An Introduction to Gas Conditioning

PETROLEUM  as produced from a reservoir is a complex mixture of  different compounds of hydrogen and carbon, all with different densities , vapor pressures, and other physical characteristics. A typical well stream is a high velocity , turbulent, constantly expanding mixture of gases and hydrocarbon liquids, intimately mixed with water vapour , free water, solids and other contaminants.

After the removal of free liquids and solids the well gas consists of the following.

(  Non associated gas from the gas wells)

Name                          % (v/v)

Methane                     73.00

Ethane                        10.73

Propane                      7.45

i-Butane                     1.65

n-Butane                    2.25

i-Pentane                    0.50

n-Pentane                   0.43

n-Hexane                   0.15

n-Heptane                  0.01

n-Octane                    0.00

n-Nonane                   0.00

n-Decane                    0.01

Nitrogen                     2.72

Oxygen                       0.00

Carbon dioxide         0.96

Hydrogen Sulphide   traces [ 7 PPM (v/v) ]

Water not analyzed ( water vapour saturated at 42 C and 5500 kPa )

Gas which is produced along with oil is generally called Associated Natural Gas.

Gas which is produced from the gas reservoir is called Non Associated Natural Gas.

Field processing is required to remove undesirable components and to separate the well stream into transportable gas and petroleum liquids , recovering the maximum amount of each at the lowest possible overall cost.

Field processing is required to remove undesirable components and to separate the well stream into gas and petroleum liquids.

2. The Purpose of Gas Processing

In general gas is processed to make it suitable for handling and ready for sale. Processing is also required to recover valuable components from the gas and enhance the total product value.

The components in natural gas that gives most problems in handling are water vapour (corrosion, hydrate), hydrogen-sulphide (toxic, corrosion) and the heavier  carbons (two phase flow in pipelines).


Solid particles present in the natural gas will choke the equipment, valves and pipe lines. Hence removal of solid particles is also a requirement in gas processing.

Corrosion products, salts, paraffin and  corrosion inhibitors are the major fouling elements found in PDO’s Gas operations.

Some typical analysis of the deposits taken from a compressor is given below, to under stand the nature of fouling, in the process of gas handling.


Source                         Description                             Composition

LP impeller 1                                                              NaCl

LP impeller 5              Black                                       CaCO3, NaCl, Fe3O4

LP impeller 6              Brown                                     CaCO3, NaCl, Fe3O4

HP impeller 1                                                             NaCl, FeCO3, Fe3O4

LP stator                     Toluene wash recovered         NaCL, CaCO3, Fe3O4.

                                    82% insoluble            



Sample 1. IP2/HP Compressor 

Predominantly iron carbonate FeCO3

Lower level of iron sulphate hydrate FeSO4.H2O, and iron sulphide Fe3S4

Sample 2. IP2/HP Compressor Impeller Eye Suction

Iron carbonate FeCO3

Iron sulphide Fe3S4 / FeS

Sample 3. IP2/HP Compressor Impeller Diaphragm

Similar to sample 2

In summary the sample are a mixture of iron carbonate and various forms of iron sulphides.

Sulphide  formation is probably due to the presence of H2S in the gas stream.


 COREXIT 7780 is injected in many places to minimize the fouling problem. It is an antifoulant as well as corrosion inhibitor. Composition :- proprietary blend of an aromatic naphtha, xylene and polynuclear aromatic hydrocarbons.

If the gas is properly processed fouling will not occur.


Gas processing is needed both by producing company and the client.

The main reasons the producer wants to process the gas are:

Gas is often saturated with water vapour at the temperature and pressure at which it is produced. Water in the liquid phase causes corrosion in the presence of carbon dioxide and hydrogen sulphide and also forms hydrates under certain conditions of temperature and pressure. Hydrate is a physical bond between the water and the lighter components in the natural gas , that can plug gas lines , equipment and valves at temperatures as high as 20C.

The higher the pressure and lower the temperature the greater the chance for hydrates to form.

Recover heavier hydrocarbon from the gas and  increase the pressure for processing and transporting is also part of the gas specification.

The main reasons the clients sets specifications are that:

A minimum delivery pressure is required.

In most cases gas is used as a fuel, and therefore requires a minimum heating value.

In nearly all cases there will be strict specifications on H2S content because of its toxicity.

He does not want water for the same reasons as the producer. Often this specification is defined as water dew point.

He does not want heavy hydrocarbons to form liquid in the pipelines. This is defined as hydrocarbon dew point specification.

In summary a gas specification should address:

Heating value between 20 and 65 MJ/m3.

Delivery pressure between 2 and 700 bar.

Hydrocarbon dew point between -8 and 0 C ( this varies ) at all possible pressures.

Water dew point as the hydrocarbon dew point at the highest pressure.

H2S and CO2 depending on the client.

Major steps in gas conditioning

Gas conditioning process without sweetening (Example GGP Yibal)

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