Upgrade gives new life to old gas plant

Facility upgrades were implemented by GPM in most areas of the plant. This occurred in stages as engineering and procurement proceeded on the new cryogenic NGL recovery section (Fig. 1).

At the time of the acquisition, liquids in the plant inlet gas were being let down from the 235 psi inlet pressure to near atmospheric pressure with flaring of the flash vapors.

In addition, lack of sufficient condensate collection and handling facilities resulted in frequent hydrocarbon carryover into the amine treating system and SRU.

As a first step, improved inlet liquids-separation equipment was installed, along with additional condensate storage and vapor-handling facilities. These actions significantly reduced flaring of vapors, which increased the plant's thermal efficiency, and greatly improved operation and stability of downstream equipment. (A condensate stabilizer was subsequently installed which essentially eliminated condensate vapor flaring.)

During this same period, a Foxboro I/A DCS was installed and implemented in the inlet receiving and treating sections of the plant.

Also during this time, GPM initiated extensive equipment and piping modifications in the MEA system which allowed essentially complete CO₂ removal in addition to H₂S. The lower CO₂ levels were required for cryogenic processing and to meet NGL product specifications associated with future higher ethane recoveries.

The upcoming changeover to a cryogenic NGL-recovery process also required extensive modifications to the mole sieve dehydration facilities. The 200 MMscfd system had consisted of four towers, each containing two beds separated by an internal head, which resulted in essentially an eight-bed system. Wet feed gas was used for regeneration with recycling of the regeneration gas back to inlet compression suction. In addition, the entire system was manually regenerated (Fig. 2).

Upgrade of the mole sieve system consisted of the following modifications:

• Conversion of three of the dual-bed towers to a single-bed configuration with total capacity of 150 MMscfd.
• Changeover from wet inlet gas for regeneration to residue gas with a regeneration gas compressor.
• Installation of a new direct-fired regeneration heater to replace an existing hot-oil system.
• Addition of a chiller for regeneration-gas cooling to eliminate off-spec water content in sales gas.
• System automation with new, high-integrity switching valves, DCS regeneration sequencing, and moisture analyzers.

These changes were implemented by GPM prior to the conversion to the cryogenic NGL process and brought the dehydration system up to a state-of-the-art configuration (Fig. 3).

Compression at the plant was also significantly upgraded. Inlet compression had consisted of two 2,200-hp Clark TLAs and four 1,200 hp Clark HRA machines. A Solar Taurus 70 turbine/compressor (7,125 site hp @100° F.) was added and one of the Clark HRAs idled, which resulted in total inlet compression power of 15,125 hp.

Suction pressure remained at 235 psig with discharge pressure decreasing slightly to 640 psig. However, inlet capacity was increased to 200 MMscfd maximum. Compression for propane refrigeration was also modified.

A single Solar T-4000/York compressor (3,380 site hp @ 100° F.) with a circulation of 24.5 MMscfd replaced three 1,600 hp GMVh-8 Cooper Bessemer compressors. New residue compression was also added since none had been required for the existing lean-oil process. Installation included a Solar Taurus 70 turbine/compressor (7,125 site hp @ 100° F.) and a Solar Centaur T-4700 (3,780 site hp @ 100° F.) with a total residue compression power of 10,905 hp.

Combined residue compression capacity was 110 MMscfd. A waste heat-recovery unit (WHRU), generating 250 psig steam, was installed on the new residue compressor gas turbines. Total steam production for the new WHRU was 40,000 lb/hr which is half the total plant steam requirement.

Installation of the WHRU allowed two of the existing boilers to be shut down.

Improvements were also made to the existing sulfur plant. The first of these was replacing the direct-fired reheaters on Beds 2 and 3 with new steam reheaters. This reduced fuel consumption and maintenance costs.

A fourth Claus bed with associated equipment was also added, along with upgrading of the controls via the Foxboro I/A DCS, to increase sulfur conversion. The net effect of these modifications was to increase sulfur recovery from 90 to 95.8% and capacity to 49.4 short tons/day. This was sufficient to support the upgrade project.

GPM brought the new turboexpander facilities on stream at the end of 1995. Design ethane recovery was 91%. However, feed to the plant was leaner than design, and observed ethane recovery was over 95%. Typical NGL recovery from the previous lean oil operation had been 6,735 b/d at 150 MMscfd inlet rate. NGL production increased to 16,800 b/d after the cryogenic facilities commenced operation.

The environmental impact of the upgrade project was significant. The overall upgrade project reduced emissions from the plant by 472 tons/yr of NO_x, 83 tons/yr of CO₂, 2,977 tons/yr of SO₂, and 5 tons/yr of volatile organic compounds.

NGL extraction plant design

The NGL recovery facilities for the Linam Ranch upgrade project were provided by Technip USA based on its Flash Vapor Reflux (FVR) process.² The central feature of the FVR process entails warming up expander inlet separator liquid against other process streams followed by flashing at an intermediate pressure.

The flashed vapor is condensed to provide a lean reflux stream to the demethanizer. This process, as applied to the Linam Ranch project, is shown in Fig. 4.

Inlet gas flow is split, and the major portion is cooled against a combination of residue gas and refrigeration streams in the inlet gas chiller plate fin exchanger. The remaining inlet gas is cooled against demethanizer streams plus expander inlet separator liquid. The inlet streams are recombined and flow into the expander inlet separator. The separator liquid is let down to a pressure intermediate between the plant inlet and the demethanizer, warms up against inlet gas in the final section of the demethanizer reboiler's plate fin exchanger, and flows to the cold gas separator.

The separator liquid is then routed to the demethanizer as bottom feed. The flash vapor is then condensed in the reflux condenser against the demethanizer overhead and fed as a lean reflux to the top section of the tower. The expander inlet separator vapor is fed to the expander and on to the demethanizer as the intermediate feed.

By generating reflux from the expander inlet liquid, the FVR process allows the entire cold vapor stream from the expander inlet separator to flow through the expander, thus generating the maximum refrigeration duty for the process and maximum horsepower for the booster compressor. In addition, by adjusting the pressure of the cold gas separator and the temperature of the warmed expander inlet separator liquid, the quantity and composition of reflux can be varied to optimize unit efficiency.

Design ethane recovery for the Linam Ranch plant was slightly over 91%, based on the original rich feed composition (6.32 gpm). As start-up of the new facilities approached, however, it became apparent that the feed composition would be leaner (4.79 gpm). The design was resimulated for the leaner feed, and ethane recovery was calculated at over 95%. Feed gas composition has remained consistently leaner than original design in the 3 years since start-up, and ethane recovery has remained uniformly high. It currently is running at over 97%. Plant design and performance are summarized in Table 1.

The process can be easily converted to ethane rejection without a plant shutdown while maintaining high propane recovery (Fig. 4). In this mode, warmed expander inlet separator liquid from the demethanizer reboilers plate fin exchanger is diverted directly to an alternate feed point on the tower by operating two block valves. This effectively bypasses the cold gas separator and eliminates reflux to the top of the demethanizer.

The steam-heated demethanizer trim reboiler is then placed in service, and the demethanizer bottoms stream is bypassed around the demethanizer reboilers plate fin exchanger. Design ethane recovery in this mode is 29.1%, while propane recovery is 94.3%.

The Linam Ranch upgrade was the first application of the FVR process. It has subsequently been used for a 320 MMscfd high ethane-recovery plant supplying feed to an ethylene cracking unit in India. Start-up of the plant was slated for mid-1999.

Plant operation since start-up

As outlined earlier, the plant performed as expected after conversion to cryogenic operation. Since then, significant strides have made to further improve plant operations. Some challenges, however, remain.

Operating successes

GPM has maintained a program of continuous improvement since the upgraded plant was restarted in early 1996. This has focused on a combination of improvements to plant operation and selected equipment upgrades.

A key factor in the improved operation has been creative use of the Foxboro I/A DCS to implement advanced control schemes, and a number of control opportunities have been identified and put into place during the past 3 years.

One outcome of these control upgrades is that the plant can now handle a 0.5 gpm swing in feed NGL content without upset. Examples of advanced controls that have had beneficial impacts on plant operation to date are discussed below. It should be noted that plant personnel implemented these control improvements, and that this work is on-going.

As mentioned earlier, additional facilities were added as part of the original upgrade project to better handle inlet liquids. The problem was that liquid slugs arrived irregularly, varied considerably in volume, and were still causing problems.

After observing that an inlet-pressure surge preceded large liquid slugs, a predictive control algorithm was implemented that shifts the inlet-liquid control mode between level and rising inlet pressure as necessary. Inlet liquid slugs can now be handled routinely.

Another application was load-balancing control on gas to the four amine contactors. It was observed that gas flow to the contactors varied fairly randomly in relation to amine flow, resulting in substandard contactor performance.

A load-balancing controller has been configured which monitors flow to each contactor and adjusts balancing valves to compensate for fluctuations in contactor pressure drops. In related developments, a predictive control algorithm has also been developed to control amine circulation in response to H₂S and CO₂ in the feed gas, and SRU trim air control has been implemented which responds to the SRU H₂S analyzer output and other selected variables.

But of the control schemes implemented so far, the most improvement has come from the "process optimizer." This is a constraint-based, fuzzy logic-type supervisory program that initiates small incremental changes to selected variables and measures the resulting effect on major economic factors such as horsepower utilization and ethane recovery.

The impact on operating efficiency has been significant, and by observing which variables the "optimizer" visits most often, plant operators have gained insight into process relationships that had not been apparent before.

In addition to the plant control upgrades, selected equipment upgrades have been undertaken to increase efficiency and/or capacity. Noteworthy projects have included expansion of the mole sieve dehydration capacity to 200 MMscfd by revamping the fourth existing sieve vessel, and retrofit of evaporative combustion air cooling onto the gas turbines to increase warm weather horsepower.

Together, these upgrades have increased nameplate capacity to 170 MMscfd while maintaining ethane recovery at 95%. Maximum throughput is now 185 MMscfd at 90% ethane recovery. Future expansion to 200 MMscfd with high recovery is achievable by installing additional residue compression and rewheeling the turboexpander. The plate fins, demethanizer, and associated piping and controls were originally sized for 200 MMscfd ultimate capacity and would not present obstacles.

Operating challenges

Although overall plant operation is very smooth with consistently high NGL recoveries, some operating problems remain. One is the result of the feed gas being leaner than design. This results in lower loads on the refrigeration system and frequent operation of the refrigeration compressor surge controls.

The surge-control valve appears to be oversized for the spillback flow, which results in fairly ragged surge control. This is not considered a major problem at this time.

Another item encountered is not a problem, per se, but a limitation detected with operation of the flash vapor reflux system in the turboexpander unit. In an effort to further increase ethane recovery, the temperature of the cold gas separator was progressively increased beyond design conditions to generate additional tower reflux.

Ethane recovery increased as expected, but past a point excessive amounts of propane were flashed as well which resulted in loss into the demethanizer overhead and a reduction in propane recovery. The cold gas separator temperature is now kept within the proper range.

A more perplexing problem has been encountered in the final section of the demethanizer reboilers plate fin exchanger. In this section, expander inlet separator liquid is warmed against inlet gas to produce flash vapor for tower reflux (Fig. 4).

Periodically, over a period of several weeks, the separator liquid side begins to plug off with an unknown substance, and heat exchange is reduced. The pluggage is removed by diverting the separator liquids to the demethanizer and allowing the plugged section to warm up while injecting some methanol. After about 24 hr, full flow and heat exchange are restored.

The mole sieve operation has been very reliable, so moisture is not considered to be the cause. A possible explanation is trace amounts of high freeze point aromatic compounds in the feed, but this has not been confirmed.

Project results

The Linam Ranch upgrade project increased processing capacity with higher NGL recovery. But significant emphasis was also placed on safety, environmental, operability, and reliability improvements to bring the plant up to modern standards.

Some of the major accomplishments of the project included:

• Capacity restored to 150 MMscfd nominal, 170 MMscfd max.
• NGL production increased 2.5 fold with leaner feed gas.
• Emissions reduced by 3,537 tons/yr.
• Operating efficiency maximized with significant automation and control upgrades.

Acknowledgments

The authors wish to thank John Eggerman and Kevin Gerber both of the Linam Ranch gas plant for their kind assistance and contributions to the preparation of this article.

References

1. True, Warren R., "Upgraded gas plant anchors reconfigured gathering system," OGJ, Feb. 26, 1996, p. 65.
2. Vijayaraghavan, B., Ostaszewski, R., US Patent No. 5,566,554.

The Authors

Les Harwell is the process group manager at Technip USA, (formerly KTI Fish Inc.). His career spans over 30 years of diversified process engineering/supervision for all types of gas processing plants, as well as refining and chemical facilities.

Harwell graduated from the University of Texas in 1967 with a BSChE degree. He joined Fish Engineering in 1975. Since then, he has been involved in all phases of process engineering, including conceptual design, process studies, detailed process engineering, and plant start-up. He is a registered professional engineer in Texas and is active in the GPSA.

Joe Kuchinski is operations support manager of the New Mexico region for GPM Corp., Hobbs, NM. He had primary responsibility for the modernization of the Linam Ranch gasoline plant.

Kuchinski is a 1978 graduate of the Colorado School of Mines with a BS degree in chemical petroleum refining engineering. He began his career with Phillips Petroleum at its Great Falls, Mont., refinery. Kuchinski has published several papers and has one US patent.

Based on a presentation at the 78th annual convention of the Gas Processors Association, Mar. 3, 1999, in Nashville, Tenn.