THE PROGRAMME

09.30

Welcome and Registration

10.00

Opening Remarks

10.10

Reducing Maintenance Costs & Improving Safety with Robotics

Paul Stockwell, Managing Director, Process Vision Ltd

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The use of robotics in the oil and gas industry is becoming a hot topic. This paper reports on the progress and challenges of a project, to develop a robot snake. It comprises of a manoeuvrable optical system, which can monitor the internal operation of processing systems while the plant is operating. The small diameter snake provides a live video feed to provide real time operations for equipment inspection and troubleshooting.

It is designed for high pressure combustible gas systems and is anticipated that the robot will be able to safely access systems via existing tapping points and become a versatile tool to perform a number of tasks that currently require a plant shutdown. It will have the ability to investigate the internal condition of piping and pressure vessels Additional tools will enable operators to troubleshoot operations problems such as foaming or fouling.

The aim of the project is to: increase availability by reducing the need for inspection shutdowns; improve safety by reducing the need for confined space working; reduce shutdown durations as on-line diagnostics will help shutdown planning and logistics.

An invitation to a demonstration day in 2020 will be offered to delegates.

10.40

Coffee Break

11.25

Highly Sour Gas: The Best Options to Process It

Manuel Jacques, Damien Menet and Christian Bladanet, TechnipFMC

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TechnipFMC was appointed by one its major client to conduct a feasibility study for the development a highly sour gas-condensate field. Sour gas levels are in the range of 22-28%vol of H2S and 13-17%vol of CO2 and contains also organic sulphur components such as carbonyl sulphide, mercaptans and disulphides.

The study addresses the evaluation of onshore technologies for gas and condensate processing (gas sweetening, gas dehydration, NGL recovery, condensate stabilization and sweetening) for five different set of export product: sales gas, LPGs, hydrocarbon condensates, Sulphur or re-injection of the acid gases, with the objective of selecting the most attractive scheme based on economic  and HSE criteria.

Using this case study, this papers aims to present the methodology,  the different process  configuration screened, including the latest development in sweetening technologies and acid gas reinjection, the pros and cons of each technology, and the influence of basic technico-economic parameters on the plant architecture and technology selection.

11.55

Val D’Agri oil and associated gas increases, how gas processing challenges were solved

Luca del Monaco, Eni SpA and Ricardo A. Gonzalez, Shell Global Solutions International B.V.

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​In 2008, ENI (operating partner) and Shell Italia EP (non-operating partner) planned to increase oil production in Val D’Agri, ultimately increasing associated gas. To process the increased associated gas without altering the Sulphur recovery trains, an acid gas removal unit (AGRU), an acid gas enrichment unit (AGEU), and a thermal oxidizer was designed. In 2009, it was discovered that the additional associated gas contained more mercaptans than expected, which warranted the project scope to be re-assessed. During this evaluation, it was determined that the proposed design could not satisfy the requirements of processing the desired gas throughput without sacrificing sales gas specifications or stack SO2 emission specifications. Different design options were evaluated to meet the specifications while minimizing the modifications to existing equipment and the original design. The chosen solution maintained the design but was enhanced by swapping the solvents in the AGRUs and the installation of a CANSOLV unit downstream of the thermal oxidizer to remove SO2 produced by the combustion of additional mercaptans. This paper details the challenges in debottlenecking Val D’Agri to process the increased associated gas, the advantages and disadvantages of solution options, and some of the lessons learned from a CANSOLV unit in operation.

12.25

Lunch

13.40

Innovation in Materials Development for LNG Dehydration

Tobias Eckardt, BASF Catalysts Germany GmbH and Eduard Wolf, BASF SE

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Effective dehydration of natural gas to cryogenic specification is a critical stage of the pretreatment train for LNG production. Zeolitic molecular sieves are the only class of adsorbents capable of meeting the required dewpoint for liquefaction. Failure to reach the required dewpoint or inability to maintain the necessary gas flow to the liquefaction section can constrain or shutdown the production of valuable LNG cargo.

The existence of physical effects such as refluxing and retrograde condensation in the dehydrator vessels during regeneration and adsorption are well understood. These effects are known to lead to degradation of the molecular sieve adsorbent by leaching of the clay binder and loss of adsorption capacity. The resulting increase in pressure drop and mal-distribution of either the regeneration or adsorption flow may ultimately require premature adsorbent replacement. Improving resistance to refluxing has focused mainly on improvements to the molecular sieve binder system, whereas reduction of the tendency for refluxing may be mitigated by better management of regeneration.

This paper presents an innovative approach to the refluxing problem based on materials development. This innovation is supported by many years of successful and highly durable installations in cryogenic applications. The paper describes the first retrofit installation of this new development in dehydration of gas for LNG production. It will also discuss potential benefits for new installations such as reduced vessel size and operational security in addition to extended bed lifetimes which could be achieved for existing units.

14.10

ssLNG to Power Plants for Distributed Power Generation

Robert Brannock, TGE Gas Engineering

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Forced by forecasted continuing cost advantages LNG versus oil and the worldwide efforts of CO2 emission reductions, more and more power plants shall be switched from oil-fueling to gas fueling. For remote locations, where no natural gas pipeline grid is in the vicinity, ssLNG-to-power is the fuel-supply solution for an adjacent gas fired power plant. The power generation in remote areas usually amounts up to 300 MW, that corresponds to LNG fueling of around 0.5 MTPA. The required LNG fuel supply can be established via barge, trucks or rail cars.

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LNG advantages versus NG from pipeline can also be used in such installations. These terminals can be equipped with additional LNG distribution facilities, e.g. LNG ISO-container loading for subsequent supply of LNG satellite or fueling stations. Another LNG advantage is the provision of cold to the adjacent power plant that implies potential of efficiency increase during power generation.

Rapid installation time and a cost beneficial solution are usually important for the customers in this business. To achieve this, a modular design approach combined with a high level of standardization for the small-mid scale LNG infrastructure are essential success factors. Depending on the individual project the standardized and modular design approach allows optimized execution by selection of either maximizing prefabrication or in-situ construction. This design approach brings clear advantages in plant expandability while providing for fast track project delivery with shortest time to commercial operations and an optimized return on investment.

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Synergies during planning, construction and operation of the total installation comprising LNG terminal and power station should be maximized. This presentation details such synergies as well as the technology, appropriate execution philosophy and proven solutions.

14.40

Coffee Break

15.25

Benefits of an integrated approach to enhance F&G detection on a FLNG

Guillaume Breysse and Damien JENN, TechnipFMC, Lyon Operating Center

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The aim of F&G systems is to detect a fire or a flammable gas leak sufficiently early to alert and initiate appropriate actions before a catastrophic  event. Once located by prescriptive rules, F&G detectors can now be specified through F&G Mapping, which is becoming an effective way to achieve coverage performance targets.

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In 2017, an in-house F&G Mapping study was carried on a FLNG EPC project with more than 1 000 detectors. This study involved many stakeholders and a robust workprocess but enables TechnipFMC to effectively optimize the design, the CAPEX, the planning and to maintain accurate knowledge of the study.

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Based on a geographic approach, defining flammable gas cloud size generating an overpressure greater than 150 mbar was a key step. As the overpressure developed by the explosion is a complex mechanism involving numerous parameters, Computational Fluid Dynamics (CFD) calculations were performed to model explosions and subsequently retrieve relevant gas cloud sizes . Building on TechnipFMC expertise in flame leak physical properties and fire mapping practices, this resulted in optimized detectors locations taking into account modules/decks specificities.

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This paper will provide an insight of the method and results of F&G mapping studies performed on TechnipFMC projects.

15.55

FLNG to Subsea… are you following me?

Andrew Loose and Stewart Taylor, KBR

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Most onshore LNG plants and at-shore floating LNG barge units are fed from extensive pipeline networks which create a large gas inventory buffer such that any interruption event at either the LNG plant or the gas source is easily managed by the control systems. In contrast, a unique feature of most offshore FLNG facilities is the very limited gas inventory in the short flowlines and risers between the subsea wellheads and the inlet of the gas pre-treatment unit. This close coupling and small inventory can give rise to some significant dynamic interactions between the FLNG liquefaction plant and the subsea wells, particularly for wells with a high design pressure. As such the design and control of the subsea system and FLNG topside process must be considered together as an integrated system and not in isolation. It is recognised that the liquefaction capacity of an FLNG unit relates to the gas turbine (GT) power available to the compressors. GT available power varies with ambient temperature and hence LNG production follows both the diurnal temperature swing and the seasonal ambient temperature variations as the control system functions to maximise the LNG production at any time. As the LNG production fluctuates with ambient temperature so too does the feed gas supply. Without any active control of the subsea chokes the amplitude of the oscillations can be quite significant, especially in early morning and evening when the ambient changes most rapidly, causing packing and unpacking of the flowlines and risers as the topside pressure reduction valves operate to maintain a steady feed gas supply pressure to the inlet facilities. This paper discusses the interactions between the subsea system and the liquefaction unit and presents the results from an integrated dynamic model that demonstrates how stable operating conditions can be achieved under all scenarios.