Due to the laws of physics and multiphase flow, subsea tie back systems are generally limited to approximately 110km as a single pipeline or 150km as dual pipelines after which the production plateaus are shortened and increasing amounts of reserves remain in the ground. This paper presents an overview of an innovative new technology which demonstrates that gas tie-backs can be achieved without the need of compression. The premise of the technology is to achieve pseudo-dry gas conditions through intermittent in-line separation with segregated transport of the associated liquid phase. Achieving near dry gas conditions in the main production conduit removes hydraulic constraints on line size and turndown, leading to improved recovery for long distance tieback opportunities. The paper demonstrates this innovative technology and its value proposition by means of a ‘bench-marked’ study of a 200km long gas tie-back in 1,800m (5,900ft) of water. The Computational Fluid Dynamics (CFD) work has demonstrated high separation efficiencies at significant superficial gas velocities, while the required hardware fits within the installation envelope of an ‘In-line’ pipeline tee. This has been coupled to the flow assurance work showing improvements in recoverable reserves, while leading to capital expenditure reductions of upwards of 50% due to the removal of offshore structures.
Pseudo Dry Gas (PDG) technology is proposed as an alternative concept for transporting multiphase fluids (gas, condensate and water) for long deep-water subsea tieback developments (Ref 1 - OTC-28949-MS) (Ref 2 - IPTC-19440-MS). Using PDG technology, subsea pipeline networks can be extended to excess of 200 km total length and considerably reduce the backpressure on the wells. This allows improved recovery of the reserves and the ability to reach currently stranded fields, especially deep-water lower-pressure gas fields. The basis of the PDG system is to remove the liquid of the main pipeline system using Piggable Liquid Removal Units. With the removal of the liquid, the gravitational pressure losses in the system are eliminated allowing the pipeline to operate like a "Pseudo" Dry Gas system. The liquid phase is transported back to shore using a second smaller pipeline running in parallel to the main pipeline by means of subsea liquid pumps (Ref 3 - OTC-29332-MS). After techno-economic reports were completed for a known basin of stranded gas in the West of Shetland, an Oil and Gas Technology Centre (OGTC) experimental project was established to determine the operation performance of the element within the PDG technology with lowest Technology Readiness Level (TRL). Currently the liquid removal unit has a TRL2 and a TRL4 will be achieved after the experimental testing programme has been fully completed. This paper assesses the separation performance (Efficiency) of the Piggable Liquid Units or PDG unit. Previous Flow Assurance and Computational Fluid Dynamics (CFD) established expected efficiencies between 84-99% depending on the gas and liquid flow rates and other factors such as unit orientation, liquid type, operating pressure and temperature. Each PDG unit has two modules which allow for gas-liquid separation of the multiphase fluid in the pipeline. A PDG unit prototype has been built and a testing programme has been developed and undertaken in collaboration with Cranfield University (CU) using the large scale Inclinable Multip hase Flow Loop facilities. The testing programme has two test matrices: Matrix 1 which studies the performance of a single module of the PDG unit and Matrix 2 which investigates the efficienc y of the entire PDG unit (two separation modules). Matrix 1 of the testing programme allows to characterise the system varying the flow conditions (flow regime, liquid and gas flow rates), drop out liquid level and size, effect of sand and the inclination and orientation of the unit as would be expected once installed. This paper focuses on the results obtained from Matrix 1 testing programme and compares them with the initia l PDG unit estimated efficiency values used in previous studies to demonstrate the prove of concept of the PDG technology. The overall conclusion is that the performance of the PDG liquid removal unit is greater than the ones originally used in technology assessment reports.
The Pseudo Dry Gas (PDG) technology / concept has been demonstrated for transporting wet gas in a long subsea tieback pipeline (200 km) in deep water depths (1.8 km) under wet gas conditions (water saturated gas) [Ref.1] along with a state of the art technology review of existing solutions. When a multiple of these in-line / piggable liquid removal units are used, they help to reduce the well back pressure by reducing the liquid content to an extent where ‘dry gas’ pressure losses are seen. Therefore, this mitigation of the gravitational pressure drop allows the use of larger pipelines to minimise the frictional pressure drop. This in turn increases recovery of reserves and allows tie back distances to be enhanced. The objective of this paper is to investigate a Pseudo Dry Gas System (PDGS) for an ultra-long deep-water gas condensate development, building upon the research and development already conducted with Strathclyde University. This work was undertaken using non-standard flow assurance methodologies and simulations recycling data and results with the advanced Computational Fluid Dynamics simulations of the liquid removal units behaviour, over various operational boundary conditions. Engagement with subsea equipment suppliers based on the flow assurance results has been undertaken. This paper describes how gas condensates within a subsea tieback system behave very differently to condensed water from a wet gas system and therefore a pseudo dry gas system needs to be configured differently for gas condensate developments. These differences include how and where the liquid drops out of the gas phase, where and if the free liquid is reabsorbed back into the gas stream and how the bubble point of condensate is equal to or very close to liquid removal units operating pressure; this greatly impacts the liquid handling system compared to a wet gas (water) design. Therefore, to ensure controlled liquid only transportation, careful examination of the liquid removal units performance, the liquid pump selection criteria and optimisation of the system needs to be undertaken. This results in a trade-off between maximum reserve recovery and system complexity. The paper demonstrates that the liquid condensate system will remain as a single liquid phase pipeline, where the number of pumps can be reduced and the pump power requirements are very low and within the existing technically qualified subsea pumps.
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