The oil & gas industry has long used dry ice as an isolation technique, for example to freeze a wellbore and allow intervention work. Now, after years of application in the nuclear sector, cryogenic freezing using liquid nitrogen has started to make inroads offshore. Jennifer Pallanich reports.
The technique of freezing a wellbore is most often used when previous operations, be they wireline or workover, were unable to perform isolation from the wellbore because of a valve failure.
'A freeze is really a do-over,' says Carlo Mazzella, special services business development manager for BTI Services, a subsidiary of Wild Well Control. And until BTI started using liquid nitrogen extensively, he says, 'The API world used dry ice and the use of N2 was extremely limited.'
Dry ice, he says, presents a certain number of challenges, notably how difficult it has become to access in the developing world, and the fact that it takes longer to obtain a freeze than with liquid nitrogen.
The liquid nitrogen technique, he notes, is not exactly new. 'Hey, they've been doing this since the 1960s,' he says. 'We're just the first ones to do this in the API world.' Liquid nitrogen can freeze a 24in conductor in under 24 hours, he says, while dry ice can take two to three days. 'Nitrogen also lets you freeze contaminants as well as some oil-based products, which is a key factor,' adds Mazzella, who joined BTI in June 2007 to develop the company's liquid nitrogen techniques for use in the oil industry.
He says there are other upsides to using the liquid nitrogen technique, such as the ability to pressure test the ice plug. Once frost rings appear on the pipe and a minimum temperature of –20°F on the tubing or casing indicates a positive freeze, he says, it's time to begin testing the integrity of the freeze plug before breaching into the system to carry out further operations. If there's 'no frost outside, [there's] no freeze inside', he says.
At its heart, Mazzella says, the process is a simple one: 'All we are doing is duplicating what Mother Nature does to us every winter.' The pipes freeze, causing plugging to the piping. Also during the freezing process, it is well established that ice expands, making it necessary to vent the pressure caused by the expanding fluid to prevent overpressurization of the pipe. Mazzella's technique calls for backfilling the piping with fluid so when the plug thaws, it is released in an equalized pressure state.
Using the liquid nitrogen has multiple benefits, he says. First, it can be used to 'generate a significant amount of ice in 24 hours,' he says, noting about 1.5 gallons per minute of flow allows him to conduct freezing operations with slight flow or movement. Second, he can apply the refrigerant 'indefinitely', maintaining the freeze as needed. The technology, adapted from a parallel industry, can be applied not just to pipes but also components like valves, crosses and tees. For the pipe freeze method, BTI holds three patents – one per technique – while the company is in the patent process on a prototype for component freezes.
To freeze the pipe, BTI attaches a heat exchanger, such as a fluid tight metal jacket, to the area of the pipe to be isolated. BTI then pre-cools the jacket with nitrogen gas before filling it with liquid nitrogen to freeze the water-based fluid along the inside surface of the pipe near the jacket. The cooling process continues inside the pipe, freezing more fluid and producing more ice along the axial plane of the pipe.
'Every nuclear plant in the United States uses cryogenic freezing as a repair method . . . but the [oil] industry was not receptive to it' at first, Mazzella says. In fact, the cultural issue has been one of the biggest constraints in uptake on the technique, that is, that the industry has always used dry ice for freezes. Aside from the difficulty in obtaining dry ice in certain locations (the BTI liquid nitrogen method relies on 50gal bottles of nitrogen or large capacity tanks that are frequently available in offshore situations), he says there are safety concerns about the industry's past method of dumping methanol on dry ice that is not freezing. 'The problem with that technique is that methanol is flammable,' he says.
'The very first time I saw a nitrogen freeze, I never went back to dry ice. I saw a more effective way of performing pipe freezing,' he says.
Nitrogen, which becomes liquid at –100°F, is finally starting to come into favor in the oil industry, he says. 'Now we're getting engineers who are more receptive to technology, rather than "that's the way we've always done it",' Mazzella says.
As with any new technique, there are hazards. Liquid nitrogen's ultra-cold temperatures make frostbite a real threat if the nitrogen makes contact with skin.
Asphyxiation within confined spaces is another hazard. BTI says it has developed strict procedures to mitigate safety concerns.
Mazzella says the technique has already seen success offshore. In the Gulf of Mexico in 1800ft of water, BTI was called on because the operator had hydrate formation plugs downhole and could not get them to thaw out. That type of plug, he says, will 'stay there forever, especially subsea'. The operator, Mazzella notes, wanted to carry out a coiled tubing operation to thaw the plugs with methanol, but the boarding valves would not allow for the operation. Instead, the pipes were backfilled with water and BTI performed a double freeze. The freeze involved isolating two 4.5in pipes below the valves. The flanges were welded in and valves with the same ID as the pipe were installed. All this work, he says, was accomplished over a six-hour interval.
In the last year, Mazzella notes, the company has also carried out routine liquid nitrogen freezes offshore Egypt. Over the years, the team has developed some specific techniques for ensuring proper freezes. 'Anything bigger than 4.5in, we freeze by night,' he says, to take advantage not just of cooler temperatures but also to give the client a window of sunup to sundown to handle the highest risk element of having the wellbore open. 'They have a full day to deal with safety and operational issues,' he says.
Question of strength
There were, however, some concerns about the strength of materials that have been exposed to cryogenic temperatures. Terry Wilt, metals and product testing department manager at Stork Materials Technology in Houston, says the question was raised about whether the frigid temperatures damaged the parent material while work was done to prevent or stop oil leaks.
Stork took API-rated metals and carried out Charpy impact and tensile strength tests on metals that had been taken to temperatures of –30°F to –230°F. Stork tested the N80, L80, P110, and S135 grades of API pipe and the N80, L80 and P110 grades of API casing/tubing.
Samples were also obtained from a test pipe at BTI that had been used in training and therefore seen 'hundreds' of exposures to cryogenic temperatures. 'Testing showed that there was only minimal affect on the microstructure and tensile properties to the pipe that had seen hundreds of exposures,' Wilt says.
He says the tests showed that while at –230°F the material became slightly more brittle but still met the specified mechanical properties for each API grade. 'Therefore, even while at –230°F, it's not affecting the strength properties of this material,' he says. Based on the various tests carried out at Stork, Wilt says, 'there is no fear that they're damaging or altering the strength of the pipe'.
Wilt says the protocol for the tensile tests involved bringing the various samples to the cryogenic temperature before the test was carried out. After the materials were brought down to –230°F, the samples do warm up to about –100°F while being installed in the tensile testing machine. To overcome this, the lab opted to shoot the samples with nitrogen to keep the material at –230°F for the duration of the test.
'Yes, the material became a little more brittle, and the strength went up slightly, as the freezing process was hardening the material,' Wilt says.
A metallurgical sample was subjected to X-ray diffraction to determine the level of retained austenite, which would indicate that certain properties have changed in the material. Austenite can transform into martensite with the cooling process. Martensite is not conducive to exposure to hydrogen, which is present in oil field operations.
'The percent of austenite in each sample was measured, and the austenite in the unexposed area had an average volume of 1.2% and the exposed areas produced 1.8% retained, which showed a slight increase but nothing detrimental to the materials,' he says. OE
Subscribe
