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Dehydration with refrigeration and hydrate suppression

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The refrigeration process is used in gas plants to remove heat from certain process streams. Refrigeration in natural gas treating is a process that serves a dual dewpoint control function—namely, it is used to meet the hydrocarbon dewpoint as well as the water dewpoint specification for residue or sales gas.

Dewpoint control by refrigeration

The temperature to which the gas is cooled depends first on meeting these dewpoint specifications. This is the minimum cooling requirement. Cooling the gas to lower temperatures than the minimum temperature for dewpoint control has to be justified by the economics of liquefied petroleum gas (LPG) recovery. This requires a cost analysis of the value of additional LPG recovery versus increased capital and operating costs. Additional recovery of LPG is achieved by either of the following methods:

  • chilling the gas to colder temperatures, such as –20 to –30°F
  • contacting the gas stream with lean oil in an absorption tower

Refrigeration is basically pumping heat from one medium to another. Heat by itself can only flow from a higher temperature medium to a lower temperature medium. Thus, refrigeration is a process that provides the cooling medium to which the gas is exposed. Refrigeration systems generally operate trouble free but can drop in efficiency, which requires investigation.[1]

Fig. 1 shows the typical refrigeration equipment for natural gas cooling. The heat exchanger cools the incoming gas to the refrigeration unit by exchanging heat with the cold gas, which has been chilled to the design cold temperature in the propane chiller.

Because the gas entering the refrigeration unit is normally saturated with water vapor and the temperature to which the gas is cooled is substantially below the hydrate point of the gas, some means of preventing hydrate formation must be instituted. The formation temperature of hydrates at a given pressure can be suppressed by the addition of chemicals, such as methanol or glycol. In conventional refrigeration units, the common chemical used for hydrate suppression in the process gas is monoethylene glycol, usually referred to as:

  • ethylene glycol (EG)
  • glycol


Glycol must be added to the natural gas being cooled at two points:

  • the inlet to the gas/gas heat exchanger
  • the inlet to the propane chiller

It is important to evenly distribute the glycol in the gas stream so that all gas is protected from freezing. This requires spraying the regenerated glycol evenly on to the tube sheet in these two vessels so that some glycol flows through each tube with the gas.

Propane, or some other refrigerant, boils in the chiller at a very low, controlled temperature, removing heat from the gas stream, thereby condensing a portion of the gas. The cold gas, condensate, and glycol flow from the chiller to a three-phase separator. The condensate goes to a fractionation unit. The gas is sufficiently cooled so it meets both the hydrocarbon and water dewpoints. It exchanges heat with the incoming gas to the refrigeration process.

The rich glycol is separated from the hydrocarbon gas stream in a three-phase separator and is routed to a regenerator. The concentration of the regenerated glycol is usually on the order of 75 to 80% glycol, with the balance being water. Sufficient glycol is injected at the two injection points to result in a mixture of water and glycol to depress the hydrate temperature to the required level, which for design purposes is the refrigerant boiling temperature.

The amount of glycol to be injected requires a determination of the hydrate temperature depression and a calculation of the rich glycol concentration by the Hammerschmidt equation.

The refrigeration effect is brought about by the vaporization of a refrigerant, such as propane, in the chiller. Propane is suited for this application, as it boils at temperatures near and below ambient temperatures. The vaporization of propane or boiling requires heat to effect the phase change from liquid to vapor—namely the latent heat of vaporization. By controlling the pressure at which the boiling of the propane takes place, the desired refrigeration temperature, down to about –40°F, is achieved.

The IFPEXOL process

By using glycol to prevent hydrates from forming in the refrigeration process, a glycol regeneration process step must be incorporated in the overall equipment scheme, as shown in Fig. 1. This includes an additional capital and operating cost burden to the refrigeration process. This cost burden can perhaps be somewhat reduced by using a relatively new innovation called the IFPEXOL process, which is illustrated in Fig. 2.

In the IFPEXOL process, the prevention of hydrates in the heat exchanger and chiller is achieved by the addition of methanol to the natural gas stream being cooled.[2] Normally, the methanol is recovered by a distillation process. However, the separation of methanol from water is somewhat difficult. In the IFPEXOL process, an innovative step is used that recovers most of the methanol for hydrate suppression without regeneration.

As seen in Fig. 2, the inlet gas stream is split into two streams. One portion of the inlet stream is contacted countercurrently with the rich methanol-water solution pumped to a small contactor from the cold separator. Because the gas stream is already saturated with water, it does not pick up any additional water. However, it contains no methanol at the inlet to this contactor. As the gas is in intimate contact with the methanol/water solution, most of the methanol leaves the water and enters the relatively warm hydrocarbon gas phase. This conserves most of the injected methanol. This gas stream joins the other stream before entering the gas/gas heat exchanger. Additional methanol is injected into this stream as required to depress the hydrate temperature of the process gas in the chiller to the boiling temperature of the propane. Because the methanol is contained in the vapor phase, the distribution of liquid methanol onto the tube sheet is not important, as is the case with glycol injection. As the gas cools inside the heat exchanger and chiller tubes, methanol condenses with the water and prevents the formation of hydrates.

Methanol loss

Methanol losses occur from the exiting chilled gas as well as in solution in the condensed hydrocarbon liquids. Recovery of the methanol in the liquid hydrocarbons is achieved with a water wash system.[3] Advantages of the IFPEXOL process are simpler process equipment and operation, as compared with glycol injection and regeneration. Furthermore, as discussed earlier, glycol absorbs some hydrocarbons, including the BTEX compounds, which are released into the atmosphere upon the regeneration of the glycol. Extra steps must be taken to avoid the release of the compounds into the atmosphere. In the IFPEXOL process, there are no emissions into the atmosphere. The main drawback to this process is the continuous loss of methanol, which has to be continuously made up from fresh supply. The IFPEXOL process is also suited for offshore operations where mass and space are limited.

Natural gas liquids (NGL) extraction methods

Lean oil absorption

Hydrocarbon liquids can be extracted from natural gas by contacting the gas with a light oil of uniform molecular weight. The fraction of each compound going into solution in the oil increases with decreasing volatility of the compound at the absorber pressure and temperature. Thus, while perhaps only a small percentage of the methane in the gas might go into solution, over 50% of propane, perhaps over 80% of butane, and so on, goes into solution in the oil. The lighter components, methane and ethane, are then rejected in the regeneration process of the oil, thereby capturing the absorbed propane and heavier compounds upon regeneration of the oil.

A simple lean oil absorption process is illustrated schematically in Fig. 3. The rich gas enters the absorption tower near the bottom and flows upward through the tower, which contains trays or packing. As the gas flows upward in the tower, it is in intimate contact with the oil, which enters the tower near the top. When the gas leaves the tower at the top, it has been stripped of most of the heavier compounds. The rich oil is then flowed to the stripping section, where the oil is heated to release the absorbed hydrocarbons. The vapors leaving the top of the stripper are cooled, condensing most of the propane and heavier hydrocarbons. The vapors from the reflux separator are compressed and recycled to the rich gas or to the sales gas.

Simple lean oil absorption processes operate at ambient temperatures. More complex lean oil absorption processes can be designed and operated at lower than ambient temperature. By contacting the chilled gas from a refrigeration unit in an absorber with cooled absorption oil, more of the components in the gas go into solution than in a process operated at ambient temperatures. The rich oil leaves the bottom of the tower through a level control valve, exchanges heat with the regenerated lean oil stream, and enters a rich oil flash tank, operating at about half the pressure of the absorption tower. Large amounts of the absorbed lighter compounds, such as methane and ethane, flash off and are routed to recompression. In recovery facilities for propane and heavier hydrocarbons, the oil then enters a deethanizer column, where the balance of the absorbed methane and ethane are rejected. These gases are flowed to a presaturator vessel and then to a recompressor, where they are joined with the main treated gas stream. From the deethanizer tower, the lean oil is flowed to the still, where the separation of the oil and the balance of the absorbed compounds takes place. Upon regeneration, the lean oil flows through heat exchangers and a cooler to a presaturator vessel where it becomes partially saturated with methane and ethane. It is then pumped back to the high pressure absorber. Another cooling step is included to ensure that the lean oil temperature is no higher than the gas temperature to maximize absorption. The design of the overall process is now performed by computer, as the material and heat balance calculations are quite intricate and require rigorous mathematical treatment.

The turbo-expander process

The turbo-expander process for treating natural gas streams for high liquids recovery was developed in the early 1960s. Its main application was to improve the recovery of ethane from natural gas, as ethane is an important feed stock for the petrochemical industry. The process achieves very low temperatures and, therefore, liquefies a substantial portion of the ethane and heavier compounds in natural gas. The various fractions of the liquid stream are recovered by distillation.

The turbo expander removes energy from the near isentropic expansion of a gas stream, which results in a drop in pressure and temperature by extracting useful mechanical energy. By using an expander to recover energy from the high pressure gas:

  • the refrigeration effect is enhanced
  • the reduction in gas temperature is greater than can be obtained by simple isenthalpic (Joule-Thomson) expansion across a valve

Turbo-expander process configurations can vary greatly. They all incorporate various heat exchangers. The gas entering the turbo-expander process must be dehydrated upstream of the plant to a very low water content so that no hydrates form when the low temperatures are reached by the gas being processed. This usually requires a glycol dehydration unit for removing most of the water, followed by a molecular sieve unit to remove virtually all of the water from the feed gas. Gas pretreatment can also include CO2 and H2S removal.

Fig. 4 is an illustration of a relatively simple turbo-expander facility. There are many other arrangements possible, depending on the gas composition and the desired level of liquids recovery. Whether the turbo expander is likely the best choice for recovering ethane and heavier hydrocarbons from natural gas requires considerable analysis.[4][5]

Gas preconditioning

Expander processes for NGL recovery can chill the gas as low as –160°F. To dry the gas to this low a water dewpoint temperature requires the use of molecular sieves in drying towers as illustrated in Fig. 5. A common class of molecular sieve used for deep drying has a pore opening of 4 Å. Instead of drying the gas with molecular sieves, it is also possible to prevent potential freezing problems with the addition of minor amounts of methanol into the gas stream upstream of the chilling section.[6]

Turbo-expander design

The design of a turbo-expander unit involves detailed heat and material balances and many flash calculations. Such design calculations are performed by computer.

Joule-Thomson expansion

Cooling of natural gas can also be achieved by expanding high pressure gas to a lower pressure across an expansion valve.[7] This is a constant enthalpy process, and the amount of the temperature reduction depends on the pressure ratio of initial pressure divided by the final pressure, the absolute pressures and the starting temperature, as well as the gas composition. This is a practical method to cool gas and extract hydrocarbon liquids if there is a lot of “free” pressure available. It is also a more practical process than the turbo-expander process for low gas rates, especially if the gas rates fluctuate.

Fig. 6 is a schematic drawing of a typical Joule-Thomson expansion process. The main process equipment is the expansion valve or choke. The high-pressure gas enters through an inlet separator, which removes the condensed water and any liquid hydrocarbons. The gas streams out of the separator, then flows through a heat exchanger, exchanging heat with the cooled, low-pressure gas. Some water and perhaps some hydrocarbon will condense in the heat exchanger from the high-pressure gas stream. The high-pressure gas then flows through the expansion valve, which drops the pressure of the gas to the design pressure. Simultaneously, a reduction in temperature occurs. Depending on the gas composition and the pressure and temperature of the gas mixture, a certain amount of the mixture will condense and form a liquid hydrocarbon stream. Water will also condense to the equilibrium water content of the gas at the final pressure and temperature.

If the resulting temperature of the gas after the heat exchanger or upon expansion is below the hydrate temperature at the operating pressure, hydrates form unless the gas has been dehydrated. To avoid the formation of hydrates in water saturated gas, a chemical hydrate inhibitor is added to the gas stream ahead of the heat exchanger. The chemical usually used to depress the hydrate temperature is ethylene glycol, but diethylene glycol can also be used. Fig. 6 shows the flow of the glycol and includes a reconcentration step. Ethylene glycol is usually regenerated to a lean concentration of about 75 or 80% by weight and is circulated at a rate such that the resulting final glycol concentration is sufficient to depress the hydrate forming temperature to about 5°F below the hydrate temperature of the gas at the final pressure. The required lean glycol circulation rate is determined by the Hammerschmidt equation and depends on:

  • the water content of the gas
  • the concentration of the lean glycol
  • the necessary hydrate temperature depression

A bypass line around the heat exchanger on the cold gas out of the low temperature separator allows for the control of the degree of cooling of the process gas. To aid the separation between the cold condensate and glycol, a heater can be included in the equipment. After heating, the liquids are flowed into a three-phase separator, where the small amount of gas, the condensate, and the rich glycol are separated. The glycol is then reconcentrated with a conventional reboiler and still and is re-injected into the process gas stream.

Membrane processing for CO2 removal

When natural gas contains a high concentration of CO2 , the options for reducing the CO2 concentration to acceptable levels are either:

  • to use a regenerative solvent, such as an amine, potassium carbonate, or Selexol
  • to install a membrane separation process

Separation by means of membrane technology makes use of thin layers of polymeric material.[8] This polymeric material can be manufactured in two main types—porous and nonporous. The porous membrane makes use of differences in diffusion rates and acts like a sieve in separating molecules based on relative size. The main application of this type of material is the separation of small molecules such as hydrogen or helium from gas mixtures. The nonporous membrane promotes the separation by dissolving some compounds in the polymeric material and allowing these compounds to diffuse through the material more rapidly than hydrocarbon compounds, which do not dissolve but diffuse through the material. In natural gas separation, the nonporous material is used. The compounds specifically found in natural gas, which have the ability to dissolve in the polymeric material, are the polar compounds:

  • CO2
  • H2S
  • H2O

Hydrocarbons also diffuse through such membranes, but at a much lower rate.

The membrane material is manufactured as a very thin film, which has no strength. It is supported in applications by a porous layer, through which the gas molecules that have passed through the membrane (permeate) flow to the low pressure side. In one type of application, the membrane and the porous permeate spacer are spirally wound around a perforated tube. A third layer is included in such construction, which is a porous feed spacer. The high-pressure gas (feed) flows through the feed spacer and is in contact with the membrane. The permeate dissolves in and/or diffuses through the membrane layer into the permeate spacer. It then flows through the permeate spacer into the perforations in the steel tube, which forms the shaft of the spirally wound layers. The high-pressure gas passes through the feed spacer to the other end, with very little pressure drop.

In the natural gas industry, membrane technology is used mainly to reduce the concentration of CO2 from very high concentrations to acceptable levels, such as less than 2%.[9] If H2S is present, most of the H2S will separate. Because the sales gas specification for H2S can be as low as 4 ppm, membrane separation is usually not sufficient to meet the specification for this compound. This process may meet the stringent specification for H2S only if the concentration of H2S is very low to begin with, such as perhaps 50 ppm or less.

While CO2 is the main target for removal in natural gas processing with membranes, hydrocarbons also diffuse through the membranes. Because hydrocarbons are the valuable sales products, various process schemes are used to minimize the loss of hydrocarbons. The amount of hydrocarbon in the permeate after one pass through a permeable membrane facility depends on:

  • gas composition
  • system pressures (high and low)
  • gas flow rate
  • total surface area of membrane exposed to high-pressure gas

While the permeation and potential loss of hydrocarbon is a disadvantage of membrane separation processes, there are many advantages over the alternatives for reducing CO2 content. The advantages are:

  • low capital investment, as compared with regenerative solvent processes
  • ease of installation
  • simple operation, as the feed gas simply flows through the facility with little pressure loss
  • low weight and space requirements, which are important in offshore installations
  • low environmental impact
  • no utilities requirement

The loss of hydrocarbon in the permeate can be reduced by compressing the permeate to a high pressure and subjecting it to a second stage of separation with a membrane.[10] The resulting high-pressure stream from the second stage is then added to the high-pressure feed gas to the first stage, as shown in Fig. 7. Other permeable membrane schemes use the membrane process for bulk removal of CO2, followed by an amine system for final cleanup.

In treating rich gas with membranes for CO2 removal, it is necessary to preheat the feed stream so that no condensation occurs because of the high-pressure drop through the membrane. The service life of the membrane material is critical to evaluating process economics relative to other methods. Service life depends on:

  • feed quality (e.g., liquid carryover, solids content, etc.)
  • the care with which the system is operated

In the absence of other data from similar operations, a service life of 3 to 5 years should be considered.

The analysis and design of permeable membrane systems can be investigated with a computer program available at a nominal cost from the Gas Research Institute of Chicago, now called the Gas Technology Institute (GTI). Their program MemCalc™ is a PC-based program that simulates the performance of membranes for removing CO2 from natural gas. The program has been evaluated by several operators of membrane process facilities.


  1. Vargas, K.J. 1982. Troubleshooting Compression Refrigeration Systems. Chem. Eng. (22 March): 137.
  2. Minkkinen, A. et al. 1992. Methanol Gas-Treating Scheme Offers Economics, Versatility. Oil & Gas J. (1 June): 65.
  3. Hampton, P. et al. 2001. Liquid-Liquid Separation Technology Improves IFPEXOL Process Economics. Oil & Gas J. (16 April): 54.
  4. Morgan, J.D. 1976. How Externally Refrigerated and Expander Processes Compare For High Ethane Recovery. Oil & Gas J. (3 May): 230.
  5. Dyck, P. and Henderson, D. 1978. Expander Wins For Gas Dewpoint Control. Oil & Gas J. (24 April): 86.
  6. Nielsen, R.B. and Bucklin, R.W. 1983. Why Not Use Methanol for Hydrate Control? Hydrocarbon Processing (April): 71.
  7. Crum, F.S. 1981. There Is a Place For J-T Plants In LPG Recovery. Oil & Gas J. (10 August): 132.
  8. Koros, W.J. 1995. Membranes: Learning a Lesson from Nature. Chemical Engineering Progress (October): 68.
  9. Lee, A.L., Feldkirchen, H.L., and Gomez, J. 1994. Membrane Process for CO2 Removal Tested At Texas Plant. Oil & Gas J. (31 January): 90.
  10. Cook, P.J. and Losin, M.S. 1995. Membranes Provide Cost-Effective Natural Gas Processing. Hydrocarbon Processing (April): 79.

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See also

PEH:Gas Treating and Processing

Gas Treating and Processing

Dehydration with deliquescing dessicants

Dehydration with glycol

Dry dessicant dehydration

Sour gas sweetening