Per Bulletin 2004-18 issued with the release of the June 2004 edition of Directive 036: "certain changes in Directive 36 affect underbalanced operations with regard to procedures and equipment requirements, specifically .... Section 10, Section 20, Section 23, Section 24"

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Interim Directive ID 94-3

18 July 1994

TO: All Oil and Gas Operators

UNDERBALANCED DRILLING

INTRODUCTION

A drilling technology which has become known as "underbalanced drilling" is being used throughout Alberta to complete new wells and to deepen or drill horizontally from existing wellbores. The purpose of this interim directive (ID) is to:

• clearly define the term "underbalanced drilling" as it regards regulatory requirements,
• set out the ERCB's requirements and application procedures for these operations, and
• announce publication of a set of Recommended Practices developed for underbalanced drilling by the Drilling and Completions Committee (DACC).

BACKGROUND

In recent years, growing interest in underbalanced drilling has resulted in the rapid development of its associated equipment technology, practices, and procedures. About mid 1993, the ERCB proposed that a sub- committee of DACC be struck to develop safety and environmental operating guidelines for underbalanced drilling. The Underbalanced Drilling Sub-Committee was subsequently formed with representatives from the Canadian Association of Oilwell Drilling Contractors (CAODC), Canadian Association of Petroleum Producers (CAPP), Petroleum Services Association of Canada (PSAC), Alberta Occupational Health and Safety (OH&S), and the Energy Resources Conservation Board (ERCB).

The committee has now completed development of a set of recommended practices which have been endorsed by all industry associations and regulatory bodies represented on the committee.

DEFINITION

For the purpose of this ID and the associated recommended practices, underbalanced drilling is defined as follows:

When the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled, the operation will be considered underbalanced drilling. The hydrostatic head of the drilling fluid may be naturally less than the formation pressure or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether induced or natural, this may result in an influx of formation fluids which must be circulated from the well and controlled at surface.

Note: The Underbalanced Drilling Sub-Committee recommends that any time the effective hydrostatic pressure of the liquid phase of a drilling fluid is intentionally reduced by the injection of a gas while drilling, underbalanced drilling practices should be applied regardless of whether or not the operator intends on achieving an underbalanced state.

SCOPE

Underbalanced drilling is as much a completion technique as it is a drilling technology. Subsequently, careful consideration had to be given to the various elements from both disciplines in developing this ID and the associated recommended practices. Further, since the definition of underbalanced drilling includes operations outside of the scope of this ID, it is necessary to identify very specifically what is and what is not included within its scope. These are defined as follows:

What Is Included

• Wells in which sufficient casing has been set to safely perform a complete shut-in of a well without fracturing formations in the open hole. Typically, the casing will be set very near the objective formation.

What Is Not Included

• Traditional hard rock air drilling in the upper section of deep foothills and mountain area wells.
• Drilling through abnormally pressured formations, typically containing high pressure low volume gas (e.g. Milk River Formation in Southeastern Alberta or the Banff Formation in the mountains and foothills). Adequate precautions including specialized equipment and procedures must be used to maintain well control in these wells until the abnormally pressured formation is cased off. The equipment and procedures used to drill through these problem formations may result in the need to acquire exemptions from existing ERCB regulations, and therefore requires ERCB approval.

NEW REQUIREMENTS

The items selected for strict enforcement by the ERCB have been identified from among the recommended practices. The remaining recommended practices will not however be enforced by the ERCB. DACC believes that strict enforcement of the recommended practices is not desirable. DACC's position is that the recommended practices, having been endorsed by the primary industry associations in Alberta, places considerable legal and moral responsibility on operators and contractors involved in underbalanced drilling to follow the recommended practices or to otherwise provide technically equivalent or better practices. The ERCB accepts this position and will provide a copy of the recommended practices as an attachment to this ID and as an Appendix to both the Drilling and Service Rig Inspection Manuals, Guides G-36 and G-37.

The following are those recommended practices selected for strict enforcement. These specific recommended practices are now ERCB requirements for all underbalanced drilling operations:

1. The blowout prevention system shall conform to the configurations shown in Appendix I and Appendix II of the recommended practices.
2. Tripping procedures shall be in accordance with section 1. 1.4 of the recommended practices.
3. Personnel Well Control Certification shall be in accordance with section 3.2 of the recommended practices.

APPLICATION PROCEDURE

Currently, each application for underbalanced drilling requires a detailed submission from the applicant. The ERCB no longer requires these submissions. In place, the ERCB requires acknowledgment in each well licence application and each application to resume drilling that underbalanced drilling is planned. Further, the applicant shall state that the operation has been designed and will be drilled in accordance with this ID. Detailed information supporting this statement shall be made available upon being requested by the ERCB. Failure to provide this information when requested will result in the application being held over for approval until a satisfactory submission of the information is received.

Attached is a copy of the recommended practices. Additional copies may be obtained at the ERCB by requesting a copy of this ID. Questions regarding this ID should be directed to the Drilling and Production Department at 297-8186.

[signed by]

R. G. Evans, P. Eng.
Board Member

Attachment

RECOMMENDED PRACTICES FOR UNDERBALANCED DRILLING

Published: July 1994

INTRODUCTION

DEFINITION

SCOPE

EXPLANATION OF EMPHASIS

THE RECOMMENDED PRACTICES
1.0 WELL CONTROL EQUIPMENT AND PROCEDURES

• 1.1 BLOWOUT PREVENTION (BOP) SYSTEM
  • 1.1.1 Design Considerations
  • 1.1.2 Surface BOP System
  • 1.1.3 Sub-surface BOP System
  • 1.1.4 Tripping Procedures
  • 1.1.5 Specialized Equipment and Procedures for Sour Well Operations

2.0 SURFACE HANDLING OF FLUIDS

• 2.1 OPEN TANK SYSTEMS
• 2.2 DIVERTER LINE TO FLARE PIT SYSTEMS
• 2.3 CLOSED SYSTEMS
  • 2.3.1 General
  • 2.3.2 Separator Flow Line Design
  • 2.3.3 Separator Design Considerations
• 2.4 SPECIALIZED EQUIPMENT AND PROCEDURES FOR SOUR WELLS
• 2.5 STORAGE AND DISPOSAL OF PRODUCTION AND WASTE

3.0 SAFETY AND SUPERVISION

• 3.1 WELL SITE SUPERVISION
• 3.2 WELL CONTROL CERTIFICATION
  • 3.2.1 Well Site Supervisor
  • 3.2.2 Rig Manager and Driller
  • 3.2.3 Coiled Tubing Operators
• 3.3 MONITORING
• 3.4 COMMUNICATIONS
• 3.5 INSPECTIONS
• 3.6 PRE-PLANNING
• 3.7 CONFINED VESSEL ENTRY
• 3.8 PERSONAL SAFETY EQUIPMENT
• 3.9 LIGHTING
• 3.10 FIRE FIGHTING EQUIPMENT

APPENDIX I - DRILLING AND SERVICE RIG BOP STACK-UNDERBALANCED DRILLING

APPENDIX II - COILED TUBING BOP STACK FOR UNDERBALANCED DRILLING

APPENDIX III - SURFACE HANDLING OF FLUIDS FOR CLOSED SYSTEMS

GLOSSARY

LIST OF REFERENCES

INTRODUCTION

The growing interest in underbalanced drilling and the rapid development of its associated technology in recent years, has taken place without documentation of proven safe operating practices. Concerned with this, Industry, Alberta Occupational Health and Safety, and the Energy Resources Conservation Board subsequently formed a committee known as the "Underbalanced Drilling Sub-committee" to prepare recommended practices to serve as a guide for both operators and regulators. These recommended practices are viewed as minimum standards, however, they do allow for a significant degree of flexibility in achieving their various objectives.

The Underbalanced Drilling Sub-Committee completed this task under the auspices of the Drilling and Completions Committee (DACC). DACC is comprised of individuals representing: Canadian Association of Petroleum Producers (CAPP), Canadian Association of Oilwell Drilling Contractors (CAODC), Petroleum Services Association of Canada (PSAC), Alberta Occupational Health and Safety (AOH&S), and the Energy Resources Conservation Board (ERCB). The Underbalanced Drilling Sub committee was comprised of representatives from all of the DACC member associations and regulatory bodies.

DEFINITION

For the purpose of these recommended practices, underbalanced drilling is defined as follows:

When the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled, the operation will be considered underbalanced drilling. The hydrostatic head of the drilling fluid may be naturally less than the formation pressure or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether induced or natural, this may result in an influx of formation fluids which must be circulated from the well and controlled at surface.

Note: The Underbalanced Drilling Sub-Committee recommends that any time the effective hydrostatic pressure of the liquid phase of a drilling fluid is intentionally reduced by the injection of a gas while drilling, underbalanced drilling practices should be applied regardless of whether or not the operator intends on achieving an underbalanced state.

SCOPE

These recommended practices are intended for wells in which sufficient casing has been set to safely perform a complete shut-in of a well without fracturing formations in the open hole. Typically, casing is set very near the objective producing formation. The recommended practices address the primary safety and environmental challenges which are inherent in this type of operation. These recommended practices have been categorized into three subject areas as follows:

RP 1.0 WELL CONTROL EQUIPMENT AND PROCEDURES

RP 2.0 SURFACE HANDLING OF FLUIDS

RP 3.0 SAFETY AND SUPERVISION

EXPLANATION OF EMPHASIS

Throughout the recommended practices you will see use of the words "should" or "shall". Where the word "shall" has been used in a recommended practice, the consensus of the committee was, that it must be followed at any underbalanced drilling operation. Where the word "should" is used, the committee as a whole did not believe it was absolutely necessary to observe the recommended practice on all underbalanced drilling operations. The committee does, however, believe that all of the recommended practices need to at least be given serious consideration in preparing for any underbalanced drilling operation.

RP 1.0 WELL CONTROL EQUIPMENT AND PROCEDURES

1.1 BLOWOUT PREVENTION (BOP) SYSTEM

1.1.1 Design Considerations

The amount and type of equipment needed is affected by the magnitude of the surface pressures expected, the method of pipe rotation (top drive or rotary table), the nature of the reservoir fluids to be encountered (sweet/sour/oil/gas) and the type of drilling fluid system to be used. Taking these factors into consideration, underbalanced drilling requires a BOP system which simultaneously:

• permits drilling to proceed while controlling annular pressure,
• allows connections to be made either with the well flowing or shut-in,
• allows tripping of the drill string under pressure to change bits or bottomhole assemblies,
• provides for backup annular control in case of diverter failure,
• provides equipment which allows annular pressure to be varied so that it will not exceed the rated working pressure of the surface equipment,
• provides a means to bleed oft pressure or to kill the well independent of the diverter system, and
• provides a means to quickly and safely shut-in the well.

1.1.2 Surface BOP System

A BOP Stack Configuration For Drilling and Service Rigs and Coiled Tubing Units

As a minimum, the BOP stack shall consist of an ERCB Class III well servicing configuration as set out in Schedule 10 of the Oil and Gas Conservation Regulations. In addition, this BOP stack shall have:

• a diverter line and diverter preventer,
• the capability to bleed off pressure to flare in the event of a diverter line obstruction or other operation requiring bleed off separately from the production vessel,
• the capability to equalize pressure between the diverter line and a point below the lowest ram type preventer (excluding coiled tubing BOP stacks and wells having an H2S content less than 10 ppm and a maximum tubing head pressure of less than 7000 kPa).
  Note: Appendix I illustrates a drilling or service rig BOP stack for underbalanced drilling.
  Appendix II illustrates an example of a Coiled Tubing BOP configuration for underbalanced drilling.

B Diverter Preventer

• The diverter preventer shall be capable of providing a seal between the wellbore and the rig floor while drilling or tripping.
• With the exception of coiled tubing units, conventional annular preventers or rotating blowout preventers (RBOP) should be used. However, rotating heads and pack-off devices traditionally used in air drilling or for shallow gas diversion, may be appropriate provided that the manufacturer supports this use and has completed testing to prove its reliability under a site specific range of conditions for its intended use.
• The accumulator system used to control the diverter preventer shall be independent of the rig's standard accumulator system.

C Blind Shear Rams

• The use of blind shear rams shall be dictated by existing drilling and servicing regulations.
  Note: Blind shear rams should be considered for underbalanced drilling of wells with high hydrogen sulphide (H₂S) release rate potential or where the proximity to the public is such that an ERCB approved site specific emergency response plan is required.

D Diverter/Flow Line

• At least one valve shall be installed in the diverter/flow line immediately adjacent to the BOP stack. This valve may be either manually or remotely operated.
  Note: Recommended practices for diverter/flow line configuration and design are discussed in greater detail in the Surface Handling of Fluids Section 2.3.2.

E Practices

• No primary well control equipment (blowout preventers other than the diverter preventer) shall be used for stripping, snubbing, or drilling except in emergency situations.
• BOP equipment shall be tested and inspected in accordance with existing ERCB regulations.
• In wells that are capable of flowing to surface without induced gasification of the drilling fluid:
  • The intermediate/production casing should be cemented to surface or the surface casing vent should be tied into a flare line extending to a flare pit.
    Note: This precaution may be necessary in the event of a casing failure above the cement top. A failure of this type recently occurred, bringing this important consideration to our attention.
  • Consideration should be given to the installation and energizing of a secondary seal in the spool above the surface casing head if the intermediate casing is not cemented to surface.
    Note: This is to prevent wellbore pressure from being exerted down through the surface casing /intermediate casing annulus in the event of a primary seal failure.

F Bleed Off and Kill Lines

• Bleed Off and Kill Lines shall conform with existing ERCB well servicing regulations.
• Both hammer union and flanged connections are acceptable downstream of the first valve off the BOP stack. Only flanged connections shall he used up to and including the connection to the first valve.

1.1.3 Sub-surface BOP System

• At least two non-ported devices (floats) to prevent back flow from the well should be installed near the bottom of the drill string while drilling underbalanced. One of these devices can be a profile nipple designed to accommodate a pump-down back-flow device.
• Air, air-mist, and air-foam drilling has resulted in several downhole fires in recent years. When planning to use air in a drilling fluid for underbalanced drilling, precautions shall be taken to ensure explosive mixtures are not generated at any point in the operation except at the end of the flare line.
  Note: From a well control perspective, the primary concern with downhole fires and explosions is the potential for parting of the drill string above the drill string floats and casing failure above the cement top of the intermediate casing.

1.1.4 Tripping Procedures

• At no time shall the wellbore be left open to the working floor when the well is live.
• When a float sub is pulled to the floor, equipment should be used and procedures should be followed to safely remove trapped gas below the float before removing the float from the drill string.
• When tripping from live sour wells, consideration should be given to setting wireline or pump down type plugs near the bottom of the drill string.
• If a well is killed prior to tripping, traditional tripping procedures including the completion of trip sheets should be followed.
• In wells that will be live while tripping, the appropriate calculations shall be made to determine whether pipe light (weight of pipe less than force of wellbore pressure pushing upward on pipe) conditions will occur. If potential pipe light conditions may occur, preparations should be made to facilitate snubbing operations.
• A pressure indicator with readout visible at the drillers station should be installed below the blind rams to monitor wellbore pressure while the drill pipe is out of the hole.
• A minimum kill fluid volume equal to one hole volume, shall be stored on location. Capability to pump the kill fluid should only require the opening and closing of two valves.

1.1.5 Specialized Equipment and Procedures for Sour Well Operations

Note: The Alberta Recommended Practices (ARPs) for Drilling Critical Sour Wells-ARP Volume 1 and ARP Volume 2-Completing and Servicing Critical Sour Wells are a valuable reference when preparing a program to drill sour wells underbalanced Reference to these ARPs is mandatory for critical sour well operations in Alberta.

• The drill pipe and casing should be designed to minimize the potential for failure from exposure to hydrogen sulphide (H₂S) gas.
• The BOP stack, flow/diverter line, and bleed oft and kill lines should be designed to minimize the potential for failure from exposure to H₂S in accordance with NACE specifications.

RP 2.0 SURFACE HANDLING OF FLUIDS

The surface handling of fluids at underbalanced drilling operations is very similar to conventional production testing In June 1993, the Drilling and Completions Committee (DACC) published Alberta Recommended Practices (ARPs) Volume 4 - Well Testing and Fluids Handling. Much of the material covered by these recommended practices is directly applicable to underbalanced drilling. Although some of the specific sections in ARP Vol. 4 are referenced below, these ARPs can serve as a general guide when designing a program for fluids handling during underbalanced drilling operations.

2.1 OPEN TANK SYSTEMS

2.1.1 Since open tank systems may result in the release of combustible vapours, special precautions shall be taken to eliminate sources of ignition near the tanks. Strict adherence to the ERCB and Alberta Labour-Electrical Safety Division requirements regarding safe separation distances to open flames, internal combustion engine exhausts and electrical sources of ignition is essential.

Note: Refer to Alberta Labour's Summary of Oil and Gas Drilling Rig Electrical Classification Areas in Alberta and ARP 4.2, Appendices II, III and IV for illustrations of the specific separation distances.

2.1.2 Continuous monitoring for explosive vapours, H₂S and oxygen deficient areas shall be conducted.

2.1.3 Own tank systems shall not be used for sour well operations.

Note: For the purpose of this recommended practice, sour wells are ones which contain an H₂S concentration equal to or greater than 10 ppm from a representative wellhead sample. Regardless of the concentration of H₂S, no sour gas may be released to atmosphere at any time.

2.1.4 If an atmospheric liquid-gas separator is used, the flare line should not be ignited unless a CSA approved detonation type flame arrestor is installed.

Note: Refer to ARP 4.3.6.1 regarding the design and installation of liquid-gas separators.

Consideration for the periodic removal of solids buildup below the separator should be made as this buildup may interfere with the performance of the separator.

2.2 DIVERTER LINE TO FLARE PIT SYSTEMS

2.2.1 This system should only be used for drilling sweet wells with natural gas, air or air-mist drilling fluids.

2.2.2 No reservoir liquids shall be produced to the flare pit.

2.2.3 A continuous purge of the diverter line should be conducted during circulation, start-up and shut-down, and when making connections.

2.3 CLOSED SYSTEMS

2.3.1 General

• Only non-combustible mixtures shall be flowed through the separator. Normally, this eliminates the use of air-type drilling fluid systems.
  Note: Monitoring for explosive mixtures inside of vessels and flow lines should be conducted when drilling fluids are designed to include oxygen (air-type systems).
• An inert gas purge system shall be rigged into the separator inlet line. A pressure relief valve should be installed on the purge gas line.
• All pressure vessels and production tanks shall be electrically bonded and grounded as per Alberta Labour's Electrical Safety Requirements.

2.3.2 Separator Flow Line Design

• The working pressure of the flow line shall be equal to or greater than the maximum well head shut-in pressure. As a minimum, this flowline shall be constructed in accordance with Appendix I of ARP 4.2 - Well Testing and Fluids Handling.
• The flow line shall be sized based on maximum flow rates and pressures but should not be less than 75 mm in diameter.
  Note: Erosion and hydrating problems increase with large pressure drops.
• Flow lines greater than 100 mm in diameter should be flanged. Flow lines 100mm in diameter or less may use hammer union connections provided that the end connections are welded to the pipe.
  Note: Welding of pipe and fittings is covered in ARP 4.2.6.2.6.
• A routine inspection and maintenance program shall be in place and documented as per ARP 4.2.9.2.
• The flow line shall be hydrostatically pressure tested to the maximum expected wellhead shut-in pressure.

2.3.3 Separator Design Considerations

• The first stage of separation shall be through a certified Boilers Branch approved vessel.
• The design shall be capable of completing the safe and efficient separation of liquids, gases and solids based on anticipated flow rates, pressures and flare line size.
  Note: Separator design capacity should be increased to accommodate slug flow if expected.

2.4 SPECIALIZED EQUIPMENT AND PROCEDURES FOR SOUR WELLS

Note: For the purpose of these recommended practices, sour wells are ones which contain an H₂S concentration equal to or greater than 10 ppm from a representative wellhead sample. Regardless of the concentration of H₂S, no sour gas may be released to atmosphere at any time.

2.4.1 No produced fluids containing H₂S or drilling fluids contaminated with H₂S shall be stored in open tanks.

2.4.2 The flare stack shall be a minimum of 12 metres in height and be equipped with an electronic igniter or continuous pilot system.
Note: A flare permit must be obtained from the ERCB if H₂S concentrations exceed five per cent.

2.4.4 A remotely operated hydraulic control valve (HCR) or an emergency shut down valve shall be installed as shown in Appendixes I, II, and III.

2.4.5 The sampling procedure for obtaining both drill cutting and well effluent samples should follow the safety stand-by system as described in ARP 4.2.2.7.

Note: Purging of the sample catcher with nitrogen, sweet gas, or propane is recommended.

2.4.6 The sour service equipment specification set out in ARP 4.2.7. should be referenced when selecting fluids handling equipment for drilling sour wells underbalanced.

2.4.7 A pressurized tank or a tank truck equipped with a functional H₂S scrubber should be used for the transportation of sour fluids off location. Reference ARP 4.4.5.4

2.5 STORAGE AND DISPOSAL OF PRODUCTION AND WASTE

2.5.1 Adequate provision shall be made for the safe storage and/or disposal of produced fluids and drill cuttings. Reservoir liquids shall not be produced to an earthen pit.

Note: Refer to ERCB Guide G-50 for further details on waste disposal.

2.5.2 For wells which contain H₂S, drill cuttings shall be held in tanks equipped with vapour control. Vapours shall either be vented to a flare stack or through an H₂S scrubbing system.

RP 3.0 SAFETY AND SUPERVISION

Note: For the purpose of these recommended practices, sour wells are ones which contain an H₂S concentration equal to or greater than 10 ppm from a representative wellhead sample. Regardless of the concentration of H₂S, no sour gas may be released to atmosphere at any time.

3.1 WELL SITE SUPERVISION

• When running 24 hour operations, a minimum of two qualified well site supervisors should be on site, working alternating 12-hour shifts.
• A minimum of two qualified personnel dedicated to the operation of the separation and fluids handling system shall be on shift at any time while drilling sour wells underbalanced.

3.2 WELL CONTROL CERTIFICATION

3.2.1 Well Site Supervisor

The Well Site Supervisor shall be certified in either Well Service Blowout Prevention or Second Line Supervisors Well Control.

3.2.2 Rig Manager and Driller

In accordance with existing drilling and servicing regulations, only the driller is required to have valid well control certification. The driller may have either a First Line Supervisors Blowout Prevention or a Well Service Blowout Prevention Certificate.

Note: Rig Managers are required to have valid Second Line Supervisors Well Control certificates when working on critical sour wells.

3.2.3 Coiled Tubing Operators

The coiled tubing operator will not require well control certification. The coiled tubing operator shall however, have sufficient experience, knowledge and training in coiled tubing live well operations to be able to respond in an appropriate and safe manner to all well control problems that may arise.

Note: A sub-committee of the Drilling and Completions Committee (DACC) was recently formed by coiled tubing operators with the purpose of developing operating guidelines which may include minimum well control certification.

3.3 MONITORING

3.3.1 If H₂S is expected to be encountered in the well, a monitoring program shall be in place. As a minimum, monitoring stations should include the rig floor, inside the rig substructure adjacent to the BOPs, and near separation vessels and storage or circulating tanks.

3.3.2 Explosive potential monitoring should be conducted anywhere there is a potential to release combustible vapours to atmosphere. Monitoring stations should include those described in recommended practice 3.3. l.

3.4 COMMUNICATIONS

3.4.1 An intrinsically safe portable communications system shall be used on the wellsite. All essential personnel shall be in contact with one another. These typically will include, but are not limited to, the following:

• Well Site Supervisor
• Rig Manager
• Driller
• Safety Supervisor
• Well Testers
• Nitrogen Operator
• Air Compressor Operator

3.4.2 If the underbalanced drilling operation lasts more than 24 hours, consideration should be given to using a central command centre in which all essential services described in recommended practice 3.4.1 are represented.

3.5 INSPECTIONS

Daily walk around checks should be performed by the wellsite supervisor, the drilling contractor and service company representatives, to ensure that equipment is functioning safely and no safety hazards have developed.

3.6 PRE-PLANNING

3.6.1 A site-specific emergency contingency plan should be prepared to a level of complexity that the operation warrants, prior to any underbalanced drilling taking place.

3.6.2 While still in the design stage, a meeting including all key personnel should be held to discuss the proposed operation so that everyone clearly understands their responsibilities with respect to safety. A key element in planning a safe operation is the site layout. The following considerations should be made when designing the well-site layout:

• Prevailing winds
• Access to fluids handling equipment
• Equipment placement
• High pressure line placement (should be clearly identifiable and not placed in a travelled area of the location)

3.7 CONFINED VESSEL ENTRY

3.7.1 Operators shall observe all Occupational Health and Safety regulations for confined vessel entry.

3.7.2 Personnel conducting operations in confined areas shall be trained in confined vessel entry.

3.8 PERSONAL SAFETY EQUIPMENT

3.8.1 Respiratory protective equipment shall be used in accordance with Part 5 of the Occupational Health and Safety Regulations. This regulation puts the onus on the operator to assess the need for respiratory protective equipment and to ensure it is available in sufficient quantity and used appropriately by workers. For sour well locations, this means that enough equipment shall be available for both operating and evacuation.

3.8.2 Clothing

Clean and approved fire retardant clothing shall be worn by all personnel on location.

3.9 LIGHTING

Adequate lighting of all working and traffic areas shall be provided. Traffic areas include both vehicular and pedestrian traffic.

3.10 FIRE FIGHTING EQUIPMENT

When hydrocarbons are being produced or when they are used in the drilling fluid, supplementary fire fighting equipment should be considered. This may require as little as additional hand-held fire extinguishers to as much as having a fire fighting vehicle on-site.

GLOSSARY

This glossary is meant to cover only new terminology or old terminology used in the context of underbalanced drilling.

Diverter Preventer - The preventer that seals off the annular space at surface to permit drilling and tripping under pressure. The preventer used for this purpose may be a conventional annular preventer, rotating blowout preventer (RBOP), rotating head, or pack-off device.

Conventional Annular Preventer - A hydraulically actuated, piston operated stationary preventer capable of sealing off the annular space around pipe or closing to seal off open hole with working pressure ratings starting at 14,000 kPa. Annular pressure applied to pipe while stripping can be controlled by regulating hydraulic pressure with a stripper regulator.

Rotating Blowout Preventer - Annular preventer designed to rotate with pipe rotation and capable of providing a seal on both smooth pipe or the kelly stem. Working pressure ratings while rotating start at about 10,000 kPa. Designed specifically for underbalanced drilling.

Rotating Head - A low pressure diverter designed for rotation with drill pipe or kelly stem. Manufacturer may not publish working pressure ratings. Primarily used for air drilling.

Pack-off Device - Non-rotating annular preventer simple in design. Contains no piston operation and may or may not have hydraulic actuation.

Flow Control Valve/Manifold - A valve or manifold used to regulate well bore pressure and to control the pressure exerted on vessels and flowlines downstream of this flow control valve or manifold.

Diverter/Separator Flowline - The portion of the flow line between the BOP stack and the flow control valve/flow control manifold.

Slug Flow - The rapid increase in flow rate of fluids from a well.

Central Command Centre - An office at the well site which accommodates representatives from all of the essential operational services. It is also the central command for all radio communications. This facility is not used as sleeping quarters.

REFERENCE LIST

1. Alberta Recommended Practices For Drilling Critical Sour Wells, ARP Volume l, July 1987, Calgary, Alberta.
2. Alberta Recommended Practices For Completing and Servicing Critical Sour Wells, ARP Volume 2, April 1989, Calgary, Alberta.
3. Alberta Recommended Practices For Well Testing and Fluid Handling, ARP Volume 4, June 1993, Calgary, Alberta.
4. Oil and Gas Conservation Regulations, Energy Resources Conservation Board, Calgary, Alberta.
5. Occupational Health and Safety Regulations Part 5, Occupational Health and Safety, Alberta Labour-Client Services Division, Edmonton, Alberta.
6. Summary of Oil and Gas Drilling Rigs Electrical Classification Areas in Alberta, Electrical Safety Division-Alberta Labour, Edmonton, Alberta.
7. National Association of Corrosion Engineers (NACE), Sulphide Stress Cracking Resistant Materials For Oilfield Equipment, 1994 Editorial Revision, MR-01-75, Houston, Texas.
8. Canadian Standards Association (CSA), Rexdale, Ontario.

APPENDIX 1: BOP STACK - UNDERBALANCED DRILLING

APPENDIX II: COILED TUBING BOP STACK UNDERBALANCED DRILLING

APPENDIX III: SURFACE HANDLING OF FLUIDS CLOSED SYSTEM EXAMPLE