The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.
A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.
The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.
A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.
ABB is running a joint project with Equinor, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion. The output will form a critical part of future advanced subsea field developments. As such an undertaking has never been achieved before, it is a journey with considerable learnings to be shared not only upon completion (anticipated by the end of 2019) but also en route.
The paper will describe steps taken to build confidence along the way that the proposed solution will be fit for purpose when fully launched. Readers will gain insights into the key steps of this cutting-edge project. These include modifying prototypes of the equipment based on rounds of simulations, laboratory assessments (eg accelerated aging, vibration and shock testing) and water testing. Insight will be provided on tedious testing and qualification effort required to achieve the technology readiness level (TRL) required.
Readers will learn from the challenges experienced in this ground-breaking project and how they were overcome. Insight will be given into the overall challenge of both research/development and qualification of the novel technology developed in the JIP. Findings from testing, including extensive lab testing against industry standards, and the impact on subsequent development will be presented. The paper will eventually share results from extensive joint research work between the partners and ABB. The results are ground breaking and will by the end of the day introduce completely new opportunities for development of subsea fields.
As a first-of-kind-project, the results gained, and the subsequent technology developed will be of considerable interest to the industry. By the end of the day, the results from this project will be a key enabler for the subsea factory vision envisioned by the industry.
This paper describes a novel chemical injection system currently under development for long-term use in subsea oil and gas fields, and discusses the process being used to vet subsystems and components, and thereby increase the overall reliability of the system. Once proven and deployed, the system is expected to be a viable alternative to delivery of production fluids via umbilicals in deep water and with long stepouts from host production facilities. For decades, deepwater engineers have discussed a future in which oil and gas production systems that are typically located on floating facilities, would be placed on the seabed. The resulting subsea factory would include pumping, fluid storage, separation, power management, connections and controls all operating in the marine environment. While these technologies have proven to be reliable in the topside environment, and some have been used for short-term intervention, to date only boosting and separation systems, subsystems and components have been qualified for long-term installation on the seafloor. This paper details how the Technology Qualification Program, defined in the second edition of API RP 17Q, has been applied to qualify the novel subsea chemical injection system. The paper describes how the performance requirements were defined, together with their reliability implications, and provides examples of qualification activities.
This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. As it has since 1969, the world came to OTC to make critical decisions, share ideas, and develop business partnerships to meet global energy demands.
The costs of subsea boosting systems have been reduced by adopting three primary strategies: simplifying the system design to reduce weight and cost, simplifying the installation and intervention, and reducing complexity and risk. This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. Emphasis on identifying more-efficient subsea boosting solutions has led to a number of initiatives in the industry.
Operators are increasingly using existing offshore infrastructure for asset life extension, and developing new marginal stranded fields rather than develop new large greenfields. Subsea processing is an enabling technology in this goal. Subsea processing is an evolving technology in ultradeepwater development and has the potential to unlock a significant amount of hydrocarbon resources. In this paper, the authors have reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each.
Operators are increasingly using existing offshore infrastructure for asset life extension, and developing new marginal stranded fields rather than develop new large greenfields. Subsea processing is an enabling technology in this goal. A cybersecurity director outlines the steps needed to adopt a risk-based cybersecurity program. He cautions that in many cases, process control systems’ confidentiality is mistakenly viewed as a lower priority than IT systems’. AUVs aren’t limited to inspections and pipeline surveys.
The entrepreneurial ecosystem and the oil and gas industry are not a perfect match, but the industry has made strides in recent years to attract the startups developing innovative technologies that could usher it into a new era. How are companies bridging the gap? Operators are looking for ways to better handle water coming from subsea wells, which is typically treated at topside facilities. Subsea separation systems are not equipped to discharge water back into the reservoir, so how do companies close the gaps? Operators are increasing capital budgets in the wake of tariffs and quotas initiated by the US government on steel imports, and the product exclusion process has revealed a host of other issues.
Offshore project execution enhancement ideas are highlighted for debottlenecking, gas-hydrate-induced pipeline vibration, and the design of subsea systems for efficient startup. Water debottlenecking increased oil production by 80% and reduced the infield transfer volume by 62%. Operators are increasingly using existing offshore infrastructure for asset life extension, and developing new marginal stranded fields rather than develop new large greenfields. Subsea processing is an enabling technology in this goal. Lessons learned in debottlenecking a “dirty” triethylene glycol contactor at the ExxonMobil Upstream Research Company’s LaBarge Black Canyon Facility in Wyoming highlight the results of work performed between 2001 and 2004.
The complete paper highlights elements of the technical development and an overview of the primary building blocks of the system, and presents in detail some of the challenges in developing, designing, and testing the control system. As the hunger for data grows, long stepouts become more common, and fiber communication becomes standard, the use of fiber in subsea oil and gas fields is set to increase. The paper provides a fast-track approach to perform screening assessment of multiple subsea concepts. Technologies are being developed that have the potential to support marine mining in all stages from prospection to decommissioning. These developments will likely have substantial influence in the oil and gas industry, itself searching for ways to maximize exploitation of assets.