document

Abstract

Hydrate plugs were formed above the mud line in three dry tree oil wells in the Gulf of Mexico. One plug was formed during slick line operations that caused the tool string to get stuck at ~3000 ft (above the mud line) while pulling out of the hole, even though the well was believe to have been freeze protected with LDHI. The other two plugs were formed when trying to open the downhole safety valves by pumping crude to return the wells to production after they were shut-in due to hurricane evacuation. Several unsuccessful attempts to melt the hydrate blockage included pumping methanol through a chemical injection line below the plug and lubricating in glycol above the plug. As a last attempt, before utilizing coiled tubing, injecting hot oil into the tubing-casing annulus was considered. Transient simulations were performed to determine the required injection temperature, rate, and time. Well integrity issues were mainly associated with the compatibility of hot oil with elastomers and possible asphaltene or paraffin precipitation in the annulus. The tool string came loose after 12 hours of hot oil injection. The hydrate plugs in the other two dry tree wells melted after 6 and 60 hours of injection time, respectively. The slick line operation was reviewed and recommended practices were put in place to prevent future hydrate blockages. A revised restart procedure has been implemented to eliminate the hydrate problem in future startups.

Introduction

A slick line operation was being performed in a dry tree well in the Gulf of Mexico when the tool string became stuck. A hydrate plug was suspected to have formed inside the production riser above the mud line. This was supported by the loss of movement of the spang jars. Estimated hydrostatic pressure and temperature inside the wellbore after shut-in were compared against the hydrate dissociation curve and shown to be favorable for hydrate formation.

On the other two dry-tree wells that had been shut-in due to hurricanes, hydrate plugs were suspected to form during opening the surface controlled subsurface safety valve (SCSSV) for bringing the wells back on production. Even though an an anti agglomerate low dosage hydrate inhibitor (AA LDHI) was injected into the wells prior to shut-in, a hydrate plug was suspected to have formed inside the production riser above the mud line. Further analysis showed that an inadequate amount of LDHI was injected due to calibration problems with the injection skid. Hydrate formation was supported by the pressure build-up in the tubing when trying to open the SCSSV by injecting crude. Estimated hydrostatic pressure and temperature inside the wellbore after shut-in were compared against the hydrate dissociation curve and shown to be favorable for hydrate formation.

Several attempts to melt the hydrate blockage were performed including pumping methanol through the chemical injection line below the plug and glycol above the plug, but without success. Before going to a coil tubing option, injecting hot oil into the tubing-casing annulus was considered.

Thermal-hydraulic transient analyses were performed to determine injection temperature, pumping rate, and pumping time to inject hot oil through the annulus. The transient simulation results confirmed that the existing topside facilities were adequate to support the operation. Well integrity issues were mainly associated with the compatibility of hot oil with elastomers and possible asphaltene or paraffin precipitation in the wellbore annulus.