Pascagoula Gas Processing Plant Designed with Deep Water Production in Mind

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Deepwater Production Drives Design of New Gulf Gas Plant

Published in Oil & Gas Journal, March 16, 1998
Authors: Luther Petty, J. J. (Roger) Chen, Doug Elliot, International Process Services, Inc., and Rod Nielsen, Amoco Corporation

Exploration and production success in deepwater, eastern Gulf of Mexico has created the need for additional gas-transmission and processing infrastructure. The Destin pipeline and the Pascagoula gas-processing plant (Fig. 1) are being built to serve this need.

The Destin pipeline originates at a junction platform at Main Pass 260 and, after coming onshore near Pascagoula, Mississippi, will connect with five interstate gas transmission pipelines, by-passing gas-transportation bottlenecks in Louisiana and Alabama.

The Pascagoula plant will be built near the point the pipeline comes onshore and immediately before the first compressor station

Figure 1

Handling Condensate

Fig. 2 shows that the Pascagoula plant straddles the Destin pipeline adjacent to the slug-catching facilities designed to remove retrograde condensate that may form in the pipeline. The slug catcher will hold 5,000 bbl of liquids from the pipeline. Gas handling capacity is 1 bcfd. Liquid from the slug catcher feeds into the condensate stabilizer. The condensate stabilizer is a typical unit designed to produce approximately 2,000 b/d of 12-psia Rvp condensate. The stabilizer will be started in July 1998 along with the Destin pipeline. Gas from the slug catcher is dehydrated, then processed in two identical trains, each with a capacity of 500 MMscfd. Inlet gas cooling, dehydration, expansion, demethanization NGL recovery, and residuegas compression are provided in each train.

Figure 2

Train A will be started in early first quarter 1999. Train B engineering is under way; construction will follow immediately after Train A with start-up in late 1999. Molecular-sieve dehydration is used for the inlet gas. A three-bed system is used for Train A and will then be expanded to a four-bed system to handle Train B. Condensate is delivered to truck loading, NGL is delivered by pipeline, and residue gas is compressed and returned to the pipeline network. The Destin pipeline network, operated by Southern Natural Gas Co., delivers gas to the onshore facilities. The Pascagoula gas-processing plant is owned by Amoco Corp. and Tejas Natural Gas Liquids L.L.C., an affiliate of Shell Oil Co. Amoco is plant operator.

Design goals

The design team for the Pascagoula plant established the following goals to meet the needs of the deepwater producer:

Provide reliable gas processing for shippers on Destin pipeline. Much of the deepwater production will be richer in NGLs than much of the shallow-water production. As a result, the Pascagoula plant must operate reliably to ensure uninterrupted flow of gas on the Destin pipeline. The plant must process all gas transported on Destin pipeline to provide market-quality gas. Finally the process design must be flexible to accommodate changing inlet compositions. There is considerable uncertainty about the gas composition because none of the fields that will deliver gas to Destin is currently producing. The first ones will come on line third quarter 1998, but confidentiality agreements currently prohibit disclosure of their names or their producing companies.

Provide value enhancement through NGL recovery. Historically, the industry has experienced wide variations in processing margins. Therefore, maximum value enhancement must be achieved through operational flexibility. The plant will be designed for ethane recovery, ethane rejection, and hydrocarbon dew point control modes of operation.

Achieve low life-cycle cost. Initial construction cost and long-term operating expenses must be minimized to achieve commerciality.

Be safe and environmentally benign. Because the Pascagoula plant lies in the middle of an industrial park and near residential neighborhoods rather than at a rural site, special design requirements resulted

Achieving objectives

Maintaining gas production within specification and at the required rate at all times is important. Normally in ethane recovery or ethane-rejection mode, one of two refrigeration compressors and both residue gas compressors are used.

Should power be lost or reduced, the residue compressors are shut down and dew point mode of operation is used. Only the dew point control mode requires two refrigeration compressors running at the same time. This greatly enhances gas-delivery reliability should exceed 98.5%.

The plant can be operated in four different modes:

In ethane-recovery mode (Fig 3), it can recover 80% of ethane from the feed gas.

The plant can be shifted to ethane rejection (Fig. 4) if required by ethane-recovery margins. The plant can recover 92.4% of propane in the ethane-ejection mode.

If ethane-recovery margins are diminished, the plant can be operated in dew point control mode (Fig. 5) with the propane refrigeration system. It can produce a gas with a heating value of less than the maximum allowable of 1,075 BTU/standard cu ft and a hydrocarbon dew point less than 0ºF.

If one of the residue gas compressors is down for maintenance, the plant can be operated with half of the flow in dew point control mode, the other half in ethane-recovery mode.

Propane refrigeration is provided to:

Increase reliability in achieving dewpoint control

Increase the plant’s flexibility to process the varying inlet compositions

Reduce total plant compression requirements

Remove heavy ends from the gas stream to eliminate solids deposition in the cryogenic section

Figure 3

Figure 4

Figure 5

Low life-cycle cost

The process scheme raises the demethanizer pressure higher than the conventional scheme. This reduces the residue gas compression requirement by as much as 5,000 bhp. The plant has a high degree of heat integration, using demethanizer reboilers and a propane subcooler to exchange heat and refrigeration. The Pascagoula plant will utilize electric-drive compression. Depending on gas price, electricity can be more costly than gas turbines on a monthly operating basis, but electric drive has a significant advantage of lower capital costs, lower maintenance costs, and improved reliability. Utilizing electric compression also ensures that the plant will not exceed NO_X and CO₂-emission limits.

An attractive electric-power purchase contract was obtained through use of a curtailable agreement. The plant has been designed with appropriate actuated switching valves to allow switching from cryogenic recovery mode (ethane recovery or rejection) to dew point control mode (refrigeration). This will allow the plant to shed the electrical load of the residue gas compression while continuing to deliver market quality gas to Destin pipeline.

The plant has two flare stacks, one low-flow flare stack and one high-flow flare stack. The low-flow flare stack is designed to release 120 MMscfd of gas; the high flare stack, to handle 1 bcfd of gas. The low-flow flare stack is designed to handle heavier hydrocarbon releases such as from the propane refrigeration system or various fire cases. The high flare stack is designed to handle releases, mainly methane, from large-volume relief valves.

There is a rupture pin in parallel with the rupture disk installed in the high-flow header. The pin will be broken at 50 psig which will only happen with a large volume release. Inclusion of this rupture pin allowed elimination of purge gas for the high-flow stack, thereby greatly reducing fuel use and air emissions. The low-flow stack is operated with air blower assistance so that it is smokeless.

A unique feature of this plant is inclusion of three sets of high integrity pressure-protection systems (hipps) valves installed in the plant to prevent over pressuring. One set of hipps valves is installed in front of the slug catcher, one at the front end of the gas plant, and the third set in front of the warm separator. Each valve set has two valves in series with separate independent actuating systems. They will be triggered by high pressure whether or not the distributed control system is operating. These valves can be closed within 3 sec, greatly reducing the likelihood of the big relief valves. Since the Pascagoula plant is in an industrial park and close to residential neighborhoods, hipps were included in the design to reduce flaring and associated air and noise pollution. Hipps are being used more frequently in Europe but, to our knowledge, this is the first use in a U.S. gas processing plant.

There are vapor recovery systems installed on the condensate tank and stabilizer overhead. If the recycle compressor is down, these vent streams can be routed to flare header and then burned. Hydrocarbon emissions are significantly reduced.

There will be no industrial wastewater discharge from the facility. All process wastewater and contaminated storm water will be collected in tanks and trucked offsite for treatment. Sanitary wastewater will be treated in an aerobic unit prior to discharge. Clean stormwater runoff will be allowed to flow into nearby drainage ditches.

Project Schedule

The project’s condensate stabilizer is independent of the cryogenic plant and is expected to begin operating in July 1998 in conjunction with startup of the Destin pipeline. Train A of the cryogenic plant will begin operating in early first quarter 1999, less than 2 years after project kickoff. Train B will follow shortly thereafter.

Plant process design was by International Process Services Inc., Houston.