Traditionally dehydration has been a triethylene glycol (TEG) unit utilizing a 4-8 tray absorber with bubble cap trays. These units work well and are relatively inexpensive. However, there has been an increasing concern about hydrocarbons emission from the vent gas and produced water over the last few years. The hydrocarbons of greatest concern are benzene, toluene, ethyl benzene, and xylene (BTEX). Units can be added on to mitigate the emissions but they take up extra space and weight which is expensive offshore. Therefore, there is an increased interest in decreasing the cost and size of conventional units or finding an alternative process that is less expensive. Under Gas Research Institute contract a survey of a number of offshore producers to determine present practices was conducted. Several absorber alternatives and/or modifications for conventional TEG units were compared with a hypothetical membrane unit for dehydration of 75 mmscfd of natural gas at 1000 psia and 100°F. Although commercial membrane units are not yet available a "good" hypothetical unit was compared because of its advantages of simplicity and lack of emissions. The membrane unit, however, was not found to be competitive. A TEG unit with a Higee? absorber was found to have a slight advantage over more conventional trayed and random and structured packing absorbers after taking into account the effect of size and weight as well as initial cost.


A survey of seventeen offshore producers was performed to generate the following information: (Foral, 1994)

  • Present offshore dehydration practices;

  • Level of industry concern over emissions; and

  • A design basis that would be typical of Gulf of Mexico offshore operating conditions.

Eleven companies responded to the survey indicating that the most commonly employed dehydration process used was TEG dehydration with bubble cap trays. In evaluating alternatives, most respondents reported that savings in size and weight were considered important. The savings in size (footprint) was considered somewhat less important than weight. The level of reliability required for offshore processes was reported by most respondents to be in excess of 95%. Before an alternative process would be considered for offshore use, the consensus of the respondents was that:

  • The unit size should be no larger than existing units with equal performance.

  • There should be a history of successful operation for a period of at least 1-3 years.

  • Materials of construction should be compatible with the offshore environment.

Most of the companies indicated that environmental regulations of the emissions of BTEX and other VOC from offshore sources require research and development to develop new technology.

Operating Conditions.

The operating conditions chosen for sizing the units were:

  • A flow of 75 mmscfd at 1000 psia and 100°F.

  • The gas was assumed to be methane saturated with water.

  • A fuel gas usage equal to 3.4% of the feed at 135 psia.

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