blowout preventors

7/29/2019 Blowout Preventors

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BLOWOUT PREVENTORS:

KICK CONTROL EQUIPMENT

PRESENTED BY:

PUNDARIK KASHYAP SAVAPONDIT



What is a kick?

An influx of formation fluid into the wellbore thatcan be controlled at surface.

What criteria are necessary for a kick to

occur?

1. The formation pressure must exceed the wellboreor annular pressure. Fluids will always flow in

the direction of decreasing or least pressure.

2. The formation must be permeable in order for theformation fluids to flow.



What is a blowout?

A flow of formation fluids that cannot becontrolled at surface.

What is an underground blowout?

An underground blowout occurs when there isan uncontrollable flow of fluids between two

formations. In other words, one formation iskicking while, at the same time, anotherformation is loosing circulation.



What is a surface blowout?

A surface blowout occurs when the well cannot be shut in to prevent the flow of fluids atsurface.



Causes Of Kicks

Not keeping the hole full when tripping outof hole

• When pipe is pulled from the hole, mud must bepumped into the hole to replace the steel volumeremoved. If not, the mud level in the hole will

drop, leading to a reduction in the overall mudhydrostatic pressure. Keeping the hole full isextremely critical when pulling drill collarsowing to the large steel volume.



• Reducing annular pressure throughswabbing

Frictional forces resulting from the mud

movement caused by lifting pipe, reduce theannular pressure. This is most critical at the beginning of a trip when the well is balanced by mud hydrostatic and when swab pressures are

greatest.



• Lost circulation

If drilling fluid is being lost to a formation, itcan lead to drop in mud level in the wellboreand reduced hydrostatic pressure.

• Excessive ROP when drilling throughgaseous sands

If too much gas is allowed into the annulus,especially as it rises and starts expanding, it will cause a reduction in the annularpressure.



Overpressured formations

Naturally, if formation pressure exceeds theannular pressure, then a kick may result.



Indications Of Kicks While Drilling

• Gradually decreasing Pump Pressure There may also be an associated increase in thePump Rate. The drop in pump pressures as a directresult of lower density formation fluids entering

the wellbore, reducing the overall mud hydrostatic.The pressure drop will be most significant with gasand worsened as gas expansion takes place. Initialpressure drop may be slow and gradual, but thelonger the kick goes undetected, the more“exponential” the drop in pressure.



• Increased mud flow from annulus, followed by…..

• An associated increase in mud pit levels

As formation fluids enter the borehole, anequivalent volume of mud will, necessarily, bedisplaced from the annulus at the surface. This is inaddition to the mud volume being circulated so that

the mud flow rate will show an increase.



As the influx continues…….

Variations in Hookload/WOB

Although certainly not a primary indicator, theseindications may be seen as the buoyancy effect on

the string is modified.

If the influx reaches surface….

Contaminated mud, especially gas cut

Reduced mud density. Change in chloride content(typically increase).



Indicators While Tripping

Insufficient Hole Fill

When tripping out of hole, the hole is not takingenough mud fill to compensate for the pipe volume that has been pulled from the hole. Thismay indicate that:

A kick has been swabbed into the hole, or that… Mud is being lost to the formation



Pit Gain

• A continual increase in trip tank level clearly shows that a kick is taking place.

Mud Flow

• Similar, mud flowing at surface indicates aninflux..

A “wet trip”

• Where the influx and pressure, beneath the string,prevents mud from draining from the string as it islifted.



• Every precaution (i.e. monitoring the well before pulling out, minimizingswabbing, flow checks) is taken toavoid taking a kick during a trip:

• The well cannot be shut in (pipe or annularrams) if drill collars are passing through the

BOP’s.



The BOP Stack

To prevent the occurrence of a blowout, thereneeds to be a way of closing, or sealing off the

wellbore, so that the flow of formation fluidsremains under control. This is achieved by theBlow Out Prevention system (BOP), an

arrangement of preventers, valves and spoolsthat is positioned on top of the wellhead



Commonly referred to as the stack, it’s purpose is to:

• Seal off the well so that the flow of formation fluidsis under control.

• Prevent fluid from escaping to surface.

• Allow the release of fluids, from the well, undercontrolled conditions.

• Allow drilling fluid to be pumped into the wellunder controlled conditions to balance formationpressure and prevent further influx.

• Allow movement of the drillstring in or out of the well



• The requirements for a BOP stack are as follows:

• It must be able to close off and seal the well

completely, with or without string in the hole.• It must have a simple and rapid shut inprocedure.

• It must have controllable lines through which to

bleed off pressure.



CRITERIA FOR SELECTION OF BOP

Selection of BOP determined by the followingfactors:

• Maximum anticipated surface pressure.

• Size of, bit and other drilling tools to be loweredthrough the BOP stack.

• Space available between top of cellar pit and

bottom of rotary table.• Matching flange connection according to the size

and pressure rating of wellhead flange.

• Service conditions.



Blowout preventer are of two

types-i) Annular BOP

ii) Ram BOP



Annular BOP

Commonly referred to as a bag type or sphericalpreventer, it is designed to stop flow from the well using a steel-ribbed packing element that

contracts around the drill pipe. The packer willconform to the shape of the pipe that is in the bore hole. It is operated hydraulically, utilizing a

piston acting on the packer. Once closed they utilize the upward well pressure to maintaintheir closed position.



• The normal hydraulic closure of an

annular preventor is 1500 psi.

• Once the packer is closed, the pressure

should be reduced slightly to reducedamage to the rubber portion of thepacker. One special feature of the annular

preventer is that it will allow strippingoperations to be carried out whilemaintaining pressure as the tool jointspass through the preventer.



Ram Preventers:

Ram type preventers have two opposing packingelements that are closed by moving them

together. Rubber packing elements again, formthe seal. A major difference between these andthe annular preventer is that they are designedfor specific applications. Rams are designed for a

certain size of pipe and will only work on thattype of pipe.



Pipe rams:

These have semi-circular openings that matchthe diameter of the pipe being used. A drillstring

comprising different pipe sizes, such as 3-inchand 5-inch drill pipe, would require two sets of pipe rams to accommodate both sizes of pipe.



Blind rams:

These are designed to close off the hole when nopipe is in the hole. If they are shut on drill pipe,

they will flatten the pipe, but not necessarily stem the flow.



Shear rams

These are a form of blind rams that are designedto cut drill pipe when closed. This will result in

the dropping of the drillstring below the BOPstack unless the stack is designed in such a way as to have a set of pipe rams below the shearrams on which a tool joint can be supported.

They will stop the flow from the well. Shear ramsare usually only used as a last resort when allother rams and the annular preventer havefailed.



The positioning of the various rams, and lines, isdependent on the expected operations. The followingsummarizes the benefits/disadvantages of positioning

the blind, or shear, rams beneath, or above, the piperams.

Lower blind rams

• The well can be shut in to allow other rams to be repairedor changed i.e. used as a master valve.

• The string cannot be hung off on pipe rams.Upper blind rams

• The string can be hung from pipe rams, backed off andthen the well shut in by the blind ram.

• Pipe rams can be closed with pipe in hole and blind ramsreplaced with pipe rams. This will minimize

• wear and also allow ram to ram stripping of the pipe.



Choke Manifold

Following a kick and shut in, back pressure is applied, in

order to balance the well, by routing returns throughadjustable chokes. Release of fluids and pressure cantherefore be controlled safely.

• A soft shut-in is where the choke is open before the ramsare closed, in order to minimize the shock exerted on theformation.

• A hard shut-in is where the choke is closed prior to shut in.

The chokes are connected to the BOP stack through a seriesof lines and valves that provide a number of different flow routes and the ability to stop fluid flow completely. Thisarrangement is known as the choke manifold.



Again, there are specific requirements for thechoke manifold:

• The manifold should have a pressure capability equal to the rated operation pressure of the BOPstack (equal to the weakest component).

• The choke line connecting the manifold to thestack should be as straight as possible and firmly anchored.

• Alternative flow and flare routes should beavailable downstream of the choke line in order toisolate equipment that may need repair.



• Choke lines are typically used to release

fluids from the annulus.

• Kill lines are typically used to pump mudinto the wellbore if it is not possiblethrough the drillstring.



Closing the Preventers

• There are three main system components toclose the preventers:

1. Pressure source

2. Accumulators

3. Control manifold.



Pressure source:

• The hydraulic fluid must be supplied undersufficient pressure to close the rams.

• Electric or pneumatic pumps are usually used todeliver the hydraulic fluid under said pressure.

• In addition, there should always be backuppumps and an alternative source of electricity orair to power them.



Accumulators:

Accumulator bottles are a series of pre-charged nitrogen bottles thatstore and supply the hydraulic fluid, under pressure, necessary toclose the preventers.

• Different preventers have different operating pressures and requiredifferent volumes of hydraulic fluid in order to function.

• The total volume of hydraulic fluid required to operate the entirestack must be known.

• Accumulator bottles are linked together in order to store the

necessary volume.

• The bottles are pre-charged with nitrogen (typically 750 - 1000 psi).

• Hydraulic fluid is pumped into the bottles, compressing the nitrogenand increasing the pressure Control manifold.



Inside Blowout Preventors

This refers to equipment that can be used to closeoff the drillstring in order to provide additional

control.

They may be manual shut off valves that can beinserted into the string at the surface, or they may

be automatic check valves actually located insidethe drillstring downhole.



• Upper kelly valve or cock This valve

is positioned between the kelly and theswivel, in order to isolate drilling fluidin the drillstring.

• • Lower kelly valve or cock This is

installed at the base of the kelly and will

most likely be used if the upper kelly valve is damaged or inaccessible.



Safety valve This is actually identical to the lower kelly valve.

Rather than being installed as part of the string, it is kept on the rig floor inorder to be quickly “stabbed” into the

top of the drillpipe should a kick occur during a trip when the kelly isracked.



CALCULATIONS



Maximum Allowable Annular

Surface Pressure

When a well has to be shut in, in order to controla kick, surface shut-in pressure is required to

balance the bottom hole pressure.

At the time of shut-in, there are two pressures

acting at the shoe:

• mud hydrostatic

• shut-in pressure applied from surface.



• These two pressures, combined, cannot exceed thefracture pressure of the formation at the shoe (Pfracdetermined from the leak off test).

• i.e. Pfrac > HYDshoe + Shut-in Pressure

• MAASP is the maximum shut in pressure that can be

applied without fracturing the weakest zone, assumingthis is the shoe:

• Pfrac = HYDshoe + MAASP • MAASP = Pfrac – HYDshoe

• At the time of a LOT, the MAASP is clearly equal to theLeak Off Pressure, since this is the shut-in pressurethat actually causes fracture.



Kick Tolerance

KICK TOLERANCE is the maximum balance gradient (i.e.mudweight) that can be handled by a well, at the currentTVD, without fracturing the shoe should the well have to beshut in.

If the mudweight, that is required to balance the formationpressures while drilling, would result in shoe fracture during well shut in, then a deeper casing shoe (with greater fracturepressure) must be set.



THANK YOU

blowout preventors

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