Abstract

Hydrate plugs were formed above the mud line in two dry tree oil wells in the Gulf of Mexico. The plugs were formed when trying to open the downhole safety valve with crude to return the wells to production after they were shut-in due to hurricane evacuation. Several attempts to melt the hydrate blockage included pumping methanol through a chemical injection line below the plug and lubricating in glycol above the plug were performed without success. As a last attempt, before utilizing coiled tubing, injecting hot oil into the tubingcasing 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 the hot oil with the elastomers and possible asphaltene or paraffin precipitation in the annulus. Sensitivity studies show that with 1 bbl/min injection rate and 150oF injection temperature, the pressure-temperature condition inside the tubing located 3000 ft below the sea level will come out of the hydrate formation region within 4 hours. However, as the section goes deeper the warm-up time increases and at some point the conditions will not warrant being out of the hydrate region even after several days of injection time. Hydrate plugs in two dry tree wells melted after 6 and 60 hours of injection time, respectively. A revised restart procedure has been implemented to eliminate the hydrate problem in future startups.

Introduction

After being shut-in due to hurricanes, two dry tree oil wells in the Gulf of Mexico were suspected to have hydrate plugs formed above the mud line. Even though 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 unknown problems with the injection skid. Hydrate formation was supported by the pressure build-up in the tubing when trying to open the surface controlled subsurface safety valve (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 erformed including pumping methanol through the chemical njection line below the plug and glycol above the plug, but ithout success. Before going to a coil tubing option, injecting ot oil into the tubing-casing annulus was considered as the ast attempt.

Thermal-hydraulic transient analyses were performed to etermine injection temperature, pumping rate, and pumpingtime to inject hot oil through the annulus. The transient imulation results confirmed that the existing topside facilitieswere adequate to support the operation. Well integrity issues ere mainly associated with the compatibility of hot oil with lastomers and possible asphaltene or paraffin precipitation in he wellbore annulus.

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