B41oa oil and Gas Processing Section a flow Assurance Heriot-Watt University

1.6 Gas Hydrate Inhibition 
Current techniques for inhibiting hydrate formation are classified into two 
categories: 
1. Thermodynamic control. 
2. Low dosage inhibitors. 
The latter is now composed of different sub-groups that, such as nucleation 
inhibitors and anti-agglomerants. Thermodynamic inhibition has been the 
traditional method for preventing hydrate formation. However, in recent times, 
kinetic inhibition has offered a more attractive methodology, both in terms of 
cost and its more environmentally friendly aspect. 
1.6.1 Thermodynamic Inhibition 
Methanol (CH
3
OH) has long been the ‘classical’ thermodynamic inhibitor of 
hydrate systems. Its behaviour essentially mimics anti-freeze in that it lowers 
the activity of water and displaces the equilibrium lines for hydrate formation to 
lower temperatures. 
After being vaporised into the gas at some upstream point, methanol then 
becomes concentrated in the free water phase. Methanol is by far the most 
commonly used chemical inhibitor. The process is to vapourise the methanol 
into the pipeline, well upstream of any possible hydrate formation zone, the 
methanol then flows with the gas and subsequently becoming dissolved in any 
free water. 
Another common thermodynamic inhibitor is mono ethylene glycol, which has 
a lower vapour pressure than methanol so can be recovered and re-used more 
easily. This also means that MEG losses to the vapour and condensate 
phases are also smaller compared to MeOH. However, MEG only provides 
inhibition in the free water and is rarely used for plug removal, unless it can be 
injected directly above the plug (e.g. in a riser). 
Thermodynamic inhibitors possess a distinct advantage in that they ensure 
that no hydrates will form if the inhibitor is added in the correct quantity over a 
specific temperature and pressure range. 
The major drawback, however, are the costs associated with this method. In 
deepwater conditions, the pressure and temperature conditions are even more 
extreme and this requires even larger amounts of methanol to prevent hydrate 
formation. An example of this is in the Gulf of Mexico where up to 60 wt.% 
methanol can be required. 
The associated costs are exacerbated by the frequent requirement of a 
secondary pipeline to transport the inhibitor from the processing platform to the 
wellhead (where it is injected into the main pipeline). 

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TOPIC 1: Gas Hydrates 
 
 
 
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The high concentrations of methanol pose a further dilemma, with its disposal 
having strong environmental implications. After hydrate-free transport of the 
wet gas, the choices are either to dump the water phase in the sea, or install a 
distillation unit to separate the inhibitor from the water: 
•
The former choice would mean that the methanol could be used only 
once and this is coupled to the environmental hazards of large-scale 
dumping; this option appears to be somewhat detrimental. 
•
The latter option requires the installation of expensive and energy 
consuming process units. 
•
The worldwide costs associated with methanol usage are in excess of 
$500 million dollars per annum and, due to its unequivocal 
effectiveness, this figure is likely to increase further. 
The thermodynamic method removes the hydrate former system from the 
hydrate thermodynamic stability region of the phase diagram. As long as the 
system is kept outside the thermodynamic stability condition, hydrate will not 
be formed. 
Thermodynamic inhibitor injection will shift the hydrate stability zone to the left, 
resulting in pipeline conditions outside the hydrate stability zone, as 
demonstrated in Figure 16. 
Perhaps the main technical problem is the transfer of inhibitor to the plug 
location. Methanol is commonly used in the industry due its high vapour 
pressure. Methanol’s high vapour pressure will facilitate its transport via the 
vapour phase to the plug location. 
For this reason it is not as effective for liquid systems or where a liquid phase 
separates the hydrate block from the vapour phase. However, for such 
systems it is possible to use other inhibitors, or to transfer methanol using 
other techniques, such as with the aid of coiled tubing. 
Figure 16: Hydrate Dissociation by Inhibitor Injection. 

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TOPIC 1: Gas Hydrates 
 
 
 
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The injection of methanol (or other inhibitors) will result in the dissociation of 
some gas hydrates leading to the following effects, some of which have 
already been discussed: 
1. Dissociation of gas hydrates is an endothermic process and this will 
result in a decrease in the system temperature. 
2. Some gas will be released as the hydrate dissociates and this will 
result in an increase in the system pressure. 
3. In addition, dissociation of gas hydrates will result in some free water. 
4. Additional free water reduces the concentration of inhibitor, which in 
turn will move the hydrate phase boundary to the right. 
5. Each, or a combination of the above factors, will move the system to 
the gas hydrate phase boundary. 
6. At this point further gas hydrate dissociation will stop. 
It is possible to maintain system pressure by releasing extra gas, which will 
result in more gas hydrate dissociation. However, heat is required for further 
gas hydrate dissociation. Also fresh inhibitor should be injected to maintain 
inhibitor concentration in the free water phase. Once again it is evident that, for 
a successful removal of pipeline blockages, the most important factor is time 
and patience. 
A good strategy would be to combine hydrate removal and prevention 
techniques where possible to achieve maximum efficiency. Clearly a plan 
should be worked out together with continuous monitoring of the system 
parameters. It is very difficult to design a standard plan for all pipelines, as 
each system could be different. However, it is believed that the above points 
and methods are helpful in designing a plan for blockage removal. 
A rough estimate (15% accuracy) of the amount of thermodynamic inhibitor 
required for effective inhibition can be determined from 
(
)
I
I
I
I
C
T
M
T
M
W
+
Δ
×
Δ
×
×
=
100
………
..
……………………
.(1.1)
Where 
I
W
is the weight percent of inhibitor required to inhibit hydrate 
formation at the conditions, 
I
M
is the molecular weight of the inhibitor, 
T
Δ
is 
the degree of subcooling 
(
)
op
eq
T
T
−
and
I
C
is the constant for a particular 
inhibitor (MeOH = 2335 and MEG = 2000). 
While this provides an estimate of the inhibitor requirements, it is common 
practice to add more inhibitor as a safety margin. 

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TOPIC 1: Gas Hydrates 
 
 
 
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The amount of inhibitor actually added is determined from three additional 
quantities: 
•
The amount of free water. 
•
The amount of inhibitor lost to the gas phase. 
•
As a general rule at 4°C and pressures greater than 1000 psi(a) 
this has been found to be 0.45 kg MeOH per MMscf (for every 
weight% of MeOH in the water phase. 
•
No more than 0.01 kg MEG per MMscf at 4°C and pressures 
greater than 1000 psi(a). 
•
The amount of inhibitor lost to the condensate phase: 
•
Around 0.5 wt% MeOH concentration in condensate. 
•
Around 0.03 % of the water phase mole fraction of MEG is 
dissolved in condensate at 4°C.