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The International Gas Union's (IGU) recent report on world LNG markets found that the trade increased by only 1.4 mt to 356.1 mt compared to 2019 supported by increased exports from the US and Australia, together adding 13.4 mt of exports. Asia Pacific and Asia again imported the most volumes in 2020, together accounting for more than 70% of global LNG imports. Asia also accounted for the largest growth in imports in 2020--adding 9.5 mt of net LNG imports vs. 2019. While 20 mtpa in liquefaction capacity was brought on stream in 2020, all in the US, startup of several liquefaction trains in Russia, Indonesia, the US, and Malaysia were delayed as a result of the pandemic, according to the report. The only project that was sanctioned in 2020 was the 3.25-mtpa Energia Costa Azul facility in Mexico, and in early 2021 Qatar took final investment decision (FID) on four expansion trains totaling 32 mtpa.
COVID-19 may lead the liquified natural gas (LNG) industry to prioritize smaller LNG projects, according to consulting group Thunder Said Energy. Smaller plants and modular, phased designs may offer a more viable option for the industry coming out of the COVID-19 pandemic. The advantages of smaller plants include a lower workforce count compared with larger LNG plants. An average international LNG facility requires 1,000 workers on site per mtpa of capacity, potentially reaching over 20,000 workers at the largest, stick-built facilities. Workers at international plants are typically housed at the project in close quarters for 2–3 week rotations, which are risky amid the pandemic.
While being the most isolated capital city of the world, Perth, Western Australia, is still a shelter for a plethora of international oil and gas companies with their sights firmly set on producing the large-scale liquefied natural gas (LNG) developments. By the end of 2018, Western Australia will be exporting nearly 50 million tonnes per annum (mtpa) of LNG, with Australia's total expected export of 88 mtpa surpassing Qatar as the world's top LNG exporter (WA LNG Industry Profile 2017; Financial Review 2017). No sooner are the latest LNG projects Wheatstone and Prelude starting up than the Perth oil and gas companies are looking to develop further LNG through the soon-to-be off-plateau North West Shelf (NWS) LNG Project. With more than 40 Tcf of discovered offshore conventional gas resources without an allocated development, there are significant opportunities for further expansion. This is an exciting time for the young professionals lucky enough to call Perth their home.
Israel has begun exporting natural gas to Egypt under what has been called one of the most important deals to have been signed by the neighboring countries since their historic 1979 peace treaty. The terms of the deal call for Dolphinus Holdings, a private firm in Egypt, to purchase 85 Bcm of gas, worth an estimated $19.5 billion, from Israel's Leviathan and Tamar offshore fields over 15 years via a subsea pipeline connecting Israel and Egypt's Sinai Peninsula. Gas from Leviathan will be supplied to Dolphinus at a rate of 2.1 Bcm per year, rising to 4.7 Bcm per year by the second half of 2022, according to Delek Drilling, one of the partners in Leviathan and Tamar. Israel will initially export 200 MMcf/d, according to Egyptian industry sources. Israeli Energy Minister Yuval Steinitz said that the Sinai Peninsula has sufficient capacity for current volumes; however, the option of building a second pipeline will be considered if demand from Egypt grows.
ExxonMobil and Russian company Rosneft are planning to build an LNG plant in a consortium with Indian and Japanese partners, according to a Reuters report. The four companies--Rosneft, Exxon, Japan's SODECO, and India's ONGC Videsh--are currently partners in the Sakhalin-1 group of fields that will supply the gas, but ExxonMobil and Rosneft had originally planned to build the LNG plant without outside help. The decision will help spread the estimated $15-billion cost of the plant among more stakeholders and potentially mitigate sanctions risk. Sakhalin-1 is a hydrocarbon project in which ExxonMobil and SODECO hold separate 30% ownership stakes, with Rosneft and ONGC Videsh splitting the remaining 40% equally between them. It consists of three fields--Chayvo, Arkutun-Dagi, and Odoptu--in the Okhotsk Sea.
The sustained increase in global demand for cleaner fuels continues to drive the gas industry growth. Liquefied natural gas (LNG) has been a key enabler for this growth by making sizeable remote gas re-serves, which are unreachable by pipeline, accessible to the major and emerging gas markets. Every segment of the LNG supply chain has its own set of technical challenges. On the upstream side, many gas resources require significant pre-treatment before liquefaction, and the feed gas to the LNG facility is typically a mixture of various compositions from multiple sources; this composition mix evolves over the life of the project. The main challenge is development planning for the contributing reservoirs under the constraints imposed by the processing facility– managing reservoir deliverability, scheduling & sequencing of wells, and downtime management while maintaining the inlet stream specification. To aid with long-term planning for such assets, a virtual field management system is needed that can emulate a real-world hydrocarbon producing asset by capturing all operational constraints, resource lim-its, and complex operating logic.
This paper describes a comprehensive field management framework that can create an integrated vir-tual asset by coupling reservoir, wells, network, and facilities models and provides an advisory system for efficient asset management. The field management component can replicate any operational logic, exercises holistic control over the sub-surface model, integrates with the surface network model, and provides optimization capabilities. This paper demonstrates this for a complex LNG asset that is fed by sour gas of different compositions from multiple reservoirs.
We describe the different levels of constraints the asset needs to operate under, including treatment plant capacity, the LNG production capacity, the contractual LNG specifications, the disposal of gas impurities and imposes them on the model by utilizing a flexible and extensible logic framework. Con-straints applied at different levels can be mutually competing and their combination with recovery opti-mization goals increases complexity. The unified field management system uses a robust scheme to bal-ance the coupled system under these constraints while optimizing overall recovery. The optimization is enabled through the ability provided by the field management system to query and retroactively control flow entities during the simulation at the desired frequency.
Customization through scripting was necessary to implement this advanced logic and was enabled by the extensible nature of the field management framework. This extensibility, along with native capabili-ties, ensures that any level of complexity can be captured, and the workflow described in this paper can be applied to any hydrocarbon producing asset for short-term and long-term development planning.
The Gorgon gas plant produces 15.6 Million Tonnes per Annum (MTPA) Liquified Natural Gas (LNG) from the Gorgon and Jansz-Io subsea gas fields. First LNG production commenced on the Barrow Island, Australia facility in 2016. One of the first systems commissioned was the wastewater treatment, collection and disposal system, a critical support utility for production operations. The Produced Water Disposal (PWD) facility is unique on Barrow Island due the location's national nature reserve status, and all treated waste must be disposed downhole. The objective of this paper is to review key lessons from design, startup and steady state operations. Perspectives will be given on facility/well management and production operations of PWD at the Gorgon plant.
Wastewater on Barrow Island is generated from several sources: Condensed water originating from hydrocarbon gas (separated at gas dehydration and Mono-Ethylene Glycol (MEG) regeneration facilities), drainage and runoff water from the plant, treated sewage effluent and other ad hoc liquid waste. These sources are collected and treated before the final product is pumped into two available onshore disposal wells. One of the challenges initially faced was that the disposal water quality did not meet the design specification required to maintain well performance. This problem reduced as the plant reached steady state operations and the team gained a better understanding of well performance over time. Other current challenges include hydrocarbon carryover and water polishing, so Engineering and Operations work together closely to ensure reliable water disposal and hence LNG production.
This case study will explore the success and lessons learnt in Gorgon PWD through a summary of field data, facility descriptions and experiences. An overview of the design will be given along with photographs of key components. The required design performance will be compared against actual operating data. In the new energy landscape, the Upstream Operators' social license to operate centers around our environmental performance. In our work we demonstrate that it is possible to treat and dispose of waste liquids responsibly while generating cashflow through LNG production.
Floating Liquefied Natural Gas (FLNG) has been on the rise in recent years to meet growing energy demand, worldwide. As energy consumption and exploitation of onshore unconventional gas reservoirs continue to grow while gas price remains almost steady, FLNG can potentially become the key for operators in offshore gas fields through integration of upstream and midstream processes on the spot.
This paper compares project economics of a FLNG utilization to those of onshore LNG plant, and Gas-to-Wire (GTW) processes. Sensitivity analysis and tornado charts are used to evaluate importance of various uncertain parameters associated with FLNG construction and operation. Costs for the hypothetical FLNG vessel is taken from the average cost of Shell's Prelude FLNG; while pipeline, LNG plant, and gas-to-wire costs were obtained from typical industry standards. A typical hyperbolic decline curve model is applied to model depletion flow regime of production life after two scenarios: a 5- and 10-years constant rate plateau time, respectively.
Several factors are included in the sensitivity analysis: LNG price, interest rate, initial production rate, and condensate-to-gas ratio (CGR), distance from shore, electricity price, natural gas price and percentage share of overnight capital cost of building a power plant to convert gas to electricity. The factors are used to gauge their effects on the net present value (NPV) of each scenario and are ranked based on their sensitivity on a tornado chart, with the most sensitive parameter on top, and so on. The analysis suggest that initial production rate has the strongest effect on NPV, followed by discount rate, LNG price, CGR, and the distance from onshore when the reservoir is dry gas. This means the longer the distance from onshore, the more attractive the FLNG alternative becomes. However, when gas price is low, and a subsidy can be obtained, GTW becomes more attractive.
This economic feasibility study will be helpful for future considerations to use FLNG to make offshore gas reservoirs that were previously considered stranded into economically viable resources. The results from this economic model will certainly play a key role in the future of natural gas industry and energy market, especially in West Africa, particularly, in Nigeria.
Abstract This paper focuses on cost-effectively designing, developing, and operating liquified natural gas (LNG) facilities in Arctic environments. It discusses the inherent challenges associated with engineering, constructing, and operating LNG infrastructure in harsh and highly remote conditions and outlines proven strategies for reducing risk. Specific areas that are discussed include the use of modular design techniques to mitigate overall project risk and drive efficient execution, as well as the deployment of digital tools/technologies for minimizing operating and maintenance costs and maximizing plant availability. For illustrative purposes, the paper discusses the strategies employed on two real-world LNG projects, both of which are located inside the Arctic Circle.
Abstract 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.