UTC presenters tackle hydrate flow challenges

May 21, 2013

Dealing with hydrate formation in pipelines is becoming a hot topic. The issue will be the focus of multiple papers at this year’s Underwater Technology Conference.Statoil intends to have a “full subsea factory” by 2020 and one of its key projects to achieve this is the Åsgard subsea compression project.

In development since 2008, it will be the first of its kind in the world when it starts up in 2015, adding an extra 280 mmboe from the Mikkel and Midgard reservoirs through the use of two 10MW gas compressors together with a scrubber, pump and cooler.

Welltec’s team lowering the toolstring the electric wireline removal of hydrates on a North Sea well.However, the 75m x 45m x 20m compression unit will have to deal with an issue common to new and redevelopment projects alike – hydrates.

It is an area drawing a lot of interest, including at this year’s Underwater Technology Conference (UTC) in Bergen, June 19-20.

Solutions are being sought and offered from design through to monitoring and metering, management and removal.

Henrik Alfredsson, CFD lead engineer at Aker Solutions, says flow assurance in general and hydrate prevention specifically have been key to the Åsgard subsea compression project.

“Hydrate clogging is and has always been a challenge in the oil & gas industry,” he says. “The challenge now, as we move in to subsea processing and more specifically subsea compression, is that the process as such is more complicated than for a normal SPS (subsea process system).

“The inclusion of subsea cooling, as a vital part of the process, infers stream temperatures decreasing towards or even below hydrate formation temperatures. Inhibiting fluid, or anti-freeze if you will, is therefore required in order to prevent a hydrate plug from forming.

“On Åsgard, we have gone to great lengths to keep us safe from hydrates. For the Inlet Cooler, it has been quite a focus and through thorough engineering and testing we feel confident that we have succeeded. Subsea cooling and passive subsea cooling is definitely a field for the future,” Alfredson says.

On Åsgard, the Inlet Cooler is designed to perform two functions – cooling the hot gas coming back from the compressor in an anti-surge event, and also to cool the wellstream in normal production and increase the efficiency of the compressor station as a whole. By cooling the wellstream, the compressor operates at a higher efficiency and, in addition, more water and hydrocarbons are condensed and can be pumped in the form of liquid rather than compressed as gas.

“The potential problem arises when you cool your gas stream below the hydrate formation temperature,” saysAlfredsson says. “Not having hydrate inhibitor available would mean that the pipe would eventually clog. And you have to bear in mind that there are a multitude of pipes in this cooler. The challenge lies within distributing the hydrate inhibitor, in this case monoethylene glycol (MEG), in to each and every pipe. Through evaluations, simulations and testing we have however made certain that inhibiting fluid is properly distributed to all the pipes. We can hence operate safely without unplanned shut downs due to hydrate clogging.”

Existing flow assurance challenges and addressing hydrate formation on Norway’s Ormen Lange development will be discussed by Pabs Angelo, senior flow assurance engineer, Norske Shell.

Ormen Lange’s flow assurance system was upgraded in 2011 to include a new pipeline monitoring system and leakage and blockage module based on a new transient multiphase flow simulator, FlowManager Dynamic.

It has been able to give accurate predictions of pressure, temperature, and flow rates of gas, condensate and water/MEG in the wells, templates, flowlines and slug catchers.

It has also helped reduce the “significant challenge” of hydrate and ice-formation by calculating the pressure, temperature, water content and MEG concentration through the entire subsea system, giving the margin to the hydrate formation curve for actual operation conditions.

Cameron will present the development and qualification of its new high flow chemical injection metering valve for gas projects.

David Simpson, subsea product manager for Cameron, will outline how deepwater chemical injection of large volumes of MEG or methanol for hydrate inhibition will be a significant challenge for some of the large bore gas wells currently under development or being planned.

Cameron’s new valve aims to achieve accurate delivery of hydrate suppression chemicals through a patented non-intrusive ultrasonic flow measurement closed-loop control device currently being deployed on a number of gas projects in the North Sea, South China Sea and Western Australia.

An artists’ impression of the Asgard compression module.It provides infinite flow rate regulation up to 26,500 l/h+, with high native flow rate measurement accuracy in an extremely low pressure drop device, Cameron says.

Despite all the efforts, hydrates can still form. Being able to remove them from subsea wells is a problem that will be addressed by Welltec at UTC.

The firm is to present on what is being billed as the world’s first hydrate removal on an electric line from a riserless light well intervention (RLWI) vessel by Welltec.

Ole Eddie Karlsen, VP Subsea, at Welltec, says the firm was brought in after a build-up in the wellhead cavity was observed indicating a possible blockage by a hydrate plug.

Methanol had been pumped through the injection master valve, which had cleared the hydrate between the flow valve and the wing valve, but the amount below the subsea tree was unknown.

“Instead of going in with an expensive rig, we went in with a vessel and electric wireline,” Karlsen says. “Usually you use risers and pump MEG in. We went in with our (3.8) reverse circulating bit tool, closed the well, and filled the lubricator on the subsea stack with MEG, then ran in and started milling, displacing the MEG.”

Ormen Lange field, located 120 km northwest of Kristiansund, Norway, holds the world’s largest gas wells, with a line size of 9 5/8 inches.The hydrate tagged at 553m where the electric line cleaner was activated, and it removed the hydrate down to a depth of 608 m in 20 hours of actual milling time. This allowed the operator to reestablish functionality to the downhole safety valve.

He estimates the method could save a third or half the cost of using a rig to intervene in the well.

A project to develop new technology for detecting hydrate restrictions subsea will be presented by Lee Robins, head of subsea, Tracerco Norge AS, and Keijo Kinnai, Senior specialist flow assurance, Statoil.

The two firms have been co-operating over several years on the project, development work on which started a decade ago using existing Tracerco technology developed for topside usage.

Its “oetomography” scanning equipment was successfully applied to locate restrictions on a couple of Statoil-operated platforms.

“Some initial tests were performed at the operator’s K-Lab underwater testing facility at Kårstø, Norway, using the flow assurance test flowline, which provided excellent results and paved the way for a new development,” Robins says.

“Due to increased needs at Statoil to have a fully operational tool available for locating hydrate restrictions the cooperation was accelerated to a new level with highly ambitious objectives.

“A development project for a new tool producing extremely high-resolution pipeline tomography scans, using a large number of gamma detectors, was therefore launched in 2012. This project has now produced a tool that will be ready for large scale testing in 2013 and subsequent quick commercial applications.”

The presentation at UTC will cover the background of the development work and give a description of Tracerco’s technology for solving flow assurance challenges. Preventing, mitigating, detecting and removing hydrates is just one of the themes to be addressed at UTC.

The event’s overall theme is Global Subsea Challenges, managing the old and the new. “It is a challenge for operators and suppliers in our industry to connect new and innovative solutions to ageing infrastructure and installations,” said conference chairman Trond Olsen.

“The challenge is most likely to grow as even more subsea tiebacks are installed, equipment gets refurbished, control systems is modified and updated, and a new generation of people coming in to the industry shall relate to and understand technology developed before they were born.” OE



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