In 1977, the Colorado Interstate Gas Company (CIG) built and commissioned the Table Rock Gas Plant to process and remove sour from the natural gas being produced from nearby Higgins Unit and Table Rock fields.
The inlet capacity was modified in 1988, This sour gas plant uses conventional processing techniques, beginning with three phase separation at the plant inlet to remove condensate liquids and water from the gas stream. The gas then goes to amine sweetening for CO2 and H2S removal, prior to passing through gas dew point control, and then down the sales pipeline. Dew point control is a dehydration technique in which ethylene glycol is sprayed into the gas stream, which is then chilled by a propane refrigeration system. The glycol/water droplets are then recovered in a knock out drum, and the glycol is reclaimed by driving the water off in a steam heated glycol regenerator reboiler.
A reduction in plant gas processing capacity was made in 1988, after several years of declining gas availability from the Texaco Table Rock gas field feeding the plant, gas availability dropped to a low of around 7 MMSCFD during the first half of 1990.
These 1988 process changes included taking the condensate stabilizer system and the Claus sulfur plant out of service. In addition, formerly there were two gas sweetening systems operated in series at Table Rock; a potassium carbonate absorbing system and a DEA diethanolamine absorbing system. The potassium carbonate system contactor and regeneration towers were blinded off and abandoned, while the DEA absorber was converted to a methyl diethanolamine (MDEA) amine sweetening system to remove both H2S and CO2.
At these reduced plant gas inlet rates, the sulfur volume of the acid gas stream was low enough that the ATS tail gas plant could remove enough of this sulfur to allow the plant to remain in compliance with SO2 emission standards. Thus for about two years from 1988 to 1998, Table Rock operated while totally bypassing the three stage Claus plant.
The maximum gas processing capacity of the Table Rock plant after the 1988 modification is about 17 MMSCFD inlet rate. In the early 1990’s, summertime inlet capacity was reduced to about 14 MMSCFD to account for loss of cooling efficiency in the amine still, due to the hotter summertime ambient temperatures (at full 17 MMSCFD summertime inlet, amine return temperatures would rise above the 130° F criteria used at Table Rock to obtain minimum H2S recovery efficiency). Warmer amine in turn results in more gas failing to meet pipeline sulfur specifications, thus there is more potential for flaring of this off-specification gas without proper amine cooling. Wintertime operation allows the full 17 MMSCFD operational rate however, as the amine cooling capacity produces return amine temperatures down around the more desirable 100° F range. With the 1995 addition of a new amine aerial heat exchanger, summertime throughput around 16 MMSCFD can now be attained.
At 11 MMSCFD, a little less than 2 MMSCFD of acid gas is produced from the amine regenerator. Table Rock focused on production of ATS with this stream. Maximum ATS production at this gas split, is around 90-95 TPD.
Plant steam is used for heat in both the dew point control system glycol regenerator and the MDEA amine regenerator reboiler. This steam is primarily provided two 48.4 MM Btu/hr natural gas fired Erie City power boilers on site, each rated at 40,000pph steam production. There are two waste heat boilers one on the exhaust of the Claus plant reaction furnace, and the ATS inlet incinerator. The waste heat boilers supplement the power boilers.
During the summer of 2003 and 2004 the plant was modified to again handle the original 60 MMCFD of inlet gas. The modification included converting the potassium carbonate system into a 1200gpm Amine unit. The sulfur plant was recommissioned to handle the increase of Acid Gas produce with the additional Inlet gas. The control system was upgraded to Delta V computer and electronic control system. Installing new support equipment, construction of a SWD salt water injection system and well.
In June of 2005 the inlet gas flow was again at 60mmcf.
In 2008 the Plant ownership changed again. In 2009 the plant was again modified to increase reliability and optimization. The Boilers were replaced with two high efficiency units, each rated at 60,000pph steam production. The incinerator was replaced with a new unit. The Sulfur plant system was rebuilt and renewed. The fiberglass lines in the ABS/ATS unit were replaced. Inlet compression was added to allow for lower field pressure increasing inlet gas flow.