FLOW ASSURANCE: Hydrate inhibitors for deepwater flow assurance

Deepwater oil and gas exploration has increased significantly in recent years, with forecasts predicting that this trend will continue. Because of the high capital and operating expenditures inherent in these developments, it is economically favorable to develop satellite fields with subsea completions.

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Reducing capital investment and operating expenses

Pramod Kulkarni
Baker Petrolite Corp.

Deepwater oil and gas exploration has increased significantly in recent years, with forecasts predicting that this trend will continue. Because of the high capital and operating expenditures inherent in these developments, it is economically favorable to develop satellite fields with subsea completions. These satellite fields tie back to existing facilities via flowlines that can extend beyond 60 mi.

The deepwater environment exposes these lines to temperatures near 40° F, which can create production problems in subsea flow and pipework due to the formation of gas hydrates. These hydrate plugs have been known to form as long as 6.2 mi and have blocked pipe as large as 40 in. in diameter. Some of these plugs can take weeks and even months to dissociate. Not only do these plugs cause a loss in production, but they also create a severe safety and environmental hazard.

Thermodynamic inhibitors

Historically, the formation of gas hydrates in subsea production facilities has been managed by keeping the fluids warm, removing water, or by injecting thermodynamic inhibitors. The most common of these hydrate inhibitors are methanol (MeOH) and glycols such as monoethylene glycol (MEG). Thermodynamic inhibitors suppress the point at which hydrates form, much like an antifreeze for water-ice, allowing protection under the most severe hydrate formation conditions.

A disadvantage is that the greater the subcooling, i.e., more severe the hydrate problem, the more inhibitor is required. As such, production facilities can reach a rate limit of methanol treatment due to supply, storage, and injection constraints, resulting in non-optimum production and increased risk of hydrate plug formation. Capital and operating costs together with production feasibility for new facilities design are also negatively impacted where large volumes of methanol are required.

Low-dosage inhibitors

Two alternate technologies for the control of gas hydrates have been developed, each having its own distinct advantages over the use of thermodynamic inhibitors. These are called kinetic hydrate inhibitors (KHI) and anti-agglomerant inhibitors (AA). They achieve hydrate control dosages that are orders of magnitude lower than those typically dosed for methanol.

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In deep waters, these lines are exposed to temperatures near 40° F, which can create flow problems in subsea flowlines, risers, and export pipelines due to the formation of hydrates
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A KHI delays hydrate formation for a period known as the induction period. This period is system specific, and as such KHIs are designed to meet individual facility requirements. KHIs are able to prevent hydrates up to around 18-20° F subcooling and are applicable to both gas and oil systems. An AA inhibitor allows hydrates to form, but as tiny, nonadherent particles that are easily dispersed into the liquid hydrocarbon phase. This inhibitor is effective to around 40° F subcooling. As such, an AA inhibitor is an economically attractive option under severe hydrate-forming conditions and is also very effective where production is shut-in for extended periods.

LDHI advantages

Both kinetic and anti-agglomerant hydrate inhibitors have the ability, when applied, to lower capital costs, reduce operating and intervention expenses, and optimize production. New production platforms can be downsized as a result of a reduction in chemical treatment storage space and weight. Umbilical design may also benefit in a reduction in size. Low-dosage hydrate inhibitors (LDHIs) have been proven to reduce supply chain costs associated with chemical, transportation, and storage. Refineries often charge a premium to process oil and gas feedstocks that contain high levels of methanol. This methanol penalty can be as much as $2/bbl. With LDHI application, there is less risk of a methanol penalty.

The LDHIs can be combined with other types of chemical treatments, reducing the number of umbilicals needed. A few of the commercially available multifunctional products are:

  • Anti-agglomerant LDHI/corrosion inhibitor
  • Anti-agglomerant LDHI/paraffin/corrosion inhibitor
  • Anti-agglomerant LDHI/paraffin inhibitor
  • Kinetic LDHI/corrosion inhibitor.

Hydrate inhibition

A subsea well in deepwater Gulf of Mexico produces 3,600 b/d of oil, 2 b/s of water, and 2.3 MMcf/d of natural gas. The 4-mi flowline is uninsulated. Fluids arrive at the platform at 600 psig of pressure and 42° F, several degrees below the predicted hydrate formation temperature. During shut-ins, the flowline pressure can reach 2,000 psig, thus posing a severe hydrate formation problem.

Prior to this field test, hydrates were controlled by methanol injection. After an extensive screening process, Baker Petrolite formulated an anti-agglomerant LDHI for use in this subsea well. With a viscosity of 23 cP at 40° F, the inhibitor was applied through long umbilicals with a small chemical injection pump. Extensive hydrate cell experiments demonstrated definitively that the product readily controlled hydrates in field oil under conditions similar to those expected in this system.

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LDHIs lower capital costs, reduce operating and intervention expenses, and help accelerate and maximize production.
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After confirming product efficacy, the next greatest concern was to ensure the product would have no detrimental effects on the production system. Capillary stability tests were thus performed at both high 190° F and low 40° F temperatures. Any increase in viscosity, solids deposition, or tendency to plug would have manifested itself by a rising differential pressure across the capillary column.

The LDHI showed no such rise in differential pressure at either temperature, thus verifying the product's suitability for injection through a long umbilical and downhole capillary. Extensive corrosion and materials compatibility tests verified that the product was compatible with all materials present in this system.

Chemical compatibility tests demonstrated the LDHI was compatible with both methanol and the paraffin inhibitor in use in the subsea well. Also, the LDHI was tested in the produced fluids to ensure no emulsion problems would be created. The 1.5-month field test successfully demonstrated the applicability of the anti-agglomerant LDHI in a subsea tieback. After the methanol injection line was flushed with the LDHI, 100 gal of the inhibitor were injected into the flowline. Even at this high concentration (two orders of magnitude higher than the normal treating rate), the inhibitor did not upset the production system.

No hydrate problems were detected during inhibitor injection, even during two brief shut-ins. The LDHI did not adversely affect overboard water quality: both oil and grease counts and aquatic toxicity tests remained within the normal operating range of this platform. The LDHI did not cause any emulsion problem, and basic sediment and water counts remained low.

Kinetic hydrate inhibitor

A field in the UK sector of the North Sea, where production is principally gas, produces via a subsea template. Fluid production is 50 b/d, of which three-fourths is water. The gas and associated fluids are transported from the template to a central handling facility via a 12-in., 10-mi flowline. The flowing wellhead pressure is 943 psig, which increases to 2,175 psig on shut-in. The flowing wellhead temperature is 96.8° F (on shut-in this falls to the temperature of the seabed, typically 39.2° F).

Hydrate control was historically maintained via the application of MEG. Under normal operations, the MEG is separated with the water at the separation stage and then regenerated to remove the water. The MEG delivery and regeneration cycle is operated in a closed loop, and as a result, increasing levels of salt have led to salt precipitation problems. The consequence of this is that the MEG is dumped overboard when clean up operations are carried out. The dumping of MEG was considered an unacceptable operating cost, which had logistic issues resultant from the need to store large volumes of MEG. In addition, the overboard discharge had environmental issues that needed to be controlled.

The typical worst-case subcooling that the system was exposed to was between 16° F and 20° F. This level made the application of an LDHI a viable alternative to MEG. Because of the high volumes of gas and relatively low levels of water/condensate produced, kinetic hydrate inhibitors were the most suitable chemical alternative.

Product performance tests were performed under worst-case operating conditions, simulating shut in and start up. In addition, compatibility tests were carried out on umbilical material. The effects of other production chemistries, primarily corrosion inhibitors, on the kinetic hydrate inhibitor performance were studied.

When the tests were complete, a trial was carried out in mid-2002 by replacing the MEG with a kinetic hydrate inhibitor. The subsequent optimization of the dosage rate has now delivered an alternative to MEG, which to date has afforded no hydrate related problems, and has removed the associated problems inherent with the MEG application. The use of the kinetic inhibitor has enabled production targets to be maintained, meeting required delivery volumes and schedules, improving the operation and economics of the production system.

Systems approach

Deepwater flow assurance through chemical treatment requires the selection of optimum combination of inhibitors and the design of a chemical injection and handling system. As various crudes respond differently to different inhibitors, a customized approach is best for achieving optimal performance. Some design parameters include treatment rates, pump capacity, and flow line diameters. Modeling the phase behavior of the flowline fluids will also provide critical design information.

Acknowledgments

The author would like to thank Nick Phillips and Lynn Frostman with Baker Petrolite Corp. for their major contribution.

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