Subsea 7 (France)

Abstract High pressure, high temperature deepwater field developments are becoming common in our industry. This combination can result in thick insulation coatings on heavy wall pipelines that require high-top tensions and subsequent shear forces for installation. This type of pipeline behaves as a steel and polymer composite that must maintain structural integrity under such loads. Wet Thermal Insulation standard exists for the coating applicator to validate the thermal performance and shear resistance of a wet thermal insulation system. However, the industry does not have guidelines in understanding the causes and sequence of events that would lead to a product defect or failure, due to the shear forces applied by a vessel’s tensioner or hang of module (HOM). A testing philosophy was developed to understand the coating’s sensitivities to welding thermal cycles, and installation loads. The understanding provides guidance on mitigating defect/failure risks and assigning a recommended safety factor for high shear loads during reel lay operations. The test philosophy included a ‘unit cell’ approach, which was a set of laboratory shear tests that replicated the installation conditions. The test procedure was then used to develop a finite element model which gave comparable results to the test. This paper presents the case for the industry to have guidelines to understand the potential causes and sequence of events that would lead to a coating defect or failure during installation.

Abstract Torpedo piles have emerged as a compelling alternative to conventional suction piles for anchoring floating facilities in deepwater developments. Gaining momentum in the offshore industry over the last decade, their design has been enhanced through specialised laboratory tests and the application of analytical and numerical tools. However, compared to suction piles, there is limited field data on torpedo piles, as their primary use has been in offshore Brazil. This study is the first step of a series of analysis on torpedo piles aiming at further developing design and installation. Various aspects of the torpedo pile solution need to be thoroughly studied, should this concept prove pivotal in competing with conventional suction piles in offshore frontier acreage. Elements such as anchor dimensions and thus holding capacity, fabrication, transportation and installation costs need to be evaluated in search of the most optimal solution. Leveraging recent installation feedback from Subsea7 on torpedo piles T-120 and existing literature, this paper presents an interdisciplinary assessment and comparison of suction and torpedo piles. It also includes an analysis of the novel finned pile design, currently applied in an ongoing Subsea7 project in Brazil. The paper comprises finite element analysis (FEA) to compare holding capacities and offers insights into installation, transportation and fabrication costs of both anchoring systems.

Abstract This paper is a summary of a study that covers through-life economics for producing green hydrogen from offshore fixed wind turbines. The options compare production of hydrogen on the turbine itself (decentralised) with production on a dedicated production platform (centralised) and production from an onshore facility. The economic analysis uses opensource hourly wind data from a windfarm development in the North Sea. The basis of calculation assumes a 1GW development using an array of 15MW turbines. The hydrogen infrastructure is sized at 80% of the turbine capacity. CAPEX, OPEX and revenue calculations are generated from data available to the partnering companies. Sensitivity analysis is performed to investigate the effect of tie-back distance (20,50,100 and 200 km). The results of the economic analysis show that decentralised hydrogen production can be competitive against onshore production at longer offshore distances. The results of flow calculation will show typical pipeline sizes required for infield gathering and export pipeline systems. The results show that electrical system losses over longer distances and the additional costs of cables compared to pipelines have a significant influence on through life economics. The study will present the distribution of the various elements of the CAPEX and OPEX cost for each option as well as the sensitivity to hydrogen commodity price and indicate where it needs to be before these projects become viable. Furthermore, the study concludes that the centralised option is less competitive due to the additional costs of structures and foundations.

Abstract As oil and gas exploration is moving to deeper waters, a key challenge is to design risers in harsh environments. Steel catenary risers (SCR) are cost-effective solutions that have been used in offshore developments due to their simplicity and robustness. However, stresses at the touchdown zone (TDZ), in such configurations are very large in ultra-deep waters for FPSOs in harsh environments leading the solution to become unfeasible in some fields. Therefore, steel lazy-wave risers (SLWR), are the market solutions for those fields. Nonetheless, SLWRs are, normally, longer risers with buoyancy modules, which increases installation time and overall cost. Gimbal Joint Riser (GJR) provides an alternative to reduce stresses at TDZ in SCRs. It is a patented device that comprises a series of hinged connection elements placed around a flexible pipe. This mechanism articulates, absorbing the energy coming from the motion of the hang-off, thus reducing stresses at TDZ. GJR is currently under qualification process. Recently, an experimental campaign involving two small scale models have been concluded. This paper brings a summary of the improvement in the GJR development obtained from these tests. A numerical model has been built to represent the experiments and the results of the calibrated real scale model derived from the experimental outputs are also presented. Results show a significant mitigation in the compressive wave at the TDZ of between 50% to 70% reduction in energy in comparison to SCRs.

Abstract Objectives/Scope The Praline project was awarded and executed during the COVID-19 pandemic and demonstrated how the right project management principles created transparency and trust between Contractor and Company so that both parties worked openly during project execution to successfully execute the scope in the required timeframe. Methods, Procedures, Process This project showcases how creating the right project environment fostered creative engineering, operational flexibility and collaborative decision making. A gate system was developed which enabled several solutions to run in parallel and focused on key dates for specific decisions which allowed for the final offshore scenario to be vetted. In addition, daily task orientated meetings were held with a small team to communicate updates and plans on specific topics between key stakeholders. All attendees were empowered to make decisions and progress tasks in the meeting. A lean and agile approach was deployed. Results, Observations, Conclusions The project was able to overcome numerous challenges during a pandemic in a short timeframe by implementing a fast-paced decision-making process which was underpinned by high-level trust between LLOG and Subsea 7. The project shifted from a plan to install the entire pipeline, In-Line Sled (ILS) and Pipeline End Termination (PLET) in a single trip to using multiple assets and mobilisations. The asset changes were required to maintain LLOG's first oil requirements and meant that the design, installation engineering, and procurement activities needed to be condensed and yet still meet high quality and safety standards. The changes in installation assets impacted the structures designs due to the installation equipment and this had a knock-on impact to the procurement and fabrication activities. One example was that the ILS needed to be redesigned to change the mudmat foundation and use an existing foundation from another project. This scope was completed in less than four weeks from the implementation of the vessel change and could only have been done through the transparent and collaborative approach established on the project. Novel/Additive Information This paper showcases how collaboration and transparency between all stakeholders enabled fast-paced decision making and selection of the optimal offshore solution in a condensed time frame.

Abstract Deterioration of carbon steel water injection subsea pipelines caused by internal corrosion is a common problem in oil fields around the world. Addressing this issue requires costly and complex water management solutions or could lead to reduced performance and total replacement of corroded pipelines. This paper shall present the Polymer Lined Pipe (PLP) technology, a field proven solution to the water injection corrosion challenges, extensively used in the North Sea. A description of the key building blocks and the recent technology qualifications shall highlight the latest product development. Eventually, the main fabrication and installation steps shall be presented in view of a regional PLP application. A regional business case comparing the three water injection corrosion approaches shall highlight the typical economic metrics that could be achieved thanks to the use of PLP technology. Today, this technology is accessible to operators in the Asia Pacific region with the recent opening of the Bintan Spoolbase in Indonesia enabling the deployment polymer lined water injection pipelines using the reel-lay method of installation. The strategic location of the spoolbase eliminates the significant intercontinental transit costs and the reel-lay method reduces offshore vessel days normally associated with conventional pipe-lay methods (S-lay and J-lay).

ABSTRACT The developments in deep and ultra-deep waters require the application of heavy wall pipes for steel risers in conventional grades. The utilization of higher-strength grade such as X80 reduces the constraints related to the manufacturing and the installation by saving line pipe weight. Seamless X80 pipes were manufactured in 323.9 x 25.4 mm and characterized. Girth welding was made using the Gas Metal Arc Welding (GMAW) process on these seamless line pipes. Four-point-bend tests were conducted as per NACE TM0316(2) to evaluate the Sulfide Stress Cracking resistance on X80 pipe and welds. There are only limited results about the fatigue behavior of high-strength steel welded joints and, especially, in sour environments. Therefore, the performance of X80 mechanized girth weld was assessed in air and in mild sour environment. Fatigue endurance tests were performed in air at room temperature at loading frequencies of 4-8 Hz and completed by tests at 24°C, pH 5.9, 0.1 psi H2S partial pressure using a frequency of 0.2 Hz. The in-air fatigue performance of the X80 girth weld was found to be comparable to X65 tested in similar conditions; the results exceeded the BS 7608 class E target curve. The environmental knock down factor (EKDF), which was obtained by comparing the mean of the in-air data with the mean of sour data, is equal to 10.

The flexible installation has special challenges due to its relatively low bending stiffness. For example, the issue of midline connector laydown is the critical bending radius occurring at the flexible next to the connector. Such critical MBR is affected by several parameters, i.e. the bending stiffness of flexible, the dimension and weight of the midline connector, the layback etc. Through numerical simulation, this study performs sensitivity checks to address the effect of each parameter mentioned above.

Abstract The objective of the paper is to present the manner in which the Oil & Gas Industry has evolved and how this evolution has impacted the trend in pipeline installation methodologies. The content for the paper is based on authors’ personal experience within the various installation contractors that he had worked for and observation in the industry spanning 4 decades, as well as research on the evolution of the design of production facilities and how this evolution has impacted the various installation methodologies. The research pertains to both on-line research as well as discussions with various experts working for the various installation contractors, including authors’ employer. The findings from the study show that changes in design codes have been made to cope with increasing demands for deep-water facilities. The changes in design code has allowed for pipelines to be installed deeper, in particular for conventional S-Lay methods, as well as pave the way for other installation methodologies, such as Reel-Lay. Other novel methods have also been invented, such as the Controlled Depth Tow Method, although this method had evolved not as a result of the changes in code but innovative ideas that allow for deep-water installation with little impact on pipeline stresses. The findings from the study shows that pipelines are being installed in deeper waters as a result of improvement in design such as shorter stinger radius, which allows for pipeline to leave the lay vessel almost vertically, increased lay tension capacities, advanced welding and NDT techniques and so on. Changes in design codes have contributed to the accomplishment of deep-water pipe-laying. In addition, the trends for pipeline installation are discussed, as well as gaps and opportunities for future development.