Elizabeth F. RhodesTreating dense-phase natural gas with fixed-bed technology has proven effective and economic at the North Sea terminal for Central Area Transmission System (CATS).
Seal Sands, England
Paul J. Openshaw, Peter J.H. Carnell
CATS is a joint venture of BP Amoco, BG, Amerada Hess, Phillips, Agip, and Fina, and operated by BP Amoco. The terminal receives rich gas from several fields that is relatively sweet, but small amounts of H2S and Hg are present and must be removed.
Fixed-bed technology was selected as the most economic purification process, while minimizing hydrocarbon loss and operator involvement.
Conventionally, the raw gas would be split into the different hydrocarbon fractions with each being processed separately. This would require the installation of a large number of reactors.
A more efficient solution is to treat the gas on arrival at the terminal in the dense phase. But this option raised questions of whether a fixed bed would be prone to fouling; could the pressure drop be kept low enough to avoid phase separation; and would inadvertent wetting by condensation cause problems.
Testing proved the viability of fixed-bed technology for dense-phase gas processing, CATS' eventual processing design, which now has had more than a year of service.
Central Graben developmentCATS is part of the Central Graben development in the U.K. sector of the North Sea. 1 The project was originally conceived to carry natural gas from the Everest and Lomond fields for a 1,725-mw, combined-cycle power plant at Teesside in Northeast England.
CATS' owners, however, decided to create a system large enough to accommodate future business from other undeveloped fields. Current capacity is more than 1.6 bcfd of natural gas.
Demand for CATS' services has been so great that by 1997, most of capacity had been contracted to seven field groups, and CATS' owners are exploring options to expand the system.
The locations of CATS and the terminal on the North Sea are shown in Fig. 1 [121,495 bytes].
The CATS pipeline begins at a riser platform adjacent the BP Amoco-operated Everest field in the Central North Sea and transports gas some 250 miles to the CATS processing terminal at Seal Sands on the northeast coast of England.
At the terminal, 600 MMscfd of gas are delivered to a downstream processor. In the processing plant, NGLs are removed and gas processed for delivery into the Transco national transmission system.
The pipeline runs for 254 miles along the seabed from the riser platform to Coatham Sands near Teesside. The 36-in. ID pipeline is made of high-strength steel with a minimum 1-in. W.T.
The inside of the pipe is coated with an epoxy film to reduce friction, maximize capacity, and extend service life. The metallurgy allows for the transportation of sour gas (H2S 150 ppmv and CO2 25 mol %).
There are six subsea connection points spaced at intervals along the line so that customers can connect to CATS at any one of these points or at the riser platform.
The connection can be made while gas is flowing, which means that CATS can provide an uninterrupted service for existing customers at the same time as it is accommodating new ones.
At present, the pipeline carries gas from Lomond (1993), Everest (1993), Andrew (1996), J-Block (1997), Armada (1997), Erskine (1998), and ETAP (1998). The pipeline system is shown in Fig. 2 [128,496 bytes].
Teesside is a major industrial center with one of the largest ports in the U.K., but the CATS terminal lies close to a designated Site of Special Scientific Interest (SSSI). Therefore, great care has been necessary at all stages of the project to avoid damage to the ecosystem.
The first stage of the project required the construction of the pipeline, pig receiver, slug catchers, filters, and metering facilities to provide gas for the power plant and downstream processor.
The next phase was to provide processing facilities to produce gas to meet the specification of the National Transmission System (NTS) and allow recovery of NGLs. The received gas contains small amounts of CO2 and H2S, but only the latter must be reduced to meet the NTS requirement.
Conventionally, dense-phase gas would be cooled by expansion to separate the NGLs, and each stream would be treated separately for H2S removal.
BP Amoco was interested in treating the gas as received in the dense phase and approached ICI to see if its Puraspec fixed-bed technology was applicable (OGJ, June 5, 1995, p. 52).
Treating gas in the dense phase raises two main questions:
- Do the kinetics follow those of a gas or a liquid?
- Is there risk of inducing capillary condensation?
Dense-phase operationThe pipeline was constructed to operate at a pressure high enough to ensure that, at the temperatures encountered, a single phase would be maintained throughout.
This is referred to as "dense-phase operation" and means that the hydrocarbon fluid is maintained at greater than its Criconderbar. Gas enters the pipe at approximately 2,600 psi and is received at the terminal at a pressure greater than 1,600 psi.
Pure gases have a relatively simple pressure-temperature diagram with an easily identifiable point at which they become supercritical. Mixed gases, particularly those of hydrocarbons, have a very complex pressure-temperature relationship.
The most interesting phenomenon they show is that of retrograde condensation.2 In this case, lowering the pressure at a given temperature may result in first the release of liquid and then the gasification of this liquid.
Fig. 3 [114,192 bytes] shows the pressure-temperature curve for one of the gas compositions expected at the CATS terminal.
Because the seabed temperature is approximately 4° C., this gas would arrive at the terminal at a temperature and pressure close to the phase boundary at which dewing could occur. Also, if this gas were also to come in contact with microporous material, it is then possible that because of capillary condensation this effect would be observed at a higher-than-expected temperature.
Premature liquid formation could have serious consequences on fixed- bed processing because it could lead to flooding and channeling. Also, it is possible that in cycling across the phase envelope, high-molecular-weight species could accumulate and foul the bed, preventing its operation.
TestingBecause of uncertainties surrounding the behavior of the raw gas at high pressures and low temperatures, the joint venture installed a small side-stream reactor on the site. This would be operated on the plant built at the first stage to supply gas to existing customers ahead of the main CATS project.
The unit was constructed to allow unmanned operation in a Division II classified area. It was assumed that supply gas would have the composition given in Table 1 [38,411 bytes].
Fig. 3 shows that the composition and conditions place the gas just outside the gas/liquid phase envelope, i.e., in dense phase. Any lowering of the pressure would cause retrograde condensation to occur.
Hence, the test reactor was constructed with provisions for heating and cooling the gas and operation at reduced pressure. Also, because of the low level of H2S in the feed, provision was made for spiking the gas with H2S to be able to simulate projected future operating conditions.
The reactor was designed to hold 1.5 l. of absorbent arranged in six beds and could receive up to 20 cu m/hr of gas. Over a period of several months, the tests shown in Table 2 [25,920 bytes] were carried out. These were designed to simulate both normal and upset operating conditions.
At all times there was complete removal of H2S from the gas. This was of particular interest in the cases of Runs 5 to 7, where condensation was taking place, and in Run 8 where fouling might have been a problem. Water is produced in the reaction to remove H2S, but Run 3 gave no evidence of hydrate formation.
Hence, it was concluded that fixed-bed absorbents could provide a practical method to remove H2S from natural gas in dense phase. This technology has the added attraction of providing a safe and environmentally acceptable process that requires minimum operator intervention.
Mercury removalNatural gas derived from fields with low levels of sulfur may contain mercury. Typically, it is present at a very low level, say 50 nanograms/cu m, and present in elemental form.
It is very difficult to detect and measure low levels of mercury in natural gas, and it is often only after a considerable amount of gas has been processed that its presence is confirmed. This is because most of the mercury is trapped on the steel pipework and will only be seen at the terminal once the system has reached equilibrium.
Some of the absorbents proposed for H2S removal are also effective for mercury removal. These provide the basis for Synetix' Merespec process for mercury removal.3 It was a simple procedure to confirm that even the extremely low levels of mercury in the gas could be removed in the H2S-removal reactor.
An interesting aside on this work is that it provides a convenient method to measure the level of mercury in the gas. Thus, if the total amount of sulfur and mercury on the absorbent is measured, then, because it is easy to measure the H2S concentration in the gas, the concentration of mercury can be obtained by simply deriving a ratio.
Material handlingThe test work outlined previously confirmed that fixed-bed technology could be used for mercury and hydrogen sulfide removal. However, as the plant had an ultimate capacity of 1.7 bscfd, there was a concern over the size of the reactors and the ease of their loading and unloading.
Normally, large reactors are charged with 1 cu m containers and a crane. But as the design bed life was only a few months, there was a reluctance to use cranes and small containers.
Synetix had used a suction technique to load and unload Puraspec absorbents at a Dutch plant, and it was decided to see if this procedure could be used on the CATS terminal.
Also, a requirement was made that loading and unloading be completed without the need to enter the vessel. This meant that all operations would have to be carried out from the top entry ports. The loading would have to leave the top surface reasonably level, and the design of the inlet-gas distributor would have to ensure there was no fluidization.
Trials were conducted on a mock-up of the top section of the proposed reactor design with loading from, and discharging into, 20-ton bulk containers. These led to the adoption of a built-in pneumatic handling system for the final design.
An additional concern was that the spent material be sent for recycling at an environmentally acceptable site. Representatives from BP Amoco and Synetix visited and audited the site of a large smelter and proved the route by shipping several bulk containers for recycling.
Gas-processing plantDense-phase gas from the CATS pipeline enters the terminal and passes through the reception facilities. These were commissioned in March 1993 (OGJ, June 7, 1993, p. 37) and provide the means to receive pigs from offshore and remove any liquids or particulates from the incoming gas.
The incoming gas passes through the slug catchers that removes any liquids in the gas by gravity. The gas is filtered with coalescing/separator filters to remove any fine particulate matter and entrained liquid droplets before downstream processing.
Any liquids collected in the slug catchers and inlet filters may be pumped to the raw NGL metering systems.
The reception facilities were built ahead of the processing facilities, allowing transportation of the gas to a downstream processor. As more contributors joined the CATS pipeline, it became necessary to add more facilities (OGJ, Feb. 12, 1996, p. 22). This expansion consisted of gas treatment and two processing trains.
Phase 1 was commissioned in May 1997, and Phase 2, which is virtually identical to Phase 1, began operating in February 1998.
Fig. 4 [193,384 bytes] shows the process flow scheme for the complete CATS system.
Gas from the reception facilities then enters the gas-treatment section where it is split into two streams.
Depending on the H2S content of the incoming gas, a proportion of the gas passes to two large fixed-bed reactors in a lead/lag arrangement. These are charged with Puraspec absorbent that removes the H2S and mercury from the gas.
The remaining portion of gas bypasses these main treatment vessels and flows through two parallel reactors charged with Merespec absorbent to remove mercury from the gas. The two streams are then blended to achieve the H2S specifications of the various redelivery streams.
The hydrocarbon content of the gas is identical for all streams before processing. The bypass is controlled via setpoints from the inlet H2S, export H2S, and export flow rate and adjusts the bypass flow rate accordingly.
The treated gas passes through a dust filter and, depending on the hydrocarbon dewpoint of the gas, can either pass to the dewpoint-reduction facilities or to the three redelivery points.
The dewpoint facilities cool the gas to 0° C. by heat exchange against cold gas from the dewpoint separator. The gas is then further cooled by pressure reduction of 93 bara across a Joule-Thomson (JT) valve.
The gas and liquid phases are separated in the dewpoint separator and the residue gas at a minimum of -5° C. is heated first by exchange with the feed and then with a heater to avoid condensation in downstream equipment.
This part of the plant has yet to operate.
The dense-phase gas then flows to the redelivery points Ex1, Ex2, and Ex3. Ex1 is for the CATS processing facilities; Ex2 and Ex3 are for downstream processing by third parties.
Ex1 processing consists of two identical processing trains, each capable of processing gas to the specification of the National Transmission System (NTS).
The CATS plant gas is dried with a TEG contactor with the Coldfinger regeneration process. The dried gas then flows through heat exchangers that cool the gas to -12° C. by contact with cold gas. The gas can then pass through a JT valve where the pressure and temperature are dropped to 60 barg and -29° C., respectively.
Phase 2 is also provided with a turboexpander coupled to a generator that raises 3.5 mw of electric power for use on the terminal. The stream of gas and liquids produced is passed to a low-temperature separator where it mixes with liquids from the turboexpander inlet separator.
The gas is then heated by exchange with the feed gas and an oil-fired heater to meet the minimum export-temperature specification and is then combined with the stabilizer overhead gas before being metered and exported to the NTS.
The metering includes a gas chromatographic analysis to determine the composition of the gas and hence ensuring compliance with NTS specification. There is a provision for injection of nitrogen upstream of the metering unit to allow control of the heating value and Wobbe Index.
LPG fractionationLiquids from the low-temperature separator are flashed to 24 bara across a level-control valve and fed to the top tray of the stabilizer column. The flash gas combines with vapor leaving the top tray and passes to the stabilizer overhead compressor and after compression is mixed with residue gas for export metering.
The flashed liquid feed is fractionated in a column with a hot-oil heated reboiler to remove ethane and lighter gases. The stabilized liquid is supplied to the LPG-fractionation unit recovering C3, C4, and C5+ for export by pipeline to local users.
The unit is of conventional design with hot oil heaters and air coolers. At low feed rates to the terminal, the liquids production is extremely low, and in this scenario tray loading may be increased by recycling propane or butane back to the stabilizer.
The design of the plant includes a fractionation mode, allowing for periods of operation on either the depropanizer or the debutanizer alone.
For periods when liquid export is not achievable, the stabilizer temperature may be increased to 189° C., resulting in a bottom liquid product to the specification of the C5+ stream and the resultant gas, although rich in hydrocarbons, is capable of achieving the export specifications of the NTS
Operating experienceThe CATS terminal was constructed under alliance partnership contracts drawn up to embody the Crine principles with the main players. 4 [Editor's note: Crine = Cost Reduction Initiative for the New Era, a program espoused and promoted by U.K. offshore operators.]
This ensured a high level of commitment not only for the construction phase but also in meeting operating targets. This process was extended into the Synetix/CATS relationship that is now based on operating effectiveness, not on the amount of product used.
The plant was completed on time and within budget. Early operation has been largely trouble free with new fields being added with minimum difficulty. The fixed-bed gas treating units have been shown to give a simple low-pressure-drop method for H2S and mercury removal.
The pneumatic handling system gave problems at first because of absorbent breakage. This led to further work to optimize the air velocity and geometry of the transfer lines.
The futureCATS 1, came on line in October 1997. An identical unit, CATS 2, was successfully commissioned in October 1998. This has enabled the terminal regularly to process 1.3 bscfd of gas.
Following successful commissioning of the remaining two fields to be brought on line, CATS will transport and process approximately 1.7 bscfd of North Sea natural gas.
In the future, there is room-and planning permission has been granted-for two more processing units, and the addition of a short pipeline in parallel to the existing CATS pipeline would enable the site to handle 3.4 bscfd of gas.
AcknowledgmentsThe authors wish to thank CATS' owners for permission to publish this article.
- Craig, R.M., "The CATS/Central Graben Development Project," GPA and SONG Conference, Wilton, U.K., 1993.
- Phase Equilibrium in Mixtures, Vol. 9, King, International Series of Monographs in Chemical Engineering.
- Carnell, P.J.H., Openshaw, P.J., and Woodward, C., "A Fresh Approach to Mercury Removal from Natural Gas and NGLs," Poster Display, LNG 12 Perth, Australia, 1998.
- Macon, R., and England, J., "CATS in CRINE," CRINE Conference-Learning to Survive, London, 1996.
Elizabeth F. Rhodes is a plant process engineer for BP Amoco at the CATS terminal. She joined the company in March 1997. Previously, she was a process engineer for ICI Katalco. She graduated in 1995 from the University of Teesside with a degree (first-class honors) in chemical engineering.
Paul J Openshaw is gas-processing technical manager for Synetix, formerly ICI Katalco, Billingham, England. He holds a BS (1983) in chemical engineering from Loughborough University of Technology.
Peter J. H. Carnell is a gas-processing consultant. Previously, he was the gas-processing business manager for Synetix. He holds a BS and PhD in chemistry from the University of Southampton and has held a post-doctoral fellowship at the Ames Institute for Atomic Research.
Copyright 1999 Oil & Gas Journal. All Rights Reserved.