OFFSHORE DESULFURIZATION UNIT PERMITS GAS LIFT OPERATIONS

Andre Cabes, Jean Elgue, Jacques Tournier-Lasserve
Societe Nationale Elf Aquitaine
Paris

The installation of a desulfurization unit for the Tchibouela oil field, offshore Congo, allowed produced low-pressure associated gas containing CO2 to be kept for gas lift operations while, for safety reasons, the large volume of H2S at low pressure was removed prior to compression.

Since October 1989, the world's first offshore amine sweetening unit has worked satisfactorily and continues to prove that it is an attractive production alternative.

For desulfurization, a selective methyldiethanolamine (MDEA) process, developed by Elf Aquitaine, was chosen because it was the only process that met the required specifications at a low pressure of 3.5 bar (51 psi).

RESERVOIR

The Tchibouela field has a shallow oil reservoir between 500 and 600 m (1,640-1,969 ft) below sea level. The field is in 85 m (279 ft) of water in the Guinea Gulf. Distance from Pointe Noire, Congo, is 35 km (22 miles).

The field, owned jointly by Elf Congo and AGIP, is operated by Elf Congo, which holds a 65% interest in the project. Field facilities (Fig. 1) include two well satellite platforms (TAF1 and TAF2), one production platform (TAP), and one flare platform (TAT).

The daily oil production, metered water free, is 9,000 cu m (56,600 b/d). Part of the associated gas, around 400,000 cu m/day (14.1 MMcfd) is used as fuel and also for gas lift.

Gas lift is needed when the wellhead pressure is too low or when the well does not flow naturally. To lighten the oil column, the gas is injected into the lower part of the tubing. Well productivity is also sustained by injecting water to maintain reservoir pressure. The main functions on each platform are summarized in Table 1.

DESULFURIZATION

The composition of the associated gas is given in Table 2. The presence of H,S raises the problem of personnel safety as well as presenting, a corrosion potential.

The safety aspect is all the more important because these are offshore installations. Consequently, the gas must be desulfurized, preferably before compression and at low pressure.

The desulfurization option is a problem because of platform dimensions but it does provide for additional safety.

The maximum H2S Content of the treated gas is set at 100 ppm by volume under normal operating conditions and at 1,000 ppm by volume in a downgraded mode.

The analysis of both the economical and technical aspects of the two processes, i.e., DEA (complete diethanolamine deacidizing) or MDEA (selective methyldiethanolamine desulfurization), favored the latter. Therefore, the MDEA process was selected.

MDEA is a tertiary amine. The characteristics are summarized in Table 3.

Selective absorption of H2S in relation to CO2 is a fundamental property of tertiary amines. The process is explained by the chemical reaction mechanism leading to the formation of salts between H2S and amine and between CO2 and amine.

Table 4 lists the major difference between the primary or secondary amines and the tertiary amines. While the reaction of H2S with MDEA is direct and fast (transfer of protons), CO2 must first react with water to form carbonic acid (slow reaction) and then it must react to produce amine carbonate and bicarbonate.

This difference in reaction velocity may be used to perform selectivity in relation to H2S. The gas-liquid contact time in the absorber is the basic control parameter.

PROCESS CONSTRAINTS

The following constraints on the process had to be accounted for:

Offshore unit
Treatment of low-pressure gas
Significant variations in feed flow rate and in gas composition
Possible operation in downgraded mode.
Provisions were made to operate the unit at full capacity with only 60% of the solvent flow rate. The H2S content of the treated gas will be held to less than 1,000 ppm by volume.
Seawater used as cooling fluid.

CONSEQUENCES

The selected process (Fig. 2) shows certain differences in comparison with a traditional process. The most noticeable are the need for pumping rich amine and the absence of a flash drum.

Also, to ensure maintenance without having to shut down the unit, the exchangers and condensers have been redesigned. These consist of two vessels operated in parallel, each able to provide 60% of the total thermal requirements.

To reduce bulk clearance and facilitate modular construction of the unit, the best solution was to group the regenerator and acid gas scrubber together. ln addition, wherever possible, plate exchangers were selected instead of the traditional types.

It was also necessary to adapt the amine filtration technique. The precoat filter has been replaced by a cartridge filter that is smaller and requires no solid product storage or handling (e.g., cellulose).

To ensure the flexibility required upon variations in the flow rate or in the supply gas composition, the absorber is provided with four amine inlets at different levels. It is thus possible to modify the number of plates in the absorption operation mode.

The platform environment concept has not originated any particular constraints in the selection of materials. Carbon steel is systematically used for vessel works. Because seawater is the only available cooling fluid, composite materials were chosen for the seawater inlet and outlet lines. Titanium is used for the trim cooler plates for regenerated amine.

CONSTRUCTION

Technip Geoproduction (TPG) was entrusted with the detailed engineering studies together with studies for other modules of the TAP platform.

The unit, except for the MDEA buffer tank but including the injection water deaeration column, as well as the fresh water storage facilities, had to be contained in a space 11 m long x 8 m wide x 25 m high.

A model had to be constructed to allow for positioning each piece of equipment vertically in relation to one another. Different parameters were considered such as traditional process constraints, restricted surface area, and the need to provide equal space between each circulation deck.

Similarly, the layout of the connecting lines between the different pieces of equipment has often been subject to contradictory constraints. For example, it was necessary to find a compromise between the shortest line requested by the process and the straight length required for metering the flow rates, especially gas flow rates.

Fig. 3 illustrates how and where the MDEA unit is located on the TAP platform.

Ateliers et Chantiers Marseille Provence (ACMP) was contracted for the construction of the units in September 1987. This company went into liquidation and was taken over by Sud Marine Industrie. This change resulted in a 6-month delay for the project. The work was finally finished, and the various elements were installed on a barge in February 1989.

The construction phase was supervised by an Elf Aquitaine team that was in charge of checking the technical, administrative, and contractual aspects.

START-UP

The transportation on barge of the various decks and units from Marseille to Tchibouela, the hoisting (the MDEA unit weighs 380 tons), and the hookup operations took place between March and August 1989.

Commissioning and start-up of the MDEA unit were carried out between September and November 1989 under the supervision of the process department engineer who had designed the original project.

The first step was to set up the preparation phase and gas supply of the unit which included the following:

Setting the blinding scheme
Checking the installation and internals
Blowing the gas networks
Rinsing the liquid networks
Chemical washing and rinsing.
Testing for leaks
Deaerating the unit, loading and preparing the solvent.

By checking the whole installation, nonconformity of some equipment was noticed. Also discovered were some unavoidable slight errors such as the boiler being too low in relation to the bottom of the regenerator, the flow from the amine drains going to the polluted water tank instead of the amine recovery drum, and the absence of an inlet deflector in the reflux drum.

As a consequence, modifications had to be done on site. This prolonged the commissioning operations by 2-3 weeks.

These problems confirm that the equipment and units designed for offshore operations should receive more thorough checking and acceptance procedures at the manufacturer and the construction site than if they were designed for onshore operators.

Modifications then could be made at a lower cost and in a more favorable environment. The commissioning time would also be reduced.

After these various preparation phases, the unit was supplied with gas on Oct. 22, 1989. The first and only problem on this unit was the plugging of the first cartridge filter.

The filtration threshold had been set at 7 m by analogy with the traditional specification for a precoat filter. But the cartridge filter was more sensitive to clogging, especially during start-up. As a result, the filtration threshold had to be increased from 5 to 30 m, and then to 50 m after a few days.

After several weeks of operation, visual checks revealed that the amine was clear and clean and that there were no deposits. The filtration threshold was then fixed at 30 m.

Similarly, the filtration threshold for the second cartridge filter designed for stopping fine coal was increased from 25 to 30 m.

Apart from these filtration adjustments, the unit developed no particular problems. The gas lift contains only 50 ppm by volume of H2S. This is far less than required.

Coabsorption Of CO2 remains very low, between 20 and 30%, depending on the operating conditions.

OPERATIONS

The unit has been operating satisfactorily since 1989. However, one of the four plate exchangers showed some leakage problems. On site intervention was not successful and the vessel had to be sent back to the manufacturer. The unit has been restarted and now operates efficiently.

The gas lift requirements are expected to increase from 400,000 to 500,000 cu m/day (14.1-17.7 MMcfd). But the process is very flexible in regard to flow rate variations (25-100% nominal) and changes in the load composition.

Possible modifications required on the unit are now under study because the actual H2S content of the associated gas is 3.25% by volume, whereas the design is based on 4.32% by volume from a former analysis.

The MDEA option proved to be attractive again last year with the transfer of a license together with the study of a new selective desulfurization unit for associated gas in the North Sea, this time for the development of the Piper Bravo platform.