Challenges and Concepts for Long-distance Tie-backs in Arctic … · 2017. 3. 15. · Challenges...
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Challenges and Concepts for Long-distance Tie-backs in Arctic Waters Sigbjørn Daasvatn Arctic Frontiers Tromsø, 21 th Jan 2015
Transcript of Challenges and Concepts for Long-distance Tie-backs in Arctic … · 2017. 3. 15. · Challenges...
Challenges and Concepts for Long-distance Tie-backs in Arctic Waters
Sigbjørn Daasvatn
Arctic Frontiers
Tromsø, 21th Jan 2015
Presenter
Presentation Notes
Thank you for the invitation to speak here at the Arctic Frontiers conference. I’m here to give you a brief insight into our thoughts about some of the challenges we are faced with when designing and installing more subsea production systems for remote tie-backs in Arctic waters.
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A global leader operating on the seven oceans
Presenter
Presentation Notes
Subsea 7 have gained valuable experience from vessel operations in sub-arctic and arctic environment. We have worked year round in the Newfoundland, we have experience from the Sakhalin region, and we have worked in the Barents Sea. We believe it will be difficult to just extrapolate the solutions used in other regions to the more remote Arctic environment without adjustment.
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Remoteness and lack of infrastructure in the Arctic
• Host platforms outside 200 nautical mile border
• Long distance tie-backs can stretch further into Arctic waters
• Evacuation
• Unstable Arctic weather
• Distances to bases
• Electric power
Presenter
Presentation Notes
The red dotted lines represents the 200 nautical miles line from the coastline. This distance compares to 370 km. Several prospects around the Arctic coast will be located in distances like this and even at longer distances from either the coastline or from other previously developed processing centres. At some of these locations, one may assess it viable to develop a field processing center based on a floating alternatives with offloading. The local infrastructure will then be connected to this host platform, including long-distance tie-backs In addition, one could tie-back other fields further out towards the ice edge, let’s say around 200 km or even longer for an oil dominated flow. This means we could reach approximately 5-600 km deep into the Arctic water from the coastline. Long-distance Tie-back solutions will provide us with a «safety margin» in the uncertain range of the variable 1-year ice extension.
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Current long tie-back distances
Graphics by Statoil
- Gas dominated > 150 km
- Fluid conditioning is handled by MEG
- Extended tie-back distance in line with power supply development
- Oil dominated flow limited to 50-60 km, need to improve technologies here
- Tyrihans 45 kilometres - longest DEH-equipped pipeline, installed in 2007-2008.
- Current limitations are related to flow assurance issues.
Presenter
Presentation Notes
The subsea installations on Snøhvit operated by Statoil are currently representing the standard state-of-the-art solutions with templates, infield flowlines and control distribution systems connected to the wellstream pipeline and control umbilical to land. 20 wells produce gas from the Snøhvit and the nearby Askeladd and Albatross fields in water depths of 250-345 metres. The gas is transported to land through a 143-kilometre pipeline. It is fair to say that the industry expect multiphase gas/condensate technology to enable transport over even longer distances than 150 km in the near future. Gas/condensate transport represents a less problems as compared to oil dominated flows. Tyrihans is tied back to the Kristin A floating production platform in the Norwegian Sea. Also this field is operated by Statoil. The 18” multi-phase production pipeline was insulated, alongside a direct electrical heating (DEH) system. The key question is now if we can find reasonable ways to increase tie-back distances further for oil dominated flows in the future?
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Challenges for Long-distance tie-backs in the harsh Arctic Regions
HMS Edinburgh Battle log of 14. December 1941: “Provided fuel to HMS ESCAPADE in extreme icing conditions.”
• Icing will also occur today
• Winterization of vessels
• Regular working conditions more inefficient
• Only installation in open water
• Installation work will mainly be planned for summer season – similar as for the North Sea
Presenter
Presentation Notes
The cruiser HMS Edinburgh was active on the Arctic run taking aid to the Soviet Union. Try to imagine how it must have been on the Arctic Convoys during the winter period. From her battle log of 14’th of December 1941 one can read: “Provided fuel to HMS ESCAPADE in extreme icing conditions.” On her last trip in April/May 1942, Edinburgh was carrying a 4,570 kg consignment of gold bullion when she sank. This gold was recovered by the diving construction company 2W in 1981 and Rockwater in 1986. These companies are now part of Subsea 7, but this is another story. The picture illustrates the icing problem, which can of course be seen just as bad today when the temperature decreases. Harsh conditions affect our ability to perform work efficiently. This will eventually reduce our cost efficiency during operations and we have to stop our work. We don’t accept the same working conditions today as our heroic sailors did at that time. So today we are limited to performing planned subsea operations outside the winter season in the periods from, say May to September, and only in open waters.
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«Subsea Highway» through Ice Berg Scours?
These ice-berg scours makes it more cumbersome to install pipelines and umbilicals at the seabed. We prepare the pipeline route at the seabed by trenching or rock filling the most difficult areas to avoid critical bending of the pipes and umbilicals.
Presenter
Presentation Notes
This render picture shows a part of the Barents Sea. We can see that the seabed is uneven. Large ridges in the Barents Sea are believed to be formed by sediments pushed forward by giant icebergs. The icebergs were probably produced from the retreating Barents Sea Ice Sheet during the last deglaciation. Scours can be seen up to several hundred meters wide and 20 m deep, with a length from a few 100 m to several km. These ice-berg scours makes it more cumbersome to install pipelines and umbilicals at the seabed. We need to prepare the pipeline route at the seabed by trenching or rock filling the most difficult areas to avoid critical bending of the pipes and umbilicals. Also, knowing the requirement of overtrawlability, we realize the work required to prepare the seabed for installation will be extensive. This seabed calls for small diameter pipelines which more easily follows the uneven seabed.
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Pipe lay vessels and reeling capacities
Seven Oceans
Example: 20km of 14 ” pipe compares to approximately 50km of 8 ” pipe
Presenter
Presentation Notes
Longer tie-back distances will create challenges to the installation of pipelines and umbilicals due to reel drum capacities. Umbilicals and pipelines can be joined, but it will be tedious work and a lot of transit. We may carry e.g. 15-20km of 14” pipe on the reel of Seven Oceans. For a long-distance tieback of 150-200km, we then need to go back and forth 10-15 trips to pick up the full length at the closest mobilisation base. If we reduce to say 8 inch, then we may install the flowline during 3-4 trips. We can clearly see it will be favourable to reduce the diameter of the pipeline.
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Flow Assurance challenges
• Over the last 20 years subsea pipeline active heating technologies have been considered and utilised for the purpose of hydrate & wax prevention
• Two of the main flow assurance challenges are: Hydrate formation & Wax deposition in the flowlines
• A combination of thermal, hydraulic, chemical and mechanical methods.
Presenter
Presentation Notes
Let’s tur our attention to what happens inside the pipes then. Hydrate formation and wax deposition in the lines are normally the main challenges for oil dominated MF transport. The hydrate and wax appearance temperatures are therefore very important design parameters in field developments. And as we know, the temperature of the fluid will decrease as heat is lost with increasing pipeline length. So we are deemed to end up in some kind of problems we need to solve. Traditionally, our struggle has been to apply flow assurance mitigative actions to maintain the temperature above the wax and hydrate formation temperatures, or to manipulate the phase change temperatures by chemicals. Today and onward, the tendency is leaning towards subsea processing where we actually do some work on the fluid to change the conditions. Companies like Statoil, Shell, Petrobras, FMC Technologies, Aker Solutions and OneSubsea have pioneered this development.
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Improved Insulation and Active Heating Flow assurance
Conventional Insulation
U-value - 2 W/m2K
DEH
Presenter
Presentation Notes
Much of our efforts through the years have been related to finding better ways of insulating the pipelines to reduce the heat loss. The thickness of the insulation have increased, but the requirement for a stable pipe at seabed has lead to limitations in the thickness of the insulation since there will also be a buoyancy effect from the insulation material which eventually makes the pipeline unstable. To increase ti-back distances further one can add heat to the system. Direct electrical heating (DEH) of pipelines is an active heating method that has proven to be a good and reliable solution for preventing the formation of hydrates and wax in multiphase flowlines. A piggyback cable (PBC) is attached to the top of the pipeline during installation and the resistance to current will generate heat in the pipeline material. Around 70% of added heat will disappear into the sea during use of this system.
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Pipe-in-Pipe and EHTF
U ≤ 1 W/m2K
U-values < 1 W/m2K
Presenter
Presentation Notes
In order to further reduce the heat loss, one can introduce dry insulation having larger thickness, and cover the insulation by an outer pipe which also results in a stable pipe on seabed due to increased weight. This is the Pipe-in-Pipe system. By trace heating a Pipe-in-Pipe system, one obtain the most efficient systems we have available today. But even if it requires only 10% of the energy compared to DEH, the EHTF system will also meet its boundary due to the resistance in the small cables and the voltage required. Typical limitations for the EHTF system is around 30-40 km. In theory, this system could also be fed from either ends to increase tie-back distance, but this will also increase the complexity of the system. So similarly to the DEH system, this “low power” consumption system has limitations versus long-distance tie-backs.
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Towed Production Systems
• Subsea 7 have designed and installed 73 towed bundle systems
• This system can carry subsea processing and wax control equipment
• Few people involved, less weather restrictions to installation operation
Presenter
Presentation Notes
Before we can review a new concept for long distance tie-backs, I need to introduce the Towed Production System. Subsea 7 has been working on subsea processing ideas since the end of the 1990’s in terms of gradually integrating processing functions into our Towed Production Systems. Gradually the number of functions in our bundle systems have increased. Until date we have manufactured and installed around 70 towed pipeline bundles, the largest being around 9000T and 7,5 km long. The main benefits of towed production are related to the possibility of performing a full scale function test of the production plant before it is launched into the sea. Secondly, the installation operation is performed by a simple low cost towing which results in a low stress installation with few people involved in the operation. This fabrication and installation method will suit well in the remote arctic developments. Work is transferred to onshore fabrication sites and offshore vessel campaigns are reduced. Finally, installed at the seabed the internal lines are protected from trawling activities by the external shell.
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How can we reach further out?
• NTNU described cold flow principles in early 1990’s
• Can lead to simpler pipelines of smaller diameters without need of insulation and active heating.
• Reduce compexity, consumption of energy and cost
Presenter
Presentation Notes
In the early 1990’s, NTNU carried out a work which showed that natural gas hydrate slurry in a circulation loop did not deposit on pipe walls in a constant temperature laboratory. This lead to early ideas about Cold Flow wherein hydrate and wax particles follow the well stream in a slurry if the conditions are right – that is there are no radial temperature gradients in the fluid. If the water content could be reduced to less than 10%, the cold flow process would generate dry hydrate particles which would follow on along in the flow in a manner without growing to a hydrate plug, and somewhat similar effects were indicated for wax deposition. SINTEFF continued this work under the name Cold Flow Technology. CF technologies are different from the flow assurance technologies for wax and hydrate prevention in that one may use a simple non-heated, uninsulated pipeline to transport partially conditioned wellstreams at ambient seabed temperature. This is very important for long distance tiebacks, cause if it works, then we can avoid insulated and heated flowline systems over large distances. If this can lead us to a long, slim, un-insulated pipe which require no additional energy – well then this is interesting for us all!
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Early principle for early Cold Flow Concept – «Wax Eater»
Presenter
Presentation Notes
Later, several ideas and concepts for cold flow building on these ideas have emerged and are currently under development by various parties. This early cold flow concept was proposed by Halliburton Subsea and others around 2000. It included water knockout separators to reduce water content to less than 10%, various cooling sections with a pig train in a wax removal loop and a following hydrate particle reactor. Explain principles… The separator was planned to be installed in a towed production system.
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«Wax Eater» test in Houston in late 1990’s
Cooling Water Tank (T-200)
Oil Storage (T-100) Treatment Loop
Oil Feed Pump (J-102)
Chilled Water Cooler (C-270&C-272)
Flowline Loop
(Oil Heater below tank)
Data Monitoring
System
Presenter
Presentation Notes
The concept was tested in a laboratory in Houston. The tests demonstrated that the wax treatment loop showed very good results. This confirmed that the rapid cooling followed by a continous mechanical pigging generated a clean pipeline downstream the wax removal unit. However, the hydrate reactor never worked well and at that stage, neither cold flow or subsea processing was matured technology.
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Concept for Wax Removal Unit
BG Knarr 550Te Towhead Structure
Conceptual solution for wax removal
The wax control unit is connected downstream the subsea processing system which may be integrated in the towhead structure.
Presenter
Presentation Notes
Today, subsea processing including separation and pumping are used for many subsea applications at a high reliability level. Statoil have proposed their own alternative cold flow system. This system is based on making use of existing subsea processing units like separators, water treatment systems and reinjection, multiphase pumps, and finally wax control. The wax control concept is used to cool down the fluid in a known part of the flowline immediately after the separation and boosting to deposit the wax on the inside of the flowline in this cooling section. The system makes use of the original and successful mechanical pigging as wax removal principle. The wax control unit is connected downstream of the subsea processing system which may be integrated in the towhead structure.
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Long-distance tie-backs in arctic regions
• The further out, the less realistic will floating production solutions be due to both HSE, cost and practical remoteness factors.
• To reach even further we need long-distance tie-backs.
• Subsea Processing with wax control can be applied in towed production systems to enable ambient temperature flow for long distance tie-backs via small diameter flowlines to host platforms located away from the 1-year ice.
• Assuming this works, electrical power supply will limit the distances from host to subsea field also for oil dominated flows.
Seven Eagle, Canada
Presenter
Presentation Notes
Selecting the technical solution for new developments is a multi-discipline exercise which requires thorough concept screening and case-specific conceptual studies to be initiated years ahead of project sanction. Early engagement is a key issue here. I believe that the Arctic regions call for solutions based on the principles of prevention rather than reaction. Subsea 7 is present with an office here in Tromsø – and this is because we believe in a future here!
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Thank you for your attention
