The subject well was a subsea producer in the Gulf of Mexico exhibiting pressure loss from its production annulus. An approximately 40 mL/minute (15 psi/hour) leak was identified via logging techniques during a riser-based intervention campaign. This leak was then determined to be past the production packer element set. The well was isolated and the data was reviewed to identify forward options. Though considered, a riser-based intervention was eliminated as an option to restore integrity and return it to production due to technical, scheduling, and economic considerations. Based on these constraints, the operator opted for a sealant remediation approach.

The operator considered multiple sealant products, ultimately working with an engineered sealing solution provider to analyze all available data to evaluate leak characteristics while still progressing other contingencies. From these parameters, a subsea sealant blend tailored to the application was prepared and successfully tested to confirm its suitability for this application. A remediation procedure was then developed to fill subsea bladders with sealant, which were then spotted on the sea floor to inject the sealant into the annulus through a Well Stimulation Tool, Bass Adapter, and Tree Running Tool utilizing an engineered lubricate and bleed volumetric injection technique. Because the annulus was fluid packed, a series of four lube and bleed cycles were performed to compress annular fluid with sealant and bleed back completion fluid to a host platform via the flowline. The selected blend of sealant was approximately 240 kg/m3 heavier than the packer fluid to facilitate its fall and allow for fluid swap in between cycles. This ensured only annular fluid was being bled off, rather than the injected sealant. After the final cycle, annular pressure was maintained at the maximum threshold for a cure period before testing the repair.

Within one day following the final lube and bleed cycle, the sealant had successfully accumulated on top of the packer as designed. The applied pressure maintained during the cure period had activated the sealant and the annular pressure remained steady over the operator's monitoring period. Given these positive indications, the operator tested the repair with no pressure loss over the test interval. All internal and regulatory requirements had been satisfied, allowing the well to be returned to production.

This sealant was designed to polymerize at the packer elements, which provided the needed pressure differential. This differential triggered a chemical reaction, thereby creating a flexible, solid seal only at the leak site. This newly formed and tested seal was designed to furnish a seal for the forecasted production profile and excess sealant would remain liquid above the packer. In the event that the leak was to return, the operator would have the capability to perform an annular pressure manipulation sequence from the host platform to activate residual sealant, thus re-establishing integrity.

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