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This document describes the general standards and practices used for the safe and effective management of well control operations on COMPANY locations.
API RP 16E, API S53, API RP 64, API SPEC 6A, API SPEC 16A
1. Well control procedures and standards shall be in accordance with the relevant WOR and API standards and Government Regulations.
2. All well operationsshall be carried out with the intention of avoiding kicks and/or the unintentional release of fluids comprising either water or hydrocarbons.
3. Under balanced drilling is not allowed without dispensation.
4. A well shall be treated as &#;live&#; when it has the potential to flow to surface if the barriers fail. This includes non eruptive wells where there is a possibility of gas being trapped.
5. The well control equipment pressure rating shall be as a minimum equal to the maximum prognosed well-head pressure plus psi.
6. The Contractors well control manual may be used provided that they comply or exceed therequirements of COMPANY Policy, the following WOR and above references.
7. Well Operations activities will be carried out using a fluid of the appropriate density to prevent any influx of formation fluid. Minimum static overbalance shall be 200 psi. In the case of HPHT wells with a narrow drilling margin (difference between Pore Pressure and Frack Pressure) a lower value can be used when drilling because of the ECD but an overbalance of 200PSI shall be restored for tripping &#; possibly using heavy mud cap pumped in hole prior to tripping.
8. Unless otherwise dictated by particular conditions, the use of driller&#;s method is mandatory to control the well when a kick has been taken.
9. For each section of the well, a well control sheet showing the pressure limitation and position of the different valves of the well control circuit shall be displayed in the rig floor, the Well Supervisor and Toolpusher offices.
10. LOT or FIT data shall be used to update the well control sheet for each hole section.
11. Updated well control sheets shall be handed over to key personnel and displayed on the drilling shelter, on the Well Operations Supervisor and Tool-Pusher offices.
12. A flapper type non-return valve (float valve) shall be used in the drill string. The valve shall be non ported.
13. The gas detection equipment, flow and volume sensors shall be fully operational and calibrated at all times during well operations.
14. The COMPANY Well Operations Supervisor (or night supervisor) shall be present on the rig floor or work area during each trip to observe the following critical aspects:
a. flow-check and/or start of continuous filling of a well with fluid,
b. First ten stands pulled off bottom &#; Ensure proper tripping practices are used
c. If the formation are unstable
d. Correct hole fill volume
e. Determine when the heavy mud pill has to be pumped so that the pipes aren&#;t pulled wet.
15. After completion of well kill or well testing operations a minimum of one complete hole volume shall be circulated prior to pulling out of the hole.
16. Kick detection, shut in, stripping and circulating drills shall be held regularly prior to enter the expected pay zone until the COMPANY Well Operations Supervisor is confident that each crew understands the well control procedure. The rig shall be equipped to detect kick volume as low as possible, the maximum being the well calculated kick tolerance (drilling and swab) see below § 17.
17. Thereafter, during the drilling of the reservoir section, a kick detection and shut in drill shall be held at least once per week for each crew. Such drills shall be reported on the IADC and Daily Drilling Reports.
18. For drilling, a kick sheet shall be prepared and updated daily and at every change in mud weight or BHA. This shall include an updated assessment of kick tolerance.
a. If kick volume tolerance limits exceed those stated in the Well Programme dispensation must be obtained prior to continuation of drilling.
b. Kick volume tolerance will be calculated assuming a drilled kick with kick intensity of
0.5ppg (mud weight + 0.5ppg). Refer to the Casing and Tubing Design Manual.
NOTE 1: The mud weight is the Pore Pressure &#; additional mud weight motivated by wellbore stability must not be taken into consideration.
c. A swabbed kick will always be considered to be less severe than a drilled kick because a swabbed kick assumes a kick intensity of zero ppg, and the same kick volume tolerance limit will apply.
d. Surface detection: This will determine the volume of kick that the rig can normally detect.
NOTE 2: we consider a kick intensity of 0.5pp for drilling kick and 0 for swab kick.
Kick Detection method Circulation pit Trip tank
Section diameter Drill kick Swab kick
17 ½ 30 bbl 15 bbl
12 ¼ 30 bbl 15 bbl
8 ½ and below (non HP/HT) 30 bbl 15 bbl
HP/HT 10 bbl 10 bbl
19. Each well control incident or any failure of any well control equipment shall be reported immediately to the Well Operations Manager of the affiliate and to the Group Well Operations Manager.
20. For drilling operations, slow circulating rates (including through the choke line in deepwater) shall be done once per shift or whenever changes on affecting pressure behaviour occurred. Pump pressure readings shall be taken at 20, 30 and 40 strokes per minute and recorded on the kill work-sheet.
21. The driller shall maintain an accurate pipe tally.
22. Spare choke needles and beans shall be available on the rig.
23. A set of calibrated pressure gauges shall be available on the rig.
24. The trip tank shall be used at all times while tripping.
25. For drilling operations, trip tank volumes shall be recorded every stands for the first 10 stands and maximum every 5 stands thereafter.
26. Flow checks shall be carried out:
a. As detailed in the Well Programme (all operations).
b. Before commencing a trip out of hole (all operations).
c. After the first ten stands has been pulled (drilling).
d. In the case of horizontal wells, after the bit has been pulled out of the horizontal section (drilling).
e. With bit at the shoe (drilling).
f. Prior to pulling tools or drill collars through the BOPs.
g. At any time when there is an anomaly in fluid of the well or mud volumes on the rig.
27. The following key personnel shall hold a current, IWCF or IADC WELLCAP well control certificate renewable every two years, however COMPANY does not consider that a valid IWCF or IADC certificate alone is a proof of competence.
a. COMPANY Well Operations Superintendent (Well Operations Manager when there is no Superintendent)
b. Well Operations Supervisor (and night supervisor where applicable)
c. Well Operations Engineer (on site)
d. Senior Well Operations Engineer at the operational base
e. Well Operations Engineer at the base
f. Rig Contractor Toolpusher(s).
g. Rig Contractor Drillers or Contractor Well Operation Supervisors.
h. Any Contractor Personnel directly supervising or responsible for operations that involve well
control (example coiled tubing supervisor).
i. Mud Engineer (The Affiliate Well Operations Manager can give dispensation to the mud engineer)
28. COMPANY affiliate Well Operations Managers shall ensure that the competence of key personnel is sufficient to undergo the planned operations, he will decide if further training is necessary:
a. Comprehensive on site drills is the best method to conduct such assessment. In certain circumstances affiliates Well Operations Manager may require personnel to undergo additional well control training (example HP/HT wells, horizontal wells).
29. MAASP shall be notified daily by the Well Operations Supervisor in the instructions to the driller or well operation supervisor.
30. When carrying out well control activities, bleeding off pressure to reduce the MAASP shall only be authorised where there is a risk that fracture gradient at shoe is exceeded and gas channelling to surface could endanger rig and rig crew.
31. Special attention must be paid when running parallel strings (tubing + control lines, electric lines, etc) or breaded cables as no annular or pipe rams are designed to seal on it.
1. The fast shut-in method is mandatory on COMPANY operations whatever the type of rig.
During normal well operation conditions the configuration is as follows:
a. Choke is closed
b. Remote CL valve on BOP closed
c. 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.
d. All other valves on choke manifold shall be closed
2. The Toolpusher or Contractor Supervisor shall ensure that, at the start of each shift, the driller or competent person checks the correct set up of the manifold valves. The COMPANY Well Operations Supervisor shall verify that it has been done. Operations shall not commence until this task has been carried out.
3. Well shut in sequences shall be detailed in the Contractor Well Control Manual or in the joint well operations manual. The method varies depending on the type of rig, land/jack-up or floating and on the ongoing operation (drilling, tripping with DP, tripping with drill collars, etc).
At all times when the well is open the driller or comparable operations supervisor or person acting as Driller shall be present on the rig floor or work area.
The Driller or comparable Operations Supervisor is responsible for:
a. Maintaining a kill sheet updated.
b. Maintaining a trip sheet.
c. Shutting in the well in suspicion of any influx
d. Ensuring that a full opening safety valve with the required cross-over is available on the rig floor
and ready to be stabbed on the drill string.
e. Ensuring that a liquid seal in the degasser is maintained.
f. Ensuring that the choke manifold is lined up correctly.
g. Ensuring that any gains or losses are detected.
h. Ensuring that flow checks are carried out.
i. Ensuring that the COMPANY Well Operations Supervisor and Toolpusher are notified of any well flow and subsequent shut-in.
The Toolpusher or comparable Well Supervisor is responsible for:
a. Ensuring that all well control equipment is present and fully operational
b. Ensuring that all rig personnel is trained and aware of their responsibilities.
c. Ensuring that drills and exercises are carried out.
Overall responsibility for well control:
a. The nominated drilling contractor representative when using third party rigs
b. The nominated COMPANY representative when using COMPANY rigs (i.e. platform rigs, land rigs).
c. In either way the responsibility will be defined and documented prior to the commencement of operations.
d. When using a third party drilling unit, the drilling contractor&#;s well control manual will be used.
e. Where, necessary a bridging document will be appended to align COMPANY and the drilling contractor&#;s standards and procedures.
1. Well Control equipment includes the following (but is not limited to):
a. Diverter systems
b. Blow out preventer stacks (BOP)
c. BOP control system
d. Secondary locking mechanisms
e. Wellhead and wellhead connector&#;s
f. Casing
g. Kelly cocks and kelly hose
h. Drill string safety valves (inside BOP&#;s)
i. Kill and choke lines
j. Choke manifold
k. Mud gas separator
l. All associated pipework and valves.
2. Casing rams are required when running full casing string in open holes where live reservoirs have been drilled. Cavities and bonnets shall have been pressure tested. Exception to this includes:
a. When sub-sea BOP are used
b. When it is not practicable to safely change rams or to maintain barriers due to the BOP configuration
c. When running liners the provision of casing rams may be decided on a case by case basis following risk assessment
d. If casing rams are not used special provision, procedure and equipment shall be in made such as dropping the casing or installing waterbushing (cross over from casing pin to drill pipe box).
3. During drilling operations (exploration and development) and workover operations, onshore and offshore, Shear Blind Rams and booster bonnets shall be provided in the BOP stack when proven or suspected eruptive hydrocarbons exist/may exist in the well to be drilled/worked over.
4. The drilling contractor shall be responsible for performing pressure testing of all contractors supplied BOP and associated well control equipment.
5. All modifications, design changes or weld repairs to well control equipment shall comply with API Specification. Original manufacturer&#;s spare parts shall always be used.
6. When a rig has been stacked for over 6 months, a complete BOP stack dismantling and inspection shall be carried out in a certified workshop.
7. A control shall be carried out on BOP internal bore to ensure there is no abnormal wear or key-seat. On subsea stacks, the check should include key-seat wear on flex joint pin and wear sleeves/bushings.
8. New and clean ring gaskets shall be installed each time BOP components are re-assembled. Grease shall not be used.
9. All master and remote operating panel handles should, at all times, be in the full open or closed position, and be free to move into either position, i.e. the shear ram operating handles should not be locked;
10. All spare operating lines and connections which are not used in the system should be properly blocked off with blind plugs at the hydraulic operating unit; All four way valves should be either in the fully open or fully closed position, as required; they should not be left in the blocked or centre position.
11. All spare parts used to repair or refurbish BOP and associated equipments must be genuine BOP&#;s manufacturer parts.
1. For exploration drilling the BOP will have a working pressure greater than or equal to that the surface pressure arising from the well being full of gas plus psi.
2. For development and appraisal drilling the BOP will have a working pressure greater than or equal to the maximum wellhead shut-in pressure calculated according to the characteristics of the reservoir fluid (specific gravity, GOR, etc.
3. For workover operations when bull-heading, injection treatment, etc are contemplated, BOP&#; working pressure shall be 110% of the maximum expected surface pressure.
4. For pulling units operating on non eruptive wells, the BOP shall have a pressure rating equal to a column of water at the reservoir TVD.
1. BOP tests shall be witnessed by the COMPANY Well Operations Supervisor, together with the contractor's Toolpusher. Any deficiency must be reported and corrected.
2. The BOP shall be function tested at the end of every trip
3. BOP pressure test shall be carried out:
a. Prior to a DST
b. Every 14 days &#; In agreement with the Drilling Contractor Rig Manager, the COMPANY Affiliates Well Ops Managers can decide to extend this period to a maximum of 21 days &#; In no case 21 days can be exceeded.
c. After every BOP flanging-up operation onto the wellhead
d. After landing the string on rams
e. After shearing a drill string
f. Whenever the pressure integrity of the equipment appears to be questionable
g. After running casing prior to drill out the shoe track.
4. On surface BOP&#;s the ram locking system shall be tested at least once per well, just after the BOP installation on the well.
The minimum equipment levels required for monitoring warning signs during live well operations are:
a. Drillers/mudlogging PVT system
b. Drillers/mudlogging flow meters
c. Gas detection equipment
d. Pump stroke counter
e. Pressure gauges.
1. The following are the minimum requirements for well control equipment.
a. The BOP stack shall consist of remotely controlled equipment capable of closing in the well with or without the pipe in the hole.
b. Welded, flanged, or hub connections are mandatory
c. In the case of H2S suspicion, the BOP system should be sour service. Special attention must be paid to the blind/shear rams to ensure that they are suitable for the service envisaged.
d. Dedicated kill lines must not be smaller than 2" nominal and shall be fitted with two valves and an NRV (check valve).
e. Choke lines must not be smaller than 3" through bore and are to be connected with two valves to the BOP stack of which the outer valve shall be hydraulically operated.
f. When dual purpose kill and choke lines are employed, both lines must not be smaller than 3" through bore and the outer valve of each line shall be hydraulically operated.
g. Blind/shear rams shall always be capable of shearing the drillpipe/tubing in use and subsequently provide a proper seal.
h. Closing systems of surface BOP&#;s should be capable of closing each ram preventer within 30 seconds. The closing time should not exceed 30 seconds for annular preventers smaller than 508 mm (20") and 45 seconds for annular preventers of 508 mm (20") and larger.
i. Closing systems of subsea BOP&#;s should be capable of closing each ram preventer within 45 seconds. Closing time should not exceed 60 seconds for annular preventers.
j. Shear rams will be equipped with boosters when necessary. The Well Ops Superintendent shall ensure that the Shear rams used on his rig are able to shear the DP they are using.
2. The stack up of the BOP shall permit the following actions:
a. Closure on pipes and full wellbore closure
b. Control and evacuation of a kick
c. Drillstring hanging on a pipe ram
d. Shearing of the drill pipes and closing of well (except that on 21 ¼&#; or larger BOP with no hydrocarbons forecast in hole section the section a blind ram may be used).
e. Control of well pressure prior to re-opening
f. Closing the well above a subsea test tree.
1. The use of a non ported drill pipe float valve located directly above the bit is mandatory on all rigs operated by COMPANY in all drilling phases. The float valve shall have been pressure tested to their nominal working pressure in their sub prior to be run in the hole. An onshore pressure test is acceptable to the condition that the valve is not removed and reinstalled in the sub after the pressure test.
2. For rigs equipped with a top drive, two independent Kelly valves shall be available, with the proper XO to connect to the top drive.
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3. At least one Kelly cock of the top drive shall be hydraulically actuated.
4. A Kelly cock will be installed below the swivel, and a nominal full opening Kelly cock will be installed at the bottom of the Kelly, of such design that it can be run through the BOP and be strippable through the last casing string.
5. The upper kelly cock shall be in good operating condition at all times.
6. A test sub for testing the Kelly or top drive and Kelly cocks shall be available on the drilling rig. On top drives the upper automatic Kelly cock shall not be used as a mud saver.
7. An inside blowout preventer assembly (back pressure valve) and drill string safety valve in the open position will be maintained on the rig floor at all times while operations are being conducted. Separate valves will be maintained on the rig floor to fit all drill pipe in the drill string. If a crossover sub is used, it will be made up to the inside BOP or drill string safety valve as required. They shall be fitted with proper handling device.
8. A kelly valve with necessary X-over (if required) and adequate thread protection shall be made up on any string, if wireline is run through it (open payzones or perforated well). A cutting device shall be available on the drill floor.
9. As part of the kill string, a 69,000 kPa (10,000 psi) (or more if necessary) 76.2 mm (3") rotating type circulating head with correct bottom subs for the drillstring sizes in use shall be available on the drilling floor.
10. A casing circulating head with a pressure rating equal to the casing rating shall be available on the drilling floor throughout casing running operations for each casing type run.
11. When a subsea BOP stack is in use, storm choke/packers shall be available, sized to match the casing and drill pipe in use
1. A diverter system can be a BOP stack system with diverter spool, or a specifically designed and developed diverter system, although the faster closing diverter unit is preferred above a large and slowly closing annular preventer.
2. Certain insert type diverters such as the KFDS and Cameron WS-1 are prohibited for use in COMPANY sites.
3. The following are the minimum requirements for a diverter system:
a. The diverter and mud return lines should be separate lines, not partial integrated lines.
b. The minimum required nominal ID of diverter outlets/lines is 254 mm (10") on floating rigs.
c. On bottom supported rigs the nominal ID of diverter lines is 305 mm (12&#;). The wall thickness shall not be less than 19 mm (0.75&#;).
d. Two diverter lines are generally required. One outlet only may be considered in the case of dynamically positioned vessels. Dispensation may be obtained if it is impractical to fit a second diverter line.
e. The minimum rated working pressure of diverter equipment is based on the anticipated back-pressure during a shallow gas blowout but shall not be less than kPa (500 psi).
f. Welded flange or hub connections are mandatory on diverter systems; quick connections in diverter lines are prohibited.
g. Diverter lines should be as straight as practically possible, properly anchored and sloping down to avoid blockage of the lines with cuttings.
h. Diverter lines should be as short as possible, but long enough to conduct flow past the extremity of the offshore drilling structure.
i. Diverter valves shall be full opening valves with an actuator. The bore of the diverter valves shall be equal to the bore of the diverter lines. Pneumatically actuated valves are prohibited.
j. Each diverter system should incorporate a kill line facility (including a check valve) to be able to pump water through the diverter system.
k. The diverter control system may be self-contained or an integral part of the BOP accumulator unit and control system. It shall be located in a safe area and have the control functions clearly identified.
l. When a surface diverter system and a subsea BOP stack are employed,
two separate control/accumulator systems are required. The diverter control should contain the minimum of functions. Preferably, a one-button or lever-activated function should operate the entire diverter system.
m. Control systems of diverters/annular preventers and BOPs should be capable of closing the diverter and annular preventers smaller than 508 mm (20") within 30 seconds, and annular preventers of 508 mm (20") or larger within 45 seconds. If possible this time should be improved
upon. Diverter valves should be opened before the diverter element is completely closed.
n. Overboard lines must be as strait as
The class of BOP is determined by the number of annulars and levels of rams in the BOP stack. E.G.: If a BOP stack has 2 annulars and 4 levels of rams, it would be designated as class 6.
To better define the BOP stack, an alphenumeric system is used to identify the number of annulars and the number of rams. The letter A is used for annular and R for rams: example a BOP stack with 2 annulars and 4 levels of rams is classified as: class 6-A2-R4.
1. Risk assessment is the method of choice to select the BOP rams and kill and choke line arrangement.
2. The arrangement of the stack shall be such that the following can be achieved.
a. Possibility of shutting a well when replacing pipe rams by casing rams.
b. Possibility of shutting a well on pipes to carry out repairs on kill and choke lines.
c. Provide sufficient clearance between pipe rams for ram-to-ram stripping.
d. Provide sufficient clearance between pipe rams and shear rams to be able to hang and shear.
e. Possibility, once the pipe is suspended on Pipe Rams and sheared, to kill the well with mud by circulation below the Shear Rams and into the fish, and to circulate the kick out in a conventional manner.
3. Possibility of hanging a drillstring on pipe rams and continuing normal circulation via the drillpipe after a back-off
Class 2 BOP system is required. As a minimum the BOP stack will consist of:
1. One double hydraulic operated ram type preventer or two single hydraulic operated ram type preventers. The upper ram type preventer will be equipped with either blind or preferably blind shear rams or:
2. One annular preventer and one hydraulic operated single ram preventer being preferably equipped with blind shear rams.
3. One kill and one choke line (3" through bore).
4. When the BOP stack has proper size side outlets (31/16" bore), the kill and choke line may be connected to the outlets of the lower preventer. In this case, the drilling spool may be omitted.
5. The wellhead spool located below such a BOP requires one Bull plug on one side, and two 2" gate valves with pressure gauge on the other side.
Class 3 BOP system, as a minimum the BOP stack shall consist of the following:
1. One annular preventer.
2. Two levels of ram type preventers; one of which must be equipped with correct size pipe
rams.
3. The upper ram preventer will be equipped with blind shear rams.
4. One drilling spool with two 77.8 mm (3 1/16") bore side outlets is allowed but not
recommended.
5. Two dual purposes kill and choke lines. Each line should have two full bore valves of which one valve of each line is hydraulically operated. Both lines should be connected to the kill and choke line manifold or:
6. When dual purpose kill and choke lines are not employed, one kill line and one choke line or:
7. Provided that the bottom ram type preventer is equipped with proper size side outlets (3 1/16&#;), the kill- and choke lines may be connected to the outlets of the bottom preventer. In this case the drilling spool can be omitted.
Class 4 BOP system, as a minimum the BOP stack shall consist of the following:
1. One annular preventer.
2. Three levels of ram type preventers; one of which must be equipped with correct size pipe rams, the other one with variable rams.
3. The upper ram preventer will be equipped with blind shear rams.
4. One drilling spool with two 77.8 mm (3 1/16") bore side outlets is allowed but not recommended.
5. Two dual purposes kill and choke lines. Each line should have two full bore valves of which one valve of each line is hydraulically operated. Both lines should be connected to the kill and choke line manifold or:
6. When dual purpose kill and choke lines are not employed, one kill line and one choke line or:
7. Provided that the bottom ram type preventer is equipped with proper size side outlets (3 1/16&#;), the kill- and choke lines may be connected to the outlets of the bottom preventer. In this case the drilling spool can be omitted.
Class 4 BOP system, as a minimum the BOP stack shall consist of the following:
1. Where possible new stacks should have one annular preventer rated at 69,000 kPa (10,000 psi) otherwise one annular preventer with a working pressure of 34,500 kPa ( psi).
2. As a minimum three levels of rams (four recommended), they shall be hydraulic operated ram type preventers; one of which must be equipped with blind/shear rams and the other two with correct size pipe rams. Variable Bore Rams (VBRs) may be used instead of fixed pipe rams, but at least one ram preventer shall be equipped with fixed pipe rams.
3. Provided that the middle and lower ram type preventers are equipped with outlets of the proper size, the kill- and choke lines may be connected to these outlets and the drilling spool omitted.
4. The BOP stack should have two dual purposes kill and choke lines. Each line should have two full bore valves of which one valve of each line is hydraulically operated. Both lines should be connected to the kill- and choke line manifold.
5. When dual purposes kill and choke lines are not employed, the BOP stack must have two kill line and two choke line entries.
6. Each entry should have two full bore valves of which one valve of each choke line shall be hydraulically operated.
7. The lower kill- and choke lines shall be connected to the BOP stack below the bottom preventer and act as spare kill and choke lines.
8. The lines may be connected to the outlets of the bottom preventer, provided that the preventer is equipped with outlets of the proper size.
9. When the lower kill- and choke lines cannot be connected to the outlets of the bottom preventer, they should be connected to the outlets of a drilling spool which is installed below the bottom preventer.
Class 5 or 6 BOP system, as a minimum the BOP stack shall consist of the following:
1. One annular preventer with a working pressure of 69,000 kPa (10,000 psi).
2. A four ram stack is compulsory.
3. They must be hydraulic operated ram type preventers, one of which must be equipped with blind/shear rams and the other two with the correct size pipe rams. Variable Bore Rams (VBRs) may be used instead of fixed pipe rams, but at least one ram type preventer shall be equipped with fixed pipe rams.
4. Drilling spool to be avoided if possible otherwise one full opening drilling spool with two 77.8 mm (3 1/16") bore side outlets (see item d).
5. Provided that the middle ram type preventer is equipped with side outlets of the proper size, the kill and choke lines may be connected to these outlets and the drilling spool omitted.
6. The BOP stack must have two dual purpose kill and choke lines. Each line should have two full bore valves of which one valve of each line is hydraulically operated.
7. When dual purpose kill and choke lines are not employed, the BOP stack must have two kill line and two choke line entries.
8. Each entry should have two full bore valves of which one valve of each choke line shall be hydraulically operated. The lower kill- and choke lines shall be connected to the BOP stack below the bottom preventer and act as spare kill and choke lines.
9. The lines may be connected to the outlets of the bottom preventer, provided that the preventer is equipped with outlets of the proper size.
10. When the lower kill and choke lines cannot be connected to the outlets of the bottom preventer, they have to be connected to the outlets of a drilling spool which is installed below the bottom preventer.
Control systems for surface BOP stacks shall consist of the following:
1. One independent automatic accumulator unit rated for 20,700 kPa ( psi) with a control manifold, clearly showing 'open' and 'closed' positions for preventer(s) and the hydraulic operated kill/choke line valves. It is essential that all air and hydraulic BOP operating units
be equipped with 0-20,700 kPa (0- psi) regulator valves similar to the Koomey type TR-5 which will not 'fail open', causing complete loss of operating pressure.
2. For psi and psi class BOP&#;s the total accumulator volume shall be sized to fully close the bag preventer, all the ram preventers, and one hydraulic valve and keep at least 50 % of the previous total volume as operating volume (the residual pressure being psi, 200 psi above precharge pressure) with the pumps out of service.
3. For BOP&#;s above psi class, the total accumulator volume shall be sized to fully close and open the annular preventer, all the ram preventers and one hydraulic valve and to keep at least 25 % of the previous total volume as operating volume (the residual pressure being
psi, 200 psi above precharge pressure) with the pumps out of service.
4. All BOP stack installations should have two remote control panels, each one clearly showing 'open' and 'closed' positions for each preventer and the pressure operated choke line valves. Each of these panels shall include a master shut-off valve and controls for regulator valves and for a bypass valve. One panel must be located near the driller's position, the other panel to be located near the exit of the location or near the rig supervisor's office.
5. At least one of the electric triplex pumps of the BOP control system shall be powered by the Emergency generator in the case of a main power failure.
6. High pressure fire-resistant control hoses with a working pressure of 20,700 kPa ( psi) are preferred, although steel swivel joints are acceptable. The hoses should be steel wrapped (co-flex type) to provide greater resistance to fire and improved durability.
7. Control hose shall have been pressure tested to the working pressure at least once prior to the rig up.
1. The Subsea BOP equipment may comprise either a single stack or a two-stack system. The single stack system is preferred.
2. The single stack system consists of one large bore BOP stack (generally 18 3/4") with a working pressure classification of 69,000 kPa (10,000 psi) or 103,500 kPa (15,000 psi).
3. The two-stack system consists of a 13,800 kPa ( psi) WP large bore BOP stack (generally 21 1/4") and a smaller bore stack (generally 13 5/8") with a working pressure classification sufficient to meet the maximum anticipated surface pressure.
Single stack subsea BOP have to be class 5 or above. A single stack system built into a guide frame with lifting attachment shall, regardless of the rated working pressure, contain the following:
1. Riser adapter
2. Flexible joint.
3. For 10K and 15K systems one annular is mandatory but 2 are recommended
4. It is acceptable to have, above the LMRP, a 34,500 kPa ( psi) WP annular preventer on a 69,000 kPa (10,000 psi) WP BOP stack,
5. A 69,000 kPa (10,000 psi) WP annular preventer on a 103,500 kPa (15,000 psi) WP BOP stack is compulsory.
6. Four ram type preventers all equipped with ram locks.
7. One of the preventers to be equipped with blind/shear rams able to seal the well and the other three with the correct size pipe rams or Variable Bore Rams (VBRs).
8. At least one ram type preventer below the blind/shear rams shall be equipped with fixed pipe rams.
9. Each preventer shall have two 77.8 mm (3 1/16") bore side outlets rated to the same working pressure as the ram preventer.
10. One side outlet of each preventer shall be fitted with two fail safe valves each for connection with the kill- and choke lines. The valves shall be 'fail-safe' in the closed position. The remainder of the side outlets shall be blanked off.
11. Two hydraulic or electro-hydraulic control pods each with 100% redundancy and provided with remote control pressure regulation to meet the water depth requirements.
12. For Subsea Single Stack systems with only one Annular Preventer, the packing system shall be changed at the commissioning stage if it has been in use for more than 1 year.
Class 5 or 6 BOP
The criteria for this type of unit is:
a. Minimum of 1 annular preventer but preferably 2
b. A minimum of 2 pipe rams (excluding the test pipe rams)
c. A minimum of 2 set of shear rams &#; one of them able to seal the well
1. A two-stack system consist of a large bore and a small bore stack.
2. The 13,800 kPa ( psi) large bore stack shall contain:
a. The male part of the upper hydraulic connector.
b. One annular preventer.
c. Two ram type preventers both equipped with ram locks; one preventer to be equipped with blind/shear rams and the other preventer with proper size pipe rams. The ram type preventers shall each have two 77.8 mm (3 1/16") bore side outlets fitted with two fail safe valves each for connection with the kill- and choke lines.
d. The female part of the lower hydraulic connector.
e. Two hydraulic or electro-hydraulic control pods (100% redundancy). These pods shall be provided with remote control pressure regulation to meet the water depth requirements.
f. The BOP stack shall be built into a guide frame, provided with a lifting attachment.
g. The small bore stack shall, regardless of the working pressure, contain the following:
h. The male part of the upper hydraulic connector, or a riser adapter.
i. One annular preventer with the same pressure rating as the ram type preventers: a 34,500 kPa ( psi) WP annular preventer on a 69,000 kPa (10,000) WP BOP stack or a 69,000 kPa (10,000 psi) WP on a 103,500 kPa (15,000 psi) WP BOP stack is acceptable above the LMRP.
j. Four ram type preventers with ram locks. One preventer to be equipped with blind/shear rams and three preventers with proper size pipe rams or Variable Bore Rams (VBRs).At least one ram type preventer below the blind/shear rams shall be equipped with fixed pipe rams. Each ram type preventer below the blind/shear rams shall have two 77.8 mm (3 1/16") bore side outlets rated to the same working pressure as the ram preventer. One side outlet of each preventer shall be fitted with two fail safe valves each for connection with the kill- choke lines. The valves should be "fail-safe" in the closed position. The remainder of the side outlets shall be blanked off.
k. The female part of the lower hydraulic connector.
l. Two hydraulic or electro-hydraulic control pods (100% redundancy). These pods shall be provided with remote pressure regulation to meet the water depth requirements.
m. The BOP stack shall be built into a guide frame, provided with a pick-up attachment.
In underwater operations, BOP operating and control equipment shall include:
An independent automatic accumulator unit rated for 20,700 kPa ( psi) WP for use with the underwater BOP control system complete with a soluble oil/water reservoir, automatic proportioning equipment for soluble oil, and a control manifold.
Without recharging, the accumulator capacity shall be adequate for closing and opening all ram type preventers and one annular preventer around the drillpipe and for closing again one ram type preventer and one annular preventer around the drillpipe and holding them closed against the rated working pressure of the preventers. The unit shall include one electrically driven triplex charging pump and two air-driven pumps for charging the accumulators. The unit shall also be fitted with a regulator, similar to the Koomey type TR-5, which will not "fail open", causing loss of operating pressure. The unit shall be located in a safe area away from the drilling floor and the spider-deck.
Part of the accumulators may be installed on the BOP stack for quicker response of the functions, and for operation via an acoustic control.
Two remote control panels, each one clearly showing 'open' and 'closed' positions for all underwater functions. When a two-stack system is used, the panels should each contain an overlay, clearly showing all functions and provided with controls for the 13,800 kPa ( psi) WP BOP stack. One panel must be located near the driller's position. The other panel to be located at a safe distance from the substructure and adjacent to the escape route from the drilling unit, or in the toolpusher's office. A meter for indicating control fluid flow should be located on each remote control panel.
The panels should be connected to the control manifold in such a way that all functions can be operated independently from each panel.
A dual hydraulic or electro-hydraulic cable and/or hose system providing 100% redundancy of control for all functions of the BOP stack.
The nature of the interconnections between the surface control equipment and the underwater BOP stack depends on the type of control system. For the direct hydraulic and pilot-operated hydraulic systems, integrated multiple hose bundles are commonly used. For electro-hydraulic systems the electrical interconnections may be combined into integrated 'umbilical' cable bundles. Alternatively the hydraulic hose can be handled separately. As a general rule, the original total lengths of the flexible control cables and hoses should be 90 m (300 feet) greater than the maximum water depth for which the system is designed.
An emergency control system sometimes referred to as an acoustic system to close at least one ram type preventer, the shear rams, and open one hydraulic connector, in the event that the BOP functions are inoperable due to a failure of the control system.
The accumulator bottles on the BOP stack should be fitted with non-return valves to prevent accidental dumping and should be of sufficient capacity for one activation of each of the emergency control functions plus 50%.
Electrical equipment shall be suitable for the zone in which it is installed (Zone 1 or 2).
BOP control fluid shall be protected against freezing.
It is compulsory to have an Emergency Air Supply permanently installed in order to retain control over subsea BOP stacks, when non-failsafe diaphragm or piston type pressure regulators exist on the hydraulic control manifold.
1. The kill, choke, emergency lines, plus all the equipment set on these lines (or upstream chokes on the choke manifold); will have a minimum working pressure equal to, or greater than the BOP on which they are installed.
2. Connections with welded flanges or clamps are compulsory.
3. This equipment will be compatible with the characteristics of the formation effluents and of the drilling fluids, and be fire resistant.
4. For psi series and over, it is mandatory to have two kill lines, i.e.
a. One kill line hooked-up permanently to the BOP stack.
b. One emergency kill line hooked-up to the upper wellhead outlet and connected to a high pressure pump before expected objectives/proven payzones may be allowed to be drilled through.
5. In the case of H2S, two kill lines are mandatory, whatever the BOP working pressure.
6. A check valve is compulsory on the Main kill line of 15,000 psi surface BOP stacks.
7. For 10,000 psi equipment or above, only welded flange or clamp end connections are acceptable.
8. In the case of HP/HT well, and/or if H2S is expected, the only acceptable Kill Line connections on Chicksan pipes are systems, with metal-to-metal seal, welded on pipe or designed as an integral connection.
9. For maximum expected wellhead pressure greater than psi, it is mandatory to have two independent choke lines (surface stacks) connected to the BOP (no "Tee" allowed). Likewise, these lines shall have independent inlets on the choke manifold. Two separate inlets shall be provided for the subsea stacks choke line (expected pressure > psi).This rule applies whatever the expected wellhead pressure in the case of H2S.
10. Chicksan type choke lines are not allowed.
11. Two independent choke line inlets on the choke manifold will be provided when the maximum expected wellhead pressure is greater than psi. Each inlet shall be properly isolated with valves so as to allow easy well control through either line, whatever condition of the other one.
12. 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.
13. The remote choke (i.e. the remotely adjustable choke) shall be in an open position with the upstream valve closed and the adjustable choke, (i.e. manually operated at the choke manifold) shall be left in a closed position.
14. The remote choke is to be operated from a control panel installed near the driller's position.
15. 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.
16. 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 minimizing gate and seat wear.
17. 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.
18. Temperatures downstream of the choke are to be limited to the design temperature rating of the choke manifold.
19. The choke manifold shall be equipped with sufficient and pressure sensor points so that pressure can be monitored and recorded without opening other valves outside of the direct circuit to the choke. This shall also include mud logging pressure senses. It is prohibited to have a rig up such that additional branches need to be opened to provide pressure information.
20. Annulus and standpipe pressure gauges shall be legible from the manual choke operating location.
1. The MGS shall never be operated above its design limitations. Each contractor should supply MGS operating performance and limitations. It shall be fitted with a 0 to 20 psi pressure gauge.
2. The opening of the Overboard Line valves on the MGS shall never be automatically controlled by any Mud Gas Separator pressure monitoring system.
3. The mud seal shall have a minimum height of 10 feet. On HP/HT wells 20 feet is recommended. The "U" tube type shall have an ID of 8&#; with 16" as optimum value.
4. The "dip" tube type which protrudes in a trip tank must be 18"minimum ID, the U tube shall be equipped with a system preventing siphon effect.
5. On HP/HT wells the capacity of the MGS is very important when circulating a kick. Its capacity must be maximum. A capacity between 35MMscf and 60MMscf is recommended.
6. The gas vent should be straight as possible, hard piping and not less than 8" nominal pipe diameter.
For more information, please visit Casing Spear Machinery.