A requirement 1 within a conventional offshore well's completion design per operator standard design and/or governmental regulation 2 is the installation of a "subsurface safety device." Among the list of permitted safety devices, subsurface safety valves (SSVs), if maintained properly, can fulfill such a requirement in well control and isolation.Whether it is of the surface-controlled (SC), subsurface-controlled (SSC), wireline-retrievable (WR), tubing-retrievable (TR), ball check, or flapper valve variety, subsurface safety valves can easily be damaged during through-tubing (wireline, coiled tubing [CT], etc.) deployment through the valve if steps, such as equalization before opening, slowing toolstring running speed, etc., are not taken to properly safeguard valve integrity. A problem that could occur during these deployments, specifically in reference to the SSV flapper-type valve, is shearing of the hinge pin on which the valve flapper rotates, allowing the flapper to "float" in a cavity directly below its rotation point, creating an effective downhole obstruction.A traditional intervention operation to repair this includes using a slickline (SL) rotating wedge to manipulate the flapper to a position that will allow a subsequent, suitably 3 sized sleeve installation through the cavity, bypassing the flapper. This will allow for both toolstring deployment past the obstruction to assist in future uphole recompletion operations and continued production without slugging from unexpected valve flapper reseating.This paper discusses a case history in which the above-mentioned conventional SL manipulation toolstring was deemed not suitable, as it was currently designed for a small cavity-type Tubing Retrievable Surface Controlled Subsurface Safety Valve (TRSCSSV), and alternative intervention means were developed. Five full-scale 4 tests were performed with four different toolstrings (one SL and three electric line [EL]) engineered to provide a method of inserting a bypass sleeve with predetermined minimum inside diameter requirements for future tubing cutter deployment. Of the four toolstring options developed, two were deemed field ready and deployed with the offshore operation itself, while the other two required additional engineered modifications. Details of the successful intervention deployment are also given in which desired flapper orientation and isolation was not only achieved by toolstring manipulation but also by well-production characteristics.Three benefits can instantly be noted from the developments and lessons learned. First, the toolstring solutions could be used for obstruction isolation of many varieties. Second, this rigless operation is part of the ongoing efforts in the Gulf of Mexico and elsewhere in the world to intervene in wells in the most economically feasible, least hazardous, and most expedited manner. Lastly, the intervention means employed here incorporates toolstring components readily available on the market. Lead time and operational use are minimized, and rig campaign schedules ...
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.
The decommissioning of wells and restoration of natural subsurface barriers which prevent hydrocarbon flow to surface, is a critical activity in well life which removes environmental impact for the future after oil/gas production facilities have been removed. Despite reduced rig/equipment costs, abandonment continues to be a substantial expenditure and represents a significant liability for operators in a cash constrained environment. While we see many efforts to reduce scope of abandonment and workover operations, engineered design and execution must comply with regulations as defined in the Code of Federal Regulations (CFR) without compromising safety. Abandonment and workover activities in the deepwater Direct Vertical Access (DVA) environment are typically conducted with a platform installed rig. However, there exists a significant amount of work involved in rig workover activities (cement plug installation, tubing cutting, circulation to workover fluid, etc) which do not require the physical workover unit itself and therefore can be accomplished "offline" both to save rig days, cost, personnel exposure, etc. In this context, "offline" will be defined as the time associated with activities that may be accomplished without dedicating critical path rig time to abandonment scope, reducing time and cost, assuming this identified rig would not otherwise be idle. Saved time may be used to provide value in a number of capacities from drilling and completing new wells to working over or abandoning another well. This paper discusses the case histories of two wells accessible via a deepwater Tension Leg Platform (TLP) in the Gulf of Mexico (GoM), both of which were scoped for conventional producer zonal abandonment and recompletion/workover activities. One would be worked over to another target production zone ~7000’ up-hole while the other would be worked over and converted into a new field injector for a major water flood project in the region. Through meticulous pre-planning, engineering design, and contingency development, the engineering and operations teams working on these two wells were able to reduce the critical path time of the work unit by realizing offline opportunities. These activities utilized conventional intervention techniques of slickline, electric line, and available pumping to both abandon these wells in an unconventional manner and ready the wells for immediate tubing pull once the rig was skidded atop. This was all done with full compliance with the CFR, in a "through-tubing" method, and satisfied abandonment conditions and operational safety requirements of the operator. While both wells noted significant savings either to acceleration of operation timeline or of first oil, the work conducted required decisive challenge management to succeed. The engineering decisions made, scope reductions identified, and trouble time events incurred will be discussed to the detail possible in this manuscript.
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