6 wi lp1-4 surface downhole equipment fi 2003

8/12/2019 6 WI LP1-4 Surface Downhole Equipment FI 2003

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WELL INTERVENTION PRESSURECONTROL

WELL COMPLETION

Dr. Imre Federer

Associate Professor


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COMPLETING THE WELLGeneral

The well intervention well control is

about the well control of working on live wells

the well operations are conducted by

wireline ,

coiled tubing

snubbing unit.

Well pressure control is the most critical consideration in theplanning and performing of any well servicing operation.


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Completion Fluid Characteristics

Dense:

enough to control well pressures but no frac. the formationCost-effective: Expensive fluids to prevent damage to sensitive formations.

Free of solid particles as possible: Solids can plug perforations as well as reduce production.

Noncorrosive : to prevent failure of tubular goods.

Stable: If the fluid is to be left in the hole for an extended period.

Filtered or cleaned: The low solids content can still cause plugging at formation.


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Completion Fluid Density Ranges

Fluid Minimum Densitykg/l (ppg) Practical Maximum Densitykg/l (ppg)

Oil 0.96 (8.0)

Diesel oil 0,84 (7.0)

Fresh water 1.0 (8.3) 1.0 (8.3)

Sea water 1.01 (8.4) 1.02 (8.5)

Brine-sodium chloride (NaCl) 1.0 (8.3) 1.18 (9.8)Brine-potassium chloride (KCl) 1.0 (8.3) 1.17 (9.7)

Brine-calcium chloride (CaCl 2) 1.32 (11.0) 1.38 (11.5)

Brine-calcium bromide (CaBr 2) 1.38 (11.5) 1.80 (15.0)

Brine-zinc bromide (ZnBr 2) 1.68 (14.0) 2.18 (18.1)


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CrystallizationPoint of Brines

Weight Crystallization Point kg/l ppg oC oF

Sodium Chloride (NaCl)1,02 8.5 -2 291,08 9.0 -7 191,14 9.5 -16 61,2 10.0 -4 25

Calcium Chloride (CaCl 2)1,02 8.5 -1 301,08 9.0 -0,5 31

1,14 9.5 -13 91,2 10.0 -22 -8

1,26 10.5 -37 -361,32 11.0 -30 -221,38 11.5 +2 35

Calcium Chloride/Bromide (CaCl 2/Br 2)1,44 12.0 12 541,56 13.0 15 591,68 14.0 17,7 641,74 14.5 18,3 65

1,8 15.0 19,4 67


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Density Loss due to Temperature

Brine Factors NaCl or KCl 0.0024

CaCl2 0.0027

NaBr or NaBr/NaCl 0.0033CaBr2 or CaBr 2 /CaCl2 0.0033ZnBr2 / CaBr 2 / CaCl2< 2.1 kg/l (17.5 lb/gal) 0.0036ZnBr2 / CaBr 2 / CaCl2< 2.1 kg/l (17.5 lb/gal) 0.0048

Calculate density loss due to temperature.

ATI = Average temperature increase, oFCf = Correction factor for temperature from TableDL = Density loss, ppg

Cf * ATI DL =


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WELL COMPLETION EQUIPMENT


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Conventional Wellhead and Christmas Tree
http://www.google.hu/url?sa=i&source=images&cd=&cad=rja&docid=yDKywfOqC9aDjM&tbnid=bHYLhz4AAYRZdM:&ved=0CAUQjRw&url=http://oilandgastechnologies.wordpress.com/2012/08/08/wellhead-and-christmas-tree-equipment-based-on-iso-10423/&ei=jTJcUfurK4zDswbL54GQCg&psig=AFQjCNFkwPClndSIC3jtTrFe23PnnMLEvg&ust=1365083090597522http://www.google.hu/url?sa=i&source=images&cd=&cad=rja&docid=yDKywfOqC9aDjM&tbnid=bHYLhz4AAYRZdM:&ved=0CAUQjRw&url=http://oilandgastechnologies.wordpress.com/2012/08/08/wellhead-and-christmas-tree-equipment-based-on-iso-10423/&ei=jTJcUfurK4zDswbL54GQCg&psig=AFQjCNFkwPClndSIC3jtTrFe23PnnMLEvg&ust=1365083090597522


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Christmas tree30000 psi


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Conventional Tree Advantages : Made up of interchangeablestandard parts cheapest option.

Disadvantages: more potential leak paths due to

the large number of connections.

Master Valve Block

Tree Cap

Tree Connector

Tubing Hanger

Wellhead


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Solid Block Tree

Their working parts incorporated into a solid , Single piece steel block

with no connections between the individual valves . Advantages: - Contain fewer potential leak paths,

- Much shorter than conventional trees.

Disadvantages : - More expensive.


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Completion can be pulled through thetree without removing it.

These trees are finding favor withoperators of ESP completion,

No valves in vertical bore of tree, Two valves are on the production or flow

wing Two retrievable plugs set in the top of

the tree below the cap.

Horizontal Tree

Tee Cap

Crown Plugs

Tubing Hanger

Treehead

Tee Connector

Wellhead


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Conventional Wellhead

API test pressures for all wellheadtesting by manufacturers, (includingthe surface pressure controlequipment and downhole equipment):

Twice the rated working pressure

up to 5,000 psi,

1 1/2 times working pressure

for 5,000 psi and above .


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Spool type casing head.

Wellhead is built up until the casing strings has been run.

BOPs must be removed after cementing a casing string to

install the casing spool. Each casing string has its own casing hanger spool.

Casing spool outlets are flanged or studs (cheaper).

Outlets name: A, B or C (A internal annulus)

A annulus may be used for monitoring pressures gas lift inlet, chemical injection inlet, kill circuit,

equalising pressure downhole before opening SSDs.

tubing, packer seal or wellhead seal leak.

Disadvantages: 1) Vertical clearance between rigfloor is excessive,

2) Each flange connection is a potential leak path.

ConventionalWellhead

A

B

C


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Compact (Unihead, Multibowl) Wellhead Each successive casing hanger is landed in the same bowl. BOPs do not need to be nippled down and up again (saves rig time).

Developed in response to the needs of offshore operators. Compact wellhead overcomes the potential leak each flange connections.

API 6A certified, API PR1, PR2 Rated for 2,000 to 15,000 PSI and -75 F to

400 F . Material classes AA to HH. Elastomeric or metal-to-metal sealing. Accommodates casing sizes up to 26

inches. Reduces number of BOP connection

breakage.

Available for both vertical and horizontalproduction.

Compact design decreases height andweight.

The wellhead sits on top of the conductor(outer most pipe is the conductor).


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CompactWellhead
http://www.google.hu/url?sa=i&source=images&cd=&cad=rja&docid=yDKywfOqC9aDjM&tbnid=bHYLhz4AAYRZdM:&ved=0CAUQjRw&url=http://solaralert.com.my/facilities.htm&ei=KzNcUfSAL8bntQaY24CwAQ&psig=AFQjCNFkwPClndSIC3jtTrFe23PnnMLEvg&ust=1365083090597522


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CompactWellhead


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CompactWellhead
http://www.google.hu/url?sa=i&source=images&cd=&cad=rja&docid=yDKywfOqC9aDjM&tbnid=bHYLhz4AAYRZdM:&ved=0CAUQjRw&url=http://solaralert.com.my/facilities.htm&ei=TDNcUcPoBInGswbHvIEY&psig=AFQjCNFkwPClndSIC3jtTrFe23PnnMLEvg&ust=1365083090597522


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Pack-off Bushing The MBS Wellhead pack-off bushing lands on the casing hanger to

suspend and seal the intermediate casing string(s).

The inner seal on the bushing is a D seal which is energized by plastic

packing. This seal can be reenergized, if necessary, throughout the life of the well.

The outer seal is radially energized .

CasingHanger

Wellheadbl kivenni!


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Tubing

Hanger

MechanicallyScrewed plug type

Wireline plug type Dual Tubing hangerwireline plug type

Located at top of the completion string,

Enable to run, hang-off, set and seal the completion string,

It forms the load-bearing and supporting interface for tubing string,

Accommodates the down hole control li ne connections.

Have a screwed or nipple profile for a plug to be installed prior toremoving the X-mas tree,

Have a function during the testing of the Xmas tree valves.

Seal is typically a metal-to-metal seal ,

Tested both prior to and after releasing the tubing hanger running tool.

Secondary Barrier


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Tubing Hanger Plugs

Tubing hanger usually has a place for locating a Tubing Hanger Plug or

Back Pressure Valve or

Two Way Check Valve.

Functions:

Sealing off the top of the well below the Xmas tree.

If using a DHSV control line(s), seals off the line(s ).

Devices can be run into the tubing hanger with the well still under pressure.

They are of two basic kinds :

Wireline type plugs

Mechanically screwed in plugs


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QUESTIONS ?


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WELL INTERVENTION PRESSURE

CONTROL

DOWNHOLE TOOLS

Well Training & Finance Ltd.Dr. Imre Federer

Associate Professor


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Downhole ToolsTubing Hanger

Flow coupling

Safety Valve

Landing Nipple

Flow coupling

Side Pocket Mandrel

Flow coupling

Sliding Side Door

Packer

Millout Extension

Perforated Joint

Polished Bore Receptacle

Landing Nipple

Landing Nipple

Wireline Entry Guide

Wireline Entry Guide

It has a smooth, often tapered, inner profile,

To allow well servicing tools to re-enter with ease.Bell Guide

45 lead in taper to allow easy re-entry wireline tools.

Mule Shoe

Has a 60 o angle on the outside of the guide.

Tubing rotation will guide the tubing into the liner. Flow coupling

Thick walled tubing designed to withstand erosion,

ID is drift of tubing but OD is collar OD.

Perforated joint

An entry path for reservoir fluids into the tubing, Allowing accurate pressure/temperature recording.

Blast joints

The wall thickness is greater than tubing.

Installed in the tubing opposite perforations,

Prevent tubing damage from the jetting,


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Nipples

Nipples are to allow a wireline device to pass through anupper nipple and be set in a lower one.

The most common locations for nipples are:

Just above the packer /seal assembly/circulating device for

pressure testing.

Just below the packer /millout extension/seal boreextension for pressure setting of the packer.

At the bottom of the completion to enable gauges to behung and left in the well for a time to monitor thereservoir.


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Nipples

No-Go Nipple

Has a No-Go restriction below the packing bore.

The primary plugging point below the packer

Receptacle for test plug to set the packer and test thetubing.

Used for plugging with locking device, when tubing has to be pulled and leaving the

packer in the hole.

Landing Nipple

Has not a No-Go shoulder, It has a recess for locking dogs.

Positive shoulder for locating the flow control device,

Provides maximum through bore for completion.


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Downhole Safety Valve

Commonly flapper valves which open downwards ,

It will isolate the reservoir fluids from surface.It should be deep enough : to be unaffected by damage due to wellhead sabotage (explosions), to be unaffected by surface impact damage to the wellhead (collisions),

to be unaffected by the crater that is formed by a major blowout, on closely spaced wellheads to be unaffected by another well being drilled

into it. In a single land well, the DHSV is often placed about 2-5 joints below the

ground level. There are offshore wells with the DHSV at 2500 ft below the tree.

Allow the DHSV to be used as a barrier , when it has been closed and inflow

tested to prove that it is holding pressure.


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Surface Controlled Sub-Surface Safety Valves (SCSSV)

It is a downhole safety device that can shut in a well in an emergency orprovide a barrier .

It can be controlled from the surface by hydraulic pressure through controlline to the SCSSV.

It is held open by hydraulic pressure supplied by a manifold at the surface.

Damage to the wellhead or flowlines causes a low operating pressure. Whenthis pressure is lost, the safety valve automatically closes.

It is failsafe and will isolate the wellbore in the event of a loss of thewellhead pressure control.

Two main categories:

Wireline Retrievable SCSSV

Tubing Retrievable SCSSV.


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Tubing Retrievable SCSSV

This is run and pulled as an integral part ofthe tubing string.

All components are incorporated in oneassembly which is installed in the completionstring.

If the control line leaks it may be possible torun with wireline a Storm Choke toproduction until to conduct workover

Damage can be happened:

Running into the open DHSV with an item ofwell servicing equipment (wear, mechanicaldamage).

Allowing the DHSV to close on the wellservicing equipment that is running through..


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Tubing Retrievable SCSSV

Disadvantage:

It can be removed for repair only with doing a workover. For this reason, should a tubing retrievable DHSV fail, the facility exists to

permanently lock it open and insert another wireline retrievable safetyvalve inside it.

Advantage:

It has a much larger bore and hence flow through it,

There is no facility for removing it before commencing intervention operations,

No potential flow path up the control line of the risk of damage to the DHSV,

It is possible to run it open with an installed straddle across the valve.

This straddle is pulled with wireline after the completion is set and the tree ison.


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Wireline Retrievable SCSSV

It is locked and sealed off in a special landing nipple Which has a side connection for the control line , Between two packing stacks allowed control pressure to open

the valve. DHSV in intervention work requires the removal . There is then a flow path from the inside of the tubing , up the

control line, to the surface.

Isolation sleeve can be installed in nipple to isolate this flowpath

Disadvantage: It is reduced bore since the DHSV must pass through the tubing

above it.

Designing the well so that the size of the tubing above the DHSVis larger than the tubing size below.Advantage: It is quick, easy and cheap to regularly replace , serviced. It is run in the well in open position by a special prong.

TOP VIEW

HRP SAFETY VALVELANDING NIPPLE

LOCKMANDREL

SAFETYVALVE


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Annulus Safety Valves

For gas lift well , it is often a requirement to install the annular safety valve.

Annular safety valve system provides a retrievable safety valve and packer .

This is usually combined with the tubing safety valve in one unit andresembles a packer.

It is placed at the same depth as an ordinary safety valve would be placed.

This is generally a packer type installation ,

But may also be a casing polished bore nipple into which a packingmandrel will seal.

In the sealing device there is a valve mechanism operated by hydraulicpressure similar to an SCSSV.

The valve mechanism opens the communication path from the annulusbelow to the annulus above the valve and is fail-safe closed .


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Sub-Surface ControlledSub-Surface Safety Valves

(SSSV)

Storm Choke valves are restrictions in the flowpath held open by a spring.

The well can be reopened by pumping. SSSV placed in a nipple in the completion. They are run and pulled by wireline. Popular in land operations due to its min.price.

Two Types:

Excess flow ( pressure differential ). If the flowrate increase significantly, the pressuredifferential across a choke changes and a springcloses the valve.

Pressure activated ( ambient pressure ). The

well hydrostatic pressure keeps the valve open.If the well starts to blow out, the tubingpressure drops and the valve is closed by aspring and pre-charged nitrogen chamber.

Spring

Open Close


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Side Pocket Mandrel (SMP)

In Gas Lift wells , high pressure gas injectedinto the annulus flows through the ports ofthe pocket in gas lift valve and into the tubing .

The standard pocket is ported between theseal bores to communicate with the casingannulus.

The SPM are used for tubing flow applications. SPM are available in sizes from 2- 3/8 to 4 -

1/2 tubing and they will work with 1 and 1 -1/2 O. D. gas lift valves.

Side pocket mandrels have a positionorienting sleeve and tool guard of the kick-over tool with the pocket.

Gas Lift Completion

Tubing Retrievable Safety Valve

Packer

Landing NippleVII GLC 1CN00049F

Side Pocket Mandrels withGas Lift Valves

Sid P k t M d l


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Side Pocket Mandrel(SMP) SPM is most commonly used in two ways.

Used as a means of gas lifting the well ,

By using a Kick-Over Tool, a plug or valve can be

run/pulled from the side pocket. Good practice to run a valve catcher below the SPM

before pulling/running devices in the pocket.

This is so that, if they drop off the Kick-Over Tool, theywill not fall to the bottom of the well.

Devices that can be installed in a SPM are:

Gas Lift Valve - gas injection into the tubing.

Shear kill valve - pressuring up annulus opens valve.

Circulation valve - for protecting the pocket.

Injection valve - for injecting inhibitor.

Gauges - for recording pressure and temperature.

Dummy Valve - plug the SPM (positive plug).

Orienting Kickover Tool


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Sliding Sleeve (SS) Circulating device which allows communication

between tubing and annulus, without unseating thepacker.

Installed in the tubing string a SS has a port that can beopened and closed by wireline.

Shifting Tool is run on wireline and engages a profileon the inside of the inner sleeve.

By jarring the inner sleeve is moved .

To close the Sliding Sleeve after it has been opened,the shifting tool is run the other way up and again itengages in the profile.

By jarring in the opposite direction to opening , theinner sleeve moves to closed position.

Such sleeves can either open upward and closedownward or open downward and close upward .


37/49

Downhole ToolsPackers

A packer seals the annular space between the casing and the tubing.

It prevents the wellbore fluids from contacting the casing above thepacker and isolates the annulus from the pressure inside the tubing.

It protects the casing from high production or stimulation pressuresand corrosive fluids.

Multiple packers isolate dual or triple completion.

Special packers are also available for squeeze cementing, acidizing, andfracturing.

There are two main groups:

Retrievable Packers

Permanent Packers


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Retrievable Packer

Packers setting mechanisms: hydraulic or mechanical Tension packers require an upstrain and compression

packers require a set down weight. The mechanism which controls whether the packer is

in the setting position is usually a J slot .

Disadvantage : During the life of the well, the downhole pressure and

temperature can change sufficiently to remove enoughweight from the packer to unseat it.

Advantage: The retrievable packer can remove, unseat and pull it

the service person can redress most retrievablepackers with seals and slips at the job site.

J slot

Mechanical SetRetrievable Packer

Downhole Tools


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Permanent Packers The packer may or may not be attached to the tubing above it It can only be retrieved by milling.Removing these packers is in two stages: First: the tubing above the packer must be removed. It may

require that the tubing be cut just above the packer. Second: a special mill is run to mill up the top set of slips, which

allows the packer to release from the casing wall.Millout Extension: It is a pup joint with a slightly larger I.D than the packer. It may be attached to the bottom of packers to enable to

retrieved after it has had the top slips milled off. It is used to accommodate a spear during packer milling

operations retrieved the packer and tail-pipe in same run.The most common way they are set is either mechanically or explosively with wireline, hydraulically by applying pressure inside them. Permanent

Seal Bore Packer


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Seal Assemblies Seal Assemblies are installed in packers to prevent pressure from escaping

between the tubing and the packer.

It run on the bottom of the tubing string and inserted into the packer.

A latch-type seal nipple is also available that locks into the packer so thattension may be pulled on the tubing if desired.

There is a set of seals that are able to slide up and down inside or outsideanother section.

This maintains isolation of the tubing and its annulus whilst allowing fortubing movement.

Downhole Tools


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Different types of sealing:

Tubing Seal Assembly: seals are able to move up and down inside a seal borein the packer itself.

Seal Bore Extension: attached to the bottom of the packer, it can be verymuch longer allowing for greater tubing movement.

Slick joint: may be run above the packer.

This is a single unit designed for running the tubing attached to thepacker.

Once the packer has been set, the pins are sheared, the hanger landedand the slick joint is able to allow tubing movement.

Tubing anchor: If the tubing is not screwed directly into the top of thepermanent packer, it may be attached by means of a tubing anchor.

This is a device that stabs into the top of the packer and seals offinside the top of the packer.


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The Polished Bore Receptacle (PBR) may be attached to the topof the packer.

This is a housing into which seals on the bottom of the tubingcan be stabbed.

These can be 40 ft to 50 ft long. It allow for tubing movement.The Extra Long Tubing Seal Receptacle (ELTSR) has the sealsinside the enlarged bottom section of tubing being run.

This is stabbed over a mandrel with a polished external surface

attached to the top of the packer. Again this may be up to 60 ft long to allow for up to 30 ft of

movement up or down.


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Downhole Tools Flow Control Devices

Blanking Plugs (Positive plugs)

They seal off in the nipple and hold pressure from both

directions . The pressure rating of plug should always be checked if it is

planned to pressure up against it from above.


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Flow Control Devices

Check Valve

Seal off in the nipple and hold pressure from above only .Usually used for pressure testing the completion above thevalve.

Often used for setting packers .

Check valves are also available which hold pressure frombelow only.

They can be pumped through by applying tubing pressureabove.

Sometimes called Pump Through Plugs they can be used to

isolate the well below a certain point while retaining theability to pump into or kill the well.

Pump Through Plug


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Pump Open Plug

It is a positive plug that holds pressure from eitherdirection.

But can be pumped open by applying excess surfacepressure, the inside of the plug shears, which allows flow

from below.

It is used for production without retrieving by slickline.

It serve as temporary tubing plugs.

It is useful for conventional plugging applications in sandyconditions where equalizing through small bore equalizingdevices might be difficult.

They can be run pre-installed in the nipple.


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Pressure Cycle Plugs

The overbalance pressure above the plug must be cycled from zero to a pre-set value of perhaps 2500 psi a fixed number of times before the plug opens.

The number of cycles can be pre-set to anything up to 20.

The pressure cycle plug offers more flexibility and security before the plug isopened.

Pump Out Plugs

When the correct pressure is applied above the plug, the bottom of the plugshears off and is left downhole.

They can give a greater flow path than pump open plugs although they havethe same disadvantage of leaving a restriction in the nipple.


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Retrievable Bridge Plugs

It can be set anywhere in the tubing

It is usually set by an explosive force, having been run on electric line.

In this respect they are like a miniature packer in that they have slips andpacking elements.

Slickline or Coiled Tubing can however pull them.

Pump Out Subs

Same principle as the pump out plug, they are attached to the bottom of acompletion.

When pressured up on and sheared, they leave a smooth full-bore end onthe pipe.

They can be used when running completions in the same way as a pumpopen plug.


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Ice Plugs

When all other methods of plugging a well are not possible, an ice plug maybe made in a piece of surface equipment.

Freeze jobs were originally done by surrounding the item to be frozen.

In a special coil through which chemicals like glycol are passed that havebeen cooled to a pre-determined level in a heat exchanger by liquid nitrogen.

It is necessary to have still fresh water at the point where the plug is to beformed.

The process can be slow with plugs taking up to 18 hrs or more to form.


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Questions?

6 wi lp1-4 surface downhole equipment fi 2003

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