Hydrate Remediation

Like the kinetics of hydrate formation, hydrate dissociation is a poorly understood subject and applying laboratory observations to field predictions has proven difficult. Part of the reason is the complicated interplay of flow, heat transfer, and phase equilibria. The dissociation behavior of hydrate depends on the hydrate size, porosity, permeability, volume of occluded water, “age” of the deposit, and local conditions such as temperature, pressure, fluids in contact with the plug, and insulation layers over the pipeline. Two factors combine to make hydrate plugs exceedingly difficult to remove: It takes a large amount of energy to dissociate the hydrate, and heat transfer through the hydrate phase is slow. Hydrates also concentrate natural gas: 1 ft3 of hydrates can contain up to 182 ft3 of gas.

Hydrate dissociation is highly endothermic. If heat transfer through the pipeline insulation layer from the surroundings is low, the temperature near a dissociating hydrate can drop rapidly. In addition, as gas evolves during hydrate dissociation, JT cooling of the expanding gas is also possible. By either of these mechanisms, additional hydrates and/or ice can form during the dissociation process. For a more complete discussion of gas hydrate structures and properties, the reader is referred to the book by Sloan.

A hydrate blockage remediation plan should be developed for a subsea system where hydrate formation is an issue. This tells operators how to spot when a blockage might be occurring and what to do about it. The state of the art would be to have an “online” or “real-time” system using a calculation engine such as OLGA to continuously predict temperatures and pressures in the pipeline and raise an alarm if hydrate formation conditions are detected. Such a system may also be able to pinpoint the most likely blockage location. Hydrate remediation techniques are similar to hydrate prevention techniques, which include:

• Depressurization from two sides or one side, by reducing pressure below the hydrate formation pressure at ambient temperature, will cause the hydrate to become thermodynamically unstable.
• Thermodynamic inhibitors can essentially melt blockages with direct hydrate contact.
• Active heating is used to increase the temperature to above the hydrate dissociation temperature and provide significant heat flow to relatively quickly dissociate a blockage.
• Mechanical methods such as drilling, pigging, and scraping have been attempted, but are generally not recommended. Methods include inserting a thruster or pig from a surface vessel with coiled tubing through a workover riser at launchers, and melting by jetting with MEG.
• Replace the pipeline segment.

Depressurization

Depressurization is the most common technique used to remediate hydrate blockages in production systems. Rapid depressurization should be avoided because it can result in JT cooling, which can worsen the hydrate problem and form ice. From both safety and technical standpoints, the preferred method to for dissociating hydrates is to depressurize from both sides of the blockage.

If only one side of a blockage is depressurized, then a large pressure differential will result across the plug, which can potentially create a high-speed projectile. When pressure surrounding a hydrate is reduced below the dissociation pressure, the hydrate surface temperature will cool below the seabed temperature, and heat influx from the surrounding ocean will slowly melt the hydrate at the pipe boundary. Lowering the pressure also decreases the hydrate formation temperature and helps prevent more hydrates from forming in the rest of the line. Because most gas flowlines are not insulated, hydrate dissociation can be relatively fast due to higher heat flux from pipeline surfaces, as compared to an insulated or buried flowline. The depressurization of the flowlines, a process known as blowdown, creates many operational headaches.

Not only does the host facility have to handle large quantities of gas and liquid exiting the flowlines, it must also be prepared to patiently wait until the plug dissociates. Because multiple plugs are common, the process can be extremely long and much revenue is lost. Some subsea system configurations, such as flowlines with a number of low spots, can be extremely difficult to blow down. The best policy is to operate, if at all possible, in a manner that prevents hydrates from forming in the first place.

Depressurization may not be effective due to production system geometry; a sufficiently high liquid head in the riser or flowline may prevent depressurization below hydrate conditions. In this case, some methods may be needed to reduce the liquid head. If additional equipment is needed to perform depressurization or remediation, equipment mobilization needs to be factored into the total downtime. System designers need to evaluate the cost/benefit of including equipment in the design for more efficient remediation versus using higher remediation times.

Thermodynamic Inhibitors

Thermodynamic inhibitors can be used to melt hydrate blockages. The difficulty of applying inhibitors lies in getting the inhibitor in contact with the blockage. If the injection point is located relatively close to the blockage, as may be the case in a tree or manifold, then simply injecting the inhibitor can be effective. Injecting inhibitor may not always help with dissociating a hydrate blockage, but it may prevent other hydrate blockages from occurring during remediation and restart. If the blockage can be accessed with coiled tubing, then methanol can be pumped down the coiled tubing to the blockage. In field applications, coiled tubing has reached as far as 14,800 ft in remediation operations, and industry is currently targeting lengths of 10 miles.

Active Heating

Active heating can be used to remediate hydrate plugs by increasing the temperature and heat flow to the blockage; however, safety concerns arise when applying heat to a hydrate blockage. During the dissociation process, gas will be released from the plug. If the gas is trapped within the plug, then the pressure can build and potentially rupture the flowline. Heat evenly applied to a flowline can provide safe, effective remediation. Active heating can remediate a blockage within hours, whereas depressurization can take days or weeks. The ability to quickly remediate hydrate blockages can enable less conservative designs for hydrate prevention.

Mechanical Methods

Pigging is not recommended for removing a hydrate plug because the plug can become compressed, which will compound the problem. If the blockage is complete, it will not be possible to drive a pig through. For a partial blockage, pigging may create a more severe blockage. Coiled tubing is another option for mechanical hydrate removal. Drilling a plug is not recommended because it can cause large releases of gas from the blockage. Coiled tubing can be inserted through a lubricator. Coiled tubing access, either at the host or somewhere in the subsea system, should be decided early in the design phase.

Safety Considerations

Knowledge of the location and length of a hydrate blockage is very important in determining the best approach to remediation, although the methodology is not well defined, This information facilitates both safety considerations in terms of distance from the platform and time necessary to dissociate the blockage. When dissociating a hydrate blockage, operators should assume that multiple plugs may exist both from safety and technical standpoints. The following two important safety issues should be kept in mind:

• Single-sided depressurization can potentially launch a plug like a highspeed projectile and result in ruptured flowlines, damaged equipment, release of hydrocarbons to the environment, and/or risk to personnel.
• Actively heating a hydrate blockage needs to be done such that any gas released from the hydrate is not trapped.

References

[1] E. Sloan, Offshore Hydrate Engineering Handbook, SPE Monograph vol. 21 (2000).

[2] S.E. Lorimer, B.T. Ellison, Design Guidelines for Subsea Oil Systems, Facilities 2000: Facilities Engineering into the Next Millennium (2000).

[3] B.T. Ellison, C.T. Gallagher, S.E. Lorimer, The Physical Chemistry of Wax, Hydrates, and Asphaltene, OTC 11963 (2000).

[4] B. Edmonds, R.A.S. Moorwood, R. Szczepanski, X. Zhang, Latest Developments in Integrated Prediction Modeling Hydrates, Waxes and Asphaltenes, Focus on Controlling Hydrates, Waxes and Asphaltenes, IBC, Aberdeen, 1999, October.

[5] B. Ellision, C.T. Gallagher, Baker Petrolite Flow Assurance Course, Texas, Houston, 2001.

[6] E.G. Hammerschmidt, Possible Technical Control of Hydrate Formation in Natural Gas Pipelines, Brennstoff-Chemie vol. 50 (1969) 117–123.

[7] A.P. Mehta, P.B. Hebert, E.R. Cadena, J.P. Weatherman, Fulfilling the Promise of Low Dosage Hydrate Inhibitors: Journey from Academic Curiosity to Successful Field Implementation, OTC 14057 (2002).

[8] S. Cochran, Hydrate Control, Remediation Best, Practices in Deepwater Oil Developments, OTC 15255 (2003).

[9] S. Cochran, R. Gudimetla, Hydrate Management: Its Importance to Deepwater Gas Development Success, World Oil vol. 225 (2004) 55–61.

[10] F.M. Pattee, F. Kopp, Impact of Electrically-Heated Systems on the Operation of Deep Water Subsea Oil Flowlines, OTC11894, Offshore Technology Conference, Houston, Texas, 2000. May.

[11] P.F. Pickering, B. Edmonds, R.A.S. Moorwood, R. Szczepanski, M.J. Watson, Evaluating New Chemicals and Alternatives for Mitigating Hydrates in Oil & Gas Production, IIR Conference, Aberdeen, Scotland, 2001.

[12] J.S. Gudmundsson, Cold Flow Hydrate Technology, 4th International Conference on Gas Hydrates, Yokohama, Japan (2002). May.

[13] D. Lysne, Ultra Long Tie-Backs in Arctic Environments with the SINTEF-BP Cold Flow Concept, Oil and Gas Developments in Arctic and Cold Regions, U.S.–Norway Oil & Gas Industry Summit, Houston, Texas, 2005. March.