H2S CONTROL KEEPS GAS FROM BIG OFFSHORE FIELD ON SPEC

May 27, 1991
George W. Spicer British Gas Plc Barrow in Furness, U.K. Colin Woodward ICI Katalco Billingham, U.K. Rising H2S levels in natural gas from western U.K.'s Morecambe Bay field threatened in 1988 to restrict gas production. Installation the next year of a chemical absorption process at the onshore terminal has solved the problem. The field was discovered in 1974 by Gas Council Exploration, a wholly owned subsidiary of British Gas plc. The project to develop the field commenced in January 1980
George W. Spicer
British Gas Plc
Barrow in Furness, U.K.
Colin Woodward
ICI Katalco
Billingham, U.K.

Rising H2S levels in natural gas from western U.K.'s Morecambe Bay field threatened in 1988 to restrict gas production.

Installation the next year of a chemical absorption process at the onshore terminal has solved the problem.

The field was discovered in 1974 by Gas Council Exploration, a wholly owned subsidiary of British Gas plc. The project to develop the field commenced in January 1980 against the background of escalating world oil prices.

Production began on Jan. 8, 1985. A maximum daily production rate of 1,587 million scfd (MMscfd) was achieved on Feb. 7, 1991.

BARROW TERMINAL

The development of the Morecambe Bay gas field is the largest single venture undertaken by British Gas. The field, with reserves of 6 tcf (170 billion cu m), is the second largest entirely within U.K. waters.

Phase 1 development offshore consists of seven platforms. Three bridge-linked platforms form a central complex of accommodation, central processing, and local drilling platform. Four remote drilling platforms are linked to the central processing platform (Fig. 1).

The gas produced offshore is received at the Barrow onshore terminal where it is processed to ensure that contract-quality conditions of water and hydrocarbon dew point, odor intensity, hydrogen-sulfide content, specific gravity, and calorific value are achieved.

The land facilities are designed to process between 100 MMscfd (0-12 million cu m/hr) and 1,200 MMscfd (1.4 million cu m/hr). Peak flowrates of 1,587 MMscfd (1.77 million cu m/hr) have been achieved, meeting more than 10% of the U.K.'s peak-day demand for gas.

A feature of the operations is frequent, rapid changes in production rate to assist in matching supply and demand.

In addition to the gas-conditioning operations, significant quantities of associated liquids are received. At peak production rates, 200,000 gpd (910 cu m) of liquids are received which require stabilizing and sweetening to convert odorous sulfur compounds (mercaptans) to less noxious disulfides.

As drilling progressed, it was found that the wells produced gas with differing quantities of H2S. Urgent action was required to ensure the sales specification for H2S (below 3.3 ppmv) without limiting production from the field. This problem was overcome by the application of fixed-bed, sulfur-removal technology (ICI Puraspec) commissioned in 1989.

OFFSHORE PROCESSING

The Morecambe Bay gas field is approximately 23 miles west of the Lancashire coast. The average water depth is 1 00 ft with a tidal variation of 30 ft.

The reservoir is 3,6003,900 ft (1,100-1,200 m) below the seabed. The field comprises two separate reservoirs with present developments having taken place for the southern lobe which contains 75% of the total reserves. The northern lobe will be developed later as a separate entity. Four drilling/production platforms are installed remote from the central complex.

On each drilling platform, gas is produced from a series of wells. Slant drilling was employed to enable an effective circular area of 3 km (1.8 miles) diameter around the platform to be drained.

The produced gas is treated in a production separator to remove free water. The gas and condensate from the remote drilling platforms pass into 24-in. infield pipelines to the central processing platform.

Monoethylene glycol is injected at the drilling platforms to prevent hydrate formation. This is recovered and regenerated at the central processing platform and returned through a 2-in. line to the remote platforms.

Treatment on the central processing platform consists of two principal operations (gas and liquid separation) followed by gas dehydration.

Glycol-inhibited gas from the drilling platforms is passed through a slug catcher to separate liquids. The gas is dried by contact with triethylene glycol (TEG) in three dehydration trains. The separated condensate is pumped through coalescers which reduce the water content to less than 100 ppm.

The dry gas and condensate are passed into a 36-in. pipeline which carries the gas and liquids 26 miles to the terminal for further treatment.

The gas flowrate determines whether the condensate is received at the terminal as a slug of liquid or as a mist in the gas phase. At flowrates greater than 16.7 million std. cu m/day (MMscmd; 600 MMscfd), turbulence in the gas stream causes the condensate to be carried as a mist of liquid droplets.

At lower flowrates, there is insufficient turbulence in the gas stream to keep the liquid in suspension, and it settles out to form extended pools in the bottom of the pipe. A large volume of liquid can be stored in this manner, and spheres or pigs are used to clear the liquid hold-up into the terminal slug catcher.

This is particularly significant for Barrow terminal which was designed to operate as a peak-shave supply.

In an extreme instance, terminal throughput has been increased from 0 to 800 MMscfd within 1 hr. The liquid inventory of the pipeline is often cleared by high production rates rather than pigging.

ONSHORE CONDITIONING

The Barrow terminal is located just outside Lake District National Park, and the adjacent coastline is designated an "Area of Special Scientific Interest."

Planning consent required that the visual impact of the terminal be limited in terms of heights of all structures: maximum 100 ft. Noise is limited to a maximum of 30 db at the site boundary, and no detectable odors are allowed.

Landscaping around the terminal has reduced the visibility of the processing units and created a nature trail.

The gas and liquids from offshore enter the terminal through an inlet shutdown valve (Fig. 2). A pig receiver is provided at the end of the offshore pipeline for recovery of pigs or spheres used to clear the liquid hold-up from the sea line.

The gas and liquids are Passed to a slug catcher which consists of eight legs of 42-in. pipe, 1,070 ft in length, with a 1-in-200 fall towards the liquid-collection manifold.

At low throughputs, this vessel is used to hold and separate slugs of liquid pushed out of the offshore pipeline by pigs. At higher throughputs, when a two-phase flow is established in the offshore pipeline, liquids are separated from the gas by velocity change.

The gas phase leaves the vessel by vertical risers to a common manifold for further treatment in the dew point trains.

Three dew point trains are installed, two with a capacity of 8.35 MMscmd (300 MMscfd) and one rated for 16.7 MMscmd (600 MMscfd). The process route is similar for each train with the gas passing through a flow-control valve into an inlet separator.

The vessel removes any liquid carried over from the slug catcher or condensate formed by cooling over the inlet flow-control valve.

The gas is then passed to gas-gas exchangers where it is cooled to 14 F. by cold returning gas (Fig. 3). The cold gas from the gas-gas exchangers is further cooled to -4 F. in a chiller vessel, where the gas flows through the tubeside of an exchanger surrounded by low-pressure evaporating liquid Freon on the shellside.

The liquid hydrocarbons condensed by this temperature reduction are removed in a low-temperature separator. The cold gas now contains an acceptable level of condensable hydrocarbons expressed as the hydrocarbon dew point.

Meeting the refrigeration duty are four electrically driven compressors. Two 1,400-hp compressors serve the 8.35-MMscmd dew point trains, and there are two 2,680-hp compressors--one for the 16.7-MMscmd train, the other as an overall standby.

The gas stream leaving the low-temperature separator is warmed by heat exchange with the incoming gas in the gas-gas exchangers. Final heating is provided by heat exchange with glycol-water in a gas superheater.

The glycol-water having removed heat in condensing the Freon refrigerant returns the heat to the gas stream. The outlets from the dew point trains then combine into a 42-in. manifold.

The gas is filtered by four filter units in parallel, each designed to handle 16.7 MMscmd and to remove particles down to 1.5 mu.

The gas is then metered for fiscal purposes to an accuracy of more than 1%. The metering facilities consist of two sets of three 24-in. meter tubes, each containing an orifice plate.

The outputs from differential pressure, temperature, line pressure, and density transmitters are monitored by a line computer calculating mass flow and total energy.

Gas-quality characteristics are confirmed before the gas leaves the terminal. The following parameters are constantly monitored: calorific value, specific gravity, Wobbe index [calorific value divided by the square root of the specific gravity], H2S, total sulfur, water dew point, and hydrocarbon dew point.

Two back-pressure control valves in parallel are used to maintain the terminal pipework at 1,000 psi. This ensures that process conditions in the gas-treatment trains do not have to be adjusted as pressures in the national grid vary.

The gas leaves the terminal through a 42-in. pipeline and travels 30 miles to a mixing station at Lupton. Here the Morecambe Bay gas is blended with other supplies from the northern North Sea to achieve final gas-quality conditions of Wobbe number and calorific value.

Official gas-quality testing is carried out at Lupton for outlet feeders to Blackrod and Warburton.

CONDENSATE PROCESSING

Condensate separated in the slug catcher and dew point control trains is passed through a common pipeline to the stabilization area. Dissolved methane and light ends are driven off from the condensate to give a final product suitable for safe storage and shipment.

The condensate contains approximately 100 ppm of noxious sulfur compounds (mercaptans). In order to prevent odor complaints from storage in floating roof tanks or during marine-loading operations, a sweetening plant was installed in which the odorous mercaptans are oxidized to less noxious disulfides.

Condensate from the stabilization plant is passed through three stages of treatment. It is initially washed with dilute caustic solution to remove acid gases and then oxidized within a fiber-film contactor with caustic solution. A cobalt-based catalyst is added to the caustic phase to promote oxidation.

The final treatment stage utilizes a carbon bed impregnated with oxidation catalyst and caustic solution. The chemical reactions are the same as for the fiber-film stage with the carbon providing a large surface area for these reactions to take place. The grade of carbon used at Barrow provides 2,000 sq m/g.

A doctor-sweet product with 1-2 ppm mercaptan content is consistently achieved.

The condensate leaves the stabilization area at less than 14 psig Rvp and is routed to one of two floating-roof storage tanks each with a capacity of 2,385 cu m (15,000 bbl).

A smaller tank, with a capacity of 1, 1 92 cu m, is provided to store condensate which requires further processing.

The floating-roof tanks provide a buffer storage before the condensate is transferred in batches to bulk storage at a separate site at Ramsden Dock, Barrow.

Condensate export is by marine tankers with loads of 6,000-8,000 cu m (38,00050,000 bbl) being uplifted.

The tank farm at Ramsden Dock provides storage and facilities for shipment of the condensate. Five tanks, each 118 ft diameter and 19.5 ft high, have a storage capacity of 203,000 cu ft. This represents storage for 29 days' operation at maximum rate.

H2S REMOVAL

Under the terms of the 1986 Gas Act, the maximum concentration of H2S permitted in the gas supply system is 3.3 ppm (5 mg/cu m). For the majority of supplies into the British Gas transmission system, the H2S concentrations are typically less than 0.5 ppm.

As the drilling program progressed for the Morecambe field, H2S levels became a more significant feature with most individual well concentrations varying between 2 ppm and 6 ppm. One well had an H2S content of 22 PPM.

Initial action was taken to reduce the effect of this by the H2S content being recognized within the ranking sequence for production from the wells.

At lower production rates, therefore, the total H2S content of the gas was within the statutory limits but at maximum production, with all wells in operation, the H2S level reached 4.5 ppm.

Because Morecambe gas is mixed at Lupton with supplies from the North Sea fields to achieve a final gas quality, higher levels of H2S from Barrow could be accepted. On a number of occasions during the winter of 1987-88, however, H2S levels approached the alarm settings at Lupton.

British Gas approved the installation of an H2S-removal unit to ensure that peak supplies from Morecambe were not constrained and that H2S levels in the transmission system were held to a minimum. An evaluation of available process routes included the use of liquid solvents, direct conversion, and dry-bed processes. This confirmed a dry-bed process to be the favored scheme technically, economically, and environmentally.

Fixed-bed absorbents are widely used in the petrochemical industry for purification of feedstocks to catalytic processes. Absorbents are flexible to rapid changes of throughput and environmentally friendly in that there are no vents, no flares, no noise, and no potentially problematic effluents.

Puraspec had initial commercial application on Amoco's NW Hutton platform in the U.K. North Sea. The process consists of chemical absorption of parts per million (ppm) levels of H2S from hydrocarbon gases and liquids by fixed-bed absorbents normally at 40-400 F.

The design conditions for the Barrow unit were the following:

  • Flow rate 1,200 MMscfd (peak 1,400 MMscfd)

  • Temperature 2-15 C. (36-59 F.)

  • Operating pressure, 66 barg (957 psig); design pressure, 99.3 barg (1,440 psig)

  • H2S inlet, 5.0 ppmv; outlet, 2.75 ppmv.

The outlet H2S figure was selected as 2.75 ppm (nominal 3 ppm) to allow for any instrument inaccuracies with the "on-line" H2S control analyzers.

The vessel design was undertaken by ICI, and the volumes were sized to give sufficient absorbent for 1 year's operation at a 60% load factor. In this way, absorbent recharges could be avoided during the winter peak gas demands and scheduled into the summer period of lower production.

It was also important that the unit not significantly increase the pressure drop over the terminal, and two large-diameter vessels were selected (15 ft diameter).

ICI also designed the inlet and outlet-gas connection points to minimize the total unit pressure drop to less than 1.4 bar (20 psi).

The unit was situated downstream of the dew point control trains and upstream of the gas filters. In this way the gas routed to the unit is water dry (dew point -40 F.) and with a low hydrocarbon dew point. The downstream gas filters protect against any dust which might be carried over in unforeseen circumstances.

The system consists of two identical vessels, in series, with piping to allow either to be in the upstream "lead" position, and with vessel bypass lines which allow the absorbent to be replenished during the operating period (Fig. 4).

The treatment unit removes all H2S from the gas being processed and this is then mixed with by-passed gas, which is untreated, to achieve a nominal outlet concentration of 3 ppm. The unit throughput and the proportion by-passed are controlled by on-line H2S analysis of the gas leaving the terminal.

During operations under design conditions, the specification is achieved by the processing of 45% of the gas, while by-passing 55%. To monitor the movement of the sulfur-absorption front, sample points are located within the vessel at positions 25%, 50%, and 75% down the bed.

Essential pipework tie-ins were carried out during the summer shutdown period 1988 followed by civil and mechanical works. The vessels were delivered from Italy during April 1989, and following installation and absorbent loading, the unit was commissioned in May 1989 just 12 months after start of the project. The 2-day commissioning trials involved processing the maximum design flow through the unit and confirmed the system pressure drop, bed characteristics, and the absence of dust in the gas filters.

OPERATING EXPERIENCE

Following commissioning, the unit remained on standby through the summer of 1989 but has operated almost continuously since November 1989. Up to Dec. 31, 1990, 28 bscf of gas had been passed through the Puraspec unit. During the same period, the terminal processed 174 bscf. On average, therefore, it was necessary to treat only 16% of the total gas throughput.

This was achieved by effective management of the higher H2S wells enabling the unit to be by-passed at lower production rates. Daily flowrates have varied from 150 MMscfd (summer) to 1,400 MMscfd (winter).

At present the absorption front is contained within the lead vessel. Clearly, with both throughput and inlet H2S levels below the design figures, even with prolonged operation, the change-out interval will be longer than the scheduled 1 year.

No absorbent was replaced during 1990 and the need to make even a partial bed change in 1991 is currently being evaluated.

Installation of this fixed-bed system has provided the flexibility to handle significant variations in flow rate and inlet H2S concentrations with minimum operator attention.

In practice, H2S levels are controlled at less than 2.5 ppm for the gas exported from the terminal giving less than 2 ppm in the blended gas leaving the mixing station at Lupton. The system has operated to give lower H2S levels when variations with the blending gas quality have been experienced.

Studies to upgrade the terminal output to 1,800 MMscfd are being carried out. It is likely that this can be achieved without significant modifications to the Puraspec system.

ACKNOWLEDGMENT

The authors would like to thank the managing director, western regions, national transmission system and construction of British Gas for his permission to publish this article. Thanks are due in particular to C. H. Brown who served as project director for the Morecambe Bay development.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.