Subsea boosting has been building a track record at increasing depths and higher pressures. This has introduced certain new challenges. Continuous development of the technology has been required to maintain the historical high reliability and operability. This paper identifies operational challenges associated with a specific deepwater field and how they were resolved. The close collaboration between the operator's and the pump supplier's teams is emphasized as a success-factor. Insight is given into the development team's problem-solving strategy, as well as the applied technology itself. Extensive use of digital tools such as advanced dynamic modelling and virtual prototyping has been applied to debug concepts ahead of physical prototyping. This resulted in a fast track project with only very few time-consuming and expensive re-iterations. In 2014 the world's deepest seabed boosting pump system was successfully installed and commissioned. The permanent real-time condition monitoring system allowed the pump manufacturer to remotely monitor the pump performance. During the first few months of operation, it was determined that the shut-in pressure gradient was significantly steeper than specified. The production pressure build-up following a pump stop was more abrupt than the pump's barrier fluid pressure control system was designed to deal with. Because the gradient of the pressure increase couldn't be altered, a limitation on the pump's maximum pressure drawdown was immediately put in place. This was done to minimize the amplitude of the pressure increase on shut-in, and to prevent the production pressure from exceeding the pump's barrier fluid pressure. Without such a limitation, this condition could result in a pump breakdown. Continuous operation with this constraint in place would lead to significant curtailment once additional pressure drawdown was required to maintain the nameplate production. Seabed pumps are equipped with a barrier fluid system, which is regarded among the main success factors leading to the high meantime to failure. The barrier fluid system provides the pump with clean fluid at a correct pressure. The barrier fluid is used for lubrication of bearings and seals, heat transfer, and electric insulation. It also constitutes a barrier, hence its name, for any production fluid ingress into the electric motor through pressure control. The pressure is being closed-loop regulated to stay within a certain band above the production pressure. Barrier fluid is conveyed between host facility and the subsea pump through small-bore tubing in the umbilical. Thus, quick volume exchanges between topside and subsea is limited. As the umbilical length increase, the response time, as given by speed of sound, also becomes a limiting factor. A subsea pressure control system is the most common solution in the industry for larger depths and long tie-backs. As the well pressures were depleting for the described deepwater field, the drawdown limit posed a risk for curtailed production. To avoid falling below the nameplate production of 170 kbbls/day, the full differential pressure capability of the pumps was soon required. The novel pressure control technology was developed, qualified and successfully implemented on the pumps. It allows for safe operation through ultra-quick production pressure changes without the need for upgrades to the umbilical. In fact, the technology allows for longer step-out and further cost savings on future umbilical and seabed boosting deployments as even smaller-sized umbilical tubing can be utilized. The successful development of the novel pressure control system prevented production curtailment altogether. The system is now successfully operating subsea, and the pumps are helping the operator to utilize the full production potential of the field.

Some of the world's largest reserves are heavy oil reservoirs, defined as liquid petroleum of less than 20°API gravity or more than 0.2 Pa.s (200 cP) at reservoir conditions, [4]. Production of heavy oil in combination with increasing water cut (WC) brings a potential for very high emulsion viscosities. In combination with gas, the high viscosity provides operating conditions highly challenging to multiphase subsea pumps. In 2013, OneSubsea was awarded the Engineering, Procurement, and Construction (EPC) contract for Total's Moho 1bis development in the Republic of the Congo in West Africa. The contract included a subsea pump station with two 3.5 MW HighBoost pumps (helico-axial multiphase pump with balance piston) capable of handling high viscosities and gas volume fractions (GVFs). As part of the Moho project, and to qualify the HighBoost technology for high viscosities, a full-scale test loop was built to verify pump performance at liquid viscosities up to 0.8 Pa.s (800cP). To cover the complete Moho operating range 0.001-0.8 Pa.s (1-800cP) and 0-75% GVF, the first article pump was tested on nitrogen and three different liquids: water, hydraulic oil, and gear oil. An extended analysis on the performance of helico-axial pumps in this unexplored domain of laminar and transition flow regimes was carried out. Extensive amounts of test data were gathered during the 2-year qualification period. After testing and design optimization, the pump performance was significantly higher than predicted. The knowledge gained also served as valuable input to the pump protection logics customized for high-viscosity pumping. During the program the pump has proven its ability to perform startups on viscosities up to 30 Pa.s (30,000cP). Qualification of this technology for high viscosity has widely extended the domain of high power, high flow and high differential pressure (dP) helico-axial multiphase pumps. Along with their proven track record in deep water and long step-out distances, the ability to pump high-viscosity fluid will enable future development of other heavy oil reserves going forward. The pump system described in this paper was successfully installed, commissioned, and started during the spring of 2017 to boost the viscous production. As of January 2018, it has been running with 100% availability following the startup.

The downturn has impacted our industry in many ways, not only in terms of budget cuts and headcount reductions but also in changing the way organizations work. The downturn has enabled the creation of novel technologies and efficient development plans such as phased development and early production systems that are transforming the industry, and the increased collaboration between operators and suppliers has been unprecedented. This paper discusses recent technology developments that have and will continue to reshape the approach to phased field developments. For many years, the concept of phased field development has focused on reducing the expense of reaching first oil while planning the development for maximum recovery and deploying technology blocks that enable future add-ons for optimal asset return on investment (ROI). Game-changing efficiency resulting from earlier engagement with customers, paired with the latest technology and tools, can maximize the potential of a phased field development. Using real-world development data as a basis, this paper details how operators can use current technology and tools to enable efficient phased field development. The case study discusses the benefits of using integrated field development and planning solutions that provide operators and suppliers a robust cloud-based collaboration solution for planning and evaluating various field development options and associated cost and schedules estimates at the click of a button. The paper then shows the impact that technology such as all-electric solutions, boosting and compression, pipeline solutions, and modular product solutions can have on the decision-making process for upcoming projects.