The following recommendations refer to the application and maintenance of various types of other well control equipment: chole manifold,
Inside pipe shut-off tools, Mud-gas separator and trip tank, Mud pit level indicator and recorder,c High pressure mud and cement system, Storm chokes.
Choke manifold
For working pressure ratings over 13,800 kPa (2000 psi), the choke manifold shall be constructed in accordance with Company's procedure.
Alternatively, a choke manifold as already installed by the owner of the drilling unit may be acceptable, but only if approved in writing by the Company Rig Superintendent.
Whilst drilling, the block valves upstream of both chokes and valves downstream of the remote choke to the mud-gas separator shall be in an open position.
The remote choke shall be in an open position and the adjustable choke, shall be left in a closed position.
The remote choke is operated from a control panel installed near the driller's position.
The minimum recommended size for all choke lines and valves is 76.2 mm (3") through bore. Valve size and line bore size of BOP stack side outlets and valves, choke lines and choke manifold should be identical throughout the system.
Choke manifolds rated to 103,500 kPa (15,000 psi) shall have hydraulically operated valves upstream of any choke to assist in opening/closing valves under pressure quickly, thus minimising gate and seat wear.
Chokes should incorporate a suitable bleeder valve facility to ensure that the pressure can be released prior to removal of the bonnet nut. Hammer type threaded bonnet nuts are not recommended. Flanged or bonnet clamp connections are preferred.
Temperatures downstream of the choke are to be limited to the design temperature rating of the choke manifold.
Inside pipe shut-off tools
Two lower kelly cocks for each size of drillpipe in use shall be available, one of which shall be used below the kelly or top drive during drilling operations and the other shall be on the drilling floor complete with removable handles for easy stabbing and connecting.
Subs for connecting the kelly cock to DCs in use shall also be available on the drilling floor.
Two drop-in type back-pressure valves must be available. These to be complete with seating subs to fit the drillstring in the hole. The drop-in valves must be able to pass the smallest bore in the drillstring above the seating sub, and preferably be wireline retrievable.
A 'Gray-type' inside BOP, with the appropriate connections for the drillstring in use, shall be on the drilling floor at all times. It shall be ready for immediate use.
The left-hand threaded upper kelly cock shall be in good operating condition at all times. A test sub for testing the kelly or top drive and kelly cocks shall be available on the drilling rig.
The upper and lower kelly cock of a top drive should be hydraulically operated.
It should be possible to break the connection above the lower kelly cock of the top drive and remove the top drive when string entry below the top drive is required with the well under pressure.
A 10,000 psi WP 3" rotating type circulating head with correct bottom subs for the drillstring sizes in use shall be available on the drilling floor.
A casing circulating head with a pressure rating equal to the casing rating shall be available on the drilling floor throughout casing running operations.
An optional item is a fast shut-off coupling (Regan type) for use in an emergency on the drilling floor. If available, it shall match the tool joints in use and be fitted with a kelly cock in the open position. It should be tested on the same routine frequency as the BOP stack.
Should you find yourself intrigued by Vigor's suite of well control equipment or other cutting-edge tools tailored for downhole drilling and completion within the oil and gas sector, we wholeheartedly encourage you to reach out. Rest assured, our team is poised and ready to provide you with not only the finest quality products but also unparalleled service that exceeds your expectations.
