Floating Compressed-Natural-Gas System Provides Simpler Path to Monetization

Liquefied natural gas (LNG) and offshore activities have much in common. - The ultimate goal of each is to produce and deliver hydrocarbons to the market. - The main oil operators are active in LNG as well as other offshore activities (e.g., ExxonMobil, Shell, BP, Total, and ChevronTexaco). - Production is transported over long distances by carriers (even if LNG carriers are far more sophisticated than oil tankers!). But, until now, LNG production plants have always been built onshore, even when gas is produced offshore (e.g., Qatar, Trinidad, and Sakhalin). The first concepts of LNG floating production, storage, and offloading (FPSO) vessels were presented by the industry in the mid-1970s. These concepts were targeting stand-alone gasfield developments or associated gas fields. Even if an LNG FPSO appears economically very attractive when compared with a “grass roots” onshore LNG plant, the operators seem not to have found the proper location or the correct “scheme” to select an LNG FPSO for developing an offshore gas field. At the other end of the LNG chain, huge investments also are foreseen to build facilities for the reception and regasification of LNG to cope with a fast-growing demand for gas. Many terminals are under construction or planned in many countries. This increased demand is not without obstacles. In some areas of North America or Europe (Italy for example), environmental constraints prevent the installation of newly built, land-based LNG terminals. As a result, the projects are moving offshore, taking the shape of fixed, gravity-based structures or floating storage and regasification units. In this offshore move of the LNG industry—“tomorrow” for the receiving terminals and the “day after tomorrow” for LNG FPSOs—those who combine LNG and offshore expertise will be key players in this new arena. Additional Offshore Facilities Construction and Design Technical Papers Available at the SPE eLibrary: www.spe.org SPE 89998 - Subsea HIPPS: A Way To Develop High-Pressure Subsea Fields Available at the OTC Library: www.otcnet.org OTC 16106 - Monitoring of Sand Deposition in Subsea Separators OTC 16185 - High-Strength Aluminum Alloys for Deepwater Riser Applications

Production of LNG directly at offshore oil and gas fields has potential to unlock significant resources at deepwater locations. This paper summarises Shell's ongoing technology developments aimed at practical, safe and economic floating production systems to deliver oil/condensate and LNG from the same unit. The key technical building blocks and their development status are discussed, and the solution for oil fields and gas fields compared. Prospects for application of the two concepts are introduced. Background The Deepwater Challenge. The world's oil and gas industry is facing significant challenges in the deepwater offshore hydrocarbon basins. Some 85% of deepwater discoveries in basins outside the Gulf of Mexico are smaller than 500 million barrels (bbl) and many are currently uneconomic to develop. Of the larger field sizes, a significant proportion consists of non-associated gas reservoirs in locations remote from pipeline infrastructure and gas markets. The Associated Gas Problem. Most remote deepwater oil discoveries rely on a technically achievable and cost effective gas disposal solution to make oil production economically viable. Frequently such nuisance gas is reinjected. However, in many cases, gas injection is detrimental to reservoir performance and Shell has reviewed the technical and commercial feasibility of numerous possibilities in its search for a new stand-alone associated gas disposal solution. By a considerable margin, the Liquid Natural Gas (LNG) solution has been shown to be the best from both a costs and operability perspective. The development concept for oil fields with associated gas liquefaction, LNG storage and export is called FONG (Floating Oil and Natural Gas). Production of both oil and LNG products from one single production unit increases the total product sales value and subsequently reduces the economic threshold for development. The critical success factor has been to keep the processing, product storage and export innovatively simple. The Non-Associated Gas Opportunity. For non-associated gas, production of LNG directly at the field should provide a lower cost development solution than the alternative of long distance (100-500 km) transport to an onshore gas/LNG plant. In the mid-nineties (1996), Shell initiated studies on the possibility to place a gas liquefaction plant on a floating barge. These studies confirmed that the concept was technically feasible, but required upscaling from 2 to 4 million tones per annum (mtpa) capacity to become economically attractive. The development concept for gas fields is called FLNG (Floating Liquid Natural Gas), and it is in the project development stage in both West Africa and Australia. This paper describes the development of FONG and FLNG and specifically addresses some of the unique features which give Shell the confidence to progress Front-End Engineering Design (FEED) studies. Common Technical Challenges Both FLNG and FONG technologies build on existing production experience with onshore LNG plants, LNG Shipping and offshore FPSO (Floating Production, Storage and Offloading) installations (Figure 1). This is however, not without challenge as one cannot simply build an onshore LNG plant on a barge, or just add LNG facilities to an FPSO unit.

While liquefied natural gas (LNG) is the dominant technology for marine transport of natural gas, compressed natural gas (CNG) is an economically attractive alternative for transportation of relatively small amounts of natural gas over shortdistances (up to 6 Bcm/year transported over 2000 km, respectively). Because the main capital expenditure in a CNG project is on marine transport vessels, careful design of CNG transport fleets and compatible distribution schedules is important. Design through solution of an all-encompassing optimization problem would be desirable but complicated and intuitive unappealing. In this work, a structured optimization framework is applied to potential marine CNG transport from a source in the Trinidad/Venezuela area to island countries in the Caribbean. Two general patterns emerge in the results: A "hub-andspoke" pattern for servicing of the largest four consumption markets (Puerto Rico, Dominican Republic, Jamaica, and The Bahamas) and a cyclical "milk-run" pattern for the remaining (smaller) markets. Introduction The role of natural gas as a fuel is slated to increase dramatically in the coming decades, owing to the efficiency and environmental friendliness of natural gas in comparison to other fuels. However, transportation of natural gas from points of production to consumption markets remains a challenge. Two well established gas transportation technologies currently dominate the market: Pipeline and liquefied natural gas (LNG) accounting for 70 and 30 percent of transported gas, respectively. Pipelines generally offer the most economically attractive solution and are the preferred choice whenever feasible, such as for land transport. Subsea pipelines are restricted by the distance and terrain they can traverse. As a result, transport of natural gas by sea vessels is favored for transport over long distances spanning sea water. While LNG is currently the dominant technology used for sea transport of natural gas, a number of recent studies have shown that compressed natural gas (CNG) is economically more attractive than LNG for sea transport of relatively small volumes of natural gas over small distances (Marongiu-Porcu, et al., 2008, Wang and Marongiu-Porcu, 2008). In comparison to LNG, which requires costly liquefaction and regasification facilities at the shipping and receiving sites, respectively and is energyintensive, CNG requires minimal investment in facilities at the shipping and receiving sites and uses less energy. The main capital cost for CNG is incurred for transportation vessels. Although the cost for transportation vessels is higher for CNG than for LNG (stemming from corresponding gas compression ratios of 300:1 vs. 600:1, respectively), overall economics favor CNG for short distances and small loads, as summarized in Figure 1. Finally, because the demands for the entire chain of operations to be well coordinated and in place are easier to meet for CNG (compression / transportation / distribution) than for LNG (liquefaction/transportation/regasification), the former provides an additional degree of flexibility that is welcome in situations of changing market conditions. Even though CNG is used widely in land applications (buses, passenger cars) and a proof-of-concept for sea transport of CNG has existed since the 1960s (Broeker, 1969), CNG has yet to make inroads into the transportation market for natural gas. Three factors have contributed towards that. First, investment emphasis internationally has been primarily on LNG, for understandable reasons (see Figure 1). Second, CNG vessel designs and projects have been envisioned to eke a bite out of the LNG pie, which is not necessarily a good approach. Third, innovative CNG vessel designs for low cost and high efficiency have become available only in recent years. There are certainly several regions worldwide whose energy needs, geography, and access to natural gas sources would make them good candidates for application of CNG sea transportation (Figure 2). For each of these regions there exist multiple scenarios for CNG distribution, in terms of number of vessels, vessel capacities, and itineraries. Identification of promising scenarios is necessary to determine project economics and possibly guide future technological developments.

While Indonesia has traditionally been a major exporter of liquid natural gas (LNG) to Japan, Korea, Taiwan and China, compressed natural gas (CNG) should be seriously considered, especially for the transportation of fuel within the Indonesian archipelago itself. CNG is an alternative that has been proposed in recent years but has yet to be implemented on a large scale because the emphasis for investments has primarily been on LNG and because CNG applications have not been well delineated. Some people still believe that LNG and CNG are competitors. They are not. The key is to find the areas, both geographic and volumetric, of least-overlapping applications. It has often been stated that CNG is more attractive for shorter distances and smaller offshore markets which are not connected to pipelines or large LNG accepting facilities. For short distances, less than1000 km, LNG cannot compete with CNG for any volume of gas. Even at longer distances (e.g., 2,000 km), until the recent collapse of gas prices, CNG is still more attractive at volumes of up to 10 Bcm/yr (or 350 Bcf/yr), assuming that offshore pipelines are not economically or physically feasible. For smaller volumes, such as 1 to 2 Bcm/yr, and long distances, CNG is the only solution to bring natural gas to many markets. We have also found that higher prices of natural gas, either at the source (cost) or at the destination (sale price), increase the volume of gas at which CNG is more attractive than LNG. Indonesia is an obvious place for such applications and we present cases for the transportation of natural gas as CNG from Borneo and Sumatra to Java and Bali. We quantify the volumes of gas that delineate CNG's superiority and show the impact of gas prices on the indicated gas volumes to be transported.

Governments and Operators are researching the potential for the development of floating liquefied natural gas (LNG) production facilities as a means to monetize gas reserves and to eliminate flaring of natural gas associated with oil extraction. Floating Production Storage and Offtake (FPSO) vessel hulls may be constructed in either steel or concrete. Concrete hull structures offer a number of advantages for the support of cryogenic facilities and the storage of produced liquids. Additionally, concrete substructures may be constructed in country using a significant proportion of locally procured materials and labor. A concrete FPSO solution has been developed to support a two LNG train facility. The concrete hull may be configured to be much larger than traditional steel FPSO alternatives and need not limit the liquid storage volume or deck area. The proposed solution has sufficient deck area to allow the topside facilities to be configured with some modularization and preassembly using vendor supplied skids. Cryogenic liquid containment requirements have been reviewed for the offshore storage. It is concluded that "double" liquid containment should be adopted rather than the "partial double" containment typical of LNG carrier ships. The adoption of the double containment design criteria has implications for the alternate storage systems, membrane or prismatic self-supporting tanks. It is accepted that the membrane system can be shown to be double containment and is well suited to a concrete FPSO application. The prismatic self-supporting tankage system requires further development, but could also be used. Concrete hull vessels can be shown to be durable and stable. The proposed CFPSO arrangement has a wide beam that ensures superior stability and low motions in extreme environmental conditions. The proposed CFPSO construction could be carried out in country and has been shown to be feasible for several locations. Indicative costs are provided, which are competitive with other alternatives, especially on a life cycle evaluation. The 9MMTPA LNG production CFPSO may be completed within 43 months of EPIC contract signing. Introduction Governments and offshore oil and gas field operators are researching means by which natural gas from associated and stranded gas fields may be monetized. In addition, governments are legislating to limit or prohibit the flaring of gas associated with oil production. The result is an increasing interest in the development of offshore gas liquefaction installations, in particular the development of floating liquefied natural gas (LNG) production facilities. The primary focus of floating LNG proposals has beendirected toward steel hulled floating, production storage and offtake (FPSO) vessels. Steel hulled FPSOs may be procured from established shipyards and fitted out at an offshore fabrication and assembly facility. Established fabrication and assembly facilities are located in East Asia, Northern Europe and North America. Construction of the hull and topside facilities in a shipyard offers a number of benefits including contractor competition at bid stage. However, shipyards generally do not have the dock facilities to construct large concrete substructures. An alternative procurement strategy that incorporates local construction in purpose built graving docks is better suited to both the concrete substructure option and a procurement strategy that seeks to assemble the production facility locally..

Introduction Floating Pipeline Company Incorporated (FPC Inc), a Canadian Corporation based in Halifax, Nova Scotia, is the licensed manufacturer for TransCanada Pipelines' Gas Transportation Modules (GTMs) used for the volume transport of Compressed Natural Gas (CNG). Compressed Natural Gas can be used economically in the niche market for stranded gas. "Stranded gas" is any gas that cannot today be economically brought to market using conventional pipeline or liquefied natural gas (LNG) technology. It is pplicable to areas where companies are not willing to invest heavily in infrastructure, or in areas where physical limitations inhibit bringing the gas ashore. Approximately 50% of the world's discoveries and expected discoveries fall into the "stranded gas" category. Transporting CNG in GTMs to niche markets can offer substantial price advantages over conventional energy sources such as electricity, propane, and diesel fuels, which are the only alternatives today. Studies carried out for the offshore fields alone indicate conservatively that the potential market for this technology could be as large as 50+ projects over the next 20 years, with clients including all the major oil and gas companies, and companies in the transportation and delivery of gas. Moving natural gas from the well to market is normally achieved by pipeline (as gas) or ships (as LNG). Several other methods are being investigated to improve the economics of transport, namely CNG, gas to liquids (GTL), and variations of these. CNG transportation has been shown to be economical in a number of specific niche situations. Moving ‘stranded gas’ as CNG can be shown to be economically attractive, for distances of less than 1,500 miles, where it is either politically restricted, physically impossible, or where the volumes are too small to justify laying a pipeline or building an LNG facility, This niche market is not limited to sea transport. It also presents significant opportunities on land through road trailers. TransCanada CNG Technology Limited (TCCNGTL) has the worldwide licence to a patented technology that enables sufficient quantities of gas to be transported under pressure economically for projects that fit the above niche markets. This technology " composite spiral wrapped, thin walled steel pressure vessels " was approved by ASME in October 2002, which now enables its use in the applications identified. Approval in Principle for the use of GTMs in ships was granted by Lloyds Registry of Shipping in September 2003. FPC Inc. along with its UK engineering partner, WaveSpec (a wholly owned subsidiary of BraemarSeascope, London) provided the engineering services for the submission to Lloyds on behalf of TCPL. More recently, FPC/TCPL/OSG and Rolls Royce have been working with Lloyds Register for the full approval of the ship for a project in East Africa. This is expected to be complete within the 2nd Quarter 2007. FPC recognizes the potential of this technology and:Is marketing and developing contracts for the transport of CNG worldwide utilizing this technology;Has established a manufacturing facility in New Brunswick, Canada to fabricate, under license, the GTMs;Plans to sell GTMs to third party project developers;

Natural gas (NG) liquefaction and compression are energy intensive processes which make up a significant portion of the overall delivered price of liquefied NG (LNG) and compressed NG (CNG). Increases in system efficiency and/or process changes which reduce the required amount of work will improve the overall economics of NG as a vehicle fuel. This paper describes a method of reducing the delivered cost of LNG by liquefying the gas above ambient pressures. Higher pressure LNG is desirable because OEM NG engine manufacturers would like NG delivered to the engine intake manifold at elevated pressures to avoid compromising engine performance. Producing LNG at higher pressures reduces the amount of work required for liquefaction but it is only practical when the LNG is liquefied on-site. Using a thermo-economic approach, it is shown that NG fuel costs can be reduced by as much as 10% when producing LNG at higher pressures. A reduction in the delivered cost is also demonstrated for CNG produced on-site from high pressure LNG.

Prelude Floating Liquefied Natural Gas (FLNG) facility reached a significant milestone in June 2018 when gas was introduced onboard for the first time as part of the facility startup process, loaded from an LNG carrier moored in side-by-side (SBS) configuration. This first offshore LNG SBS operation allowed Prelude’s utilities to switch from running on diesel to running on gas. SBS mooring is the base case configuration for of floading both LNG and Liquefied Petroleum Gas (LPG) into product carriers using Marine Loading Arms (MLA) once the Prelude FLNG facility is fully operational. These complex and weather sensitive operations are expected to take place on a weekly basis. This means critical decisions about weather-window and timing should be supported as much as possible by predictive analysis and modelling of environment forecasts to reduce the risks. Prelude Floating Liquefied Natural Gas (FLNG) is designed to offload Liquefied Natural Gas (LNG) and Liquefied Petroleum Gas (LPG) to carrier vessels moored in a side-by-side (SBS) configuration, using Marine Loading Arms (MLA) technology. For onshore terminals or small/medium FLNG, the traditional design of MLA (Double Counterweight Marine Arm – DCMA), featuring a vertical riser, can be used. However due to the exceptional freeboard of Prelude a new type of MLA was designed, namely the Offshore Loading Arm Footless (OLAF), without vertical riser in order to reach the LNG or LPG manifolds located as far as about 16 meters below the MLA base. Thanks to the OLAF design, the length and weight of the articulated MLA sections is reduced in comparison with conventional DCMA, and so are the dynamic loads applied by the MLA on the vessel manifold, which was mandatory to remain below the acceptable stress limit of standard LNG/LPG carrier manifolds. OLAF employs the field proven targeting system (TS) allowing the connection and disconnection of the MLA to the vessel manifold in dynamic conditions. This paper describes the assumptions and process to design and validate this new system — in terms of overall geometry and structural design, while verifying project feasibility, aiming at a reliable design of all components and minimizing the risks during operations. The key challenges and lessons learnt are also discussed. This innovative type of MLA had to be thoroughly designed and tested before being manufactured and assembled on the FLNG. The innovation management was also coupled with the additional challenge imposed by the expected highly dynamic conditions of relative motion between vessels that were never encountered for such systems in the past. MLA were designed with the objective to cover the operable envelope induced by berthing, mooring and relative motion criteria, so that it should not become an additional criterion in general. Since such an envelope is larger for this offshore application compared to sheltered terminals, this objective was particularly challenging but could be met thanks to the OLAF design. The SBS hydrodynamic numerical model is based on potential theory and includes multi-body coupling, non-linear mooring characteristics and coupling with sloshing. This model was calibrated using wave basin tests with a good agreement, and was used to determine the maximum operable environments and associated MLA envelope, using a 39-year hindcast for various LNG carriers and considering a scenario with different criteria and loading conditions. More than 100,000 time-domain simulations were required to evaluate non-linear quantities on a reduced set of environment ‘bins’. The new OLAF-type MLA was developed using these hydrodynamic simulations. Specific processes — based on spectral screening and selection using relevant criteria — were used to identify and select, in a systematic way, the designing load cases for connecting, connected, and emergency disconnection cases, while complying with the maximum allowable loads of conventional LNG and LPG carrier manifolds. An instrumented 1:4 OLAF scale model was built and tested with 6 degrees of freedom hexapods reproducing the motions on both sides of the OLAF which enabled us to confirm a 10% accuracy of the numerical studies results. The actual OLAF were dynamically tested with a full scale motion simulator before shipment to the yard for installation. The successful first operations were performed safely and confirmed the validity of the design. Measurements are now collected onboard Prelude to verify the design and when possible improve the accuracy of numerical modelling.

Commercialization of the world's natural-gas resources continues to be a leading industry initiative as natural gas remains the fastest-growing resource addition to global energy supplies and we continue to embrace clean-energy initiatives. Natural-gas reserves on a global basis exceed 5,000 Tcf (Apanel 2005). Gas will increase its share of the world's energy supply in the coming decades. ExxonMobil expects natural gas to account for 25% of the world's total energy needs by 2030 (Donnelly 2005). Shell forecasts that natural-gas demand will grow 3% per year over the next 15 years and that demand for liquefied natural gas (LNG) will grow 8 to 10%/yr (Donnelly and Denney 2005). As gas globalization progresses, a variety of transportation and utilization methods will be needed for exploitation of remote natural-gas resources. Pipelines will continue to dominate gas transportation, but other technologies will be required to overcome ever-increasing distances between production centers and markets, overcome geopolitical barriers, and facilitate gas development from offshore developments. LNG, compressed-natural-gas (CNG), and gas-to-liquid (GTL) technologies will grow in importance as transportation and use options. LNG will continue to be the dominant technology, with CNG and GTL finding niches within the global transportation and use infrastructure. Technical advancements in LNG, CNG, and GTL continue to outpace their commercialization. Clearly, technology will not be a limiting factor in the globalization of natural gas. The papers featured this month highlight some of the technical innovations in applying LNG and CNG to offshore gas development. As exploration and development moves into deeper waters and more-remote offshore frontiers, LNG and CNG technologies will provide developers with options in transporting gas to distant markets. GTL technology will be available in selected applications to use otherwise stranded gas and supply environmentally friendly fuels to both developed and emerging economies. Ultimately, GTL will move offshore, analogous to the evolution of LNG and CNG. The key will be to make further advancements in reducing plant complexity, size, and weight. For readers desiring a broader view of technological developments in natural-gas production, transportation, and use, I recommend the additional-reading papers. References Apanel, G. 2005. GTL Update. Paper SPE 93580 prepared for the 14th SPE Middle East Oil & Gas Show and Conference, Bahrain, 12–15 March. Donnelly, J. 2005. The Gas Age. JPT 57(12): 14. Donnelly, J., and Denney, D. 2005. ATCE Sessions Tackle Contemporary Challenges Facing the Industry. JPT, 57(12): 30. Natural Gas Technology/Monetization additional reading available at the SPE eLibrary: www.spe.org SPE 96037 "Downhole Pressure Boosting in Natural-Gas Wells: Well-Candidate Selection and Project Progress," by J.E.N. Liley, Corac Group plc. SPE 95655 "Analysis of Gas-Cycling Performance in Gas/Condensate Reservoirs Using Neurosimulation," by L.F. Ayala, SPE, Pennsylvania State U., et al. SPE 97627 "An Inflow-Performance Relationship for Horizontal Gas Wells," by N. Akhimiona, SPE, Chevron, et al. SPE 95531 "Assessing Producibility of a Region's Gas/Condensate Reservoirs," by C.S. Kabir, SPE, Chevron, et al.

Global carbon emissions are driving the maritime industry toward cleaner fuels, with LNG already established as a transitional option that reduces SOx, NOx, and particulate emissions relative to conventional marine fuels and in line with decarbonisation strategies. This research aimed to explore the transition of offshore and marine platforms from conventional marine fuels to cleaner alternatives, with liquefied natural gas (LNG) emerging as the principal transitional fuel. Subsequently, floating liquefied natural gas (FLNG) platforms are increasingly being deployed to harness offshore gas resources, yet they face critical challenges related to weight, space, and energy efficiency. The study proposes pathways for transitioning FLNG energy systems from LNG to zero-carbon fuels, such as hydrogen derived directly from LNG resources, to optimise fuel supply under the unique operational constraints of FLNG units. The work unifies the independent domains of pure-fuel and blending-fuel processes for LNG and hydrogen, viewed in the context of thermodynamic processes, to optimise hydrogen–LNG co-firing gas turbine performance and meet the base power line of 50 MW. Furthermore, the research article will contribute to the development of other floating production platforms, such as FPSOs and FSRUs. It will be committed to clean energy policies that mandate support for green alternatives to hydrocarbon fuels.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23261, ’Development of CO2-Tolerant LNG-Production System,’ by JungHan Lee, Jeheon Jung, and Kyeongmin Kim, SPE, Daewoo Shipbuilding and Marine Engineering, prepared for the 2012 Offshore Technology Conference, Houston, 20 April-3 May. The paper has not been peer reviewed. During natural gas liquefaction, CO2 must be removed to prevent icing and plugging in the system. The CO2-removal system may be the most important part of the gas-treatment system. CO2 removal systems require complicated amine contactor and regeneration systems with substantial heat sources. The CO2-tolerant natural-gas-liquefaction system called cluster liquefaction accepts approximately 1% of CO2 for the liquefaction and related systems. The CO2-tolerant characteristics of this liquefaction process will provide a multifold safety margin against CO2 problems in cryogenic systems and valves. CO2-Tolerant Liquefied-Natural-Gas (LNG) Production System Considerations. Natural gas liquefaction at higher pressures and equivalent higher liquefaction temperatures has the advantages of reducing liquefaction energy and adopting more-efficient refrigerant. Despite the advantages, the higher-pressure storage requirement for the produced LNG has been a cost burden in overall LNG chains. For that reason, natural gas liquefaction at higher pressures has not been adopted by the industry. The specific weight ratio (SWR) of natural gas, defined as the natural gas weight divided by the containment system weight, is an important indication of capital expenditures. The typical SWR of conventional LNG is approximately 10–20 times that of compressed natural gas (CNG). Even for the increased- pressure LNG, the SWR is typically 10 times that for CNG. Hence, storage as a liquid after cooling and insulation is far more efficient than CNG. For increased-pressure LNG, the main cost contributor has been the cryogenic material for the higher pressure. However, if a cost-effective solution for increased-pressure containment is developed, it may become a viable option. Examples. Intermediate-Pressure LNG (20 bara, 1% CO2). Substantial CO2 can be dissolved in LNG produced at increased pressure. CO2 in the LNG should be liquid, not solid or as two phases. During cool down at a predetermined pressure, the feed gas can pass through the solid formation region in the interim stage. Hence, this region should be avoided by liquefying the natural gas at a higher pressure before reducing the pressure. If the CO2 level is sufficiently lowered during the gas treatment, the solid formation can be avoided regard-less of the liquefaction temperatures and processes.

Offshore oil and gas production and processing facilities are prone to incidents such as leakage which may escalate thus causing major accidents. These accidents pose a serious threat to personnel and assets. Previously, accident modelling has relied on studying a single event and its impact. It has been witnessed from past events that accidents are caused by combinations of events and therefore, accident modelling must consider multiple sequences of events and interdependent factors. The Floating Liquefied Natural Gas (FLNG) is a complex processing facility where a leakage of liquified natural gas (LNG) may escalate to a range of events such as fire to vapor cloud explosion. The escalation of events is dependent on the multiple intertwined factors evolving with time and space. This study is focussed on developing novel methodologies and models to study the transitional events and their causation during a major event in complex LNG processing facilities. This thesis outlined an extensive literature review and analysis of offshore and marine safety from the perspective of fire and/or explosion accidents. It analysed various causes of fire and/or explosion accidents and proposed a series of countermeasures with respect to different causes. The impact of the cryogenic temperature of LNG on steel structure during its accidental leakage has not been extensively studied. This study modelled an LNG pool formation and the impact of cryogenic temperature on a structural material during an accidental release of LNG. The study confirmed that an instantaneous LNG pool formation does cause immediate failure, however, this may significantly minimise design life of the structure and due attention is needed throughout its service life particularly in the spilled area. Literature review showed that minor leaks occur frequently, and they are often overlooked assuming that they are inconsequential. However, in the case of LNG, it can be too simple to ignore small leak due to the potentiality of causing suitable scenario for fire and explosion event upon rapid vaporisation after the leakage. This study proposed a novel technique for modelling fugitive leakage of LNG in a processing facility. The developed methodology is applied considering three different degrees of congestion and revealed that higher congestion levels present higher flammable hazards than the lower levels of congestion within the acceptable congestion level. As fire is the main cause of accident in oil and gas processing facilities, this study proposed a novel methodology for modelling fire impact assessment in a typical FLNG processing facility using Computational Fluid Dynamics (CFD). Three most credible fire accident scenarios were chosen from among various fire scenarios considered in the FLNG facility. It is found that the scenario in the Mixed Refrigerant Module in the liquefaction process presents the highest risk of fire to both on-board personnel and assets. In a complex processing facility, there is a high likelihood of occurrence of transitional scenarios such as hydrocarbon release, fire, explosion and dispersion of combustion products. Finally, this study modelled potential transitional events and their integrated impact during an accidental release of LNG. This study revealed that in a complex processing facility, transition of events is highly possible, and the impact of such events can be more severe than that of the individual event. This study serves as a comprehensive source of knowledge and technique on which to model various accident scenarios. The study of these scenarios assists in better understanding of accident causation and improves design to prevent causation of such events. The study also provides a practical approach to design safety measure to control and mitigate hazards when prevention is challenging. This thesis will serve as a guiding book to better design of processing facilities and safety measures for a complex processing facility.

Well-to-wheel analysis of bio-methane via gasification, in heavy duty engines within the transport sector of the European Union

Chapter Two - LNG technology

Vehicle exhaust and roadside air samples were collected at Guangzhou, Shenzhen and Chengdu in China, where liquefied petroleum gas (LPG), liquefied natural gas (LNG) and compressed natural gas (CNG)—common fuel alternatives for vehicles worldwide—are used, respectively. The emission characteristics, ozone formation potential (OFP) and health risks of nonmethane hydrocarbons (NMHCs) in conventional and clean alternative fuel exhaust emitted by vehicles were assessed to explore the environmental and health effects from the change in NMHCs due to using clean alternative fuels. Our results indicate that the fuel type significantly impacted the composition of the roadside air. The OFP values for the total NMHCs were much lower in the CNG (2.5 ppmv), LNG (4.7 ppmv) and diesel (4.5 ppmv) exhaust than in the gasoline (94.3 ppmv) and LPG (23.1 ppmv) exhaust, indicating that using CNG and LNG may effectively reduce O3 formation due to vehicle exhaust. Additionally, the hazard quotient (HQ), hazard index (HI) and cancer risk (Risk) of NMHC species in the vehicle exhaust were calculated. Both the HI and Risk of these species in the exhaust from gasoline-powered vehicles greatly exceeded those from the other four types of vehicles, suggesting that using clean alternative fuels instead of gasoline benefits human health.