Many materials may be added to water to depress the hydrate temperature. For many practical reasons, a thermodynamic hydrate inhibitor (THI) such as an alcohol or one of the glycols is injected, usually methanol, diethylene glycol (DEG) or monoethylene glycol (MEG). All may be recovered and recirculated, but the economics of methanol recovery may not be favorable in many cases. Hydrate prevention with methanol and or glycols can be quite expensive because of the high effective dosage required (10 to 60% of the water phase). Large concentrations of solvents can aggravate potential scale problems by lowering the solubility of scaling salts in water and precipitating most known scale inhibitors. The high rates of methanol create a logistical problem as well as a health, safety, and environmental (HS&E) concern because of the handling issues associated with methanol. The total injection rate of inhibitor required is the amount/concentration of inhibitor in the liquid water phase for the desired hydrate temperature suppression, plus the amount of inhibitor that will distribute in the vapor and liquid hydrocarbon phases. Any inhibitor in the vapor phase or liquid hydrocarbon phase has little effect on hydrate formation conditions.  Due to the accuracy limitations of the hydrate depression calculations and flow distribution in the process, it is recommended that the hydrate formation temperature with inhibition be chosen with a design factor below the coldest expected operating temperature of the system to ensure adequate inhibitor injection rates.

Low dosage hydrate inhibitors (LDHIs) are relatively new and only recently reaching the “proven technology” stage in oil and gas processing.  Although LDHIs move the hydrate formation line to the left, it is only temporary. In typical systems they will “delay” the formation of hydrates for about 12 hours. The LDHIs are two classes of chemicals: Kinetic inhibitors (KHIs) and Anti-Agglomerants (AAs). A KHI can prevent hydrate formation but contrary to methanol cannot dissolve an already formed hydrate. Current KHIs have a difficult time overcoming a subcooling temperature (ΔT) threshold of about 15 °C (27 °F). AAs allow hydrates to form and maintain a stable dispersion of hydrate crystals in the hydrocarbon liquid. AAs form stable water in oil micro-emulsion. AAs adsorb onto the hydrate crystal lattice and disrupt further crystal growth but must have a liquid hydrocarbon phase present and the maximum water to oil ratio is about 40-50%.

Laboratory studies and field experiences indicate hydrate-inhibition synergy is gained through the combination of a THI and LDHI [1]. This is termed a hybrid hydrate inhibition (HHI). In the June 2010 tip of the month (TOTM) we demonstrated the synergy effect of mixed THIs like NaCl and MEG solution and presented a shortcut method to estimate the synergy effect of brine and MEG solution. In this TOTM, we will discuss the results of a successful application of combined methanol and a KHI solution for a well producing natural gas, condensate and water in the Gulf of Mexico (GOM). The following sections are based on the paper presented by Szymczak et al. [1].

As mentioned earlier, THIs are used in concentration ranging from 10 to 60 weight percent in water and LDHIs are used in concentration normally less than 5 weight percent. Proper combination of THI and LDHI will result in lower injection rates of the combined inhibitor mixture while controlling hydrate formation. In addition, the combined inhibitor mixture provides the ability to dissociate any hydrates that may form. Table 2 extracted from reference [1] presents the cost comparison between LDHI and methanol for various related activities. As can be seen in this table the cost of HHI for most activities is low and medium for unit cost and volume usage.

Table 1- Cost comparison of LDHI, Methanol and HHI for an offshore application [1]

Cost Factor LDHI Methanol HHI
Unit Cost Very High Low Medium
Transportation Low High Low
Pump High High Low
Storage Low High Low
Crane Lifts Low High Low
Corrosion Low High Low
Volume Low High Medium

Field Study:

To demonstrate the synergy effect of THI plus LDHI (HHI) and to illustrate the advantage of using HHI, we will discuss the results of a field study in the GOM reported by Szymczak et al. [1]. The well production flows 5.6 km (3½ miles) through 114 mm (4½-in) flowline to a production platform where natural gas, condensate and water are separated. There was a seven-line umbilical bundle that included a 9.5 mm (3/8-in) outside diameter line for methanol and/or LDHI injection. The hydrate-inhibitor injection point was at the tree. The recent gas composition is presented in Table 2 while detailed system information is shown in Table 3.

Table 2- Field Gas Composition [1]

Component Mole %
Nitrogen 0.2045
Carbon Dioxide 0.5893
Methane 95.7432
Ethane 0.4462
Propane 0.3431
i-Butane 0.1508
n-Butane 0.1823
i-Pentane 0.1262
n-Pentane 0.1088
Hexane 0.1663
C7+ 1.9392

To inhibit hydrate formation, a sufficient rate of methanol was injected to assure hydrate-free operation. Knowing the rate of water production, methanol was injected at approximately 0.019 m3/h (5 gal/hr). The injection rates were monitored and adjusted by comparing the chemical feed-line pressure at the wellhead and the flowline pressure measured at the platform.

Monitoring pressure drop between the inlet and outlet of pipelines is an industry-wide standard method of flow assessment. Fluctuating pressure drop values provide the operator with instant information concerning flow irregularities or obstructions. Only formed and dislodged hydrates manifest as rapid pressure fluctuations, whereas flow regime change or wax and scale build up result in gradual pressure changes. The GOM facilities operating experience showed that with only methanol in the system, the pressure difference between the wellhead and the flowline at the platform changed rapidly. The differential pressure changed as much as 345 kPa (50 psi) daily and was always between 1034 and 1724 kPa (150 and 250 psi) [1].

Table 3- Flowline Data [1]

Terrain Flat
Gas Flow Rate 0.5663 x106 std m3/d (20 MMSCF/D)
Line Length 5.6 km (3.5 miles)
Line Diameter 114 mm (4.5 in)
Water Flow Rate 0.023 m3/d (6 gal/day)
Condensate Traces
High Pressure 35, 853 kPa (5,200 psi)
Low Pressure 7,584 kPa (1,100 psi)
Average Pressure 27,579 kPa (4,000 psi)
Flow Speed 3.66 to 6.096 m/s (12 to 20 ft/sec)
Practical Methanol Rate 0.019 m3/h (5 gal/hr)
Sea Temperature 5 °C (41 °F)
Outlet Temperature 12.8 °C (55 °F)

Table 4 presents a summary of Szymczak et al. [1] calculation results for the worst case-scenario methanol injection rate. The relatively large dosage of methanol required was the result of a combination of temperature and gas volume conditions in the pipeline resulting in most of the injected methanol going into the vapor phase of the system at equilibrium conditions. For the detail of calculations, refer to Chapter 6, Volume 1, Gas Conditioning and Processing [2]. For methanol concentration below 25 weight percent, the Hammerschmidt [3] equation may be used. The practical 0.019 m3/h (5 gal/hr) rate of methanol applied resulted in borderline operating conditions between obstructed flow and line plugging. Szymczak et al. stated that the short fluid residence time in the flowline prevented the formation of a complete hydrate plug. Note that the high values of subcooling temperature eliminated KHI as the sole hydrate-prevention method. Known KHIs become ineffective inhibitors at approximately ΔT>15 °C (ΔT>27 °F) [1].

HHI Results

Szymczak et al. [1] reported that the inhibitor usage was reduced dramatically from 0.019 m3/h (5 gal/hr) of methanol to 0.0028 m3/h (0.75 gal/hr) of HHI and the pressure drop showed a lowering trend. They optimized the HHI dosage at approximately 0.0025 m3/h (0.67 gal/hr), a HHI rate sufficient to protect the flowline from producing hydrates in any case of rate or pressure/temperature fluctuation. This HHI rate represented an 80% reduction compared to the methanol injection rate. As a result of the injection rate reduction, the costs of transportation, pump maintenance, storage on the platform, corrosion inhibition of the flowline, labor and safety costs related to crane lifts, and pressure drop were reduced. For further detail on this field study, refer to Szymczak et al. paper [1].

Table 4- The worst case-scenario theoretical methanol injection rate requirement

Flowline Pressure Option 35, 853 kPa (5,200 psi) 27,579 kPa (4000 psi)
Hydrate depression (Subcooling) 23 °C (41.4 °F) 20 °C (36 °F)
Weight % methanol in water phase 23 20
Injection rate 0.045 m3/h (12 gal/hr) 0.035 m3/h (9.2 gal/hr)

In summary, HHI provides both thermodynamic and LDHI inhibition. From a cost standpoint, the HHI is cost-efficient compared to THIs. Additionally, the HHI can reduce corrosion and may eliminate the need for corrosion inhibitor.  From an offshore operational standpoint, the HHI significantly reduces logistical costs related to shipping, storage, handling, and chemical pumping. In addition to cost reduction, the problems related to health, safety, and environment (HS&E) would reduce too.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing) and G5 (Gas Conditioning and Processing – Special).

John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at, or email your consulting needs to

By: Dr. Mahmood Moshfeghian


  1. Szymczak, S., Sanders, K., Pakulski, M., Higgins, T.; “Chemical Compromise: A Thermodynamic and Low-Dose Hydrate-Inhibitor Solution for Hydrate Control in the Gulf of Mexico,” SPE Projects, Facilities & Construction, (Dec 2006).
  2. Campbell, J. M., “Gas Conditioning and Processing”, Vol. 1, The Basic Principles, 8th Ed., Second Printing, J. M. Campbell and Company, Norman, Oklahoma, (2002).
  3. Hammerschmidt, E. G. “Formation of Gas Hydrate in Natural Gas Transmission Lines”, Ind. Eng. Chem., 26, 851-855, (1934).
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