Tiny tubing takes on hydrates
  from: Offshore Engineer
  by: Mark Embry
  Tuesday, July 08, 2008

Despite best efforts at inhibition, hydrate plugs are an occasional offshore annoyance. Traditional methods of dissolving the plugs are dangerous, expensive and environmentally unfriendly. BJ Services’ Mark Embry describes a safer, more economical alternative.

Between September 2007 and February 2008, two major well operators in disparate areas of the Gulf of Mexico faced the same flow assurance frustration: a gas hydrate plug had blocked the wellbore. Since hydrates began haunting operators in the 1930s, bullheading methanol has been the ‘industry standard’ for removing hydrates from the wellbore. But when this method will not dissolve a plug, operators turn to alternatives, such as coiled tubing fluid delivery and milling operations.

For these two Gulf of Mexico operators, the goal involved further reductions in fluid volumes, non-productive time and platform disruptions – by rapid deployment and use of capillary tubing.

Inhibiting hydrates

Hydrates form when water molecules crystallize around guest molecules, such as light hydrocarbons and hydrogen sulfide. Depending on pressure and gas composition, gas hydrates can build up at any place in which water coexists with natural gas, even at temperatures as high as 80°F. For example, hydrates will form near the mudline in a wellbore where fluids experience pressure- and temperature-related phase changes, or alternatively in flowlines from subsea completions to separation facilities. Most offshore wells use some form of hydrate inhibition technology to avoid these problems.

Methanol and ethylene glycol are the traditional oilfield inhibitors, and they use thermodynamic processes to inhibit hydrate formation or dissolve any that form. Another option for hydrate inhibition is low-dose hydrate inhibitors, which use kinetic and/or antiagglomerant chemistry to inhibit hydrate formation. They work at lower injection rates than the thermodynamic options, but they cannot dissolve hydrates that form if production or environmental conditions change, for example, if production must be shut-in for several hours.

Combining the thermodynamic, kinetic and anti-agglomerant chemistries, BJ Services’ Ice-Chek proprietary inhibitor technology efficiently produces a ‘slow-to-fail’ phenomenon: It limits the rate of hydrate crystal growth, discourages accumulation of any crystals that do form, and melts them to avoid any problems. In the field, this provides operators with a much wider window to adjust chemical feed rates if needed to overcome unanticipated changes in well pressure/temperature.

Unplugging a well

Despite best efforts at inhibition, GoM mudline water temperatures are as low as 34°F, so surges in production pressure/ temperature/rates/fluid compositions can overcome the inhibitors and result in plug formation. Hydrates often form due to failure in the chemical injection system, failure to inhibit water injected into the well, or during long periods of down time in production. Removing them is fairly straightforward, but can be timeconsuming and expensive, using standard industry chemicals and procedures.

The industry standard is methanol, bullheaded into the well at high volumes, assuming injection is possible. Even when it is, the process can be timeconsuming; however, methanol is highly flammable and can create environmental concerns in discharge water, in pipelines or at the separation and processing facility. In addition, large concentrations of solvents aggravate potential scale problems by reducing the solubility of scaling salts in the water.

Bullheading ethylene glycol is also effective for dissolving plugs, but it is expensive, so minimizing fluid requirements is essential for an economical operation.

An ideal means of reducing the fluid requirement would be to deliver the fluid directly to the plug with some jetting action, such as a coiled tubing wash tool. Alternatively, a coiled tubing unit or a workover rig could be deployed to mill out the plug. Any of these options can incur days of non-productive time required for rigging up/down the specialized equipment.

An economical alternative is to inject the chemicals through capillary tubing, a smaller (3/8in or 5/8in) cousin to conventional coiled tubing. Like coiled tubing, the technology reliably places chemicals exactly where they are needed. However, the smaller tubing diameter means the equipment footprint is about four times smaller than a conventional coiled tubing arrangement, and weight can be as much as ten times lower, facilitating rapid deployment, nearly anywhere in the world. This reduces requirements for rig cranes, space on boats and the rig, and rig-up time.

The small diameter of the capillary does result in rate restrictions, but that is not typically an issue in hydrate plug removal. High rates can help expedite the process, but just getting chemical in contact with the hydrate and allowing time for it to dissolve is effective. The rate constraints are minimal, compared with the time saved in quick mobilization and rig up. In addition, the small diameter can be an advantage in tight wellbores or, for example, when a fish is blocking access to the problem area.

Depending on the size of the production tubing, penetration rates into the hydrate plug average 20ft/h, which is much faster than the traditional method of bullheading. Chemical costs can be reduced considerably; as a rule of thumb, the method uses only about 1 barrel of chemical per 10ft of hydrate.

BJ Services recently used capillary tubing to remove hydrate plugs from two deepwater wells for operators in the Gulf of Mexico. The method allowed economical, safe and rapid solution to be employed to correct a difficult problem.

Saving a fish

The first project involves a well in the eastern Mississippi Canyon. Slickline on a platform had been performing a routine gauge ring run but became stuck around 2700ft while pulling out of the hole. Communication with the well was lost, and it was determined that a large hydrate plug had formed. After considering some of the other options noted above, the operator called BJ Services to mobilize a capillary tubing unit.

An offshore capillary tubing unit was safely rigged up alongside the slickline unit using a Y-body on top of the dry tree. The slickline was cut, threaded through the vertical section of the Y-body, and tied back to the spool. Capillary was rigged up on the other section of the Y-body, and the 3/8in capillary tubing was run into the well alongside the slickline.

After the capillary tagged the plug, nonflammable ethylene glycol was pumped to dissolve the plug. After dissolving 300ft of hydrate, the slickline was freed and able to come out of the hole. After the slickline was out, the capillary tubing was pulled out to allow the slickline crew to fish. The capillary was finally run back in the well to dissolve the remaining 200ft of hydrate.

This method saved the operator a considerable amount of money by not having to cut the slickline and mobilize a conventional coiled tubing unit to drill or wash out the plug. If the slickline tool had fallen to the bottom of the 22,000ft well, subsurface equipment could have been damaged, and a costly fishing job would have been required.

Saving time, money

The second job was in a well in the central East Breaks. Seawater had been pumped to kill the well while remedial actions were being performed. During well shut-in, a hydrate plug formed at approximately 4000ft. Several unsuccessful attempts were made to dissolve the plug by bullheading methanol into the well.

Following mobilization, BJ Services safely rigged up the capillary tubing system in under six hours, saving up to several days if a workover rig or other option had been rigged up. Capillary tubing was run into the well and tagged the restriction. Methanol was pumped down the 3/8in tubing at 1 gal/min. After eight hours of pumping, 160ft of hydrate had been dissolved. An additional 10bbl of methanol was spotted down to 5000ft to prevent further hydrates from forming while the well remained shut-in. A gauge ring run confirmed the wellbore was clear.

The entire operation took 32 hours. A riser was not needed, and the crane was not tied up, which might have delayed other operations on the rig. The operation used only 12bbl of methanol to dissolve the hydrate and inhibit reoccurrence, compared with hundreds of barrels that would have been required for bullheading without as high a chance of success. The cost of using the capillary tubing unit was considerably less than that of a workover rig or conventional coiled tubing unit, and non-productive time during rigging up and down was reduced considerably compared to the other options.

Focus on safety

Capillary tubing units include top-of-theline wellhead pack-offs for complete well control. Systems include a simple, singlebarrier, threaded 5000psi system or a dual-barrier, flanged 15,000psi system specifically designed for high-pressure and H2S applications.

BJ Services also provides a wide selection of chemical pumps, pump manifolds, and tanks as part of a complete service package. To help facilitate wellsite services, all of the equipment used with our capillary tubing services have fit-for-purpose, field-proven downhole and surface components. OE

About the author

Mark Embry is a field engineer with BJ Services Company. He graduated with a BS in chemical engineering from the University of Mississippi and is based in Kilgore, Texas.

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