Gas subsea systems typically contain small quantities of water, which allows them to be continuously treated with methanol or glycol to prevent hydrate formation. These inhibitors prevent the formation of hydrates by shifting the hydrate stability curve to lower temperatures for a given pressure. If the systems produce too much water, it is difficult to economically treat with methanol. As a result, the system designs have to incorporate insulation of almost all components of a system and develop complex operating strategies to control hydrate formation during transient activities such as system startup and shutdown.

Hydrate prevention techniques for subsea systems include:

  • Thermodynamic inhibitors;
  • Low-dosage hydrate inhibitors (LDHIs);
  • Low-pressure operation;
  • Water removal;
  • Insulation;
  • Active heating.

Thermodynamic Inhibitors

The most common method of hydrate prevention in deepwater developments is injection of thermodynamic inhibitors, which include methanol, glycols, and others. Methanol and MEG are the most commonly used inhibitors, though ethanol, other glycols, and salts can be effectively used. Inhibitor injection rates, whether methanol or MEG, are a function of water production and inhibitor dosage. Inhibitor dosage is a function of design temperature and pressure and produced fluid composition. Water production multiplied by the methanol dosage is the inhibitor injection rate, which will change throughout field operating life due to typically decreasing operating pressures and increasing water production.Selection of the hydrate inhibitor is an important decision to be made in the early FEED design and can involve a number of criteria:

  • Capital costs of topside process equipment, especially for regeneration;
  • Capital costs of subsea equipment;
  • Topside weight/area limitations;
  • Environmental limits on overboard discharge;
  • Contamination of the hydrocarbon fluid and impacts on downstream transport/processing;
  • Safety considerations;
  • System operability;
  • Local availability of inhibitor.

Methanol and MEG are both effective inhibitors if sufficient quantities are injected; for deep water, inhibitor dosages of 0.7 to 1 bbl of inhibitor per barrel of water are generally used. Methanol can provide higher hydrate temperature depression but this effect is typically countered by high losses to the hydrocarbon liquid and gas phases. The selection of inhibitor is often based on economics, downstream process specifications, environmental issues, and/or operator preferences.

Costs for inhibition systems are driven by up-front capital costs, which are dominated by the regeneration system and also by makeup costs for inhibitor loss. Methanol is cheaper per unit volume, but has greater makeup requirements. Additionally, a methanol regeneration system may be as much as 50% less expensive than a MEG regeneration system. The methanol system starts out cheaper, but, with increasing field life, becomes more expensive due to methanol makeup costs.

The risks of using thermodynamic inhibitors include:

  • Underdose, particularly due to not knowing water production rates;
  • Inhibitor not going where intended (operator error or equipment failure);
  • Environmental concerns, particularly with methanol discharge limits;
  • Ensuring remote location supply;
  • Ensuring chemical/material compatibility;
  • Safety considerations in handling methanol topside.

Low-Dosage Hydrate Inhibitors

While development of AAs and KHIs continues, cost per unit volume of LDHIs is still relatively high, but is expected to decrease as their use increases. A potentially important advantage is that they may extend field life when water production increases.

Low-Pressure Operation

Low-pressure operation refers to the process of maintaining a system pressure that is lower than the pressure corresponding to the ambient temperature based on the hydrate dissociation curve. For deep water with anambient temperature of 39 F (4 C), the pressure may need to be 300 psia (20 bar) or less. Operation at such a low pressure in the wellbore is not practical because pressure losses in a deepwater riser or long-distance tieback would be significant. By using subsea choking and keeping the production flowline at a lower pressure, the difference between hydrate dissociation and operating temperatures (i.e., subcooling) is reduced. This lower subcooling will decrease the driving force for hydrate formation and can minimize the inhibitor dosage.

Water Removal

If enough water can be removed from the produced fluids, hydrate formation will not occur. Dehydration is a common hydrate prevention technique applied to export pipelines. For subsea production systems, subsea separation systems can reduce water flow in subsea flowlines. The advantage of applying subsea separation is not only hydrate control, but also increasing recovery of reserves and/or accelerating recovery by making the produced fluid stream lighter and easier to lift. Another benefit is reduced topside water handling, treatment, and disposal.

As a new technology, subsea water separation/disposal systems are designed to separate bulk water from the production stream close to subsea trees on the seafloor. Basic components of such a system include a separator, pump to reinject water, and water injection well. Additional components include instrumentation, equipment associated with controlling the pump and separator, power transmission/distribution equipment, and chemical injection.

Water cut leaving the separator may be as high as 10%. Operating experience on the Troll Pilot has shown water cuts of 0.5 to 3%. Because these systems do not remove all free water, and water may condense farther downstream, subsea bulk water removal does not provide complete hydrate protection. These systems need to be combined with another hydrate prevention technique, for example, continuous injection of a THI or LDHI. The main risk associated with subsea water separation systems is reliability.

Thermal Insulation

Insulation provides hydrate control by maintaining temperatures above hydrate formation conditions. Insulation also extends the cooldown time before reaching hydrate formation temperatures. The cooldown time gives operators time either to recover from the shutdown and restart a warm system or prepare the system for a long-term shutdown.

Insulation is generally not applied to gas production systems, because the production fluid has low thermal mass and also will experience JT cooling. For gas systems, insulation is only applicable for high reservoir temperatures and/or short tie-back lengths. One advantage of an insulated production system is that it can allow higher water production, which would not be economical with continuous inhibitor injection. However, shutdown and restart operations would be more complicated. For example, long-term shutdowns will probably require depressurization.

Active Heating

Active heating includes electrical heating and hot fluid circulation heating in a bundle. In flowlines and risers, active heating must be applied with thermal insulation to minimize power requirements.

Electrical Heating

Electrical heating (EH) is a very fast developing technology and has found applications in the offshore fields including Nakika, Serrano, Oregano, and Habanero in the GoM, and Asgard, Huldra, and Sliepner in the North Sea. Advantages of electrical heating include eliminating flowline depressurization, simplifying restart operations, and providing the ability to quickly remediate hydrate blockages. Electrical heating techniques include:

  • Direct heating, using the flowline as an electrical conductor for resistance heating;
  • Indirect heating, using an EH element installed on the outer surface of flowline.

Hot Fluid Circulation Heating in a Pipe Bundle

Hot fluid heating has many of the same advantages as electrical heating. Instead of using electricity for supplying heat, however, hot fluid, typically inhibited water, circulates in the bundles to provide heat to the production fluids. Examples of such bundles include Statoil Asgard and Gullfaks South, Conoco Britannia, and BP King. These bundles can be complex in design, with thermal and mechanical design, fabrication, installation, life cycle, and risk issues that need to be addressed.

Active heating techniques provide a good level of protection. With active heating, hydrate control is simply a matter of power, insulation, and time. Active heating can increase the operating flexibility of a subsea production system, such that concerns including water cut, start-up, and operating flow rate and depressurization times are of lesser importance. Electrically heated flowlines and low-dosage hydrate inhibitors are two developing technologies in hydrate prevention for reducing the complexity of the design and operation of subsea systems.

Electrically heated flowline technology reduces hydrate concerns in subsea systems. Instead of relying on the lengthy process of blowdown for hydrate remediation, electrical heating provides a much faster way to heat the flowline and remove the plug. The other potential advantages of electrical heating are covered in Chapter 14. Low-dosage hydrate inhibitors reduce the volume of chemicals that must be transported and injected into the subsea system. Methanol treatment rates, for hydrate control, are on the order of one barrel of methanol for each barrel of produced brine. The low-dosage hydrate inhibitors may be able to accomplish the same task at dosage rates of less than 1%. This leads to a reduction in umbilical size and complexity. Note, however, that the hydrate inhibitors must be injected continuously to prevent hydrate formation.

References

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[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.