Summary
Hydrate plugs were formed above the mudline 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
because of hurricane evacuation. Several unsuccessful attempts to melt the
hydrate blockages included pumping methanol through the chemical injection
lines below the plugs and lubricating in glycol above the plugs. As a last
attempt, before using 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 the hot oil with the elastomers and
possible asphaltene or paraffin precipitation in the annulus. Sensitivity
studies show that with a 1-bbl/min injection rate and 150°F injection
temperature, the pressure-temperature condition inside the tubing located 3,000
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 because of hurricanes, two dry tree oil wells in the
Gulf of Mexico were suspected to have hydrate plugs formed above the mudline.
Even though an anti-agglomerate low dosage hydrate inhibitor (AA LDHI) was
believed to be injected into the wells before shut-in, a hydrate plug was
suspected to have formed inside the production riser above the mudline. Further
analysis showed that an inadequate amount of LDHI was injected because of
unknown problems with the injection skid. Hydrate formation was supported by
the pressure build-up in the tubing when injecting crude to confirm the surface
controlled subsurface safety valve (SCSSV) had opened. 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.
Literature Review
Searching in SPE elibrary, four relevant papers were found relating to
authors’ experience in dealing with hydrate remediation issues occurring in
subsea equipment during drilling, in the string above the mudlines during well
test operation, in the subsea Christmas-tree cap, and in the riser attached to
the floating production storage offloading (FPSO) vessel. One paper discussed
options available to remove hydrate blockage from the choke and kill lines
during offshore drilling operations.
Yousif et al. (1997) evaluated several options to remove a hydrate blockage
from the choke and kill lines that could occur during deepwater offshore
drilling operations. The options included radial heat tracing, pipe warm-up,
and hot water circulation through coiled tubing. The authors also presented a
complete mathematical formulation of the energy balance of the hydrate melting
process. The effects of heat flux, hydrostatic pressure over the plug,
insulation thickness and quality, water circulation rate, and inlet water
temperature on the melting process were investigated. The authors found that
the controlling parameters are the heat flux, the quality of the insulation
material, and the water circulation rate. The authors also found that heat
tracing is a viable technique to either melt a hydrate plug or prevent hydrates
from forming in the choke and kill lines. The hot water circulation technique
can be used if coiled tubing intervention is permissible. For heat tracing and
hot water circulation methods to be successful in melting hydrate plugs, the
authors suggest insulating the choke and kill lines to preserve the delivered
heat that will otherwise dissipate to the ambient.
Barker and Gomez (1989) discussed two deepwater wells that experienced
hydrate plugging in subsea equipment during drilling operations. The first case
described an occurrence of hydrates because of gas influx from the formation,
channeling through the cement column, and migrating up the 7×9 5/8-in. casing
annulus. The leaks on the wellhead hanger pack-off allowed the migrating gas to
enter the freshwater mud at the subsea wellhead. After the kill operation, to
stop the gas influx, both the choke and the kill lines were found plugged.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
14 February 2006
- Meeting paper published:
1 May 2006
- Revised manuscript received:
10 November 2006
- Manuscript approved:
28 December 2006
- Version of record:
20 November 2007
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