The Blowout Preventer Stack is such a vital part of the rig equipment that it should never be overlooked. The BOP system is actually a unique set of very large hydraulic valves. BOP’s have large bores, high pressure tatings, and operate quickly. These characteristics build some limitations into system that operating crew needs to be aware of and watch out-watch carefully-.
BOP Stack Organization:
The BOP stack may be built in a rich mix of configurations and the purpose of the BOP stack is to close in the well and allow the greatest flexibility for subsequent operations. If this is kept in mind, many possible stack configurations are satisfactory. Critical concerns of well control operations are some inherent limits such as pressure, heat, space, economics, etc, in the design or operation of the stack.
Sometimes it is called BAG PREVENTERS, SPHERICAL PREVENTERS, or simply HYDRILS, are probably the most versatile well head pressure control devices. Some models are highly welbore energized, that is, well pressure pushes upwards and provides additional sealing force.
The preventer consists of a circular rubber packer element, a piston, a body and a head (cap). When hydraulic fluid is pumped into the closing chamber, a sequence takes place in which the sealing element is forced inwards. Most modern annular preventers will close around the kelly, collars, drill pipe, work string, tubing, wireline, or in an emergency, the open hole.
Most annular preventers are designed for a maximum recommended closing pressure of 1,500 psi (103.42 bar), though some annular BOPs have a maximum operating chamber working pressure of 3,000 psi (206.24 bar).
The diverter system is an annular preventer coupled with a large diameter piping system underneath. It is used when only conductor pipe is set and to divert flow and gas from the rig on vessels with a riser. The large diameter pipe, usually has routing in two directions. This system diverts the stream of wellbore fluids away from the rig and personnel.
Diverter systems should be used if a well cannot be shut in for fear of lost circualtion or formation breakdown. Some government regulations and operator policies require the use of diverters. Depending on the type of operations, for instance on floating rigs, diverters may be used throughout the entire drilling operation. Typically, the diverter system is installed on conductor casing or as a part of the marine riser, with diverter lines running to a safe, downwind area; therefore, on offshore locations two diverter lines are utilized with the control for the diverter line so the annular preventer can not be closed before the diverter line(s) open. In addition to saying that, Diverter systems are designed for brief periods of high flow rates, not high pressure.
The rotating head is becoming commonplace in many areas. It allows rotation of the string with pressure below it. Underbalanced drilling operations can keep on with circulation through the choke manifold. Several manufacturers have models that allow rotation of the string, or maintaining static pressures to 5000 psi.
Given the nature of rotating pipe while under pressure, several replacement packer elements should be maintained on location. In case of a packer leak, consideration should be given to replacing element before operations continue. Depending on the manufacturer, additional equipment may be required. This may include a dedicated hydraulic unit, rig floor control panel, and cooling systems.
The pipe ram is the basic blowout preventer. The reliability ot the ram is in part because of the effort put into the desing of the ram. Most ram preventers are normally closed with 1500 psi. operating pressure and should not be varied unless specific conditions or type of ram require a different or procedure.
Rams come in many sizes and pressure ratings. There are many types of custom built or specialty rams designed for particular applications. Rams range from simple manual one-ram sets to multiple-ram set bodies, Simple rams consist of a polished rod that closes by turning handles on either side to screw the ram inward and around the pipe. Complex multiple sets of rams may be housed in a single body remotely operated by hydraulic pressure.
The rams of most BOP systems are closed by means of hydraulic pistons. The piston rod is sealed against the well by a primary lip seal, installed in the bonnet, through which the operating rod passes is sealed from operating cylinder. If well pressure bypass the primary seal and enters the operating cylinder, it may force the ram open. To prevent this, a series of secondary seals and a detection method are provided, including back up O rings, plastic injection seal and a vent to the atmosphere. If fluid is noticed venting out of the BOP, the secondary or auxiliary plastic seal should be energized to seal against the piston shaft.
Most rams are designed to seal against pressure from the lower side only. This means the ram won’t hold pressure if placed in an upside down position. Additionaly it will not pressure test from the top side. Therefore, care must be used when installing the stack to ensure that it is right side up.
When changing packers on rams, remember most problems come from improperly closing and sealing the bonnet or door seal. It is a good practice to inspect- make sure- and replace these seals as necessary, each time the rams are changed or doors opened. A set of pipe rams and ram sealing elements for each size pipe used should be kept on location as well as complete sets of bonnet or door seals for each size and type of ram preventer used.
Pipe rams are designed to close around pipe. The basic strength and major limitation of a pipe ram is the ram block cutout. The ram preventer is a steel block cut to fit the pipe size around which it is to be closed.
The cutout is meant to close and provide a good seal around one particular diameter or size pipe. Most rams have guides to center the pipe, the ram block cutout fits the pipe size closely. While the ram will close around pipe that has a small taper, it won’t close around the tool joint with no crushing the joint or damagingthe ram face. Pipe rams should not be function tested without the suitable size pipe in the preventers to prevent damage.
Blind rams are a special type of ram with no pipe cutout on the ram block. Blind rams have large packer elements, and are made to close with no pipe in the hole. When tested, they should be pressured to full rating.
Shear rams are another type of ram, but with special shear blades to cut tubular goods ( tubing, drillpipe, collars, etc.). Higher than normal regulated pressures and/or the use of hydraulic boosters may have to be used depending on the type of shear ram and the tubular to be cut.
Variable Bore rams:
Variable bore rams ( VBRs) seal on several sizes of pipe, and depending on the type of VBR, on a hexagonal kelly. They may also serve as the primary ram for one size pipe and a backup ram for another size.
On wells with tapered strings where space is a concern. variable bore rams may also be used. In addition, a set of VBRs in a preventer may save a round trip of the subsea blowout preventer stack, This is because the rams do not have to be changed when different diameter pipe strings are used.
On one type of VBR, the packer contains steel reinforcing inserts similar to those in the annular BOP packer. These inserts rotate inward when the rams are closed, so that the steel provides support for the rubber which seals against the pipe. In standard fatigue tests, variable bore ram packers, Variable bore rams are suited for H2S service.
Choke/kill line Connections:
The high pressure line connections to the stack are weak points that need to be checked and rechecked. Common problems include using nipples that are too light, dirty seal rings, damaged mating surfaces, loose nuts and long unsupported nipples or lengths of pipe. There is very little to say about these points that does not fall under the heading of common sense.
Another source of problems is the use of low pressure goses where there is not much room for steel piping. Excessive bends in pipe, or bent lines coupled with high-pressure situations, is not a good practice. This becomes particularly hazardous if the line involved is the choke line.
Fill Up line:
A fill-up line above uppermost preventer should be included in the stack. The purpose of this line is to fill the gole during trips and when well is not circulated. Maintenance of this line is slight, although if fluid is left in line it may plug and corrosive fluids may damage the line.
BOP Test Tool:
The design of the BOP test tool varies, but it is a device attached to the end of tubing and run to the bottom of the BOP stack or in the casing head, and is held in place initially by the pipe weight. It is typically fitted with elastomeric seal rings and may also have several sealing cups to effect a seal. If the seals fail, the well bore may be energized.
The maintenance of the test tool should inchude component inspection, proper cleaning and storage after each use and inspection and replacement of sealing elastomeric as needed.
Blowout preventers for rotary drilling date back to the early part of the 20th century. However, it was the 1950’s before there were good methods of closing the preventers. Fluid pumps, rig air and hydraulic pump closing units have all been tried and were unsatisfactory. Hydraulic accumulators are the first systems that have proven satisfactory. The accumulator provides a rapid, reliable and practical way to close blowout preventers when a kick occurs. Because of the importance of reliability, closing systems have extra pumps and excess fluid volume in addition to alternate or backup systems. Air/Electric powered pumps are rigged to recharge the unit automatically as the pressure in the accumulator bottle drops.
The standard rig system uses a control fluid of hydraulic oil or a mix of chemicals and water stored in 3000 psi accumulator bottles. The basic accumulator system should have maintenance at least every 30 days or every well ( which ever comes first). The following needs to be checked during operational maintenance of the master accumulator package.
Clean, wash the air strainer. Fill air lubricator with 10 weight oil.
Check air pump packing. Check the electric pump packing.
Remove and clean the suction strainers. Check oil bath for the chain drive on electric pump.
Fluid volume in hydraulic reservoir should be at operating level.
Remove and clean the high-pressure hydraulic strainers.
Lubricate the four-way valves. clean the air filter on the regulator line.
Check precharge of individual accumulator bottles ( should read 900 to 1100 psi).
The Nitrogen Precharge
An important accumulator element is the 1,000 psi (68.95 bar) nitrogen precharge in the bottle. If bottles lose their charge completely, no additional fluid under pressure can be stored. Keep bottles near their 1,000 psi (68.95 bar) precharge operating pressure. Nitrogen tends to leak away or be lost over time. Loss varies with each bottle, but each bottle in the bank should be checked and the precharge recorded every 30 days, or every well, whichever comes first, using the following procedure.
Shut off air to the air pumps and power to the electric pump.
Close the accumulator shut-off valve.
Open the bleeder valve and bleed the fluid back into the main reservoir.
The bleeder valve should remain open until the precharged is checked.
Remove guard from accumulator bottle.
Open accumulator shut-off valve.
Turn on air and power. The unit should recharge automatically.