Kamis, 15 Oktober 2009




Fluids in the formation are under pressure. When drilled, this pressure can escape to the surface if it is not controlled. Normally drilling mud offsets formation pressure, that is the weight or pressure of the drilling mud keeps fluid in the formation from coming to the surface. For several reasons however, the mud weight can become lighter than it’s necessary to offset the pressure in the formation. When this situation occurs, formation fluids enter the hole. When formation fluids enter the hole, this is called a “kick”. A blowout preventer stack is used to keep formation fluids from coming to the surface. These are called “BOP”s. By closing a valve in this equipment, the rig crew can seal off the hole. Sealing the hole prevents more formation fluids from entering the hole. With the well sealed or shut in, the well is under control. Rig crews use a surface BOP system on land rigs, jack-up rigs, submersible rigs and platform rigs. They use a subsea BOP system on offshore floating rigs, like semi-submersibles and drill ships.

[TOOL BOX]: Why do you suppose subsea BOP system are used on semi-submersibles and drill ships? Blowout prevention equipment is very large and very heavy. Semi-submersibles and drill ships are dynamic, that is they float and thus move with wind & waves while in working mode. On floating rigs, it is not practical to mount the BOP stack on top of the long riser pipe. The BOP stack is much too heavy for the relatively thin and flexible walls of the riser pipe. Also because the riser walls are relatively thin, they cannot withstand the high pressures that could develop inside the riser when the well’s shut in on a kick. So the rig crew mounts the BOP stack on the well head at the see floor and makes up the riser on top of the stack.


A blow out is dangerous. Formation fluids like gas and oil blow to the surface and burn. Blow outs can injure or kill, destroy the rig, and harm the environment. Rig crews there for trained and work hard to prevent blowouts. Usually they’re successful, so blowouts are rare. But when they happen, they are spectacular and thus often make news.

Taking a Kick

A kick is the entry of formation fluids into the well bore while drilling. A kick occurs when the pressure exerted by the drilling mud is less than the pressure in the formation that the drill string is penetrating. The mud that circulates down the drill string and up the hole is the first line of defence against kicks. Drilling mud creates additional pressure as it circulates. The mud pressure keeps formation pressure from entering the well bore. On the rig, they say mud keeps the well from kicking. Sometimes however, crew members may accidentally allow the mud level or mud weight in the hole to drop, this drop in weight or level can happen for several reasons.

For example, the crew may fail to keep the hole full of mud when they pull the pipe out of it, or they may pull the pipe too fast, which can lower the bottom hole pressure. When the mud level or mud weight drops, the pressure exerted on the formation decreases. If either happens, formation fluids can enter the hole. If they do, the well takes a kick. In other words, when the formation pressure exceeds the weight of the mud column, then the well can kick.

[TOOL BOX]: Liquids and gases exert a force against the container. That is the liquid or gas pushes against the wall of the container. If we measure the amount of push or force being exerted on each unit of area on the container, we have the pressure of liquid or gas. So pressure is defined as Force per Unit Area. Common units that are used to measure pressure are Pounds per Square Inch and Kilopascals. This gauge shows the down hole pressure of the mud column; this gauge shows the reservoir pressure. Change the pressure of the mud column and see what happens. To keep a kick from becoming a blowout, the rig crew uses blowout prevention equipment.


Basic Concepts

The blowout preventer—BOP stack, consists of several large valves stacked on top of each other. These large valves are called blowout preventers. Manufacturers rate BOP stacks to work against pressure as low as two thousand pounds per square inch or 2000 psi, and as high as 15000psi, that’s about 14000 Kilopascals to over 100000 Kilopascals. Rigs usually have two kinds of preventers. On top is annular preventer. It’s called an annular preventer because it’s around the top of the wellbore in a shape of a ring or an annulus. Below the annular preventer are ram preventers. The shown of valves in ram preventers close by forcing or ramming themselves together.
The choke line is a line through which well fluids flow to the choke manifold when the preventers are closed. Even though the preventers shut in the well, the crew must have a way to remove or circulate the kick and mud out of the well.

When the BOP shut in the well, mud & formation fluids exert through the choke line to the choke manifold. The manifold is made up of special piping and valves. The most important valve is the choke. The choke is a valve that has an adjustable opening. Crew members circulate the kick through the choke to keep back pressure on the well. Keeping the right amount of back pressure prevents more kick fluids from entering the well. At the same time, they can get the kick out of the well and put in heavier mud to kill the well. That is regain control of it. The well fluids leave the choke manifold and usually to a mud gas separator. A mud gas separator separates the mud from the gas in the kick. The clean mud goes back to the tanks; the gas is flared or burned at a safe distance away.

BOP Operation

When the well takes a kick and the BOP is open, well fluids force mud to flow up the well bore and into the BOP stack. When the driller closes the annular BOP, flow stops. Usually, drillers close the annular BOP first. The closed annular BOP diverts the flow of the choke line, which goes to the choke manifold. The driller can open a valve on the choke line and safely circulate the kick out of the well through the choke manifold.

[TOOL BOX]: Here is an annular preventer, click on it to see how it works. An annular BOP closes on drill pipe, drill collars or any shape of tubular in the well. It can also close an open hole, a hole with no tubulars in it at all. It’s usually the first preventer used to close in the well. Here are four types of Ram-Preventers: Pipe Rams, Blind Rams, Blind-Shear Rams and Variable Bore Rams (VBR Ram). Click on each one to see how the rams work.

Pipe Rams

Pipe rams are used when there is drill pipe in the BOP stack. The pipe rams fit around the pipe, closing off the annulars. Pipe rams back up the annular preventer. That is then it’s likely at the end the annular BOP failed, crew members could shut the pipe rams to seal the well. Also some pipe ram preventers are used to hang off or suspend the drill string and some subsea BOPs.

Blind Rams

Blind rams are designed to seal an open hole. If the annular BOP fails and there’s no pipe in the hole, the crew could seal the hole by closing the blind rams.

Blind-Shear Rams

Blind-shear rams are designed with blades that cut through the drill pipe and then seal the open hole. They’re used in extremely emergencies, like when an offshore floating rig has to move off a well that they’re drilling because of a hurricane or other such emergency. Blind shear rams allow them to cut the pipe, seal the hole and then move the rig a safe distance away.


Variable Bore Rams or VBR are special pipe rams that can close over a range of pipe sizes such as 5 inch diameter to 3 inch diameter.



Here are the major parts of a land, jack-up, platform or submersible rig’s blowout prevention equipment: the blowout preventer or BOP stack, the driller’s BOP control panel, the BOP operating unit accumulator, the choke manifold, the choke control panel, the mud gas separator, the flare line & flare pit, the trip tank and drill string valves.

[TOOL BOX]: Prompt quiz: You’ve just learned the names of the equipment used in well control operations. Let’s see how well you can identify the equipment. Using the mouse, drag the labels to their correct locations. When you’ve completed this exercise, click the “accept” button.

Driller’s BOP Control

From this BOP control panel, the driller opens and closes or controls the blow out preventers and the line to the choke manifold. Rig builders usually place the control panel on the rig floor, close to the driller’s position. Lever and switches allow the driller to quickly open and close the preventers and other valves in the system.


The accumulator bottles store or accumulate hydraulic fluid under very high pressure, up to 3000 psi, over 20000 KPa. This high pressure fluid ensures that the preventers close very fast. The BOP operating unit accumulator is installed some distance from the rig floor.

Hydraulic Lines

When the driller activates the BOP operating unit, it pumps the hydraulic fluid through the high pressure pipes of lines into the BOP stack. The hydraulic pressure opens or closes the preventers.

Operating Lever on Accumulator

Usually, the driller operates the accumulator from a control panel on the rig floor. In an emergency however, crew members can operate the BOPs by using the control valves on the accumulator itself.

Choke Manifold / Chokes

Here is a choke manifold. Flow gets to it from the BOP stack via a choke line. The manifold usually has two or more special valves that called chokes. Usually well flow goes through only one of the chokes, the others are back ups or used under special conditions.

Choke Operation

By adjusting the size of the opening in the choke, making the opening larger or smaller, the driller adjust the amount of the flow through the choke. The smaller the opening, the less flow; the larger the opening, the more flow. The less flow, the more back pressure on the well; the more flow, the less back pressure on the well. This adjustment of back pressure keeps the pressure on the bottom of the hole constant so that no more kick fluids can enter the well.

Choke Control Panel

The driller or another crew member uses the choke control panel to adjust the size of the choke’s opening as kick fluids flow through it. By watching the pressure on the drill pipe and casing, and by keeping the mud pump at constant speed, the choke operator can adjust the choke to keep the pressure on the bottom of the hole constant. The choke operator must keep the bottom hole pressure constant to successfully control and circulate a kick out of the hole.

Mud-Gas Separator

Often, kick fluids and mud from choke manifold go through a line to a mud gas separator. Frequently, formation gas is the main part of a kick. However, kick fluids may also contain water, oil, or combination of these fluids. In any case, the mud gas separator removes the gas from the mud. With the gas removed, the pump circulates gas-free mud into the mud tanks and back down the hole. The separated gas goes to a flare line.

Separator Operation

In the separator, mud with gas in it from choke manifold enters the top and falls over several baffle plates. The gas breaks out of the mud as it falls over the baffle plates and goes into the flare line. The gas-free mud falls to the bottom outlet where it goes to the mud tanks for circulation down hole.

Flare Line & Flare Pit

The flare line conducts gas from the mud gas separator to a flare pit on land rigs. The gas is burned or flared at the flare pit. Notice that the flare line outlet is a good distance away from the rig floor, so even while gas is flaring, the crew can still safely work on the rig floor.
Offshore, where there is no flare pit, the flare line conducts the gas over the side of the rig. The line runs over the water, a safe distance away from the rig.

Trip Tank

A trip tank is a special mud tank. It is used when they pull drill string from the hole, for example, to change out a dull bit. They also use the trip tank when they run drill string back into the hole. Pulling the drill string and running it back in is called a “trip”, which is why they call the small tank a “trip tank”. They use it to keep accurate track of how much mud the drill string displaces in the hole.

Trip Tank Operation

When the crew pulls drill string from the hole, the mud level in the hole drops. If they let the mud level drop too far, it won’t exert enough pressure to keep formation fluids from entering the hole. So, as the crew pulls pipe, they continually circulate fluid from the trip tank to replace the drill string and keep the hole full. They also watch for unusual changes, and may make sure that the volume of mud they put in exactly replaces the volume occupied by the drill string. Since the volumes are small, the level of mud in the trip tank is calibrated in small increments, such as stands of pipe, or barrels or liters of mud, or both. If the volume they put in is less than the volume occupied by the drill string they removed, then it’s likely that formation fluids have entered the hole. For example, let’s say the crew pulls one stand of drill pipe. In this instance, the stand displaces .7 barrels or 111 liters. There for, they should pump .7 barrels or 111 liters of mud to replace the stand. The mud level in the trip tank should sure drop .7 barrels or 111 liters. If the level in the tank shows less, then formation fluids have entered the hole and the crew must take steps to control the well.



Subsea BOP equipment is similar to a surface stack. There are, however, some very important differences. This section discusses these differences.
Subsea stacks attach to the wellhead on the sea floor. Meanwhile, the rig floats on the water, hundreds or thousands of ft or meters above. Major parts include: the Subsea BOP stack, this is a lot like a surface BOP stack; other parts are different, however. Here’s the flexible or ball joint.
The marine riser with a choke line and a kill line, guide lines, the telescopic joint with riser tensioners, the hose bundle, and two control pods. The driller controls the subsea BOP valves from electric BOP control panel on the rig. The subsea hose bundle carries the control signals and hydraulic fluid from the rig down to the control pod and selected subsea BOP valves.

Marine Riser System

Marine riser pipe is special pipe and fittings. It seals between the top of the subsea BOP stack and the drilling equipment located on the floating rig. Crew members run the drill string into the hole inside the riser pipe. The riser pipe also conducts drilling fluid up to the rig. Manufacturers attach two smaller pipes called the choke and kill lines to the outside. Crew members use them to control the well during a kick or special operations. Guide lines guide and help position equipment such as the BOP stack to ocean floor. The flexible joint cuts down on bending stresses on the riser pipe and BOP. The telescopic joint compensates for the vertical motion of the floating rig.

Riser & Guideline Tensioner

Crew members also attach the riser tensioning system to it. Riser tensioner lines support the long riser pipe. The riser and guide line tensioners put constant tension on the riser pipe and guide lines. This tension suspends the riser pipe. It also compensates what the movement of the rig caused by wave action. Riser tensioner systems usually range in capacity from over 300,000 to almost 1,000,000 pounds (that is 135,000 to over 450,000 kg) with 50 ft or 15 meters of wire line travel. They utilize up to 12 compression loaded tensioners that use air pressure for compensation.



Drill string valves stop fluids from flowing up to drill string. Often, if the well kicks with the bit off bottom, formation fluids flow up the annulus, and up the drill string. Crew members close the drill string valves to stop the flow in the string. If the kelly is made up, they can close the upper or lower kelly cock. If the kelly is not made up, then they can install a full opening safety valve on the top of the drill string.

An inside blowout preventer or IBOP is a one-way valve, a check valve they can install in the drill string. One side of the IBOP is a float valve that is sometimes made up in the drill string near the bit. It prevents back flow up the drill string. Another type of IBOP is the Drop-in valve or DIV. It’s dropped into the drill string and falls to a special landing sub that’s usually located near the top drill collar and drill stem. It allows the driller to pump mud down the string. But the check valve won’t allow influx fluid to flow up the string.
Another type of the inside BOP is the Heavy Duty Check Valve or Gray Type Valve after one company that makes it. It’s a plunger check valve that the crew stab it in the drill pipe at the surface. It’s usually used during stripping operations. Stripping is when the cerw lowers the pipe in the hole while the BOPs are closed & under pressure.

Upper / Lower Kelly Cocks

An upper kelly cock is located above the kelly. The upper kelly cock normally surves as a back up to the lower kelly cock. If the lower kelly cock failed, crew members will use a special operating wrench to close the upper kelly cock. The closed upper kelly cock prevents further flow, it protects the equipment above the kelly from high pressure flow. Usually crew members close the lower kelly cock if a kick puts risk on the equipment above the kelly. They make it up at the bottom of the kelly. A crew member uses a special operating wrench to close it. The crew can also close the lower kelly cock to keep mud from falling out of the kelly when they break out the kelly to make a connection. A cock is another name for a valve. Cock is short for weathercock, which is English term for valve.

Full-Opening Safety Valve

Here is a full-opening safety valve. If the kelly is not made up in the drill string and flow occurs. Crew members can insert the safety valve in the drill string. This procedure is called “stabbing”. A full-opening valve has as large an inside opening as possible. When fully open, flow from the frill pipe passes through the valve with no additional restriction. This relatively large opening allows the crew to stab the valve against pressure coming out of the drill string.

Safety Valve Usage

The crew picks up the safety valve by its lifting handles. They make sure it’s fully open and stab it into the drill pipe. Then they screw it into the pipe. Finally they use a special operating wrench to close the valve and shut off flow. Driller should make sure the rig has the right crossover subs at hand on the rig floor. Crew members should be able to make up the safety valves and any drilling string member coming out of the rotary. For example, if a drill collar is in the rotary, the safety valve’s threads may not match the drill collar’s threads. They will need the right crossover sub to make it work.

[TOOL BOX]: This well is taking a kick. To shut it in, choose one of the two valves you see here: a one-way safety valve and a full-opening safety valve. Click on the valve you wan to use. Hold your mouse button down and drag the valve to drill pipe… Good choice! The full-opening safety valve is the correct valve to use in this situation. It can be stabbed on the drill pipe while it’s open and then close to shut in the drill string. You’re not done yet though, the annulus hasn’t been sealed, so the well is still not fully secured. Click on the correct preventer on this BOP stack that should be closed first. That’s right! The annular preventer is closed first. Good job! You’ve successfully closed in this well.

Float Valves

Float valves also prevent flow up the drill string. Crew members place a float valve in a sub, a special drill string fitting, just above the bit. One type allows mud to be pumped down but shut against upward flow. Under normal conditions, pump pressure moves drilling mud through the open one-way valve, and influx of formation fluids from below causes the float valve to close. This prevents further flow up the drill string.

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