The PETRONAS Floating LNG concept was envisaged to monetize stranded gas resources. At the same time, PETRONAS has also exploring the development of Floating Compressed Natural Gas (FCNG) and Floating Gas to Liquids (FGTL) as part of the "Technology Challenge Initiatives". In completing the elements in the overall LNG value chain, an FSRU will also become one of the fast track method to import LNG especially to the non-LNG importer country. The two floaters namely PFLNG1 & PFLNG2 was built by PETRONAS to monetize the gas for offshore Sarawak and Sabah respectively which in turn increased the country's LNG production capacity. As part of the aim to commit to green house or flaring mitigation, PETRONAS is also gearing up towards the evaluations of miniscale Floating CNG vs Floating GTL. On the supply side, the development of Floating Storage Regasification Unit (FSRU) is believed to be an added value to PETRONAS as one of the biggest LNG exporter in the world. The fast track nature of the project presents a challenge to the Gas and Upstream Business in meeting the target date. The advantages of having a floating facilities as a solution to monetize the stranded gas field and mitigating the flaring/venting activities will be covered considering the risk identified throughout the development phases. The important of front end engineering has led to a fit for purpose design and excellent construction methodology. The famous debate with regards to offshore vs onshore gas development will be revisited aligned with the technology maturity and market availability. Speaker will review the new facilities as a viable option in the future for any gas developments requiring a quick solution. Extensive technology selection exercises were conducted in finalizing the turret mooring, gas treating, liquefaction, regasification, cargo containment and offloading systems. Designers and licensors have done rigorous design optimisation and marinization studies on impact of floater motion where it was evaluated against an extensive list of criterias. Specific offshore and marine technology selection for the facilities will be discussed in the effort of realizing the aim to bring conventional gas facilities to offshore environment. Speaker will share the challenges in selecting the right equipments in order to suit the condition including sea state, weather and regulatory requirements.

In 2019, Australia led all Liquified Natural Gas (LNG) exporters in incremental growth ( IGU World LNG report, 2019 ), supported by the start-up of the Wheatstone and Ichthys LNG projects. Production and economic recovery of gas are affected by the association of chemical compounds naturally present at low to trace levels within natural gas such as carbon dioxide, hydrogen sulphide and mercury. These contaminants generate a cascade of costly treatments and waste recovery efforts. If the level of mercury in a produced gas stream is higher than expected, the treatment process in the LNG plant rapidly reaches capacity and may cause shut-down of the facility or rejection of gas supply resulting in significant profitability impacts. There may also be long term consequences that could impact on the decommissioning of industrial infrastructures in the future. High mercury levels in produced gas have been reported in South East Asia and Australia ( Chalkidis et al., 2020 ; Black and Saunders, 2018 ; Zeeshan and Manikandan, 2017 ). However, currently there are no standard method to accurately quantify the presence of mercury in gas in the reservoir. The highly absorbent and multi-speciated nature of mercury makes reliable gas sampling difficult and generally leads to gross under-predictions of quantity. The spatial distribution of mercury within the reservoir means mercury may not appear in the initial production phase and its presence in fluids may vary over the lifetime of the field. Understanding the source, the transport mechanism and the distribution of naturally present contaminants in the subsurface is critical for lowering their impact in industrial activity through avoidance. High mercury levels of about 1000 microgram per cubic meter (µg/Sm 3 ) were reported in reservoir gas samples from a sand unit of the Gorgon gas field in the Northern Carnarvon Basin, Australia ( Chevron Australia, 2014 ). Other gas samples from different depth intervals in the same well delivered readings below 20 µg/Sm 3 . The closest exploration well to GOR-1D (about 2.5 km), North Gorgon-1, has provided abundant core materials that were investigated to detect and understand the distribution of mercury in the rocks. Our research seeks to address some of the significant but remaining geoscientific knowledge gaps on the generation and distribution mechanisms of mercury in rocks, from source to accumulation in the subsurface. In this paper, we provide an assessment of the workflow by examining preliminary analytical results on the detection and quantification of mercury in rocks.

One of the advantages of a floating LNG (floating Liquified Natural Gas) plant compared to an onshore plant is its capability to relocate from one location to another. For better economic opportunity, an existing FLNG plant is relocated to a new offshore location, 450 km away. Several studies are conducted prior to commencement of the relocation. One of them is to evaluate flow assurance issues before, during reconnection to the new facility, commissioning, start-up and subsequent operations. These aspects are evaluated through steady state and transient simulations, in particular to identify major issues that may require additional equipment or significant operational changes to mitigate the consequences arising from conditions at the new location. The main objective of flow assurance study at the initial project stage is to identify and specify Long Lead Items (LLI). Two of the LLI aspects that had to be finalised early are pipeline size and distance between the gas exporting platform and FLNG vessel to meet FLNG's feed gas arrival temperature specification. At design flowrate, it is observed that Joule-Thomson (J-T) cooling resulted in fluid temperature arriving at FLNG riser below ambient temperatures. Parametric studies are also performed for commissioning, black start-up and gas ramp-up, based on operational experience at the first location. Recommended optimum start-up sequence is successfully employed during commissioning and recorded data is found to be comparable with results from simulations. Flow assurance is one of the critical considerations to relocate an FLNG vessel and associated systems to a new location. This paper explains how the study was done and shares the start-up experience for industry's first operational FLNG.

The fluid is seen with the high pressure and low temperature during the CO 2 waterless fracturing operation, which is prone to accidents such as casualties and environmental pollution. In this paper, a complete operation safety management approach and a contingency plan are developed, with respect to the CO 2 waterless fracturing. For the fracturing equipment and support facility, high-pressure-resistant, low-temperature-tolerant specialized wellhead, valve and surface pipeline are required. The pipe wall thickness should exceed the N80 tubing criterion, and the relief line has to be anchor-fixed. In order to prevent suffocation caused by CO 2 , all vehicles and personnel must stay windward. All safety valve outputs should be arranged leeward, facing no personnel operation and equipment placement. Crews must appropriately wear protection that prevents suffocation and cold injury. While operating valves, they should stand beside the valve and operate steadily, so as to avoid object strike induced by the dry ice. The contingency plan corresponding to the operation condition is developed. In the case of CO 2 leakage, the operation should be stopped immediately, personnel will be evacuated to the open area on the windward side, and the air blower at the field should be turned on. As for the occurrence of gaseous CO 2 in the surface process, one has to identify the gasification position in a timely fashion and adjust the vent valve of the blender and the surface pipeline and the wellhead valve correspondingly. If gaseous CO 2 occurs inside the wellbore, the countermeasures of close surveillance, stabilizing pressures by injecting CO 2 at a small rate, and pressure relieving after switching off pumps are implemented, depending on the severity of the case. Upon the arrival of the blender pressure at 2.4 MPa, the safety valve is open for venting. Synergistic pressure relief should be executed by opening the sand-input ball valve, gas valve and liquid valve, if the pressure continues to grow. So far the CO 2 waterless fracturing has been successfully operated for over 20 times, in the tight oil reservoir, shale oil reservoir, low-pressure sensitive gas reservoir, etc. No safety accident has been reported, which demonstrates the rationality and operability of the proposed risk management and control approaches for the CO 2 waterless fracturing.

Floating Liquefied Natural Gas (FLNG) allows for the processing of LNG to be done offshore, hundreds of kilometers away from land. Its versatility enables the unlock the gas reserves in remote and stranded fields that were previously uneconomical to explore, making it possible to monetize those fields far out at sea. In order to fast track the project, an evaluation of the new feed gas composition and modification of both upstream and FLNG facilities was conducted. The identified Long Lead Items (LLI) initiated and studies being conducted in-house to secure the items. An integrated upstream facilities and FLNG team had been established for the execution of the project. In March 2019, the floating LNG unit embarks to fulfill its technological life cycle and was relocated to monetize another stranded field some 450km away from its original location. The overall journey of the relocation took 13 months to complete, right from the inception of the idea to the first drop of LNG in Sabah waters. This paper serves to share Petronas experience in overcoming the challenges of the facility's relocation, starting from selecting the new field until the loading of LNG at the new location.

The floating Gas industry is growing rapidly. As with all sectors in boom times, the focus is firmly on output. We need to ensure safety, compliance and profitability of what are high value, complex assets some of which operate close to high population densities. The speed of growth must be matched by an equivalent effort to maintain asset integrity while continuing production. Put simply, existing inspection and maintenance methods are not fit for purpose. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. The industry needs to operate with high levels of asset integrity, with a programme of continuous improvement and with a long-term planning view. Effective Asset Integrity programmes are a key part of the strategy, and it is widely agreed that better use of data and robotics will help reduce unnecessary work and human risk. The HITS (Hull Inspection Techniques and Strategy) JIP, part of the FPSO Forum, has a membership made up of oil majors, service providers, classification societies and regulators. It has encouraged the development of new technologies, which have significantly improved safety and reduced operational costs. Drawing on experiences of other industries, the HITS JIP has driven innovation; safer, more cost-effective, more efficient technology, which has led to less impact on core operations of floating production assets: these include: The gas industry provided a means of placing nuclear industry miniature cameras into sea chests and isolation valves so that they can be inspected without affecting operations; Hull inspections were improved using deck launched, remotely operated underwater vehicles (ROVs) adapted to carry out cavitation cleaning of sea chest inlet grids, impressed current cathodic protection (ICCP) anodes and points of structural interest, such as bilge keel end connections; The forestry industry provided the idea for chain crawlers for inspection and repair of deep-water moorings; From the Nuclear industry, robotic inspections using high performance cameras, adapted to be inserted through Butterworth hatches or purpose-fitted ports in the deck enabling general and close visual inspection to meet regulatory requirement without the need for confined space entry; To protect the hull, diverless ICCP systems, deploying retractable anodes through the hull; and For pressure systems, using data more effectively; inputting inspection data to confirm fitness for service to an agreed level of confidence. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. It will describe the steps that have already been taken to create an industry wide group including operators, class, regulators and service providers, to agree the primary challenges and to encourage development of solutions in a cost-efficient way. It will describe how innovations developed and proven in the FPSO and other sectors can be successfully introduced to this sector.

This paper will share the experience in the development of an online mercury measurement system for high pressure liquid hydrocarbon streams. It focuses on challenges in handling high pressure volatile hydrocarbon, impurities associated with the matrix, particulates, water and mercury concentration. Challenges associated with assurance in sample representativeness, and validation complete with automation are also discussed. The project was initiated to reduce cost of current offline mercury analysis, the need to minimize analytical error, expedite acquisition of analytical results, and minimize personnel exposure to mercury during manual sampling and analysis. In addition, the determination of mercury in natural gas and condensate is made difficult by the very low concentrations involved, the highly volatile nature of mercury and the complexity of the sample matrix. This dictates that either a highly sensitive detector or a large sample volume or both are needed to perform adequate analysis. A variety of techniques with different sensitivities are presently available for the determination of mercury. The system developed consists of 4 main modules; sample pretreatment, sample capture, sample conditioning and mercury measurement (i.e. detection system). The detection system utilizes a spectroscopic technique for mercury analysis hyphenated with in-house developed liquid hydrocarbon conversion system and sampling system. Results gained from performance testing demonstrate good reliability and opens new prospects to further develop the system for other facilities where mercury monitoring is required, especially for remote facilities.

The Floating LNG 1 (FLNG 1) project is one of the most audacious and risky projects ever undertaken in recent years. Being the first of its kind in the world, it poses a lot of engineering as well as process safety challenges never before encountered in the industry. Issues like integration between top side systems, hull and marine systems, subsea systems and life support system adds complexity to the project. Limited mechanical handling volume, available escape route and having product inventory stored underneath the process units make it exceptionally difficult to manage escalation of potential hazards and to prepare for contingency measures. To mitigate such a high operating risk, pervasive use of sensors and automation is necessary. As a result, the amount of safety sensors and automation systems required are significantly more than the typical numbers required for a facility of similar size built onshore hence the safety and automation systems have to be thoughtfully designed and thoroughly appraised to ensure high safety integrity without jeopardizing the availability of the facility while keeping space and weight requirement of the facilities within tolerance. This paper highlights the specific strategies and approaches taken by the FLNG 1 project team to overcome the challenges associated with the design and engineering of the safety and automation systems since being the first of its kind in the world there was no reference to learn from.

Natural gas produced from many major reservoirs can contain significant amounts of carbon dioxide (CO 2 ) and must be treated to meet typical specifications for pipelines or liquefaction plant feed. The treatment process selected was low temperature CO 2 distillation which involve high pressure operation and formation of highly concentrated CO 2 streams. Pressure protection for high pressure, low temperature and high CO 2 systems have been challenging to date because of potential solid CO 2 formation during pressure let down and the consequent plugging. Blowdown or depressuring of process equipment during an emergency or planned shutdown is a critical process safety operation. It may be necessary in the event of fire, leak, pipe rupture or other hazardous situations, as well as for planned shutdown. Devices such as blowdown valves, relief valves, restriction orifices, rupture disks, and safety valves transfer the potentially hazardous content of process equipment to a safe lower-pressure location or to the flare/vent system for controlled combustion or safe venting. To ensure blowdown will be executed safety and effectively, a number of design concerns must be addressed such as low temperature solid CO 2 identification and Minimum Design Metal Temperature (MDMT) for piping and equipment material selection. Rapid depressurizing and gas expansion can potentially put equipment at risk of brittle fracture if the temperature goes below its ductile-brittle transition temperature of the selected material and potential plugging due to solid CO 2 formation. In addition, the entire pressure relief system including safety valves, relief orifices, flare piping and knockout drums, must be sufficiently sized to handle the flowrates that occur during blowdown, in addition to the piping and capacity of the flare/vent system. Accurate prediction on the minimum vessel wall temperature during blowdown is important for selecting the appropriate construction material, for reducing overdesign and consequently lowering project cost. Similarly, having an accurate prediction of the maximum flow rate during blowdown reduces overdesign associated with the relief valve/network, without compromising on safety. The paper will address the potential of solid CO 2 formation based on proprietary software for blowdown and proposed some mitigation plan with respect to solid CO 2 formation within the process piping and equipment.

Resonant fluid motion between an FLNG vessel and LNG carrier may play a critical role in side-by-side offloading operations in open seas. There have been many studies investigating aspects of gap resonance, a number of which have been focused on wider gaps (e.g. 12 m, 30 m) which may be less relevant to side-by-side offloading operations. In this study, we investigate resonant fluid motion in a narrow gap (i.e. 4 m) which is relevant to a typical side-by-side offloading configuration. Both numerical and wave basin tests are reported, and we consider round and square bilge cases. In the experiments, transient wave groups are used which avoids reflections from wave basin walls. Numerical models based on potential flow theory are developed using linear frequency domain, linear time domain and nonlinear time domain approaches. Unlike the majority of existing studies which have focused on reproduction of response amplitude operators, we attempt to reproduce the experimental time histories. This requires accuracy in simulating both amplitude and phase for each wave component, arguably providing a better guide as to whether the relevant physics has been captured in the models. In this study, vessels with identical shapes except for round and square bilges are investigated, and we find that different levels of damping beyond the radiation damping component are necessary to obtain good fits. The comparison between the numerical simulations and the experimental data reveals the difficulty in re-producing the time history of a resonant response with a combination of different resonant modes.

This paper describes the installation scope for the Chevron-operated Wheatstone Project, including the following items: A number of heavy subsea structures comprised of Pipeline Termination Structures, Subsea Isolation Valves (SSIV) and drill centre manifolds. Fabrication, metrology and installation of a large number of clad tie-in spools of widely varying weight, length, shape and stiffness. Tie-in spools at the Wheatstone Platform (WP) to connect the WP risers to the SSIVs and flowlines (and associated diver-assisted flanged connections). A Dynamically Positioned Heavy Lift Vessel (DPHLV) was used for the subsea structures installation campaign. The DPHLV performed 13 heavy structure lifts in a range of water depths. The maximum structure weight was 527 tonnes (Te). A Heavy Construction Vessel (HCV) was mobilised to perform the deployment of 68 spoolpieces, ranging in size from 4" to 44" internal diameter. A range of spool spreader-beam arrangements was incorporated depending on the spool geometry and weight. The maximum combined spool plus spreader weight was 188Te. The subsea structures were installed within very tight seabed landout tolerances. Such tolerances were achieved using the vessel's Class 2 Dynamic Positioning capability, as well as the calibration of an acoustic seabed survey array which provided the necessary global subsea positioning reference. The spools offshore lifting operation, including multi vessel-interactions, was a technically challenging and weather sensitive activity. Safe and efficient methods were developed for the transfer of personnel from HCV to barge, mooring the barges to the HCV, and tagging the spools during lift off barge. The HCV was also used to tie-in the spools at the drill centres using diverless connection systems. The spools deployed in the vicinity of the Wheatstone Platform were tied-in using a Dive Support Vessel. Pipe handling frames and air bags were operated by the divers to assist flange tie-ins of the stiff and large diameter spools. The structures were installed in seastates up to 1.8m Significant Wave Height, with the governing case for the installations being seabed landout. A high capacity Passive Heave Compensator (PHC) was incorporated into the rigging arrangement to dampen the load during seabed landout, hence allowing landout within the maximum allowable speed. The PHC also ensured that vessel roll was kept to a minimum by allowing for a controlled unloading of the crane, and that there was no structure re-impact with seabed during de-ballasting operations upon seabed landout.

Floating LNG (FLNG) plant is one of the options to monetize remote and marginal gas field. A robust upstream facility design requirement should include flow a assurance assessment in order to achieve stable operations and protect the integrity of the LNG facility. In this case study for a specific FLNG project, flow assurance issues associated with the FLNG receiving dehydrated gas from a processing platform are explained. The aspects include hydrate management, flow stability and location of the pressure control system. For FLNG, the producing wells normally produced as wet gas to the processing facility via a relatively short pipeline. A LNG plant requires constant pressure, flowrates and compositions to operate in a stable manner because most equipment such as refrigerant loops, compressor and distillation columns are sensitive to changes in inlet conditions. Consequently the location of the pressure control valve (PCV) and the impact of transient operations on the dehydrated gas were studies including the effect of the gas dehydration unit offline. For the pipeline, the location of the PCV at the upstream facility and FLNG facility affect the pipeline survival time in term of seconds versus minutes. During normal operating condition, the dehydrated gas poses no major threat to operations as the inlet facility had been designed for, except for low temperature during the initial start-up and the gas turndown requirement during pigging operation. Sensitivity cases indicated that when the dehydration unit is offline, hydrate inhibition is required for shutdown, restart and depressurisation operations. The hydrate inhibition requirement depended on the mode of inhibition required i.e. continuous vs. intermittent or the availability of inhibition for the existing field. An integrated flow assurance study between departing upstream and inlet receiving facilities of FLNG enabled the design of a robust inlet facility suitable for the FLNG process.

An onboard, autonomous power system was required to supply electricity to a floating LNG (FLNG) plant anchored offshore the state of Sarawak in Malaysia. The power system together with its ancillaries were designed to be reliable and robust enough to operate an LNG plant located 180km offshore while sustaining a crew of 140 people. The design of the power system started by estimating the amount of power required by the plant. The distribution of loads was then decided and system voltages were selected. The voltage of power generators was then matched with the selected system voltage either through direct connection or via unit transformers. This resulted in different design options which when combined with a plant constrained by limited space and weight as in the case of FLNG, presented unique design challenges. System studies were carried out together with protection coordination to ensure system stability. The results concluded that the power system will remain stable during a three-phase fault at the highest system voltage. In the event of a total power outage, the electrical system was designed to safely shutdown the plant and then restart it to resume production. The power generation system at the topside was installed on the floater at the dockyard. All electrical systems were tested prior to sail-away. The load-testing of the GTG's at the dockyard would have incurred substantial cost in terms of the fuel, load bank rental and supporting services. After careful consideration, it was decided to carry out the load tests offshore at the production location. The unique design of the electrical system for the Floating LNG plant will provide a reference for future, similar projects. The lessons learned will serve to improve future designs in this niche technology.

The concept of Floating LNG Bunkering Terminal (FLBT) has been developed for offshore bunkering services in Korea. FLBT which has a 220k m 3 storage capacity is under developing, which can receive LNG from LNG carriers or transfer LNG to LNG bunkering shuttles at sea. FLBT is consisted of the hull, the mooring system and equipments including the berthing system, the ship-to-ship transfer system. As the safe LNG transfer operation is the most essential point for this facility, a series of experiments was performed in order to verify the operational safety of LNG loading and unloading operations at ocean environment. The preliminary design includes FLBT hull design, operational site, requirements, side-by-side and turret mooring system, and LNG transfer process. Experiments of ship-to-ship mooring configurations were performed in the ocean engineering basin of Korea Research Institute of Ships and Ocean engineering(KRISO). Experimental results were reviewed with aspect to motion responses of floaters, tensions at the ship-to-ship mooring system, and relative motions between LNG loading arms and corresponding manifolds. In the experiments, the loads on the ship-to-ship mooring system did not exceed their maximum breaking loads, while motion responses of bunkering shuttles were relatively large. The experimental results will be also analyzed in terms of the reliability of ship-to-ship mooring lines and the applicability of a conventional rigid LNG loading arm. Finally, the design will be updated continuously with the conceptual development of FLBT and the feedback from the stability check.

The purpose of this paper is to share the challenges and engineering solutions in managing risk of using nitrogen as the refrigerant in the LNG (Liquefied Natural Gas) liquefaction process on a Floating LNG (FLNG). In December 2016, the first FLNG started to produce LNG 130 km offshore using Nitrogen Liquefaction Technology, which is also the first in the world. Multi-Component Refrigerant (MCR) is commonly used to liquefy natural gas worldwide in the LNG plants. However, the Nitrogen Liquefaction Technology has been selected in view of its inherently safer non-flammable non-corrosive property, simplified process and reduced refrigerant handling and storage onboard. As compared to MCR, the flammable hazard on the FLNG is reduced by adopting nitrogen as refrigerant. Nevertheless, during the course of engineering design, other risk that could potentially be posed by nitrogen was identified. The main concern is the brittle fracture and anoxia risk in the event of cryogenic nitrogen loss of containment. This leads to engineering challenges in terms of the process containment, structural impact, ability to detect, safe disposal and drain and lifesaving appliances, etc. This sharing can be the pioneer reference for other FLNG designs in particular the refrigerant system, the relevant risk management and the engineering solutions.

Objectives/Scope Leak Detection (LD) in critical pipelines and fluid transfer systems is a key requirement for the future of the petroleum industry in terms of assuring the health and safety of personnel, the public, the environment, and assets. For the LNG industry, safe transfer of LNG between production facilities (e.g. FLNG), tankers, and storage systems is essential. Assurance of integrity and safety should be pursued continuously in these systems, and effective LD systems can act as an early warning, allowing for safe mitigation of risk. Methods, Procedures, Process Current pipeline LD systems typically use Computational Pipeline Monitoring techniques. However, these LD systems have limitations in terms of their achievable minimum leak detection threshold and detection timing issues requiring a different approach be developed. One such approach that is attracting much attention is the utilization of Fiber Optic (FO) systems. These may provide lower leak detection thresholds, shorter detection time coupled with extended range detection monitoring of long, e.g. 400+ m flexibles. FO Digital Temperature Sensors (DTS) have already been used for temperature measurements on flexible pipes and pipelines over several kilometers long. In Situ LD systems may possibly allow earlier detection of small leaks that are outside the capability of currently available systems. Being able to detect leaks with a real time LD may be very advantageous. This paper presents recent developments in design, integration, and testing of FO systems, which can provide detection of leaks in offshore pipelines and flexibles. The use of FO sensing for offshore pipeline leak detection is still in its infancy and is emerging for cryogenic flexibles. New LD technologies are being developed for improving not only sensitivity, but, also how to reliably and economically deploy the system in situ in a LNG Flexible. Results, Observations, Conclusions Several FO sensing technologies, including Raman, Brillouin and Fiber Bragg Grating (FBG) are under evaluation for Technip LNG flexibles. A quantitative/qualitative comparison of available FO solutions including deployment considerations in a flexible are discussed and presented in this paper. Novel/Additive Information What else can be done with this system? Other potential uses are to monitor stress or strain along the entire length of the pipe, provide a continuous temperature measurement, flexibles shape, etc. This type of monitoring may be coupled with Computational Fluid Dynamic (CFD) models to improve integrity and safety predictions.

BIG DATA and GAS NETWORK MANAGEMENT: two extremely different terminologies used in the past in extremely different contexts. This paper details the effort and success by Malaysia Petroleum Management (MPM), PETRONAS. This initiative was supported by SAS Institute and Protechnology/Netgas. It is to merge the 2 worlds and handle the current challenges met in the management of complex upstream gas pipeline networks with an innovative and effective solution based on the principles of big data analytics. The starting point was for us to gather the requirement to respond quickly and accurately to demand volatility and changing network operation conditions, while complying with the tripartite commercial agreements between PETRONAS, our natural gas customers and our Petroleum Arrangement Contractors (PACs). A software solution was developed to put the gas flow process, with its fluid- and thermodynamic rules, in the center of the operational process of gas gathering and blending, as well as the management of related commercial transactions and pipeline network operation management. The solution optimizes the volumetric transactions and ensures the delivery quality of the natural gas, supplied from different platforms at different qualities, while ensuring operational controllability with precise operator guidelines. It ensures so the highest operational regularity and planning flexibility. The modular software solution brings a couple of important innovations like dynamic calculus-numerical modeling of a full pipeline network, reverse simulation which optimizes automatically the supply and controls to meet the demand, integration of the commercial volumetric logic with the operational fluid- and thermodynamic, workflow automation and data and information integration. Supporting existing business processes, like planning, scheduling and operational monitoring, the fast staged implementation approach and the ease of use round up the benefits of this innovative solution with low entry barrier.

The LP-ERS process is suitable for implementation on marginal and stranded crude and associated gas producing fields where associated gas is used as fuel and/or flared. Whilst flaring of associated gas is not recommended, in many instances this is unavoidable due to various techno-commercial considerations. Crude and associated gas production facilities typically receive production fluids from wells at relatively low pressures, ranging from 5 barg to 20 barg. At these pressures, there would be significant quantities of C4+ components that can be extracted as condensates and stabilized with the crude. However, conventional enhanced recovery systems currently available are bulky and costly, resulting in these enhanced recovery systems not being implemented for marginal and stranded developments. The LP-ERS is a proprietary process, particularly developed to address the abovementioned issues, to extract condensates (C4+ components) from low pressure associated gas in a cost effective manner, without the need for bulky compression, refrigeration and dehydration facilities that are typically required for conventional enhanced recovery systems. Apart from increasing revenue due to increased volume of stabilized crude production which is generally in the range of 5% to 25% (depending on wellstream fluid GOR, etc.), the implementation of the system will also significantly reduce greenhouse gas emissions (by approximately 20%) and improve the quality of the bulk stabilized crude oil produced.

Every effort has been tried for the reduction of sloshing impact loading to the LNG Cargo Containment System (CCS). And, a new type of floating mat system is recently considered for the further sloshing reduction to mitigate the sloshing impact loading in partial filling of the LNG CCS. In this study, model scale sloshing tests are carried out with partial filled tank heights for the comparison of the reduction effects of a new type of floating mat system on the sloshing induced impact loading, and model scale sloshing simulations, using Multi-Material Arbitrary Lagrangian Eulerian (MMALE) formulation and Fluid-Structure Interaction (FSI) analysis technique of LS-DYNA code. The sloshing response results from model scale sloshing tests are applied to validate the sloshing simulations for the extension of diverse model scale sloshing simulations and full scale ones.

In design process of the LNG (liquefied natural gas) CCS (cargo containment systems), it is very difficult to determine the effects of sloshing impact and the corresponding response of the CCS. The reliable sloshing assessment methods for LNG CCS are important to satisfy the structural strength of the systems. Since compressibility of the sloshing impact may limit the maximum pressure, mixture model of multiphase is required to represent the sloshing physics. A multiphase CFD model has been introduced to simulate the impact of the LNG sloshing by considering the two phases of gas and liquid. The scheme of CFD model is tried based on the Eulerian domain model that employs the CVFEM. It includes the interphase momentum interaction between liquid and gas. For verification of numerical model, sloshing impact in a rectangular insulation box is simulated to compare the sloshing impacts induced by inhomogeneous multiphase model. Also, the numerical model is applied to localized FSI model for strength assessment of LNG CCS.