An Introduction to LPG (Liquefied Petroleum Gas)

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An Introduction to LPG (Liquefied Petroleum Gas)
1) What is LPG?
2) Why it is called Liquefied Petroleum Gas
3) What is commercial Propane & Butane
4) Why Propane & Butane are used in combination
5) Properties of LPG
6) Natural Gas condensate
7) Composition of natural gas condensate
8) Separating the condensate from the raw natural gas
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What is LPG ?

LPG or LP Gas is Liquefied Petroleum Gas. This is a general description of Propane (chemical formula C3H8) and Butane (chemical formula C4H10), either stored separately or together as a mix.

Liquefied Petroleum Gas is the generic name for mixtures of hydrocarbons (mainly propane and butane). When these mixtures are lightly compressed (approx. 800 kPa or 120 psi), they change from a gaseous state to a liquid and become more dense (by approx. 270 times). eg. 1 litre of LPG liquid is equal to 270 litres of LPG vapour.

Why is it called Liquefied Petroleum Gas?

This is because these gases can be liquefied at normal temperature by application of a moderate pressure increase, or at normal pressure by application of cooling using refrigeration.

LPG comes from two sources. It occurs naturally in oil and gas fields and is separated from the other components during the extraction process from the oil or gas field. LPG is also one of the by-products of the oil refining process.

There are two different grades or blends of LPG and they are not interchangeable. One is for automotive use only (called autogas) and will contain butane and propane. The other is propane only, which is used for decanting into cylinders for caravans, barbecues, camping and household use.

What is commercial Propane & Butane?

Ideally products referred to as “propane” and “butane” consist very largely of these saturated hydrocarbons; but during the process of extraction/production certain allowable unsaturated hydrocarbons like ethylene, propylene, butylenes etc. may be included in the mixture along with pure propane and butane. The presence of these in moderate amounts would not affect LPG in terms of combustion but may affect other properties slightly (such as corrosiveness or gum formation).

Why are Butane and Propane used in combination?

While butane and propane are different chemical compounds, their properties are similar enough to be useful in mixtures. Butane and Propane are both saturated hydrocarbons. They do not react with other. Butane is less volatile and boils at 0.60C. Propane is more volatile and boils at – 42 0C Both products are liquids at atmospheric pressure when cooled to temperatures lower than their boiling points. Vaporization is rapid at temperatures above the boiling points. The calorific (heat)

 

values of both are almost equal. Both are thus mixed together to attain the vapor pressure that is required by the end user and depending on the ambient conditions. If the ambient temperature is very low propane is preferred to achieve higher vapor pressure at the given temperature.

Properties of LPG:

LPG is:

  • (It’s normal to odorise LPG by adding an odorant prior to supply to the user, to aid the detection of any leaks).
  • Heavier than air.
  • Approximately half the weight of water.
  • Non toxic but can cause asphyxiation.
  • LPG expands upon release and 1 litre of liquid will form approximately 250 litres of vapour.
  • Relative density of liquid propane and butane at 150 is 0.508 and 573 respectively.
  • Relative density of vapour propane and butane at 150 is 1.58 and 2.06 respectively.
  • Vapour pressure of the propane and butane at -100 Care 256 and 4 Kpa respectively and at 00C are 388 and 40Kpa respectively (gauge).
  • Fire point of propane and butane are 5100C in air and 4900C in air respectively.
  • Burning velocity of both propane and butane in air is 32 cm/s.

 

Characteristic Units Propane n-Butane
Chemical formula   C3H8 C4H10
Modular weight   44,094 44,094
Freezing Point of liquid at 760 mm Hg (°C) -187,7 -138,3
Boiling Point of liquid at 760 mm Hg (°C) -42,1 -0,5
Specific Weight of liquid at 15,5 °C (Kgr/lt) 0,507 0,502
Relative density of vapour (air = 1) at S.C.   1,522 2,006
Critical Temperature (°C) 96,8 152,0
Critical Pressure – absolute (bar) 42,6 30,0
Vapour to liquid ratio at S.C.   272,7 237,8
Latent Heat at Boiling Point and 760 mm Hg (Kcal/Kg) 101,7 92,3
(Kcal/lt) 51,5 53,1
High Calorific Value at S.C. (Kcal/Kg) 12048 11851
(Kcal/lt) 22766 29875
Air required for burning at S.C. (m3air/1 m3 vapour) 23,82 30,97
(Kgr air/1 Kgr vapour) 15,71 15,49
Specific Heat of vapour at S.C. [Cp] (Kcal/Kgr°C) 0,388 0,397
Specific Heat of vapour at S.C. [Cv] (Kcal/Kgr°C) 0,343 0,361
Flash Point (°C) -105 -60
Low Flammability Limit of vapour / air mixture (LFL)   2,37 1,86
High Flammability Limit of vapour / air mixture (HFL)   9,50 8,41
Octane Number   125 91

 

Natural Gas Condensate:

Natural gas condensate is a low-density mixture of hydrocarbon liquids that are present as gaseous components in the raw natural gas produced from many natural gas fields.

It condenses out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas.

The natural gas condensate is also referred to as simply condensate, or gas condensate, or sometimes natural gasoline because it contains hydrocarbons within the gasoline boiling range. Raw natural gas may come from any one of three types of gas wells:

  • Crude oil wells – Raw natural gas that comes from crude oil wells is called associated gas. This gas can exist separate from the crude oil in the underground formation, or dissolved in the crude oil.
  • Dry gas wells – These wells typically produce only raw natural gas that does not contain any hydrocarbon liquids. Such gas is called non-associated
  • Condensate wells – These wells produce raw natural gas along with natural gas liquid. Such gas is also non-associated gas and often referred to as wet gas.

A low-density, high-API gravity liquid hydrocarbon phase that generally occurs in association with natural gas. Its presence as a liquid phase depends on temperature and pressure conditions in the reservoir allowing condensation of liquid from vapor. The production of condensate reservoirs can be complicated because of the pressure sensitivity of some condensates: During production, there is a risk of the condensate changing from gas to liquid if the reservoir pressure drops below the dew point during production. Reservoir pressure can be maintained by fluid injection if gas production is preferable to liquid production. Gas produced in association with condensate is called wet gas. The API gravity of condensate is typically 50 degrees to 120 degrees.

Gas condensate fields are getting more important due to an increasing share of gas produced from these fields within the global structure of gas production. One of the essential problems of gas condensate field development is condensate recovery optimization. Development of depleted gas condensate fields is followed by reservoir pressure depletion and retrograde condensation of higher boiling hydrocarbons (condensate) with some dropped out in liquid phase and lost to formations due to the fact that this condensate becomes immobile regardless of further fluid flow. As a result, up to 30-60% of initial condensate reserves can remain in the formation. So far, only one stimulation technique is used for

 

condensate recovery enhancement and that is cycling-process, which is a reinjection of dry gas into the formation. However, in many cases the application of cycling-process is not applied due to economic and other reasons. Thus, the gas industry is in desperate need for updating existing stimulation techniques applied in gas condensate fields and is in search of new technologies to enhance condensate recovery by both, maintaining the reservoir pressure thereby preventing condensate loss to formation, and by extracting retrograde condensate already dropped out in formation.

Composition of natural gas condensate:

There are hundreds of wet gas fields worldwide and each has its own unique gas condensate composition. However, in general, gas condensate has a specific gravity ranging from 0.5 to 0.8 and may contain:

  • Hydrogen sulfide (H2S}
  • Thiols traditionally also called mercaptans (denoted as RSH, where R is an organic group such as methyl, ethyl, etc.)
  • Carbon dioxide (CO2)
  • Straight-chain alkanes having from 2 to 12 carbon atoms (denoted as C2 to C12)
  • Cyclohexane and perhaps other naphthenes .
  • Aromatics (benzene, toluene, xylenes and ethylbenzene)

Separating the condensate from the raw natural gas:

 

Schematic flow diagram of the separation of condensate from raw natural gas

There are quite literally hundreds of different equipment configurations for the processing required to separate natural gas condensate from a raw natural gas. The schematic flow diagram to the right depicts just one of the possible configurations.

The raw natural gas feedstock from a gas well or a group of wells is cooled to lower the gas temperature to below its hydrocarbon dew point at the feedstock pressure and that condenses a good part of the gas condensate hydrocarbons. The feedstock mixture of gas, liquid condensate and water is then routed to a high pressure separator vessel where the water and the raw natural gas are separated and removed. The raw natural gas from the high pressure separator is sent to the main gas compressor.

The gas condensate from the high pressure separator flows through a throttling control valve to a low pressure separator. The reduction in pressure across the control valve causes the condensate to undergo a partial vaporization referred to as a flash vaporization. The raw natural gas from the low pressure separator is sent to a “booster” compressor which raises the gas pressure and sends it through a cooler and on to the main gas compressor. The main gas compressor raises the pressure of the gases from the high and low pressure separators to whatever pressure is required for the pipeline transportation of the gas to the raw natural gas processing plant. The main gas compressor discharge pressure will depend upon the distance to the raw natural gas processing plant and it may require that a multi-stage compressor be used.

At the raw natural gas processing plant, the gas will be dehydrated and acid gases and other impurities will be removed from the gas. Then the ethane (C2), propane (C3), butanes (C4) and C5 plus higher molecular weight hydrocarbons (referred to as C5+) will also be removed and recovered as byproducts.

The water removed from both the high and low pressure separators will probably need to be processed to remove hydrogen sulfide before the water can be disposed of or reused in some fashion.

Some of the raw natural gas may be re-injected into the gas wells to help maintain the gas reservoir pressures.

The hydrocarbon dew point is the temperature (at a given pressure) at which the hydrocarbon components of any hydrocarbon-rich gas mixture, such as natural gas, will start to condense out of the gaseous phase. It is often also referred to as the HDP or the HCDP. The maximum temperature and the pressure at which such condensation takes place is called the cricondentherm. The hydrocarbon dew point is a function of the gas composition as well as the pressure.

The hydrocarbon dew point is universally used in the natural gas industry as an important quality parameter, stipulated in contractual specifications and enforced throughout the natural gas supply train, from producers through processing, transmission and distribution companies to final end users.

The hydrocarbon dew point of a gas is a different concept from the water dewpoint, the latter being the temperature (at a given pressure) at which water vapor present in a gas mixture will condense out of the gas.