Severe corrosion and operating problems due to deposition of solids in an offshore gas re- injection system were investigated. Potential corrosion mechanisms were identified and matched to the morphology and location of the observed corrosion damage. Predicted corrosion rates were compared with observed corrosion rates. Carbon dioxide, hydrogen sulphide, oxygen, elemental sulfur, chlorides methanol and combinations thereof were considered. Corrosion due to elemental sulphur was identified as the mostly likely cause of corrosion. The sulphur drop was the result of reaction between hydrogen sulphide and oxygen following oxygen ingress into the sour process gas. Further corrosion was prevented by eliminating the source of oxygen ingress. This also solved the operational problems created by the solids.
High corrosion and operational problems due to severe deposition of solids in an Offshore Gas Re-injection system were investigated in 1999. This paper describes the approach used to evaluate possible corrosion mechanisms. The scope of the investigation included the following:
- Topside re-injection equipment and piping,
- Risers
- 31-km subsea pipeline from the manned platform to the wellhead injection satellite.
The effects of corrective measures are also presented.
BACKGROUND
Liverpool Bay is the only sour oil and gas development in the UK sector. The asset is situated in the Irish Sea just off the coast from Liverpool (Figure 1.) It consists of a central manned platform, Douglas, three unmanned platforms at Hamilton, Hamilton North and Lennox and a sub-sea single well completion at Hamilton East. There is an onshore gas-sweetening terminal at the Point of Ayr. Oil is produced from the Douglas and Lennox fields. Hamilton, Hamilton North, and Hamilton East are all gas producers. The pipeline network joining the facilities is shown schematically in Figure 2. Oil from the Douglas field is lifted by Electric Submersible Pumps (ESP's). Gas injection is used to recover oil from the Lennox field. The gas is compressed at the Douglas platform and transported to Lennox via a 12" API 5L x42 carbon steel pipeline. A simplified process diagram is shown in Figure 3. Re-injection gas is co-mingled gas from the Lennox Gas Receiver, the Lennox Production separator, and the Douglas Production separator. Gas stripped from the oil is also compressed and added to the process stream. The gas is sour, containing up to 2% H2S.
OPERATIONAL AND CORROSION PROBLEM
Extensive deposits and high corrosion rates were identified at the outlet channel of the Injection compressor aftercooler shown in Figures 4 and 5. This prompted a survey of downstream carbon steel piping. An extract from the results is shown in Figures 6 and 7. Corrosion rates were of the order of 3 mm/y but increased to 6 mm/y in the aftercooler nozzle where there was a flow effect as shown in Figure 8. The subsea pipeline was also surveyed by intelligent pig, which confirmed a corrosion problem in the subsea portion of the pipeline at the Douglas end as shown in Figure 9. The metal loss was confirmed by UT wall thickness checks carried out subsea by divers. A corrosion rate of 1.5mm/year was observed at the Douglas end of the sub sea section of the pipeline reducing to zero at the satellite end. This compared with 3 mm/year in the riser and topside piping.
At the time of the metal loss, large amounts of solids were recovered from the pig receiver and injection separator at Lennox. These were mostly iron sulfide but also contained elemental sulfur. Yellow deposits of element sulfur were found in Corrosion Resistant Alloy (CRA) pressure relief valves at the injection separator and in the
