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Annular BOP Preventer | Hydril, Shaffer & Cameron Guide

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 as Cameron, Hydril & Shaffer BOP types that are used in drilling rig.

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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 in order to maximise 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 pipe in the hole will shorten the life of the packing unit, especially when high closing pressures are equired to achieve this.
  • Motion reversal is hard on the packing unit, so 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 drilling rig is the time required to close it. The annular preventer takes three to ten times the volume of fluid to close, compared to a set of 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 are smaller or have 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 are passing through it.

The regulator valve in the drilling rig that used to regulate 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 from the viewpoint of reducing 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 in use 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 also 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.

Hydril GK annular BOP blowout preventer drilling rig
Figure 1A Hydril GK annular blowout preventer
Hydril GK annular BOP blowout preventer in drilling rig
Figure 1B Hydril GK annular blowout preventer

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-centre 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 proceduresoft 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 serves as a sealing surface against the rubber packing unit; there is no metal-to-metal wear and thus longer equipment life results.
  • Utilisation of Maximum Packing Unit life is made possible with a piston indicator for measuring piston stroke. This measurement indicates 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 affect on stripping capability and greater overall life of the packing unit results. The resulting ability to strip the drillstring 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, which eliminates pulling the drill string for replacement and reduces operating expenses with more options for well control techniques.
  • Large Pressure Energised 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 extrusion of the rubber when it is 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.

Packing element of Hydril GK annular bop blowout preventer in drilling rig
Figure 2 Packing element of Hydril GK annular blowout preventer in drilling rig

Replacing a worn packing unit is fairly simple:

  • Bleed off operating pressure.
  • Unlock and remove preventer cover.
  • Lift out worn packing unit.
  • Check seals on head and piston.
  • Drop in 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 TypeIdentification ColorIdentification CodeOpr. Temp. RangeDrilling Fluid Compatibility
Natural RubberBlackNR-30 C – 105 CWater-Based Mud
Nitrile RubberRed BandNBR-6 C – 85 COil-Based Mud / Oil Additives
Neoprene RubberGreen BandCR-30 C – 75 COil-Based
Table 1

It is also advisable to use the kelly or Top Drive and a special cover break-out sub 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.

Cover break plate
Figure 3 – Cover break plate

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.

During normal wellbore operations, the BOP is kept fully open by leaving the piston down. This position permits passage of tools, casing, and other items up to the full bore size of the BOP as well as providing 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 control of the piston during drilling and reduces wear caused by vibration. (See Fig 4.1)

CLOSURE SEQUENCE (OPEN)
Fig 4.1 CLOSURE SEQUENCE (OPEN)

The piston is raised by applying hydraulic pressure to the closing chamber. This raises the piston, which in turn squeezes 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 drilling rig. Guidelines for closing pressures are contained in the applicable Operator’s Manual. (See Fig 4.2)

CLOSURE SEQUENCE (PART CLOSED)
Fig 4.2 CLOSURE SEQUENCE (PART CLOSED)

The packing unit is kept in compression 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. Application of opening chamber pressure returns the piston to the full down position allowing the packing unit to return to full open bore through the natural resiliency of the rubber. (See Fig 4.3)

CLOSURE SEQUENCE (SEALED OFF)
Fig 4.3 CLOSURE SEQUENCE (SEALED OFF)

Complete shut in of the well bore is possible with all Hydril Annular blowout preventer BOP’s. 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.

Annular Preventer
Fig 4.4

Stripping Operations

Drill pipe can be rotated and tool joints 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 provides lubrication for 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, an 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, it is sometimes advisable to add an accumulator to the opening chamber line 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 both 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 on 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 of control 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:

  1. Minimise closing/opening fluid volumes.
  2. Reduce closing pressure.
  3. Automatically compensate (counter balance) for marine riser hydrostatic pressure effects in deep water.
  4. Operate as a secondary closing chamber.

Automatic Counter Balance can be achieved in subsea applications by the selection of 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.

Hydril Type GL 5000 PSI Annular BOP
Hydril Type GL 5000 PSI Annular Preventer in drilling rig
Hydril GL BOP
Hydril GL drawing

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.

closing pressure for annular bop in drilling rig

Operating pressure for Subsea Drilling Rig Annular BOP Preventers

\Delta P= \frac{ \big(0.052 \times W_{m} \times D_{w} \big) – \big(0.45 \times D_{w} \big) }{ P }

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 sea water = 1.04 and 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, which in turn forces the packing element to close. NL Shaffer suggests a closing pressure of 10,350 k.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.

NL Shaffer spherical annular preventer in drilling rig
Figure 4 – NL Shaffer spherical annular BOP preventer – drilling rig

Figure 5 illustrates the action of the packing element. Steel segments moulded 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.

Action of the packing element of NL Shaffer spherical annular BOP
Figure 5 – Action of the packing element of NL Shaffer spherical annular preventers – drilling rig

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 reservoir of rubber makes it possible to strip into or out of a hole without replacing the element during the trip.

Detail of the packing element
Figure 6 – Detail of the packing element

Long stripping life is especially valuable in offshore 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 moulded into the rubber. They make metal-to-metal sliding contact with the sphere of the housing, 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:

  1. A control line to the closing (lower) port.
  2. 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.
  3. control line to the opening (upper) port.
  4. 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 If necessary, a water-soluble oil such as Koomey K-90 and water can be used for environmental protection. 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.

Installation hookup for dual Spherical BOP
Installation hookup for dual Spherical BOP

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 the element’s spherical shape causes it to close in at the top as it moves upward.

The element seals around the drill string as the piston continues to rise (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. To prolong sealing element life, it is important to use proper operating procedures when stripping. The recommended procedures are:

  1. Close the preventer with 1,500 psi closing pressure.
  2. Just prior to commencing stripping operations, reduce closing pressure to a value sufficient to allow a slight leak.
  3. 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 will need to be incrementally increased to prevent excessive leakage.
shaffer spherical stripping
closing pressure for shaffer spherical

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 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.

Cameron type D annular preventer BOP in drilling rig
Figure 7 – Cameron type D annular preventer BOP

When the packing element is closing, 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)

Packing element of Cameron D annular preventer
Figure 8 – Packing element of Cameron D annular BOP

Stripping Through Closed Preventer

Stripping operations using the cameron annular BOP is considered the simplest and preferred technique. In order 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.

To further ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through the element, a surge dampener must be placed in the closing line (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, such that the annular regulator can be used effectively.

Surge dampener connected to the closing line of an annular preventer
Figure 9 – Surge dampener connected to the closing line of a Cameron annular BOP

To facilitate the accurate recording of 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.

Rig layout for combined stripping and static volumetric method
Figure 10 Rig layout for combined stripping and static volumetric method

Useful Tables

Gallons of Fluid Required to Operate on Open Hole
Gallons of Fluid Required to Operate on Open Hole

Annular BOP Related Calculations Exampls

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.

\Delta P= \frac{ \big(0.052 \times 16 \times 500 \big) – \big(0.45 \times 500 \big) }{ 2.13 }

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:

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