Natural Gas Processing Facility Research Articles

Bench and pilot scale assessment of 5A molecular sieves for tail gas treatment applications

The modified Claus Process stands out as the predominant method for sulfur recovery within natural gas and crude oil processing facilities. Over the past five decades, in a bid to mitigate the environmental consequences of SO2 emissions, the efficiencies of sulfur recovery units have been enhanced through the integration of tail gas treating units (TGTU). Globally, it is imperative that this sulfur recovery efficiency attains a minimum of 99.95%. This paper delves into both bench- and pilot-scale evaluations of utilizing commercial 5 A molecular sieves to extract H2S from specific tail gas streams, as part of scrutinizing the efficacy of a novel tail gas treatment process, delineated in Patent No. US 10662061 B1 (May 26, 2020). The evaluation revealed that employing a 5 A molecular sieve to remove H2S from dry tail gas treating presents distinct advantages. Notably, the CO2 adsorption capacity on 5 A molecular sieves, being several times that of H2S, did not substantially impair the physical stability and removal capacity of 99.95+% tail gas treating, even after 99 adsorption/desorption cycles. Furthermore, the evaluation demonstrated that extended regeneration at 300°C (as opposed to 250°C) following the 50th and 90th cycles could effectively reinstate the original removal capacity of the 5 A molecular sieves. Additionally, the gas emanating from the 5 A molecular sieve bed could be reused as regeneration gas for the second stage of the patented process. The H2S removal capacity of 5 A molecular sieves from dry tail gas, approximately 1.3 mmol/g, aligns with the reported capacities of other adsorbents, which range from 0.37 to 1.53 mmol/g. Given the cost-effectiveness of 5 A molecular sieves compared to AgY molecular sieves, and based on the evaluation outcomes, it is judicious to conclude that the use of 5 A molecular sieves will be a compelling option for future tail gas treating within sulfur recovery units.

Organic Solvent Contamination in Groundwater Around Natural Gas Plants

Alberta is a province that has vast deposits of natural gas. However, in its natural form it is considered sour in that it has impurities, i.e., it contains hydrogen sulphide (H2S), carbonyl sulfide (COS), carbon dioxide (CO2), mercaptans and organic sulphides. To enable the marketing of the natural gas these impurities must be removed using organic compounds and solvents. As a result of spills, leakage during processes, seepage from unlined storage ponds some of these solvents have contaminated groundwater around natural gas processing facilities. Remediation of the organic solvents is a difficult problem. To achieve an understanding of the processes involved in their degradation, a hydrogeochemical assessment of a site can be done using existing data from the site to track the development of groundwater redox zones across the different hydrostratigraphic units (HSU). This is relevant because the oxidation is hypothesized to have contributed to the biodegradation of the compounds. The objective of this global assessment is to assign a groundwater redox zone for each sample, with special emphasis placed on defining the oxidative groundwater zone (OGZ) due to its relevance to biodegradation. Ideally, the oxic groundwater zone would be defined based on the concentration of molecular oxygen (i.e., dissolved ) in groundwater (McMahon and Chapelle 2008). However, molecular oxygen, normally measured as ‘dissolved oxygen’, was not routinely measured as a field parameter in this study and therefore was unavailable to define the OGZ. The scheme adopted considers the concentrations of terminal electron acceptors (TEA) present in groundwater and measured in commonly measured parameters including oxygen, nitrate, and sulphate and dissolved metals (manganese and iron). These TEA's are consumed under progressively more reducing conditions after oxygen reduction is complete in the order: nitrate reduction, manganese reduction, iron reduction, sulphate reduction, and finally carbonate reduction (one form of methanogenesis). The results show that redox zonation is heterogeneously distributed across the site, both within and between HSUs. Multiple lines of hydrogeochemical evidence support buffered aerobic biodegradation at the site.

Subsea Injection Systems Enable Carbon Capture and Sequestration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32460, “Subsea CO2 Injection Systems for CCS Applications: Themes, Challenges, and Opportunities,” by Julian P. Tucker and Kamaldip Randhawa, Baker Hughes. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ The complete paper presents a discussion of challenges and opportunities relating to subsea system design for CO2 injection in carbon capture and storage (CCS) applications. The scope of the text includes field development considerations, systems operation and control, intervention, monitoring, and barrier testing. A global review of existing and planned CCS developments is used to identify common system characteristics and core functional requirements. The paper reviews topics associated with CO2 transportation, injection, and storage across multiple disciplines to provide holistic guidance and commentary specifically for subsea system design relating to CO2 injection for CCS applications. Value Drivers For widespread adoption of CCS, dedicated geologic carbon storage (GCS) must be a commercially viable activity. Simply put, the cost of storage per tonne of CO2 must be less than the price that can be charged for storage as a service. Financial incentives also must be present to support the carbon price for development to take place. Transitional incentives to close the gap between costs and the low value of CO2 emissions reduction also may be required to support development. In all cases, however, the common denominator is that the cost of storage per tonne must be as low as possible. This is driven by the capital expenditure and operating costs of a project (as well as post-injection-period obligations), which include the cost of CO2 transportation and injection systems and associated equipment. Types of Transportation and Storage Networks For dedicated GCS, several types of offshore storage systems are available that are linked to different types of emitters, transportation networks, and value chains. Storage systems linked to natural gas processing facilities may be considered single-point emitters. The overall architecture of these systems, however, will depend on where the CO2-rich production stream is processed and separated before reinjection. The most common method of CO2 transportation to offshore locations is through a subsea pipeline, which enables a continuous flow of CO2 and a high system availability. It is worth mentioning that some developments also have considered transportation to offshore storage sites by ship, with injection through an intermediate floating storage vessel. Once installed, a pipeline provides continuous injection with high availability, whereas a vessel will be affected by transit time, weather conditions, downtime caused by maintenance, and high operating costs owing to fuel use. Furthermore, challenges with field expansion also may result.

Improvement of system reliability in a natural gas processing facility by PSO and DE

Improvement of system reliability in a natural gas processing facility by PSO and DE

Investigation of mechanical, microstructure, and corrosion properties of duplex stainless steel joint for natural gas processing facilities

Duplex stainless steel is an exotic material known for its excellent corrosion resistance and mechanical properties due to the presence of a two-phase structure that is quite balanced between ferrite and austenite, making it one of the top choices for the oil and gas industry. In this paper, we will discuss the process and investigation of the welding results of the A/SA 790 UNS 31803 duplex pipe joint which is connected using the gas tungsten arc welding (GTAW) process for gas purification process applications. The welding process and qualification is based on the ASME BPVC Sec code. IX was then tested to obtain information on the characteristics of the mechanical properties, microstructure, and corrosion resistance of the resulting joints. Heat input in the welding process is a crucial factor that determines the equilibrium of the ferrite and austenite phases which then correlates with the mechanical properties and corrosion resistance of the joint. Based on the microstructural analysis, there was a decrease in the ferrite phase in the weld metal, but it was still within the required limits. Furthermore, the results of the mechanical properties test showed that the tensile strength of the joint was greater than the tensile strength of the base metal and no open discontinuity was observed in the bending test. The corrosion test showed no signs of pitting corrosion with a weight loss value of 1.7 g/m2.

Mercury solubility and its modeling in an artificial natural gas at high pressures

Getting to know of mercury (Hg) behavior will contribute to proper handling and removal of Hg in natural gas processing facilities. Hg solubility was measured in an artificial natural gas, composed of 88.80 vol. % methane, 5.10 vol. % ethane, and 6.10 % vol. % carbon dioxide, by a flow-type apparatus up to 6.031 MPa at (268 to 303) K. The Hg mole fraction ranged from 4.991 × 10–9 to 8.125 × 10–7 in the vapor phase. The Hg solubilities decreased with increasing pressure, and the pressure dependencies were similar to that in pure methane. The experimental data were correlated with the Peng–Robinson equation of state (PR-EOS) developed in the previous studies, where the attractive parameter of Hg was evaluated from the saturated vapor pressure, and binary parameters among the other constituents of the artificial natural gas determined from the VLE data available in the literature. The calculation results were acceptable and agreed with the experimental data without any additional corrections. The maximum and the minimum the absolute relative deviation (ARD) and the average absolute relative deviation (AARD) were 9.72, 0.0542, and 3.20 %, respectively.

Estimating water content of natural gas mixtures considering heavy hydrocarbons contribution using artificial neural networks

The accurate estimation of the water content of natural gas is the basis for proper equipment design in natural gas processing and transmission facilities. Methods for estimating the water content of natural gas have been reported based on pressure and temperature data, and the concentration of acid gases. This work aims to develop a predictive model based on artificial neural networks (ANN) to estimate the water content of natural gas, considering the contribution of heavier hydrocarbons than methane, commonly present in the rich gases, gas condensates, or liquefied petroleum gases. The novelty of the proposed model is the incorporation of natural gas richness (GPM) as an input parameter for calculating the water content of natural gas, in addition to temperature, pressure, and acid gas equivalent content. Experimental data from the literature is used in the ANN training and validation, with the help of the BigML machine learning platform to perform a multi-layer-feedforward neural network. The ANN performance showed the ability to accurately predict the water content for different gas mixtures (rich, lean, sweet, and sour gases). Comparisons with available models in the literature are performed, showing that the ANN model provides accurate estimations (AAD: < 10%).

Natural gas flaring, respiratory health, and distributional effects

Although there is strong evidence that oil and natural gas development lead to decreases in local ambient air quality, there is less evidence of a causal link between these activities and human health. This paper explores the environmental health costs of burning natural gas by-products during crude oil extraction – flaring. We estimate the impact of flared natural gas on respiratory health by using quasi-random variation in upwind flaring generated by the interaction of wind patterns and natural gas processing capacity. Specifically, we construct a novel dataset to estimate the causal effect of increased upwind flaring on the monthly respiratory-related hospital visitation rate by using the number of upwind wells that are connected to a capacity-constrained natural gas processing facility as an instrument for monthly upwind flaring. We find that a 1% increase in the amount of flared natural gas in North Dakota would increase the respiratory-related hospital visitation rate by 0.73%. Furthermore, zip codes that were exposed to more than half of all flared natural gas extracted less than 20% of all resource wealth during the sample time period, and the zip codes exposed to a disproportionate amount of flaring tend to be economically-disadvantaged and communities of color. Our estimates indicate that the health costs constitute a material portion of the external cost of flaring, and therefore ought to be considered in global initiatives to reduce flaring.

Emissions and Air Quality Implications of Upstream and Midstream Oil and Gas Operations in Mexico

Mexico approved amendments to its constitution in December 2013 that initiated transformational changes to its energy sector. This study developed a 2016 bottom-up emissions inventory for volatile organic compounds (VOCs), nitrogen oxides (NOx), sulfur dioxide (SO2), carbon monoxide (CO), and fine particulate matter (PM2.5) from upstream and midstream sector sources, including onshore and offshore well sites, gas flaring, natural gas processing facilities, and natural gas compressor stations, throughout Mexican basins. Crude oil storage tanks at onshore oil well sites and venting and fugitive sources at offshore oil production sites were the primary sources of VOC emissions. Key contributions to NOx, CO, and PM2.5 emissions were from internal combustion engines at offshore oil well sites and midstream operations. SO2 emissions were associated with onshore and offshore gas flaring and boilers and process heaters at natural gas processing facilities. Application of the inventory with the Comprehensive Air Quality Model with Extensions (CAMx) indicated that oil and gas production operations could contribute to ozone and PM2.5 concentrations in Mexican and U.S. states under favorable transport patterns. This study provides a foundation for assessing the implications of Mexico’s future energy policies on emissions and domestic and cross-border air quality and public health.

Development of a small unmanned aircraft system to derive CO&amp;lt;sub&amp;gt;2&amp;lt;/sub&amp;gt; emissions of anthropogenic point sources

Abstract. A reduction of the anthropogenic emissions of CO2 (carbon dioxide) is necessary to stop or slow down man-made climate change. To verify mitigation strategies, a global monitoring system such as the envisaged European Copernicus anthropogenic CO2 monitoring mission (CO2M) is required. Those satellite data are going to be complemented and validated with airborne measurements. Unmanned aerial vehicle (UAV)-based measurements can provide a cost-effective way to contribute to these activities. Here, we present the development of an sUAS (small unmanned aircraft system) to quantify the CO2 emissions of a nearby point source from its downwind mass flux without the need for any ancillary data. Specifically, CO2 is measured by an NDIR (non-dispersive infrared) detector, and the wind speed and direction are measured with a 2-D ultrasonic acoustic resonance anemometer. By means of laboratory measurements and an in-flight validation at the ICOS (Integrated Carbon Observation System) atmospheric station Steinkimmen (STE) near Bremen, Germany, we estimate that the individual CO2 measurements have a precision of 3 ppm and that CO2 enhancements can be determined with an accuracy of 1.3 % or 0.9 ppm, whichever is larger. We introduce an anemometer calibration method to minimize the effect of rotor downwash on the wind measurements. This method derives the fit parameters of a linear calibration model accounting for scaling, rotation, and a potential constant bias. For this purpose, it analyzes wind measurements taken while following a suitable flight pattern and assuming stationary wind conditions. From the calibration and validation experiments, we estimate the single measurement precision of the horizontal wind speed to be 0.40 m s−1 and the accuracy to be 0.33 m s−1. By means of two flights downwind of the ExxonMobil natural gas processing facility in Großenkneten about 40 km west of Bremen, Germany, we demonstrate how the measurements of elevated CO2 concentrations can be used to infer mass fluxes of atmospheric CO2 related to the emissions of the facility.

Alternative and Potential Uses for the Sulfur Byproducts Produced from Oil and Gas Fields

Along with oil and gas operations, huge amounts of sulfur byproducts are produced. For example, in the State of Qatar which has the third largest proven reserves of natural gas, an incredible amount of sulfur is produced as byproduct from its natural gas processing facilities. The amount of produced sulfur surpasses by far the amount that can be utilized currently in the country. Hydrogen sulfide (H2S) existing in natural gas extracted from Qatar’s North Field is converted to elemental sulfur using the conventional Claus process. Managing byproduct sulfur from natural gas processing is a key aspect of economic development and environmental protection in many countries with oil and gas facilities. Therefore, new markets must be found to utilize sulfur to avoid disposal crises. Sulfur byproduct from natural gas can be utilized for various applications. This paper discusses alternative potential uses for sulfur in addition to the current practices of sulfur utilization. Some of these alternative applications of sulfur byproducts include the potential usage for medicinal uses, road construction, batteries, hydrogen production, structural additives, solar energy, waste treatment, arsenite removal, and production of maize.

Plant-wide assessment of high-pressure membrane contactors in natural gas sweetening – Part I: Model development

This paper presents a predictive mathematical model of high-pressure membrane contactor, with a view to developing a plant-wide model of natural gas sweetening including amine regeneration. We build upon an existing model of high-pressure membrane contactor by Quek et al. [Chem Eng Res Des132:1005–1019, 2018], which uses a combination of 1-d and 2-d mass-balance equations to predict the CO2 absorption flux and membrane wetting under lean solvent operation. For the first time, quantitative predictions of the CO2 absorption flux can be made under both lean and semi-lean operations. A 1-d energy balance that accounts for the solvent evaporative losses and the exothermic CO2 absorption into the amine is solved alongside the mass-balance equations, in order to predict the solvent temperature profile inside the contactor. The evaporative losses of water and amines can be quantified separately, as well as the absorptive losses of light hydrocarbons with the amine solvent. The model’s predictive capability is tested against data from a lab-scale module and a pilot-scale module that is operated under industrially relevant conditions at a natural gas processing facility in Malaysia. A close agreement between model predictions and measurements of the CO2 absorption flux, solvent temperature profile, and hydrocarbon loss is observed for a wide range of gas and solvent flowrates and compositions, thereby validating the modeling assumptions. The contactor model is combined in a plant-wide model of natural gas sweetening in the companion paper, where it is used for process integration and analysis.

Plant-wide assessment of high-pressure membrane contactors in natural gas sweetening – Part II: Process analysis

This paper presents a model-based assessment of a natural gas sweetening process combining high-pressure membrane contactor with conventional amine regeneration. The analysis builds on a mathematical model of the membrane contactor developed in the companion paper, which is capable of quantitative predictions of the CO2 and hydrocarbon absorption in the amine solvent and the solvent evaporative losses to the treated gas. The predictive capability of the plant-wide model is tested against data from a pilot plant operated under industrially relevant conditions at a natural gas processing facility in Malaysia, showing a close agreement of the predictions with the CO2 outlet purity and the energy consumption at various CO2 loading in the amine solvent. This enables a model-based analysis of various operational decisions on the plant-wide solvent losses and hydrocarbon recovery from the rich amine. A new semi-lean process configuration that replaces the energy-intensive stripper column by a simple flash separator is shown to reduce the overall energy consumption significantly while still meeting sales gas specification. This new configuration forms the basis for the scale-up of a commercial natural gas sweetening process, which shows a high intensification potential in terms of volume footprint and energy duty compared to conventional amine treating plants.

Modeling impacts of combustion products on humans in complex processing facilities

AbstractHeat radiation, combustion products, and flame engulfment are the main hazards from a fire event. Several reports have indicated that fire toxicity has caused greater numbers of human injuries and fatalities than those of heat radiation and flame engulfment. In a complex facility, the risk of fire toxicity increases significantly due to the difficulty of escaping in cases of emergency rescue and evacuation operations. This study proposes a methodology to model the impact of combustion products on humans. Several fire scenarios were considered to identify credible fire scenarios. In the most credible fire scenario, concentrations of combustion products over the layout of a facility were modeled. The results showed that the concentrations of CO and CO2 are below the short‐term exposure limit and lethal concentration 50 threshold limits at the considered time. The possible reasons for this are that the fire location was in a well‐ventilated area and equipment layouts were designed with proper safety gaps replicating a full‐scale dimension of an operating floating liquefied natural gas processing facility. The concentration of soot is above the threshold limit, and this has the potential to cause adverse health effects. This study can provide a tool for assessing fire toxicity in processing facilities, which will help improve safety measures.

Improving NGL recovery process with dividing-wall column for offshore applications

Fractionation process within natural gas processing facility is an essential step that allows to obtain liquid light hydrocarbons that are often used as feedstocks in petrochemical industries. In this article, a process scenario that includes a heat integrated distillation column is proposed for natural gas liquids (NGL) recovery and assessed through multiscale simulations. Aspen HYSYS software was used to develop steady state process models whose results were used to estimate capital and utility costs. It was noticed that the proposed process has the highest capital cost and lower operating cost which reduces remarkably the total annual cost, this process can also achieve 60 % ethane and 97 % propane recoveries with no additional of external refrigeration. Heat integration, low TAC, separation efficiencies for ethane and propane components, self-refrigeration and more importantly a possibility of operating the process in ethane recovery and ethane rejection modes are the main highlights of the proposed NGL recovery process.

Mercury solubility measurements in natural gas components at high pressure

Saturated vapor pressure of elemental mercury (Hg) and Hg solubility in compressed gaseous methane, ethane, and carbon dioxide were investigated. The apparatus designed for this study was based on a flow method and equipped with a cold vapor atomic absorption survey meter to measure Hg concentration in gas phase. The saturated Hg vapor pressure ranged from 4.579 × 10−2 to 2.757 × 10−1 Pa at 278–298 K. The Hg solubility was measured up to 6.042 MPa for methane, 3.533 MPa for ethane, and 2.070 MPa for carbon dioxide at 268–303 K. The Hg mole fraction ranged from 4.842 × 10−9 to 8.683 × 10−7 in the vapor phase. The Hg solubility decreases with increasing pressure, and the pressure dependencies are similar in the three gases. The activation energy of Hg solubility was determined from the Arrhenius plot at the 1.55 and 3.55 MPa isobars. The activation energy at 1.55 MPa is about 60 kJ/mol·K for the three gases, similar to that at the saturated Hg vapor pressure. At 3.55 MPa the activation energy has the same value for methane but decreases to around 60 kJ/mol·K for ethane. The Peng–Robinson equation of state (PR-EOS) was used to correlate the saturated Hg vapor pressure and the Hg solubility in the vapor phase. The attractive parameter in the PR-EOS was fitted with the saturated Hg vapor pressure, and its temperature dependence was investigated using the van der Waals one-fluid mixing rule. The average absolute deviations were 0.322, 0.265 and 0.197 % for Hg solubility in gaseous methane, ethane and carbon dioxide, respectively. This investigation contributes to predicting mercury partitioning in natural gas processing facilities.

Science & technology issues associated with natural gas production transmission and processing

National priorities for science and technology development in Russia include the transition to green and resource-conscious energy, improving the efficiency of production, and deep conversion raw hydrocarbon materials. Plans to encourage these developments will encourage a harmonious and sustainable research and development sector for the energy industry, and will also encourage that Russian companies participating in the global natural gas market maintain a competitive edge. Gazprom, as the largest transnational energy corporation, will need to cooperate closely with the Russian Academy of Sciences. In 2002, the Gazprom Management Committee and the Presidium of RAS adopted the Basic and Applied Research Program for RAS institutes, which guided research teams of the Academy in completing a package of work focused on the most important development problems in the country’s natural gas production. The R&amp;D Program for Gazprom was updated in 2017 and is focused on the development of energy and industrial infrastructure in Russia. This R&amp;D program forms a pillar that supports emerging technologies and the development and adaptation of innovative products and services for use in natural gas production, transmission, and processing facilities.

Absorption kinetics of mercury (II) chloride into mono-ethylene glycol (MEG) solution

Different mercury species have been found in the oil and gas reservoirs. Dynamic absorption of mercury (II) chloride (HgCl2) into solutions of mono-ethylene glycol (MEG) is reported in this work. It was observed that absorption of HgCl2 into MEG solutions was comparable to the absorption in pure water and the effect on MEG was not seen for MEG concentrations of 2–30 v/v%. The absorption flux was mainly affected by the absorption temperature and the concentration of HgCl2 in the gas phase. Utilisation of several mercury analysis techniques such as flow injection mercury spectroscopy (FIMS), inductively couple plasma-mass spectroscopy (ICP-MS), Fourier-transform infrared spectroscopy (FTIR) and Raman spectroscopy show that no interactions between HgCl2 and MEG were detected for the test parameters studied. The findings from this work helps to improve the knowledge on the behaviour of HgCl2 within natural gas processing facilities, especially during transportation in pipelines and the MEG regeneration process.

A screening-level life cycle greenhouse gas analysis of CO2 enhanced oil recovery with CO2 sourced from the Shute Creek natural gas-processing facility

This life cycle analysis (LCA) evaluates life cycle greenhouse gas (GHG) emissions associated with a system that produces both natural gas and crude oil. Two systems are defined: System 1, which independently produces natural gas and oil, and System 2, which captures carbon dioxide (CO2) from the natural gas-processing plant and utilizes this captured CO2 for enhanced oil recovery (EOR). The LCA uses customized spreadsheet models with emission factors from peer-reviewed literature and publications of the National Energy Technology Laboratory of the U.S. Department of Energy. The modeling results show that the CO2 EOR scenario using captured CO2 produces both natural gas and oil with lower life cycle GHG emissions than alternative systems producing natural gas and oil independently. Sensitivity analyses show that the model results are most sensitive to the fraction of CO2 captured (or equivalently, the fraction of CO2 vented) at the natural gas-processing facility and the incremental oil recovery factor and net CO2 utilization factor of the EOR operations. The input variable driving the relative difference in life cycle GHG emissions between these two systems is the fraction of CO2 captured at the natural gas-processing facility (i.e., the capture rate). The results of this study highlight the necessity of linking processes in the life cycle modeling, as a change to one process can affect other processes within the coupled energy system comprised of natural gas and oil. In addition, this analysis shows, as prior work has also suggested, that CO2 EOR using captured anthropogenic CO2 provides a viable means for offsetting carbon emissions from oil production and combustion via the associated storage of CO2 that occurs incidentally during this tertiary method of oil recovery.

The conflict over the proposed LNG hub in Western Australia’s Kimberley region and the politics of time

In 2013, the Australian oil and gas company, Woodside Petroleum, and its multinational joint venture partners announced that they would not be proceeding with a $40 billion liquefied natural gas (LNG) processing facility on the coast of the Kimberley, north-western Australia. The corporations’ decision was made after a five-year campaign against the gas hub by Indigenous, community and environmental groups. The limited academic literature on this case has focused on particular sets of actors and stages of the conflict. This paper applies a broader perspective by examining the positions of a range of actors over a longer time period. It argues that i) the concept of the politics of time provides a useful lens for understanding the dynamics of the conflict ii) the state attempted to exercise control over the development using temporal strategies, but this facilitated alliances between Indigenous and non-Indigenous people and iii) the state also exercised control over corporate actors, but was ultimately unable to compel investment in an increasingly globalized market featuring new floating LNG technology (FLNG).