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2021 ◽  
Vol 73 (11) ◽  
pp. 62-63
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30437, “Risk Management and Control for CO2 Waterless Fracturing,” by Siwei Meng, Qinghai Yang, SPE, and Yongwei Duan, PetroChina, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Given shortages and uneven distribution of water resources in China, efforts must be made to develop waterless fracturing techniques. The fluid experiences high pressures and low temperatures during carbon dioxide (CO2) waterless fracturing operations, which can lead to accidents and environmental pollution. In the complete paper, a safety-management approach and a contingency plan for such operations are developed. At the time of writing, this CO2 waterless fracturing methodology has been completed successfully more than 20 times. Surface Process Work Flow of CO2 Waterless Fracturing The basic process of a CO2 waterless fracturing operation is shown in Fig. 1. First, several CO2 storage tanks are connected in parallel. The booster, sealed blender, fracturing pump (all mounted on trunks), and wellhead equipment are connected. The measuring trunk communicates with each vehicle to monitor operation status. Proppant is put into the sealed blender, into which liquid CO2 is injected for pre-cooling. Pump testing is conducted on the high-pressure line and the wellhead and the low-pressure liquid supply line is pressure-tested. Operation does not proceed until pressure-testing results are positive. Afterward, liquid CO2 is injected into formations to fracture them and, moreover, extend created fractures. The sealed blender is enabled to inject prop-pants, and displacement begins after the end of proppant injection. Finally, a series of tasks, including well shut-in for soaking and flowback, is carried out successively.


2021 ◽  
Vol 73 (11) ◽  
pp. 77-78
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31298, “Novel Active Slug Control in Angola: Development and Field Results,” by Lisa Ann Brenskelle, SPE, Martin Bermudez Morles, and Lauren Annette Flores, Chevron, prepared for the 2021 Offshore Technology Conference, Houston, 16–19 August. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Hydrodynamic slugging was anticipated during the design of a new facility in Angola. A simulation study demonstrated that a control scheme from the literature could be applied effectively to control the slugging. That solution was rejected, however, because of the use of a pseudovariable as the principal control point. A novel control scheme, therefore, was developed and tested in simulation for both hydrodynamic slugging and severe riser-induced slugging. Upon commissioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug-control scheme was effective in controlling incoming slugs. Slugging-Control Approaches Various control schemes have been implemented to control slugging in hydrocarbon-processing systems, including subsea systems. The accepted control approaches to the various types of slugging differ because causes of slugging differ, although the effects on processing facilities are similar. For hydrodynamic slugging, the use of a pseudoflow controller, which uses a calculated value of flow, is the accepted conventional approach. The pseudoflow is calculated from the equation for volumetric liquid flow through a valve, which results in a value that is not physically meaningful for multiphase fluids. For terrain slugging, the accepted approach is the use of pressure control, wherein the pressure is upstream of the slug-forming area. For riser slugging, this is at the base of the riser. For both hydrodynamic and terrain slugging, the accepted control schemes usually modulate the control valve located upstream of the vessel first receiving produced fluids, normally depicted as a separator, although this vessel also could take other forms. Use of this valve in relation to slugging is common, whether used manually or in a control scheme. Maximum production occurs with the valve fully open, but this cannot control or prevent slugging. Known field-demonstrated control schemes include pseudoflow control, pressure control upstream of the slug-forming area, pressure control upstream of the slug-forming area cascaded to (i.e., determining the setpoint for) the pseudoflow control, and composite variable control. Each of these control schemes has practical disadvantages affecting usability in the field. The principal disadvantage of pseudoflow slug control is that setpoint determination is difficult because the pseudoflow is not an actual physical flow rate. Trial and error would be required to determine the pseudoflow setpoint each time it would need to be adjusted, which would be a frequent occurrence as operational conditions change. In the case of slug control through pressure control upstream of the slug-forming area, the principal disadvantage is the use of a subsea pressure sensor because the slug-forming area, the low point, frequently is subsea. Not only is subsea instrumentation expensive, but such instrumentation also is difficult to replace should it fail.


2021 ◽  
Vol 73 (11) ◽  
pp. 73-74
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30172, “A Streamlined Multidisciplinary Work Flow for Pipeline-Slugging Assessment,” by Jeff Zhang, Saurav Jha, and Tim Matuszyk, Wood, prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Free spans exist in subsea multiphase pipelines laid over undulating seabed profiles or across continental scarps for offshore field developments. Slug-flow-induced fatigue damage on the free spans can have a significant effect on project economics. Slug-flow assessments can prove time-consuming. The complete paper describes an integrated iterative approach between the flow-assurance and pipeline-engineering disciplines to streamline the work flow based on the value or cost associated with changes in input parameters that affect pipeline fatigue-assessment outcomes. Slug-Flow Assessment Work Flow The complete paper further details key goals for each step. Step 1: Plan Project Slug-Flow Design Requirements. Key to this step is to create a close interface between flow-assurance and pipeline engineers to discuss and align overall timing, critical decisions, and hold points that are required as part of the slug-flow assessment and any specific project-design considerations. Step 2: Execute Slug-Flow-Prediction Assessment. Slug-flow prediction typically is conducted by engineers using industry-standard multiphase dynamic-flow simulators. The step requires significant time and effort because of long simulation times and large data post-processing requirements. Step 3: Generate Slug-Flow Interface Data. The two methods typically used for converting flow-assurance slug-flow results into formats that can be used readily by pipeline engineers are the time-history approach and the time-dependent-matrix approach. Step 4: Execute Slug-Flow Response Assessment. This assessment typically is conducted by pipeline engineers to assess the effects of predicted slug-flow interface data on proposed pipeline con-figuration designs. Industry-standard finite-element-analysis (FEA) tools are used for this step. Step 5: Finalize Design Through Iteration and Optimization. Where the slug-flow response assessment results show excessive fatigue damage that affects feasibility of the proposed design, iteration and optimization are performed. Step 6: Consider Operational Monitoring Requirements. Operational fatigue monitoring can be considered if operational restrictions are required or if some level of risk or concern remains with the final design.


2021 ◽  
Vol 73 (10) ◽  
pp. 65-66
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30985, “From Data to Assessment Models, Demonstrated Through a Digital Twin of Marine Risers,” by Ehsan Kharazmi and Zhicheng Wang, Brown University, and Dixia Fan, SPE, Massachusetts Institute of Technology, et al., prepared for the 2021 Offshore Technology Conference, Houston, 16–19 August. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Assessing fatigue damage in marine risers caused by vortex-induced vibrations (VIV) serves as a comprehensive example of using machine-learning methods to derive assessment models of complex systems. A complete characterization of the response of such complex systems usually is unavailable despite massive experimental data and computation results. These algorithms can use multifidelity data sets from multiple sources. In the complete paper, the authors develop a three-pronged approach to demonstrate how tools in machine learning are used to develop data-driven models that can be used for accurate and efficient fatigue-damage predictions for marine risers subject to VIV. Introduction In this study, machine-learning tools are developed to construct a digital twin of a marine riser. The digital twin uses various sources of training data, including field data, experimental data, computational-fluid-dynamics simulations, extracted databases, semiempirical codes, and existing knowledge of underlying physical models. The authors also show that a well-trained digital twin can use the streaming data from a few field sensors efficiently to provide an accurate reconstruction of motion and to provide fatigue-damage prediction. Several machine-learning algorithms have been developed in the literature to predict the life span of the structure through the changes in parameters. To the best of the authors’ knowledge, most existing methods are developed as black boxes that return parameters by only feeding experimental data and therefore are ignorant of the underlying physics. In the first of three approaches, the authors enhance the capabilities of semiempirical codes by developing efficient databases through active learning. In the second approach, the LSTM-ModNet framework is applied to reconstruct and analyze the entire motion of a riser in deep water from sensor measurements through modal decomposition in space and the sequence-learning capability of recurrent neural networks in time. The formulation described in the paper provides a tool that efficiently combines different types of sensor measurements, such as strain and acceleration. In the third approach, a higher level of abstraction is introduced and the nonlinear operator that maps the inflow current velocity to the root-mean-square function of the riser response is approximated. In particular, the newly developed neural network DeepONet is used as a black box to learn the mapping between the input parameters (the inflow velocity, riser bending stiffness, and tension as a function of water depth) to the output parameters (strain, amplitude, and exciting frequencies as a function of water depth). In these approaches, data from the high-mode VIV test is used to train the networks.


2021 ◽  
Vol 73 (10) ◽  
pp. 71-72
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm3, and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.


2021 ◽  
Vol 73 (09) ◽  
pp. 58-59
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30407, “Case Study of Nanopolysilicon Materials’ Depressurization and Injection-Increasing Technology in Offshore Bohai Bay Oil Field KL21-1,” by Qing Feng, Nan Xiao Li, and Jun Zi Huang, China Oilfield Services, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Nanotechnology offers creative approaches to solve problems of oil and gas production that also provide potential for pressure-decreasing application in oil fields. However, at the time of writing, successful pressure-decreasing nanotechnology has rarely been reported. The complete paper reports nanopolysilicon as a new depressurization and injection-increasing agent. The stability of nanopolysilicon was studied in the presence of various ions, including sodium (Na+), calcium (Ca2+), and magnesium (Mg2+). The study found that the addition of nanomaterials can improve porosity and permeability of porous media. Introduction More than 600 water-injection wells exist in Bohai Bay, China. Offshore Field KL21-1, developed by water-flooding, is confronted with the following challenges: - Rapid increase and reduction of water-injection pressure - Weak water-injection capacity of reservoir - Decline of oil production - Poor reservoir properties - Serious hydration and expansion effects of clay minerals To overcome injection difficulties in offshore fields, conventional acidizing measures usually are taken. But, after multiple cycles of acidification, the amount of soluble substances in the rock gradually decreases and injection performance is shortened. Through injection-performance experiments, it can be determined that the biological nanopolysilicon colloid has positive effects on pressure reduction and injection increase. Fluid-seepage-resistance decreases, the injection rate increases by 40%, and injection pressure decreases by 10%. Features of Biological Nanopolysilicon Systems The biological nanopolysilicon-injection system was composed of a bioemulsifier (CDL32), a biological dispersant (DS2), and a nanopolysilicon hydrophobic system (NP12). The bacterial strain of CDL32 was used to obtain the culture colloid of biological emulsifier at 37°C for 5 days. DS2 was made from biological emulsifier CDL32 and some industrial raw materials described in Table 1 of the complete paper. Nanopolysilicon hydrophobic system NP12 was composed of silicon dioxide particles. The hydrophobic nanopolysilicons selected in this project featured particle sizes of less than 100 nm. In the original samples, a floc of nanopolysilicon was fluffy and uniform. But, when wet, nanopolysilicon will self-aggregate and its particle size increases greatly. At the same time, nanopolysilicon features significant agglomeration in water. Because of its high interface energy, nanopolysilicon is easily agglomerated, as shown in Fig. 1.


2021 ◽  
Vol 73 (09) ◽  
pp. 50-50
Author(s):  
Ardian Nengkoda

For this feature, I have had the pleasure of reviewing 122 papers submitted to SPE in the field of offshore facilities over the past year. Brent crude oil price finally has reached $75/bbl at the time of writing. So far, this oil price is the highest since before the COVID-19 pandemic, which is a good sign that demand is picking up. Oil and gas offshore projects also seem to be picking up; most offshore greenfield projects are dictated by economics and the price of oil. As predicted by some analysts, global oil consumption will continue to increase as the world’s economy recovers from the pandemic. A new trend has arisen, however, where, in addition to traditional economic screening, oil and gas investors look to environment, social, and governance considerations to value the prospects of a project and minimize financial risk from environmental and social issues. The oil price being around $75/bbl has not necessarily led to more-attractive offshore exploration and production (E&P) projects, even though the typical offshore breakeven price is in the range of $40–55/bbl. We must acknowledge the energy transition, while also acknowledging that oil and natural gas will continue to be essential to meeting the world’s energy needs for many years. At least five European oil and gas E&P companies have announced net-zero 2050 ambitions so far. According to Rystad Energy, continuous major investments in E&P still are needed to meet growing global oil and gas demand. For the past 2 years, the global investment in E&P project spending is limited to $200 billion, including offshore, so a situation might arise with reserve replacement becoming challenging while demand accelerates rapidly. Because of well productivity, operability challenges, and uncertainty, however, opening the choke valve or pipeline tap is not as easy as the public thinks, especially on aging facilities. On another note, the technology landscape is moving to emerging areas such as net-zero; decarbonization; carbon capture, use, and storage; renewables; hydrogen; novel geothermal solutions; and a circular carbon economy. Historically, however, the Offshore Technology Conference began proactively discussing renewables technology—such as wave, tidal, ocean thermal, and solar—in 1980. The remaining question, then, is how to balance the lack of capital expenditure spending during the pandemic and, to some extent, what the role of offshore is in the energy transition. Maximizing offshore oil and gas recovery is not enough anymore. In the short term, engaging the low-carbon energy transition as early as possible and leading efforts in decarbonization will become a strategic move. Leveraging our expertise in offshore infrastructure, supply chains, sea transportation, storage, and oil and gas market development to support low-carbon energy deployment in the energy transition will become vital. We have plenty of technical knowledge and skill to offer for offshore wind projects, for instance. The Hywind wind farm offshore Scotland is one example of a project that is using the same spar technology as typical offshore oil and gas infrastructure. Innovation, optimization, effective use of capital and operational expenditures, more-affordable offshore technology, and excellent project management, no doubt, also will become a new normal offshore. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202911 - Harnessing Benefits of Integrated Asset Modeling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field by Yukito Nomura, ADNOC, et al. OTC 30970 - Optimizing Deepwater Rig Operations With Advanced Remotely Operated Vehicle Technology by Bernard McCoy Jr., TechnipFMC, et al. OTC 31089 - From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil by Paulino Bruno Santos, Petrobras, et al.


2021 ◽  
Vol 73 (09) ◽  
pp. 55-56
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31284, “Greater Tortue Ahmeyim Project for BP In Mauritania and Senegal: Breakwater Design and Local Content Optimizations,” by Alexis Replumaz, Yann Julien, and Damien Bellengier, Eiffage Génie Civil Marine, prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. During summer 2017, the authors’ company was invited by BP to bid for the construction of a concrete caisson breakwater protecting an offshore liquefied natural gas (LNG) floating terminal at a water depth of 33 m on the Mauritanian/Senegalese maritime border. As a result of subsequent front-end engineering design (FEED) studies, including 3D model testing, the company was able to reduce the amount of concrete required by 40% compared with the initial design, leading to financial and environmental benefits. Introduction The BP Tortue development comprises a subsea production system tied back to a pretreatment floating, production, storage, and offloading (FPSO) unit, which transfers gas to a near-shore hub for LNG production and export. Phase 1 will provide sales gas production and domestic supply and will generate approximately 2.5 mtpa of LNG to Mauritania and Senegal. The Phase 1 FPSO, in 100–130 m of water, will process inlet gas from the subsea wells located across several drill centers by separating condensate from the gas stream and exporting conditioned gas to a hub, where LNG processing and export will occur. The hub, 10 km from shore, comprises a breakwater to protect marine operations, including LNG processing and carrier loading. A single floating LNG vessel will condition the gas for LNG export. Hub construction began early in 2019 and should be completed in 2021 for a first-gas target in 2022. The breakwater design was conceived during the bidding stage of the project at the end of 2017 by proposing an alternative design for the breakwater adapted to project-specific conditions and regional facilities. The design has been improved continuously and optimized during the FEED stage based on a collaborative approach between the client and the contractor. Client Preliminary Design Optimizations During pre-FEED and bidding stages, the client performed an intensive geotechnical campaign based on several shallow and deep boreholes and a large-area geophysical survey. In water depths greater than 18 m along the maritime boundary between Mauritania and Senegal, a significant layer of soft soil exists, except around the outcrop located on the west side (10–11 km offshore in approximately 33 m of water). Although rock quantities could be slightly higher in the western location, the reduction of the dredging quantities and the reduction of the effect on the nearby coastal community of Saint Louis (lighting, noise, and vessel traffic) led to selection of this location for the hub terminal. The initial breakwater type was a rubble-mound structure. However, a composite breakwater (caisson on berm foundation) allowed for optimization of dredging and rock quantities. The change in breakwater type allowed a rock-quantity drop from 5.8 million to 1.1 million m3.


2021 ◽  
Vol 73 (09) ◽  
pp. 53-54
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31250, “Wandoo B: Application of Advanced Reinforced Concrete Assessment for Life Extension for Non-Jacket Structures,” by Robert Sheppard, Spire Engineering; Colin O’Brien, Vermilion Oil and Gas; and Yashar Moslehy, Spire Engineering, et al., prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Wandoo B is a concrete gravity-based structure (GBS) and is the main production facility for the Wandoo field offshore northwest Australia. It was installed in 1997 with a design life of 20 years. The structural assessments discussed in this paper are part of a comprehensive life-extension project encompassing wells, subsea systems, marine and safety systems, and topsides facilities and structures to demonstrate fitness for service through the end of field life. Background The GBS serves as the support structure for the Wandoo B facility and provides oil storage for the Wandoo field. The structure has four shafts approximately 11 m in diameter that support the top-sides facilities and a base structure with permanent ballast and oil storage cells (Fig. 1). It was originally developed as an ExxonMobil-led project and now is owned and operated wholly by Vermilion Oil and Gas Australia. The reinforced concrete (RC) shafts and the base top slab are pretensioned. In the shafts, tendons are enclosed in 20 ducts distributed around the circumference. The top of the shafts provides a mating point with the steel topsides structure with the connection formed by embedded anchor bolts in a bulge in the shaft cross section. The topsides structure is a three-level braced steel frame system supporting production operations for 12 well conductors contained within the northeast shaft and three outboard well conductors. Life-Extension Project The facility was designed with a target life of 20 years. The life-extension project was intended not only to satisfy the operator’s responsibility to continue safe operations and adhere to their safety case but also to meet the expectations of the regulator. The structural aspects of the project included four phases, the first two of which are detailed in this synopsis: - Design assessments per latest standards and modifications where required - Ultimate capacity assessments with retrofit modifications where required - Risk studies and workshops to demonstrate that risk is as low as reasonably practicable (ALARP) - Integrity-management manual and inspection plan The first two phases were addressed using the latest condition-assessment, weight, and environmental data available. The phased approach allowed the assessment team to use basic linear approaches to demonstrate code compliance and only use the more-advanced analysis techniques to evaluate the critical components that did not satisfy code or were needed to provide input to the ALARP assessment and establish target reliability for the facility.


2021 ◽  
Vol 73 (08) ◽  
pp. 63-64
Author(s):  
Chris Carpenter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30732, “Economic Feasibility Study of Several Usage Alternatives for a Stranded Offshore Gas Reservoir,” by Khoi Viet Trinh, SPE, and Rouzbeh G. Moghanloo, SPE, University of Oklahoma, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. This paper compares economics of a floating liquefied natural gas (FLNG) project with those of an onshore LNG plant and gas-to-wire (GTW) processes. Sensitivity analyses and tornado charts are used to evaluate the importance of various uncertain parameters associated with FLNG construction and operation. This study will be helpful for future considerations in using FLNG to convert offshore gas reservoirs previously considered stranded into economically viable resources. The results from this economic model can play a key role in the future of the natural gas industry and energy market in West Africa. Assumptions Before presenting different economic scenarios, the following assumptions must be established: * The pipeline will have the correct diameter, pressure rating, and metallurgy to transport produced gas. Only the pipe length will be considered a variable. * Operating expenses (OPEX) of both onshore LNG and FLNG will be the same. Realistically, however, OPEX of FLNG will be different from that of onshore LNG. * A subsidy from the Nigerian government has been obtained for the onshore LNG plant. * The electricity price is assumed to be $0.25/kWh. * An assumed upstream cost of $2/Mscf to cover onshore LNG gas pretreatment is assumed. * The onshore LNG plant and FLNG will have the same lifespan. However, in reality, availability of FLNG can be lower than that of onshore LNG. Pricing Models FNLG. Because of the relative recency of FNLG, few pricing models have been readily available. For the complete paper, Shell’s Prelude project is the basis for pricing of FLNG. Prelude costs averaged out to approximately $14 billion, which will be used as the cost of the facility for the FLNG scenario in the economic analysis.


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