The use of vacuum insulated tubing was first used in Alaska where it ensured the integrity of the permafrost as hot oil was being produced through it. By the early 1980s, the tubing was being used widely for enhanced oil recovery (EOR) in the production of heavy oil from areas such as Bakersfield, California, and the heavy tar sands of northern Alberta, Canada.
These early EOR designs evolved into a much-improved product, currently used for wax prevention and hydrate avoidance in offshore completions. In 1995, Diamond Power pioneered the use of vacuum insulated tubing for a subsea completion in the Gulf of Mexico. Having contracted for almost 60,000 ft of various sizes and designs of vacuum insulated tubing for use in downhole completions to date, with 13,000 ft currently in operation, the next logical step for this technology is its use in flowlines.
Diamond Power has patented a vacuum insulated tubing pipe-in-pipe design where the annular space between the tubes is evacuated to vacuum conditions (U.S. Patent No. 4,512,721). It is used in downhole, subsea completions, along with EOR steaming applications.
After four years of application in downhole and enhanced oil recovery applications, vacuum insulated tubing now is being considered for flowlines use to protect against hydrate and solids formation.
A vacuum is an ideal insulator. Creating a vacuum between the two pipes minimizes both gas convection and conduction heat transfer between the inner and outer pipes. Radiative heat transfer is minimized by providing a reflective blanket of insulation over the outside diameter of the inner tube. The inner and outer pipes are welded together, after which the vacuum is created, and the tubing sealed.
While the thermal conductivity of the body of the tubing has been experimentally measured at less than 0.001 Btu/hr-ft-°F, the coupling area has been computer simulated with a 2D axisymmetric model, indicating an overall thermal conductivity of less than 0.005 Btu/hr-ft-°F for most of the applications Diamond has reviewed in the Gulf of Mexico and the North Sea.
Once a vacuum has been established within the annulus between the two pipes, it must be maintained. There is not only a tendency for molecules to be desorbed from the metal matrix, but during subsequent oil production, corrosion of the vacuum insulated tubing (VIT) string will generate hydrogen. Some of this hydrogen will permeate into the vacuum annulus.
Unless the hydrogen, and other gases, can be eliminated, there will be a slow, steady pressurization of the annulus. Over time, hydrogen becomes the dominant gas to permeate the vacuum space, and the VIT will ultimately lose its thermal properties. The rate at which hydrogen permeation occurs can be estimated, based on expected well conditions, completion tubing material, completion fluids to be used, etc. To provide this service, regardless of operating conditions, the hydrogen pressure is kept in check with the use of a chemical compound called "getter."
Getter is a compound well known in the vacuum industry. Essentially, getter captures hydrogen, and traps it via chemical bonding. There are two types of getter used. A non-evaporable getters works by surface adsorption followed by bulk diffusion into the getter matrix. An organic getter absorbs hydrogen through a dehydrogenation reaction. The getter is typically purchased as granules or tablets, and is added during the fabrication process.
- Shell's Tahoe: The first vacuum insulated tubing installed in a subsea completion project was for Shell's Tahoe field in the Gulf of Mexico, located in 1,400 ft water depth. The A3 well was completed in November of 1996, and brought on line in early 1997. It has now been operational for two years. About 7,200 ft of vacuum insulated tubing was installed at the top of the completion tubing string. This design consisted of a 5-1/2 in. outside diameter (OD) outer pipe, with a 4-1/2 in. OD inner pipe. The well met expected wellhead oil temperature.
- BP's Troika: On the heels of the Tahoe installation, BP Exploration in Houston, Texas, placed an order for vacuum insulated tubing for a number of wells on Troika. The Troika field is located in Green Canyon block 200 in the Gulf of Mexico. The water depth is 2,670 ft. One reason BP decided on the vacuum insulated tubing was for end-of-life conditions.
The plan was to keep the flowing wellhead temperature elevated to help lengthen the cool-down time in the insulated flowline. The Troika wells are tied back to the Bullwinkle platform, 14 miles away, making it the longest subsea tieback for an oil system in the Gulf of Mexico.
The primary purpose for using the VIT on this project was to minimize the time required to move above the hydrate formation temperature. It was estimated that at 2,500 b/d, an uninsulated completion string would take five days to exceed the hydrate formation temperature plus safety margin at startup. With 5,800 ft of VIT at the top of the tubing string, it would take only three hours to heat up sufficiently. At 5,000 b/d, it was estimated an uninsulated string would take 15 hours to heat up, while a VIT-assisted string would take one hour. The reservoir temperature was 170°F, while the cloud point was predicted to be around 90°F.
The pipe used was similar to that chosen for Tahoe, with a few differences. While the engineered tubing was also a 5-1/2 in. by 4-1/2 in. design, there was a slightly longer setback from the end of the tube to the beginning of the fillet weld between the inner pipe and the outer pipe. The longer setback would allow a thread re-cut if needed.
- Amerada Hess' Penn State: This field is located in Garden Banks 216 in a water depth of 1,456 ft. It is a subsea tieback, about five miles to the Bald Pate platform. The initial characterization of the well indicated there were three pay zones, with the top two composed of gas, and the lowest an oil zone. The lowest pay zone of oil had a reservoir temperature of 190°F, with an anticipated paraffin content of 17%.
Hess designed for the use of VIT primarily with the oil zone in mind. The cloud point of the oil was 137°F.
The Penn State VIT design.
With a bottomhole temperature of 190°F, and a cloud point of 137°F, the purpose for using the VIT was primarily to avoid paraffin, although hydrates were also a concern. It was estimated that with bare pipe, the wellhead arrival temperature would be 117°F. With 8,200 ft of VIT at the top of the completion string, the wellhead arrival temperature is estimated to be 160°F, allowing a sufficient safety margin above the anticipated cloud point.
The design of the VIT for Penn State was different than that used on the earlier completions. It consisted of a 5-in. OD outer tube of carbon steel material, with an upset 3-1/2-in. OD inner tube of 13% Cr, 110 ksi. The welding of the carbon steel was qualified to 13% Cr, which leads to a substantial reduction in price due to the outer tube being carbon, and not the more expensive chrome.
Amoco has ordered several vacuum-insulated tubing hanger handling pups, that are just a shade under six ft in length. Some are fabricated from 22% Cr, while others were fabricated of 25% Cr materials. These will be used on the King project, in the Gulf of Mexico.
The designs discussed above are all threaded and coupled for use in downhole completions. While there are different designs, they generally fall into the category of all 13%Cr design, or a design using a carbon steel outer tube and an inner tube of 13%Cr. Of course, there is also a design using 100% L80 materials.
There is a fairly wide range of costs that can result, based on a number of factors including cost of materials, type of thread, and type of design.