Pressure Control Equipment
Pressure Control Equipment
Pressure Control Equipment
Learning Objectives
Overview
The BOP stack and equipment can work in
The Blowout Preventer (BOP) stack and related pressures up to its rating.
pressure control equipment are widely used
• As pressure ratings increase, tolerance to
throughout the exploration and production
misuse decreases.
industry.
• Equipment may be “de-rated” because of
Equipment is rugged and reliable when properly
misuse, working in pressures over its pressure
maintained.
ratings, it’s age and history.
• Controls high formation pressure.
• Allows passage of string and tools.
• Provides for circulation.
Configuration issues for BOPs are complex. Type and arrangement depend on a variety of
factors.
• Maximum anticipated formation pressure
• Types of formation fluids
• Must be versatile
- Close on pipe
- Close on open hole
- Provide circulating paths
- Alternate circulating paths
• Experience in area
• Operator/Contractor:
- Policy
- Availability
• Height
• Weight, etc.
BOPs
Annular Ram
Annular Type
Preventer
General Hydril
Shaffer Cameron
Rotating
Diverters
Heads
Operating pressures, characteristics, and limitations vary because there are many different
models and manufacturers.
• Because of these variations, hydraulic regulators should allow adjustment of operating pressure.
The most recurring problem when using different makes and models is unfamiliarity of the
operating pressures and closing pressures of the preventer.
The larger the bore size and the smaller the pipe, the more the closing pressure that is
necessary to provide a seal.
• May require increased pressure to seal around irregular shaped objects (e.g., “square kelly”).
• Increased pressure may lead to packer element deterioration.
It takes a longer amount of time to close an annular than a ram type preventer because the
annular requires more hydraulic fluid.
Try to keep the operating pressures on the annular preventer as minimal as possible in order to
preserve the life of the packer element.
The regulator valve is crucial for moving or stripping pipe with tool joints. It maintains constant
pressure and seals against the pipe.
• Allows flow back through the regulator to maintain constant pressure.
• The drawback: if well pressure becomes greater than manifold pressure and a seal fails, well pressure
can enter through the closing line regulator back to the accumulator system.
The factory may provide packer elements that are pre-split, which allow removal when the kelly
or string cannot be removed from the well bore.
MSP
GK
• Widespread use, very popular.
Available in 7 1/16 to 16 3/4 inch bore.
Available up to 15K rating.
Well energized – well bore pressure
increases closing force on packer.
–As well pressure increases,
regulated closing pressure
should be adjusted.
–Consult Manufacturer for well
pressure vs. regulated closing
pressure chart.
GX
• Designed for high pressure.
Available in 11, 13 5/8 and 18 3/4 inch
bore.
Available in 10 and 15K ratings.
Not as wellbore energized as GK.
GL
• Developed for subsea BOP stack
use.
Has balance chamber to
compensate for mud in riser in water
depth over 1,200 feet.
Spherical
• Widespread use, very popular.
Available in 4 1/16 to 30 inch bore.
Available 5 to 15K ratings.
1,500 closing pressure, regulate after
closing according to manufacturer.
Model DL
• Widespread use, very popular.
Available in 7 1/16 to 211/4 inch bore.
Available 2 to 20K rating.
Operating system isolated from well
pressure – well pressure does not
alter its closing pressure.
This system is made up of an annular preventer paired with a large diameter piping system
underneath.
Diverter systems are used to ensure safety of personnel and equipment from shallow gas flows.
• Diverters are made for short periods of high flow rate, not for high pressure.
• Large diverter lines reduce erosion effects at high flow rates.
The rotating head allows for string rotation with pressure below it.
• Replacement packer elements should be kept on location while rotating pipes are under pressure in
case of packer leak.
• Sealing packer may fail at high pressures.
Additional equipment may be required including:
• Dedicated hydraulic unit.
• Rig floor control panel.
• Cooling systems.
The majority of ram models are designed to seal pressure from the bottom.
A common problem occurs when changing packers on rams, which results in improper sealing of
the bonnet or door seal.
Most are designed to close with 1,500 psi regulated pressure.
The pipe ram is the basic blowout preventer, designed to seal around the pipe.
• The ram block cutout is the pipe ram’s strength and limitation.
• The cutout is designed to provide a good seal around a specific diameter or size pipe.
Pipe rams should not be closed on an open hole because damage and packer intrusion may
occur.
These have bigger packing elements and are designed to seal without pipe in the bore.
Blind/shear rams have the combination of open hole closing ability and cutting ability.
This allows the pipe to be cut and seals the wellbore after.
Saves space, weight and height as you don’t have to have separate blind and shear rams.
Manual and Hydraulic systems available depending on ram manufacturer and model.
Hydraulic ram locks engage and lock the ram position once actuated.
Packer elements of annular and ram preventers are made from a high tensile molded rubber and
plastics compounds.
• Natural rubbers, nitrile and neoprene are common compounds used for packer elements.
Annular packer elements are shaped around a series of steel fingers, which add power and
control the extrusion of packer material.
A codification system is used to identify different packer elements from each other by using
information on its:
• Generic compound
• Date of manufacture
• Serial number
• Manufacturer’s part number
• Hardness
• Operating temperature range
New ring gaskets are always used when testing and installing BOPs.
CAUTION: If the casing wellhead is not vertical, BOP and casing stress problems may
develop.
Use care when cleaning ring grooves, hydraulic ports, etc. This can help to eliminate future
complications or testing problems of stack.
Flanges and ring gaskets provide connection point and pressure seals between BOP stack
components.
Scratching ring-gaskets, ring grooves, or mating surfaces during cleaning or nipple up can ruin
the pressure integrity of the stack, failure to pressure test and potential failure and loss of control
during well control operations.
Do not use wire brushes or scrapers on mating surfaces and ring grooves. Prevent any
scratching that can cause failure.
Rings should be closely examined for damage that may cause the ring to be unable to seat
properly.
Nuts on the connecting flanges must be properly tightened and kept tight at all times.
“X” type ring gaskets should be used between BOP stack components.
In order to minimize friction and wear, the pipe should drop down the center of the BOP
without coming in contact with its walls.
• This can be difficult because the BOP stack may be off-centered with any movement,
settling, or tipping of the rig.
• The BOP may also be off-centered if the derrick is not perpendicular at the base, causing the
top to be off-centered from the hole.
• BOP wear is not immediately apparent.
• The casing and wellhead may also be damaged.
There is a chance that this damage can increase with time and may result in the stack
not being able to seal during a kick.
• Wear rings or bushings reduce inside wear and damage.
The BOP test tool is a device attached to the end of tubing and run to the bottom of the BOP
stack or in the casing head.
It is fitted with several sealing elements.
- These elastomeric seals should be inspected prior to use and replaced when necessary.
If these fail the well bore may become pressurized.
Safety
Valves/Floats/BPV
General FOSV
Lower Kelly
BPV
Cock
Float Sub/Dart
Valve
Safety valves, floats, and blowout preventers close off tubing/drill pipe.
Many types of these are handled and often made up by the crew. This requires training of the
crew on proper use and maintenance. Types include:
• Upper kelly cock.
• Lower kelly cock.
• Full Opening Safety Valves (FOSV).
• Inside BOP.
• Floats/back-pressure valves (BPV)/check valves.
The Inside BlowOut Preventer (IBOP) sometimes called the Gray valve is a one way, or check valve.
It is used for stripping in the hole under pressure.
• Allows the hole to be circulated but prevents pressure or flow reversing back into the string.
Since it is not full-opening, the inner diameter of the string is restricted.
• Does not allow wireline tools to be run through it.
• For this reason, it is rarely used unless necessary.
Typically an actuating rod assembly is used to keep it in the open position. By removing the rod
assembly, the valve should close.
Depending on the operation a sub may be run that will accept a valve pumped to the sub.
• FOSV stabbed first, then dart loaded into a make-up joint (or into the IBOP if possible).
• Chicksan lines made up to IBOP.
• FOSV opened and dart pumped to float sub.
Float subs are subject to erosion and the dart may not seat properly.
Chokes and
Manifolds
Manual
Chokes
Adjustable
Remote
Gate Valves
Adjustable
Chokes control the flow rate of fluids and provide back-pressure during well control operations.
Fixed chokes, such as a production choke are not suitable for well control as the orifice size
cannot be adjusted quickly.
Most kill operations use remote adjustable choke.
Consists of a bar that moves in and out of a narrow choke gate, or “half moon opening” fixed and
rotating plates.
It operates by the choke console, which releases hydraulic pressure on a double-acting cylinder that in
turn rotates the upper choke plate or bar to a more open or closed orifice size.
In drilling operations and pressure-related work, these are preferred because they allow for monitoring
of pressures and strokes and control the position of the choke all from one console.
May be trimmed for H2S service.
Closing
Systems
Volume
General
Requirements
Accumulator
Charging Maintenance
Fluids
WILD WELL CONTROL
Closing/Accumulator Systems
A manual screw-jack system was used to close ram preventers prior to the 1950s. This system is
still in use in some areas.
Since it is important to shut the well in quickly, hydraulic closing units were developed.
An accumulator must be reliable when it comes time to shut in the well during a kick.
• Hydraulic closing systems have extra pumps, excess fluid volume, and backup systems.
Most liquids are generally not compressible. So, a gas filled bladder is used inside accumulator
bottles to push out closing fluid to the BOP. Bottles must be kept near 1,000 psi pre-charge
operating pressure.
No additional fluid pressure can be stored if nitrogen precharge bottles lose their charge.
Bottles should be checked for proper pressures using the following procedure:
• Shut off air to the 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 pre-charge is checked.
• Remove guard from accumulator bottle pre-charge valve. Screw on gauge assembly. Open accumulator
Pre-charge valve by screwing down on the T handle. Check Pre-charge pressure. Gauge should read 1,000
psi or close to it. If over 1,100 psi, bleed excess pressure off; if under 900 psi, recharge to proper pressure
with nitrogen. Close Pre-charge valve by unscrewing T bar, remove gauge assembly. Reattach guard.
• Open accumulator shut-off valve.
• Turn on air and power. The unit should recharge automatically.
N2
Manifold
Fluid used in the accumulator system should meet the following requirements:
Hydraulic oil or a mixture of fresh water and soluble oil are ideal fluids for these conditions.
• Hydraulic oil is more expensive and considered a pollutant, whereas, fresh water and soluble oil is not.
Improper and corrosive fluids can harm accumulator and closing elements of BOP stack.
Gas Handling
Equipment
General MGS
Degasser
Well control operations are difficult and potentially dangerous without gas handling equipment.
Gas handling equipment allows venting and/or burning of large amounts of gas that is a
potentially explosive mixture if allowed to mix with air surrounding the rig.
If this system is overloaded, flammable/toxic gases may accumulate around the pit and rig floor
areas. The pump rate must be reduced or stopped.
• Since triplex pumps smoothly displace high volumes, they are more commonly used versus duplex
pumps.
Rig pumps are generally equipped with at least one stroke counter to accurately measure
displacement of volume.
If pump operations exceed pressure restrictions, the pump’s pressure relief valve will blow and
cause the well to unload into the pits.
• Some operations require the use of higher pressure/low volume service company pumps.
Proper maintenance should be used to ensure safe operations and accurate displacements.
The circulating or “standpipe” manifold system allows pump selection, fluid routing, and isolation
of pumps not in use.
It routes fluid from the pumps to the upper area of the derrick to connect with the rotary, or kelly
hose.
• The kelly hose provides a flexible connection between the standpipe and swivel and allows for pipe
travel while pumping.
• The swivel provides for rotation of pipe while pumping.
Changes to manifold lineup:
• Only if another fluid flow path has been opened first.
• The entire manifold system should be frequently checked for correct alignment.
The mud/fluid return indicator is one of the most important tools used in kick detection.
Detection of change is crucial because if the mud return indicator dictates a change from an
established trend, a kick or lost circulation may be occurring.
The flow sensor should be frequently checked to see if it is working properly by changing pump
rate to see if the flow sensor report changes.
Several interconnected tanks are used to hold, treat or mix fluid for circulating or storage.
The proper amount of tanks and volume capacity should be available depending upon the
operation.
Fluid can be routed tank to tank by:
• Ditches interconnecting tanks.
• Equalizing lines from tank to tank.
• Using circulating/mixing manifolds.
In an interconnected pit system, the first tank is usually a settlement tank that prevents sand or
unwanted solids from entering the main mixing, circulating suction tanks.
The intake and discharge lines from the degasser should be in separate pits.
PVTs monitor, record, and total up the volume in each pit as well as the total surface fluid volume.
• When a well kick pushes fluid out of the hole, there is an increase in pit level volume that is recorded by the
PVT; therefore, an increase in pit volume is a positive sign of an influx.
These systems use mechanical floats or electrical sensors to measure the height of fluid.
The trip tank is the best method of measuring the amount of fluid needed to fill the hole on a trip
out or the amount of fluid displaced on the trip back in.
• A small tank with accurate measuring markers provides more precise measurement.
Measuring the amount of fluid required to fill or that is displaced from the well is necessary to
ensure that a kick has not entered the well.
There are several different types of trip tanks:
• An automated trip tank has a pump, actuated by the driller that uses the flow line sensor to indicate
when the hole is full.
• Continuous fill trip tanks fill the hole automatically as pipe is pulled by circulating from the tank across
the hole.
If the tank is used to measure displacement from pipe on trip in, it is generally positioned below
the flow line level.
Maintenance of Trip Tanks:
• Check valves for easy operations.
• Clean trip tank markers and pit level floats of fluid buildup or solids.
• Calculate and post accurate volume displacements.
• Check driller’s recorder for accuracy.
Gas detectors detect changes in gas flow out of the well and areas of gas concentration in places
that must be monitored for explosive or hazardous gas presence.
• Special gas detectors are used in areas containing toxic gases that can harm personnel.
Frequent testing of gas detectors should be performed.
Stale or trapped gas in gas detectors can be removed by blowing intake/sniffing lines.
Broken and plugged lines or dirty detector heads are noticeable problems with gas detectors.
Pump, choke, and shut-in pressures are crucial to well control operations.
Drill pipe or tubing gauges are generally located on the driller’s console and the remote choke
panel.
Choke pressure gauges are located on the choke/kill manifold and remote choke panel.
The gauge at the remote choke panel is used when recording slow pump rates.
Gauges should be repaired when there are unusual and large discrepancies between readings.
• Small inaccuracies can be tolerated if conditions do not worsen and if the inaccuracy is over the
pressure range of the gauge.
Most regulatory bodies require a pressure gauge to monitor pressure between strings of casing.
There is debate over low pressure accuracy of large range gauges.
• For this reason, many rigs use multiple gauges in order to compensate for the inaccuracies.
When objects hit the gauge, vibrations, pulsation, and shock absorption may cause inaccuracy
and damage.
• Fluid-filled gauges provide a type of cushion from vibrations and shocks and also lubricate and protect
internal components.
A cause of inaccuracy is air in the hydraulic line from the gauge to sensor, so a hydraulic fluid
hand pump can be used to purge the lines.
A gauge placed at the bottom of a fluid column not only reads the hydrostatic pressure of the
column, but it also reads the atmospheric pressure exerted on that column.
Atmospheric pressure at sea level is about 15 psi but fluctuates depending on different weather
conditions and elevation.
A gauge that reads in psig has been adjusted to subtract the atmospheric column above it.
Standard geological graphs are commonly used to record measurements of time, depth, weight,
torque, pressure, and penetration at one foot intervals.
In addition, some systems also accurately display the rate of penetration in feet-per-hour.
Most operations require the use of string rotation at one point or another.
• A rotary table transmits the pipe rotation and supports the Workstring when the load is not supported by
the derrick.
• Pipe rotation can also be rotated by a top drive, power swivel or power tongs.
Changes in the rotational torque indicate down hole problems.
Learning Objectives