Nipple Down

Key Takeaways

• The sequence of a nipple-down operation on an onshore well begins with securing the wellbore against flow: a mechanical barrier (bridge plug set above the reservoir perforations, or cement plug if the well is to be abandoned) or a hydrostatic barrier (kill weight fluid at density sufficient to overbalance the formation pore pressure) is verified in place and documented in the well status record before any BOP component is loosened; API Spec 6A and IADC well control guidelines specify that at least one verified mechanical or hydrostatic barrier must be in place before BOP disassembly begins, and the company man or company representative on location is required to formally authorize the nipple-down before work commences; after barrier confirmation, the BOP stack is bled down to zero pressure (confirmed by a calibrated pressure gauge and bleed valve), all hydraulic control lines are disconnected and drained, the upper Kelly cock or top drive IBOP is confirmed closed, and the annular or ram preventer is confirmed open (rams in the open position allow the tubing or casing to pass freely during nipple-down without requiring hydraulic pressure to close them before removal).
• BOP stack weight management is a critical safety consideration during nipple-down on offshore platforms and onshore workover rigs where the BOP components weigh hundreds to thousands of pounds: a typical 13-5/8-inch 10,000-psi double-ram BOP unit (two sets of pipe rams or one pipe ram and one blind-shear ram) weighs 8,000 to 15,000 pounds (3,600 to 6,800 kg) excluding the annular preventer; before any bolts are broken in the flange connections between BOP components, the component above the connection being broken must be fully supported by the rig's traveling block, winch, or crane, with the support rigging pre-tensioned to the component weight so that the component cannot fall when the last bolt is removed; the rig floor layout must provide a clear path for moving the removed BOP components to the pipe rack, work basket, or storage area without placing them over occupied work areas; on floating vessels, the BOP is lowered from the wellhead on the marine riser string to the vessel's moon pool for BOP nipple-down at the rig floor level, reversing the nipple-up sequence in which the BOP was pressure-tested on surface before running to the subsea wellhead.
• Wellhead valve installation follows the nipple-down of the BOP stack in the well completion sequence: after the BOP is removed, the temporary wellhead top (the drive pipe or structural casing spool that was the BOP stack's base flange) is used as the mounting point for the permanent wellhead master valve (the lower master gate valve or ball valve that is the primary isolation valve in the completed wellhead), the wing valve assembly (a side-outlet valve for production flow to the flowline), and the Christmas tree (the assembly of valves, fittings, and choke that controls and monitors the well during production); the nipple-down and Christmas tree installation sequence requires that the wellbore remain under barrier control throughout the transition from BOP to Christmas tree, typically by maintaining kill weight fluid in the wellbore and using a temporary wellhead plug (a wireline-set plug in the casing or tubing hanger) to provide an additional mechanical barrier during the transition period when neither the BOP nor the Christmas tree is installed; API 6A specifies the pressure testing requirements for wellhead components after installation, and the completed wellhead must be pressure-tested before the well is placed in production.
• Nipple-down during workover operations (where the BOP must be removed and reinstalled to pull tubing, set new completion equipment, or perform recompletion) follows a well-kill procedure before BOP disassembly: the well is killed by circulating kill weight fluid (typically calcium chloride brine formulated to slightly exceed the formation pore pressure gradient) down the drill string or coiled tubing and up the tubing-casing annulus until the well is confirmed dead (no pressure on the annulus at the surface and the returns fluid is the kill fluid with no gas or formation fluid cut); after the well is killed, the kill fluid hydrostatic head is the sole barrier and the BOP can be nippled down once the well status is documented; some operators install a secondary mechanical barrier (a tubing plug run by wireline into a landing nipple in the top of the tubing string) before nippling down the BOP during workover, providing a dual-barrier system for the period when the BOP is off the wellhead; the kill fluid hydrostatic head calculation must account for the true vertical depth of the perforations (not the measured depth in a deviated well), the kill fluid density, and the conversion from fluid density to hydrostatic pressure: hydrostatic pressure (psi) = 0.052 x fluid density (lb/gal) x TVD (ft).
• Documentation and inspection requirements for the nippled-down BOP include recording the condition of all ram packer elements (checking for wear, cuts, or extrusion that would reduce the seal integrity in subsequent use), testing the hydraulic actuators, accumulators, and control lines (which may have been exposed to temperature cycling, pressure cycling, and wellbore fluids during drilling), and inspecting the flange faces, studs, and nuts for corrosion, galling, or damage that would prevent proper reassembly and pressure testing; API 16D and API 53 specify maintenance, testing, and inspection intervals for BOP equipment, and the nipple-down inspection provides an opportunity to conduct these checks while the stack is at surface rather than requiring a separate BOP retrieval from the subsea wellhead or a surface wellhead disassembly during production; any deficiencies found during nipple-down inspection are documented in the BOP maintenance log and repaired before the BOP is nippled up for the next drilling or workover job, ensuring that the equipment is certified fit for the next pressure envelope it will encounter.