Line of sight

Maintaining a flowline that will operate smoothly following a shutdown means addressing a host of flow assurance challenges. The industry has typically approached the flow assurance question through chemical and mechanical means. Jennifer Pallanich examines the strides made with two mechanical approaches subsea separation and direct electrical heating.

Offshore flow assurance tends to focus on five main issues: hydrates, waxes, sand, scale, and asphaltenes. Those are the culprits you want to design around, says Rob Perry, director of global subsea processing systems for FMC Technologies. For instance, four elements are all required at the same time to form a hydrate gas, water, high pressure and low temperature. So removal of any one of these elements prevents a hydrate problem, he adds.

Each of the three subsea separation units supplied to Total for the Pazflor development consists of a separation vessel 25m high, weighing 300t, and two hybrid liquid booster pumps. The major flow assurance challenges were oil quality, size of development area (600km2), the presence of sand, and the hydrate domains.

Many factors together dictate whether a hydrate problem will exist. In short, though, he says, applying heat would address the low temperature issue, and other solutions would be removing water from being in contact with gas or reducing pressures. Subsea separation and processing makes it possible to both manage pressures and separate the different phases in the production stream so some of the conditions that are required to form hydrates are now removed.

Different approaches are appropriate for tiebacks of different distances. Perry says heating a pipeline may make sense for a shorter tieback.

Total chose to use a subsea separation and processing system for the Pazflor project offshore West Africa; that was one of the first full field developments to include subsea separation and boosting as part of the initial field development concept (OE January 2011).

FMC designed a trio of subsea separation units for the project that solves hydrate problems while also making it possible to add energy, mix fluids from different reservoirs, and solve flow assurance issues. Gas and liquid phases are separated from each other subsea. In a shutdown scenario, the whole subsea production system can be depressurized to low pressures, even though the field is in deepwater. Total began production at Pazflor in 2011 in 600-1200m water depth. Each of the separation units is able to handle 110,000b/d of oil and 35mmcf/d of gas.

A subsea separation and processing project FMC developed with Petrobras R&D division CENPES is Marlim, which features oil and water separation. The deepwater subsea oil/gas/water/sand separator in 700m of water that FMC Technologies has supplied, dubbed Marlim Prototype or SSAO (Sistema de Separação Submarina Água-óleo), was designed to debottleneck the Campos Basin facility and reinject the water (OE August 2011). The unit was installed in November 2011; Petrobras expects to start the system in mid-2012.

Longer term, subsea processing will be able to deliver the same export fluid specifications as topsides facilities. Rob Perry, FMC

Subsea oil/water separation, as delivered in Marlim is the first step in removing enough water to prevent flow assurance issues, Perry says. While today the water in oil content is greater than that from topsides processes, future technologies will further improve separation performance and allow production streams to be stable enough to allow them to be transported over extremely long distances, just like export pipelines, he adds. Longer term, subsea processing will be able to deliver the same export fluid specifications as topsides facilities.

FMC has developed several technologies to a prototype stage to prove the technology, including inline electrostatic coalescers to separate the last remaining water from oil and gas conditioning to separate the last remaining water from gas, Perry says.

We're taking the enhanced technologies that we already have today, and are making these available within future subsea separation processes.

Petrobras Marlim SSAO was installed in November 2011 in the Campos Basin. The objective for the three-phase separation system was to achieve oil-in-water separation meeting 100ppm oil content and 10ppm sand-in-water for reinjection.

Perry is confident these subsea separation systems will play a huge role in Arctic offshore projects, where longdistance tiebacks are likely to be the norm.

A heated approach

The appeal of direct electrical heating (DEH) for use during shutdowns is at least two-fold, according to Torunn Lund-Clasen, Nexans DEH department manager. First, using heat rather than chemical inhibitors can provide a more environmentally-friendly solution for preventing blockages in flowlines. Second, chemicals only provide a brief window in which work can be done before problems start to crop up whereas DEH can prevent the problems as long as heat is applied to the lines. With DEH, she says: ‘You can buy yourself as much downtime as you need.’ Days, she points out, rather than the hours chemicals might provide.

In the late 1980s, Lund-Clasen says, a joint industry project supported by SINTEF, Statoil and Nexans, to name a few, focused on direct heat as an alternative to chemical flow assurance methods for the North Sea. While chemicals reduce the critical temperature where hydrates are formed, DEH ensures that the well stream is kept above the critical temperature for hydrate formation. Nexans did the qualification of the DEH concept, which was first installed on Asgard in 2000 in the North Sea. DEH heats the pipeline by forcing a large electric current to flow through the pipeline steel.

It's challenging engineering-wise, and it's fun to work with because you're always pushing the limits of technology. Torunn Lund-Clasen, Nexans

It seems very simple, but when you start to look at it . . . you take a standard steel pipe that is used for oil & gas transportation and now you need to know about the magnetic permeability and electrical conductivity of the pipe in order to establish the required power rating for the system, notes Lund-Clasen.

Since the first installation on Asgard offshore Norway, Nexans has delivered nine of the systems in operation. Over the course of fulfilling the nine DEH projects, Nexans has delivered 200km of DEH pipeline. It's challenging engineering-wise, and it's fun to work with because you're always pushing the limits of technology, Lund-Clasen says. Each system is tailor-made because the requirements change for every project.

One of the systems was for the Skarv field in 350-400m of water in the North Sea. BP awarded the Skarv project to Nexans in 2010. Included in the project was a 12km-long hydrate-prevention system rated to 24kV with a 25-year design life for installation in 375m water depth. A portion of the deliverable was installed last year, with the final connections to be installed this year. The BP-operated Skarv field in the Norwegian Sea is expected to begin production to the FPSO in 4Q 2012.

Near end arrangement of Nexans DEH system.

A second project is for the Statoiloperated Skuld field in the North Sea. The project was awarded last year, and installation of the 25km-long hydrate prevention system in 400m water depth is planned for this summer. The project, rated to 24kV, has a 25-year design life and is protected for trawl impact. We are using a piggyback cable with integrated protection. It's the first project with that solution, Lund-Clasen says. Before this, we integrated the cable in an external protection profile.

The previous solution, she notes, was more complex to install. By integrating the protection, she says, it's possible to save installation time. As of May, Nexans was wrapping up the manufacturing of the system at its Halden, Norway, plant.

The company is focused on improving the technology associated with direct heating. Currently, Lund-Clasen says, Nexans is working to qualify the technology for use in 2000m and 3000m of water. When considering a DEH system for 3000m water depth, there are several new issues to consider, she says. Increased weights and loads, material qualification, water pressure influence and long cable catenary lengths are some issues that differ significantly from the DEH systems installed in 300-400m.

Future development of the system will also focus on longer and larger pipelines, she notes. The challenge with length is when the length increases, the voltage increases, Lund-Clasen says. This leads to challenges related to the aging properties of the high voltage installations, which must be qualified for the accumulated operating time under relevant operating conditions, she says.

Going the distance

So far, the longest DEH system to be installed was 42km long, which Nexans supplied for the Tyrihans field in 2007/8.

Nexans DEH armored feeder cable (top) and DEH piggyback cable.

Aker Solutions has developed a technology it refers to as an Integrated Heating System (IHS) that the company believes will be useful for heating production or export flowlines 30in or larger that will stretch more than 100km along the seafloor. With this power distribution system, which provides power to DEH, pumps and process units, Ole Heggdal, technical manager for DEH pipeline heating systems at Aker Solutions, says: You get much higher flexibility in designing DEH in terms of pipe length, dimension and parallel runs. For long tiebacks with remote-end pumps and process systems that need power, this will easily be provided by the IHS since both systems can be powered by the same cable.

The heating systems can be conventional end fed or mid point, but the system eliminates power supply cables from land to each DEH system that gives unacceptable losses, according to Aker. The system can be extended to over 300km with acceptable losses and efficiency, the company adds. Heating 200km of 30in flowline with maintenance free IHS has an attractive opex and capex compared to alternative systems, the company says, especially in areas with high environmental focus.

This is a big step for this technology, Heggdal says. While an end-point fed system can supply DEH for up to 50km with power supply from shore, he notes, using the IHS makes it possible with multiple mid-point systems to double the distance several times with one power supply cable covering all the sections.

The maximum that we have seen so far is that we cannot heat flowlines longer than 40-50km, Heggdal adds.

That has been a limiting factor for DEH in many field developments. Long step outs over 100km is relatively new and so far not been interesting. This can most likely only be accommodated using pumps or process. Longer step outs over 200km is relevant for Arctic developments. In fact, he says, Aker has looked into the possibility of using IHS for distances up to 300km with pipes 30in or larger. That would be possible through the use of a three-phase power cable system using mid-point connections. By moving components from topside of platform down to the seabed you get better operational conditions for these electrical units and you will save a lot of weight and space on the platform, he says.

The system will actually be cheaper because the subsea DEH capacitor-bank will reduce the cable conductor size to less than one-third, and you get rid of a lot of cables to each individual heating system.

Subsea equipment requires power supply from the topsides, typically for pumps, boosting, subsea separation and compression, Eirik Haugen, sales manager for umbilicals at Aker Solutions, says. IHS provides the power supply for all the subsea applications, which makes it possible to more flexibly combine and optimize the applications, he says.

The cable has a poor power factor,’ Atle Pedersen, research scientist at SINTEF Energy Research, says. The heating cable together with the pipeline is inductive. With a very poor power factor of about 0.3 we need to compensate the DEH system with a capacitor bank.

The system will actually be cheaper because the subsea DEH capacitor-bank will reduce the cable conductor size to less than one-third. Ole Heggdal, Aker Solutions

Heggdal says putting the capacitor subsea means the ability to use a cable of much smaller proportions. As he puts it, it's a minor adjustment to include a power supply. Heggdal says he was working in 2011 to figure out a way to reduce the cost of deepwater and long step out DEH systems and cables. I have heard that capacitors could be moved into the turret systems of FPSOs in order to reduce the cable size in the swivel system. Then I saw that this was a possibility for also reducing the cable size all the way out to the various sections of the pipeline. The next thing was I saw fairly soon we had to develop a special feeder cable for infrastructure to accommodate a large communication line and a highway for power. To save costs, Aker sees IHS being installed at the flowline, and the cable can be strapped to a DEH heated pipe without interfering with the system.

He notes that the system components used in the IHS are well known. The only unproven component in the system is the capacitor. Both transformers and the electrical penetrators are qualified in the Ormen Lange test set up in Nyhavna performed by Aker Solutions. The subsea capacitor is not proven technology and not qualified. IHS is about to enter qualification, he says, which will take two or three years to complete. There are also patents pending on the new technology, he says.

Aker Solutions believes the pipe with piggyback could be useful in DEH applications for distances exceeding 100km or 200km, particularly in deepwater and Arctic locations. Aker developed the Integrated Heating System (IHS) concept (inset), which the company believes will be useful for heating production or export flowlines 30in or larger stretching more than 100km along the seafloor.

SINTEF is handling testing and qualification analysis of the technology. As Pedersen notes, this involves materials and aging testing.

With SINTEF Energy Research, Aker has developed a fiber optic system that is embedded in the cable protection to monitor the temperature, which detects and enables location of faults on the cable. A new generation of fault detection with monitoring is necessary to have 100% detection along the entire flow line, Heggdal says. He believes demand is high for providing DEH for distances exceeding 100km or 200km, particularly in deepwater and Arctic locations.

What we see now is increased demand for these systems. Most oil companies find this technology interesting. Many of them have been through the investigation and this seems to be the most cost efficient system in the market today, Heggal says. DEH has a long track record. It's simple. And reliable. OE