Part 4. Blowout Prevention (BOP)

4.1 Drilling BOP requirements

The operator of a well being drilled shall ensure that the well has installed thereon and maintained at all times casing and blowout prevention equipment that:

  1. is adequate to shut off any flow at the well head whether or not any type of tool or equipment is being used in the hole; and
  2. complies with the well classification set out in section 4.3 and with the specifications set out in Schedule 1.

4.2 Well specific BOP requirements

Note: The Ministry may, by condition on a well licence, specify the blowout prevention requirements that apply to a well.

4.3 Well classes

For the purpose of drilling BOP requirements and the BOP equipment required in Schedule 1, wells are classified as set out below:

  1. Class A: a well without the first control string of casing set;
  2. Class B: a well in which the first control string of casing is set and the true vertical depth is not greater than 1800 metres.

4.4 Cable tool drilling BOP requirements

The operator of a well being drilled with a cable tool rig shall ensure that the following BOP requirements are met.

4.4.1 Casing bowl or spool

The casing bowl or spool upon which the BOP equipment is attached shall have:

  1. flanges that are an integral part of the casing bowl or spool, or a thread/flange crossover directly on top of the casing bowl or spool; and
  2. at least one valve except where a drilling spool has been installed between the casing bowl or spool and the lowest blowout preventer.

4.4.2 Cable tool drilling BOP equipment

  1. For Class A wells, Schedule 1, page 112 BOP equipment is required.
  2. For Class B wells, Schedule 1, page 114 BOP equipment is required.

4.4.3 Hydraulic operation

All components of Class B well BOP’s that are hydraulically operated shall be connected to an accumulator system.

4.4.4 Mechanical operation

The lower-most component of Class B well BOP’s may be operated mechanically. Where mechanical operation of blowout preventers is employed the wheel used to close the system shall be located 5 metres outside of the rig floor and the shaft connecting the BOP to the wheel shall be secured to the preventer to prevent disengagement during closing or opening operations.

4.4.5 Accumulator system

Where an accumulator system is used it shall be:

  1. installed and operated in accordance with the manufacturer’s specifications;
  2. capable of providing, without recharging, fluid of sufficient volume and pressure to open the hydraulically operated valve on the bleed-off line if this valve is hydraulically operated and to effect full closure of all hydraulically operated preventers and to retain a pressure of 8400 kPa on the accumulator system;
  3. connected to the BOP’s and the hydraulically operated valve on the bleed-off line if this valve is hydraulically operated with lines of working pressure equal to the working pressure of the accumulator, and where lines are located under the rig floor, be of steel construction unless completely sheathed with adequate fire resistant sleeving;
  4. recharged by a pressure controlled pump capable of recovering within 5 minutes the accumulator pressure drop resulting from the operation of the hydraulically operated valve if present and full closure of the annular preventer;
  5. capable of closing any ram type preventer within 30 seconds using only the accumulator;
  6. capable of closing any annular type blowout preventer within 90 seconds;
  7. equipped with readily accessible fittings and gauges to determine the precharge pressure; and
  8. equipped with a check valve between the accumulator recharge pump and the accumulator.

4.4.6 Nitrogen supply

The accumulator system shall be connected to a nitrogen supply that is:

  1. capable of opening the hydraulically operated valve and capable of closing the annular blowout preventer and one ram type preventer;
  2. at a pressure of not less than 12,500 kPa; and
  3. has a gauge installed or readily available for installation, to determine the pressure of each nitrogen container.

4.4.7 Ram type preventers

Ram type blowout preventers, which are not equipped with automatic ram locking devices, shall have hand wheels either installed or readily accessible for installation.

4.4.8 Hydraulic BOP system controls

The blowout prevention system shall include operating controls for each hydraulically operated blowout preventer and the hydraulically operated valve if one is installed. These controls shall be located near the driller’s position so that access to them is not restricted.

4.4.9 Kill systems

An inlet below all the BOP’s must be available to connect a kill truck or kill pump to, and shall:

  1. be at least 50 millimetres in diameter;
  2. for Class B wells, have a nipple and valve installed into the drilling spool, casing bowl or casing head and a kill line attached to the valve and extending at least 10 meters from the well;
  3. all components of the kill line must have a working pressure rating at least equal to that of the BOP system; and
  4. the inlet for pumping kill fluids into the well shall have completely separate lines attached to the drilling spool, casing bowl, or casing head.

4.4.10 Bleed off system

An outlet below all the BOP’s shall be available to bleed pressure from the well and shall:

  1. be at least 50 millimetres in diameter;
  2. for Class B wells, have:
    1. a nipple and valve installed into the drilling spool, casing bowl, or casing head,
    2. a bleed off line that:
      • is attached to the valve,
      • extends at least 10 meters from the well,
      • is equipped to allow the casing pressure to be measured at the end of the bleed off line while pressure is being relieved from the well, and
      • has an adjustable choke installed to allow for the controlled release of pressure from the well;
  3. have a working pressure at least equal to that of the BOP system for all components of the bleed off line; and
  4. have completely separate lines attached to the drilling spool, casing bowl, or casing head.

4.4.11 Flexible hose

A flexible hose may be installed in place of a steel kill or bleed off line provided that the hose:

  1. has a pressure rating equal to that of the BOP system;
  2. has the same internal diameter as the steel line;
  3. has factory installed connections;
  4. is sheathed to provide an adequate fire resistant rating;
  5. is marked so that its manufacturer can be readily identified;
  6. does not contain bends with a radius less than the manufacturer’s specified minimum bending radius;
  7. is secured to prevent stresses on connection valves and piping, and is protected from mechanical damage; and
  8. is shop serviced and shop tested to its working pressure at least once every three years and the test data and maintenance performed shall be recorded and made available to the Ministry upon request.

4.4.12 Pressure tests

For Class B wells, each component of the BOP system shall be pressure tested in conjunction with the casing pressure test prior to drilling the cement out of the previous casing string. The operator shall not proceed with any drilling operations until the pressure test of the BOP system has been successfully completed.

4.4.13 Function testing of BOP’s

The operator of a well being drilled shall ensure that the appropriate blowout prevention equipment is mechanically tested at least daily and any equipment found defective shall be made serviceable before operations are resumed.

4.4.14 BOP servicing

At least once every three years all blowout preventers shall be shop serviced and shop tested to their working pressure and the test data and maintenance performed shall be recorded and made available to the Ministry upon request.

4.4.15 Rig crew training

The operator of a well shall at all times ensure that:

  1. the rig crew is trained in the operation of the BOP equipment;
  2. the driller has a First Line Supervisor certificate issued within the previous three years by the Petroleum Industry Training Service or equivalent in blowout prevention and kick control procedures;
  3. at least one person who has a Second Line Supervisor certificate issued within the previous two years by the Petroleum Industry Training Service in well control procedures is readily available;
  4. blowout prevention drills are performed prior to drilling out the first control casing string casing shoe;
  5. blowout prevention drills are performed by each drilling crew every seven days;
  6. drills performed in accordance with clauses (d) and (e) are recorded in the drilling log book; and
  7. the procedures, calculations, formulae and current data needed to control a kick at a well are clearly posted at the rig.

4.5 Rotary drilling BOP requirements

The operator of a well being drilled with a rotary drilling rig shall ensure that the following BOP requirements are met.

4.5.1 Rotary BOP equipment

  1. For Class A wells, Schedule 1, page 113 BOP equipment is required.
  2. For Class B wells, Schedule 1, page 115 BOP equipment is required.

4.5.2 Drill through components

Drilling-through components installed between the top flange of the uppermost blowout preventer element and the rotary table shall be constructed so as to permit their removal while drill pipe or other equipment is in the drilled hole. This section does not apply to drilling operations utilizing a rotating head.

4.5.3 Casing bowl

The casing bowl shall have:

  1. the flange as an integral part of the casing bowl; and
  2. at least one valve, except where a drilling spool has been installed between the casing bowl and the lower ram type blowout preventer.

4.5.4 Hydraulic operation

All blowout preventers shall be hydraulically operated and, except for wells in Class A, shall be connected to an accumulator system.

4.5.5 Accumulator system

Where an accumulator system is used it shall be:

  1. installed and operated in accordance with the manufacturer’s specifications;
  2. capable of providing without recharging, fluid of sufficient volume and pressure to open the hydraulically operated valve on the bleed-off line, to effect full closure of the annular preventer and to retain a pressure of 8400 kPa on the accumulator system;
  3. connected to the blowout preventers and the hydraulically operated valve on the bleed-off line with lines of working pressure equal to the working pressure of the accumulator, and where lines are located under the substructure, be of steel construction unless completely sheathed with adequate fire resistant sleeving;
  4. recharged by an automatic, pressure controlled pump capable of recovering within 5 minutes the accumulator pressure drop resulting from the operation of the hydraulically operated valve and full closure of the annular preventer;
  5. capable of closing any ram type blowout preventer within 30 seconds using only the accumulator;
  6. capable of closing any annular type blowout preventer of a size up to and including 350 millimetres within 60 seconds;
  7. capable of closing any annular type blowout preventer of a size greater than 350 millimetres within 90 seconds; and
  8. equipped with readily accessible fittings and gauge to determine the precharge pressure.

4.5.6 Nitrogen supply

The accumulator system shall be connected to a nitrogen supply that is:

  1. capable of opening the hydraulically operated valve and capable of closing the annular blowout preventer and one ram type preventer;
  2. under a pressure of not less than 12,500 kPa; and
  3. have a gauge installed or readily available for installation, to determine the pressure of each nitrogen container.

4.5.7 Ram type preventers

Ram type blowout preventers, which are not equipped with automatic ram locking devices, shall have hand wheels either installed or readily accessible for installation.

4.5.8 BOP system controls

The blowout prevention system shall include:

  1. operating controls for each blowout preventer and the hydraulically operated valve on the bleed-off line, located near the driller's position so that access to them is not restricted; and
  2. an additional set of operating controls that are:
    1. capable of closing each blowout preventer and opening the hydraulically operated valve on the bleed-off line,
    2. located at least 15 metres from the well, and
    3. readily accessible and shielded or housed to protect the operator from the flow from the well.

4.5.9 BOP kill system

The blowout prevention system, except for wells in Class A, shall include a kill system for the purpose of pumping fluid into the well that:

  1. consists of an arrangement of valves and steel lines which have a working pressure equal to that of the blowout prevention system specified in Schedule 1 for the applicable class of well;
  2. have a kill line connecting the mud line to the drilling spool;
  3. be valved to isolate the kill line from the stand pipe;
  4. have two flanged valves installed on each drilling spool; and
  5. have lines of at least 50 millimetres nominal diameter.

4.5.10 Flexible hose

A flexible hose may be installed in place of the steel kill line provided that the hose:

  1. has a pressure rating equal to that of the blowout preventer system;
  2. has the same internal diameter as the steel line;
  3. has factory installed connections;
  4. is sheathed to provide an adequate fire resistant rating;
  5. is marked so that its manufacturer can be readily identified;
  6. does not contain bends with a radius less than the manufacturer's specified minimum bending radius;
  7. is secured to prevent stresses on connecting valves and piping, and is protected from mechanical damage; and
  8. is shop serviced and shop tested to its working pressure at least once every three years and the test data and maintenance performed shall be recorded and made available to the Ministry upon request.

4.5.11 Class B bleed-off system

The blowout prevention system shall include a bleed-off system for the purpose of bleeding off well pressure and an accurate pressure gauge and other necessary equipment must be installed or readily accessible for installation on the stand pipe or other suitable connection to provide the drill pipe pressure at the choke control location. The bleed-off system shall:

  1. consist of an arrangement of valves, chokes and steel lines which have a working pressure equal to that of the blowout prevention system specified in Schedule 1 for the applicable class of well, except that part of the bleed-off line downstream from the last valve on the bleed-off manifold;
  2. contain only straight pipe or 90 degree bends constructed of tees and crosses blocked on fluid turns; and
  3. be securely tied down.

4.5.12 Class A bleed-off system

The bleed-off system for wells in Class A shall consist of:

  1. a line having a nominal diameter of 75 millimeters, containing a quick opening valve and terminating in an earthen pit at least 30 meters from the well when drilling with mud; or
  2. a line having a nominal diameter of 100 millimeters and terminating in an earthen pit at least 30 meters from the well when drilling with air.

4.5.13 Spool to manifold bleed-off line

The section of bleed-off line connecting the drilling spool to the choke manifold shall:

  1. have a nominal diameter of at least 75 millimetres;
  2. be connected by flanges or high pressure hammer unions and conform to the requirements specified in section 4.5.12;
  3. contain 2 flanged valves installed on the drilling spool, one of which must be hydraulically operated, and where 2 spools are installed the hydraulically operated valve shall be connected to the upper spool; and
  4. where a flexible hose is installed in the section of bleed-off line connecting the drilling spool to the choke manifold, it shall conform to the requirements specified in section 4.5.10.

4.5.14 Choke manifold

The choke manifold shall:

  1. be constructed in conformance with the requirements of section 4.5.11;
  2. permit the flow from the well to be diverted to;
    1. the flare pit through a 75 millimetre minimum nominal diameter line, and
    2. a mud system line and a flare pit line through two 50 millimetre minimum nominal diameter choke lines;
  3. contain two adjustable chokes, one in each choke line, valves to isolate each choke;
  4. be constructed with a valved outlet located so that regardless of which line is in use, the casing pressure can be monitored by an accurate pressure gauge which shall be either installed or readily accessible for installation;
  5. be equipped so as to provide the casing pressure at the choke control where a remotely operated choke is installed;
  6. be constructed to provide the flow paths illustrated in Schedule 1, although not necessarily conforming to the exact configurations there shown;
  7. be located outside the substructure, readily accessible; and
  8. be protected from freezing.
4.5.14.1 Manifold - mud system line

A line from the manifold to the mud system shall:

  1. be connected to each choke line;
  2. be at least the same nominal diameter as the choke lines; and
  3. direct the flow to a mud tank through a mud-gas separator except where the pump suction is taking fluid from earthen pits.
4.5.14.2 Choke manifold bleed-off line

The section of bleed-off line downstream from the last valve on the choke manifold to the flare pit shall:

  1. have a nominal diameter of at least 75 millimetres;
  2. extend at least 30 metres from the well and be securely tied down; and
  3. terminate in a slightly downward direction into an earthen pit which shall:
    1. be excavated to a depth of not less than 1 metres,
    2. have side and back walls rising not less than 1 metres above ground level, and
    3. be shaped to contain the liquid.
4.5.14.3 Auxiliary bleed-off lines

Auxiliary bleed-off lines, where installed, shall be the same nominal diameter as the lines being extended and conform to the requirement of section 4.5.14.2.

4.5.15 Mud tanks

Where a mud tank is in service, the operator shall:

  1. install and maintain a mud-gas separator connected to a separate flare line with a diameter of at least 25 millimetres larger than the inlet line and terminating in an earthen pit 30 metres from the well; and
  2. install and maintain a device or method to provide warning at the driller's position of a change of the level of fluid in the mud tank or of an imbalance in the volume of fluids entering and returning from the well.

4.5.16 Drilling fluid volume

The drilling mud system shall be equipped with a device to accurately measure the volume of drilling fluid required to fill the hole while pulling the pipe from the well.

4.5.17 Pulling pipe

The operator, while pulling pipe from a well, shall ensure that the:

  1. hole is filled with drilling fluid at sufficiently frequent intervals so that the fluid level in well bore does not fall below a depth of 30 metres; and
  2. volume of fluid is recorded each time the hole is filled.

4.5.18 Cold weather

During cold weather operations, the operator shall ensure that:

  1. sufficient heat is provided or maintained to the blowout preventer stack and associated valves, kill system, and accumulator system and choke manifold to maintain their effectiveness; and
  2. all lines in the bleed-off system, including those sections between the blowout preventers and the choke manifold, are:
    1. empty,
    2. filled with a non-freezing fluid that is miscible with water, or
    3. heated.

4.5.19 Drill string safety valve (stabbing valve)

The operator shall maintain on the drilling rig in a readily accessible location a full opening drill string safety valve in the open position and a device capable of stopping back-flow if one is not installed in the drill string, both of which can be stripped into the well when installed in the drill pipe or drill collars.

4.5.20 Air, gas or foam drilling

Where a well is being drilled with air, gas or foam the operator shall:

  1. install and maintain;
    1. in addition to the blowout prevention equipment required in Schedule 1, a rotating head that diverts the flow during the period the well will be drilled with air;
    2. a diverter line not less than 30 metres in length;
    3. a reserve volume of drilling fluid equal to at least 1.5 times the capacity of the hole;
    4. when drilling formations that may contain hydrogen sulphide, a continuous hydrogen sulphide monitor on the diverter line; and
  2. flare any gas flowing from the end of the diverter line.

4.5.21 Pressure tests

Before drilling out the casing shoe, the operator shall ensure that a ten minute pressure test is conducted on the casing and on:

  1. each ram type blowout preventer prior to drilling the cement out of the surface, intermediate and production casing, to 1400 kilopascals with a low viscosity fluid, and the test shall be conducted prior to each ram type test described in clauses (b) and (c),
  2. each ram type and annular blowout preventer and the bleed-off manifold prior to drilling the cement out of the surface casing, to 3500 kilopascals or to a pressure numerically equivalent in kilopascals to 25 times the setting depth in metres of the first control string, whichever is the lesser;
  3. each ram type blowout preventer and the bleed-off manifold prior to drilling the cement out of the intermediate and production casing to a pressure equivalent to the working pressure of the ram type preventer, except that, where the pressure at the casing shoe would exceed 67 percent of the casing burst pressure, the casing shall be excluded from the test by using a casing hanger plug; and
  4. each annular preventer, prior to drilling the cement out of the intermediate and production casing, to a pressure equivalent to one-half its working pressure.
4.5.21.1 Suspension of operations - test results

The operator shall not proceed with any operation at a well until the tests required in section 4.5.21 have been satisfactorily completed and all BOP equipment is functioning properly.

4.5.22 Casing wear

Casing exposed to drill pipe wear shall be tested to determine its adequacy for pressure control by either:

  1. running a casing inspection log to determine casing wear; or
  2. pressure testing to a pressure not greater than 50 per cent of the burst pressure of the weakest section of the casing, or to the working pressure of the blowout preventers, whichever is lesser.

4.5.23 Mechanical BOP testing

The operator of a well shall ensure that:

  1. the blowout prevention equipment is mechanically tested daily and any equipment found defective shall be made serviceable before operations are resumed;
  2. for any annular type blowout preventer, all mechanical and pressure tests required by this section shall be conducted with pipe in the hole; and
  3. all tests are be reported in the drilling log book, and in the case of a pressure test, the report shall show the blowout preventer tested, the test duration and the test pressures observed at the start and finish of each test.

4.5.24 BOP servicing

Blowout preventers shall be shop serviced and shop tested to their working pressure every three years and the test data and maintenance performed shall be recorded and kept by the operator.

4.5.25 Rig crew training

The operator of a well shall at all times ensure that:

  1. the rig crew is trained in the operation of the blowout prevention equipment;
  2. the driller has a First Line Supervisor certificate issued within the previous three years by the Petroleum Industry Training Service or equivalent in blowout prevention and kick control procedures;
  3. at least one person who has a Second Line Supervisor certificate issued within the previous two years by the Petroleum Industry Training Service in well control procedures is readily available;
  4. blowout prevention drills are performed prior to drilling out the first control casing string casing shoe;
  5. blowout prevention drills are performed by each drilling crew every seven days;
  6. drills performed in accordance with clauses (d) and (e) are recorded in the drilling log book; and
  7. the procedures, calculations, formulae and current data needed to control a kick at a well are clearly posted at the rig.

4.5.26 Drill stem testing

When a drill stem test is conducted on a well, the operator shall ensure that there is:

  1. a device installed above the down-hole test equipment to allow circulation of fluids through the drill string; and
  2. a remote controlled master valve installed on the testing head.

4.6 Servicing blowout prevention

The operator of a well during completion, workover, re-entry, plugging, plugging-back, servicing or reconditioning, except solution mining wells where there is no pressure in the salt cavern or gallery, shall ensure that:

  1. the well is under control;
  2. blowout prevention equipment is installed and maintained to enable the shut off of any flow from the well regardless of the type or diameter of tools or equipment in the well;
  3. the blowout prevention equipment installed is in accordance with the well classification and specifications set out in section 4.6.3;
  4. the blowout prevention equipment has a pressure rating equal to or greater than the pressure rating of the production casing flange, or the formation pressure, whichever is the lesser;
  5. hydraulic ram type blowout preventers which are not equipped with an automatic ram locking device, have hand wheels either installed or readily accessible for installation; and
  6. for hydrocarbon salt cavern storage wells, the requirements of Class II servicing blowout prevention requirements are met.

4.6.1 Flowing Class I gas wells

Notwithstanding section 4.6, clause (a), gas wells in Class I may be completed, serviced or reconditioned while the well is flowing.

4.6.2 Lubricator

A full lubricator system may be used in place of or in conjunction with blowout prevention equipment specified in this Part when performing well servicing operations that are normally conducted through the wellhead assembly such as perforating, logging or stimulating wells.

4.6.3 Servicing well classes

For the purpose of the servicing blowout prevention requirements and the blowout prevention equipment required in Schedule 2, wells are classified as set out below:

  1. Class I: a well in which the reservoir pressure of the zone is less than 5500 kilopascals, and there is no hydrogen sulphide present in the representative sample of the gas and the well is;
    1. a gas well, or
    2. included in a waterflood scheme;
  2. Class II: a well where the pressure rating of the production casing flange is less than or equal to 21,000 kilopascals and the hydrogen sulphide content in a representative sample of the gas is less than 10 moles per kilomole;
  3. Class III: a well where the pressure rating of the production casing flange is;
    1. greater than 21,000 kilopascals, or
    2. less than or equal to 21,000 kilopascals and the hydrogen sulphide content in a representative sample of the gas is 10 moles per kilomole or greater.

4.6.4 Hydraulic operation

All blowout preventers shall be hydraulically operated and connected to an accumulator system that shall be:

  1. installed and operated in accordance with the manufacturer's specifications;
  2. connected to the blowout preventers with lines of working pressure equal to the working pressure of the system and within 7 metres of the well the lines shall be of steel construction unless completely sheathed with adequate fire resistant sleeving;
  3. capable of providing, without recharging, fluid of sufficient volume and pressure to effect full closure of all preventers, and to retain a minimum pressure of 8400 kilopascals on the accumulator system;
  4. recharged by a pressure controlled pump capable of recovering within five minutes the accumulator pressure drop resulting from full closure of all preventers;
  5. capable of closing any ram type preventer within 30 seconds;
  6. capable of closing the annular preventer within 60 seconds;
  7. equipped with readily accessible fittings and gauge to determine the pre-charge pressure; and
  8. equipped with a check valve between the accumulator recharge pump and the accumulator.

4.6.5 Accumulator system

The accumulator system shall be connected to a nitrogen supply capable of closing all of the blowout preventers installed on the well.

4.6.6 Nitrogen supply

The nitrogen supply shall:

  1. be capable of providing sufficient volume and pressure to effect full closure of all preventers, and to retain a minimum pressure of 8400 kilopascals, and
  2. have a gauge installed or readily available for installation, to determine the pressure of each nitrogen container.

4.6.7 Class I and II BOP system

For wells in Classes I and II the blowout prevention system:

  1. may utilize the rig hydraulic system to recharge the accumulator; and
  2. shall have operating controls for each preventer in a readily accessible location near the operator's position, and an additional set of controls located at a distance from the well of not less than 5 metres.

4.6.8 Class III BOP system

For wells in Class III the blowout prevention system shall have:

  1. an independent accumulator system with operating controls for each preventer located at least 25 meters from the well, shielded or housed to protect the operator from flow from the well; and
  2. an additional set of controls in a readily accessible location near the operator’s position.
4.6.8.1 Class I BOP system

For gas wells in Class I the blowout prevention system shall have:

  1. a diverter system consisting of two 50 millimetre nominal diameter lines, or one 75 millimetre line, connected to a valved spool below the blowout preventers, extending at least 20 metres from the well and securely tied down;
  2. a shut-off device installed in the bottom joint of tubing to prevent flow when tripping the tubing into or out of the well; and
  3. a tubing stripper.
4.6.8.2 Class II and III BOP lines

For wells in Class II and III the blowout prevention system shall have two lines, one for bleeding off pressure and one for killing the well, which shall:

  1. be either steel, or flexible hose;
  2. be valved and having a working pressure equal to or greater than that required for the blowout prevention equipment described in section 4.6.3(c);
  3. have one line connected to the rig pump and one line connected to the tank;
  4. be fitted with the necessary equipment to allow one line to be connected to the tubing and a second line to be connected to the well annulus using;
    1. a flanged outlet on the blowout preventer below the lowest set of rams, or
    2. an outlet on a spool located below the blowout preventers;
  5. be at least 50 millimetres nominal diameter; and
  6. be securely tied down.

4.6.9 Class II and III BOP manifold

The blowout prevention system for wells in Class II and III shall include a manifold which shall:

  1. consist of an arrangement of valves and steel lines which have a working pressure equal to that of the blowout prevention system specified in Schedule 2 for the applicable class of well;
  2. contain a check valve to prevent flow from the well to the rig pump;
  3. contain a pressure relief valve upstream of the check valve; and
  4. be equipped with an accurate pressure gauge, which shall be either installed or readily accessible for installation.

4.6.10 Pressure gauge

An accurate pressure gauge to determine the well annulus pressure during a well shut-in shall be either installed or readily accessible for installation.

4.6.11 Safety valve (stabbing valve)

The operator shall maintain on the service rig in a readily accessible location a full opening safety valve in the open position which can be attached to the tubing or other pipe in the well.

4.6.12 Pressure test

Before commencing operations at a well, except for a well in Class I, the operator shall ensure that a 10-minute pressure test is conducted on:

  1. each ram preventer to 1400 kilopascals, prior to the tests described in (b) and (c);
  2. each ram preventer, the full opening safety valve and the connection between the stack and the wellhead to the wellhead pressure rating or the formation pressure, whichever is less, and
  3. each annular preventer to 7000 kilopascals or the formation pressure, whichever is less.

4.6.13 Annular preventer tests

For an annular type blowout preventer, all mechanical and pressure tests required by this section shall be conducted with pipe in the hole.

4.6.14 BOP mechanical tests

The operator of a well shall ensure that the blowout prevention equipment is mechanically tested daily and any equipment found defective shall be made serviceable before operations are resumed.

4.6.15 Test recording

All tests shall be reported in the servicing log book, and in the case of a pressure test the report shall state the blowout preventer tested, the test duration and the test pressure.

4.6.16 BOP servicing

At least once every three years all blowout preventers shall be shop serviced and shop tested to their working pressure and the test data and the maintenance performed shall be recorded and kept by the operator.

4.6.17 Training

At all times the operator of the well shall ensure that:

  1. a driller who is the holder of a valid certificate issued by the Petroleum Industry Training Service in well service blowout prevention and well control procedures is on the well site at any time operations are in progress;
  2. the rig crew is trained in the operation of the blowout prevention equipment;
  3. blowout prevention drills are performed by each rig crew every seven calendar days; and
  4. drills are performed in accordance with clause (c) are recorded in the servicing logbook.

4.6.18 Cold weather

During cold weather operations sufficient heat shall be provided to maintain the effectiveness of the blowout prevention system.

4.7. Equipment setback requirements

The location of equipment used at the well site shall be spaced in accordance with the distances specified in Figure 2 and Part 5.