Operators are beginning to consider new methods of maintaining flow assurance within offshore facilities without heating or chemical dosing.

Various enhancements to existing techniques for flow assurance in pipelines are being considered by industry technologists, ranging from the heating and insulation approach to completely "blue sky" science.
Flow assurance is a fairly new term coined by members of the DeepStar deepwater research and development (R&D) collaboration in the United States. It originates in the science of ensuring the flow from the sand face completion in the well to the first phase separator.

Paul Fairhurst, a senior flow assurance engineer for BP based in the United Kingdom, described three key issues within the subject area. First is energy, second is delivery and third is integrity.

Energy: "This is providing the flow from the sand face to a separator at a rate that we require," Fairhurst said. Associated with that is the need to be able to predict any frictional pressure drop in a pipeline, and the hydrostatic head which the well flow has to overcome in order to reach the separator.

"Every time we want to flow a reservoir of oil spatially to a hub, we cannot just put a hub [platform] with it. It is too expensive. We need to build a central facility with critical mass and tie it back.

"That critical limit has been 30 km (18 miles). If we can find oil reservoirs within 30 km of an existing hub, we can do that."

But he said tieback technology and flow assurance become major issues once reservoirs are found beyond 30 km.

Delivery: Fairhurst said if a reservoir can flow naturally, and is found at a water depth of 3,280 ft (1,000 m), then a hydrostatic head or backpressure of at least 1,000 psi has to be overcome first before the wellstream can even reach a separator. "Then it is less likely that the reservoir pressure will flow back to the facility," he said.

The pressure of the reservoir fluid drops as it leaves the well bore, and reduces further as it progresses along any flowline. This pressure drop needs to be calculated, too, in order to predict the likely flow characteristics and help design export pipe and production facilities.

At that point it becomes necessary to consider water injection to artificially boost the reservoir pressure. Also the size of the export pipe or flowline has to be predicted. "You can be quite inaccurate with the pressure drop and still have the right pipe size," Fairhurst said.

Integrity: "It involves making sure that a flow path exists so that you do not corrode your pipe and have a leak, or so that it becomes blocked with solids," Fairhurst said.

Here, he refers to asphaltenes, hydrate plugs and wax - some of the principal obstacles to ensuring flow through pipelines.

Asphaltenes are solids that can precipitate around the bubble point of hydrocarbon fluids - the point at which dissolved gases begin to vaporize out of a liquid - which depends on pressure, temperature and the composition of the gas and liquids.

They become visible as a black, coke-like deposit, that can choke production lines. "It is one of the least understood solids compared with wax or hydrates," Fairhurst said. "But you can predict its occurrence and you can dose it with chemicals."

He said asphaltenes usually appear in separators and they resemble "croutons" floating on the surface of liquid. BP has encountered the problem in production systems in both Norway and in the Gulf of Mexico. The company has an R&D program underway to investigate the formation of asphaltenes and how to deal with them.

But wax and hydrate are seen as greater problems in the flow assurance chain.
Wax is a paraffin deposit, which comes out of the wellstream at around 102?F (40?C).
As flowlines from wellheads to production facilities get longer, then the opportunity for hydrocarbons to cool during transport down to ambient seabed temperature - often 34?F to 38?F (2?C to 4?C) - is greater. And with that comes the risk of wax formation.

"The first thing is to make sure that the flow arrives at 40?C or higher," Fairhurst said. "If wax forms in the line, the hole in the middle gets smaller, and that can block your pipe."

Pigging a line is a commonplace solution to wax formation, but it entails a production shutdown and the dreaded non-productive time (NPT) for facilities. "We have pipelines where we expect to pig once every 3 days to remove wax."

So one of the other major subject areas for flow assurance experts is thermal management - preventing hydrocarbons in a flowline cooling to the point where wax can form and potentially block a line.
As production from greater depth becomes commonplace, then lower ambient temperatures enter the flow assurance equation.

At 66?F (20?C) hydrate plugs form, these comprise a combination of water and lighter hydrocarbons methane and ethane etc. Described as hot ice, Fairhurst said, "It does actually block a pipeline. It is a slushy, ice-like structure."

Learning to live with and manage these hydrate-forming characteristics is the kind of technology that is driving large deepwater developments both in the Gulf of Mexico and offshore Angola.

Dosing the wellstream with chemicals such as monoethylene glycol (MEG) to prevent hydrate formation is one solution, which entails a capital cost - to provide equipment to generate MEG and then to circulate it and recover it from the wellstream. But Fairhurst said chemical dosing is not always possible during periods of normal production when water cut from production wells is too high.

Hot water circulation and direct pipeline electrical heating (DEH) are some of the techniques already employed to prevent the wellstream cooling to the extent that hydrates and wax can form in flowlines. But again, providing hot water and DEH adds capital cost to a project. Materials selected to build insulated pipes are not always suitable for a wet environment. "So you get a pipe with polyurethane foam or Rockwool," Fairhurst said. "That will cost double compared to a wet system and the next decision is to go for a heated pipe and that is another order of magnitude of cost."

Once a hydrate forms, the question then becomes how to get rid of it. One way is to heat the blocked pipe to melt the ice. However, Fairhurst explained, "It takes a long time to melt it." Also the volumetric ratio of gas when converted from solid is vast - to the order of 150 or more. For example, one cubic meter of hydrate can produce more than 150 cubic meters of gas. So when a hydrate plug is melted, it causes a steep increase in pressure. Hard won experience has shown that pressure generated during melting hydrates can burst a pipe.

Hot water circulation is regarded as a much more passive hydrate melting technique.

Other technology tools are available to the industry. One is a coiled-tubing conveyed device that uses fluid to propel an unblocking device to the hydrate plug location within a flowline and some tools under development have a projected range of 12 miles (20 km). Others are based on a pig propelled by hydrate inhibitor.

Another factor is sand production. In an uneven flowline it can accumulate at the bottom of bends in a pipeline, constricting the flow. Furthermore, if sand comes into contact with wax it can form larger obstacles known as sand pancakes.

Cold flow is one of the approaches now under investigation by BP as it believes this might provide the solution to ensure slugging in flowlines and pipeline blockages are eliminated.

Fairhurst said the concept is based on allowing the wellstream to cool down to the ambient sea temperature near a wellhead - where it can be encouraged, under the right conditions, to form a slurry. Creating this slurry is the most difficult part of the problem but if it can be done, this slurry can then be transported through a flowline to a treatment facility. The immediate benefit is eliminating the need for an insulated or heated flowline back to a hub.

"You then have to process the cold flow at a platform and that is the Holy Grail," Fairhurst explained. "The idea of cold flow is that you overcome wax and hydrates near the wellhead so that you can transport it to facilities. We have a proof of the concept in a laboratory with BP's technology partner Sintef." Further concept testing is under consideration.

Other approaches include enhancements to direct electric heating with hot water circulation - again eliminating insulated pipe - and finding other ways to add and retain heat economically. One idea is to use insulating gel - much like chemical sachets used as handwarmers, which retain heat and then slowly dissipate it.

Other approaches include more sophisticated controls for slug flow, with online systems mimicking the flow process which are better able to predict when and where slugs and hydrate will form, particularly with wet gas lines. This would allow process control equipment to control slugging and dose hydrate-prone areas of a flow system before a hydrate plug arrives there.

And there is an educational issue, too. Fairhurst believes there is a lot more science to flow assurance than is currently understood, since the subject brings together a number of different disciplines - chemical engineering, mechanical engineering, process control and production engineering. He believes there is a need for academic institutions to focus their petroleum courses more towards flow assurance. "We are totally dependent on this [academic] community for our developments, and we are not getting the graduates with that qualification," he said.

With large capacity wells these days, in some cases with 95/8-in. completions and capable of producing 350 MMcf/d of gas or 50,000 b/d of oil - avoiding the blockage of such high flowrate wells is a crucial business and commercial issue.

Consequently unplanned shut-ins need to be minimized. If shut-ins are planned, i.e. deliberate, then there is time to remove any built up material, hydrate, wax or sand from the system. But if the shut-in is unplanned, Fairhurst suggested much of the first few hours is spent trying to work out what has happened and why, effectively a "do nothing" period when minor system faults will be easily rectified by automated process systems.

"In 99% of shut downs, the plant is back on within 3 hours," he said.

But with planned shut downs, it could take a day or more to get back to full production. Protective measures can be taken to protect vulnerable system elements such as wellheads and flowlines by pumping them full of glycol to prevent freezing. Remediation of the system might involve partial depressurization and pigging of flowlines. "Then we have all the baggage of restarting again afterwards."
All of this is highly complicated work, balancing the effects of one action to prevent a particular set of circumstances arising, against another. It is all a fine balancing act.