Use of TEG-MeOH To Control Wellbore Hydrate Formation

Abstract

Technology Update The Southwest Kinsale (SWK) reservoir is part of the Kinsale Head reservoir in the Celtic Sea offshore Ireland. SWK was completed with three subsea wells tied back to the Kinsale Head platforms in 1999 (Well 3) and 2001 (Well 4 and Well 5). After initial depletion, SWK was con-verted to gas storage in 2001–02 and has been operated by PSE Kinsale Energy each year since. The storage is seasonal with injection in May to September and withdrawal principally from December to March. The nominal capacity is 8 Bcf with a maximum flow rate of approximately 95 MMscf/D. Background of the Problem The operation has experienced gas hydrate formation during the latter part of each withdrawal season since 2006. In 2011, the company decided to expand its storage business. Hydrate formation was identified as the key technical risk to that expansion. While the company has an excellent record of meeting withdrawal nominations, isolated incidences of hydrate formation have proved challenging. In March 2011, the company set up a structured program to understand and resolve the problem. The majority of the withdrawal uses “free flow,” i.e., reservoir pressure, to generate gas flow over the 7-km distance to the Bravo platform, which has a choke and flowmeter, and thereafter, the 5-km distance to the Alpha platform, where the withdrawn gas is processed by separation and triethylene glycol (TEG) dehydration. From there, the gas travels another 50 km to the shore terminal. The flow can be boosted during peak demand in the latter part of withdrawal by a boost compressor upstream of the TEG dehydration. Production gas from other reservoirs commingles upstream of the TEG process. There is neither downhole pressure nor temperature indication in the wells, nor is there a downhole chemical dosing point. On each Christmas tree between the master and wing valves, there is a chemical injection point (fed by two umbilical cores), a pressure sensor, and a temperature sensor. The hydrate inhibitor historically used was methanol (MeOH). No corrosion inhibitor is injected. The wells are in 90 m of water and completed at approximately 900 m total vertical depth below mean sea level. The reservoir temperature is approximately 27°C. Wells 4 and 5 are deviated while Well 3 is vertical.