Natural Gas Well Production Problems



Eng. AlSayed Amer

The ongoing process of producing hydrocarbons from a well is a dynamic process and this is often evidenced in terms of changes in the rock or fluid production characteristics.

Problems are frequently encountered as a results of many reasons will be discussed.

Associated Production Problems

There are three basic problems which reduce gas flow from natural gas wells that have a sufficient reservoir pressure, porosity and permeability in a surrounding sand formation:

1-    Restriction of gas flow through casing perforations (sand covers perforations).
2-    Liquid loading of production tubing with water or condensate.
3-    Back pressure on wellhead.

gas well

gas well

  • Sand production and perforation blockage

When sand moves and covering the casing perforation (sometimes a sand bridge accumulated and above the perforation). A greater reduction of gas production will be observed.

Reasons for this problem

The sand production or perforation blockage is a problem resulted from many reasons:

  • Wellhead chock opening is large.
  • Well was shut in for a long time which led to settling of suspended sand to the bottom.
  • The mechanical collapse or breakdown of the formation may give rise to the production of individual grains or “clumps” of formation sand with the produced fluids.
  • Failure of gravel pack in case of gravel pack completion.
  • In formations containing siliceous or clay fines, these may be produced with the Hydrocarbons creating plugging in the reservoir and wellbore.Problem investigation and confirmationTo confirm if sand is indeed covering the perforations or not, a weighted wireline is lowered through the tubing, when the wireline losses tension then the wireline surface operator realized that the weight has “tagged bottom”.
    This tagged depth is compared to the well completion tally record to insure if any or all perforations was covered by sand.
    If 20 % to 30% of perforation was covered, then it is a good idea to wash the well out with a coil tubing unit.Effects of Sand Production Sand Erosion. Caused by the presence of solids combined with high velocity. Occurs in tubing, pipework, in zones of diameter restriction & turbulence such as chokes, elbows.Loss of production. Installing sand control equipment will decrease the production rate due to the pressure drop across the unit.Sand disposal. Sand production rate of 0.1% of the produced fluid generates 5.62cu.ft (0.159m3) of solids per 1000bbls of production.

    Overcoming the problem

    sand separatorSand is being controlled with a variety of methods and techniques at the bottom hole & at the surface.
    At bottom, gravel packing systems are the most common methods used.
    At surface, in well testing, three Schlumberger purpose-built types of sand removal units are used:

    – Dual-pot Sand Filter.
    – Sand Separator.
    – Cyclonic Desander.

    sand filter


Gas well Liquid loading

“Liquid loading of a gas well is the inability of produced gas to remove the produced liquids from the wellbore” when the gas velocity is not sufficient to entrain the liquid out of tubing (entrainment velocity). The produced liquid will accumulate in the well, therefore creating a hydrostatic pressure in the well against formation pressure and reducing production until the well ceases production.

Problem reasons 

  • There may be an aquifer below the gas zone which may either lead to water coning
    or water encroachment.
  • The source of liquids may be another zone or zones, especially if the completion type of the well is open hole.
  • The water produced along with gas may be free water present in the formation.
  • Depending on the reservoir, bottom hole and tubing head pressures water and/or Hydrocarbon vapor may enter the well and condense while travelling up the production tubing, coming out of liquid.

Source of liquids

Water coning: If gas rate is high enough, water may be “sucked” to perforated zone from a water zone below.

Aquifer Water: Pressure support from a water zone may lead to the water zone “traveling” to perforations.

Water produced from another zone.

Free formation water: Water and gas come from the same zone.

Water of Condensation: Condensation can occur higher in the well (p/T dependent), which can cause water to fall back and accumulate at perforations. Temperature decreases and/or pressure increase -> water vapor will condense out of gas. Condensed water can be identified by low or no salt content

Factors that influence liquid loading

  • Tubing size.
  • Surface pressure.
  • Amount of liquids being produced with the gas.

Recognition of Liquid Loading

gas wellOver life of gas well, liquid production is likely to increase while gas production will decrease. Led to accumulation of liquids in wellbore until well dies or flows erratically at lower rates so early diagnosis can minimize losses

Unnoticed liquid loading can result in reservoir damage.

  • Memory gages can detect the height of liquid columns.
  • Echometer device can detect liquid level in casing.


Overcoming the problem

  • Conventional plunger lift systems use well shut-in pressure buildups to efficiently lift columns of fluid out of well without venting.
  • Shutting in the well to allow bottomhole pressure to increase, then venting the well to the atmosphere (well blow down).
  • Swabbing the well to remove accumulated fluids.
  • Installing velocity tubing.
  • Installing an artificial lift system.
  • Use Foaming Agents.

Velocity TubingSoap Stick Launcher


Converting Natural Gas to LNG


Natural gas, which is comprised primarily of methane, is one of our most abundant natural resources, both domestic and abroad. Unfortunately, many of the natural gas reservoirs are located in relatively remote areas, or offshore, and high transportation costs tend to prohibit extensive use of this potentially valuable resource. To overcome this limitation, the Department of Energy’s Federal Energy Technology Center (FETC) has developed a highly diversified research program to evaluate, promote and develop processes that convert natural gas, methane, into higher value products (i.e., liquid fuels) which will offset the high transportation costs and allow use of this untapped, environmentally friendly resource.
By advancing technologies to convert unmarketable gas resources into valuable products, cooperative efforts between DOE and industry could yield the following benefits by 2010.
(1) Our domestic production of oil will be increased through the supply of 200,000 to 500,000 barrels per day of high quality liquid transportation fuel made from Alaska’s North Slope gas resources.
(2) Advanced gas-to-liquids conversion technology that yields ultra clean burning diesel fuels that meet the most stringent emissions requirements, at costs below those of comparable fuels made from crude oils, will be
(3) Small-scale gas-to-liquids technology for both natural gas liquefaction and chemical conversion to higher hydrocarbon liquids will enable economic and environmentally sound usage of remote offshore oil reservoirs with
associated gas, and also onshore gas reservoirs without pipeline access.
Three potential routes for the conversion of natural gas have emerged: direct, indirect and physical conversion. Direct conversion focuses on the chemical transformation of natural gas to ethane, ethylene, acetylene or methanol. Indirect conversion methods concentrate on the production of syngas (CO and H2), which is subsequently converted to liquid fuels. Physical conversion techniques center on the conversion of natural gas to liquefied natural gas (LNG). All three approaches are currently under investigation under the gas-to-liquids conversion program at FETC. In addition, the economics of gasto-liquids conversion is continually evaluated.

Direct Conversion
The direct conversion of methane to higher hydrocarbons has been extensively investigated in the past 15 years. Unfortunately, employing conventional catalytic systems, yields have remained low. In the case of C2 production, yields have been limited to 30% or less. Yields of oxygenated hydrocarbons (i.e., methanol and formaldehyde) have remained even lower, on the order of 5 – 6%. In order to overcome these limitations, FETC has attempted
to fund relatively novel research projects.
Approaches include the use of electric fields, plasma torches and hydrogen transport membranes. As an example, the hydrogen transport membrane approach is presented in more detail.
Methane is allowed to react in the absence of oxygen (pyrolytically), over a catalyst, on one side of the membrane.
Conversion to higher hydrocarbons, in particular C2 is highly equilibrium limited. However, hydrogen produced during the reactions is selectively removed via transport through the membrane. Removal of hydrogen allows the reaction to proceed further, thus removing the equilibrium constraints. On the other side of the membrane oxygen is present. The transported hydrogen can further react with the oxygen to produce water. Overall the reaction can be written as:

2 CH4 + O2 = C2H4 + 2
H2O, which is simply the oxidative coupling of methane. Results of this work are anticipated in the coming year.

Physical Conversion
In addition to chemical conversion, physical conversion of methane to liquefied natural gas (LNG) has shown promise. In this work, natural gas is liquefied employing Thermoacoustically Driven Orifice Pulse Tube Refrigeration (TADOPTR). This technology has the unique capability of producing refrigeration power at cryogenic temperatures with no moving parts. The technology is well suited for liquefaction capacities in the range of roughly 500 to 10,000 gallons per day. The research is being carried out under a Cooperative Research and Development Agreement (CRADA) between Los Alamos National Laboratory (LANL) and Cryenco, a small business located in Denver, Colorado. During 1997, the TADOPTR demonstrated production of 100 gallons per day of liquefied natural gas. The system is currently being scaled up to demonstrate production of 500 gallons per day of liquefied natural gas in
early 1998.

Indirect Conversion
Indirect methane conversion requires the production of synthesis gas (CO and H2) which is subsequently to higher hydrocarbons and liquid fuels. Synthesis gas production requires either steam (steam reforming) or oxygen (partial oxidation) as a coreactant.
In either case, generation of these reactants is extremely energy and capital intensive and, as a result, the major cost of converting natural gas to liquid fuels lies in the initial synthesis gas production step.  Clearly, over half of the process cost, approximately 60%, is associated with synthesis gas generation.
Considering the partial oxidation route to synthesis gas, any reduction in the cost of oxygen production would translate into a reduction in the overall cost of liquid fuels production. One technology which shows considerable promise is the use of ceramic membranes for oxygen production. Briefly, air (80% nitrogen, 20% oxygen) is allowed to pass on the outside of the membrane.
The membrane is a highly dense, non-porous ceramic material capable of withstanding high temperatures. Due to 1) an oxygen partial pressure differential across the membrane and 2) the nature of the ceramic material, oxygen is selectively removed from the air and transported across the membrane as an oxide ion (O2-). . It is important to note that oxygen separation has been achieved without the use of relatively expensive cryogenics or compression.
In addition to functioning as an oxygen separation unit, the membrane also serves as the synthesis gas reactor.
methane (natural gas) is passed through the inside of the membrane. Oxygen diffusing through the membrane further reacts with the methane resulting in the formation of synthesis gas. By utilizing the above approach, it is
anticipated that both capital and operating costs can be substantially reduced and provide an alternate, cost competitive route for the production of liquid fuels.

Currently, several new downstream research activities are being initiated. This includes the development of Fischer-Tropsch catalysts for the production of liquid fuels and testing of these materials for their performance and emission characteristics.

Economic/Process Analysis
It is imperative that the current status of all issues concerning the conversion of natural gas to liquid fuels be continually monitored and updated. Therefore, continued economic and process analysis of existing and potential natural gas conversion technologies is a necessary and integral part of the gas to liquids program. Recent studies include:

1) the potential and economics for offshore gas to liquids conversion.
2) an economic assessment of Alaskan North Slope gas utilization options. Of particular importance in the latter work was the identification of the window of opportunity to extend the lifetime of the Trans Alaskan Pipeline System (TAPS).
3. Identification of a viable technology to convert gas to pipeline quality liquids by 2009 – 2016 could extend the lifetime of TAPS by some 20+ years. Continued operation of TAPS is vitally important to Alaska=s economy; therefore, this provides considerable incentive to develop and commercialize new gas to liquids conversion
technologies, capable of 200,000 – 500,00 bbl/day production, early in the 21st century.
The primary focus of the gas to liquids program is on the conversion and utilization of domestic natural gas supplies. However, it is important to remain active in world wide gas activities. Participation in the CANMET Consortium allows interaction with an international group of oil, gas, utilities and chemical companies.
The overall objective of the gas to liquids program is: In partnership with industry, develop and demonstrate advanced technologies and processes for the economical conversion of methane to liquids that can be used as fuels. FETC’s gas to liquids research program provides a unique opportunity for industrial partnerships and rapid technology transfer in an effort to achieve this goal.

Surge Control in Centrifugal Compressors

Compressor Surge ControlDresser-Rand has been a leading designer and supplier of surge control systems for centrifugal and axial compressors for over thirty-five years.
Recent innovations in control technology have made it possible to supply surge control systems which are capable of coping with rapid flow fluctuations and process gas variations. Current surge control systems from Dresser-Rand Control Systems provide protection against surge with more efficient compressor operation, especially in process applications that involve variations in the gas mixture and temperature.
Several surge methods are in use today, each with its own approximations and consequent inaccuracies.
Operating the compressor safely in spite of these inaccuracies is usually accomplished by establishing the surge
controller flow set point based on the expected worst-case operating conditions. This worst-case flow set point
may be excessive for normal operating conditions but is necessary in order to provide for safe operation at all
expected operating conditions.
This worst-case setting approach can result in inefficient compressor operation caused by excess recycle or
blow-off flow and wasted energy.
A more practical surge control method, which uses a Universal Performance Curve, has been developed and
patented by Dresser-Rand. The Universal Performance Curve method offers several benefits when compared to
traditional surge control methods. It provides extremely accurate surge control by defining the surge point over a
wide range of process gas conditions. This method makes it possible to position the control line for optimum
surge protection which eliminates unnecessary recycling and increases overall plant operating efficiency.

Compressor Surge and Measurement
Centrifugal and axial compressors will surge when forward flow through the compressor can no longer be maintained, due to an increase in pressure across the compressor, and a momentary flow reversal occurs. Once surge occurs, the reversal of flow reduces the discharge pressure or increases the suction pressure, thus allowing forward flow to resume again until the pressure rise again reaches the surge point.
This surge cycle will continue until some change is made in the process or compressor conditions.
A surge controller typically measures a function of pressure rise versus flow. The controller operates a surge
valve to maintain sufficient forward flow to prevent surge.

Surge Control Algorithm
Dresser-Rand’s method of accurately defining the surge point over a wide range of changing conditions makes it
possible to set the control line for optimum surge protection without unnecessary re-cycling. This method
automatically compensates for changes in molecular weight, temperature, compressibility, pressure and compressor rotor speed.
The system utilizes a characterization of compression ratio (Pd/Ps) versus compensated compressor inlet flow
function (hs / Ps) ½ as control parameters. This algorithm allows for use of the Dresser-Rand surge control
system on most applications, resulting in minimized recycle or blow-off flow. This method reduces the initial cost
and simplifies engineering, testing, operation, and maintenance associated with the system when compared to alternative methods.
The input signals required to facilitate use of the surge control algorithm on centrifugal compressors are the
suction flow differential pressure, suction pressure and discharge pressure as indicated in Figure 1.

Surge Control Operation
Figure 2 illustrates the use of the universal surge control map. The compressor flow set point is provided by the
control line. The location of the control line in comparison to the surge line depends on the slope of the speed
lines of the map. The control line is positioned to the right of the surge line which provides a safety margin for the
surge controller PI (Proportional & Integral) algorithm. The PI control loop is used to compare the control set point
to the operating point of the compressor and provides an output to the surge valve to prevent the flow from
decreasing below the control line. When a safe relationship between the control line and the surge line is
determined, this relationship is configured into the surge controller.
Under normal operating conditions, PI control is used and surge control action is initiated at the control line by
opening the surge valve as required to maintain forward flow through the compressor. This prevents a further
shift of the operating point to the left towards surge.
In the case of rapid reductions in flow, such as process upsets, three additional controls are implemented.
First, a backup line, located between the control line and the surge line, is used. If the compressor operating point
moves to the left of the control line and reaches the backup line, Dresser-Rand’s Closed Loop Step Logic will
quickly force the surge valve open as required to increase forward flow through the compressor.
Second, if the operating point of the compressor reaches the backup line a set number of times (i.e. 3), within a
specified period of time (i.e. 5 minutes), the control set point will be shifted to the right via Dresser-Rand’s Set
point Shift Logic.
Third, a variable proportional gain action has been added to the control loop to assist in stabilizing the process
when rapid decreases in compressor flow are encountered.

Step Logic
The backup line is positioned between the surge line and the control line and provides a basis for additional
control action. If the operating point of the compressor decreases to flow values less than those defined by the
backup line, traditional PI control is enhanced by the Closed Loop Step Logic control function to facilitate rapid
opening of the surge valve.
The output to the valve is forced to decrease in discrete, timed steps, thus opening the surge valve much quicker
than possible with conventional PI control. Valve opening steps are initiated until the flow has moved to a safe
Compressor surge is avoided by this quick incremental control of the surge valve thus minimizing the effects of
process upsets.

Set Point Shift
If the flow decreases to the backup line a predetermined number of times (adjustable) within a given time period
(indicating a recurring problem) the surge control set point is shifted a percentage of full scale flow (i.e. 2%) in the
direction of higher flow. This action establishes a larger margin of safety from the surge line. The flow set point
continues to be shifted as necessary until the backup line crossings cease, or to a maximum of ten percent
greater than the control line value.
The intent of the set point shift is to prevent surge until the cause of the instability can be corrected. The shifted
set point remains in effect until reset by the operator.

Floating Proportional Algorithm
Compressor-Surge-ControlDerivative action as applied in a conventional PID controller, under normal compressor operating conditions, would tend to make the system unstable and therefore is not used. However, for some fast changing conditions, the normal PI control response is not sufficient to prevent flow from decreasing to values less than the control line.
In general, the controller needs to be slow for normal operating conditions, but fast when needed to protect
the compressor from surge. During rapid decreases in flow near the surge control line, Dresser-Rand uses a
Floating Proportional control algorithm to open the surge valve before the operating point reaches the
control line.
Normal PI control is resumed when the process upset has been stabilized.

There are two methods of implementing the Dresser-Rand surge control algorithm.
The first method uses the DI-TRONICS® IV control system. This PLC (Programmable Logic Controller) based
control system incorporates surge control as an integral part of the PLC program without the need for additional
external hardware. Compressor inlet flow, suction pressure, and discharge pressure measurements are input
directly into the system using standard PLC analog inputs. The tuning parameters are displayed and adjusted
from an Operator Interface (OI) screen. Compressor curves, with the operating point, control line and back-up
line are displayed on the Operator Interface monitor. The system parameters are trended and displayed on the
Operator Interface monitor.
The second method utilizes a stand-alone controller and is offered for installations which do not require a PLC, or
for those applications where the PLC used is not capable of providing adequate surge control.
Both systems utilize the Universal Performance Curve concept.

Field Devices and Process Designs
Compressor surge is a phenomenon which can occur very rapidly during upsets in process conditions. Proper
surge control requires not only an appropriate control algorithm and a dedicated control strategy but, also specific
attention to the field devices and process design.
Flow measuring devices should be located such that gas disturbances will be minimized (less noise), and
designed for the full operating range of the compressor.
Transmitters should be located as close as possible to the source of measurement to minimize reaction time.
Surge valves should provide a full stroke response preferably within 1 second, but no more than 2 seconds.
The surge valve should be linear and should be sized in accordance with the compressor maps and expected
operating conditions.
Since the effects of opening the surge valve are a decrease in compressor discharge pressure and/or an
increase in suction pressure, to increase flow through the compressor, process and piping designers should
minimize, as much as practical, the piping volume in the recycle path and the volume between the compressor
and the discharge check valve.

Natural Gas Processing

Necessary Conditions and Goals of Processing :
The types of treatments carried out on gas streams usually are:
– heating;
– inhibition.
– dehydration;
– liquid hydrocarbon recovery;
– sweetening.

Treatment needs and objectives:
The first gas treatments are temporary. Their aim is to prevent the hydrates formation and they’re classified as follows:
– separation of free water;
– increase in the temperature of gas above that of hydrate formation;
– inhibitors injection to prevent hydrate formation.

Elimination of free water
The elimination of free water in the gas is carried out through separators that are installed at the well-head and at the entrance of the treatment stations.
This treatment removes the liquid phase from the two-phases coming out of the well head. The gaseous phase is saturated before the treatment and is still saturated (at pressure and temperature conditions) leaving the
Gas undergoes a temperature decrease flowing within the pipe from well head to the treatment station and expands (decreasing in pressure, caused by head losses along the pipe and across valves and fittings). The expansion causes a temperature loss (Joule-Thompson effect), since another condensation of moisture takes place, so that the liquid phase can be present at the inlet of the treatment station once again.

Gas heating

In the diagram representing the hydrates formation of a 0,7 specific gravity gas, the evidenced area defines the condition under which the hydrates can form.
From the same diagram it is evident that we have the gas phase increasing the temperature.
The treatment is temporary because heating the gas at constant pressure increases the capacity to hold vapour, however content is still the same.
So, when the temperature is lower than the previous values, gas returns into the hydrates formation area.

read more about Hydrate and Hydrate Prevention

Inhibitors are liquid substances that prevent and also eliminate the formation of hydrates. The inhibitors enter a solution with water, lowering its freezing point thus shifting the equilibrium of hydrates towards lower
temperature values. The inhibitors which are generally used are:
– ethyl Alcohol;
– methanol;
– diethylene Glycol.

Other chemical inhibitors are used in order to hinder, in case of sour gas, the corrosion of the machinery located at the wellhead.
Both treatments are temporary, since they do not eliminate the problem, but simply hand it over to the treatment stations, either for the elimination of water vapour or the elimination of corrosive agents such as CO2 and/or H2S.

Final treatments
After temporary treatments, gas is delivered to the treatment plant and then to users, according to the requested specifications.
The final treatments eliminating harmful elements from natural gas consists in:
1. reducing water (dehydration);
2. reducing the content of superior hydrocarbons (adsorption);
3. reducing the content of hydrogen sulphide and carbon dioxide

The above-mentioned treatments are carried out by appropriate types of plants according to the composition of natural gas. Moreover, the plants are managed to meet the user’s specifications.

The maximum concentration allowed for the various undesirable components are indicated as follows:

(These specifications can vary depending on the customer)
WATER Content usually expressed as dew point temperature
e.g. < 5 °C at 50 bar
HYDROGEN SULPHIDE Content = 2 ppm/Vol Max
CARBON DIOXIDE Content = 1,3 Mol% Max
NITROGEN Content = 6 Mol% Max
GASOLINE Content usually expressed as dew point temperature
e.g. < -10 °C at 50 bar

Hydrates and Hydrate Prevention




Hydrates are crystallized, compact, porous and rather light mass, similar to compressed snow. They are made of water, hydrocarbons, H2S and CO2.
Unlike ice, hydrates have an unusual characteristic: they form at a temperature that is above water freezing point . For instance, they can form at 20 °C at particular pressures.
When they are exposed to air, they dissolve chugging and fizzing because of the gas that is more or less slowly freed according to the surrounding temperature. When they are lit in the air, they can slowly and completely
burn, until they leave a small residue of water. This does not represent the quantity of water they actually contain, as part of the water content is lost through evaporation. Hydrates form quite easily by simple contact of gas
and water and the formation is related to the conditions of temperature and pressure, according to the law of equilibrium.
They can quite frequently form in lines that gather gas from the various wells and transport it to the central treatment station where it undergoes dehydration.
This formation of hydrates can partially or totally obstruct the lines, limiting or hindering the transportation of gas
Hydrates can form only if the following conditions occur:
a) presence of H2O in the liquid state
b) presence of hydrocarbons
c) turbulence (created by curves, collisions etc)
d) for a given pressure, only if the temperature is lower than a certain value.
The researcher Donald L. Katz experimented the mixtures of gas with different compositions to determine the formation curves of hydrates.

read more about Gas Dehydration

Methods to prevent the formation of hydrates
In order to reduce the possible formation of hydrates in a line that transports natural gas it is essential that:
a) there is no free water;
b) the temperature is higher than that required for hydrates formation.
If one of these conditions cannot be removed, it is necessary to use other systems to prevent the formation of hydrates:
a) the use of inhibitors (anti-freezing agents), i.e. substances capable of
decreasing the hydrate formation temperature.
b) Water removal from the gas

Hydrates elimination
The method for hydrates elimination depends on the nature of the obstruction.
Partial clogging: can be located when the pressure and the gas flow in the conducts vary. This is due to a partial obstruction in the conduct.
In this case, the operator should check if a hydrate prevention system has been installed upstream the hydrate clog (i.e. a heater or an inhibitor injection system) and if it functions properly..
The interventions that can follow are:
– temperature increasing of the outlet gas released by the heater;
– Increasing of the inhibitor rate.
– The inhibitors injections upstream the choke.
Complete clogging: The complete clogging with hydrates provokes a total production shutdown, so the methods adopted in case of partial clogging are no longer valid. In this case, decompression will be the proper method
for melting.
The decompression must be carefully carried out, since it can be dangerous.
First of all, the pressure upstream the choke has to be reduced by balancing the pressures upstream & downstream the choke itself. This is done in order to avoid that a higher ΔP and the hydrates clog detachment can have evident consequences on the pipeline.
Once the pressure is balanced, the contemporary released upstream and downstream depressurisation must reach the atmospheric pressure.
At this point the clog melts on its own, having absorbed the molecules of gas at the pressure level in which the hydrate had formed.

From the nature of hydrates and their formation it can be stated that, correct gas treatment must be carried out so that such dangerous formations are avoided.

Sweet Gas – Acid Gas – Condensate Gas


A natural gas is called sweet gas if it has no sour components such as H2S, CO2, mercaptans, but is almost exclusively composed of methane, low amounts of ethane, propane, inert gases (N2) and traces of heavier
hydrocarbons. It is generally saturated in water at reservoir temperature and pressure.
A natural gas is usually defined as sour when it contains hydrogen sulphide (H2S) and/or carbon dioxide (CO2).
A condensate gas reservoir can be defined as a reservoir in which temperature is between critical temperature and cricondenthermal point (maximum temperature at which coexistence of the two phases is still possible) for the particular natural hydrocarbon system it contains.
At this point it is useful to outline a phase diagram of a natural hydrocarbon system.
In a natural hydrocarbon reservoir, within the porous bed that makes up the source rock, we will find hydrocarbons of aliphatic, aromatic and naphthenic type, ranging from low molecular weight terms (like methane) to sometimes, very high molecular weight terms (crude oil), together with minor amounts of some non hydrocarbons (CO2, N2, H2S etc.).
Formation water is almost always present in the reservoirs.
In the reservoir, the fluids can be present as a single phase gas (a gas reservoir), single phase liquid (an under-saturated petroleum reservoir) or two distinct phases (a petroleum reservoir with an overlaying gas cap).


The points along the line AC represent liquid at incipient vaporization i.e first vapour bubble formed, and constitute the “bubble point” curve. (Fig. above) The points along the CB curve represent vapours at incipient condensation
i.e and constitute the “dew point” curve.

From the diagram we can observe that a pressure decreasing, for temperatures between Tc and Tc’, that cross the dew point curve, causes the appearance of dew (drops of liquid) in the initially homogeneous gaseous phase. Bubble point and dew point curves cross at point C, known as the critical point of the system, corresponding to critical temperature and critical pressure. In a multi-component system the coexistence of liquid and gaseous phases is possible even at temperatures above critical temperature. Therefore, it is preferable to define as critical, such a state in which all the intensive properties (density, compressibility, viscosity, etc.) of the liquid and gaseous phases are equal.
POINT C’: maximum temperature at which coexistence of the two phases is still possible; it identifies the CRICONDENTHERM state.
POINT C”: maximum pressure at which both liquid and gaseous phase can coexist; it identifies the CRICONDENBAR state.
The internal AB area of the curve represents the region of coexistence of liquid and gaseous phase. The dotted curves inside this area connect points of equal percentage of liquid phase.
By reducing pressure below the dew point value, there is initially an increase of the liquid phase and subsequently a partial or total reevaporation of the phase itself. This phenomenon is known as retrograde condensation and the reservoirs involved in this action are commonly known as condensed reservoirs. The pressure reduction produced by the gas distribution in these reservoirs, that are initially single phase gaseous, causes a liquid phase to appear in the layer.

In the following table, the components of SWEET, ACID and CONDENSED gas fluids are indicated.Sweet-and-Acid-Gas-components





Components of Natural Gas other than Methane

natural gas

Natural gas is a mixture of methane, with lower amounts of other hydrocarbons and other substances.
These other constituents modify the physical and chemical characteristics of natural gas, for example, inert gases make the natural gas heating value lower.
The substances that can be in natural gas are:
• Carbon dioxide
• Nitrogen
• Hydrogen sulphide
Heavier hydrocarbons which can be separated to give condensate (gasoline) Water vapour is always contained in natural gas.

Carbon Dioxide (CO2)
The content in CO2 varies from traces to very high amounts. It forms from the reaction of field water with silicates and carbonates. Even a minimal presence of carbon dioxide in natural gas saturated with water forms carbonic acid, which is the cause of severe corrosion in the surface equipment and the pipelines, that are usually made of carbon steel. Its removal is therefore, often a “must” in the plants.
The CO2 removal can be done by absorption using ethanolamine. Unfortunately, since the elimination process is carried out in the plants, corrosion inside well production tubing and conducts it is prevented or mitigated through injection of inhibitors.
The corrosion of carbon steel by CO2 is dependent on two factors: the presence of water or saturated steam and the partial pressure of CO2. CO2 is corrosive for carbon steel, only when it is combined with water, because it creates carbonic acid and ionic carbonic acids.
CO2 + H2O = H2CO3
H2CO3 = H+ + HCO3

Nitrogen (N2)
It is almost always present in small percentages in natural gas. Nitrogen does not cause corrosion in the equipment, but reduces the heating value of the gas. Its elimination can be required to produce sales gas with the specified calorific value.
The removal of nitrogen from the sales gas is normally accomplished using a cryogenic process.
Nitrogen is also commonly available as utility fluid, in all petrochemical plants, where is used for blanketing tanks and vessels and for inerting the plants and pipelines. Nitrogen is normally produced from the air either via an air fractionation unit or from air treated on carbon molecular sieves.
Usually it is stored in liquid form in special double-wall tanks. In gaseous state it is available in the plant from supply stations as part of a distribution network., normally at about 8 bar.

Hydrogen Sulphide (H2S)
It is the most dangerous compound that can be found in natural gas. It is responsible of corrosion phenomena taking place inside the gas treatment facilities; it is highly toxic and even lethal over certain concentrations.
Hydrogen sulphide is a weak acid in dry conditions, but in the presence of water its corrosive power is high.
H2S, corrodes carbon steel, because of its ionisation into H+ and HS –.
Its corrosion however, is less rapid than that of CO2 due to its lower ionisation. Moreover, H2S is depolarised by oxygen. The corrosion by hydrogen sulphide can also cause the so called sulphide stress corrosion cracking,
that can be avoided mainly by a proper material selection. To reduce general corrosion caused by H2S and CO2 inhibitors are used.
Inhibitors are substances injected into the pipes in low quantities. Main feature of inhibitors is the fact that some functional groups in their molecules can form very thin layers on the pipe wall, maintaining the metallic surface isolated from the acid. Among these compounds the most commonly used are the amino compounds.

Natural Gasoline
Gasoline is a liquid hydrocarbon mixture that forms from the condensation of the fractions that are less volatile than natural gas, that is to say propane, butane, pentane and higher hydrocarbons. Gasoline, from a commercial
standpoint, is defined by the following characteristics:
1. REID vapour pressure (0,7 bar)
2. Volatile substances @ 60 °C (28 ÷ 85 %)
3. Volatile substances @ 135 °C (> 90 %)
4. Final boiling point (< 190 °C)
5. Sourness Absent (Not corrosive)
The content of heavy hydrocarbons in the natural gas H2S, CO2 are the key factors for the definition and the design of proper treatment units.

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 Industry

Natural Gas Terminology:

Reservoir: Porous & permeable underground formation containing an individual bank of H.C.s confined by impermeable rock or water barriers characterized by a single natural pressure system.

read also What is Natural Gas

Field: Area of one or more reservoirs related to same structural feature.

Pool: Contains one or more reservoirs in isolated structures.

Wells can be classified as gas wells, condensate wells, and oil wells.

Gas wells: Wells with producing gas-oil ration (GOR)>100,000 scf/stb.

Condensate wells: Producing GOR < 100,000 scf/stb but > 5,000 scf/stb.

Oil wells: Wells with producing GOR < 5,000 scf/stb

Because NG is petroleum in a gaseous state, it is always accompanied by oil that is liquid petroleum. There are 3 types of NG: nonassociated gas, associated gas & gas condensate.

Nonassociated gas: Gas from reservoirs with minimal oil.

Associated gas: Gas dissolved in oil under natural conditions in the oil reservoir.

Gas condensate: Gas with high content of liquid H.C. at reduced P & T.

Utilization of Natural Gas

–  Natural gas is one of the major fossil energy sources.

– Combustion of 1 scf of NG generates 700 → 1,600 Btu of heat, depending upon gas composition.

– NG provided close to 24% of U.S. energy sources over 2000-2002.

– NG is used as a source of energy in all sectors of the economy.

– Natural gas was once a by-product of crude oil production.

– Since its discovery in 1821 in U.S.A. in Fredonia, New York, NG has been used as fuel in areas immediately surrounding the gas fields.

– In the early years of NG industry, when gas accompanied crude oil, it had to find a market or be flared; in the absence of effective conservation practices, oil-well gas was often flared
in huge quantities.

Consequently, gas production at that time was often short-lived, and gas could be purchased as low as 1 or 2% per 1,000 ft3 in the field.

– Consumption of NG in all end-use classifications (residential , industrial, commercial & power generation) increased rapidly since World War II.

– This growth resulted from several factors, including:

– Development of new markets.

– Replacement of coal as fuel for providing space & industrial process heat.

– Use of NG in making petrochemicals and fertilizers.

– Strong demand for low-sulfur fuels.

– The rapidly growing energy demands of Western Europe, Japan & U.S.A. couldn’t be satisfied without importing gas from far fields.

– Natural gas, liquefied by a refrigeration cycle, can now be transported efficiently and rapidly across the oceans by insulated tankers.

– The use of refrigeration to liquefy NG, and hence reduce its volume to the point where it becomes economically attractive to transport across oceans by tanker.

– It was first attempted on a small scale in Hungary in 1934 and later used in U.S.A. for moving gas in liquid form Louisiana up the Mississippi River to Chicago in 1951.

– The first use of a similar process on a large scale outside U.S.A. was the liquefaction by a refrigerative cycle of some of the gas from the Hassi R’Mel gas field in Algeria and the export
from 1964 onward of the resultant liquefied natural gas (LNG) by specially designed insulated tankers to Britain & France.

– NG is in this way reduced to about 1/600 of its original volume and the non-methane components are largely eliminated.

– At the receiving terminals, LNG is re-gasified to a gaseous state, whence it can be fed as required into the normal gas distribution grid of the importing country.

– Alternatively, it can be stored for future use in insulated tanks or subsurface storages.

– Apart from its obvious applications as a storable & transportable form of NG, LNG has many applications in its own right, particularly as a nonpolluting fuel for aircraft and ground

– Current production from conventional sources is not sufficient to satisfy all demands for NG.

Natural Gas Reserves

– 2 terms are frequently used to express NG reserves: proved reserves & potential resources.

– Proved reserves: Quantities of gas that have been found by the drill. They can be proved by known reservoir characteristics such as: production data, pressure relationships  and
other data, so that volumes of gas can be determined with reasonable accuracy.

– Potential resources: Quantities of NG that are believed to exist in various rocks of the Earth’s crust but haven’t yet been found by the drill. They are future supplies beyond the
proved reserves.

– There has been a huge disparity between “proven” reserves and potential reserves.

– Different methodologies have been used in arriving at estimates of the future potential of NG.

– Some estimates were based on growth curves, extrapolations of past production, exploratory footage drilled & discovery rates.

– Empirical models of gas discoveries and production have also been developed and converted to mathematical models.

– Future gas supplies as a ratio of the amount of oil to be discovered is a method that has been used also.

– Another approach is a volumetric appraisal of the potential undrilled areas. Different limiting assumptions have been made, such as drilling depths, water depths in offshore areas,
economics & technological factors.

– Even in the case of the highly mature and exploited U.S.A., depending upon information sources, the potential remaining gas reserve estimates vary from 650 Tcf to 5,000 Tcf.

– Proved NG reserves in 2000 were about 1,050 Tcf in U.S.A. & 170 Tcf in Canada.

– On the global scale, it is more difficult to give a good estimate of NG reserves.

– Unlike oil reserves that are mostly (80%) found in Organization of Petroleum Exporting Countries (OPEC), major NG reserves are found in the former Soviet Union, Middle East, Asia
Pacific, Africa, North America, Southern & Central America, and Europe.

Types of Natural Gas Resources

– NG classified as: conventional NG, gas in tight sands, gas in tight shales, coal-bed methane, gas in geopressured reservoirs & gas in gas hydrates.

  1. Conventional NG: Either associated or non-associated gas.

Associated or dissolved gas is found with crude oil. Dissolved gas is that portion of the gas dissolved in the crude oil and associated gas (sometimes called gas-cap gas) is free gas in
contact with the crude oil.  All crude oil reservoirs contain dissolved gas and may or may not contain associated gas.

– Non-associated gas is found in a reservoir that contains a minimal quantity of crude oil.

– Some gases are called gas condensates or simply condensates. Although they occur as gases in underground reservoirs, they have a high content of H.C. liquids so they yield
considerable quantities of them on production.

  1. Gases in tight sands: Found in many areas that contain formations generally having porosities of 0.001 to 1 millidarcy (md).

– At higher gas permeabilities, the formations are generally amenable to conventional fracturing and completion methods.

  1. Gases in tight shales: The shale is generally fissile, finely laminated, and varicolored but predominantly black, brown, or greenish-gray.

– Core analysis has determined that the shale itself has up to 12% porosity, however, permeability values are commonly < 1 md.

– It is thought, therefore, that the majority of production is controlled by naturally occurring fractures and is further influenced by bedding planes and jointing.

– Coal-bed methane: methane gas in minable coal beds with depths < 3,000 ft.

– Although the estimated size of the resource base seems significant, the recovery of this type of gas may be limited owing to practical constraints.

– Geopressured reservoirs: In a rapidly subsiding basin area, clays often seal underlying formations and trap their contained fluids. After further subsidence, P & T of the trapped fluids
exceed those normally anticipated at reservoir depth.

– These reservoirs have been found in many parts of the world during the search for oil & gas.

– Gas hydrates: Snow-like solids in which each water molecule forms hydrogen bonds with the four nearest water molecules to build a crystalline lattice structure that traps gas
molecules in its cavities.

– Contains about 170 times NG by volume under standard conditions.

– Because it’s a highly concentrated form of NG and extensive deposits of naturally occurring gas hydrates have been found in various regions of the world, they are considered as a
future, unconventional resource of NG.

read also What is LPG?

Future of the Natural Gas Industry

– The 19th century was a century of coal that supported the initiation of industrial revolution in Europe.

– The 20th century was the century of oil that was the primary energy source to support the growth of global economy.

– Simmons (2000) concluded that energy disruptions should be a “genuine concern“. He suggests that it will likely cause chronic energy shortage as early as 2010.  It will eventually
evolve into a serious energy crunch.

– The way to avoid such a crunch is to expand energy supply and move from oil to NG and eventually to H2.

– NG is the fuel that is superior to other energy sources not only in economic attractiveness but also in environmental concerns.

– At the end of the last century, natural gas took over the position of coal as the number 2 energy source behind oil.

– In 2000, total world energy consumption was slightly below 400 × 1015 Btu. Oil accounted for 39%, while NG & coal provided 23 % & 22 %, respectively of this.

– It is expected that the transition from oil to NG must be made in the early 21 century.  This isn’t only motivated by environmental considerations but also by technological innovations
and refinements.

1. Natural Gas Engineering Handbook, Dr. Boyun Guo and Dr. AIi Ghalambor
2. Natural Gas, by Primož Potočnik.
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Natural Gas to Liquids GTL


  • GTL means Gas to Liquids.
  • A whole range of fuels can be produced from Natural gas by partial oxidation to synthesis gas (a mixture of H2 and CO) and subsequent conversion of this gas • 1993 – Shell pioneered the GTL business at their Shell Middle Distillate Synthesis Plant in Bintulu.
  • In this plant Naphtha, Kerosene and Fischer Tropsch Diesel (FTD) were produced apart from other specialized products

how to convert natural gas to NGLGas to Liquids: A New Frontier for Natural Gas:

  • The relatively high world crude oil prices have drawn attention to the potential for developing previously uneconomical natural gas reserves, such as associated gas or stranded gas.
  • Converting these resources to liquids – either to liquefied natural gas (LNG) or to petroleum liquid substitutes, such as diesel, naphtha, motor gasoline, or other products (such as lubricants and waxes) by employing “gas to liquids” (GTL) technology – could provide a way to bring these gas resources to market.
  • GTL has recently become attractive as an option for monetizing stranded gas and complementing traditional commercialization opportunities such as LNG or pipeline transportation.

Gas to Liquid – Commercial Viability

NGL commercial

Gas to Liquids: Economics

  • The economics of GTL continue to improve with advances in technology and scale.

–        Capital costs have dropped significantly, from more than $100,000 per barrel of total installed capacity for the original plants to a range of $25,000 to $30,000 per barrel of capacity today.

–        Moreover, Royal/Dutch Shell has commented that it expects to be able to reduce the costs to below $20,000 per barrel.

–       By comparison, the costs associated with conventional petroleum refining are around $15,000 per barrel per stream day after several decades of technology improvements.

  • The high oil prices of recent years have made transportation fuels produced through GTL technology commercially viable.
    •          Few companies release the detailed costs of their GTL conversion technologies.
    •          According to ConocoPhillips, assuming that the cost of natural gas is $1.00 per million Btu, GTL fuel is cost competitive with diesel fuel at world oil prices above $20 per barrel.

GTL – FTD – Advantages:

  • Among the different GTL products, the diesel fraction is highly valued in the downstream market because of its unique properties that meet environmental regulations

–        The GTL fuel reduces emissions relative to conventional diesel, as it contains near-zero sulfur and aromatics.

–        GTL fuel also exhibits a high cetane number that enhances engine combustion performance

–        Because they are compatible with existing vehicle engines and fuel distribution infrastructures, GTL fuels are the most cost-effective in reducing emissions among the non-conventional fuels

Gas to Liquid Plants

At present, worldwide there are at least 9 commercial GTL projects at various stages of planning and development

  • for the period 2009 to 2012 that could bring to market an additional capacity of 580 thousand barrels per day.
  • More than 19 additional proposed projects could double that capacity beyond 2012
  • Initiated by companies operating in gas-rich countries – Qatar, Iran, Russia, Nigeria, Australia, and Algeria – where natural gas can be developed at a cost of less than $1.00 per million Btu.

Gas to Liquids – Major Initiatives

  • Qatar’s North Field, with an estimated 900 trillion cubic feet of natural gas reserves, and the adjoining South Pars field in Iran with an estimated 500 trillion cubic feet of reserves, are the cheapest natural gas resources in the world
  • For other countries, such as Nigeria and Algeria, GTL complements their LNG industries
  • offers promise for use in Nigeria to convert natural gas that would otherwise be flared.
  • Challenges

–        Huge capital investments

–        Project financing

–        Availability of qualified contractors and operators

Gas to Liquids –  Major Initiatives – Qatar

  • Qatar NGL projectsSix of the nine confirmed GTL projects are located in the state of Qatar as joint ventures

–        Based on an integrated development and production sharing agreement (DPSA) with major international oil companies.

–        Foreign companies have favored this approach, because it gives them an opportunity to book part of the gas reserves on their balance sheet and support their upstream and downstream activities

–        By 2011, Qatar is set to produce about 394,000 barrels of GTL products per day or 68% of total planned GTL capacity

  • Have established a favorable climate in terms of transparent business and investment policies.
  • Stable tax regulations
  • Enforcement of formal agreements
  • Government’s willingness to protect foreign investors through its legislature.
  • Stable political climate
  • Developed infrastructure and Service
  • Provides guarantees for the safety of foreign employees
  • Potential for future development through expansion of existing facilities.
    • Qatar reached agreements with a group of financial institutions to fund their gas-related projects in exceed $60 billion

    –        Developed a master plan to expand its port

    –        Double the size of Ras Laffan Industrial city from 39 square miles to 77 square miles,

    –        Accommodate 7 GTL projects, 16 LNG trains, 5 gas processing plants, 6 to 7 ethylene plants, and a variety of other gas-related industries.

    –        By 2012, Qatar must produce nearly 25 billion cubic feet of natural gas per day to support its commitments.

    –        10.3 bcf/day to produce 77 millions metric tons of LNG p. a

    –        4 bcf/day for the 394,000 barrels per day of GTL

    –        5 bcf/day for petrochemical, local power, and industrial projects

    –        2 bcf/day for exports through the Dolphin pipeline.

Gas Treating

Introduction to Gas Treating

When talking of gas treating, it is most often implied that natural gas is the focus. The natural gas industry is one of the World’s largest. However, there is also treatment of gas in the synthesis gas industry, and there are a number of processes used for this that are similar to those used for natural gas treatment.

Finally, there is a large industry devoted to separate air to make nitrogen, oxygen and argon, and to an extent, krypton and xenon. Such plants would be cryogenic distillation outfits for large capacities while adsorption and membranes are also in use for smaller units. There is also an emerging interest in CO2 removal from flue gases caused by the focus on CO2’s role in global warming.

The term gas treating is normally used to cover CO2 removal, H2S removal, water removal, hydrocarbon dew pointing and gas sweetening. Gas sweetening is a generic term for sulfur removal. Sometimes the term ‘gas conditioning’ is used instead of gas treating.

The key question is ‘why treat gas?’

This is a multi-faceted issue. The gas is produced from a well at a location where there is usually only a negligible market for it. Transport of the gas to the market is the first challenge. Traditionally this has been achieved by pipelines.

A lot could be said about pipelines, but here it will suffice to say that these are constructed in some steel material, and the properties of these materials are such that the presence of certain gases must be kept low to ensure the integrity of the pipeline. Hydrogen sulfide is a key component as it may cause stress corrosion cracking.

Pipeline specifications may vary, but its content is commonly kept below 3–5 ppm. In the US the number 0.25 grain per 100 SCF is often used, but there is no standard in this matter. It must be remembered that the flow velocity in gas pipelines will be too high to allow integrity for a protective sulfide film on

the inner pipe wall. For flow assurance reasons the dew point of the gas must be engineered before entering the pipeline. If the temperature is reduced, both water and hydrocarbons may condense. Water could form hydrate crystals with methane and these could block the flow of gas. Such hydrates are hard and time consuming to get rid of.

Clearly no pipeline operator would want this to happen. Liquid water could also cause corrosion when acidified by CO2 that is likely to be present in the gas. This is also undesirable. Finally hydrocarbon condensate could amass to quantities that would cause flow problems if left unchecked.

It must be remembered that pipelines follow landscapes where its elevation goes up and down repeatedly. CO2 is usually also kept below a certain limit, say 1–4%, depending on the local situation.

There is also another reason other than the pipeline considerations to treat gas. Downstream of the transport system, that could be complex, there is a multitude of customers that will use the gas. Their equipment will have been made with certain gas specifications in mind. Here, the gas heating value will an issue, theWobbe number is often specified and there will be limits on H2S and CO2. Corrosion issues apart, H2S would end up as SO2 in the flue gas and this would be an environmental problem.

Process Categories

There is limited attention paid to processing gases in a typical chemical engineering curriculum. This is, however, a huge field where many chemical engineers find employment. In general terms, there are four principally different main methods that may be used to separate gases. They include (in alphabetical order):

  • Absorption
    • Adsorption
    • Cryogenics: liquefaction and distillation
    • Membrane permeation.

Ab- and adsorption are often mixed up in write-ups, probably because their spelling is so similar. Process-wise there is a huge difference though. Adsorption is essentially a surface phenomenon while absorption involves something being dissolved.

Cryogenics involves gases being cooled until they condense after which they may be separated by distillation. Some such processes could also be argued to lean towards absorption and/or desorption. A nitrogen wash unit, sometimes used for synthesis gas treatment, is an interesting case with respect to that kind of discussion.

Membrane technology used for gas separation is in general based on so-called dense membranes that separate gases based on different permeation rates. Small volume niche

products within inorganic membranes may be different, but a discussion of this is beyond

the present scope.


Absorption is a much used process for separating gases, removing undesired gas components or to prevent pollution from stacks. The process is, by its nature, run at supercritical temperature with respect to the main gas component(s). There is no boiling like that seen in distillation columns. The mass transfer process is generally rate controlled. All components

are in principle undergoing mass transfer between gas and liquid, but all does not need to be accounted for and/or may be neglected. Mass transfer rates and mass transfer coefficients may differ in different directions for different components.

If a lot of gas needs to be absorbed, large absorbent flows will be needed. This represents an operational cost that, in the end, may be a show stopper for using absorption.

It is a very interesting process, and is in many ways the main focus for this treatise. A separate sub-chapter is dedicated to a preliminary discussion of absorption into alkanolamines in view of these absorbents’ commercial importance.


Practical adsorption processes use a granulated material with affinity for the component, or components that are desired to be removed. This material is referred to as the adsorbent,

while the material adsorbed is referred to as the adsorbate. There are four categories of adsorbents commonly used:

  • Molecular sieve zeolites
  • Activated alumina
  • Silica gel
  • Activated carbon.

There is also a carbon molecular sieve that is used for making moderate quantities of nitrogen from air, but we shall leave that aside. Also liquids may be treated by adsorption. In gas treating with absorbents, there is usually an adsorption treatment of this absorbent.

Regeneration of adsorbent may be done by both pressure swing and thermal swing, or a combination. Pressure swing alone is a commercial process that is applied to air separation and at least to hydrogen recovery from streams of synthesis gas. In gas treating contaminant removal by a combination process involving both temperature and pressure variation is mainly used. It could be used to remove water from the gas, and it is used as pretreatment

upstream of liquefied natural gas (LNG) trains to ensure sufficiently low dew points.

Pressure swing implies that the pressure is changed, and temperature swing implies that the temperature is changed.

Adsorption processes are semi-continuous. By this we mean that they continuously treat the gas without a buffer volume, the discontinuity comes from the need to switch between two or more parallel units. The unit not adsorbing is being regenerated offline at a lower pressure and increased temperature with a heat carrying dilution gas flowing through.

This dilution gas may need to be a part of the product gas that most likely will need to be recirculated. In big units more than two parallel columns are often used, sometimes in intricate process stages to emulate some counter-current action while regenerating.

Isotherms for commercial adsorbents are hard to come by. There used to be a couple of companies that handed out leaflets with such content, but such information is certainly not offered on their web sites. In this context it has to be kept in mind that these products are forever being developed such that isotherms may be improved. It is, however, nice to be able to make the odd order of magnitude estimate. This is by no means the result of a thorough

review, but the isotherms used have been published by a number of people and such publications are summarized in Table 2.1 to provide a quick reference as a starting point.

When both CO2 and water are adsorbed, it should be clear from Table 2.1 that water is significantly more strongly adsorbed and will push CO2 away as they compete for adsorption sites. In pretreatment of air for air separation plants this means that there will be a CO2 front moving through the adsorption bed in the direction of flow with a water front pushing from behind. A practical aspect of this is that there is no real need to check for water breakthrough.

It is actually easier to handle a CO2 detector and a water break-through would, in any case, be worse for a cryogenic plant.

On the practical side molecular sieve zeolites could catch 10 g water per 100 g of zeolite in a practical cycle. (Suggested as a quick first approach by a sales engineer a long time ago.

The capacity for CO2 is less. This has implications for adsorption column design. When the gas quantity to be treated is large and the contaminant concentration is significant, the amount of adsorbent needed could be become very large.

Adsorption is mostly used for trace quantity removal. Specific applications will be discussed as they arise. They could include water removal from gas, and a big application is combined water and CO2 removal from air feed to ASUs (ASU=Air Separation Unit).

There is a lot of research going on in the hope of finding a solution that may be used for CO2 removal from flue gas. Recent adsorbents have been reviewed by Hedin and co-workers (2013). They point out that rapid cycling is necessary and believe that some form of structured adsorbent is necessary for success. Treatment of flue gas by vacuum-pressure swing adsorption (VPSA) has been studied (Xiao et al., 2008).

They tested three-bed designs using up to 12 steps in the adsorption-desorption cycle to improve CO2 recovery and purity. Recoveries reported were in the range 70–82%, and purities 82–96%. In the air separation industry VSA is used when oxygen purity does not need to be high, typically 90% although higher can be provided. Argon follows oxygen and is one reason why the purity is that low for reasons of economics.

1. Gas Treating – Absorption Theory and Practice – DAG A. EIMER
2. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Natural Gas Hydrates

what are Hydrates

  1. Introduction to Hydrate

Natural gas hydrates are ice-like materials formed under low temperature and high pressure conditions. Natural gas hydrates consist of water molecules interconnected through hydrogen bonds which create an open structural lattice that has the ability to encage smaller hydrocarbons from natural gas or liquid hydrocarbons as guest molecules.

Interest in natural gas hydrates as a potential energy resource has grown significantly in recent years as awareness of the volumes of recoverable gas becomes more focused. The size of this resource has significant implications for worldwide energy supplies should it become technically and economically viable to produce. Although great efforts are being made, there are several unresolved challenges related to all parts in the process towards full scale hydrate reservoir exploitation. Some important issues are: 1) Localize, characterize, and evaluate resources, 2) technology for safe and economic production 3) safety and seafloor stability issues related to drilling and production. Thisarticle gives a brief introduction to natural gas hydrate and its physical properties. Some important characteristics of hydrate accumulations in nature are also discussed.

read also What is Natural Gas

Experimental results presented in this chapter emphasis recent work performed by the authors and others where we investigate the possibilities for producing natural gas from gas hydrate by CO2 replacement. By exposing the hydrate structure to a thermodynamically preferred hydrate former, CO2, it is shown that a spontaneous conversion from methane hydrate to CO2 hydrate occurred. Several experiments have shown this conversion in which the large cavities of hydrates prefer occupation by CO2.

read also Hydrate and Hydrate Prevention

  1. Structures and Properties

There are three known structures of gas hydrates: Structure I (sI), structure II (sII) and structure H (sH). These are distinguished by the size of the cavities and the ratio between large and small cavities. SI and sII contain both a smaller and a larger type of cavity, but the large type cavity of sII is slightly larger than the sI one. The maximum size of guest molecules in sII is butane. SH forms with three types of cavities, two relatively small ones and one quite large.


The symmetry of the cavities leaves an almost spherical accessible volume for the guest molecules. The size and shape of the guest molecule determines which structure is formed due to volumetric packing considerations. Additional characteristics are guest dipole and/or quadropole moments, such as for instance for H2S and CO2. The average partial charges related to these moments may either increase the stability of the hydrate (H2S) or be a decreasing factor in thermodynamic stability (CO2). SII forms with for instance propane and iso-butane and sH with significantly larger molecules, as for instance cyclo-hexane, neo-hexane. Both methane and carbon dioxide form sI hydrate. SI hydrates forms with guest molecules less than 6 Å in diameter. The cages and the number of each cage per unit cell are shown in Figure 1. SI cages are shown at the top of the figure. The unit cell of sI hydrate contains 46 water molecules and consists of 2 small and six large cages.

The unit cell is the smallest symmetric unit of sI. The two smaller cavities are built by 12 pentagonal faces (512) and the larger of 12 pentagonal faces and two hexagon faces (51262). The growth of hydrate adds unit cells to a crystal.

Classification of Hydrate Deposits

hydrate classes

Boswell and Collett, 2006, proposed a resource pyramid to display the relative size and feasibility for production of the different categories of gas hydrate occurrences in nature. The top resources of the gas hydrates resource pyramid are the ones closest to potential commercialization. According to Boswell and Collett, these are occurrences that exist at high saturations within quality reservoirs rocks under existing Arctic infrastructure.

This superior resource type is estimated by US geological survey (USGS) to be in the range of 33 trillion cubic feet of gas-in-place under Alaska’s North Slope. Prospects by British Petroleum and the US DOE anticipate that 12 trillion cubic feet of this resource is recoverable. Even more high-quality reservoirs are found nearby, but some distance away from existing infrastructure (level 2 from top of pyramid). The current USGS estimate for total North Slope resources is approximately 590 Tcf gas-in-places. The third least

challenging group of resources is in high-quality sandstone reservoirs in marine environments, as those found in the Gulf of Mexico, in the vicinity of existing infrastructure.

There is a huge variation in naturally occurring hydrate reservoirs, both in terms of thermodynamic conditions, hosting geological structures and trapping configurations (sealing characteristics and sealing geometry). Hydrates in unconsolidated sand are considered as the main target for production. For the sake of convenience, these types of hydrate occurrences have been further divided into four main classes,

Class 1 deposits are characterized with a hydrate layer above a zone with free gas and water. The hydrate layer is composed with either hydrate and water

(Class 1W) or gas and hydrate (Class 1G). For both, the hydrate stability zone ends at the bottom of the hydrate interval. Class 2 deposits exist where the hydrate bearing layer, overlies a mobile water zone. Class 3 accumulations are characterized by a single zone of hydrate and the absence of an underlying zone of mobile fluids. The fourth class of hydrate deposits is widespread, low saturation accumulations that are not bounded by confining strata that may appear as nodules over large areas. The latter class is generally not regarded as a target for exploitation.

Proposed Production Schemes


The three main methods for hydrate dissociation discussed in the literature are (1) depressurization, where the hydrate pressure is lowered below the hydration pressure PH at the prevailing temperature; (2) thermal stimulation, where the temperature is raised above the hydration temperature TH at the prevailing pressure; and (3) through the use of inhibitors such as salts and alcohols, which causes a shift in the PH-TH equilibrium due to competition with the hydrate for guest and host molecules. The result of hydrate dissociation is production of water and gas and reduction in the saturation of the solid hydrate phase.

Environmental Aspects of Gas Hydrates

  1. Climate change

The natural gas produced from hydrates will generate CO2 upon combustion, but much less than conventional fuel as oil and coal per energy unit generated. The global awareness of climate change will most likely make it more attractive in relation to oil and coal if fossil fuels, as anticipated, continue to be a major fuel for world economies the next several decades. However, increased global temperatures have the potential of bringing both permafrost hydrates and subsea hydrates out of equilibrium. As a consequence, huge amounts of methane may be released to the atmosphere and accelerate the greenhouse effect due to feedback. In general hydrate is not stable towards typical sandstone and will fill pore volume rather than stick to the mineral walls. This implies that if there are imperfections and leakage paths in the sealing mechanisms the hydrate reservoir will leak. There are numerous small and large leaking hydrate reservoirs which results in methane fluxes into the ocean. Some of these fluxes will be reduced through consumption in biological ecosystems or chemical ecosystems. The net flux of methane reaching the atmosphere per

year is still uncertain. Methane is by far a more powerful greenhouse gas than CO2 (~20 times). hypothesized that major release from methane hydrate caused immense global warming 15 000 years ago. This theory, referred to as “clathrate gun” hypothesis is still regarded as controversial, but is supported in a very recent paper by Kennedy et al. (2008). The role of gas hydrate in global climate change is not adequately understood. For hydrate methane to work as a greenhouse gas, it must travel from the subsurface hydrate to the atmosphere. Rates of dissociation and reactions/destruction of the methane gas on its way through sediment layers, water and air are uncharted.

  1. Geomechanical Stability

Gas hydrates will affect the seafloor stability differently for the different types of hydrate occurrences. All of these hydrate configurations may take part of the skeleton framework that supports overlying sediments, which in turn is the fundament for pipelines and installations needed for production. These concerns have already been established for oil and gas exploitation where oil and gas reservoirs that lie below or nearby hydrate bearing sediments. However, geohazards would potentially be far more severe if gas hydrate is to

be produced from marine hydrate deposits. During melting, the dissociated hydrate zone may lose strength due to under-consolidated sediments and possible over-pressuring due to the newly released gas. If the shear strength is lowered, failure may be triggered by gravitational loading or seismic disturbance that can result in submarine landslides

Several possible oceanic landslides related to hydrate dissociation are reported in the literature. Among these are large submarine slides on the Norwegian shelf in the North Sea  and massive bedding-plane slides and slumps on the Alaskan Beaufort Sea continental margin.

Production of CH4 from hydrates by CO2 exposure

Thermodynamic prediction suggests that replacement of CH4 by CO2 is a favourable process. This section reviews some basic thermodynamics and earlier experimental studies of this CH4-CO2 reformation process to introduce a scientific fundament for the experimental work presented later in this chapter.

Thermodynamics of CO2 and CH4 Hydrate

CO2 and CH4 form both sI hydrates. CH4 molecules can occupy both large and small cages, while CO2 molecules will prefer the large 51262 cage. Under sufficiently high pressures or low temperatures both CO2 and CH4 will be stable, but thermodynamic studies suggest that CH4 hydrates have a higher equilibrium pressure than that of CO2 hydrates for a range of temperatures. A summary of these experiments is presented in Sloan & Koh,

shows the equilibrium conditions for CO2 and CH4 hydrate in a P-T diagram. This plot is produced using the CSMGem software (Sloan & Koh, 2008), which supplies the most recent thermodynamic predictions.

CO2-CH4 exchange in bulk

Based on the knowledge of increased thermodynamic stability it was hypothesized that CO2 could replace and recover CH4 molecules if exposed to CH4 hydrate .

Several early researchers investigated the CO2-CH4 exchange mechanism as a possible way of producing methane from hydrates. These studies emphasized the thermodynamic driving forces that favour this exchange reaction, though many of the results showed significant kinetic limitations. Many of these early

studies dealt with bulk methane hydrate samples placed in contact with liquid or gaseous CO2, where available surfaces for interaction were limited., studied the CO2-CH4 exchange process in a high pressure cell using powdered CH4 hydrate and then exposed it to CO2. They observed a fairly rapid initial conversion during the first 200 minutes, which then slowed down significantly. found remarkable recovery of methane hydrate by using CO2 and N2 mixtures. They found that N2 would compete with CH4 for occupancy of the smaller sI cages, while CO2 would occupy only the larger sI cage – without any challenge of other guests. They also found that sII and sH would convert to sI and yield high recoveries (64-95%) when exposed to CO2 or CO2-N2 mixtures.

An inherent limitation in this experiment is the absence of mineral surfaces and the corresponding impact of liquids that may separate minerals from hydrates. These liquid channels may serve as transport channels as well as increased hydrate/fluid contact areas.

CO2-CH4 Exchange in Porous Media

Lee et al., 2003 studied the formation of CH4 hydrate, and the subsequent reformation into CO2 hydrate in porous silica. CH4 hydrate was formed at 268 K and 215 bar while the conversion reaction was studied at 270 K. The temperatures in the ice stability region could have an impact on the reformation mechanisms since ice may form at intermediate stages of opening and closing of cavities and partial structures during the reformation. Temperatures below zero may also have an impact in the case where water separates minerals from hydrates. Preliminary studies of the CO2 exchange process in sediments showed slow methane production when the P-T conditions were near the methane hydrate stability and at CO2 pressure values near saturation levels .The research presented below revisit the CO2- CH4 exchange process in hydrates formed in porous media, this time in larger sandstone core plugs and well within the hydrate stability for both CO2 and CH4 hydrate, and outside the regular ice stab

1. Gas Treating – Absorption Theory and Practice – DAG A. EIMER
2. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Gas Markets, Gas Applications and Feedstock

The natural gas market world-wide is huge. Although there is a need to provide a standardized gas such that all the end users’ gas burners will function as intended, there are regional differences in specifications. The US market has this challenge that makes the interchangeability of gases difficult, and the cost and feasibility of standardizing has been considered but discarded.

In the UK, however, a similar conversion was done area by area in the 1960s and 1970s as the market was converted from ‘town gas’ to ‘North Sea gas’. (Town gas was synthesized by gasification of coal.) Town gas was common in Europe until the advent of gas finds in the North Sea. Pipelines from these and Russian fields serves this market today. North America has had a change of fortune in recent years by technology enabling the production of so-called shale gas. There have also been LNG projects developed, with more coming on stream in the next few years. Gas is challenged by other forms of energy.

Although existing users are to an extent ‘sitting ducks’ due to investments made, provision costs of gas must be kept in check to keep its market share. Electricity is the immediate competitor in the retail market, and that in turn could be provided through the combustion of gas, coal or oil, and other sources are nuclear power plants and hydroelectricity. The more alternatives that are available in any one market, the more the focus on provision cost of energy in the market. Deeper discussions of these issues may be found elsewhere (BP, 2011; IGU, 2013a,b; Natural Gas Supply Association, 2005).

Specifications of natural gas as a product is a very interesting topic in many ways and the specifications really determine what treatment a gas eventually needs. There are two dimensions to this. One is the transport system that supplies a market and what treatment the gas needs to uphold flow assurance in the supply chain. The other is the end market with its appliances where gas burners have been fitted with certain gas properties in mind.

Interchangeability of gas cannot be taken for granted. There are many stumbling blocks to this (IGU, 2011). Methane, or natural gas, is less reactive than their heavier analogues like ethane, propane and so on. As feedstock for making hydrogen as in the ammonia process it is the preferred starting point as the ratio of hydrogen to carbon is highest in methane. For this reason, and because of the pricing, natural gas is the feedstock of choice for this purpose.

The C2+ fraction of the natural gas has in the main a higher market value as feedstock than as fuel. Hence the opportunity to separate these components from the gas is often taken. The economics of this has varied over time though.


For various assessments it is valuable to have a feel for sizes of plants and associated variables. The question being, what is big, what is small, what is a challenge and what is trivial. Plant sizes and complexities will vary widely. Perhaps the simplest gas treating plant to be encountered in this context will the end-of-pipe solution scrubber where some contaminant is to be removed from an effluent gas stream before being released. Maybe this scrubber has a packing height of 3m and a diameter of 2 m, and furthermore when the absorbent has done its job, it may be returned to the process without further ado. A 400MW CCGT (Combined Cycle Gas Turbine) power plant that needs CO2 abatement will have a gas stream in the order of 1.8millionm3/h, and the absorber would have a diameter around 17m if there is one train only.

A large synthesis gas train may have a gas flow in the order of 10 000 kmol/h. This would be 224 000Nm3/h. However, the pressure could be around 25 bar if this was an ammonia plant, and this would imply a real gas stream in the order of 10 000m3/h. In natural gas treating there is a wide range of plants.

A fairly small one might be 10 MMSCFD. This is a typical way of specifying plant size in North America. MMstands for ‘mille-mille’, which is Latin inspired, meaning 1000 × 1000 (or a million). SCF is Standard Cubic Feet, and D implies per 24 hours (a Day). In North America ‘Standard’ means the gas volume is at 60ºF and an absolute pressure of 14.696 psi (psi =pounds per square inch).

the ‘standard’ pressure may also be 14.73 psi, which is based on a pressure of 30 in. of a mercury column. Beware; if you are buying gas the difference in what you get is 0.23%, which is not to be given away easily in negotiations. A large gas plant could be in the region of 2million Sm3/day. This is typical of a gas field in the North Sea. This is in metric units, and the ‘standard’ now implies 15ºC and 1.013 bar. If this was indeed the gas’s temperature and pressure it would be at its ‘standard

conditions.’ Note that 15ºC and 60ºF are not identical. European and American standard conditions are not equal: something to be kept in mind when selling and buying.
An often used specification for H2S allowed in natural gas is 0.25 grain per 100 SCF. This is a US term. One ‘grain’ is 1/7000th of a pound (lb). LNG plants are usually referred to in million tonnes of LNG per year. A plant of 3million tonnes per year was considered big less than 10 years ago, but one-train capacities have been stretched to 5–7 and there is a new generation of plants with a third refrigeration loop that could take the capacity to 10 million or more.

A large ammonia plant today would typically be 2000 tonnes per day. This is almost the double of what was usual around 1970. Cryogenic air separation units (ASU) could be as big as 3500 tonne of oxygen per day, but this size of plant is rare. Traditionally they have been built to provide oxygen for steel works. However, they figure in present day studies on oxy-fuel plants. That is, power plants where hydrocarbons, or coal more likely, is combusted with oxygen to make the CO2 resulting more easily accessible for capture and storage.

It is good to develop an intuitive sense for plant sizes and put them into perspective. The ability to distinguish between the various ‘standard’ units of gas quantity is a must. To help in this direction and to summarize the earlier discussion of plant sizes.

Ambient Conditions

Plants have been built in all sorts of places. Some are hot, some are cold and some are to be found at a high altitude where the air is thin. When comparing plant costs and efficiencies, this must be kept in mind. An LNG plant will of course have a better efficiency if the heat sink is at 5ºC compared 35ºC. On the other hand winterization may be costly. Special precautions must be made if it is to be operated for weeks on end at −40ºC.

1. Gas Treating – Absorption Theory and Practice – DAG A. EIMER
2. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

What is LNG?

What is LNG?
Liquefied natural gas, or LNG, is natural gas in its liquid form. When natural gas is cooled to minus 259 degrees Fahrenheit (-161 degrees Celsius), it becomes a clear, colorless, odorless liquid. LNG is neither corrosive nor toxic.
Natural gas is primarily methane, with low concentrations of other hydrocarbons, water, carbon dioxide, nitrogen, oxygen and some sulfur compounds. During the process known as liquefaction, natural gas is cooled below its boiling point, removing most of these compounds. The remaining natural gas is primarily methane with only small amounts of other hydrocarbons. LNG weighs less than half the weight of water so it will float if spilled on water.


LNG plant

Natural gas is in great demand globally as a clean fuel and as a feedstock for petrochemicals, agricultural chemicals and plastics. Traditionally, transport has been limited to pipelines, whose economic and physical limitations have typically restricted distribution to regional/interstate supply, relatively close to the gas source, where terrain and geopolitical considerations are not prohibitive. However,
when converted to Liquefied Natural Gas (LNG), the fuel can be conveniently transported by ship to distant markets
worldwide – well beyond the reach of pipeline systems, thereby greatly increasing the availability of this highly desirable energy resource with an unparalleled flexibility of supply.

Liquefied natural gas (LNG) is essentially natural gas (NG), cooled at a certain temperature below its vaporization point. Thus, the LNG  productive chain starts in the exploration and production of natural gas.
At this initial exploration phase, there is a close relation between the NG and petroleum industries. This occurs because usually, in the same basin, there may be gas together with
petroleum, either dissolved or as a gas layer formed in the upper part of the deposit. In this case, it is said that natural gas is “associated” to petroleum. In turn, the so-called “nonassociated” gas is the one found in fields where there is very little or no petroleum, allowing only the exploration of gas. This way, the geological research efforts to locate these fields, as well as the drilling, development and exploration technologies may be shared between the two industries.

 How it works
When chilled to -162º C (-260º F) at 1 atm, natural gas is a clear liquid taking up 600 times less space than the corresponding gas and enabling practical transportation
by specially designed ships. Various combinations of refrigeration cycles are used in licensed LNG production processes, but most employ gas turbine-driven compressors
to achieve the necessary cryogenic temperatures. For commercial, safety and environmental reasons, these compression units must be very robust, efficient, and
highly reliable.

Where does LNG come from?
A majority of the world’s LNG supply comes from countries with large natural gas reserves. These countries include Algeria, Australia,
Brunei, Indonesia, Libya, Malaysia, Nigeria, Oman, Qatar, and Trinidad and Tobago.

What countries import LNG?
There are 60 LNG receiving terminals located worldwide. Japan, South Korea, the United State and a number of European Counties
import LNG.

Where are LNG import terminals located in the United States?
LNG terminals in the United States are located in Everett, Massachusetts; Cove Point, Maryland; Elba Island, Georgia; and Lake Charles, Louisiana; Offshore Boston; Gulf of Mexico; Freeport, Texas; Sabine, Louisiana; and Peñuelas, Puerto Rico.

How is LNG transported?
LNG is transported in double-hulled ships specifically designed to handle the low temperature of LNG. These carriers are insulated to limit the amount of LNG that boils off or evaporates. This boil off gas is sometimes used to supplement fuel for the carriers. LNG carriers are up to 1000 feet long, and require a minimum water depth of 40 feet when fully loaded. There are currently 136 ships which transport more than 120 million metric tons of LNG every year. (Source: University of Houston IELE,Introduction to LNG.)

 How is LNG stored?

LNG tank farm

When LNG is received at most terminals, it is transferred to insulated storage tanks that are built to specifically hold LNG. These tanks can be found above or below ground and keep the liquid at a low temperature to minimize the amount of evaporation. If LNG vapors are not released, the pressure and temperature within the tank will continue to rise. LNG is characterized as a cryogen, a liquefied gas kept in its liquid state at very low temperatures. The temperature within the tank will remain constant if the pressure is kept constant by allowing the boil off gas to escape from the tank. This is known as auto-refrigeration. The boil-off gas is collected and used as a fuel source in the facility or on the tanker transporting it. When natural gas is needed, the LNG is warmed to a point where it converts back to its gaseous state. This is accomplished using a regasification process involving heat exchangers.

 How is natural gas stored?
Natural gas may be stored in a number of different ways. It is most commonly stored underground under pressure in three types of facilities. The most commonly used in California are depleted reservoirs in oil and/or gas fields because they are more available. Aquifers and salt cavern formations are also used under certain conditions. The characteristics and economics of each type of storage site will dictate its suitability for use. Two of the most important characteristics of an underground storage reservoir are its capability to hold natural gas for future use and its deliverability rate. The deliverability rate is determined by the withdrawal capacity of the associated valves and compressors and the total amount of gas in the reservoir. In other states, natural gas is also stored as LNG after the natural gas has been liquefied and placed in above-ground storage tanks. (Source: U.S. Department of Energy, Energy Information Administration.)

 How is LNG used?
LNG is normally warmed to make natural gas to be used in heating and cooking as well as electricity generation and other industrial uses. LNG can also be kept as a liquid to be used as an alternative transportation fuel.

Why use LNG?
Natural gas is the cleanest burning fossil fuel. It produces less emissions and pollutants than either coal or oil. The North American supply basins are maturing and as demand for natural gas increases in California and throughout the United States, alternative sources of natural gas are being investigated. Natural gas is available outside of North America, but this gas is not accessible by pipelines. Natural gas can be imported to the United States from distant sources in the form of LNG. Since LNG occupies only a fraction (1/600) of the volume of natural gas, and takes up less space, it is more economical to transport across large distances and can be stored in larger quantities. LNG is a price-competitive source of energy that could help meet future economic needs in the United States.

 Is LNG flammable?
 When cold LNG comes in contact with warmer air, it becomes a visible vapor cloud. As it continues to get warmer, the vapor cloud becomes lighter than air and rises. When LNG vapor mixes with air it is only flammable if it’s within 5%-15% natural gas in air. If it’s less than five percent natural gas in air, there is not enough natural gas in the air to burn. If it’s more than 15 percent natural gas in air, there is too much gas in the air and not enough oxygen for it to burn.

 Is LNG explosive?
As a liquid, LNG is not explosive. LNG vapor will only explode if in an enclosed space. LNG vapor is only explosive if within the flammable range of 5%-15% when mixed with air.

 What is a Rapid Phase Transition?
When enough LNG is spilled on water at a very fast rate, a Rapid Phase Transition, or RPT, occurs. Heat is transferred from the water to the LNG, causing the LNG to instantly convert from its liquid phase to its gaseous phase. A large amount of energy is released during this rapid transition between phases and a physical explosion can occur. While there is no combustion, this physical explosion can be hazardous to any nearby person or buildings.

  LNG Liquefying
The natural gas liquefying plant is the main stage in the LNG production chain. In it, the temperature of natural gas is reduced to -162º C, which is below the vaporization point of methane. Hence, the methane gas turns liquid and its volume is reduced to 1/600 of the original volume
The liquefying plant is usually built in coastal areas, in bays, so that it facilitates the production outflow by vessels, thus making it also desirable for the plant to be close to the NG producing fields, as the transportation price via gas pipelines is considerable and, depending on the distance to be covered, it may increase the global costs of the project.
The premises composing the liquefying plant are: a gas processing unit (UPGN) in case the gas has not been previously processed with the separation of components of greater commercial value and the standardization of the product global composition. The gas is then dehydrated and broken down, so that hydrocarbons are separated: processed or dry gas (essentially methane), ethane, GLP (propane and butane) and C5+ components (especially natural gasoline). This way, the natural gas processed is led to the liquefying
stage in a set of heat exchangers and LNG storage tanks.
The liquefaction of NG is conducted at several stages of gas cooling until the cooled liquid is obtained in a process similar to that of a conventional refrigerator. A cooling gas extracts heat from the NG by means of heat exchangers in parallel sets, forming liquefying trains until this gas is cooled at a temperature of -162ºC.
Propane is the main cooling gas, leading the NG temperature to -30ºC; the gas will go through other cooling trains in which nitrogen, associated to other hydrocarbons, act as secondary coolers, making NG go below the vaporization temperature.
The technology that uses propane as initial cooling gas is the most commonly used and gained the market along the evolution and diffusion of LNG in the world market,
incorporating several technological improvements, mainly concerning cooling compression turbines, which account for a large share of the plants operational cost and their efficiency, allied to increase in power and environmental improvement in the use of cooling gases, besides the development of much more efficient thermal insulating materials, which revest the storage tanks, were essential for the growth in the insertion of LNG as a viable option to
natural gas.
The storage of liquefied NG is made in tanks with compression and re-liquefying systems to recover the gases that leak from stocking and resume the gas state; the logistics of liquefying, shipping and transportation forecasts is necessary for minimizing the stored volume, maximizing the LNG production and therefore mitigating losses from re-liquefying
and storage.

LNG Shipping

LNG ship
LNG ship

 In order to convey the LNG between the liquefying and regasification plants, specially built vessels for storing gas in its liquid form are used, which count on large reservoirs capable of keeping the gas temperature during transportation. However, losses occur in this process varying from 1% to 3% of the initial volume, according to the distance to be covered, besides the consumption of the gas employed as fuel for the LNG Carrier Ship.
the ones that store gas in spherical tanks and those counting on tanks in longitudinal positions; the costs between the two types is similar both in construction and in operation.In function of its great meaningfulness for the world LNG industry, Japan concentrates a large share of the shipyards that build these types of vessels, and today it has European
and Korean shipyards as competitors in this sector. The major producing companies are Daewoo Shipbuilding, Hyundai Heavy Industries, Mitsui Engineering & Shipbuilding,
Samsung Heavy Industries, Kawasaki Shipbuilding and Mitsubishi Heavy Industries.
Besides LNG Carrier Ships, LNG can also be conveyed by smaller tanks, by means of trucks or trains generally used to supply peak, temporary or isolated demands when the development cost of a gas pipeline makes the gas supply too expensive.
 Regasification plants constitute the importation side in the LNG chain. They are usually located close to the natural gas consumer centers and harbor LNG Carrier Ships in
especially built terminals. The plants are formed by LNG storage tanks and heat exchangers where LNG is again transformed into gas for distribution.

What is Natural Gas?

Natural gas is a subcategory of petroleum that is a naturally occurring, complex mixture of hydrocarbons, with a minor amount of inorganic compounds. Geologists and chemists agree that petroleum originates from plants and animal remains that accumulate on the sea/lake floor along with the sediments that form sedimentary rocks. The processes by which the parent organic material is converted into petroleum are not understood.

    Natural Gas is a mixture of gaseous hydrocarbons occurring in reservoirs of porous rock (commonly sand or sandstone) capped by impervious strata. It is often associated with petroleum, with which it has a common origin in the decomposition of organic matter in sedimentary deposits. Natural gas consists largely of methane (CH4) and ethane (C2H6), with also propane (C3H8) and butane (C4H10)(separated for bottled gas), some higher alkanes (C5H12 and above) (used for gasoline), nitrogen (N2) , oxygen (O2), carbon dioxide (CO2), hydrogen sulfide (H2S), and sometimes valuable helium (He). It is used as an industrial and domestic fuel, and also to make carbon-black and chemical synthesis. Natural gas is transported by large pipelines or (as a liquid) in refrigerated tankers. Natural gas is combustible mixture of hydrocarbon gases, and when burned it gives off a great deal of energy. We require energy constantly, to heat our homes, cook our food, and generate our electricity . Unlike other fossil fuels, however, natural gas is clean burning and emits lower levels of potentially harmful byproducts into the air. It is this need for energy that has elevated natural gas to such a level of importance in our society, and in our lives.
The contributing factors are thought to be bacterial action; shearing pressure during compaction, heat, and natural distillation at depth; possible addition of hydrogen from deep-seated sources; presence of catalysts; and time.

Natural gas accumulations in geological traps can be classified as reservoir, field, or pool. A reservoir is a porous and permeable underground formation containing an individual bank of hydrocarbons confined by impermeable rock or water barriers and is characterized by a single natural pressure system. A field is an area that consists of one or more reservoirs all related to the same structural feature.

a pool contains one or more reservoirs in isolated structures. Wells in the same field can be classified as gas wells, condensate wells, and oil wells. Gas wells are wells
with producing gas-oil-ration (GOR) being greater than 100,000 scf/stb, condensate wells are those with producing GOR being less than 100,000 scf/stb but greater than 5,000 scf/stb; and wells with producing GOR being less than 5,000 scf/stb are classified as oil wells.

natural gas components
natural gas components

The Components of Natural Gas

   Although the principal use of natural gas is the production of pipeline quality gas for distribution to residential and industrial consumers for fuel, a number of components in natural gas are often separated from the bulk gas and sold separately.

The principal use of methane is as a fuel; it is the dominant constituent of pipeline quality natural gas. Considerable quantities of methane are used as feedstock in
the production of industrial chemicals, principally ammonia and methanol.


The majority of the ethane used in the United States comes from gas plants, and refineries and imports account for the remainder. In addition to being left in the
gas for use as a fuel, ethane is used for the production of ethylene, the feedstock for polyethylene.
Gas plants produce about 45% of the propane used in the United States, refineries contribute about 44%, and imports account for the remainder. The principal uses
are petrochemical (47%), residential (39%), farm (8%), industrial (4%), and transportation (2%) . A special grade of propane, called HD-5, is sold as fuel.
When NGL is fractionated into various hydrocarbon streams, the butanes along with part of the propane are sometimes separated for use in local markets because
they are transportable by truck. The remaining light ends, an ethane−propane mix (E-P mix), is then pipelined to a customer as a chemical or refining feedstock.
Approximately 42% of the United States supply of isobutene comes from gas plants, refineries supply about 5% (this percentage does not include consumption
of isobutane within the refinery), and imports are responsible for about 12%. The remaining isobutane on the market is furnished by isomerization plants that
convert n-butane to isobutane. The three primary markets for isobutane are as a feedstock for MTBE (methyl tertiary butyl ether) production (which is being
phased out), as a feedstock in the production of reformulated gasoline, and as a feedstock for the production of propylene oxide.
  6. n-BUTANE
Gas plant production of n-butane accounts for about 63% of the total supply, refineries contribute approximately 31%, and imports account for the remainder.
Domestic usage of n-butane is predominantly in gasoline, either as a blending component or through isomerization to isobutane. Specially produced mixtures
of butanes and propane have replaced halocarbons as the preferred propellant in aerosols.
Natural gas liquids (NGL) include all hydrocarbons liquefied in the field or in processing plants, including ethane, propane, butanes, and natural gasoline. Such
mixtures generated in gas plants are usually referred to as “Y-grade” or “raw product.”
Natural gasoline, a mixture of hydrocarbons that consist mostly of pentanes and heavier hydrocarbons and meet GPA product specifications, should not be confused
with natural gas liquids (NGL), a term used to designate all hydrocarbon liquids produced in field facilities or in gas plants.
The major uses of natural gasoline are in refineries, for direct blending into gasoline and as a feedstock for C5/C6 isomerization. It is used in the petrochemical
industry for ethylene production.
Current sulfur production in the United States is approximately 15,000 metric tons per day (15 MMkg/d); about 85% comes from gas processing plants that
convert H2S to elemental sulfur. Some major uses of sulfur include rubber vulcanization, production of sulfuric acid, and manufacture of black gunpowder

1. Natural Gas Engineering Handbook, Dr. Boyun Guo and Dr. AIi Ghalambor
2. Natural Gas, by Primož Potočnik.
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

What is LPG

Liquefied petroleum gas (LPG) includes propane, butane, butadiene, isopropane, propylene, and vinyl chloride monomer, which are all by-products of the production of oil and natural gas. LPGs have a variety of uses including as a cooking/heating fuel, refinery feedstock, automotive power, and numerous other plastics and chemicals applications.
another definition of LPG is that LPG is a mixture of commercial butane and commercial propane having both saturated and unsaturated hydrocarbons. LPG marketed in
India shall be governed by Indian Standard Code IS-4576 (Refer Table 1.0) and the test methods by IS-1448.

The Chemistry of LPG


Atoms of hydrogen (H) and carbon (C) combine to form hydrocarbon molecules which can be made up of different numbers of hydrogen and carbon atoms, hence the term
A molecule containing three carbon atoms and eight hydrogen atoms is called propane.

In a like manner, four carbon atoms bonded to 10 hydrogen atoms forms butane:


There are two possible configurations for the butane molecule. The above arrangement consists of a straight C-chain and is called normal butane or n-butane. If the C-chain is branched, it is called iso-butane. Such a re-arrangement of the atoms is known as isomerisation and has no significant effect on the fuel properties.
Hydrocarbons with single carbon bonds are known as saturated hydrocarbons while those with double or triple bonds are unsaturated hydrocarbons. Examples of saturated
hydrocarbons are methane (CH2), ethane (C2H6), propane (C3H8) and butane (C4H10). Unsaturated hydrocarbons include ethylene (C2H4), propylene (C3H6), butylene (C4H8)
and acetylene (C2H2).

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LPG Density:
LPG at atmospheric pressure and temperature is a gas which is 1.5 to 2.0 times heavier than air. It is readily liquefied under moderate pressures. The density of the liquid is approximately half that of water and ranges from 0.525 to 0.580 @ 15 deg. C.
Since LPG vapour is heavier than air, it would normally settle down at ground level/ low lying places, and accumulate in depressions.

 Calorific Value (CV) :
All substances which burn generate energy in the form of heat, which varies in quantity with the nature of the substance. The total amount of heat liberated by burning a substance is known as its Calorific Value or CV. It is usually expressed in megajoules per kg (MJ/kg). For LPG, it is 49,6 MJ/kg.

 Vapor Pressure :
The pressure inside a LPG storage vessel/ cylinder will be equal to the vapour pressure corresponding to the temperature of LPG in the storage vessel. The vapour pressure is dependent on temperature as well as on the ratio of mixture of hydrocarbons. At liquid full condition any further expansion of the liquid, the cylinder pressure will rise by
approx. 14 to 15 kg./ for each degree centigrade. This clearly explains the hazardous situation that could arise due to overfilling of cylinders.

Thermal rate of expansion (expansion and contraction)
The thermal rate of expansion of liquid LPG is about 10 times that of water and since liquids can not be compressed, it is probably the most important property of LPG affecting the way the gas is stored, handled and filled. Storage tanks and portable cylinders filled to allow for an ullage space in the vessel and cylinders must never be filled to more than about 85% of the internal volume.
When the valve of an LPG is opened, the pressure inside the cylinder is reduced and the liquid starts to vaporise (boil) at lower pressure. This vaporisation of the gas causes cooling to occur and the temperature of the gas will decrease. If the gas off-take rate is too high, the gas temperature will decrease to below 0ºC and ice will start to form on the  lower outside wall of the cylinder. Because LPG contains propane and butane, with boiling points of –42,1ºC and – 0,5ºC respectively, the mixture begins to separate – propane continues to boil off while the butane remains in liquid form at temperatures below its boiling point of –0,5ºC. To avoid this situation, vaporiser units are used for LPG or pure
propane can be used instead of Handigas (butane/propane mixture). It should be noted that low winter temperatures will aggravate this situation.

 Flammability :
LPG has an explosive range of 1.8% to 9.5% volume of gas in air. This is considerably narrower than other common gaseous fuels. This gives an indication of hazard of LPG vapour accumulated in low lying area in the eventuality of the leakage or spillage.
The auto-ignition temperature of LPG is around 410-580 deg. C and hence it will not ignite on its own at normal temperature.
Entrapped air in the vapour is hazardous in an unpurged vessel/ cylinder during pumping/ filling-in operation. In view of this it is not advisable to use air pressure to unload LPG cargoes or tankers.

 Combustion :
The combustion reaction of LPG increases the volume of products in addition to the generation of heat. LPG requires upto 50 times its own volume of air for complete
combustion . Thus it is essential that adequate ventilation is provided when LPG is burnt in enclosed spaces otherwise asphyxiation due to depletion of oxygen apart from the formation of carbon-dioxide can occur.

LPG has only a very faint smell, and consequently, it is necessary to add some odourant, so that any escaping gas can easily be detected.
Ethyl Mercaptan is normally used as stenching agent for this purpose. The amount to be added should be sufficient to allow detection in atmosphere 1/5 of lower limit of
flammability or odour level 2 as per IS : 4576.

LPG is colourless both in liquid and vapour phase. During leakage the vapourisation of liquid cools the atmosphere and condenses the water vapour contained in them to form a whitish fog which may make it possible to see an escape of LPG.

LPG even though slightly toxic, is not poisonous in vapour phase, but can, however, suffocate when in large concentrations due to the fact that it displaces oxygen. In view of
this the vapour posses mild anaesthetic properties.