In this “Tip of the Month”, we will focus on the question of: Which technology should you choose? The answer, of course, is “It depends.” It depends on what you are trying to accomplish, the constraints imposed on your system and the relative economics.

A Rule of Thumb is “Use MEG injection if you have to cool the gas for NGL recovery anyway.” Like all Rules of Thumb, there are exceptions. But let’s explore the basics of each technology.

Let’s begin by defining our terms. See Figure 1 for a typical mechanical refrigeration process used for hydrocarbon dew point control and moderate NGL recovery that uses MEG injection to prevent hydrate formation. Warm inlet gas is cross-exchanged with the cold dry sales gas and then flows to the gas chiller. To prevent hydrates from forming, MEG is injected in the tubes at the warm end of both exchangers. The temperature of the chiller is adjusted to condense liquids from the feed gas. The cold gas exiting the chiller together with the rich MEG solution and condensed hydrocarbons enters the cold three-phase separator. The rich MEG is sent to the regeneration section of the unit where the water is removed. The resulting lean MEG is sent back to the process.

Process Flow Diagram

Copyright © 2007 John M. Campbell and Company

Figure 1. Typical mechanical refrigeration plant with glycol injection system [1]

In this flow diagram, two things are taking place: temperature reduction of the process gas to condense both water and hydrocarbons; and, MEG injection and subsequent regeneration to prevent hydrates from forming. Inspection of Figure 1 reveals the majority of the equipment, including the refrigeration compressors, etc. which are not shown, is employed to reduce the temperature. Besides mechanical refrigeration, other options to achieve the required gas cooling include JT – valve expansion or use of a turboexpander. For either of these options, the MEG injection and regeneration portion of this plant is minor by comparison.

In this scheme, the sales gas exiting the gas-to-gas exchanger has a water and hydrocarbon dew point determined by the operating temperature of the cold separator. The CAPEX of this system is essentially driven by the gas cooling equipment, including the refrigeration system. The key point to remember here is that the water is being removed from the gas by low temperature condensation. The purpose of the injected MEG is not to “dehydrate” the gas but to prevent formation of hydrates. At the MEG concentrations normally used in these systems, approximately 80 – 85 wt%, the MEG absorbs only a small amount of water vapor from the gas.

Let’s now look at a typical circulating TEG system. See Figure 2. The same rich, water saturated natural gas stream flows to a properly sized inlet separator to remove liquids. The gas then enters a glycol contactor equipped with either structured packing or bubble cap trays. As the gas rises, the water is removed by the falling TEG. The concentration of the lean glycol entering the top of the contactor is the main variable that determines the water dew point specification that can be made. The rich glycol that leaves the glycol contactor is sent to a flash drum and then to a regeneration section. The lean glycol leaving the regenerator is then returned to the contacting tower.

In this system, we are only making water dew point specification gas. The NGL content/hydrocarbon dew point of the sales gas is the same as that of the feed gas. Circulating TEG systems are therefore used only for dehydration. A significant cost item for the circulating TEG system is the high pressure contacting tower.

Now let’s explore how we can compare and contrast these two technologies.

If your objective is to make only pipeline water specification gas, you will most likely choose a circulating TEG system. This is intuitively obvious from a comparison of the two flow diagrams cited above. Assume, for example, that you want to dehydrate a lean natural gas stream that is water saturated at 70 bar and 40°C. A quick comparison of Figures 1 and 2 shows that there is much more equipment associated with chilling the feed gas (Figure 1 + the refrigeration compressors, etc. that are not shown) then there is with a circulating TEG system (Figure 2). Hence, for dehydration only to pipeline water specifications, a circulating TEG system will almost always be selected.

On the other hand, if your objective is to recover hydrocarbons and remove water simultaneously, then a low – temperature process with MEG injection may be the best choice. Assume you have a rich natural gas stream that is water saturated at 70 bar and 40°C. Assume a mechanical refrigeration process is selected for hydrocarbon liquids recovery with a cold temperature of -35°C. We have two options to consider: we can dehydrate the gas with a circulating TEG system to a water dew point of -35°C and then send the dehydrated gas to an LTS plant consisting of a gas-to-gas exchanger, chiller, refrigeration system, etc., but with no MEG injection/regeneration system; or, we can send the feed gas directly to the LTS plant which has an MEG injection system retrofitted to prevent hydrates from forming.

Figure 2

Copyright © 2007 John M. Campbell and Company

Figure 2. Basic glycol dehydration unit [2]

Since the underlying equipment required to recover NGL’s is the same in both options, the cost comparison is essentially between the circulating TEG system and the MEG injection system. The TEG system will use less circulating rates then the MEG system, but will likely have a higher regeneration duty. Achieving the large dew point depression of 75°C with a circulating TEG system will be challenge and will add to the system cost. The key difference, however, is the circulating TEG system requires a high pressure contactor while the MEG injection system does not. In this situation, the most likely choice will be to go with the MEG Injection system.

For more information about dehydration and hydrate inhibition, the reader should refer to JMC books and enroll in our G4 (Gas Conditioning and Processing) and G5 (Gas Conditioning and Processing – Special) courses.

By Harvey M. Malino and Mark Bothamley


  1. Campbell, J. M. “Gas conditioning and processing, Volume 1: Basic Principles,” 8th Ed., John M. Campbell and Company, Norman, Oklahoma, USA, 2001.
  2. Campbell, J. M. “Gas conditioning and processing, Volume 2: The Equipment Modules,” 8th Ed., John M. Campbell and Company, Norman, Oklahoma, USA, 2000.
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