperatures (204 to 230) K and pressures up to the mixtures’ critical points using the differential capillary rise method in a high-pressure visual sapphire cell. The combined standard absolute uncertainties of the measured IFT were between (0.04 and 0.96) mN·m−1. The absolute deviations of measured IFT from values predicted with a Parachor model were within 3 mN⋅m−1, while a Linear Gradient Theory model over predicts mixtures’ IFT by up to 5.2 mN⋅m−1. The reference-quality IFT experimental data provided by this work should facilitate improvements of prediction models and allow separators in LNG plants to be designed with more confidence.

Design and optimization of the sustainable natural gas liquefaction process plant: A process system engineering approach

With the rapid development of the world economy and technologies, the energy demand is increasing. Based on the current regulations energy sectors need low-emission and low-carbon energy solutions. Natural gas (NG) is considered a green future fuel that is usually stored and transported as compressed gas or cryogenic liquid. The liquefied NG has 1/600th of its volume which helps in transportation. Liquefied natural gas (LNG) operations are the most energyintensive techniques. During refrigeration and liquefaction, the units of the LNG consume around ∼40−50% of the entire LNG supply chain energy. To date, the simplest single mixed refrigerant (SMR) cycle-based NG liquefaction plants have exergy efficiencies of around 26.97%. Moreover, the conventional SMR process utilizes a hydrocarbon-based mixed refrigerant (i.e., C1 to C3 and N2) mixture that is further harmful to the ecosystem. In this research work, it was found that the addition of eco-friendly hydro-fluoro-olefin (HFO123yf) with conventionally used refrigerants reduces energy consumption under the same conditions. Further hydraulic turbines were proposed to replace the expansion valves require for the Joule Thompson cooling effect that further increasing the process reversibility and energy efficiency. Hence, this research utilizes the optimization of the HFO based modified mixed refrigerant mixture (HSMR) for optimal operation of the LNG plant. The evaluated result shows that the proposed stochastic biogeography-based optimization (BBO) algorithm successfully reduces the overall energy consumption by 0.232 kW/kg-NG. This energy consumption is about 41.709 % compared to our base case study and it was 36% more efficient compared to the conventional SMR published study. This research further explores the sensitive decision variables that affect power consumption using the sensitivity analysis index method. The sensitivity indices may enable us to operate the plant in any abrupt changing or uncertain conditions when needed quick optimization using only a few key sensitive optimizing variables which are useful for real-time plant optimization. Moreover, the economic analysis of the proposed plant shows a total annualized cost of 6,158,000 USD with a 20% rate of return, per year.

THE FEASIBILITY OF MICRO-CRYOGENIC TECHNOLOGY APPLICATION FOR ENHANCING DOMESTIC NATURAL GAS UTILIZATION, CASE STUDY : NATURAL GAS PROVISION AT R & D CENTRE FOR OIL AND GAS TECHNOLOGY "LEMIGAS"

Indonesia with a huge natural gas reserves distributed in various islands and separated by sea has utilized the gas for domestic energy source and petrochemical feedstock purposes. Transportation of the gas to its consumers can be in the form of either pipeline gas or Liquefied Natural Gas (LNG) schemes. Selection of the scheme chosen is determined based on its economic evaluation and technical reliability. The distribution of gas reserves in various islands segmented by sea in Indonesia in combination with economic activity concentration especially in Java island bring about difficulties in gas development due to the up-front massive investment required on gas pipe laying or LNG plant construction. It is therefore required to find a cheaper alternative to the scheme with an established safety standard application, in order that the domestic gas utilization will be able to be enhanced and thus reducing petroleum liquid import. An alternative that can be significantly considered is micro-cryogenic technology development in Indonesia for constructing a low capacity LNG plant so that a small scule of LNG can be economically produced. The LNG is then distributed to gas consumers at regions which has no existing and will not be viable for new gas network installation. Micro-cryogenic technology application is thought to be developed considering a preliminary feasibility study results. The study found that micro-cryogenic technology is around US$ 0,75 million (68,2%) cheaper than gas pipeline technology to provide natural gas for Gas Demonstration Plant operation at R D Centre for Oil and Gas Technology "Lemigas"