Hydrate Remediation in Deepwater Gulf of Mexico Dry-Tree Wells: Lessons Learned
- Amrin F. Harun (BP Egypt) | Thomas E. Krawietz (BP America) | Muge Erdogmus (BP America)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2007
- Document Type
- Journal Paper
- 472 - 476
- 2007. Society of Petroleum Engineers
- 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 4.3.3 Aspaltenes, 3.1.6 Gas Lift, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 1.14 Casing and Cementing, 4.5 Offshore Facilities and Subsea Systems, 4.3.1 Hydrates, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 4.1.2 Separation and Treating, 4.5.3 Floating Production Systems, 4.2.4 Risers, 5.2.2 Fluid Modeling, Equations of State, 4.3 Flow Assurance, 5.3.2 Multiphase Flow, 1.3.2 Subsea Wellheads, 5.6.4 Drillstem/Well Testing, 1.6 Drilling Operations, 5.4.2 Gas Injection Methods, 5.1.1 Exploration, Development, Structural Geology
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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.
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.
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.
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