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Job Safety Analysis (JSA)
Drilling >> Well Control

Properly trained personnel are essential for well control activities. Well control consists of two basic components: an active component consisting of drilling fluid pressure monitoring activities, and a passive component consisting of the Blowout Preventers (BOPs). [More... BOPs]

The first line of defense in well control is to have sufficient drilling fluid pressure in the well hole. During drilling, underground fluids such as gas, water, or oil under pressure (the formation pressure) opposes the drilling fluid pressure (mud pressure). If the formation pressure is greater than the mud pressure, there is the possibility of a blowout.

The activities involved in well control are:
Fig. 1. Blowout preventer stack (BOP)
Fig. 1. Blowout preventer stack (BOP)
Back to TopBlowout Prevention Program
Potential Hazard:
  • Receiving injuries caused by loss of well control.
Possible Solutions:
  • Appropriate training for tasks performed. Example topics include the following:
     
    • Causes of kicks, including detection

    • Pressure concepts and calculations

    • Well control procedures

    • Gas characteristics and behavior

    • Fluids

    • Constant bottom hole pressure well control methods

    • Well control equipment

    • Regulatory information

  • Use of appropriate well control equipment including:
     
    • Specification

    • Installation

    • Maintenance
Additional Information:
  • Well CAP. International Association of Drilling Contractors (IADC), (2006). Ensures that well control training schools adhere to a core curriculum developed by industry.

  • Standards. American Petroleum Institute (API).
    • RP 53, Blowout Prevention Equipment Systems for Drilling Operations. Second Edition, (2006, May).


Back to TopMonitoring and Maintaining Mud System
Fig. 2. Schematic of the circulating system: Drilling mud flows through the mud return line (center) upon its return to the surface from the hole to the shale shaker (upper left), then to the adjacent desander, desilter and degasser back to the mud tank (upper left). Through the suction line, the mud pump (center) circulates the mud through the discharge line (above), the stand pipe (upper right) through the rotary hose (right) and the swivel (lower right), the kelly and into the drill pipe. Fig. 2. Schematic of the circulating system: The drill bit, drill collar, annulus, drill pipe, kelly and swivel are depicted in the upper right. Drilling mud flows through the mud return line (center) upon its return to the surface from the hole to the shale shaker (upper left), then to the adjacent desander, desilter and degasser back to the mud tank (upper left). Mud passes through the suction line, and the mud pump (center) circulates the mud through the discharge line (above), the stand pipe (upper right) through the rotary hose (right) and the swivel (lower right), back to the kelly and into the drill pipe.













The mud circulatory system consists of the elements shown in Fig.2.

Each part of this system must function and be in good repair to maintain well control.
[For more information, see Maintenance Activities]

If the mud level increases, it may be a sign that a kick is in progress.

On some rigs there is a mud float level gage which sounds an automatic alarm if the mud exceeds a pre-specified level.

Potential Hazard:
  • Loss of well control (blowout)
Possible Solutions:
  • Keep the mud circulating system in good working order
     
  • Check and maintain the properties of the drilling fluid, including proper pit level periodically
     
  • Properly train crew in monitoring and well control procedures.

  • Maintain a properly functioning surface control system.
Fig. 3. Kick illustration: Schematic of mud circulating system, with a close up view of the drill bit hitting the lower vein at unexpected higher pressure. KICK occurring. Mud pit fills. Shut-in well. Above the animation is the illustration of the mud return from the surface to the mud pit through the circulating system.

Fig. 3. Kick illustration: Schematic of mud circulating system, with a close up view of the drill bit hitting the lower vein at unexpected higher pressure. KICK occurring. Mud pit fills. Shut-in well. Above the animation is the illustration of the mud return from the surface to the mud pit through the circulating system.

View larger image



     



Back to TopInstalling BOPs, Accumulator, and Choke Manifold
Fig. 4. A blowout preventer (BOP) with one annular BOP on top and two ram type BOPs are stacked together with a kill line valve and a choke line valve.
Fig. 4. A blowout preventer (BOP) with one
annular BOP on top and two ram type BOPs
are stacked together with a kill line
valve and a choke line valve.


Fig. 5. Choke manifold
Fig. 5. Choke manifold
The blowout preventer (BOP), accumulator and choke manifold are installed by the rig crew after the surface casing is set and cemented. The accumulator and choke manifold have been set into place during rigging up and now need to be hooked up and tested. The choke line valve is used to redirect the mud from the well bore to the choke manifold during a kick. The kill line valve is used to direct drilling fluid to the BOP during a kick.

Potential Hazards:
  • Being crushed by falling equipment if hoisting slings fail.

  • Being struck by, pinched by or caught between equipment during installation.
Possible Solutions:
  • Ensure workers stand clear of equipment being hoisted and tag lines are used where appropriate.

  • Coordinate hoisting tasks with rig crew.

  • Inspect the hoisting slings for wear before any hoisting operation.

  • Ensure all personnel wear proper PPE.
Additional Resources:
  • Standards. American Petroleum Institute (API).
    • RP 53, Blowout Prevention Equipment Systems for Drilling Operations. Second Edition, (2006, May). Provides information that can serve as a guide for installation and testing of blowout prevention equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating). This is the recommended specification for the installation, use, and maintenance of this equipment.



Back to TopTesting BOPs, Accumulators, and Choke Manifold
Fig. 6. Choke manifold
Fig. 6. Choke manifold
The BOPs, accumulators, and choke manifold should be tested and properly maintained.


Potential Hazards:
  • Being hit by hoses or sprayed by hydraulic fluid if there is a seal or hydraulic line failure during pressure testing.
Possible Solutions:
  • Ensure workers stand clear of pressurized lines during testing procedures.



Back to TopMaintaining Surface Control System
Fig. 7. BOP
Fig. 7. BOP

Properly maintain the surface control system.

Potential Hazards:
  • Protruding pipes and objects

  • Being struck by dropped objects.

  • Slips, trips, and falls.

  • Atmospheric hazards
Possible Solutions:
  • Wear appropriate personal protective equipment (such as hard hats, work gloves, safety shoes, and eye protection).

  • Implement injury awareness training (such as dropped objects, working from heights)

  • Use appropriate fall protection.

  • Ensure workers are aware of the slipping and falling hazards.

  • Monitor for potential hazards (H2S, methane, O2 deficiency).


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