Flow assurance: Chemical inhibition of gas hydrates in deepwater production systems

When both water and guest molecules are present, hydrates can form at well above 32 °F (0 °C) if the pressure is sufficient. In oil and gas production systems, hydrates form primarily as one of two structure forms, known as Structure-I (or Type-I) or Structure-II (or Type-II) depending primarily on the size and concentration of the guest molecules.

In offshore production, the conditions conducive to hydrate formation commonly occur during transient operations (shutdown and restart conditions) due to low temperatures, but can occur under steady-state production conditions (typical of long subsea tiebacks). Hydrate formation can restrict flow and even form a solid plug to block all production in a short time period.

Remediation can be time-consuming, expensive, and dangerous depending on the location and extent of the blockage. Not only can hydrate plugs interrupt production, they can be a safety risk if not remediated properly. The chief hazard is for the plug to dislodge and then travel down the line at high speed due to differential pressure across the plug. This can cause catastrophic failure, resulting in equipment damage, injury, and even loss of life. It is essential to implement a strategy to prevent or manage hydrates for uninterrupted production in a safe and cost-effective manner.

Long deepwater subsea tiebacks are problematic due to the high pressures and low temperatures of the production fluids in the flowline. Many mechanical methods to manage or to prevent hydrate formation (e.g. insulated flowlines, active heating) seek to avoid the conditions that cause hydrate formation, but can be expensive, impractical, and/or ineffective under some conditions.

The most common way to prevent hydrates is chemical inhibition. There are two main methods of chemical inhibition: thermodynamic inhibitors (methanol, ethylene glycol) and LDHIs (low dose hydrate inhibitors).

Types of hydrate inhibitors

To determine the optimum chemical treatment when hydrates are a concern, dozens of production parameters under both steady-state and transient operating conditions must be considered. Some of the most significant factors are:

• Hydrate structure
• Subcooling
• Operating pressure and temperature
• Water composition (total dissolve solids) and water cut
• Injection points and conditions (fluids, pressure, temperature)
• Residence time of fluids
• Slugging, liquid hold-up
• Joule-Thomson cooling (valves, elbows, etc.)
• Other production chemicals in system
• Topside fluid processing.

Thermodynamic inhibitors (TIs) such as methanol and ethylene glycol work by shifting the hydrate equilibrium curve to the left to lower the hydrate equilibrium temperature enough to keep the system out of the hydrate formation region. TIs generally require very high injection rates, with higher subcooling in a system requiring a higher concentration of TI.

Thermodynamic inhibitors are sensitive to changes in system subcooling, so injection rates must be adjusted accordingly if system parameters (particularly subcooling) change. The system subcooling at operating conditions is about 33 °F (0.5 °C) , requiring more than 40% by volume of methanol injection into the system based on aqueous phase (i.e. 4 bbls of methanol injection for every 6 bbls of produced water) to prevent hydrate formation.

In some cases, regeneration units are installed to recover most of the injected TIs. Moreover, TIs can exacerbate scaling problems, cause salting out of high TDS (total dissolved solids) brines, and cause contamination of the export oil (methanol).

While thermodynamic inhibitors can be very effective under certain conditions, exploration and production into deeper waters with harsher conditions, long subsea tiebacks, and high production rates prompted the need for better hydrate inhibition methods and led to the development of low-dosage hydrate inhibitors.

Thermodynamic inhibitors used to treat systems with high subcooling and/or high water cuts often require large volumes of methanol or ethylene glycol injection (e.g. 30-60% by volume). Low dosage hydrate inhibitors (LDHIs) with typical injection rates of 0.5-2.0% by volume can be more cost-effective and practical when used properly. There are two primary types of LDHIs – anti-agglomerates (AAs) and kinetic hydrate inhibitors (KHIs). Unlike thermodynamic inhibitors, LDHIs do not significantly change the hydrate equilibrium curve and operate on completely different mechanisms.

AA hydrate inhibitors are surface active molecules that attach to and disperse fine hydrate particles to prevent them from agglomerating and growing into masses that could become a plug. When small hydrate crystals begin to form, the AA molecules attach to them to help make the surface hydrophobic, which mediates the capillary attraction between the crystals and free water and disperses the fine particles into the oil layer. This results in a transportable slurry of tiny hydrate particles in oil that can flow to the processing facilities.

Because AAs allow hydrates to form as very fine crystals dispersed in the oil layer, these types of applications generally do not depend on subcooling. For more than a decade, anti-agglomerates have been cost-effective alternatives to thermodynamic inhibition. However, AAs have two primary limitations, namely water cut and topside emulsion formation.

Since AAs require an oil layer to disperse the hydrate particles, they have a water-cut limitation that typically ranges around 40-60% water cut, depending on conditions (such as water composition). AAs generally are more effective in higher salinity brines, but more recent advances in the technology have resulted in AAs that work in condensed water systems.

Because they are surfactants, AAs can contribute to stable emulsion formation and/or affect overboard water quality. In addition to hydrate performance testing, it is essential that emulsion tendency testing is performed using different formulations, active components, and topsides chemicals in order to ensure adequate separation and water quality is maintained, particularly with continuous injection applications.

With proper testing and formulation, AAs can offer the most cost-effective solution to hydrate control for both oil and gas systems with low-to-moderate water cuts. Some offshore production systems are being designed with AAs as the primary hydrate control.

Kinetic hydrate inhibitors (KHIs) typically are water soluble, low molecular weight polymers whose active groups interfere with the nucleation and growth of hydrate crystals. Unlike AAs, KHIs delay hydrate formation for a length of time, known as the “hold time” or “induction time.” The length of the hold time depends primarily on the subcooling of the system. Higher subcooling results in shorter hold times.

Hold times can range from as little as a few hours or days to as long as several weeks (for lower subcooling). KHIs have a subcooling limits rather than water-cut limits, and can work even at 100% water cut. The practical subcooling limit for most KHIs is around 22 °F (12 °C). At higher subcooling, the hold times are not sufficient for most offshore applications. However, KHIs have been combined with methanol or glycol to extend this subcooling limitation, and combinations of thermodynamic and kinetic inhibitors are in use in both offshore and onshore production systems.

KHIs are useful for systems with low-to-moderate (5-20 °F) subcooling that operate under generally consistent conditions, but there are several limitations that must be considered. Since KHIs operate on a time-dependent mechanism, they are not practical in systems which may experience long shut-in conditions. Systems which produce Structure-I hydrates are more difficult to treat with KHIs when compared with the more common Structure-II hydrates. Most of the high-performance KHIs have solubility limitations based on temperature and salt content of the water. They become less soluble and even precipitate at higher temperatures and/or salt content of the water phase. Other chemicals in the system, particularly corrosion inhibitors, can impact a KHI.

Overall, KHIs (alone or with thermodynamic inhibitors) offer an alternative way to control hydrate formation that can be the most practical solution under the right conditions. KHIs have been used successfully in the field for about 13 years.

Testing methods and equipment

While there are several types of testing equipment and methods designed to mimic field conditions for hydrate formation and inhibitor testing, they fall into three types of equipment: rocking cells, autoclaves, and flow loops. Each attempts to recreate the field conditions by charging the system with an oil phase, water phase, and gas phase under the high-pressure and low-temperature conditions of the field and then measure the performance of various inhibitors and dose levels under these conditions. It is critical to use the actual field fluids and gas compositions to accurately reproduce the field conditions.

Since other production chemicals can affect the performance of the inhibitors, those chemicals must be included in tests. Finally, the test equipment has to simulate both steady-state and shut-in/restart conditions.

It is generally agreed that large flow loops come closest to matching field system conditions. The relative size, flow regime, and gas-to-oil ratio can be reproduced more accurately in flow loops. The drawbacks are the large amount of fluids required and the time involved in set-up and turnaround. For most field applications where multiple formulation testing and dose rate optimization is necessary and requires several sets of tests, flow loop testing can be impractical.

They are most often used for fundamental studies and “final” testing versus chemical selection. Flow loops can range in total length and pipe diameter from very large (4 in ID and several hundred feet in length) to very small “mini-loops.” Hydrate formation or plugging in flow loops usually is detected by differential pressure across the pump.

High-pressure autoclaves are common pieces of hydrate test equipment. These are temperature-controlled cells that include some sort of agitation, either magnetic stir bar or blade type agitator-mixer. They often include a viewing window with built-in video and still picture capability as well as torque measurements for the stirring blades and pressure/temperature transducers. They are useful for KHI testing with very long hold times (seven days or more) and usually require no more than a few hundred milliliters of fluids per test. Hydrate formation is detected by a pressure drop in the cell as recorded by a data acquisition system.

High-pressure rocking cells (or rocking ball cells) use small individual “cells” charged with the test fluids, pressurized with the field gas, then cooled to pipeline conditions while being rocked back and forth. A stainless steel ball in the cylindrical fluid chamber provides agitation during rocking. The main chamber typically is a clear sapphire tube configured to allow observation during testing. This is important when testing AAs because the size and dispersion of the hydrate crystals, observations of fluid flow characteristics, and whether clusters of hydrates stick to the sides or ends of the chamber are critical to predict whether a particular candidate will work in the field.

Rocking cells have the advantage of high throughput and can test several different inhibitor formulations, dose levels, water cuts, and fluid and gas compositions in a single test run, and require only small amounts of test fluids. In general, rocking cells are considered a conservative test, and experience has shown that when properly conducted, it is a good predictor of both AA and KHI performance in the field.

About the authors

Zubin Patel graduated cum laude with a Bachelor of Science degree in chemistry from Midwestern State University and earned a Ph.D. in synthetic organic chemistry from the University of Southern California.

Jim Russum earned a Bachelor of Science degree in chemical engineering from Tennessee Technological University and a Ph.D. in chemical engineering with a minor in polymer chemistry from the Georgia Institute of Technology.

Case history

An operator had hydrate problems in several high-GOR gas wells producing light condensate and condensed water. The wells, producing over 200 MMcf/d via a 20-mi (32 km) subsea tieback to a host facility, had to be treated with methanol on a continuous basis. Field optimization with methanol called for continuous use of about 4,500 gal/day to avoid hydrate issues. While methanol was successful, the operator was near maximum methanol delivery capacity and sought a more practical, cost-effective solution.

Due to the low water cut in the system, an AA was proposed. However, continuous treating of condensed water in a high-GOR gas system over 20 mi is problematic for most AAs, so a new AA chemical and formulation was developed specifically for this system to maximize performance while minimizing topsides impact of emulsions.

The newly developed AA was tested and custom-formulated for these fluids and conditions. All of the wells were converted to the AA, replacing the methanol with less than 200 gal/day of continuous injection with the new AA. To date, all of the wells are operating at normal capacity, no hydrate issues have arisen, and topsides emulsion impact has been minimal. The yearly operational savings is estimated at over $1.5 million.