LNG Facilities Research Articles

Big Players Pivot in Response to Regulatory Pressures

_ Early January brought with it significant changes in the environmental side of the oil and gas industry. ExxonMobil and Chevron, the two largest US oil producers, announced they will exit California, and the Biden administration froze LNG export approvals. After 50 years of producing oil in California, ExxonMobil will take a $2.5 billion writedown of the value of some of its California properties to be recorded in its fourth-quarter earnings. The company said the decision is primarily related to its Santa Ynez operations off the coast of Santa Barbara. Its US Securities and Exchange Commission (SEC) filing said, “While the Corporation is progressing efforts to enable a restart of production, continuing challenges in the state regulatory environment have impeded progress in restoring operations.” After the Refugio oil spill in May 2015 (approximately 100,000 gal), resulting from a leak from a pipeline owned by Plains All American Pipeline, ExxonMobil acquired the damaged asset in October 2015. Just a few months before the purchase, the Santa Barbara County Board denied ExxonMobil’s request to truck its oil produced off the coast of Gaviota to its Las Flores Canyon processing facility and on to refiners located in Pentland, California. Seeking an alternative, ExxonMobil planned to replace two stretches of the 112-mile corroded pipeline for transit of its oil. Met with opposition to replace the damaged pipeline and denied permission to repair and restart production at the site (halted since 2015), ExxonMobil is now selling the Santa Ynez operation to Sable Offshore, a blank-check company created in 2020. The company will loan Sable the money for the purchase of its three offshore production platforms, pipeline, and onshore processing facility. Sable’s agreement with ExxonMobil requires production to be started by early 2026 or the assets and liabilities revert to ExxonMobil. Chevron, headquartered in San Ramon, California, will write down $3.5 billion to $4 billion in assets, citing its home state’s regulations that “have resulted in lower anticipated future investment levels.” The company intends to continue operating its oil fields and related assets. In the SEC filing, Chevron wrote it also will incur fourth-quarter charges related to decommissioning of US Gulf of Mexico assets that have reached the end of their productive lives. The company sold some of those assets, but US law stipulates that previous owners may be responsible for those costs if the current owner declares bankruptcy. Chevron wrote it’s “probable” that it may see such costs. January closed with another unexpected announcement on 26 January. The Biden administration paused decisions on permits to export LNG to non-free trade agreement countries to review current projects seeking approvals. US Energy Secretary Jennifer Granholm stated, “We must review export applications using the most comprehensive, up-to-date analysis of the economic, environmental, and national security considerations.” She added that this was not a ban on exports and would not affect already authorized exports, which when combined with existing plants, total 48 Bcf/D. “Within this decade another 12 Bcf/D of US export capacity already authorized and under construction will come online,” Granholm said. While environmental impact (greenhouse gas emissions including CO2 and methane) was one of the reasons for the decision, along with market, economic, national security, and energy security, Granholm pointed out that facilities totaling 22 Bcf/D of capacity have been approved but have not yet started construction. This capacity, combined with existing infrastructure, is “more than enough to make the US a ‘behemoth’ in the LNG field,” according to Holland & Knight in an analysis dated 29 January. The international law firm said this raises the question of whether further development of LNG facilities could hurt US citizens as higher percentages of produced gas are exported. “This line of thinking follows the historical rhetoric on this issue as domestic users of natural gas want to ensure their feedstock price is stable. To support those claims, recent studies have concluded that ‘higher LNG exports create a tighter domestic natural gas market (all else held equal), increasing domestic natural gas prices.’” Could unintended consequences of these recent announcements rear up in the future? And could they be a behemoth for the US or global markets? For Further Reading Growth in 2022 US LNG Liquefaction Capacity Hits Top of the Charts by Pat Davis Szymczak, SPE Oil and Gas Facilities.

Peculiarities of cryogenic pipelines insulation selection at small scale liquefied natural gas production and consumption facilities

The article analyzes the typical design and materials of thermal insulation of cryogenic pipelines, compares them on the basis of thermal conductivity, and considers the key differences in the regulatory and technical documents of the Russian Federation, the People's Republic of China and the European Union, which should be taken into account in the design of thermal insulation of pipelines at low-tonnage LNG facilities. A number of regulatory requirements in the Russian Federation restrict the use of commonly used materials such as polyisocyanurate and pouleorethane foam without the development of a safety case or the use of additional compensating measures. Thermal insulation structures based on aerogels or foam glass are acceptable, but have a number of shortcomings.

Reviewing the development of floating LNG facilities and their global impact

This Review encapsulates a comprehensive review of the development and global impact of Floating Liquefied Natural Gas (FLNG) facilities. These innovative structures have revolutionized the liquefied natural gas industry by enabling offshore gas extraction, liquefaction, and storage. The study explores the evolution, challenges, and transformative influence of FLNG facilities on the global energy sector. The review begins with an examination of the historical development of FLNG technology, tracing its roots to the early 21st century. It showcases how these floating facilities have evolved from conceptual designs to operational structures, emphasizing key technological advancements that have propelled their growth. The global impact of FLNG facilities is analyzed through multiple lenses. Economic considerations, such as cost-effectiveness and accessibility to remote gas reserves, emerge as significant drivers for their adoption. The study also delves into the environmental implications, assessing the potential benefits and challenges associated with offshore liquefaction. Challenges inherent in FLNG development, including engineering complexities and regulatory considerations, are addressed. The study sheds light on how these challenges have been navigated, leading to successful deployment and operation of FLNG facilities in various regions. The transformative influence of FLNG facilities on global energy dynamics is highlighted, with a focus on their role in unlocking stranded gas reserves and facilitating timely responses to shifting market demands. The review emphasizes their adaptability to different geographic and economic contexts, showcasing their versatility as a pivotal component of the liquefied natural gas supply chain. In conclusion, this review offers a panoramic perspective on the development of FLNG facilities and their profound impact on the global energy landscape. By bridging technological innovation, economic viability, and environmental considerations, these floating facilities emerge as key contributors to the evolving dynamics of the liquefied natural gas industry, shaping a resilient and adaptive future for the energy sector.

Comparative Assessment of Methane Emissions from Onshore LNG Facilities Measured Using Differential Absorption Lidar.

This study provides results from measurements of methane emissions from three onshore LNG liquefaction facilities and two regasification facilities across different regions using the Differential Absorption Lidar (DIAL) technique. The measurement approach was to quantify, at each facility, emissions from the key functional elements (FEs), defined as spatially separable areas related to different identified processes. The DIAL technique enabled quantification of emissions at the FE level, allowing emission factors (EFs) to be determined for each FE using activity data. The comprehensive data set presented here should not be used for annualization, however shows the potential of what could be achieved with a larger sample size in terms of potential methane reduction and improving inventory accuracy. Among the benefits in obtaining data with this level of granularity is the possibility to compare the emissions of similar FEs on different plants including FEs present in both liquefaction and regasification facilities. Emissions from noncontinuous sources and superemitters can also be identified and quantified enabling more accurate inventory reporting and targeted maintenance and repair. Site throughput during the measurement periods was used to characterize total site EF; on average the methane losses were 0.018% and 0.070% of throughput at the regasification and liquefaction facilities, respectively.

Canada, the EU and energy security: a historical perspective

ABSTRACT Canada’s energy relations with the EC/EU have historically been driven by hopes for complementary trade and like-minded international positions, especially once international energy governance took on urgency in the 1970s. Since the early 2000s these two objectives have become less compatible as they pit transatlantic energy trade against the global climate change agenda. Not only does Ottawa have to reconcile hydrocarbon energy production and pledges to net zero carbon emissions, but it also has to balance short and long-term time horizons as the world embarks on its decarbonizing journey. Current Canadian plans for LNG and hydrogen facilities in the eastern part of the country illustrate the difficulty of navigating between immediate responses to a crisis – providing LNG to Europe to make up for deliveries from Russia – and longer-term plans to become an exporter of cleaner energy such as hydrogen to foster the next energy transition and help address climate change. Leaning on historical institutionalism and constructivism, the following analysis will show that Canada’s present and future energy relations with the EU are best understood as the outcome of decades of transatlantic energy diplomacy, institutionalized understandings of energy security and global frameworks which link energy and climate matters.

Engineering Poster E10: Carbon capture clusters

Poster E10 Net zero is an endeavour that will impact every corner of the world. We need global communication and collaboration. To move fast, the transition must become more efficient and spread the best solutions far and wide. For difficult to decarbonise industries, collaboration is essential. The other essential ingredient is policy. The UK banned diesel and petrol car sales from 2030. This is driving electric vehicle manufacturing and supply chains. The EU banned single-use plastics from 2021. Consequently, Coca Cola Europe announced 100% of their bottles would be based on recycled plastic. Norway introduced a carbon tax in 1991 to encourage research into low-carbon solutions. It became the first country to geologically sequester CO2 and the first to do it from an LNG facility. Ten years after the tax was introduced, Norway’s carbon emissions had dropped by 14%. Policies influence emissions. They drive not only environmental outcomes but also sustainable growth and the ability to future-proof their economies. In 2007 and 2012, the UK announced funding for a commercial-scale carbon capture and storage project, both times the programs were aborted. A third attempt, this time focussing on decarbonising four industrial clusters by 2030, was announced in 2018 along with the first ‘net-zero’ carbon cluster by 2040, with the support of a number of UK policies it is expected to progress to construction. This paper discusses the journey from policy through partnerships to the development of Carbon Capture and Hydrogen Clusters in the UK and looks at lessons learnt for Australia. To access the poster click the link on the right. To read the full paper click here

Concurrent 14. Presentation for: Major geological surfaces of the Exmouth Plateau from the new Broadband PreSDM reprocessed 3D seismic data with full waveform inversion

Presented on Wednesday 18 May: Session 14 The Barrow Sub-basin and Exmouth Plateau, of Australia’s North West Shelf, contain Australia’s largest gas reserves, underpinning the three major LNG facilities, including Gorgon, Wheatstone and Pluto. In addition, there remains significant near-field exploration potential such as the Sasanof prospect. While there is full 3D seismic coverage in the basin, the existing 3D surveys are of different vintages covering only parts of the basin with diverse acquisition and processing parameters. Multi-Client Resources has produced an extensive 3D seismic reprocessing project (BEX-MC3D) incorporating 23 legacy 3D surveys to provide a seamless 25 570 km2 3D dataset. The BEX-MC3D was processed from field tape through DUG Technology’s advanced Broadband PreSDM processing sequence with Full Waveform Inversion (FWI) imaging. The BEX-MC3D provides one continuous superlative 3D dataset covering almost the entire Barrow Sub-basin and the Exmouth Plateau. Major geological surfaces corresponding to key tectonic events from overburden to reservoirs have been interpreted from the BEX-MC3D Priority area in the current study. These high-fidelity imaged surfaces form a basin-wide framework for: (1) rapid exploration lead and prospect identification through the creation of trap and reservoir visualisations; (2) improved reservoir connectivity analysis and modelling of producing and discovered fields to support better reservoir management and field development decisions; and (3) improved understanding of basin-burial history for reservoir quality and geo-mechanical property prediction. This paper will present and discuss major geological surfaces in the context of future exploration lead/prospect identification, reservoir characterisation for field development and management, and improving overall understanding of the basin history. To access the presentation click the link on the right. To read the full paper click here

Concurrent 10. Presentation for: Embracing technology to deliver an intelligent Scarborough offshore facility

Presented on Wednesday 18 May: Session 10 The Scarborough gas field is located approximately 375 km offshore the Burrup Peninsula in approximately 900 m water depth. The Scarborough Project will process gas from the field through a new semisubmersible Floating Production Unit (FPU), then through an onshore LNG facility. Woodside’s Operations and Project teams have focussed on enabling safe, reliable, and efficient operations to be realised throughout the facility operating life. Woodside has adopted a justify in, design out, embrace technology approach to meet this requirement. At the heart of this approach is the requirement to minimise the time required for personnel to be present on the facility. This is being achieved by utilising technology in design and innovative equipment and material selection. The FPU will be remotely controlled from an Integrated Remote Operations Centre located in Perth. Critical equipment located offshore will be constantly monitored for condition and performance with data able to be analysed efficiently, enabling effective and timely decisions. An extensive digital environment will be utilised to capture information and allow for intelligent solutions to aid this analysis. Materials and coatings have been selected to meet the design life and reduce maintenance-intensive refurbishment requirements. Offshore equipment can be remotely reset and restarted and includes appropriate sparing to maximise availability. Maintenance and environmental benefits have been realised by selecting electrical alternatives for lifeboats and cranes with a large installed battery system enabling a reduction in spinning reserves. This strategy will result in a lower emissions facility with reduced operating costs and offshore exposure hours. To access the presentation click the link on the right. To read the full paper click here

Accident type analysis and consequence simulation of LNG terminals equipment and facilities

A new round of energy change, energy clean and low carbon development become an inevitable trend. In the adjustment of energy structure, natural gas becomes the strongest growth carrier and LNG reserve peak regulation is of great significance. Building liquefied natural gas receiving center to secure domestic natural gas supply has become the main target, task and key work. Through the simulation of various equipment and facilities in the LNG terminal under different leakage scenarios, the accident scenarios are selected according to the protection distance criteria, the simulation of steam diffusion, pool fire, jet fire and explosion is carried out, and the influence range of consequences is obtained. The thesis provides a theoretical basis for the quantitative risk assessment for LNG terminal accident and the prediction of emergencies, having positive guiding significance for risk management and emergency disposal of new or operating LNG terminals.

Carbon capture clusters

Net zero is an endeavour that will impact every corner of the world. We need global communication and collaboration. To move fast, the transition must become more efficient and spread the best solutions far and wide. For difficult to decarbonise industries, collaboration is essential. The other essential ingredient is policy. The UK banned diesel and petrol car sales from 2030. This is driving electric vehicle manufacturing and supply chains. The EU banned single-use plastics from 2021. Consequently, Coca Cola Europe announced 100% of their bottles would be based on recycled plastic. Norway introduced a carbon tax in 1991 to encourage research into low-carbon solutions. It became the first country to geologically sequester CO2 and the first to do it from an LNG facility. Ten years after the tax was introduced, Norway’s carbon emissions had dropped by 14%. Policies influence emissions. They drive not only environmental outcomes but also sustainable growth and the ability to future-proof their economies. In 2007 and 2012, the UK announced funding for a commercial-scale carbon capture and storage project, both times the programs were aborted. A third attempt, this time focussing on decarbonising four industrial clusters by 2030, was announced in 2018 along with the first ‘net-zero’ carbon cluster by 2040, with the support of a number of UK policies it is expected to progress to construction. This paper discusses the journey from policy through partnerships to the development of Carbon Capture and Hydrogen Clusters in the UK and looks at lessons learnt for Australia.

Major geological surfaces of the Exmouth Plateau from the new Broadband PreSDM reprocessed 3D seismic data with full waveform inversion

The Barrow Sub-basin and Exmouth Plateau, of Australia’s North West Shelf, contain Australia’s largest gas reserves, underpinning the three major LNG facilities, including Gorgon, Wheatstone and Pluto. In addition, there remains significant near-field exploration potential such as the Sasanof prospect. While there is full 3D seismic coverage in the basin, the existing 3D surveys are of different vintages covering only parts of the basin with diverse acquisition and processing parameters. Multi-Client Resources has produced an extensive 3D seismic reprocessing project (BEX-MC3D) incorporating 23 legacy 3D surveys to provide a seamless 25 570 km2 3D dataset. The BEX-MC3D was processed from field tape through DUG Technology’s advanced Broadband PreSDM processing sequence with Full Waveform Inversion (FWI) imaging. The BEX-MC3D provides one continuous superlative 3D dataset covering almost the entire Barrow Sub-basin and the Exmouth Plateau. Major geological surfaces corresponding to key tectonic events from overburden to reservoirs have been interpreted from the BEX-MC3D Priority area in the current study. These high-fidelity imaged surfaces form a basin-wide framework for: (1) rapid exploration lead and prospect identification through the creation of trap and reservoir visualisations; (2) improved reservoir connectivity analysis and modelling of producing and discovered fields to support better reservoir management and field development decisions; and (3) improved understanding of basin-burial history for reservoir quality and geo-mechanical property prediction. This paper will present and discuss major geological surfaces in the context of future exploration lead/prospect identification, reservoir characterisation for field development and management, and improving overall understanding of the basin history.

Embracing technology to deliver an intelligent Scarborough offshore facility

The Scarborough gas field is located approximately 375 km offshore the Burrup Peninsula in approximately 900 m water depth. The Scarborough Project will process gas from the field through a new semisubmersible Floating Production Unit (FPU), then through an onshore LNG facility. Woodside’s Operations and Project teams have focussed on enabling safe, reliable, and efficient operations to be realised throughout the facility operating life. Woodside has adopted a justify in, design out, embrace technology approach to meet this requirement. At the heart of this approach is the requirement to minimise the time required for personnel to be present on the facility. This is being achieved by utilising technology in design and innovative equipment and material selection. The FPU will be remotely controlled from an Integrated Remote Operations Centre located in Perth. Critical equipment located offshore will be constantly monitored for condition and performance with data able to be analysed efficiently, enabling effective and timely decisions. An extensive digital environment will be utilised to capture information and allow for intelligent solutions to aid this analysis. Materials and coatings have been selected to meet the design life and reduce maintenance-intensive refurbishment requirements. Offshore equipment can be remotely reset and restarted and includes appropriate sparing to maximise availability. Maintenance and environmental benefits have been realised by selecting electrical alternatives for lifeboats and cranes with a large installed battery system enabling a reduction in spinning reserves. This strategy will result in a lower emissions facility with reduced operating costs and offshore exposure hours.

Location of temporary buildings at LNG site based on quantitative studies

AbstractTemporary buildings, installed on site during the construction phase, may not be removed until the commissioning, completion, or beginning of normal operation. Once the hydrocarbons are introduced, these buildings have the potential to be exposed to process hazards (fire, explosion, toxicity, etc.) resulting in injury or fatality of the personnel inside the building. Providing safe location to these portable building is imperative and should be determined based on detailed hazard analysis, building siting study as per API 753. Facility siting study is done to calculate the potential impact of blast overpressure, thermal radiation from jet fires, pool fires, and toxicity hazards and evaluate the safe distance to the temporary buildings. Simultaneous operations is also evaluated in order to optimize temporary building location and further risk management strategies are implemented such as mitigation measures based on the hazard impacts, like, adding gas detectors at the air intake of HVAC to shut down the power supply to the temporary buildings, public announcement system, evacuation drills, and so on. This paper will address the temporary building siting study and associated mitigation measures with the highlight of its application into the risk management, using a large LNG facility as an example.

The effect of barriers on reducing thermal heat fluxes from a hydrocarbon pool fire

The radiant heat flux from a pool fire is frequently calculated using the solid flame model, where the flame envelope is approximated as a stationary cylinder whose surface emits thermal radiation at a constant rate. Radiant heat flux calculations using the solid flame model assume the target to be at a given elevation, typically at ground level, and to have an unobstructed view of the fire. The presence of obstacles (e.g., walls, buildings, etc.) or terrain features that would create shaded areas and provide shielding of a target from the fire is typically neglected in these calculations: this is a conservative approach, but it is not accurate. This paper presents a methodology to utilize the solid flame model to calculate the heat flux to a target while taking into account the presence of an obstruction between the target and the fire. The shielded solid flame method can quantitatively account for the presence of obstacles as a passive mitigation measure and allows project developers or designers to optimize their facility layout to meet safety requirements. The methodology presented in this paper uses the same correlations found in currently used solid flame models (e.g., LNGFIRE3), therefore, it remains consistent with current regulatory requirements for LNG facilities in the U.S.

Safety guidelines and a training framework for LNG storage and bunkering at ports

This paper summarises the main achievements of the project “Sustainability Performance of LNG-based maritime mobility”- (SUPER-LNG), financed by the Adriatic Ionian Interreg framework. Within this project, guidelines for safety reporting, risk assessment, and emergency planning of small scale LNG facilities and bunkering operations at ports have been developed. The main elements of these guidelines are presented in the article together with the results of their specific application on a small LNG facility, consisting of LNG pressurised tanks, LNG trucks, and a loading arm section. In addition, a training programme has been also created with the aim to promote safety and knowledge transfer on the LNG fuel chain to interested stakeholders, such as port operators, maritime instructors, port authorities, and stakeholders in planning, licensing, and emergency management practices related to LNG handling.

Incorporating an Asset Health Index into a Life Cycle Costing: A Proposition and Study Case

A physical asset’s health is the consequence of a series of factors, ranging from the characteristics of the location where it operates to the care it is submitted to. These characteristics can influence the durability or the horizon of the useful life of any equipment, as well as determine its operational performance and its failure rates in the future. Therefore, the assessment of the influence of asset health on Life Cycle Costs is a compelling need. This paper proposes the incorporation of a factor that reflects the projected behavior of an asset’s health index into its corresponding Life Cycle Costing (LCC) model. This allows cost estimates to be made more realistic and LCC models to be operated more accurately. As a way of validating this proposal, a case study is shown. The methodology proposed in this case study was applied in a real case, considering an LNG facility located in central Chile. In addition, sensitivity studies and comparisons with the results obtained by a traditional Life Cycle Costing model are included. The results show the usefulness of incorporating asset health aspects into the Life Cycle Costing of physical assets.

Bayesian network-based failure analysis of fire safety barriers in floating LNG facility

Fire accidents on floating LNG (FLNG) processing facilities are initiated by the uncontrolled gas leaks and then evolved through the successive failure of relevant safety barriers (SBs). This paper develops a methodology to perform comprehensive failure analysis of fire SBs and corresponding consequences in FLNG system using a Bayesian network (BN). Two BN models were constructed and compared, the independent BN and the dependent BN. The BN models were mapped from Event Tree–Fault Tree (ET–FT) diagram. The inter-dependency between SBs and uncertain causal relationships was completely considered in the dependent BN model. The dependent model also investigated the dependency of all SBs on the release prevention barrier (RPB) as the critical and initial barrier of the fire safety system. The probabilities of SBs failure obtained using the dependent BN were less than that of independent BN values. This could be ascribed to the influence of SBs inter-dependency and the model uncertainty due to uncertain relation relationships between managerial and organization factors (MOFs) and functional failures. Among SBs, it was found that the RPB has the highest failure probability. The diagnostic analysis further identified the MOFs as the most influencing factors contributing to SBs failure. The predictive analysis revealed that the large fire with major damage has a higher probability to occur in comparing with other consequences. Additionally, the BN was extended to estimate the risk levels of consequences by integrating the accident probability, accident severity, and escape, evacuation, and rescue (EER) process reliability. The findings indicated that the EER operations have a major influence on the risk level and suggested to be considered for reliable risk level assessment rather than traditional risk matrix.

Malaysia’s Petronas is Looking Near and Far for Gas and Oil

Petronas is looking within its home country, around Southeast Asia, and to the Americas in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. It is also exploring new partnerships with other global operators that offer regional and technical expertise. The integrated company, whose upstream portfolio consists primarily of natural gas, wants to both accelerate its exploitation of the hydrocarbon and add more oil to the mix. Back home, Petronas—the world’s third-largest LNG seller—continues to target domestic gas to leverage its control of the gas value chain all the way to its petrochemical and LNG liquefaction plants. The company’s LNG facilities include its 30-million tonnes/annum (mtpa) complex in Sarawak, and the world’s first floating LNG facility, the 1.2-mtpa PFLNG Satu. A second floating LNG facility is expected to be ready for sail away by 2020. Petronas is taking advantage of a growing Southeast Asia gas market, counting Japan, Korea, Taiwan, “and increasingly China” as major LNG customers, said Adif Zulkifli, Petronas executive vice president and chief executive officer of gas and new energy, on the sidelines of a recent SPE forum in Kuala Lumpur. Adif said one of Petronas’ primary goals is to turn Malaysia’s large inventory of contingent resources into proved reserves. The company has worked “to intensify exploration activities in Malaysia,” and it is seeking to bring more partners into the fold: The country recently revised terms in its deepwater production-sharing contracts to attract more international participation. “We are quite progressive in terms of attracting investment, and that has brought in some new plays into the space,” he said. Adif believes “there is much potential within the deep waters of Sabah that is still left untapped and remains very attractive to investors.” Last year, the Total-operated Tepat-1 well in deepwater Sabah tested a frontier Miocene carbonate buildup “and is believed to have found oil and gas, though commerciality is uncertain and the results are being kept very tight,” according to a report from research consultancy Westwood Global Energy. “Tepat demonstrates that explorers are still testing new plays in the region and that a breakthrough could yet happen.” Elsewhere in Southeast Asia, said Adif, the company hopes to soon monetize its operated deepwater Kelidang cluster project off Brunei, continue exploratory work on the recent onshore Sakakemang discovery in Indonesia, and improve recovery from its Yetagun block off Myanmar. Petronas farmed in to the Sakakemang block in January, a month before operator Repsol announced the discovery, which comes with a preliminary estimate of 2 Tcf in recoverable resources. Petronas also intends to explore the deepwater Moat-tama Basin off Myanmar and frontier areas off East Indonesia, he added.

ANALISIS KEEKONOMIAN PROYEK GAS-TO-LIQUID SEBAGAI ALTERNATIF PEMANFAATAN CADANGAN GAS ALAM INDONESIA

The reservoir on Field A that has an estimated large reserve of natural gas of 10,73 TSCF would have a potential economic value when developed correctly. The natural gas reserve is planned to be extracted by utilizing 18 subsea production wells connected to five subsea manifolds at a depth of 300 ‒ 1000 m at below sea level. Gas production will be done by using FPSO. Produced gas then will be pumped to onshore processing facilities on Yamdena island through undersea pipeline that used corrosion resistant alloy as long as up to 100 km in length. The natural gas processing would either be done by building an LNG facility scenario or building a GTL facility scenario on Yamdena island. The LNG scenario would produce the natural gas into LNG and gas condensate. While the GTL scenario would produce the natural gas as a synthetic liquid fuel such as LPG, naphtha, kerosene, and diesel. The feed gas volume used on both scenarios is assumed to be 1.041 MMSCFD. The economic indicator calculated for GTL yields an NPV of 1.743,44 MMUS$ and for LNG yields 1.940,51 MMUS$. The IRR calculated for GTL yields 13,27% and for LNG yields 13,14%. The POT period calculated from cummulative cash inflow for GTL scenario will take 9,84 years time, while on LNG scenario POT will take 9,90 years time. The PI value calculated for GTL scenario yields a value of 1,46 and for LNG scenario yields a value of 1,44. Results from sensitivity analyses on economic indicator found that the parameters which has significant effect on the change of economic indicator values are product sell price.

A study on local residents' perception in communication process for LNG terminal risks

The objective of this paper is to explore the locals' perception on risk communication process between LNG organisation and local residents. Using a traditional communication model based on the source-message-channel-receiver-effect (SMCRE), the factors of risk communication process were measured to determine the residents' perception of facility risks. The individual factors that influenced SMCRE elements were grouped and analysed by factor analysis. Also, multiple regression analysis was conducted to examine the effect of latter element on former element: the order of elements was S → M, M → C, C → R, and R → E. In terms of the model's final process, an effective pathway had two cases. The first case was the relieving of social conflicts and anxieties through mutual understanding. The second case was the promotion of trust. This study can assist LNG organisations with providing better risk communication to residents and enhance the acceptance of LNG facilities.