The annular preventer (also called bag type, spherical, or universal preventer) is the most versatile piece of equipment on the BOP stack since it can close around the casing, drill pipe, drill collars, wireline, and even close an open hole. The rubber packing elements of the annular preventers, which allow this flexibility, are also subject to wear and abuse. Treated properly, the packing unit of the annular preventer has a long, reliable life span, but it can be destroyed in a very short time or very few closing cycles by improper use. Here, we will cover all annular blowout preventer BOP types, such as Cameron, Hydril & Shaffer BOP types that are used in drilling rigs.
The following factors influence the life span of annular preventers:
- The closing pressure, as regulated through the control system, should be as low as practically possible to maximize the life of the packing unit.
- Testing the annular preventer under high test pressures significantly shortens the life of the packing unit.
- Closing the annular preventer without a pipe in the hole will shorten the life of the packing unit, especially when high closing pressures are required to achieve this.
- Motion reversal is hard on the packing unit, so the pipe should be moved as far as possible in one direction before reversing the direction (i.e., long strokes).
- Spare packing units should be stored in a dark, cool room.
The Closing Time of Annular Preventers
The closing time of annular BOP preventers The main disadvantage of the annular preventer in a drilling rig is the time required to close it. The annular preventer takes three to ten times the fluid volume to close, compared to a set of preventer rams, and therefore requires a longer closing time. Even though current regulations specify a 38 mm minimum diameter hydraulic control line, many surface stacks may still have hydraulic lines to (1112′ 1) the annular preventer that is smaller or has a restriction in them, which prevents rapid closing. Raising the closing pressure does not help as much as using larger lines and fittings. In addition, it increases the wear on the packing unit. The small lines and/or restrictions make the packing unit movement inflexible when trying to strip and cause excessive packing unit wear during stripping operations, especially when tool joints pass through it.
The regulator valve in the drilling rig that regulates the annular preventer closing pressure should allow fluid passage back through it if the line pressure increases. That way, the packing unit can open against the closing pressure while stripping a tool joint. It is very important to see to it that this regulator is in good shape, that there are no check valves ahead of it (often present in the four-way valve), or that it has been replaced by a plain regulator.
The arrangement where a small accumulator bottle (surge bottle) is placed in the closing line of the· annular preventer to allow for hydraulic fluid movement when stripping is very desirable to reduce packing unit wear. This arrangement is recommended for all surface and subsurface stacks.
There are some differences in the operation of the various annular preventers. Therefore, the most commonly used types will be discussed.
Hydril GK Annular Preventer BOP
The Hydril GK annular blowout preventer (Figure 1A & B) is the most common annular preventer used in drilling rig, particularly in surface stack installations, and is unique in its response to well pressures. Like most other annular preventers, the preventer is closed with about 5,520 kPa (800 psi) pressure. The Hydril GK annular blowout preventer with a working pressure of less than 69,000 kPa (10,000 psi) is, however, also energized by the well pressure so that when the well pressure increases, the closing pressure must be reduced to avoid damaging the packing unit.
This wellhead pressure assist is derived from its piston configuration and applies to the GL and MSP types of annular BOP preventers (except the 749.3 mm/29·5 3,450 kPa/500 psi unit). The manufacturer’s instructions on Hydril annular blowout preventers should be consulted for more detailed information. Charts determining operating pressures are also provided in the manufacturer’s literature.
Operating Features
- The Hydril GK Annular BOPs are particularly qualified to meet the industry’s needs for simple and reliable blowout protection. Over 40 years of operational experience provide the simplest, field proven mechanism in the industry.
- Only Two Moving Parts (piston and packing unit) on the Hydril Annular BOP mean few areas are subjected to wear. The BOP is thus a safer and more efficient mechanism requiring less maintenance and downtime.
- A Long piston with a length-to-diameter ratio approaching one eliminates tendencies to cock and bind during operations with off-center pipe or unevenly distributed accumulation of sand, cuttings, or other elements. This design ensures the packing unit will always reopen to full bore position.
- Back to Front Feedable Rubber on the Packing Unit enables the packing unit to close and seal on virtually any shape in the drillstring or completely shut in ( hard shut in procedure – soft shut in procedure) the open bore and to strip tool joints under pressure. This feature permits confident closure of the BOP at the initial indication of a “kick” (kick warning signs) without delaying to locate the tool joint.
- The Conical Bowl Design of the Piston provides a simple and efficient method of closing the packing unit. The piston is a sealing surface against the rubber packing unit; there is no metal-to-metal wear, thus, longer equipment life results.
- Utilization of Maximum Packing Unit life is made possible with a piston indicator for measuring piston stroke. This measurement indicates the remaining packing unit life and ensures valid testing.
- A Field Replaceable Wear Plate In the BOP Head serves as an upper non-sealing wear surface for the movement of the packing unit, making field repair fast and economical.
- Flanged Steel Inserts In the Packing Unit reinforce the rubber and control rubber flow and extrusion for safer operation and longer packing unit life.
- Greater Stripping Capability is inherent in the design of the packing unit since testing (fatigue) wear occurs on the outside, and stripping wear occurs on the inside of the packing unit. Thus, testing wear has virtually no effect on stripping capability and greater overall life of the packing unit results. The resulting ability to strip the drill string to the bottom without first changing the packing unit means a safer operation, lower operating costs, and longer service life for the packing unit.
- The Packing Unit Is Tested to Full Rated Working Pressure at the factory and the tests are documented— before it reaches the well site—to ensure a safe, quality performance.
- The Packing Unit Is Replaceable with Pipe In the Bore, eliminates pulling the drill string for replacement, and reduces operating expenses with more options for well control techniques.
- Large pressure-energized seals are used for dynamically sealing piston chambers to provide safe operation, long seal life, and less maintenance.
- Piston Sealing Surfaces Protected by Operating Fluid lowers friction and protects against galling and wear to increase seal life and reduce maintenance time.
The Packing Element
The packing element or unit has steel segments vulcanized into the rubber body to reinforce it and limit the amount of rubber extrusion when activated.
Figure 2 shows how the packing unit extrudes due to the vertical movement of the piston, whose taper squeezes the packing rubber inward. Hydril GK annular blowout preventer: The type of elastomer (natural rubber, synthetic rubber, or neoprene) used in the packing element should be the most suitable for the particular well conditions. Refer to Table 1.
Replacing a worn packing unit is fairly simple:
- Bleed off operating pressure.
- Unlock and remove the preventer cover.
- Lift out worn packing unit.
- Check seals on the head and piston.
- Drop in the new packing unit, and replace and lock cover.
Should the packing unit have to be replaced while the pipe is in the hole, the packing unit has to be cut with a knife between two steel segments,preferably at 90°, to the lifting eyebolt holes.
| Packing Unit Type | Identification Color | Identification Code | Opr. Temp. Range | Drilling Fluid Compatibility |
| Natural Rubber | Black | NR | -30 C – 105 C | Water-Based Mud |
| Nitrile Rubber | Red Band | NBR | -6 C – 85 C | Oil-Based Mud / Oil Additives |
| Neoprene Rubber | Green Band | CR | -30 C – 75 C | Oil-Based |
It is also advisable to use the oil and gas Kelly or Top Drive and a special cover break-out sub (Drilling Subs) with a plate for this job (see Figure 3). The tools required are lifting bolts with the correct thread for the packing element and lifting bolts with the correct thread and sufficiently long to lift the piston out.
Annular BOP Preventer Closure Sequence
All Hydril Annular Blowout Preventers employ the same time-tested design for sealing off virtually anything in the BOP bore or the open hole for any drilling rig.
The BOP is kept fully open during normal wellbore operations by leaving the piston down. This position permits the passage of tools, casing, and other items up to the BOP’s full bore size and provides maximum annulus flow of drilling fluids. The BOP is maintained in the open position by application of hydraulic pressure to the opening chamber. This ensures positive piston control during drilling and reduces wear caused by vibration. (See Fig 4.1)
The piston is raised by applying hydraulic pressure to the closing chamber. This raises the piston, squeezing the steel-reinforced packing unit inward to a sealing engagement with the drill string. The closing pressure should be regulated with a separate pressure regulator valve for the annular BOP in the drilling rig. Guidelines for closing pressures are contained in the applicable Operator’s Manual. (See Fig 4.2)
The packing unit is compressed throughout the sealing area, thus assuring a tough, v durable seal off against virtually any drill string shape—kelly, tool joint, pipe, or tubing to full-rated working pressure. The application of opening chamber pressure returns the piston to the full-down position, allowing the packing unit to return to a full-open bore through the natural resiliency of the rubber. (See Fig 4.3)
A complete shut-in of the well bore is possible with all Hydril Annular blowout preventer BOPs. During CSO, the flanges of the steel inserts form a solid ring to confine the rubber and provide a safe seal off of the rated working pressure of the BOP. This feature should be utilized only during well-control situations, as it will reduce the life of the packing unit.
Stripping Operations
Drill pipe can be rotated, and tool joints can be stripped through a closed packing unit while maintaining a full seal on the pipe. The longest packing unit life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packing unit. This leakage indicates the lowest usable closing pressure for minimum packing unit wear and lubricates the drill pipe motion through the packing unit.
The pressure regulator valve should be set to maintain the proper closing chamber pressure. If the pressure regulator valve cannot respond fast enough for effective control, a BOP accumulator (surge absorber) should be installed in the closing chamber control line adjacent to the BOP—precharge the accumulator to 50% of the closing pressure required. In subsea operations, adding an accumulator to the opening chamber line is sometimes advisable to prevent undesirable pressure variations with certain control system circuits.
Hydril Type GL 5000 PSI Annular BOP Preventer
Hydril GL Annular Blowout Preventer is designed and developed for subsea and surface drilling rig operations. The GL family of BOPs represents the cumulation of evolutionary design and operator requirements. The proven packing unit provides full closure at maximum working pressure on an open hole or virtually anything in the bore – casing, drill pipe, tool joints, kelly, or tubing. Features of the GL make it particularly desirable for subsea and deep well drilling. These drilling conditions demand long-life packing elements for drill pipe stripping operations and frequent testing.
The GL BOP offers the longest life packing unit for annular blowout preventers available in the industry today – especially for the combination of BOP testing and stripping pipe into or out of a well under pressure. The latched head permits quick, positive head removal for packing unit replacement or other maintenance with only minimal time required.
The following outstanding features of the drilling rig Hydril GL annular blowout preventer make these units particularly qualified to meet the industry’s needs for simple and reliable blowout protection.
The Secondary Chamber, which is unique to the GL BOP, provides this unit with great flexibility in controlling hookup and acts as a backup closing chamber to cut operating costs and increase safety factors in critical situations. The chamber can be connected in four ways to optimize operations for different effects:
- Minimise closing/opening fluid volumes.
- Reduce closing pressure.
- Automatically compensate (counterbalance) for deep water marine riser hydrostatic pressure effects.
- Operate as a secondary closing chamber.
Automatic Counterbalance can be achieved in subsea applications by selecting one of the optional hookups of the secondary chamber.
The Latched Head provides fast, positive access to the packing unit and seals for minimum maintenance time. The latching mechanism releases the head with a few turns of the Jaw Operating Screws while the entire mechanism remains inside the blowout preventer. There are no loose parts to be lost downhole or overboard. The Opening Chamber Head protects the opening chamber and prevents inadvertent contamination of the hydraulic system while the head is removed for packing unit replacement.
As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape.
Operating pressure for Subsea Drilling Rig Annular BOP Preventers
Where:
- Adjustment Pressure (∆P) = Adjustment Pressure
- Wm = drilling fluid density in lb./gal.
- Dw = water depth in feet
- 0.052 = conversion factor
- p = 2.13 = the ratio of closing chamber area to secondary chamber area for GL 16 3/4 – 5000.
- 0.45 psi/ft. = pressure gradient for sea water using a specific gravity of seawater = 1.04.
- 0.433 psi/ft. Pressure gradient for fresh water.
The optimum closing pressure for the standard hookup is obtained using the following formula:
Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)
NL Shaffer Spherical Annular BOP Preventer
The NL Shaffer spherical annular preventer uses a closing piston that forces the rubber packing element up against a concave cover, forcing the packing element to close. NL Shaffer suggests a closing pressure of 10,350k.Pa (1,500 psi) in its literature, but also notes that the pressure should be reduced according to the operating characteristic tables if the pipe is to be moved.
Figure 5 illustrates the action of the packing element. Steel segments molded into the element partially close over the top of the rubber to prevent excessive extrusion when sealing high pressures. These segments always move out of the well bore when the element is opened, even when the element is old and worn far beyond normal replacement conditions.
Only the top portion of the rubber, in the spherical sealing element, contacts the drill string or kelly. Most of the rubber is held in reserve to be used for sealing once abrasion makes it necessary. This large rubber reservoir makes it possible to strip into or out of a hole without replacing the element during the trip.
Long stripping life is especially valuable in offshore rig use because an annular preventer closed around the drill pipe of a floating vessel is constantly exposed to stripping movement due to vessel motion.
Stripping is claimed to be smooth with a spherical BOP because the element opens and closes easily due to the steel segments molded into the rubber. They make metal-to-metal sliding contact with the housing sphere, providing a low coefficient of friction.
INSTALLATION
A blowout preventer operating and control system is required to actuate the Spherical BOP. Several systems are available, and those commonly used on drilling rigs work well. The recommended installation requires the following:
- A control line to the closing (lower) port.
- For stripping, an accumulator bottle in the closing line adjacent to the BOP. This bottle should be precharged to 500 psi for surface installations and to 500 psi plus 45 psi per 100′ of water depth for subsea installations.
- Control line to the opening (upper) port.
- A hydraulic regulator to allow adjustment of operating pressure to meet any given situation.
The hydraulic operating fluid should be hydraulic oil with a viscosity between 200 and 300 SSU at 100°F. Water and a water-soluble oil such as Koomey K-90 can be used for environmental protection if necessary. If equipment is exposed to freezing temperatures, ethylene glycol must be added to the K-90 and water solution for freeze protection.
NOTE: Some water-soluble systems will corrode the metals used in BOP’s. If water-soluble oil is used, the user should ensure that it provides adequate lubrication and corrosion protection.
OPERATING REQUIREMENTS
Sphericals have relatively simple operating requirements compared to other annulars. When closing on stationary pipe, 1,500 psi operating pressure is sufficient in most applications. Recommended closing pressures for specific applications are given in the table at the bottom of the page.
Closing action begins when hydraulic fluid is pumped into the closing chamber of the Spherical BOP below the piston (upper right). As the piston rises, it pushes the element up, and its spherical shape causes it to close in at the top as it moves upward.
The element seals around the drill string as the piston rises (middle right). Steel segments in the element move into the well bore to support the rubber as it contains the well pressure below.
When there is no pipe in the preventer, continued upward movement of the piston forces the element to seal across the open bore (lower right). At complete shutoff, the steel segments provide ample support for the top portion of the rubber. This prevents the rubber from flowing or extruding excessively when confining high well pressure.
STRIPPING OPERATIONS
Stripping operations are undoubtedly the most severe application for any preventer because of the wear the sealing element is exposed to as the drill string is moved through the preventer under pressure. It is important to use proper operating procedures when stripping to prolong the sealing element’s life. The recommended procedures are:
- Close the preventer with 1,500 psi closing pressure.
- Just before commencing stripping operations, reduce closing pressure to a value sufficient to allow a slight leak.
- If conditions allow, stripping should be done with a slight leak to provide lubrication and prevent excessive temperature buildup in the element. As the sealing element wears, the closing pressure must be incrementally increased to prevent excessive leakage.
Cameron Type D Annular Preventer
The Cameron type D annular preventer BOP, shown in Figure 7, has a different type of packing element and piston design. During closing, the hydraulic pressure is admitted below the inverted T-shaped operating piston, moving it and its pusher plate upwards. The upward movement of the pusher plate forces a large solid rubber toroid (or doughnut) to move the packing element into the closed position around the pipe or over the open hole. During opening, the process is reversed. Hydraulic pressure above the flange section of the operating piston forces it downwards, allowing the preventer to open.
When the packing element closes, its steel reinforcing members rotate inward to maintain a continuous steel support ring around the drill pipe. This prevents packing element extrusion far more effectively than the conventional widely spaced radial fingers (see Figure 8)
Stripping Through Closed Preventer
Stripping operations using the Cameron annular BOP is considered the simplest and preferred technique. To ensure a long operating life of the annular packing element, it is important to reduce the closing pressure to accommo date the annular pressures encountered. Thus, low annular pressures allow the closing pressures to be as low as 3,450 kPa (500 psi), whereas higher pressures (10,350 kPa/1,500 psi) and above, could severely reduce the condition of the element, in particular when tool joints pass through.
A surge dampener must be placed in the closing line to ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through the element (see Figure 9). Any check valve installed in the closing line – to ensure that the BOP stays closed if hydraulic supply is lost – should be removed so that the annular regulator can be used effectively.
To accurately record bled-off volumes in the trip tank, it is advised to install a stripping tank adjacent to the trip tank (see Figure 10). The strip tank should be calibrated to account for the closed end displacement of the pipe in use.
Useful Tables
Annular BOP Related Calculations Examples
Operating Pressure for Accumulator Bottles
3 1/2 ” – 7″ pipe, 3500 psi well pressure, 16 lb./gal. Drilling fluid, 500 ft. water depth.
Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)
From the Surface Closing Pressure graph: Surface Closing Pressure = 900 psi.
Adjustment Pressure (∆P) = 90 psi
Closing Pressure = 900 psi + 90 psi = 990 psi.
Pre-Charge Pressures – Surge Bottles
The pre-charge pressure for the closing chamber surge absorber can be calculated using the following example: 3 1 / 2 ” – 7″ pipe, 500 feet water depth.
Precharge = 0.80 [Surface Closing Pressure + (0.41 x Dw)]
Where:
- Dw = water depth in feet.
- 0.41 psi/ft. = pressure gradient for control fluid (water and water-soluble oil) using a specific gravity of the mixture = 0.95 and 0.433 psi/ft pressure gradient for freshwater.
- Surface Closing Pressure = 600 psi.
Precharge = 0.80 [600 psi + (0.41 psi/ft. x 500 ft)] = 644 psi.
References:
- Shell Well Control Manual, Shell
- WELL CONTROL for the Rig-Site Drilling Team