Well Control On Rigs: 15 – Checks & Tests

Table of Contents

  • The drilling supervisor will perform these checks and tests, which Shall not be delegated. I recommend co-checking with the contractor rep / Senior Tool Pusher.
  • Commencement of these checks and tests is after the BOP stack installation, weekly on low & medium risk sections after that, or daily for high-risk wells (to be specified as such upfront).
  • Please notify the driller before your inspection round, as you may have to manipulate the BOP Koomey Unit.
BOP Control Unit pressures & leaks: Check pressures of accumulator (3000 PSI), manifold (1500 PSI) and annular (between 700 and 1500PSI subject to ‘requirements’). Check air pressure to air pumps (125 PSI). Look and listen for any leaks of air or oil. Remove the two inspection caps from the reservoir and look along the line of ‘3-position / 4-way valves’ for evidence of leaks. 
BOP Control Unit set up: Check the 4-way valve setting on control unit for hard shut in. No operational 4-way valves should be in neutral position; this will lead to no pressure on the function and to confusion about actual position in critical situations. Also check all suction and discharge valves of all pumps and all valves to accumulator bottles to be open. (unless under maintenance/PTW). 
BOP Control Unit Function: Try to remember when was the last time you heard the pneumatic and/or electrical pumps running. Check the audible alarms are switched on and all alarm lights are working. Once a week and with the rig managers permission open up the bleeder valve and check when the pumps kick in and out again but be aware of the actual Well Control situation first. 
Alarms: Check the audible air pressure alarm is working by closing the airline to the control unit and bleed some air. The alarm should sound at 80 PSI if ok. If not, inform RM-do not attempt to repair. Open air valve after the test! 
Remote Stations: Check the air pressure and hydraulic pressures on both remote stations. Allow a maximum deviation of 10 % from the values on the unit. When was remote station last used? (They should be used alternatively w/weekly function tests) 
Drill Floor: Check that the FOSV (Full Opening Safety Valve) and Gray valve are on the rig floor including the correct x/o’s needed for the strings in use. Ensure the FOSV is working smoothly with correct Alan key and Gray Valve is functional and stored with push rod down and secured in place. 
Trip Sheet: A Trip Sheet must be maintained that reflects the theoretical and actual tank level every 5 stands. All previous trip sheets to be kept filed neatly in the doghouse. (Trip sheets must be signed for verification by STP & DSV) 
Back Pressure Manifold: Ensure the back pressure manifold is set correctly to handle a kick (hard shut in, starting with annular closure or fast shut in with Pipe Ram closure as per previously agreed method). Check standpipe pressure gauges on back pressure manifold are reading correct value and have the correct scale. Confirm there is at least 4 tons of anchor weights are in place stopping the vent line from moving. Check the annular pressure gauges reading every BOP test and record this. Check all gauges have the correct / applicable scales for use in a well control situation. Mention the scales in use. 
BOP’s: Check that all temporary pipe work is fitted with safety lines. Check the BOP hyd. hoses for any leaking connections, and that valves are lined up for hard shut in. 
Hyd. choke: Confirm that you have function tested from the rig floor and that instructions are clear how to operate if/when there is a power failure. Check oil level, manual pump action. 
Mud Ditch/Tanks: Check that the tank system has sufficient volume, level is monitored with a mechanical marker (checked 15 mins) AND fully functional PVT system, Flo-Sho and mud weights recorded regularly (30 mins) by the mud tester. Some rigs may have additional mud logger & sensors. If so ensure they are monitoring overall pit levels and flow in/out correctly. 
Kick Tolerance: Defined as “the maximum kick volume that can be taken into the well without fracturing the weak point” (normally the shoe). Check if it is posted at rig floor and all are aware of this. 
Degassers: Confirm the last weekly function of vacuum degasser, and that a check valve is installed on discharge hose at Poor Boy Degasser (PBDG). 
Poor Boy Degasser: Ensure the mud weight is known in the PBDG, and that it is re-circulated with any change in properties of the mud. Verify you have your return line from choke routed via the PBDG to the trip tank. Also the PBDG should have a ‘hot line’ to fill up or flush when required. 
Well Control drills: Perform relevant drills ahead of possible challenges: strip drill (2-monthly) as per PCM WS Revision 1.06, page 29; Table 4 – Drill Requirements for Drilling Operations, before drill out casing shoe before reservoir. Un-announced pit/kick/trip (min.: weekly/crew) drills as required before/during being exposed. sections, on all well risk categories. Frequency and reporting as per PCM WS Revision 1.06, page 28; 4.3.1 General Requirements. (With your TL you may discuss exemptions, i.e.: during critical work, whereby a drill would cause a disproportional risk). 

Well Control Routine Checklist

This list has to be checked by STP and DSV, after the casing has been set and before the shoe is drilled out prior to entering HC zones.

BOP Stack  
Has the Annular rubber been visually inspected at Rig-up?  
Did you verify the RAM rubber configuration?  
Has the BOP been Low- and High pressure tested?  
No leakages from weep holes observed?  
Are handwheels available (on location) to lock the rams?  
Are the Shear rams capable of shearing the DP in use?  
Is there a NRV installed in the Kill line? If not, do you have a dispensation?  
Have the side outlets been fitted with WECO connections?  
Are the handwheels on the side outlet v/v’s locked & installed?  
Are all snublines installed on the HP lines?  
Is there a pressure gauge installed on the 13-3/8″and 9-5/8″ Annulus? What do they read?  
Are all gauges on the remote choke panel working?  
Can the Poor Boy degasser & Choke Manifold Pressure gauges be read from this position?  
Have all functions on the remote choke panel been tested?  
Is the emergency back-up for choke control working?  
Is the MAASP auto control by-passed on the choke panel?  
ECS Unit  
Are gas sensors calibrated ?  
Has an Accumulator test been done? What was the final pressure?  
Are Closing & Open times the same as last time?  
Are there any known defects on the Koomey unit?  
Are the remote controls checked and function tested?  
What is the minimum air pressure for the air pumps to operate the system?  
Is there a Kellycock Key available?  
Is the Kellycock ready to be stabbed, using lifting handles?  
Is a Gray v/v available, pressure-tested, thread clean?  
X-over’s on the rigfloor for DC’s to Kellycock?  
Are all gauges working and calibrated?  
Is the Close-in procedure posted in the doghouse?  
Is the Pre-kick sheet up-to-date?  
Is the Flow-show working?  
Mud gas separator (Poor Boy degasser) flushed, i.e. mudseal not plugged?  
Is there a gauge installed on the Poor Boy degasser?  
Are all connections tight on the Poor Boy degasser?  
Flare line installed = 150 meter?  
What is the maximum circulating rate for the PB degasser?  
Has the MGS been tested and achieved a 5 Psi drawdown?  
Has the Vacuum degasser been run and tested? How much dawdown was created?  
Are V-belts onsite for the Vacuum degasser?  
Has the stripping bottle precharge pressure been checked?  
Is striptank pump working?  
Is striptank cleaned and reading clearly visible?  
Is triptank clean and system function tested?  
Will a Kick-drill be done before drilling out Shoetrack?  
Will a Choke-drill be done before drilling out the Shoetrack?  
Did STP and DSV check line-up?  
Do you have a calibrated pressure gauge in your office?  
Is there a ditch magnet available?  
What is the maximum allowable Swab-Volume?  
Have driller been instructed on depths of HC zones?  
What is your minimum overbalance on HC zones?  
Did you check the Drilling program for any hazards identified?  
Clear instructions to ECS posted?  
Do key personnel have their IWCF or equivalent WellCaP?  
Is there at least 50 MT Barites on site?  
Graph paper available from contractor STP to make Kill graph?  
Are all recording devices in the EDC office working?  
Are mixing hoppers in good condition?  
Is there a CLEAR action plan in place, of who is doing what, in well control situations?  

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