Welcome and Introduction - David Paganie, Conference Manager & Chief Editor; Offshore

Minister's Welcome - Hon. George Papanastasiou, Minister of Energy, Commerce and Industry

Chairman's Opening Remarks - Demetris Fessas; Acting General Director; Cyprus Hydrocarbons Company

Keynote Presentation - Kristian Svendsen, Country Manager, Egypt and Cyprus; Chevron

Keynote Presentation - Hon. Osama Mobarez, Secretary General; Eastern Mediterranean Gas Forum

Coral South Project comprises the installation of a floating liquefied natural gas facility (Coral Sul FLNG) to gather the gas production from six (6) wells at 2000 meters water depth. The project is operated by ENI on behalf of Area 4 partners and is located 80km offshore northern Mozambique in the Rovuma Basin. The FLNG has a nameplate production of 3.4 MTPA and a design life of 25 years. It is the world’s first ultra-deep water FLNG, Africa’s first full function open sea FLNG and first in Mozambique. Coral-Sul FLNG has an internal non-disconnectable turret system to transfer fluids and control to the subsea field and it is the world deepest and largest internal turret for ultra-deep water designed to sustain cyclonic conditions. Coral Sul Subsea Production System consists of three (3) production clusters with a dedicated double looped subsea flowline and an umbilical for control and chemical supply. Subsea dual headers and 2 hubs integrated manifolds allows production collection from gas producers, control (hydraulic and electrical) and chemical distribution to each well. The subsea production well is equipped with a 7x2’’ Horizontal Xmas Tree including choke and wet gas flow meter system. Subsea wells completion development has been carried out between March and November 2021 by drillship in SIMOPS with the Installation campaigns throughout 2021. SURF installation involved subsea structures (Manifolds and Xmas Trees), flexible flowlines & risers, umbilicals and multibore wellhead jumpers. Installation operations and Drilling & Completion campaigns have been successfully executed with the support of Pemba logistic bases. FLNG departed the fabrication yard in South Korea mid-November 2021 and arrived in Mozambique operations site in early January 2022 with all the offshore installation campaign for the mooring and hook up of the subsea production system occurring in the most challenging period due to the potential for cyclones to occur. This presentation highlights the experience and lessons learned gained during the subsea production system installation, turret fabrication and all the planning and challenges faced during the FLNG mooring, offshore installation and SURF hook up activities.

The presentation will focus on the main functionalities deployed on the first ever deep offshore FPSO deployed in the East Med “the Energean Power”, and one of the first of its kind “Gas Driven” FPSO.

This presentation provides an assessment of CAPEX savings opportunities when deploying unconventional technologies for long distance tiebacks. The assessment includes two different tieback scenarios (200km and 400km) where the reference case is conventional electro-hydraulic architecture, and comparing it to the following alternatives: (a) electro-hydraulic controls with hydraulic-only umbilical + DC/FO; (b) All-Electric Subsea (AES) + 3kVDC power transmission; (c) All-Electric Subsea + DC/FO.  
 
Authors: Lee Mitchell, Masoud Hajiaghajani

This presentation will provide a brief technical description of the offshore section of the EastMed Pipeline Project.

The Energy Trilemma refers to the balancing act of three energy policy concerns often in conflict with one another; energy equity, energy security and energy sustainability. The ripple effect of the Ukraine invasion has cause significant disruption to the Trilemma by threatening to shrink the economies of some of the most vulnerable parts of Central and Eastern Europe and creating bottlenecks in the supply of natural gas across the continent. While diversification into renewable energy sources forms part of the REPowerEU plan from the Council of the European Union, natural gas as an energy source will continue to play an important role in the transition to clean energy due to its reliability and affordability. As energy demand continues to increase and exploration moves deeper offshore in harsher environments, subsea gas compression can keep the gas flowing and extend the operating life of existing, depleted gas fields. The successful run of the Åsgard Subsea compression system since 2015 is expected to extend the field’s life to 2032 and boost recovery by an additional 306MMboe. This success has enabled the system to now be deployed in Australia (Jansz-Io offshore field), as the country looks to secure its own long-term natural gas supply. When compared to fixed or floating topside solutions, subsea solutions have significantly lower power demands, lower carbon footprint and is inherently safer, cutting down on labour costs and manual operations in harsh climates. This presentation will cover how subsea gas compression is a cost-efficient solution in securing long-term natural gas supply in the present economic and political climate where exploration of deeper plays is expensive and energy security is a real threat.

Natural gas production plays a strategic role in the energy transition plans of European countries, international and national oil companies. Multiple Deepwater gas discoveries in the Mediterranean region can be developed to meet the increasing gas demand in Europe. The main characteristics of this specific region are a combination of stranded Deepwater gas reservoirs, and often ultra-long tie-back distances of up to 400km between subsea production wells and host facilities that may either be located offshore or onshore. This presentation will give an overview of the following technologies and how they can be combined to unlock the full value of Deepwater gas field developments: instrumented all-electric subsea production systems, power distribution, fiber optics communication, and cloud-based remote production monitoring & optimization digital solutions.

Subsea control systems for the control of subsea trees, manifolds and processing systems are today highly reliable. Flexibility is ensured and project specific engineering is eliminated by the “configure to order approach”. The presentation will cover a brief historical overview of how control and monitoring of subsea wells has developed, including the implementation and impact of new technologies and shifts in working processes. Following the brief historical overview, the presentation will describe main features of and share experience from the implementation of the state-of-the-art series subsea controls. Specifically addressed is: -Development of “Mean Time To Failure” (MTTF) of subsea controls, discussion on reasons for the significant increase experienced -Backwards compatibility, how current products and technology can be applied to upgrade systems with 20+ years in service -Options for long distance control, 250 km and beyond -Integration of fiberoptic sensing, including Distributed Acoustic Sensing (DAS) -Hybrid electric and full electric subsea control, experience from more than 500 subsea electric actuators in service -Integration of High Integrity Pipeline Protection (HIPPS) functionality -Integration of advanced downhole completions, with many zones and high power draw The presentation is aimed to provide the audience with an overview of subsea production system control, and which features are naturally integrated to optimize the system performance.

The presentation will focus on the first stage of the roadmap covering the first 18 months to high pressure hydrocarbon testing. A review of the scientist basis of the testing envelopes, linked to field studies, CFD work through the evaluation of the design and the low pressure prototype testing and how these and other factors relate to the higher concept design. The reasoning behind the use of a magnetic drive subsea pump within the test coupled with using a subsea control system. The goal of this presentation to demonstrate the basis and roadmap of the preproduction qualification work.

Subsea tiebacks of increasingly long distance are being considered in multiple regions globally. In mature hydrocarbon production basins such as the North Sea and the US Gulf of Mexico, longer distance subsea tiebacks offer an opportunity to maximize production from existing hub facilities, reducing the development cost of new fields. In other regions, such as the East Mediterranean, Western Australia, and South-East Asia many fields are remote, often in very deep water. Delivering these fields as tiebacks offers significant CAPEX and OPEX economies compared with the procurement of new deep-water floating production units. Whilst there are significant potential benefits of delivering these future developments as subsea tiebacks, these long-distance tiebacks face multiple technical and commercial challenges such as: •Challenging flow assurance requiring chemical injection, subsea pumping, pipeline heating. •Supply chain constraints such as the reducing capacity of umbilical manufacturers with the increasing demand for subsea cables driven by offshore wind projects. •Equipment reliability. •Challenging risk profiles, such as the CAPEX impact of umbilical failure on long distance projects. Multiple new technologies are being developed and evaluated to overcome these and other technical and commercial constraints to long-distance tiebacks, and it is considered likely that future long distance tieback projects will utilize a new toolkit of technologies, with specific initiatives selected to both de-risk the developments and improve the economics of the project. One technology building block being considered for future long-distance tieback projects is the use of a buoy at the wellsite to provide power, control, remote communication facilities to the subsea equipment, in lieu of a long-distance umbilical from the host facility. This presentation provides a techno-economic assessment of using a utility buoy to provide power and control to a subsea tieback compared with a long-distance umbilical. A case study is presented detailing a utility buoy solution for a long-distance tieback project, based on BPT’s proprietary ‘Floating NUI’ buoy technology. The presentation will illustrate the functionality provided by the buoy technology, contrasting CAPEX, OPEX, and risk profile compared with a traditional umbilical solution.

Chevron operates the Tamar and Leviathan deepwater gas production assets offshore Israel. The subsea system consists of high flow rate wells connected to a subsea manifold and through long gathering lines to the production platform. The system is directly tied to the national grid supplying natural gas for electricity production in Israel, Egypt and Jordan. Due to the high criticality of both Tamar and Leviathan assets, a comprehensive Integrity Management plan was created to ensure continuous production. The plan consists of a risk-based matrix for the subsea equipment, pipelines, jackets and controls equipment. The use of the IM plan led the team to discover several issues that could potentially cause a disruption in the gas flow, that could potentially lead to commercial and reputational impact. A case study will be presented to demonstrate the importance of the IM plan in identifying the issue and the remediation plan: UTAs (Umbilical Terminal Assembly) OFL (Optical Flying Lead) receptacle calcification buildup.

The state of wetgas metering technology today is such that with the right combination of electromagnetic, Venturi and gamma measurements; gas, oil and water flow rates can be calculated to an uncertainty that allows them to be used for fiscal allocation. The technology is often extended to detection of formation (saline) water breakthrough using electromagnetic measurements. The detection of saline water is critical in high gas-fraction wells for flow assurance purposes, including scale, hydrate and corrosion management. However, the small volumes of produced water makes the distinction between condensed and formation water a very challenging task. In some applications, this is further complicated by the fact that MEG is injected upstream of the wetgas meter The management of sand erosion is also a challenge for gas production systems, especially if high flow velocities are expected. Excessive erosion in the Subsea Production System (SPS) may compromise asset integrity or the functionality of critical components, such as the choke valve. Production constraints may necessarily be imposed based on conservative assumptions for sand loading. Access to reliable erosion monitoring information is therefore critical in the optimization of the well operational envelope. The paper will present a state-of-the-art technology for wetgas flow measurement which has been extended to meet the challenges described above via the following developments: 1)Formation Water Detection using complementary methodologies of electromagnetic measurements and PVT predictions. Each method has its own sensitivities, but when combined provide a high degree of flexibility to the specific production scenario. The impact of chemical injection shall also be described. 2)An improved wetgas meter design which has been optimized for ultra-high GVF wells where sand erosion is a concern. The impact of which is an increased maximum gas flow rate that can be accommodated. 3)The use of ultrasonic Wall Thickness Monitors (WTMs) integrated into the wetgas meter in specific locations and used to quantify erosion over longer time frames than is typically possible using traditional sand detection methods such as Acoustic Sand Detectors (ASDs).

Challenging reservoir conditions and modern flow assurance strategies require extreme sensitivity and real-time data. Water is the most significant and hazardous risk involved in producing subsea gas reservoirs and it is of paramount importance to early identify and measure water breakthrough and to have a robust hydrate management system. This presentation will discuss how subsea flow meter solutions can help, with field examples to support the premise from projects in the Eastern Mediterranean.

The design of subsea production system components such as flowlines, risers and jumpers, shares many similarities with oil production systems. The presence of multiphase flow is a unique feature of gas systems, that not only requires special consideration but can also be the key design driver, affecting fabrication and system cost. The multiphase flow through the pipe can result in different flow regimes, that can cause different types of vibrations on flowlines and jumpers. These flow-induced vibrations (FIV), result in significant fatigue damage that typically require the use of high-quality welds, with strict fabrication requirements. FIV of pipelines and jumpers also requires in-situ monitoring to confirm the design and manage the integrity. This presentation will focus on the FIV of flowline spans and jumpers, explain the importance and implications on design. The importance and use of structural response monitoring will be presented, providing example applications and describe the monitoring systems used. The presentation will also highlight the use of monitoring data to validate design and manage integrity.

The impact of Pandemic has increased the demand for personnel limitations on FPSOs and offshore platforms, not only from a cost perspective but also from an HSE perspective. This presentation presents steps toward a Normally Unattended FPSO.

Subsea 7’s “Make Possible” strategy focuses on providing a more sustainable energy mix (conventional & renewables) to tackle climate change. it is our position that data stack has an impactful value proposition. Unlocking this value for the energy industry is deemed essential to increase efficiency and deliver projects more effectively from early concept engagement, through project execution and through life-of-field. In 2021, Subsea 7 technology development instigated an on-going case study (managed by the author) aiming at evaluating the value proposition of digitalizing the data from a recently executed development offshore Norway, as a case study for digital service delivery. Subsea 7 was well positioned to tackle this case study with its expertise in technology development, product/discipline specialist knowledge, integrity asset management, a burgeoning digital transformation group and recent acquisition of two key players in the digital transformation market: 4Subsea and Xodus-Group. This collaboration was enforced by alignment from the operator providing permission to use live project data. The project focused on capitalizing on the temperature data from the first functional 20km Electrically-Heat Traced Flowline; namely EHTF®, a subsea pipe-in-pipe system with electrical heating wires and fiber optics in a partially vacuumed annulus. The fibers are used for distributed temperature sensing, providing a temperature reading every meter along the flowline length. The project scope is offshore data acquisition to the cloud, processing the data to produce valuable output and visualization of this output on a platform that provides the end user with insight allowing sustainable operations. The acquisition of data was performed through successful collaboration with the operator to ensure the required cyber security is maintained. The temperature data was then processed and correlated to other design parameters to monitor and report on the temperature profile and trends along the flowline, thermal insulation efficiency, thermal ageing of the EHTF components – with more use cases in development. The resultant processed data is then visualized on dashboards showing status, provide warning/alarms, and operator recommendations where applicable. The data processing is performed on 4insight® cloud-based platform, where all stakeholders have a common integrated interface.  To-date the project has underlined the main value for digital service delivery: efficient asset life-of-field management. This value can be captured by reducing production & integrity risk through proactive asset monitoring and management, allowing for a more effective decision-making by operators for operational & Inspection, Repair & Maintenance (IRM) activities, improving vessel utilization, thus reducing associated carbon emissions. From a broader perspective, the value can be seen by avoiding unplanned downtime, validating, and expanding operational envelopes, and allowing SME-assessed automated reporting. Furthermore, the benefits feed-back through the contractors and suppliers, alongside the operator, with insight validating the production and integrity envelopes through the production life cycle: fabrication, installation & commissioning. Geared with such knowledge, conservatism is reduced, system usage is improved, and the understanding of design and project delivery is enhanced.

Design execution, delivery and management of operations of oil and gas facilities involve complex and iterative processes spanning a long period of time from concept to decommissioning. In such complex and large projects, several teams and disciplines participate to the common effort, with their expertise and tools, to provide an overview of the project that is, at the same time, as complete as possible, and manageable. In this process however, teams often work in siloses, with complex and repeated hand over of information and additional effort of coordination. The risk represented by lack of coordination or communication may be severe, especially if not mitigated by sufficient margins. However, as the industry evolves towards improved efficiency, reduction of carbon footprint and, in general, a more sustainable configuration, there is increasing demand of managing uncertainty and complexity, to reduce risks, improve profitability and operate safely. In this work we introduce a novel approach to modelling and simulating the facilities through an Integrated Asset Model (IAM) through a continuous model of the entire asset, from the reservoir to the process. As the project is enriched with details, the model evolves to a real time digital twin, which enables engineers to improve efficiency by breaking down the barriers between disciplines and improving sharing of information and decision-making. In this paper, we show how a more holistic approach to the entire asset can deliver better returns on capital and improve the economics of the entire project. We explore the detail of connecting real time data with rigorous simulation and consistent thermodynamics throughout. This then leads to a single true representation, removing conservative design margins and inconsistencies in operational data; saving your assets time and cost in both the design and operations phases of their lifecycles.

After years of growing concern over climate change, energy companies are striving to develop viable technologies using their expertise to reduce their carbon footprint. Carbon Capture and Storage (CCS) technology has strategic interest for two reasons: firstly, it is one of the pillars of a net zero strategy thanks to the capability of directly reducing part of the emissions related to the business; secondly, CCS is emerging as a new market to provide decarbonization solutions to the industry such as the hard-to-abate sectors. Depleted reservoirs at the end of their productive life offer convenient opportunities to develop CCS hubs. Offshore CCS projects are nowadays largely limited to shallow water, but deep water CCS developments are likely to play a crucial role in the next future as the storage demand grows. The aim of this presentation is to show specific requirements and related architectures for a subsea system able to inject carbon dioxide in depleted reservoirs, with interest in new technologies addressing cost-efficient solutions. The design of a subsea injection system is affected by a large number of parameters. Among them are the step-out distance from the host facility, the water depth of the injectors, the thermodynamic conditions and the flow rate of the carbon dioxide, reservoir conditions, and the wellhead locations on the seabed. This presentation isolates all these parameters and discusses their impact in terms of CO2 phase behaviour (gas, dense or liquid) and operability of the injection (single or multi-phase). Sensitivities of these parameters were performed and implications in the overall development are presented. Different sets of parameters were then selected to build up some realistic case studies, leading to different suitable subsea architectures. The proposed subsea architectures are underpinned by a set of emerging concepts and technologies, as well as state-of-the-art products. Among them, the subsea electrification – together with the DC/FO cable – can remove the need for hydraulic-chemical distribution provided that the injection parameters are such that no inhibitor is required. Furthermore, downhole chokes could allow for the regulation of flow downhole, thus preserving the subsea injection equipment from issues such as low temperature due to CO2 phases changes. This presentation shows how new technologies can provide effective and cost-efficient solutions. The proposed architectures are compared to a baseline gas production development, highlighting potential simplifications of the system and cost saving areas.

Operator led dialogue on the key energy transition opportunities