Drilling Rig Inspection Manual Important Message The EUB is updat updating ing public publicati ations ons that that pre-da pre-dated ted the amalg amalgama amatio tion n of the Energy Resources Conservation Board (ERCB) and the Public Utilities Board (PUB) in 1995. The Alberta Energy and Utilities Board (EUB) take the place of any references to the ERCB, PUB, or their full names. Major Major revisi revisions ons to EUB document documents s are occurr occurring ing as part part of regula regulator tory y reengineering and streamlining initiatives. In some cases, older publications are withdrawn or integrated into new ones. This document has not yet gone through the revision process. Please consult the latest Acts and Regulations to interpret and apply legal requirements.
Guide to manual About this manual Using the manual Policies Aeub responsibilities Conduct Safety Industry/government involvement Conducting the Inspection Arrival at well site Bop system requirements and specifications Bop controls Crew training and cert1fication Bop mechanical test Air shut-offs/diesel and gasoline gasoline engine spacing Accumulator sizing and operating operating policies Back-up nitrogen supply Winterizing bop equipment Spacing regulations Mud tank monitoring and tripping requirements Bop pressure test Well-site conditions Operator and contractor inspections Well-site records and signs Smoking Casino inspection Completing the inspection report General Information Mechanical tests Inspection results Remedial action Signatures and on-site discussions Special wells Appendices SA inspection reports Schedule 8- blowout prevention systems Aeub well license Maximum Maximum length of drill pipe that can be pulled pulled while tripping before fluid level drops 30 m Accumulator sizing calculations calculations - alternate method Back-up nitrogen calculations - alternate method Aeub crew training assessment assessment form Crew procedures form Serious deficiencies Significant deficiencies Bop fluid volumes (tables courtesy of p.i.t.s.) Alberta occupational health health & safety legislation (AOH&s) Minimum design and installation specifications for atmospheric open bottom mud-gas separator (degasser) Bop modifications blowout prevention - drilling with service requirements
Other bop modifications Spacing diagram Oilfield waste management inspection guidelines Coiled tubing drilling requirements Underbalanced drilling - rig requirements Critical well drilling requirements Drilling blowout prevention requirements modification
Alphabetical index A About this manual AOH&S Legislation Electrical Protection Branch Legislation Purpose of This Manual Accumulator sizing and operating policies Accumulator Requirements Accumulator Reservoir Venting Accumulator Specifications - Table No. 1 Accumulator Volume/Pressure Graph - Drawing No. 2 Determining Precharge Pressure Drilling or Servicing BOP Data - Drawing No. 1 Example Sizing Calculation Low-pressure Alarm System Precharge Requirements Recharge Pump Problems Recording Accumulator Specifications Sizing Calculations (Method 1) Sizing Methods Sizing Rechecks When lo Complete Sizing Calculations Accumulator sizing calculations - alternate method Aeub crew tra1ning assessment form Aeub responsibilities Aeub well license Air shut-offs/diesel and gasoline engine spacing Confirming Shut-off Test with Well-site Supervisors Disengaging Clutches Handling Spacing Problems Individual Motor Tests Reason for Shut-offs Shut-off Requirements Air shut-offs/diesel and gasoline engine spacing (cont’d) Shut-off Test Results Spacing for Vehicles without Air Shut-off Alberta occupational health & safety legislation Alphabetic index Appendices Alberta Occupational Health & Safety Legislation Accumulator Sizing Calculations - Alternate Method BOP Fluid Volumes Coiled Tubing Drilling Requirements Crew Procedures Form Critical Well Drilling Requirements Drilling Blowout Prevention Requirements Modification AEUB Crew Training Assessment Form AEUB Well License Back-up Nitrogen Calculations - Alternate Method
Maximum Length of Drill Pipe That Can Be Pulled While Tri Before Fluid Level Drops 30 m Minimum Design and Installation Specifications for Atmospheric Open Bottom Mud-Gas Separator (Degasser) Sample Inspection Reports Schedule 8 - Drilling Blowout Prevention Systems Serious Rig Deficiencies Significant Rig Deficiencies Underbalanced Drilling ARRIVAL AT WELL SITE Contact with Operator’s and Contractor’s Representative Request by Operator or Contractor that BOPs Not Be Checked B Back-up nitrogen calculations - alternate method Back-up nitrogen supply Example Nitrogen Calculation Nitrogen Bottle Usable Volume Graph - Drawing No. 3 Nitrogen Calculations (Method 1) . Nitrogen Calculation Methods Nitrogen Requirements Recording Nitrogen Particulars BOP CONTROLS Check Valve Installation Fire-proofing Hydraulic Lines Floor and Remote Requirements Master Control Location Manual Closing/Locking Handwheels BOP FLUID VOLUMES BOP MECHANICAL TEST BOP, Hydraulic Valve, Accumulator, and Recharge Pump Check BOP PRESSURE TEST Inspector’s involvement Handling Test Deficiencies Test Requirements BOP SYSTEM REQUIREMENTS AND SPECIFICATIONS Air Drilling Requirements Bleed-off Line Bleed-off Manifold and Gauges BOP Quick Connectors BOP Requirements Casing Bowl and Outlets Casing Rams Degasser Requirements Double Drilled BOP Equipment Drilling Stem Test Riser Flange Connections Flare Line Flexible Hoses in Bleed-off and Kill Lines Fluid Turns
Kill Line Remote Drill-string Pressure Assembly Stabbing Valve and Inside BOP C CASING INSPECTION Example Calculation for Pressure Testing and Casing Wear Logging Casing Inspection Requirements Logging the Casing Pressure Testing the Casing COILED TUBING DRILLING OPERATIONS COMPLETING THE INSPECTION REPORT General Information Inspection Results Mechanical Tests Remedial Action Signature and On-site Discussions Special Wells CONDUCT CONDUCTING THE INSPECTION Accumulator Sizing and Operating Policies Air Shut-offs/Diesel and Gasoline Engine Spacing Arrival at Well Site Back-up Nitrogen Supply BOP Controls BOP Mechanical Test BOP Pressure Test BOP System Requirements and Specifications Casing Inspection Crew Training and Certification Mud Tank Monitoring and Tripping Requirements Operator and Contractor Inspections Smoking Spacing Regulations Well-site Conditions Well-site Records and Signs Winterizing BOP Equipment CONTENTS CREW PROCEDURES FORM CREW TRAIN1NG AND CERTIFICATION Conducting Crew BOP Drills Crew Assessment and Procedures Forms Crew Drill Requirements Hands-on Drill Not Possible Inspectors Role P.I.T.S. Blowout Prevention Certificate Recording Blowout Drills Rig Supervisor’s Involvement CRITICAL WELL DRILLING E
ELECTRICAL INSPECTIONS OF DRILLING RIGS G GENERAL INFORMATION GUIDE TO MANUAL About this Manual Alphabetic Index I INDUSTRY/GOVERNMENT INVOLVEMENT INSPECTION RESULTS M MECHANICAL TESTS Description and Location of BOP Equipment Contents MUD GAS SEPARATOR SPECIFICATIONS Minimum Design and Installation Specifications for Atmospheric Open Bottom Mud Gas Separator Specifications (Degasser) MUD TANK MONITORING AND TRIPPING REQUIREMENTS Automated Monitoring Checking Flowline Flow sensors Checking Mechanical Monitors Checking PVT Systems Hole-Filling Procedures and Tripping Reports Mechanical Monitors Monitoring Requirements Trip Tank Design and Operation Trip Tank Monitoring During Drilling Operations o OPERATOR AND CONTRACTOR INSPECTIONS Daily Inspections Detailed Inspections Recording Daily lnspections Recording Detailed Inspections Reviewing Detailed Inspection Forni P POLICIES Conduct AEUB Responsibilities lndustry/Government Involvement Safety R REMEDIAL ACTION Action Required for Serious Deficiencies Action Required for Significant Deficiencies Follow-up to Serious Deficiencies General Handling Serious Deficiencies Handling Significant Deficiencies Operator/Contractor Initiated Remedial Action (Significant Deficiencies) Operator and/or Contractor Initiated Shut-down (Serious Deficiencies)
Recording Serious Deficiencies Recording Significant Deficiencies Redundant Drilling Equipment S SAFETY SAMPLE INSPECTION REPORTS SCHEDULE & DRILLING BLOWOUT PREVENTIONS SYSTEMS SERIOUS RIG DEFICIENCIES SIGNATURES AND ON-SITE DISCUSSIONS Area Office Inspectors Signature On-Site Supervision Signatures SIGNATURES AND ON-SITE DISCUSSIONS (cont Recording Rig Down-time Inspection Report Review with On-site Supervisions SIGNIFICANT RIO DEFICIENCIES SMOKING Handling Smoking Violations Penalties for Smoking Smoking Regulations SPACING REGULATIONS Rigs Employing DC Electric Motors Welding Well to: Crude Oil Storage Tank End of Flare Line Flame-type Equipment Rubbish Burn Pit SPECIAL WELLS General Bleed-off Equipment Integrity Kick Detection Kick Prevention Supervision Specific High Hazard Areas of Southeaster Alberta U USING MANUAL Non-AEUB Users Preliminaries References Waiver Underbalanced Drilling W WELL SITE CONDITIONS Condensate Requirements Containment of Drilling Fluids DST Equipment Engine Exhausts Handling Containment and Spillage Problems Sump Construction
Waste Disposal/Storage WELL SITE RECORDS AND SIGNS Posting Well License Posting Geological Prognosis/Well Control Data (stick diagrams) Recording and Checking Deviation Surveys Recording Daily Mechanical Test Recording Operator and Contractor Inspections Recording Pressure Test Recording Weekly Diesel Engine Test Shop Servicing Records for BOPs and Flexible Bleed-off and Kill-l ine hoses Warning Signs in H Areas WINTERIZING BOP EQUIPMENT Heating Requirements Use of Diesel Fuel Use of Glycol
Purpose of Manual This manual is designed to assist those who do rig inspections. (The AEUB, Licensees and their Contractors). Inspectors should use this manual as a reference during inspections. It anticipates questions that may arise in interpreting regulations. This manual is divided into three main sections: 1. AEUB policy related to inspections. 2. Detailed instructions and criteria for conducting the inspection. 3. Detailed instructions explaining each item on the inspection report. AOH&S Legislation This manual includes AOH&S legislation with respect to drilling rig safety (Appendix 1060). Its inclusion is intended to inform users of this manual of the regulations that should be considered in the overall safety performance at drilling Sites. Included with the sections on AOH&S is a copy of their Rig Inspection Check Sheet. (Appendix 1060) AEUB inspectors should become familiar with AOH&S legislation and be prepared to - Alert operations and/or contractors regarding unsafe operating practices, - advise AOH&S of unsafe operating practices noted during rig inspections. AEUB inspectors may periodically note differences between AEUB and AOH&S equipment spacing requirements. During such occasions, the AEUB requirements lake precedence. Roles and Expectations AEUB inspectors conduct inspections of rigs to ensure compliance with AEUB requirements. They are not inspecting the electrical systems on those rigs. However, if during the AEUB inspection an “obvious problem with the electrical system is noted, the inspector will write the following reminder on the AEUB rig inspection form. A copy of that form will be forwarded to Alberta Labour at the address listed at the end of this agreement. “There was an indication of deterioration or lack of maintenance on the electrical systems associated with this rig. It is your responsibility to obtain the services of a certified electrician to ensure that ah electrical equipment and wiring associated with the rig meet the requirements adopted under the Safety Codes Act.” -
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Obvious problem because of the lack of formal electrical training of AEUB staff obvious problems are considered to be electrical systems with signs of poor maintenance such as tattered and frayed cords, numerous light protectors missing, and evidence of shorting or sparking. It is the responsibility of the contractor to ensure electrical compliance and there will be no follow up on these reminders by AEUB staff. However,
repeat electrical problems would be followed up by Alberta Labour as they will have copies of ah such reminders forwarded to them by AEUB inspectors. Background Alberta Labour staff does not normally inspect electrical systems on rigs after the rigs are in service. They are concerned that rigs, with their constant moving, are prone to electrical system deterioration. AEUB staff though they have no formal training in electrical systems, inspects rigs at regular, if infrequent, intervals. It is felt that AEUB staff could help Alberta Labour by reminding personnel, at rigs with questionable electrical systems, of their responsibilities and questionable electrical systems, of their responsibilities and informing Alberta Labour. AEUB has no jurisdiction to enforce any requests for remedial work on electrical systems. Goals of this Agreement 1. To help ensure that electrical systems on rigs are maintained according to the Safety Codes Act 2. To coordinate “government inspections”, efficiently reduce duplication, and facilitate government agencies’ aid to each other. 3. To emphasize the fact that AEUB staff, while willing to help, are not trained specialists iii the area of electrical inspections and that in no way should their inspection be construed as a complete and thorough inspection of the electrical system. 4. To ensure that it is understood that, by this willingness to help, the AEUB is in no way assuming jurisdiction of electrical systems. 5. To ensure that the AEUB and its staff are protected from the potential of court actions as a result of trying to help out a member of our government family Purpose of Rig Inspections The Inspectors Role Where it becomes obvious that such commitment is lacking and an open disregard for the Board’s requirements is displayed, a system of escalating consequences will be imposed by the AEUB. This will be in keeping with our “firm but fair’ approach to all our customers. In an effort to be efficient in the use of the Board’s resources, the following criteria may be used in determining which rigs will be inspected. 1. Inspection history of the Rig Contractor and Operator Previously noted unsatisfactory items or requests for remedial action should be followed up. 2. On Site Assessment of Drilling Occurrence information Are there any instances of kicks, blows, blowouts, or a history of hole problems (high potential for lost circulation or abnormally pressured formations) documented for the area the rig is working in and are the on site personnel aware of them. 3. Approvals, Directives
Are there any new policies or requirements which may need to be addressed during the inspection. 4. Focus The inspector should thoroughly evaluate equipment, procedures and operating policies on site including: • crew training, kick prevention, detection and control. • Well control information - leak off gradients, Maximum Allowable Casing Pressure (MACP). • drilling program. • offset well data, • Geological prognosis, expected tops and problem zones and minimum mud weights to control the expected formation pressures. The inspector should also be receptive to: • Concerns and questions regarding regulations or requirements. • providing additional clarification or information as requested. An inspector should be prepared to initiate additional discussion or request additional crew training if during the inspection there is evidence it is required. Industry Role This is achieved by the implementation of: 1. Internal inspection, compliance programs, and being aware of their company AEUB inspection record and taking appropriate action where necessary. 2. Ongoing training of wellsite personnel. For safety, well control and equipment. 3. Informing on site personnel of potential hole problems, sensitive environmental and public issues, in order to ensure appropriate responses are implemented. 4. Cooperation with the AEUB, government and public by the open exchange of dialogue to address areas of mutual concern. Conducting the inspection Arrival at well site Contact with Operator’s and Contractor’s Representative 1. Whenever possible, the inspection should be conducted without prior notice given to the operator or contractor. 2. Upon arrival at the site, contact the Rig Manager (toolpusher) and the company representative. - If unavailable, locate the Driller 3. Take time to get acquainted. 4. Explain the purpose of the visit 5. Determine if hole conditions are safe to conduct a full inspection. 6. If the Rig Manager and/or the company representative request that the blowout preventers (BOPs) not be checked because of the current operation*, use discretion in deciding whether or not to proceed with the inspection. - It is advisable to respect the wishes of the rig supervisors. An abbreviated inspection may, however, still be conducted.
- Consult with your supervisor if there is concern about conducting a full inspection. *Operations that may be cited are: - Drill-stem testing - Logging - Fishing - Tight or sloughing hole conditions - Changing over a mud system (when stopping circulation would seriously disorient the break-over) - Coning - Circulating samples to surface - Drill string position in the wellbore on directionally drilled or horizontally drilled wells. (Pipe may become stuck if circulation is interrupted across deviated section). BOP system requirements and specifications 1. Refer to Appendix 1010 - Schedule 8 – Blowout Prevention Systems to determine the required type and pressure rating of the BOPs. 2. The casing bowl flange must be an integral part of the bowl, and the bowl must have at least one side outlet and valve. - The side outlet must be flanged or studded in Classes V and VI BOP Systems. - A valve is not required on the bowl when a drilling spool eqz4pped with the appropriate valve/valves has been installed between the casing bowl and the lower pipe rams. - Threaded outlets on Classes 1, II, III, IV are acceptable. The make up of these outlet nipples and valves should be periodically checked for-tightness after drill out of the casing shoe. Any time a threaded connection is broken after drill out a pressure test must be conducted. (It may be necessary to set a plug or packer in the surface casing to conduct pressure test). 3. It is a common oversight for an operator/contractor to install a 14-MPa casing bowl on a Class IV well which is to be drilled to a depth exceeding 1800 m. This error is classified as a serious deficiency and the bowl must be replaced. - Drilling conditions must be stable before an operator/contractor should be asked to undertake a bowl change out. - If the surface casing shoe has been drilled out, a bridge plug may have to be run inside the casing to secure the well and to enable a pressure test. - Generally, both the operator and contractor will be cited for the deficiency. - The contractor may not be cited if it can be determined that the contractor discussed the deficiency with the operator, but the operator chose not to take corrective action. - Casing bowl data must be available upon request Double Drilling BOP Equipment 4. The double drilling of BOP equipment (BOP body, BOP flanges, adapter flanges, or spools) is acceptable; however, the following policies are recognized by industry: - Double studding the body of a BOP, to accept two sizes of API flanges (equipment which may have a lower pressure rating), does not result in a derating of the preventer.
- Double drilling flanged BOP equipment, to accommodate connections to other API equipment (equipment which may have a lower pressure rating), results in a derating of the flange to the lower working pressure. - In many cases, derated flanges will be acceptable for the particular class of well being drilled. However, if a double drilled flange is to be used in an application requiring a higher pressure rating, the operator must provide evidence from either the manufacturer or a professional engineer (P. Eng.) that the flange is certified for the higher pressure (equipment identification must be established with certification document). - If certification cannot be provided during the inspection, the operator must provide the necessary certification within 24 hours. If this cannot be done a Serious deficiency must be recorded on the rig inspection report and operations suspended. BOP Quick Connectors 5. Quick connectors may be used to connect various flanged BOP equipment. - AH clamp type connections must be AEUB approved or suitable for the service in use. - Clamp-type connections can save many man-hours when connections must be repeatedly made up and broken. Such connections may also be used in the bleed-off and kill line and in the bleed-off manifold. Casing Rams 6. If casing is being run, the pipe rams do not have to be replaced with casing rams. This matter is left to the operator’s discretion. Flange Connections 7. Where flange connections are required in the BOP system, ensure that they are properly designed. Flanges mated to back-welded threaded connections are only acceptable if the connections have been stress relieved. This generally requires shop fabrication. - See item 4 for method of handling deficiency. Flange connections/stress relieving of back welded threaded connections does not apply to Field Fabricated Rubberized coating shock hose ends, used in the bleed off line. Ensure API and A.S.M.E. standards are utilized. Bleed-off Line 8. The bleed-off system, up to the last valve on the manifold, must have a working pressure equal to that of the BOP system. The bleed-off system is defined as the line from the BOP stack to the end of the flare lime. 9. The line off the drilling spool shall contain two flanged valves and one of the valves must be hydraulically operated. The position of the hydraulic control valve (whether the inner most or outside valve), is left to the operators discretion. Valve handles must be in place. 10. Steel swivel joint connections may not be used in the bleed-off system. (Chiksans) is a common term used for these type of connections. Fluid Turns
11. All directional changes in the bleed-off system (including the flare line) must be made with right-angle connections constructed of running tees and crosses blocked on fluid turns. Drill-stem Teat Riser 12. A drill-stem test riser may be installed in the bleed-off system provided a properly designed connection is employed - A manufactured tee or flanged connection is acceptable. - Saddle-type fittings or nipples welded directly to the bleed-offline are considered inappropriate. Riser deficiencies should not be marked as unsatisfactory during the initial inspection. However, a comment must be noted on the inspection report that the connection must be changed before the next hole. - A significant deficiency will result if the change did not take place before the next inspection. Bleed-off Manifold and Gauges 13. All choke and valve handles must be installed. 14. A gauge must be installed or readily accessible for reading the casing pressure at the choke control location. - The manifold gauge should have a range of O - 10 500 kPa or less. - A low-pressure gauge may be used but it must be valved to prevent overpressuring. - A higher ranged gauge may be used provided it has readable increments of 250 kPa or less. A higher ranged gauge will be necessary when intermediate casing is set. Remote Drill-string Pressure Assembly 15. An accurate pressure gauge and other necessary equipment must be installed or readily accessible for installation on the standpipe (or other suitable location) to provide the drill pipe pressure at the choke control location. - The system may consist of a pressure sensor mounted on the standpipe, an appropriate length of hydraulic hose to reach the manifold building, and a pressure gauge at the choke manifold. - The assembly may be disconnected and hung in the doghouse, or any other accessible location, when not iii service. - The required assembly must also be available for installation at the rig manifold even if a remote choke and pressure monitoring equipment is in service. - The choke operator must be able to read the drill pipe pressure when opening the choke- control. - The inspector should ensure that the rig crew automatically assembles this equipment as part of their blowout drill (only if equipment not already installed). Degasser Requirements 16. Mandatory in Class III wells and above. A degasser (mud-gas separator) must be ready for service (fully connected and either emerged in drilling fluid or BOP drill must include crewman assigned to fill tank when a remote degasser is used) whenever drilling fluids are being circulated from a mud tank.
- A visual inspection of ¡he degasser inlet line unions must be conducted prior lo and at regular intervals after they have been made up. These visual inspections must be documented in the lour report. 17. The degasser must be either an Atmospheric Open Bottom type or an enclosed (atmospheric or pressurized) design. Vacuum degassers or other types designed to remove solution gas are not considered acceptable. 18. Atmospheric Open Bottom degassers must meet the design and installation specifications as set out in Appendix 1070 of this manual. 19. Since enclosed degassers are not commonly found on drilling rigs, design and installation criteria is not provided in Appendix 1070. - There are several proprietary designs available and on the market for such degassers. Purchaser/users should vcri1 with the manufacturer that its product meets acceptable design criteria (considering the type of drilling the equipment is to be used for). - If this degasser design is encountered during an inspection, its design specifications should be discussed with the operator, contactor and the Board’s Drilling and Production Department Kill Line 20. The kill line must have the same pressure rating as the BOP stack. (From the bleed-off spool connection to last valve on the kill line side as shown in Section 1010 of Schedule 8). The remainder of the system (towards mud pump) shall be valved so that it may be isolated. A threaded union connection is acceptable at the location of the tie-in point of the pumping unit. A steel swivel joint connection may be used between the pump and the isolation valve. The use of a check valve in the Kill Line is left to the operator’s discretion. 21. The kill line must be hooked up at all times or be very easily connected by making up one connection. Flare Line 22. All flare lines (except degasser vent lines) must be adequately secured. Devices suitable* to the soil conditions must be used. e.g. stakes, cement or filled weights, or a properly designed clamp and interconnecting cable mechanism. - A minimum of 4 sets of stakes or securing devices should be used. The first tie-down should be positioned immediately downstream of the pipe racks and every 10 m thereafter. Discretion must be used when a man building is located downstream of the pipe racks (securing devices at 10 m intervals, downstream of the manifold building, would be adequate). - The securing of the flare line to the pipe racks is optional. - The end of the lime should be secured as close as possible to the flare pit. - Ideally, the flare line should be laid in a straight line; however a slight curvature of the line is acceptable providing a “fluid turn’ would not be required to make this same direction change. - The line may contain direction changes provided they are made in accordance with Section 210(11). - An elbow must not be used at the end of the flare line to direct well effluent into the pit.
- A visual inspection of the flare line unions must be conducted prior to and at regular intervals after they have been made up. These visual inspections must be documented in the tour report as per ID 92-1. Flexible loses in Bleed-off and Kill lines 23. A flexible hose may be installed in the bleed-off or kill line provided the hose - has a working pressure equal to that of the BOP system, - has the same internal diameter as the steel line, - has factory-installed connections (see Section 210, item 7 for clarification), - is sheathed to provide an adequate fire-resistant rating (only if under substructure), - does not contain bends with a radius less than the manufactures specified minimum bending radius (hose must not be crimped), - is secured to prevent stresses on connecting valves and piping, - is protected from mechanical damage, Stabbing Valve and Inside BOP 24. The rig must be equipped with a full opening stabbing valve; valve operating wrench and an inside BOP which is capable of stopping back-flow up the drill string. - The necessary cross-over subs must also be available to enable the make-up of the stabbing valve and inside BOP with drillpipe, drillcollars, tubing, or any other working tubulars in the well. 25. The stabbing valve, inside BOP, and associated tools and subs must be readily accessible, operable and conform to the following: - “Readily accessible” means the crew should be able to find this equipment without any searching whatsoever. - During cold weather, these items must be kept on a stand in the doghouse. In warm weather, they may be kept on a stand on the rig floor or suspended and counterbalanced in the derrick. - The stabbing valve must be kept in the open position. (A serious deficiency exists any time the stabbing valve is found to be closed). - The inside BOP must be kept with the stabbing valve, but must not be madeup. The use of’ a float in the drill string does not eliminate the need for an inside BOP to be with the stabbing valve. - The valves must be equipped with handles if more than one person is necessary to handle the valve. Alternatively, an open hanger cap may be used but all hoisting assemblies or handles must be removable to allow the valves to be stripped into the well Flow T or Other Drill through Components 26. Drill through components and Flow T’s positioned between the uppermost BOP and the rotary table must be removable with pipe or tools in the wellbore (either two piece construction or sized to be pulled through the floor with the table bushings removed). If a rotating head component is in place then operators must consider well control/procedure options as these are not removable. (Significant deficiency exists if no procedure in place). Drilling with a Service Rig
27. Operations involving drilling with a service rig may be required to conform to all or part of the drilling regulations and requirements as outlined under section 4 part 2 of Guide G-33 “Application for a Well License (see Appendix 1075). Air Drilling Requirements 28. Recommendations for Class I Air Drilling should include: All annular preventer of some type must be installed. This would be required to obtain full closure of the well should the rotating head fail while the reservoir is open with pipe in the hole. The accumulator system must include accumulator bottles of sufficient volume to meet sizing requirements. The blooey line size must be a minimum 152 mm to conform to present drilling policy. Recommendations for Class II Air Drilling must include: All requirements and recommendations outlined in Class 1 plus a working spool and a set of pipe rams. BOP CONTROLS Floor and Remote Control* Requirements 1. There must be both floor and remote controls for each blowout preventer and hydraulically operated valve installed. The controls must be properly installed, correctly identified, and show function operations (cg. open-close). The remote controls need only be capable of closing the BOPs and opening the hydraulic control valve. 2. The floor controls must be located near the Driller’s position and be easily accessible it is satisfactory for the controls to be located on the sub-base, down a few stairs, or a few steps away. Use discretion. 3. The remote controls must be - located at least 15 m from the well, - shielded or housed, - Readily accessible. Master Control Location 4. It is preferable, but not mandatory, that the main hydraulic controls be located at the remote panel and the auxiliary controls be located on the rig floor or near the Drillers station. Check Valve Installation 5. A check valve must be installed in the BOP hydraulic system for all well classifications, to allow for a change out of the charge pump in the event that a pump failure occurs after the system has been energized. - On a Class I BOP system the check valve should be located between the charge pump and the BOPs. - Ah other BOP systems should have the check valve located between the accumulator charge pump and the accumulator itself. Fire-proofing Hydraulic Lines
6. All non-steel hydraulic BOP control lines located under the rig substructure must be completely sheathed with fire resistant sleeving. * Remote - refers to distance, NOT the main or auxiliary controls referred to under Item Number 4. Manual Closing/Locking Handwheels 7. Check whether or not the ram-type preventers have automatic locking features. If they do not, then a closing/locking device must be installed or be readily accessible - Manual locking rams are easily identified as the manual locking shafts extend through the cylinder head permitting the installation of locking handwheels. Selflocking rains have enclosed ram shafts. - A single handwheel is acceptable as the ram closing device. - A ratchet and socket set is considered a suitable replacement for a handwheel. - “Readily accessible” means ¡he crew should be able to find the closing device without any searching whatsoever. (May be stored in the sub or at a location nearby as long as the crew knows their location.) - Ensure handles can operate on the Rams, (not obstructed by Kelly Sock or beams. If obstructed, ensure socket or alternate equipment will work). Mark as UNSAT sign only if no suitable back up will work. Conducting Crew BOP Drills 1. A crew BOP drill must be conducted during the inspection provided it is operationally prudent to do so. Rig Supervisor’s Involvement 2. The Rig Manager and/or the operator’s representative should be requested to co-ordinate the blowout drill, following the procedures outlined in Appendix 1040. - The alert should be initiated by the Rig Manager or the operator’s representative. - A horn is the required method of alerting the crew. A Significant deficiency exists if the rig does not have a horn, but the crew responds to an alternate alert. A Serious deficiency exists if the horn is not operable and the crew does not respond to any form of alternate alert. Drill Requirements 3. The drill conducted should determine the crews ability to detect a well kick (see Section 255(3) for kick influx monitor testing when using mud tanks), and perform a shut-in for the operation in progress at the time of the i nspection. - The intent of this check is to emphasize the AEUB goal to educate, survey the crew’s awareness of kick detection and their control capability in order to reduce the number of well control incidents. 4. The crew should be capable of applying well control procedures for four situations: a shut-in while drilling, tripping, tripping with drill collars opposite the BOP stack, and while out of the hole. Inspector’s Role
5. The inspector’s role throughout the drill should be that of an observer unless it is apparent that the drilling supervisor needs some assistance in establishing the format of the drill. The inspector may also question the crew about specific well control procedures. Crew Assessment and Procedures Forms 6. Use the Crew Training Assessment Form and the Crew Procedures Form(s) when observing drills. - The Crew Training Assessment Form (Appendix 1035) only serves as a guide and is not to be left at the rig. It may be appropriate to retain the form in the office files if crew t is found deficient. - The Crew Procedures Chart(s) (Appendix 1040) only serve as guides during the inspection. Hands-on Drill Not Possible 7. If adverse hole conditions will not permit a “hands-on” type drill, have the Rig Manager and/or operator’s representative conduct a verbal drill in the doghouse. 8. If the crew is not properly trained operations must be suspended until additional training is provided. The necessary training should be provided by the on-site supervisors; however, the inspector may wish to offer some assistance. Recording Blowout Drills 9. Check the tour sheets to ensure that a blowout drill is conducted by each crew a minimum of once every 7 calendar days. - A drill frequency of once/hole is adequate for holes drilled in less than 7 days. - A drill must be conducted by the crew on tour before drilling out the surface, intermediate or production casing shoe. - Other crews must conduct drills on their first lour after drill-out. - For critical wells, an additional BOP drill must be conducted within the 24-hour period prior to the penetration of the critical zone. P.I.T.S. Blowout Prevention Certificates 10. The Driller must possess a valid First Line Supervisors Blowout Prevention (Kick-Control) Certificate, issued by P.LT.S. (Certificates expire on the date referenced on the card and are invalid thereafter). - The inspector should request to see the Drillers certificate to ensure that he/she does in f have one and secondly, to ensure that it has not expired. - If the Driller claims to have a valid certificate, but is unable to produce it during the inspection, the inspector must take the necessary follow-up action to substantiate the Driller’s claim (this may be done either during or immediately after the inspection). - It is a serious deficiency if the Driller has never held a certificate and the rig must be shut down until such time as a qualified Driller takes over operations. - A Significant deficiency exists if the Driller’s certificate has expired A deficiency letter must be send to both the operator and contractor requesting an explanation for the deficiency. 11. A person possessing a valid Second Line Supervisors Well Control Certificate must be readily available to the well site to assist the drilling crew
with well control operations. (Certificates expire on the date referenced on the card and are invalid thereafter). - “Readily available” means within 2 hours driving time. - The person designated should be familiar with the day-to-day drilling activities. - The individual should be contacted to determine their awareness of their responsibilities and their certification details. - While drilling Class III, IV, V, VI wells and potential - hydrocarbon bearing zones have been penetrated, either the rig manager or the licensee‘s representative must be on site while tripping in or out of the well. They shall posses a valid Second Line Supervisors Well Control Certificate. (11)92-1, Section 1.5.1.) However, if it becomes necessary to make an unscheduled trip out of the hole when neither of these individuals is present, the trip may commence immediately after contacting the qualified individual(s). This individual shall then return to the well site immediately. BOP MECHANICAL TEST BOP, Hydraulic Valve, Accumulator and Recharge Pump Check 1. Have crew drain the BOP stack (summer and winter). Leave the casing bowl valve open during the function test. Crew may also wish to close the manual valve in the bleed-off line during winter operations to ensure no fluid enters the line or that no antifreeze is lost from the manifold line if used 2. If no drillpipe is in the well, witness the function of the blind ram. (To the closed position form the floor and remote control positions.) - After checking the blind rams with no pipe in the hole have the crew run a single joint in order to check the annular and pipe rams. 3. From the floor controls close the pipe ram (both sets if two required or in use). Close the annular, open the hydraulic valve. .Note closing times and proper function and element conditions. - Return rams and annular to open position, close the hydraulic valve. (The allowed closing time for rams is 30 seconds, 60 seconds for annulars up to 350 mm and 90 seconds for annulars of over 350 mm). Allow the accumulator to fully recharge. 4. From the remote control position have the crew shut down the accumulator recharge pump. - Observe and record (he accumulator operating pressures (before function test). - Close the pipe rams (both sets if required or in place). - Close the annular. - Open the hydraulic valve. - Visually check the position of the rams, annular and hydraulic valve. - Observe and record the accumulator pressure (after the function test). - A serious deficiency automatically exists if the pressure after the function test is 8400 kPa or less. - If the pressure is approaching but NOT below 8400 kPa an accumulator sizing calculation must be performed as the annular was closed on the drillpipe. Calculations will indicate if the accumulator has additional useable fluid available (at a minimum pressure of 8400 kPa or above) to close the annular element on open hole. If it does not, a serious deficiency exists.
5. Have crew start up the recharge pump. The accumulator must be recharge to the original starting pressure within 5 minutes. See Section 235, Item 9 if this is not achieved. 6. Have Crew: - open the annular and pipe rams and close the hydraulic valve. - Open the manual valve on the bleed-off line if it was closed for the test. - Close the casing bowl valve. - remove the single joint of drillpipe from the well if one was run in order to perform the tests. - Observe and record the accumulator pressure (after the function test). - A serious deficiency automatically exists if pressure after the function test is 8400 kPa or less. - If the pressure is approaching but NOT below 8400 kPa an accumulator sizing calculation must be performed as the annular was closed on the drill pipe. Calculations will indicate if the accumulator has additional useable fluid available (at a minimum pressure of 8400 kPa or above) to close the annular element on open hole. If it does not, a serious deficiency exists. 5. Have crew start up the recharge pump. The accumulator in must be recharge to the original starting pressure within 5 minutes. See Section 235, Item 9 if this is not achieved. 6. Have Crew: - Open the annular and pipe rams and close the hydraulic valve. - Open the manual valve on the bleed-off line if it was closed for the test - Close the casing bowl valve - Remove the single joint of drillpipe from the well if one was run in order to perform the tests AIR SHUT-OFFS/DIESEL AND GASOLINE ENGINE SPACING Reason for Shut-offs The purpose of air shut-off is to prevent diesel motors from running uncontrolled in the event of a natural gas blow from the well. Since diesels are compression ignition engines, fuel shut-offs will be ineffective in stopping the engine if it is drawing a combustible air-gas mixture into its air intake. Shut-off Requirements 1. Ensure that any diesel engine within 25 m (75 feet) of a well is equipped with - An air intake shut-off valve equipped with a remote control readily accessible from the Driller’s position, or - A system for injecting an inert gas into the engine cylinders, equipped with a remote control, or - A suitable duct so that air for the engine is obtained at least 25 m (75 feet) from the well Confirming Shut-off Test with Well-site Supervisors 2. Before conducting a mechanical test of the air intake shut-offs consult with the Rig Manager and/or operators representative as to possible problems (hole problems, inability to restart motors, etc). Disengaging Clutches
3. When conducting the test, ensure that the engines are idling and the clutches are disengaged so that all engines will have to stop independently. - It is a good check to ensure that fuel shut-offs are NOT being operated in place of air intake shut-offs. Individual Motor Tests 4. The motors may be tested individually by holding the air shut-offs open. - This may alleviate possible problems of engines failing to restart. Shut-off Test Results 5. The motors must power down and stop rapidly. The motors must stop for the test to be successful – engine lugging is not acceptable. Spacing for Vehicles 6. Vehicles (Diesel or gasoline) are not allowed within 25 m (75 feet) of a well during drilling operations. However, vehicles essential to operations may operate within this distance provided the wellsite supervisor first assesses the on safety. - This policy applies in instances where a vehicle may be unloading supplies such as water, fuel, or tubular goods. - It does not apply where a vehicle may be performing an operation on the well (e.g. power tongs, Iogging or DST units). - Vehicles such as power tong units that must remain operational while on lease should either be equipped with an air intake shut-off (if using a diesel motor), or have enough hydraulic hose to allow a distance of 25 m from the unit to the well - Units such as DST vehicles that do not need to be running other than getting the vehicle in or out of loading position, should either be parked 25 m (75 feet) from the well when not in use or shut off. Handling Spacing Problems 7. Spacing problems relating to Item 6 above do not constitute an unsatisfactory rig inspection. A comment that a problem existed and that it was corrected should be made on the inspection report. Spacing exemptions may be granted by Area Office staff provided the operator discusses its spacing needs with the appropriate Area Office before commencing. ACCUMULATOR SIZING AND OPERATING POLICIES Accumulator Requirements 1. The accumulator must have sufficient usable fluid available, at a minimum pressure of 8400 kPa, to close the annular preventer and pipe rams and opens the hydraulic control valve. The accumulator must be: - Located al least 15 m from the well. (Preferably with the remote control panel). - Shielded or housed.
- Readily accessible. (Immediately available for determining precharge pressure or repairing.) - If two sets of pipe rams are required or an additional ram has been added and is in use as REDUNDANT equipment (see Section 320, (24, 25) then there must be additional useable fluid available to close the extra set of rams. (Unless this redundant equipment is Iocked out.) When to Complete Sizing Calculations 2. Accumulator sizing calculations must be completed during the following situations: - First time inspection of a rig. - Any time a function lest as outlined in Section 225 cannot be completed. - After a function test has resulted in a pressure drop which approaches 8400 kPa (9000 kPa or less would be considered approaching 8400 kPa). - See Item 5 of this Section or Appendix 1025 for sizing methods. Recording Accumulator Specifications 3. Determine and record the accumulator system’s make, number of bottles, capacity, design pressure and operating pressure (upstream of any regulators). The operating conditions of the accumulator must not be changed prior to conducting the BOP mechanical test or the accumulator sizing calculations. - Accumulator specifications should be available at each rig and this includes specifications for “homemade” models. Operators and/or contractors should be encouraged to complete a BOP Data sheet similar to Drawing No. 1 on page 5. - Operators of “homemade” models must affix a tag to their units indicating the manufacturer, working pressure, and capacity. - Reminder: Subtract one US gal from nominal size of each accumulator bottle to account for displacement of bladder or float assembly (see Table No. 1 on page 9 for accumulator specifications). - Reminder: Accumulators are sized in US gala. Use the following for conversions: US gals x 3.7854 liters Determining Precharge Pressure 4. If well conditions allow and it is safe to do so, have the Rig Manager check the precharge pressure on each accumulator bottle. Record pressures. - A gauge and the necessary fittings must be readily available to determine the pressures. - Another method of determining precharge is available if the well-site supervisors are concerned about the “down-time” necessary for determining individual pressures or if a proper gauge and fittings are not available. However, this method will only indicate the lowest precharge in service and it also has a number of other shortcomings which could create problems for less experienced inspectors. It should only be used as a last resort for calculation purposes. Method: A. Shut down recharge pump. B. Depressure accumulator.
C. Restart pump. D. Observe first pressure* obtained on accumulator gauge - this is the lowest precharge pressure available. * It should take only a few seconds to obtain this pressure. Sizing Methods 5. Two methods for calculating accumulator sizes are provided in the manual. - Method 1, shown in item 6, is the preferable method to use during inspections because of its simplicity. - The “Alternate Method”, shown in Appendix 1025, requires more detailed calculations. - Drawing No. 2 (page 7), in Method 1, is derived from the equations shown in Appendix 1025. Sizing Calculations (Method 1) 6. Complete usable fluid volume calculations, using Drawing No. 2, and the following procedures: - Using pressures obtained in items 3 and 4 and Drawing No. 2, follow accumulator operating pressure slope on drawing (go beyond apex for precharge less than 8400 kPa) until it intersects with the appropriate vertical precharge pressure line. - Read drawing’s left vertical axis to determine the percentage of total accumulator capacity which is considered usable at the current operating pressures. - Calculate usable fluid using percentage determined. Usable Fluid = Per cent x Acc Cap - Determine the total fluid volume required to close the annular, pipe rams and open the hydraulic valve, also include the volume required to function any redundant BOP equipment in use (i.e. not locked out). (See Appendix 1055). - Compare this volume required with the volume of useable fluid calculated earlier. - The accumulator is adequately sized if the useable fluid volume is equal to or greater than the fluid volume required to activate the BOP components. Example sizing calculation Rig has 151.6-litre accumulator operating at 21-MPa and 7-MPa precharge pressure Per cent usable fluid available at current operating pressures - 50.0% Calculated usable fluid 50,0 x 151.6 litres = 75.8 litres 100 Rig has 21-MPa BOP stack - components to be considered: 254-mm Hydril GK-900 Annular BOP - closing vol req’d 28.1 litres 254-mm Hydril MPL Pipe Rams* - closing vol req’d 12.5 litres 101.6-mm Cameron HCR Hydraulic Valve - opening vol req’d 2.3 litres Total closing/opening volume required 42.9 litres
• The accumulator is adequately sized since the usable fluid volume available exceeds the volume required to activate BOP components. * The total volume required to close the annular, all in service pipe rams and the hydraulic valve must be included in calculations. DRAWING No.1 EXAMPLE ONLY DRILLING OR SERVICING BOP DATA
Table 1 accumulator specifications Volume per No. of accumulator bottles
Common accumulator suppliers and sizes
Sizing Rechecks 7. Once an initial accumulator sizing check has been completed it is not necessary to complete sizing calculations during each subsequent rig inspection - provided the accumulator’s operating parameters and BOP stack remain the same. - Pressures after a function test which are approaching 8400 kPa, (from 9000 kPa and below) should result in a sizing check to determine if adequate useable fluid volume exists above 8400 kPa. As the closure of the annular on open hole may drop pressure below 8400 kPa. Precharge Requirements 8. Full precharge is not required for an accumulator to meet the requirements. - The accumulator is considered adequate, regardless of its precharge pressure, if sufficient usable fluid is available to activate the BOP components described in item 1 (annular. both sets of pipe rams if two required or in use, hydraulic valve) and retain a minimum accumulator pressure of 8400 kPa. Sizing calculations must be performed. Manufacturer’s Recommended Precharge: 5250 kPa (± 10%) for 10500 kPa system 7000 kPa (±10%) for 14 000 kPa system 7000 kPa (± 10%) for 21 000 kPa system Recharge Pump Problems 9. If the accumulator recharge pump fails to recharge the accumulator to its original operating pressure, a complete function test of the BOP components
and sizing calculations must be completed to reconfirm that adequate usable fluid is available while operating at the lower accumulator pressure. - If less than 8400 kPa remains on the system after the function test, a serious deficiency automatically exists. Low-pressure Alarm System 10. Although it is not a regulation, Board inspectors should recommend that a low-pressure alarm system be installed in instances where decreasing accumulator pressures have gone undetected by a particular operator and/or contractor. - This option should be considered the second time a problem is noted. - Electronic alarms, using either a warning light or horn, can be installed without difficulty. - The alarm setting should be integrated with the accumulator operating pressure. Accumulator Reservoir Venting 11. It is recommended an accumulator reservoir which is enclosed in a building have its vent installed in such a manner that venting takes place outside the building. BACK-UP NITROGEN SUPPLY Nitrogen Requirements 1. Sufficient usable* nitrogen must be available, at a minimum pressure of 8400 kPa, to fully close the annular preventer and pipe rams and open the hydraulic valve. - If two sets of pipe rams are required or an additional BOP has been added and is in use as redundant equipment (see Section 320 (24. 25) then there must be additional usable nitrogen available to operate the extra BOP component. (Unless the redundant equipment is locked out.) - The nitrogen supply must be tied into the system at a point which will allow the N2 to function the BOPs and NOT be lost by venting or displacement into the accumulator bottles. (See CAODC technical bulletin 1 and Appendix 1030 to determine if the rig system is properly configured. The nitrogen bottles must be: - Located at least 15 m from the wellbore. (Preferably with the remote BOP accumulator controls) - Shielded or housed. - Readily accessible (immediately fully operational) by opening the valves to the accumulator system). * Usable fluid is defined as the equivalent litres of stored nitrogen at a minimum pressure of 8400 kPa. Recording Nitrogen Particulars 2. Determine and record the number of nitrogen bottles in service. Determine if the bottles are in crossflow. (On a common line tied into the system.) If they can be equalized when both bottles are open then the pressure must be averaged and the usable fluid volume calculated using an average of all bottles. (See
Figure No. 1 page 5.) If the bottles are independent of each other by means of a check valve installed on each bottle (if both bottles are open pressures cannot equalize) then the pressure in each bottle can be used individually to calculate the usable fluid equivalent. (See Figure No. 2 on Page 5.) Nitrogen Calculation Methods 3. Two methods for calculating back-up nitrogen adequacy are provided in the manual. - Method 1, shown in item 4, is the preferred method to use during inspections because of its simplicity. - The “Alternate Method” shown in Appendix 1030 requires more detailed calculations. - Drawing No. 3, in Method 1, is derived from the equations shown iii Appendix 1030. Nitrogen Calculations (Method 1) 4. Complete usable fluid volume calculations, using Drawing No. 3 and the following procedures: - Plot the pressure of the bottles in service (either combined average or independently as determined from item 2 above) on a vertical axis and draw a horizontal line across the appropriate bottle size - then plot perpendicular line down to the horizontal axis. Read the equivalent litres of usable nitrogen. Total the fluid volumes determined. - Determine and total the fluid volume required to close the annular and pipe rams and open the hydraulic valve (see Appendix 1055) and compare this volume with the volume of usable nitrogen calculated earlier. - The back-up nitrogen supply is adequate if it a calculated volume is equal to or greater than the fluid volume required to activate the BOP components. Example nitrogen calculation - for “average” pressures from combined bottles (see figure no. 1 on page 5) Rig has two 42-litre nitrogen bottles available: Tied into common cross flowline without independent check valves. Bottle 1 @ 17.5 MPa - Bottle 2 @ 14.0 MPa Average bottle pressure 17.5 MPa + 14.0 MPa = 15.75 MPa 2 bottles Usable fluid (per bottle) from drawing 37.0
litres
TOTAL USABLE FLUID 2 x 37.0 litres
74.0
litres
254-mm Hydril GK-900 Annular BOP - closing vol req’d
28.1
litres
254-mm Hydril MPL Pipe Rams* - closing vol req’d
12.5
litres
Rig has 21-MPa BOP stack - components to be considered:
101.6-mm Cameron HCR Hydraulic Valve - opening vol req’d
2.3
litres
TOTAL CLOSING/OPENING VOLUME REQUIRED
42.9
litres
• Nitrogen volume is acceptable since 74.0 litres are available when only 42.9 litres are required to activate BOP components. * If two sets of pipe rams are required, or redundant equipment is in service (not locked out) the closing volume for each set must be included in the calculations. Example nitrogen calculation - for individual pressure. (See figure no. 2 on page 5) Rig has two 42-litre nitrogen bottles available: Tied in but independent isolation by check valve. Bottle 1 @ 16.5 MPa - Useable Fluid from Drawing
41.0 litres
Bottle 2 @ 14.7 MPa - Useable Fluid from Drawing 2 bottles
31.5 litres
Total usable fluid
72.5 litres
Rig has 21-MPa BOP stack - components to be considered:* 254-mm Hydril GK-900 Annular BOP - closing vol req’d
28.1
litres
254-mm Hydril MPL Pipe Rams* - closing vol req’d
12.5
litres
101.6-mm Cameron HCR Hydraulic Valve - opening vol req’d
2.3
litres
Total closing/opening volume required
42.9
litres
• Nitrogen volume is acceptable since 72.5 litres are available when only 42.9 litres are required to activate BOP components. * If two sets of pipe rams are required, or redundant equipment is in service (not Iocked out) the closing volume for each set must be included m the calculations. Figure 1 N2 bottle configuration Common line “Crossflow” equalized system - use average pressure from all bottles.
Figure 2 N2 bottle configuration Independent bottles isolated by check valve - use individual pressure from each bottle.
WINTERIZING BOP EQUIPMENT Heating Requirements 1. During cold weather operation, sufficient heat must be provided to maintain the effectiveness of the BOP system (if the rig boiler is in service this is a good indicator that the BOP system must be heated). - The BOP stack shall be ice-free. - The portion of the bleed-off line under the sub-structure, as well as the man must be heated and fully operational. - The portion of line outside the substructure does NOT require heating, however it is recommended. - The bleed-off lime and manifold may be filled with a freezing depressant fluid (e.g. glycol) or blown out with ah to help prevent freezing problems. - A steam hose coiled around the bleed-offline and manifold may also assist in preventing freezing problems (operators or contractor’s discretion). Use of Diesel Fuel 2. The use of diesel fuel in the bleed-off system should be discouraged because - It does not serve as an absorbent as does glycol, - It simply displaces water from the system (total displacement may not always be successful), -. It is flammable (flash point approx. 48-59 degrees C), - It may not be compatible with valve gaskets and/or packing, - When cooled, diesel may become cloudy, “gel”, as fine wax crystals precipitate. Also, dissolved water may form very fine ice crystals (summer fuel -91-15, winter fuel -411-42 degrees C). Therefore, wax (and ice) could hamper operation of the system. Use of Glycol 3. Operators and contractors should be reminded to follow the manufacturer’s mixing requirements when using glycol to winterize the bleed-off and kill system. An improper mixture, even from the standpoint of adding too much glycol, can create a problem during cold temperatures. 4. Ensure disposal of glycol or other antifreeze component is in accordance with Section 250(5) and Appendix 1100. SPACING REGULATIONS Well to Flame-type Equipment 1. No flame-type equipment shall be placed or operated within 25 m (75 feet) of a well, oil storage tank, or other source of ignitable vapour (except water injection wells). - Flame-type equipment is any fired heating equipment using an open flame, which includes a space heater, torch, heated process vessel, boiler, and an electric arc or open-flame welder. Including wellsite shacks and trailers etc. with stoves, pilot lights, etc. - Drills, grinders or other portable type tools must not be used within 25m of the wellbore without shutting in the wellbore first. Welding
2. Special circumstances may necessitate welding within 25 m (75 feet) of a well. Strict safety procedures must be adhered to, which include closing the applicable BOPs. Under no circumstances is welding to be carried out while drilling ahead. Well to End of Flare Line 3. The flare pit and the termination of all flare lines shall be at least 50 m (150 feet) from a well (see Section 320(2) for method of handling deficiency). 4. The flare pit shall - be excavated to a depth of not less than 2 m, - have side and back walls rising not less than 2 m above ground level, - be constructed to resist the erosion of a high-pressure flow of gas or liquid, - be shaped to contain all liquids. - The use of a “flare tank” is permitted when environmental restrictions will NOT allow a flare pit. The tank must be suitable to contain fluids, have an open top, or venting provision which will NOT create back pressure and be spaced at least 50 m from the wellbore. The line must be secured to the tank There is no size requirement for the tank but it must be appropriate for the volume of fluid expected as would be the flare pit above. Well to Rubbish Burn Pit Site and Waste Disposal 5. All rubbish must be transported to a suitable disposal site or be burned in an incinerator at least 50 m (150 feet) from the well (see Section 320(2) for method of handling deficiency). - All burning must be carried out according to AEUB Informational Letter IL 8110, Disposal of Campsite and Well Site Waste, and according to Alberta Environments Clean Air Act. - Rubber, plastic, or any other material cont or coated with rubber or plastic is considered “prohibited debris” and must not be burned. - Disposal/Storage of waste lubricants, oil, glycol, oilfield wastes, must be done in accordance with the “Oilfield Waste Management Requirement (7L 93-8) refers to Appendix 1100. Crude Oil Tank 6. No oil storage tank shall be located within 50 m (150 feet) of a well, unless approved by an AEUB (8.090) representative. This particular concern is more applicable service rigs, but a problem may be encountered if oil is recovered during a drill-stem test (see Section 320(2) for method of handling deficiency). The use of oil based fluids for drilling mud and the use of crude oil for “spotting” to release stuck drillpipe must be considered as potentially hazardous and the on site safety of this procedure must be addressed before commencing operations. Employing DC Motors 7. Diesel electric rigs employ DC electric motors for operating their drawworks, rotary table and mud pumps.
