Operations for Gas Handling (Conditioning), Treatment, and Separation of NGL


Natural gas associated with oil production or produced from gas fields (free) generally contains undesirable components such as H2S, CO,, N2, and water vapor. In this chapter, natural gas conditioning is detailed. This implies the removal of such undesirable components before the gas can be sold in the market. Specifically, the gas contents of H2S, CO,, and water vapor must be removed or reduced to acceptable concentrations. N2, on the other hand, may be removed if it is justifiable. Gas compression is usually needed after these treatment processes. Once the gas is treated, then the recovery of natural gas liquid (NGL) becomes a feasible and a profitable avenue.

In this chapter, for convenience, a system involving field treatment of a gas plant could be divided into two main stages, as shown in Figure 18.1.

The gas treatment operations carried out in stage I involve the removal of gas contaminants (acidic gases), followed by the separation of water vapor (dehydration). Gas processing, stage II, on the other hand, comprises two operations: NGL recovery and separation from the bulk of gas and its subsequent fractionation into desired products. The purpose of a fractionator’s facility is simply to produce individual finished streams needed for market sales.

Gas field processing in general is carried out for two main objectives:

  • • The necessity to remove impurities from the gas.
  • • The desirability to increase liquid recovery above that obtained by conventional gas processing.
  • 18.1.1 Background

In its broad scope, gas field processing (G.F.P.) includes dehydration, acidic gas removal (H2S and C02), and the separation and fractionation of liquid hydrocarbons (known as NGL). Sweetening of natural gas almost always precedes dehydration

Division of gas system into two stages

FIGURE 18.1 Division of gas system into two stages: gas treatment (conditioning) and gas processing.

and other gas plant processes carried out for the separation of NGL. Dehydration, on the other hand, is usually required before the gas can be sold for pipeline marketing and it is a necessary step in the recovery of NGL from natural gas.

18.1.2 Effect of Impurities (Water Vapor, H2S/C02), and Liquid Hydrocarbons Found in Natural Gas

The effect each of these components has on the gas industry, as end user, is briefly outlined:

i. Water Vapor

It is a common impurity. It is not objectionable as such. If it condenses to liquid, it accelerates corrosion in the presence of H2S gas. In case it leads to the formation of solid hydrates (made up of water and hydrocarbons), it will plug valves and fittings in the pipe.

ii. ELS/CO,

Both gases are harmful, especially H2S, which is toxic if burned to give S02 and SO,, which are nuisance to consumers. Both gases are corrosive in the presence of water. In addition. C02 contributes a lower heating value to the gas.

iii. Liquid Hydrocarbons

Their presence is undesirable in the gas used as a fuel. The liquid form is objectionable for burners designed for gas fuels. In case of pipelines, it is a serious problem to handle two-phase flow: gas and liquid.

  • 18.2.1 Selection of Gas Sweetening Process

There are many key parameters to be considered in the selection of a given sweetening process. These include the following:

  • • Type of impurities to be removed (H,S and mercaptans)
  • • Inlet and outlet acid gas concentrations
  • • Gas flow rate, temperature, and pressure
  • • Feasibility of sulfur recovery
  • • Acid gas selectivity required
  • • Presence of heavy aromatic in the gas
  • • Well location
  • • Environmental consideration
  • • Relative economics

Generic and specialty solvents are being divided into three different categories to achieve sales gas specifications:

  • • Chemical solvents
  • • Physical solvents
  • • Physical-Chemical (hyprid) solvents

The selection of the proper gas sweetening process depends on the sulfur content in the feed and the desired product as illustrated in Figure 18.2. Several commercial processes are available and shown in the schematic flow sheet of Figure 18.3.

  • Acid Gas Concentration in Outlet Gas
  • 18.2.2 Amine Processes

Amine gas sweetening is a proven technology that removes H,S and CO, from natural gas and liquid hydrocarbon streams through absorption and chemical reaction. Aqueous solutions of alkanolamines are the most widely used for sweetening natural gas. Each of the amines offers distinct advantages to specific treating problems:

a. Monoethanolamine (MEA): it is used in low-pressure natural gas treatment applications requiring stringent outlet gas specifications.

Selection of gas sweetening processes

FIGURE 18.2 Selection of gas sweetening processes.

b. Methyl diethanolamine (MDEA): it has a higher affinity for H2S than C02, which allows some C02 “slip” while retaining H2S removal capabilities.

c. Diethanolamine (DEA): it is used in medium to high pressure treating and does not require reclaiming, as MEA and diglycolamine (DGA) systems do.

d. Formulated (specialty) solvent: a variety of blended or specialty solvents are available on the market.

A typical amine process is shown in Figure 18.4. The acid gas is fed into a scrubber to remove entrained water and liquid hydrocarbons. The gas then enters the bottom of absorption tower which is either a tray (for high flow rates) or packed

Classification of gas sweetening processes

FIGURE 18.3 Classification of gas sweetening processes.

(for lower flow rate). The sweet gas exits at the top of tower. The regenerated amine (lean amine) enters at the top of this tower and the two streams are contacted counter-currently. In this tower, CO, and H,S are absorbed with the chemical reaction into the amine phase. The exit amine solution, loaded with CO, and H,S, is called rich amine. This stream is flashed, filtered, and then fed to the top of a stripper to recover the amine, and acid gases (CO, and H,S) are stripped and

exit at the top of the tower. The refluxed water helps in steam stripping the rich amine solution. The regenerated amine (lean amine) is recycled back to the top of the absorption tower.


Natural gas usually contains significant quantities of water vapor. Changes in temperature and pressure condense this vapor altering the physical state from gas to liquid to solid. This water must be removed in order to protect the system from corrosion and hydrate formation. The wet inlet gas temperature and supply pressures are the most important factors in the accurate design of a gas dehydration system. Without this basic information the sizing of an adequate dehydrator is impossible.

Natural gas dehydration is defined as the process of removing water vapor from the gas stream to lower the dew point of the gas. There are three basic reasons for the dehydration process:

  • 1. To prevent hydrate formation: Hydrates are solids formed by the physical combination of water and other small molecules of hydrocarbons. They are icy hydrocarbon compounds of about 10% hydrocarbons and 90% water.
  • 2. To avoid corrosion problems: Corrosion often occurs when liquid water is present along with acidic gases, which tend to dissolve and disassociate in the water phase, forming acidic solutions.
  • 3. To avoid side reactions, foaming, or catalyst deactivation during downstream processing in many commercial hydrocarbon processes.
  • 18.3.1 Prediction of Hydrate Formation

Methods for determining the operating conditions leading to hydrate formation are very essentials in handling natural gas. In particular, we should be able to find:

  • 1. Hydrate formation temperature for a given pressure
  • 2. Hydrate formation pressure for a given temperature
  • 3. Amount of water vapor that saturates the gas at a given pressure and temperature (i.e., at the dew point)

At any specified pressure, the temperature at which the gas is saturated with water vapor is being defined as the “dew point”. Cooling of the gas in a flow line due to heat loss can cause the gas temperature to drop below the hydrate formation-temperature. Elaborate discussion of both approximate methods and analytical methods are presented by Abdel-Aal et al.

18.3.2 Methods Used to Inhibit Hydrate Formation

Hydrate formation in natural gas is promoted by high-pressure, low temperature conditions, and the presence of liquid water. Therefore, hydrates can be prevented by adopting one (or more than one) of the following procedures:

  • 1. Raising the system temperature and/or lowering the system pressure (tem- perature/pressure control).
  • 2. Injecting a chemical such as methanol or glycol to depress the freezing point of liquid water (chemical injection).
  • 3. Removing water vapor from the gas (liquid-water drop out); in other words depressing the dew point by dehydration.
  • 18.3.3 Dehydration Methods

The most common dehydration methods used for natural gas processing are the following:

  • 1. Absorption, using the liquid desiccants (e.g., glycols and methanol)
  • 2. Adsorption, using solid desiccants (e.g., alumina and silica gel)
  • 3. Cooling/condensation below the dew point, by expansion and/or refrigeration

This is in addition to the hydrate inhibition procedures described earlier.

Different dehydration methods are classified as shown in Figure 18.5

18.3.4 Dehydration Using Absorption System

The absorption process is shown schematically in Figure 18.6. The wet natural gas enters the absorption column (glycol contactor) near its bottom and flows

Glycol dehydration unit

FIGURE 18.6 Glycol dehydration unit.

upward through the bottom tray to the top tray and out at the top of the column. Usually six to eight trays are used. Lean (dry) glycol is fed at the top of the column and it flows down from tray to tray, absorbing water vapor from the natural gas. The rich (wet) glycol leaves from the bottom of the column to the glycol regeneration unit. The dry natural gas passes through mist mesh to the sales line. The rich glycol is preheated in heat exchangers, using the hot lean glycol, before it enters the still column of the glycol reboiler. This cools down the lean glycol to the desired temperature and saves the energy required for heating the rich glycol in the reboiler.

18.3.5 Dehydartion Using Adsorption (Solid-Bed Dehydration)

When very low dew points are required, solid-bed dehydration becomes the logical choice. It is based on fixed-bed adsorption of water vapor by a selected desiccant. A number of solid desiccants could be used such as silica gel, activated alumina, or molecular sieves. The selection of these solids depends on economics. The most important property is the capacity of the desiccant, which determines the loading design expressed as the percentage of water to be adsorbed by the bed. The capacity decreases as temperature increases. Figure 18.7 represents solid bed dehydration.

A solid desiccant unit for natural gas dehydration

FIGURE 18.7 A solid desiccant unit for natural gas dehydration.



Objective: To investigate the economics of utilizing natural gas as a fuel for heating crude oil.

Process: Natural gas is recovered from gas-oil separator plant (GOSP) using an absorber de-ethanizer system, along with an amine treating unit and a gas dryer to have available desulfurized gas that can be used or sold as a fuel gas.

Given: The total cost for the recovery of this gas is estimated to be $0.75/ MCF. It has been suggested to use this gas as a fuel for heating 5,000 bbl/day of 40° API crude oil from 80°F to 250°F.

Find: 1 [1] [2] [3]


The heat duty required is calculated using the well-known equation: Q = m Cp Д T

= 127.7 MM Btu/day

Assuming the heating value of the gas is 960 Btu/ft and the heat efficiency is 60%; then the fuel gas consumption will be 221,700 ft-7day.

The cost of using this fuel gas for heating = 2217000 ft3/day x $0.75/MCF

= $166.28/day

The cost of using the fuel oil for heating = [127.7 MM Btux$2.2/MM Btu]/0.6

= $468.23/day

A daily savings in the cost of fuel of about $300 is realized if the change to fuel gas takes place. One has to consider other economic factors in making this analysis. The capital cost involved in changing the burner system has to be considered.


MDEA has become the amine molecule chosen to remove H2S, C02, and other contaminants from hydrocarbon streams. Amine formulations based on MDEA can significantly reduce the costs of acid gas treating. Under the right circumstances, MDEA based solutions can boost plant capacity, lower energy requirements, or reduce the capital required.

The ultimate goal of amine sweetening is to produce specification quality product as economically as possible. Amine technology has produced selective absorbents which remove H2S in the presence of CO,. The use of selective amines results in:

Lower circulation rates.

• Reduction in reboiler sizes and duties, while meeting the H2S specification. Unfortunately, many operators now are exceeding the CO, specification in their sweet gas streams due to changes in inlet composition or increased throughput. Achieving specifications wfithin the constraints of the process equipment is most cost effective and desirable.

In general, if the objective is to slip as much CO, as possible, the engineer should consider using the most selective amine at the lowest concentration and circulation rate with the fewest number of equilibrium stages in the absorber to achieve the H,S specification. Cold absorber temperatures tend to increase the CO, slip and enhance H,S pickup. If the objective is to achieve a certain CO, concentration, then the problem is more complicated. Variables to consider include increasing the amine concentration and using mixtures of amines. How'ever, equipment size may have to be reevaluated. Increasing the lean amine temperature increases CO, pickup for the selective amines to a point. The maximum temperature depends on amine concentration, inlet gas composition, and loading. Higher lean amine temperature also increases water and amine losses and decreases H,S pickup.

Alternatively, solvents that are designed for CO, removal are also available. For example, DOW’s Specialty Amines cover the full range from the maximum CO, slip, to nearly complete CO, removal.



In order to exclude the costly DGA treatment of sour natural gas, the NCPO approach proposed by Abdel-Aal and Shalabi is recommended to produce synthesis gas from sour gas by direct partial oxidation, as illustrated in Figure 18.8.

Currently, synthesis gas is produced by steam reforming of sweet natural gas. This is a catalytic process in which the feed gas has to be sulfur free to avoid catalyst poisoning. As a result, acidic gas removal is a prerequisite for the steamreforming process as shown in Figure 18.9. H,S is separated from the natural gas by one of the physiochemical separation methods. The separation process is expensive and involves the use of amine solvents. The chemisorption of acidic gas into the solvents is followed by regeneration of these solvents. Although the

Current technology to produce synthesis gas from sour natural gas

FIGURE 18.9 Current technology to produce synthesis gas from sour natural gas.

bulk production of synthesis gas is done via catalyzed steam reforming of sweet natural gas, non-catalyzed partial oxidation of sour natural gas with appropriate conditions may prove to be more attractive.

Compare between the two systems: the current technology and the NCPO from the technical and economic point of views.


Natural gas procrssing comprises two consecutive operations: NGL recovery (extraction) and separation from the bulk of gas followed by subsequent fractionation into desired products. The purpose of a fractionator’s facility is simply to produce individual finished streams needed for market sales. Fractionation facilities play a significant role in gas plants.

Case study involving the optimum recovery of butane using lean oil extraction is presented.

Natural gas leaving the field can have several components which will require removal before the gas can be sold to a pipeline gas transmission company. All of the ELS and most of the water vapor, C02, and N2 must be removed from the gas. Gas compression is often required during these various processing steps.

The condensable hydrocarbons heavier than methane, which are recovered from natural gas, are called NGLs. Usually associated gas produces higher percentage of NGLs. It is generally desirable to recover NGL present in the gas in appreciable quantities. This normally includes the hydrocarbons knowm as C3+. In some cases, ethane C2 could be separated and sold as a petrochemical feed stock. NGL recovery is the first operation in gas processing, as explained earlier. To recover and separate NGL from a bulk of a gas stream would require a change in phase; that is, a new phase has to be developed for separation to take place by using one of the following: [4]

• A mass-separating agent; examples are adsorption and absorption (using selective hydrocarbons, 100-180 molecular weight).

The second operation is concerned w'ith the fractionation of NGL product into specific cuts such as liquefied petroleum gas (LPG) (C,/C4) and natural gasoline. It should be pointed out that the fact that all of the field processes do not occur at or in the vicinity of the production operation does not change the plan of the system of gas processing and separation.

The principal market for natural gas is achieved via transmission lines, which distribute it to different consuming centers, such as industrial, commercial, and domestic. Field processing operations are thus enforced to treat the natural gas in order to meet the requirements and specifications set by the gas transmission companies. The main objective is to simply obtain the natural gas as a main product free from impurities. In addition, it should be recognized that field processing units are economically justified by the increased liquid product (NGL) recovery above that obtained by conventional separation.

Description of a typical natural gas processing plant is shown in Figure 18.10.

Description of a typical natural gas processing plant. (Source

FIGURE 18.10 Description of a typical natural gas processing plant. (Source: Wikipedia the free encyclopedia)

  • 18.4.2 Recovery and Separation of NGL
  • Options of Phase Change

To recover and separate NGL from a bulk of gas stream, a change in phase has to take place. In other words, a new phase has to be developed for separation to occur. Two distinctive options are in practice depending on using Energy Separating Agent (ESA) or Mass Separating Agent (MSA).

i. Energy Separating Agent

The distillation process best illustrates a change in phase using ESA. To separate, for example, a mixture of alcohol and water heat is applied. A vapor phase is formed in which alcohol is more concentrated, and then separated by condensation. This case of separation is expressed as follows:

For the case of NGL separation and recovery in a gas plant, removing heat (by refrigeration) on the other hand, will allow heavier components to condense; hence, a liquid phase is formed. This case is represented as follows:

Partial liquefaction is carried out for a specific cut, whereas total liquefaction is done for the whole gas stream.

ii. Mass Separating Agent

To separate NGL, a new phase is developed by using either a solid material in contact with the gas stream (adsorption) or a liquid in contact with the gas (absorption).

18.4.3 Parameters Controlling NGL Separation

A change in phase for NGL recovery and separation always involves control of one or more of the following three parameters:

  • 1. Operating pressure, P
  • 2. Operating temperature, T
  • 3. System composition or concentration, x and у

To obtain the right quantities of specific NGL constituents, a control of the relevant parameters has to be carried out.

First: For separation using ESA, pressure is maintained by direct control. Temperature, on the other hand, is reduced by refrigeration using one of the following techniques:

a. Compression refrigeration

b. Cryogenic separation; expansion across a turbine

c. Cryogenic separation; expansion across a valve

In cryogenic cooling process to recover NGL, gas is cooled to very low temperature (-100 to -120°F) by adiabatic expansion of the gas mixture by turbo expanders. The water and acid gases are removed before chilling the gas to avoid ice formation. After chilling, the gas is sent to demethanizer to separate methane from NGL.

Second: For separation using MSA. a control in the composition or the concentration of the hydrocarbons to be recovered (NGL); x and у are obtained by using adsorption or absorption methods.

Adsorption provides a new surface area, through the solid material, which entrains or “adsorbs” the components to be recovered and separated as NGL. Thus, the components desired as liquid are deposited on the surface of the selected solid; then regenerated off in a high concentration; hence, their condensation efficiency is enhanced. About 10-15% of the feed is recovered as liquid. Adsorption is defined as a concentration (or composition) control process that precedes condensation. Therefore, refrigeration methods may be coupled with adsorption to bring in condensation and liquid recovery.

Absorption, on the other hand, presents a similar function of providing a surface or “contact” area of liquid-gas interface. The efficiency of condensation, hence NGL recovery, is a function of P, T. gas, and oil flow rates, and contact time. Again, absorption could be coupled with refrigeration to enhance condensation.

In lean oil extraction method, the treated gas is cooled by heat exchange with liquid propane and then washed with a cold hydrocarbon liquid, which dissolves most of the condensable hydrocarbons. The uncondensed gas is dry natural gas and contains mainly methane with small amounts of ethane and other heavier hydrocarbons. The condensed hydrocarbons or NGLs are stripped from the rich solvent, which is recycled back to the process.

To summarize the above, a proper design of a system implies the use of the optimum levels of all operating factors plus the availability of sufficient area of contact for mass and heat transfer between phases.

18.4.4 Fractionation of NGL

Due to their added value, heavier hydrocarbons are often extracted from natural gas and fractionated by using several tailor made processing steps. In general, and in gas plants in particular, fractionating plants have common operating goals: [5]

As far as the tasks for system design of a fractionating facility, these goals are as follows:

  • • Fundamental knowledge on the process or processes selected to carry out the separation; in particular, distillation.
  • • Guidelines on the order of sequence of separation (i.e., synthesis of separation sequences).

NGL are normally fractionated into the following three streams:

  • 1. An ethane rich stream used for producing ethylene
  • 2. LPG. It is propane-butane mixture and is important feedstock for olefin plants
  • 3. Natural gasoline

NGLs may contain significant amounts of cyclohexane.

18.4.5 Shale Gas

Conventional gas reservoirs are areas where gas has been "trapped”. After natural gas is formed, the earth’s pressure often pushes the gas upward through tiny holes and fractures in rock until it reaches a layer of impermeable rock where the gas becomes trapped. This gas is relatively easy to extract, as it will naturally flow out of the reservoir when a well is drilled. Unconventional gas occurs in formations where the permeability is so low that gas cannot easily flow (e.g., tight sands), or where the gas is tightly adsorbed (attached) to the rock (e.g., coalbed methane). Gas shales often include both scenarios—the fine-grained rock has low permeability; and, gas is adsorbed to clay particles. The pore spaces in shales are typically not large enough for even tiny methane molecules to flow through easily. Consequently, gas production in commercial quantities requires fractures to provide permeability.

Shale gas is defined as natural gas from shale formations, i.e., natural gas trapped within shale (fine grained sedimentary rocks) formations. Shale has low matrix permeability to allow significant fluid flow to well bore; therefore, commercial production requires mechanically increasing permeability. Shale gas reserves are known for long but natural fracture technology used earlier was uneconomical to produce shale gas. The recent developments in horizontal drilling and hydraulic fracturing (called fracking) made it viable. Mitchell energy, a Texas gas company, first achieved economical shale gas fracture in 1998. Shale gas is currently under evolutionary stage and so far is largely confined to North America. The complete technology and economic factors are yet to get matured. Several high profile shale gas drilling efforts in Europe have already failed.

Shale gas costs more to produce than natural gas (NG) from conventional wells. The high cost is mainly due to expense of massive hydraulic fracturing treatments required to produce shale gas and horizontal drilling. Drilling a vertical and horizontal well cost about $1 million and $4 million respectively. The huge requirement of water for hydraulic fracking and then the waste water treatment are major cost inhibitors. Overall, addressing environmental concerns associated with shale gas hugely adds up to its cost. The shale gas production may be feasible only in those regions where energy/NG prices are high. The shale gas production cost in the USA is estimated to be between $4 and $7 per MMBtu but it’s termed as “foggy economics” since all factors not considered. Earlier it was thought that shale gas will produce less green-house gases but scientists recently concluded otherwise and opine that it will accelerate global warming. Shale gas production requires large amounts of water and chemicals added to it to facilitate underground fracturing process that releases gas. A maximum of 70% of used water is recovered and rest remains underground which can lead to contamination. Significant use of water for shale gas production may affect the availability of water for other uses and can affect aquatic habitat. The treatment of large amount of recovered waste water before reuse or disposal is an important and challenging issue. There are some evidences of groundwater contamination in areas of fracking. The environmental impacts of shale gas production are therefore challenging but still considered to be manageable.

So far shale gas is mostly confined to North America. There is little drilling progress in China. Australia, and Poland. In other countries, it’s still in pilot stages. Canada has huge shale gas reserves but exploration is restricted due to strict environmental regulations and related issues. In the USA, BP predicted NG self-sufficiency and NG share of total energy consumption to double to 40% with 4% anticipated annual growth in shale gas production by 2030. The Energy Information Administration (ElA) however slashed BP shale gas forecast reserves by 41% in Jan 2012. The energy demand (dominated by oil) will still grow in next two decades by 39%, but most of the growth in demand will be from Asian countries, especially China and India. In Saudi Arabia, evaluation of shale gas reserves is in progress and production may start in 2020, but low NG price remains a major issue in developing the prospects.



Associated natural gas is passed through an absorption unit to recover heavier hydrocarbons (butane plus), which can be sold for a value of $7.5/gal. Calculations show that the minimum total cost for the recovery and the extraction of the butanes in the plant is estimated to be $1,2/gal of butane recovered. Other additional costs for processing the absorbing oil used in the recovery are estimated to be $27/million gal of the lean oil circulated.

The engineering group in the plant developed the following empirical relationship for the rate (R) of the absorber oil used as a function of the rate of butane produced (P):

  • 1. Compute the optimum butane recovery, P„, and the optimum circulating oil rate, R„, applicable to this plant.
  • 2. What is the value of P at which the process of recovery breaks even?


d/dp (profit) = 6.3 - 1.3 (0.108) P(U; setting this derivative equal to zero: At the break-even point, profit = 0


The tower must process a gas feed stream at affixed rate to remove a soluble gas component by absorption in a liquid phase. Here we have the two scenarios:

  • • Increasing the diameter of the tower, lowers the gas velocity in the bed, reducing the pressure drop, hence lowering the pumping costs of the feed gas. But a large diameter tower is more costly to construct.
  • • Choosing a smaller diameter will cause flooding inside the column to occur, and liquid is carried up the gas stream, making the tower inoperative.


Some balance must be reached between the pumping costs and the construction costs, in order to lower the total costs of operation. Also, it is not practical to construct a tower of extremely large diameter because of liquid distribution problems.

Apparently, there are constraints on the tower diameter. Solution is reached by optimization technique in order to minimize the total annual costs of operating the tower as a function of the tower diameter.

The total annual costs of operation = Capital cost of the tower, depreciated over the life time ($/year) + annual operating (pumping) costs ($/year).

  • [1] The cost of heating the crude oil using this gas.
  • [2] Compare it with the cost of heating using fuel oil at S2.2/MM Btu.
  • [3] Do you recommend change in operation to use the fuel gas as a heating fuel instead of using the fuel oil?
  • [4] An energy-separating agent; examples are refrigeration (cryogenic cooling)for partial or total liquefaction and fractionation.
  • [5] The production of on-specification products 2. The control of impurities in valuable products (either top or bottom) 3. The control in fuel consumption
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