Section

Changes Effective February 16, 2006

19.1 Oil-Based Mud Systems

The use of oil-based drilling fluids (or any other potentially toxic drilling additive) is prohibited when drilling above the "base of groundwater protection" depth. The base of groundwater protection refers to a depth of 15 metres below the deepest non-saline aquifer. The Water Act  (Alberta Ministerial Regulation 205/98) defines non-saline water as water with a total dissolved solids (TDS) content less than 4000 mg/l.

For more detailed information on base of groundwater protection, see EUB ST55: Alberta's Usable Groundwater Base of Groundwater Protection Information .

19.2 Crude Oil Used to Release Stuck Drill String (spotting)

When crude oil is used for spotting, the licensee must ensure that control of subsurface pressures will be maintained at all times during the spotting and circulation of the crude oil.

23.1.1 Drilling More Than 100 m or More Than One Hydrocarbon-bearing Formation

When the licensee is conducting drilling operations with a service rig, the operation is classified as a drilling operation if more than 100 m measured depth of new hole will be drilled or more than one potential hydrocarbon-bearing formation will be penetrated.

All requirements set out in Directive 036 must be complied with.

Section

Changes Effective July 1, 2006

1.1.5 Double Drilling/ Studding

Studding flanged equipment to accommodate connections to other American Petroleum Institute (API) equipment that may have a lower pressure rating results in a derating of the flange to the lower working pressure.

If a studded flange is used in an application requiring its original pressure rating, documentation must be provided from either the original equipment manufacturer (OEM) or a professional engineer (P.Eng.) that the flange is certified for the higher-pressure rating.

2.1.1 Diverter Line

The diverter line must have a working pressure at least equal to that of the required BOP system (1400 kPa).

The diverter line connections must be flanged, hammer union, threaded, or bolted groove lock type.

2.2.7 Degasser Inlet

For class II wells, the degasser inlet line must have a working pressure >7 MPa up to the connection on the degasser.

For well classes III-VI, the degasser inlet line must have a working pressure >14 MPa (schedule 40 pipe is acceptable) up to the connection on the degasser.

Degasser inlet lines should be accessible full length, and it is recommended that no portion of the line be submerged in drilling fluid. If a portion of the line is submerged, it must be tested annually to ensure competent wall thickness. Documentation records of this test must be available at the rig site.

2.2.8 Degasser Vent Line

Degasser vent lines should be accessible full length, and it is recommended that no portion of the line be submerged in drilling fluid. If a portion of the line is submerged, it must be tested annually to ensure competent wall thickness. Documentation records of this test must be available at the rig site.

2.2.9 Flare Line(s)

For class II wells, the flare line must have a working pressure >7 MPa.

For well classes III-VI, the flare line must have a working pressure >14 MPa (schedule 40 pipe is acceptable).

4.1 Bleed-off, Kill, or Diverter Line(s)

Flexible hoses used in the bleed-off, kill, or diverter line(s) must be fire sheathed if used within 7 m of the well.

Adequate fire-resistant sheathing for flexible hoses used in the bleed-off, kill, or diverter line(s) is defined as a hose assembly that can withstand a minimum of 5 minutes of 700 ^o C flame temperature at maximum working pressure without failure.

4.2 Flare and Emergency Flare Line(s)

Flexible hoses used in the flare and emergency flare line(s) must be fire sheathed if used within 7 m of the well.

Adequate fire-resistant sheathing for flexible hoses used in the flare or emergency flare line(s) is defined as a hose assembly that can withstand a minimum of 5 minutes of 700 ^o C flame temperature at maximum working pressure without failure.

6.1 Accumulator System

Class 1 wells require an accumulator system that is recharged by an automatic pressure controlled pump capable of recovering, within 5 minutes, the accumulator pressure drop resulting from the function test of the BOP components and the hydraulically controlled remote valve (HCR).

For class I wells, the accumulator system must be capable of providing, without recharging, hydraulic fluid of sufficient volume and pressure to open the HCR on the diverter line, close the annular preventer on the drill pipe, and retain a minimum pressure of 8400 kPa on the accumulator system.

When a CTU is used to drill a class V or VI well, the accumulator system must be capable of providing, without recharging, hydraulic fluid of sufficient volume and pressure to open the HCR on the bleed-off line, close the annular preventer on the drill pipe, close two ram preventers, and retain a minimum pressure of 8400 kPa on the accumulator system. In addition to the above functions, the accumulator system for CTUs must also provide sufficient volume and pressure to shear the coiled tubing and retain on the accumulator system a minimum pressure of 8400 kPa or the minimum pressure required to shear the coiled tubing, whichever is greater.

For critical sour wells, the accumulator system must be capable of providing, without recharging, hydraulic fluid of sufficient volume and pressure to open the HCR on the bleed-off line, close the annular preventer on the drill pipe, close, open, and close one ram preventer, and if blind/shear rams are installed, provide sufficient volume and pressure to shear the drill pipe and retain on the accumulator system a minimum pressure of 8400 kPa or the minimum pressure required to shear the drill pipe, whichever is greater.

If the existing accumulator system cannot meet these requirements because of the addition of the blind/shear rams, the accumulator system's capacity and/or pressure must be increased or a separate accumulator system must be installed. It is also acceptable to supplement the existing accumulator system with a nitrogen (N ₂ ) booster that will provide sufficient volume and pressure to shear the drill pipe and retain a minimum accumulator pressure of 8400 kPa or the minimum pressure required to shear the drill pipe, whichever is greater.

All non-steel BOP hydraulic lines located within 7 m of the wellbore must be completely sheathed with adequate fire-resistant sheathing.

Adequate fire-resistant sheathing for hydraulic BOP hoses is defined as a hose assembly that can withstand a minimum of 5 minutes of 700 ^o C flame temperature at maximum working pressure without failure.

6.2 Backup Nitrogen (N ₂ ) System

When a CTU is used to drill a class V or VI well, the backup N ₂ system must be capable of providing, without recharging, hydraulic fluid of sufficient volume and pressure to open the HCR on the bleed-off line, close the annular preventer on the drill pipe, close two ram preventers, and retain a minimum pressure of 8400 kPa on the accumulator system. In addition to the above functions, the backup N ₂ system must also provide sufficient volume and pressure to shear the coiled tubing and retain on the backup N ₂ system a minimum pressure of 8400 kPa or the minimum pressure required to shear the coiled tubing, whichever is greater.

For critical sour wells, the backup N ₂ system must be capable of providing N ₂ of sufficient volume and pressure to open the HCR on the bleed-off line, close the annular preventer on the drill pipe, close, open, and close one ram preventer, and if blind/shear rams are installed, provide sufficient volume and pressure to shear the drill pipe and retain on the backup N ₂ system a minimum pressure of 8400 kPa or the minimum pressure required to shear the drill pipe, whichever is greater. For critical sour wells, if the existing backup N ₂ system cannot meet these requirements because of the addition of the blind/shear rams, the backup N ₂ system's capacity and/or pressure must be increased or a separate backup N ₂ system must be installed. It is also acceptable to supplement the existing backup N ₂ system with an N ₂ booster (this may be the same N ₂ booster system that supplements the accumulator).

6.3.1 Floor Controls

A gauge indicating the accumulator system pressure must be available at the floor controls.

6.3.2 Remote Controls

The BOP remote operating controls must be capable of opening each BOP component.

9.1 Mud Tanks

All wells being drilled must have mud tanks with an appropriate mud tank fluid volume monitoring system.

9.3 Trip Tank -- Design and Fluid Level Monitoring

Well classes I and II must have a trip tank with a fluid level monitoring system.

The trip tank must

• be equipped with a fluid level-monitoring system that will accurately measure the volume of drilling fluid required to fill the hole while tripping the drill string from the well,
  
  
• be designed with both the suction and return lines connected to the trip tank when tripping the drill string into and from the well, and
  
  
• be equipped with a fluid level indicator that is visible from the driller's position in readable increments, and the driller must know the volume of fluid per increment for the system being used.

If the drill string is being circulated while tripping tubulars (coiled tubing units or top drives), hole fill volumes must be monitored using an automated mud tank fluid volume monitoring system that is electronically operated (see Sections 9.3.1 and 9.3.2 of Directive 036 ). This procedure (circulating while tripping) requires an isolated circulating system. Fluids must be circulated either from the trip tank with returns back to the trip tank or alternatively from the suction tank with returns directed back to the suction tank.

9.3.1 Well Classes I, II, and III

If a trip or suction tank is being used to monitor fluid volumes when wells are circulated during tripping operations (coiled tubing units or top drives) (see Section 9.3 of Directive 036 ):

• an automated fluid volume monitoring system must be used. This system must be capable of measuring changes of 0.04 m ³ or less and the monitoring system must have a minimum readout to 2 decimal places.

9.3.1 Well Classes V, VI

If a trip or suction tank is being used to monitor fluid volumes when wells are circulated during tripping operations (coiled tubing units or top drives) (see Section 9.3 of Directive 036 ):

• an automated fluid volume monitoring system must be used. This system must be capable of measuring changes of 0.08 m ³ or less and the monitoring system must have a minimum readout to 2 decimal places

11.3.3 Trip Records

For all well classes, when tripping the drill string out of the well:

• the total calculated and actual (measured) volumes must be recorded in the drilling logbook for each trip.

If the drill string is being circulated while tripping tubulars (i.e., coiled tubing units or top drives), actual hole fill volumes must be recorded at a minimum for every 100 m interval of drill pipe removed and for every 20 m interval of drill collars and recorded on the trip sheet. If tripping resumes without circulating, the trip tank must be used to monitor hole fill volumes. Flow checks must be conducted and recorded at all required intervals (see Section 11.3.1 of Directive 036 ) with the well in a static condition (pump off).

12.1 Electrical Appliances and Electrical Devices

Any electrical appliance or electrical device that is a potential source of ignition may not be used within a hazardous location (as defined in the Canadian Electrical Code, Part I, and as determined by the Code for Electrical Installations at Oil and Gas Facilities) without first shutting in the wellbore. Any electrical equipment to be used in a hazardous location must be specifically approved and suitable for its intended application.

During drilling operations, special circumstances (e.g., pipe inspection) may require the use of electrical devices (that are potential sources of ignition) within a hazardous location . These procedures must only take place after the licensee representative has first assessed on-site safety and strict safety procedures are set out and adhered to. This safety assessment and proposed procedures must be reviewed with the crew and documented in the tour reports prior to the operation being conducted.

For the purposes of oil and gas well drilling and servicing operations, the Canadian Electrical Code essentially defines hazardous location to mean premises (substructures, tanks, buildings, or parts thereof) in which there exists the hazard of fire or explosion due to the fact that highly flammable gases may be present.

Section

Changes Effective January 1, 2007

6.1 Accumulator System

All hydraulic BOP line end fittings located within 7 m of the wellbore must be fire rated to withstand a minimum of 5 minutes of 700^o C flame temperature at maximum working pressure without failure.

For well classes V and VI and critical sour wells, the accumulator system must be equipped with two separate automatic pressure-controlled recharge pumps. The primary pump must be capable of recovering, within 5 minutes, the accumulator pressure drop resulting from the function test (see Section 6.4.1 of Directive 036 ) of the BOP components and the HCR on the bleed-off line. The secondary pump must be capable of recovering, within 5 minutes, the accumulator pressure drop resulting from opening the HCR and closing the annular preventer on drill pipe (see Section 6.4.1 of Directive 036 ).