IWCF Well Control Lesson 7 Equipment Part One Contents API RP 53 Diverters Accumulator Unit API Recommended Practice 53 • Goal of document – Promoting personnel safety – Public safety – Integrity of the drilling equipment • Purpose – A guide for installation and testing of blowout prevention equipment systems such as: BOP’s, choke and kill lines, choke manifold, hydraulic control system, etc. 3 API RP 53 discussed • Diverters • BOP’s – Annular BOP – Ram BOP • Choke Manifold • Kill and choke lines • Hydraulic System 4 Diverter • It is a low pressure annular preventer which can divert or re-route flow rather than shut in the well fluids. It is used during top-hole drilling. • It can pack-off around: – – – – Kelly Drill string Casing Some on open hole (if having packing units) • But it can not: – Shut in the well 5 Diverter system components • The diverter system consists of: – Low pressure annular preventer – Vent line connected to outlets below the packing element. – Full opening valves – Control system to put valve on open position before the diverter packer closes. 6 KFDJ Diverter 7 KFDJ Diverter 8 Hydril MSP Diverter 9 Diverter • • • • • • • • 1. closing port 2. outer packer (outer active seal) 3. flow line 4. flow line seals 5. insert packer 6. lockdown dogs 7. closed face 8. insert packer lockdown dogs 10 Definition • Rated Working Pressure: – The maximum internal pressure that equipment design to contain or control. (Correct) – The maximum test pressure that equipment design to contain or control. (Wrong) • Test Pressure: – Shell proof or hydrostatic testing pressure for all equipment must be 1.5 times RWP of the equipment. • Anticipated surface pressure: – ASP is the expected surface pressure or anticipated bottom hole pressure minus anticipated hydrostatic pressure. 11 BOP • At least once a week function test. • Low pressure test 200 to 300 psi. and kept for at least 5 minutes. • Initial High pressure test: RWP of BOP’s or wellhead stack whichever is lower. • Subsequent high pressure test: ASP but not greater than RWP of ram BOP’s. • Annular should be tested at ram BOP test pressure or 70% of RWP of annular BOP. • Pressure test should perform : – Prior to spud – After repair or reassemble of pressure containment seals on any part. – Not exceed 21 days. • The weakest part of BOP part is the rated working pressure of stack. Example: If we connect 5000 psi RWP flange on a 10K psi stack all stack will be down graded to 5,000 psi stack. 12 Connection Types • Studded • Clamp Hub • Flanged (API) 13 Flange and ring gaskets • Flange 6B – Require Re-tightening – R and Rx Ring gasket – No face to face make up • Flange 6BX – Only BX ring gasket • RX and BX gaskets are pressure energized. – Not interchangable. – Must installed on clean ring groove. 14 Groove and ring gaskets 15 Choke Manifold • Must have: – One hydraulic or Remote operated choke – One Manual Choke – A bypass line with the same diameter of manifold and at least two valve in this bleeding line. – Upstream valves, chokes and lines must meet RWP. – One valve should be installed downstream of each choke. 16 Choke Manifold • Must meet: – Should have working pressure equal or greater than RWP of BOP. – Installed in safe place, accessible location outside of the rig substructure. – All valves should be full bore. – Two valves which one is remotely operated must be installed between BOP and Choke manifold. – Must have backup air system. – Bleed line should be at least equal in diameter with choke line. 17 Choke manifold 2K, 3 K 18 Choke manifold 5K 19 Choke manifold 10K 15K 20 BOP Control system • Precharge pressure: – 1000 psi for 3000 psi system – 1500 psi for 4500 and 5000 psi system • Stored Hydraulic Pressure: – Volume of fluid recoverable between MOP and precharge pressure. • Usable Fluid: – Volume of fluid between MOP and 200 psi above precharge pressure. • Minimum calculated operating pressure: – Is equal to MRWP of BOP divided by closing ratio. 21 BOP Control system • Response time: – Ram, 30 seconds or less – Annular, • Smaller than 18 ¾ , not more than 30 seconds • Grater or equal 18 ¾ , 45 seconds – HCR valves, not more than monitored closing time of Ram. • • • • Only Nitrogen should be used. Two independent pump Air pump should work with minimum 75 psi air pressure. Each pump has to provide a discharge pressure at least equal to BOP control system working pressure. 22 BOP Control system • • • With pumps inoperative, accumulators should be capable of : – Close one annular preventer (against zero wellbore pressure) – Close all ram type – Open one HCR valve and Maintain 200 psi or more above precharge pressure The pumps on accumulator system must be able to pressurized system from precharge pressure to maximum rated working pressure of system within 15 minutes. With accumulators inoperative or shut off Each pump should be capable of: – Close annular preventer on minimum pipe size – Open HCR valve And maintain pressure recommended by Manufacturer for seal off of pipe within two minutes. 23 24 25 Separator or bladder type Float or piston type Accumulator Bottle Types 26 Safety Valves • Float valve – Flapper-type – Spring loaded • Kelly guards – Upper kelly cock – Lower kelly cock • Inside BOP or NRV • Dart or drop down • All of which has to be tested at least to ASP but limited to BOP RWP in use. 27 Float Valve • Flapper-type • Spring loaded 28 Kelly Guards • Upper kelly cock • Lower kelly cock – Full opening safety valve (FOSV) – Both Manually operated 29 Gray Valve • IBOP or Gray Valve • None return valve (NRV) • Non-return Safety Valve • Stab-in nonereturn safety Valve 30 Gray Valve (NRSV) • It will not allow wireline to pass through. • Needs pumping to read SIDPP. • Kept open by a Thandle. • Has release rod to keep in open position and can not run into the well while is open. 31 Drop Down check-guard valve • It need landing Sub. It must be pumped down • It can be retrieved – By tripping out – By wire line • Also known as drop or dart valve 32 Testers • Plug Tester • Cup Tester – To test entire casing head, side outlets and casing to wellhead seals. 33 Annular Preventer • Closed on open hole or any object. • Variable hydraulic pressure closing allow tool joint to pass. • Allow rotation or reciprocating on request. • Packing Elements: – Packing elements are selected based on temperature and mud type. – Has some metal segments to prevent rubber extrusion and help support of string weight during hang-up. 34 Packing elements: 35 Hydril GL • It has secondary chamber: – Reduce closing pressure – Reduce closing volume • It can be used both in land and marine but designed for deepwater. 36 Hydril GL 37 Hydril GK 38 Hydril GK closing 39 Hydril DL • Use special packing unit with steel segments 40 Shaffer 1- Head latched 2-Packing unit 3- opening port 4- Piston 5- closing port 41 Cameron D 1- Ring Groove 2- Head latched 3- Packing 4- Packing unit donut 5- Opening chamber 6- Piston 7- Closing chamber 42 43 Rams • Ram types: – Pipe Ram – Variable bore – Shear/ Blind • • • • Closing ratio : well bore pressure divided by pressure require to close the ram. Weep hole: is a hole to monitor hydraulic and/ or mud leakage if primary seal failed. Secondary seal: an emergency sealing plastic which can be activated when leakage monitored in weep hole. Action to take if leakage monitored through the weep hole: – While drilling or regular test: • Halt operation and repair equipment immediately. – While well control operation: • Activate secondary seal and finish the job. Repair ram as soon as well is safe. 44 Ram secondary seal 45 Ram Packer extrusion Ram packers are equipped with heavy metals to prevent extrusion and helping pipe weight handling. 46 Pipe Ram 47 Variable Ram Shaffer multi ram 48 Shear Ram 49 Ram 50
