Long Gas Tiebacks – Pseudo Dry Gas Systems

Thomas, L.K.; Liebana, Laura; Wood, Terry; Stokes, Stephen; Luff, Richard

doi:10.4043/28949-ms

Cited by 4 publications

(1 citation statement)

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“…Where the cost of installing a new facility nearby would be prohibitive, increasing upstream tieback lengths through the use of subsea multiphase pumps (for oil-dominant reservoirs) or compressors (for gas-dominant reservoirs) has proven to be an attractive option in recent years; as these operations function to increase upstream pressure, they have a parallel effect on required injection volumes of THIs and thus further motivate the consideration of LDHIs. Alongside this strategy, the use of subsea separation has also started receiving attention in recent years; the use of a novel, passive subsea separation systems, 222 with AAs to protect the liquid return line, has been suggested to reduce the emissions profile of an upstream gas transmission line by nearly a factor of 5. The definition and management of hydrate blockage risk throughout operational lifethrough both mechanistic simulation tools and complementary laboratory equipmentcritically underpins the success of these, and likely future, upstream gas line alternatives.…”

Section: Challenges and Perspectivesmentioning

confidence: 99%

Hydrate Risk Management in Gas Transmission Lines

Aman

2021

Energy Fuels

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Gas hydrates are ice-like solids that can readily form and restrict flow in high-pressure natural gas transmission lines. The use of antifreeze thermodynamic inhibitors dominated production systems throughout the 20th century, where most research necessarily focused on measuring and predicting the hydrate phase boundary. In the 21st century, market competitiveness and environmental constraints have motivated a paradigm shift toward the identification and management of hydrate blockage risks, which has largely been facilitated to date through two research efforts: establishing and continuously refining mechanistic models to predict hydrate blockage formation; and exploiting critical stages within that blockage mechanism to develop novel, environmentally compatible inhibitors. This review presents a historical perspective on the development of an oil-dominant blockage mechanism and the technologies enabled by these efforts. Efforts over the past decademade possible through the collaboration between industry, the Australian government, and academiaare then summarized in the context of producing the first mechanistic blockage model for gas-dominant transmission lines, including the role of innovative high-pressure pilot-scale flowloop systems. Together, these blockage mechanisms have enabled new opportunities to develop and deploy low-dosage hydrate inhibitorsincluding the creation of new experimental capabilities that can be used to quantify occurrence probability or severity and the transient simulation tools that can leverage such knowledgethat support the ability to quantitatively manage hydrate blockage risk in hydrocarbon transmission lines. As they offer superior resolution in performance assessment to first-generation approaches, these new experimental methods offer structure–function design and optimization of low-dosage inhibitors against secondary, environmental parameters.

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Section: Challenges and Perspectivesmentioning

confidence: 99%

Hydrate Risk Management in Gas Transmission Lines

Aman

2021

Energy Fuels

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Pseudo Dry Gas Technology: Pathway to Decarbonisation of Energy Consumption for Remote Offshore Gas Fields

Ngo

Thomas

Raghavendra

et al. 2021

SPE/IATMI Asia Pacific Oil &Amp; Gas Conference and Exhibition

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Transporting large volumes of gas over long distances from further and deeper waters remains a significant challenge in making remote offshore gas field developments technologically and economically viable. The conventional development options include subsea compression, floating topside with topside compression and pipeline tie-back to shore, or floating liquefied natural gas vessels. However, these options are CAPEX and OPEX intensive and require high energy consumption. Demand for a lower emission solution is increasingly seen as the growing trend of global energy transition. Pseudo Dry Gas (PDG) technology is being developed by Intecsea, Worley Group and The Oil & Gas Technology Centre (Aberdeen) and tested in collaboration with Cranfield University. This is applied to develop stranded or remote gas reserves by removing fluids at the earliest point of accumulation at multiple locations, resulting in near dry gas performance. This technology aims to solve liquid management issues and subsequently allows for energy efficient transportation of the subsea gas enabling dramatic reductions in emissions. The PDG prototype tested using the Flow Loop facilities at Cranfield University has demonstrated the concept’s feasibility. Due to a greater amount of gas recovered with a much lower power requirement, the CO2 emissions per ton of gas produced via the PDG concept is by an order of magnitude lower than conventional methods. This study showed a reduction of 65% to 80% against standard and alternative near future development options. The paper considers innovative technology and a value proposition for the Pseudo Dry Gas concept based on a benchmarked study of a remote offshore gas field. The basin was located in 2000m of water depth, with a 200km long subsea tie-back. To date the longest tieback studied was 350km. It focused on energy consumption and carbon emission aspects. The conclusion is that decarbonisation of energy consumption is technically possible and can be deployed subsea to help meet this future challenge and push the envelope of subsea gas tie-backs.

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Novel Pseudo Dry Gas System for Extended Subsea Tie-Backs

Rafty

Thomas

Liebana

et al. 2019

Day 1 Tue, March 26, 2019

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The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression. Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery. Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.

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Long Gas Tiebacks – Pseudo Dry Gas Systems

Cited by 4 publications

References 0 publications

Hydrate Risk Management in Gas Transmission Lines

Hydrate Risk Management in Gas Transmission Lines

Pseudo Dry Gas Technology: Pathway to Decarbonisation of Energy Consumption for Remote Offshore Gas Fields

Novel Pseudo Dry Gas System for Extended Subsea Tie-Backs

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