Natural Gas Dehydration Part.1

Definition of Natural Gas Dehydration

 the removal of water from natural gas by lowering the dew point temperature of the natural gas


To prepare natural gas for sale, its undesirable components (water, H2S and CO2) must be removed. Most natural gas contains substantial amounts of water vapor
due to the presence of connate water in the reservoir rock. At reservoir pressure and temperature, gas is saturated with water vapor.
Removal of this water is necessary for sales specifications or cryogenic gas processing. Primary concerns in surface facilities are determining the:
– Water content of the gas.
– Conditions under which hydrates will form.
Liquid water can form hydrates, which are ice-like solids, that can plug flow or decrease throughput. Predicting the operating temperatures and pressures at which
hydrate form and methods of hydrate prevention.

Water vapor is the most common undesirable impurity in gas streams. Usually, water vapor and hydrate formation, i.e. solid phase that may precipitate from the gas when it is compressed or cooled. Liquid water accelerates corrosion and ice (or solid hydrates) can plug valves, fittings, and even gas lines. To prevent such difficulties, essentially gas stream, which is to be transported in transmission lines, must be dehydrated as per pipeline specifications.
The processing of natural gas to the pipeline specifications usually involves four main processes :
Oil and condensate removal
Water removal
Separation of natural gas liquids
Sulfur and carbon dioxide removal
Most of the liquid free water associated with extracted natural gas is removed by simple separation methods at or near the wellhead. However, the removal of the water vapor
requires more complex treatment, which usually involves one of the two process, either absorption or adsorption.
In absorption, dehydrating agent (e.g. glycols) is employed to remove water vapors and in adsorption, solid desiccants like alumina, silica gel, and molecular sieves can be used.
The absorption process has gain wide acceptance because of proven technology and simplicity in design and operation.

  Dew Point:

   The dew point is the temperature and pressure at which the first drop of water vapor condenses into a liquid. It is used as a means of measuring the water vapor content of
natural gas. As water vapor is removed from the gas stream, the dew point decreases. Keeping the gas stream above the dew point will prevent hydrates from forming and
prevent corrosion from occurring.
Dew point depression is the difference between the original dew point and the dew point achieved after some of the water vapor is removed. It is used to describe the amount
of water needed to be removed from the natural gas to establish a specific water vapor content

Natural gas contains water in 2 forms :
–  In liquid form (free water) .
– In vapor form (dissolved)
Water present :
1. At source from reservoir (associated water with gas)
2. As a result of sweetening in aqueous solution.
It is necessary to reduce and control the water content of gas to ensure safe processing and transmission.

Water content is stated in a number of ways :
1. Mass of water/unit volume lb/MMscf.
2. Dew point Temperature.
3. Concentration, part per million by volume ppmv.
4. Concentration, part per million by mass ppmw.

   Why Dehydrate?

   Dehydration refers to removing water vapor from a gas to lower the stream’s dew point. If water vapor is allowed to remain in the natural gas, it will:
– Reduce the efficiency and capacity of a pipeline
– Cause corrosion that will eat holes in the pipe or vessels through which the gas passes Form hydrates or ice blocks in pipes, valves, or vessels
– Dehydration is required to meet gas sales contracts (dependent upon ambient temperatures).

Water Content of Gas:

   Liquid water is removed by gas-liquid and liquid-liquid separation. The capacity of a gas stream to hold water vapor is: A function of the gas composition Affected by the pressure and temperature of the gas Reduced as the gas stream is compressed or cooled When a gas has absorbed the limit of its water holding capacity for a specific pressure and temperature, it is said to be saturated or at its dew point.
Any additional water added at the saturation point will not vaporize, but will fall out as free liquid. If the pressure is increased and/or the temperature decreased, the capacity of the gas to hold water will decrease, and some of the water vapor will condense and drop out.
Methods of determining the water content of gas include:
– Partial pressure and partial fugacity relationships
– Empirical plots of water content versus P and T Corrections to the empirical plots above for the presence of contaminants such as hydrogen sulfide, carbon dioxide and
nitrogen and Pressure Volume Temperature (PVT) equations of state.


    What Are Gas Hydrates?
Gas hydrates are complex lattice structures composed of water molecules in a crystalline structure: Resembles dirty ice but has voids into which gas
molecules will fit Most common compounds.

    – Water, methane, and propane
– Water, methane, and ethane
The physical appearance resembles a wet, slushy snow until they are trapped in a restriction and exposed to differential pressure, at which time they become very solid structures, similar to compacting snow into a snow ball.

Why Is Hydrate Control Necessary?
Gas hydrates accumulate at restrictions in flowlines, chokes, valves, and instrumentation and accumulates into the liquid collection section of vessels. Gas hydrates plug and reduce line capacity, cause physical damage to chokes and instrumentation, and cause separation problems.

What Conditions Are Necessary to Promote Hydrate Formation?
Correct pressure and temperature and “free water” should be present, so that the gas is at or below its water dew point. If “free water” is not present, hydrates cannot form.

How Do We Prevent or Control Hydrates?
1. Add heat.
2. Lower hydrate formation temperature with chemical
3. inhibition Dehydrate gas so water vapor will not condense into “free water”.
4. Design process to melt hydrates.

 Why Using Glycols?
Glycols are extremely stable to thermal and chemical decomposition, readily available at moderate cost, useful for continuous operation and are easy to regenerate. These properties make glycols as obvious choice as dehydrating agents.
In the liquid state, water molecules are highly associated because of hydrogen bonding. The hydroxyl and ether groups in glycols form similar associations with water molecules. This liquid –phase hydrogen bonding with glycols provides higher affinity for absorption of water in glycol. Four glycols have been successfully used to dry natural gas: ethylene glycol (EG), Diethylene glycol (DEG), Triethylene glycol (TEG) and Tetraethylene glycol (TREG).
TEG has gained universal acceptance as the most cost effective choice because:
– TEG is more easily regenerated to a concentration of 98-99.95% in an atmospheric stripper because of its high boiling point and decomposition temperature.
– Vaporization temperature losses are lower than EG or DEG
– Capital and operating cost are lower
Diethylene glycol is preferred for applications below about 10oC because of the high viscosity of TEG in this temperature range.

for more details, see Natural Gas Dehydration Part.2

1. Gas Dehydration Field Manual, Maurice Stewart & Ken Arnold
2. Gas Dehydration by TEG and Hydrate Inhibition Systems, Arthur William
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Natural Gas Dehydration Part.2

The principle of glycol dehydration is contacting a natural gas stream with a hygroscopic liquid which has a greater affinity for the water vapor than does the gas. Contactor pressure is subject to economic evaluation usually influenced by water removal duty, required water dewpoint, vessel diameter and wall thickness. After contacting the gas, the water-rich glycol is regenerated by heating at approximately atmospheric pressure to a temperature high enough to drive off virtually all the absorbed water. The regenerated glycol is then cooled and recirculated back to the contactor.

Triethylene glycol (TEG) is the most commonly used dehydration liquid and is the assumed glycol type in this process description. Diethylene glycol (DEG) is sometimes used for uniformity when hydrate inhibition is required upstream of dehydration or due to the greater solubility of salt in DEG. Tetraethylene glycol (TREG) is more viscous and more expensive than the other glycols. The only real advantage is its lower vapour pressure which reduces absorber vapor loss. It should only be considered for rare cases where glycol dehydration will be employed on a gas whose temperature exceeds about 50 °C, such as when extreme ambient conditions prevent cooling to a lower temperature.
TEG has been applied downstream of production facilities that use MEG or DEG as a hydrate inhibitor without apparently leading to contamination problems. Methanol used as a hydrate inhibitor in the feed gas to a glycol dehydration unit will be absorbed by the glycol, and according to the GPSA Engineering Data Book it can pose the following problems:
– methanol will add additional reboiler heat duty and still vapor load and therefore increase glycol losses;
– aqueous methanol causes corrosion of carbon steel. Corrosion can thus occur in the still and reboiler vapor space;
– high methanol injection rates and consequent slug carry-over can cause flooding.
Where there is upstream hydrate inhibition, credit should be taken for any favorable reduction in the water content of the vapor phase. This effect is less significant at lower
feed temperatures, i.e. equivalent to about 2 °C reduction in water dewpoint at 10 °C feed temperature at 9 MPa pressure and 60 percent by weight MEG in the aqueous phase.
Adherence to the recommendations in this DEP can minimize but not eliminate entrainment and vapor losses of glycol. Glycol entrainment may lead to the following downstream problems:
– coalescing and partial condensation in pipelines resulting in localised corrosion;
– in cryogenic plants, particularly at temperatures below -25 °C, freezing of TEG and plugging of equipment;
– reduced performance of downstream adsorption plant, e.g. molecular sieves or silica gel.
Any entrained glycol should be removed upstream of cryogenic plant in high efficiency gas/liquid separators to prevent possible plugging. A range of lean TEG concentrations can be achieved with the basic regeneration flow.

1. Gas Dehydration Field Manual, Maurice Stewart & Ken Arnold
2. Gas Dehydration by TEG and Hydrate Inhibition Systems, Arthur William
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish