Subsea pumping- and metering represent technologies which may contribute to simplifying and enabling developments of marginal, and remotely located oil & gas fields. The Asia Pacific region has already seen several subsea implementations of the multiphase technologies over the last years which include both subsea boosting- and metering. The multiphase technologies are particularly suitable for offshore- and subsea operations, and offer the operators a cost- effective solution. The multiphase technology area has gained experience through successful operation since the mid 90s. The fact that natural gas has increased its value in many parts of the world, has driven the request for the next technology step - wet gas compression. However, there are two different system approaches to this challenge; - True Wet Gas Compression - subsea rotating machinery working directly on the wellstream without or limited preprocessing, or - Subsea Gas Compression - marinized dry gas compressors with upstream well-stream processing and associated control systems This paper describes the development and full- scale test of a Multiphase Compressor, which is working directly on the well stream without pre- processing. A description of how this technology can simplify complex offshore field developments will be given, as well as an overview of the operating characteristics and main features of the compressor.
The first subsea multiphase boosting system was installed in 1994 and it is today a proven technology with a global track record. In addition to bringing increased production and recovery, multiphase boosting may also reduce flow assurance issues, reduce project CAPEX and OPEX, improve operability and safety as well as reduce the greenhouse gas emissions when compared to gas lift, the default lifting solution. A review of the evaluation process and drivers during subsea artificial lift evaluations over the last three decades indicates that in general only a few of the actual upsides of subsea multiphase boosting have been considered, suggesting that there is a need for a more complete overview of the advantages and an approach to uncovering and quantifying the actual value. This paper discusses the different aspects of subsea multiphase boosting through a comprehensive list of tangible benefits that may support the field development decision process towards identifying the potentially significant and hidden value of subsea multiphase boosting. Referencing experience from more than 30 installations it also provides a historical summary of the various aspects of subsea boosting and which drivers were and were not considered during the decision making process.
The Jack and St. Malo fields were developed in a deepwater Gulf of Mexico (GoM) setting by Chevron and co-owners and commenced production in 2014. The reservoirs are located roughly 25 miles apart, about 250 miles southwest of New Orleans, Louisiana. Water depths in both fields are around 7,000 feet, and the reservoirs lie approximately five miles below the water surface. The Jack and St. Malo fields were developed with subsea completions flowing back to the Walker Ridge Regional Platform, the largest, by displacement, semi-submersible floating production unit (FPU) in the GoM. The Lower Tertiary trend (LTT) in the GoM poses a number of documented challenges for flowing reservoir fluid from the sand face to surface facility. The key challenges are related to low permeability, high pressures, high temperatures, as well as water and well depths. The naturally high pressures driving Jack and St. Malo fields during the early stages of development will decrease over time as the fields are produced. To compensate and maintain production levels, it was decided to deploy three powerful subsea pumping systems on the seabed to boost fluids from the wells to the host platform. While a number of subsea boosting systems have been deployed over the years, the Jack and St. Malo fields required technology qualification in order to meet design requirements in terms of water depth, pressure rating and shaft power. This paper will describe the technology qualification program of the world's first high pressure seabed boosting system, as well as the subsequent delivery project and deployment of three subsea boosting systems in the Jack and St. Malo fields. An overview of the drivers for selecting this technology will be provided, as well as insight into early operational experience from the field.
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...
The challenge of increased recovery in development of subsea fields has driven the advancement of subsea processing technologies, in particular within the subsea boosting domain. The successful operation of large subsea boosting systems on a global scale, coupled with significant added value of pre-compression systems in gas fields, has driven the next technology step; subsea multiphase compression. The application of the multiphase compressor in a subsea environment simplifies a subsea compression system significantly, as there is no need for pre-processing. This enables development of simplified subsea systems at lower capital expenditure and field development costs. This paper will provide an overview of the Technology Qualification Program (TQP) completed for Statoil's Gullfaks Subsea Compression (GSC) project, as well as present the WGC4000 compressor performance characteristics and mechanical design. Experiences from the GSC project, as well as deployment and commissioning of the subsea compression system in second half of 2015, will also be described.
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