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Over the past ten years, subsea multiphase pumping has accomplished extraordinary technology breakthroughs. The drivers are the oil and gas companies’ requirements for deeper and more remote subsea production satellites along with producing more challenging fluids. The multiphase pump (MPP) technology has kept evolving, breaking records in terms of shaft power, design pressure, differential pressure, and high viscosity capabilities. In addition, the current reliability data shows 86.5% probability of 5 years failure-free operation. Today, a main challenge is the ability to withstand sand erosion. A subsea MPP is placed on the seafloor to increase the production from subsea oil and gas wells, normally without any upstream separator or sand control system. The inevitable sand production is directed through the pump and transported further to the topside arrival separator. The MPP considered in this paper is a dynamic helico-axial pump with rotational speeds typically ranging up to 4,600 rpm and 3.5 MW. Obviously, both pump vendor and operator have made significant efforts to make the MPP as robust as possible. The first part of this paper describes how sand production is mitigated and controlled in a subsea oil and gas production system, but also how an accidental sand event can nevertheless happen. In the second part, the various wear mechanisms of MPP components are explained based on operational experience and wear tests. Finally, it presents the comparison of the wear observed on the Moho pump retrieved from the field with the wear rate and pattern predicted by the in-house MPP wear prediction model.

The emerging subsea processing system described in this work, comprises several deepwater wells equipped with electric submersible pumps (ESPs) and one or more seabed booster pumps. This system provides efficient reservoir hydrocarbon recovery by maximizing pressure drawdown at the sandface. The in-well ESPs increase the pressure drawdown to improve production throughout the life of the reservoir, while the subsea booster pump lifts the combined production from all wells to reach the processing facilities at sea surface. This system integrates several production technologies to optimize performance, lower operating costs, and support reliable and safe operation.The Lower Tertiary trend (LTT) in the Gulf of Mexico (GOM) poses a number of documented challenges for flowing reservoir fluid from the sandface to surface facility. The key challenges are operations due to low permeability, high pressures, high temperatures, and water and well depths. The primary objective of this work was to document the feasibility of the subsea processing system and quantify its production performance for a typical LTT field. The work included development of a full field system layout and simulations of production performance for a range of reservoir and system assumptions. In addition, operational issues such as system stability, power balancing, and basic control methods were considered, including the use of transient simulations, to ensure a reliable and efficient operation of the system. These form the basis of a unified pump control methodology. To verify the impact of in-well ESP reliability on field performance, a comprehensive availability model was developed using reliability data for individual system components; ESP reliability, ESP intervention time, and rig deployment time were varied to determine their impact on overall system availability. The results of the availability model were then combined with the steady-state production results to define production availability and calculate a range of internal rate of return (IRR) values for a typical LTT field development.Utilization of the system showed enhancement in oil recovery in the range of 20 to 50% over use of a seabed boosting pump alone and substantial improvement in total liquid and oil gain as compared to natural lift. The system resulted in very satisfactory IRR and achieved production availability targets by using alternatively deployed ESPs. Moderate improvement in in-well ESP reliability combined with shorter rig mobilization time for intervention shows significant improvement in production availability. In total, the combination of seabed boosting pumps and in-well ESPs should be considered as a viable method of enhancing recovery from challenging deepwater subsea fields such as those of the LTT in GOM.The unified pump control methodology is the key to safe and reliable operation of the system. The current work presents an approach on how to operate ESPs safely, by minimizing transient responses and shifting total operating load as much as possible to the seab...

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.

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