Challenging wax on Pil and Bue

Waxy crude on the Pil and Bue project and topside constraints has led VNG Norge to explore pipe-in-pipe heating systems. Elaine Maslin reports.

Statoil’s Njord A facility. Photo by Thomas Sola/Statoil.

Pil and Bue, or bow and arrow, are oil and gas discoveries in Blocks 6406/11 and 12 on the southern part of the Halten Terrace in the Norwegian Sea. Both discoveries were made in 2014, and contain a total 80-155 MMboe.

But, to produce these fields, operator VNG Norge, faces a number of challenges. “The Pil and Bue fields are quite waxy, with a high pour point [the point at which a liquid loses its liquid properties],” Alireza Forooghi, lead flow assurance engineer, VNG Norge, told the Underwater Technology Conference (UTC) in Bergen in June. “The fluids form strong gels during shut down. A 30km journey to the topside facilities makes it even more challenging.”

VNG Norge looked at a standalone development, using a floating production vessel, but chose the tieback option to Statoil’s Njord A facility. The next closest host for a tieback would be Shell’s Draugen platform, some 65km away. But, while Njord A is closer, it also has process constraints, including gas compression ullage, surge volumes to accommodate slugging and liquid handling for pipeline depressurization.

The flow assurance challenge could be tackled using heated pipelines. Most existing waxy crude developments are onshore, Forooghi says. Those offshore are mostly non-gel forming and the few that are use short, duel multiphase flowlines to a dedicated floating production vessel.

VNG Norge’s subsea concept for Pil and Bue is 6-8 wells, with a 36km multiphase flowline to a production template, gas and water injection flowlines, served from the Njord A topside, to an injection template, close to the production template.

For the Pil and Bue flowline, VNG Norge screened three options: pipe-in-pipe (PIP) without active heating, which would rely on pipeline depressurization for hydrate management and continuous wax pour point depressant injection; electrical heat trace (EHT) PIP technology; and direct electrical heating (DEH) of the pipeline.

Forooghi says that early in the project lifetime hydrate formation pressure will not be reached, when the flowlines are depressurized. But, there would be issues with low pressure startups, due to the amount of liquids left in the line after depressurization, leaving gelled segments that would need 200-400 bar pressure to restart the line – without active heating.

In a DEH PIP, the flowline forms part of an electrical circuit. A number of variations exist, where the inner pipe and outer pipe form a circuit (end-fed PIP), or where a piggy back cable providing power is used completing the circuit at both ends of the flowline. Center fed (or closed circuit) systems also exist, where power is supplied from a mid-line connection along the pipe, then forming an electrical circuit with the inner and outer pipes.

Closed circuit (or center fed) DEH PIP has been used in the US Gulf of Mexico on the Oregano and Serrano fields, since 2001. This was a first for the technology, Forooghi says. Open loop, or piggy back DEH applications, have also been used on various Norwegian fields, including the first DEH application of any kind on Asgard, in 2000. Center fed systems have been used on Na Kika (2004) and Habanero (2003), both in the US Gulf of Mexico.

EHT PIP has also been used, Forooghi says, on Total’s Islay project in 2011. EHT uses trace heating elements, i.e. cables, helically wound around the pipe. This is an option gaining traction, Forooghi says, with others looking at it for Norwegian developments, including Tommeliten Alpha, and it’s an option for Snadd, as well as Total’s Zinia 2 project offshore Angola.

“DEH PIP has some real advantages,” Forooghi says. “It has relatively high thermal performance in the system, the flowline size is not limited. It can be laid in S-lay and J-lay, it is field-proven, operational and possible to repair if the system fails. The disadvantages are that it has relatively high-power demand, and while it’s applicable in short flowlines, longer flowlines need to be divided into sections, and it requires a relatively high number of bulk head and water stops to make it,” although this is the same for EHT, he says. It’s also exposed to relatively heavy wait-on-weather for offshore operations and welding, he says.

The advantages of EHT are relatively high thermal and electrical efficiency, he says. “It has a good level of redundancy through using a number of heat traced cables. It can be tested onshore for faster offshore installation. The main disadvantage is the limitations in size of pipe. The biggest flowline size to date in 12in and it is limited to reel lay or towing to field and it’s not repairable.

“EHT is the best option for Pil and Bue, because we only need it in shut-down and start-up. During normal operations, we will be running quite hot. In late field life we are planning to have gas cap blow down, when might be required to be used on a continuous basis.”

VNG is running a competitive front-end engineering and design (FEED) study between Subsea 7 and TechnipFMC, following which it will look to qualify the technology for Pil and Bue, due to new elements in the system for the development.

This is likely to be around the challenges of using this technology on a 34km tieback – when previously it’s been limited to shorter lengths (6km on Islay), due to short heating circuits. This could mean a move towards using higher voltage cables, which would be exposed to relatively high temperatures. “The overall system behavior will need to be designed and simulated to design life,” Forooghi says.

Development engineering work is being supported by Norway’s Reinertsen. The subsea production systems contract was awarded to TechnipFMC and Aker Solutions. A contract for engineering, procurement, construction and installation is due to be awarded in Q4 2017.

Drying out

Minox’s system. Photo from Minox.

Norway’s Minox has a DryGas compact gas dehydration concept. It is a two-stage gas dehydration process based on the firm’s Minox Deoxygenation technology. The technology - initially designed for topsides has two separators with static mixers upstream. Glycol (TEG or MEG) is used to extract moisture from the gas–including a conventional TEG regeneration. The system use less glycol than conventional dehydration systems and would be a lot more cost effective solution than injecting glycol for flow assurance with an untreated gas.

Minox has completed full-scale testing of the system at Statoil’s K-Lab, at Kårstø, Norway, supported by Statoil and the Research Council of Norway (Demo2000 program) and is awaiting a report. The next steps will be adding a glycol pump and optimizing how much glycol is needed. To take the system subsea, which the firm plans to do, will involve a full redesign tailor-made for the subsea environment, says Minox CEO Bjørn Einar Brath.

Brath says that the system is already half the weight and size of a comparable system. Traditional systems consist of large contactor towers, absorbers, extending up through multiple topside decks, where the wet gas reacts with TEG as it passes through the absorber. The conventional towers are sensitive to movements of the installation, which can be a problem on floating installations, and require larger volumes of TEG and the energy.

The firm has been making systems using similar technology for water deaeration for topsides since the late 1980s and it is used by nine major operators now.

ExxonMobil has also been working on gas dehydration technologies. Earlier this year it unveiled its cMIST technology, which dehydrates natural gas using an absorption system inside pipes, replacing the need for conventional dehydration tower technology. It is an inline technology that could be deployed onshore, offshore and, potentially, subsea.

cMIST removes water vapor from natural gas with a 70% reduced footprint and 50% of the weight of traditional systems, the firm says. At its core is a “droplet generator,” used to break up conventional solvent into tiny droplets that become dispersed in the gas flow, increasing the surface area for the absorption of water from the gas. This is followed by an inline separator that coalesces the water-rich glycol droplets and moves them to the outside wall of the pipe for effective separation from the dehydrated natural gas. The water-rich glycol is regenerated using a conventional system and sent back to the droplet generator to be used again. ExxonMobil has licensed cMIST technology to the Chemtech division of Sulzer.