Applying Well Remediation Techniques to Subsea Flowlines in Deepwater Gulf of Mexico
- Lisa Ann Hudson (Schlumberger) | Gregor Jon Bowen (Schlumberger) | Truman A. Breithaupt (Shell Exploration & Production)
- Document ID
- Society of Petroleum Engineers
- SPE/ICoTA Coiled Tubing & Well Intervention Conference and Exhibition, 31 March-1 April, The Woodlands, Texas
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 4.2.4 Risers, 2.4.3 Sand/Solids Control, 4.3.1 Hydrates, 4.3.4 Scale, 4.1.2 Separation and Treating, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers, 1.6.1 Drilling Operation Management, 4.3 Flow Assurance, 4.1.5 Processing Equipment, 3 Production and Well Operations, 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 1.6 Drilling Operations, 5.6.4 Drillstem/Well Testing, 4.5 Offshore Facilities and Subsea Systems
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Flow assurance in subsea production flow lines is becoming more prevalent as deepwater well developments continue to grow. Coiled tubing (CT), though traditionally used in wellbore environments, can be utilized to address flow assurance.
Complications are possible when applying CT technology in a nonconventional environment. Connection tie-ins and available deck area are typically incompatible with intervention-type activities, and challenging issues such as weight limitations, nature of blockage, and weather sensitive environments lead to the need for elaborate planning with multiple contingencies to address the uncertainties. Our study investigated the operational planning and logistical requirements associated with the radiation of the flow assurance for the Serrano flowline.
The Serrano flowline is located in the Gulf of Mexico (GOM), in 3,500 ft of water and is tied back 6 miles to the Auger TLP. Three subsea wells have produced through the electrically heated Serrano flowline since 2001. In November 2006, there was an unplanned shutdown of the flowline and despite numerous attempts to restart, the wells had failed to flow.
In December 2007, after 6 months of intensive and complex planning, a standalone CT operation was successfully performed while drilling operations continued on the main rig. The operations consisted of utilizing a unique small footprint compensation frame to allow access to the flowline from a confined area. Then a 1-1/2-in CT string was deployed into the flowline to retrieve a sample of the blockage for diagnostic purposes. The analysis of the sample dictated the optimal cleanout strategy which was to combine a specialized rotary nozzle with pumping diesel and solvents to successfully clean out the flowline. The blockage was breached at a depth of 3,700 ft after cleaning almost 1,000 ft in less than 24 hours. The flowline was reinstated and gas production restored to >2,000 bbl/d and 8 MMcf, thus preventing the client from losing the lease.
The Serrano flowline is tied back six miles to the Auger TLP platform and consists of 3 wells. The flowline is a single 6 in by 10 in pipe-in-pipe insulated flowline. The flowline and its counter part the Oregano are not only the first pipe-in-pipe single flowline systems but also the first use of an electrical heating flowline system. This heated system was used to aid in the reduction/elimination of potential hydrate formation due to subsea temperatures.
In August 2005, the hurricane Katrina evacuation caused a shut-in of the flowlines for 17 days. The flowlines were brought back online without incident. Shortly after the August shut-in, hurricane Rita, November 2005, caused another shut-in for a total of 78 days. The comparison of the well tests completed before each shut-in showed that production values were comparable and little to no loss was seen. The third shut-in was done in July 2006 for 2 days after which a small but noticeable reduction in productivity was seen. The flowline was shut in for 1 week in November 2006. Generator power to the EH (electrical heating) system was lost. Once the flowline was opened back up for restart, it would not flow. It was suspected that a hydrate formed in the flowline during the shut-in period, but other possibilities were sand and paraffin buildup. Pressure (2,800 psi) was applied from the riser side of the blockage; however, it failed to dislodge the plug. Methanol was then pumped down the riser to further prevent hydrate formation since it was possible that the EH system was not functioning properly. The top of the plug has been estimated to begin at approximately 2,200 ft to 3,500 ft, based on the fluid volumes pumped into the flowline from the TLP. There were some variations during the November 2006 shutdown compared to the previous shutdown operations, which include a blowdown of the flowline, a Chilly Choke back pressurization upon restart, and the injection of approximately 24 bbl of MeOH injected into the riser section.
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