Production Alonso 2

Front 1

This is installed in the hole to protect the casing from erosion and corrosion and to provide control for production.

Back 1

Tubing

Front 2

Tubing is classified according to which properties?

Back 2

OD, Grade, Weight, length and Type joints

Front 3

Cylinder, machined to specified dimensions, that is passed through a pipe to locate obstructions and/or to assess compliance with the appropriate specifications.

Back 3

Drift Mandrel

Front 4

This completion method is based on the decrease of the fluid level inside a well by applying a piston (swab). This assumes the sequential withdrawal of fluid from above the piston to the surface.

Back 4

Well completion by Swabbing

Front 5

The snap-around latches that couple around tubing below the pipe coupling and enables the traveling block on a rig to grab and lift the tubular string.

Back 5

Elevators

Front 6

A round device that holds the slips when supporting a string of drill pipe on a rig.

Back 6

Spider

Front 7

The holder for the slips on a rig. Suspends the tubing during connection make-up.

Back 7

Tubing spider

Front 8

Wedge-shaped devices (usually containing steel teeth) that hold the pipe. Capable of suspending heavy pipe string loads.

Back 8

Slips

Front 9

These will not crush the tubing should be used on the body of the tubing and should fit properly to avoid unnecessary cutting of the pipe wall.

Back 9

Tubing tongs

Front 10

This is the action of insert the seal stack or stinger into the polished bore receptacle.

Back 10

Stab

Front 11

These are hydraulic power make up tools suspended above the rig floor

Back 11

Power tongs

Front 12

This is the action of screw pipe joints together.

Back 12

Make-up

Front 13

To connect tools or tubulars by assembling the threaded connections incorporated at either end of every tool and tubular.

Back 13

Make-up

Front 14

A pipe connection with a thicker connection body than the pipe body. In an external upset, the thickness is offset to the outside diameter. Abbreviated EUE or EU.

Back 14

External Upset

Front 15

In this pipe connection the threads or connections are integrated with the pipe.

Back 15

Integral joint

Front 16

A pipe connection with consistent I.D. and O.D. with the pipe. The connection walls are thin and weaker than EU or IU connections. Used in flush joint liners and wash pipes. Also called an NU connection.

Back 16

Non Upset

Front 17

A pipe connection with a smaller I.D. than the pipe but a consistent O.D. Abbreviated IU.

Back 17

Internal Upset

Front 18

A type of tubing connection in which the internal or external surfaces are the same diameter throughout the tubing joint.

Back 18

Flush joint

Front 19

The Raising and free fall of a bit on a drillstring in a well to shake the shale accumulation off the bit.

Back 19

Spudding

Front 20

A large diameter bit that is used to drill the first few hundred feet of hole.

Back 20

Spudding bit

Front 21

A manual or air-activated device on the elevators of a drilling or workover rig or service unit that grips drillpipe, casing or tubing for hoisting. These have three or four sets of slips with teeth.

Back 21

Spiders

Front 22

To start the well drilling process by removing rock, dirt and other sedimentary material with the drill bit.

Back 22

Spud (Spud a well)

Front 23

To apply weight to a troublesome drilling section, usually by moving the drilling string up and down, in hopes that the section will drill faster.

Back 23

Spud

Front 24

Large capacity self-locking wrenches used to grip drillstring components and apply torque. These are the active tongs during breakout operations.

Back 24

Breakout tong

Front 25

A string of casing used when drilling a well to protect an outer string of pipe from drill string contact or to protect a zone.

Back 25

Protection string

Front 26

An isolation device commonly used in fracturing to protect the tree from pressure and proppant erosion.

Back 26

Tree Saver

Front 27

A type of corrosion in which there is loss of metal in localized areas. The corrosion rate in this is many times greater than the corrosion rate on the entire surface.

Back 27

Pitting

Front 28

Tubing must be designed under which conditions.

Back 28

Collapse, Burst, Tension, Corkscrewing

Front 29

During the service life of a well, tubing can experience various combinations of pressures and temperatures that result in tubing length changes. What are the four basic effects to consider?

Back 29

Balloning, Buckilng, Piston effect and Temperature

Front 30

Extremely localized attack that results in holes in the metal. Will accelerate after start.

Back 30

Pitting

Front 31

A form of corrosion in which susceptible types of metals will break by a combination of stress within the metal and the specific type of corrosion.

Back 31

Stress Corrosion Cracking

Front 32

A type of spontaneous brittle failure in steels and other high-strength alloys when they are in contact with moist hydrogen sulfide and other sulfidic environments.

Back 32

Sulfide corrosion cracking

Front 33

The weight reading when the pipe is entering the well. Compared to the pick-up weight to estimate the friction.

Back 33

Slack-off weight

Front 34

The surface weight measurement when pulling a pipe string or wireline out of the hole. Includes both string weight and frictional drag.

Back 34

Pickup weight

Front 35

This term refers to the amount of slackoff weight or tension that is left on the packer when the tree is landed and the wellhead is flanged up.

Back 35

Landing condition

Front 36

Installing casing to the casing set point.

Back 36

Land casing

Front 37

The process of assembling flanged components such as pressure-control equipment.

Back 37

Flange up

Front 38

In well completion this is the action of finish an operation or process.

Back 38

Flange up

Front 39

This effect is caused by pressure changes inside the annulus and tubing at the packer, acting on different areas.

Back 39

Piston effect

Front 40

Tubing strings tend to made this effect only when the internal tubing pressure (pi) is greater than the annulus pressure (po).

Back 40

Buckling

Front 41

This is simply a mechanical means of forming a seal between two strings of pipe or between the pipe and the open hole. This generated seal isolates the tubing from the casing or open hole, preventing vertical flow of fluids or gases.

Back 41

Packer

Front 42

This packer element have teeth that anchor the packer in the casing or open hole.

Back 42

Slips

Front 43

This packer element support the slips and create a wedge to enhance anchoring capability

Back 43

Cone

Front 44

This packer element expand to seal the area between the packer and the casing or open hole

Back 44

Elastomer element or Packing element

Front 45

This packer element maintains a consistent bore and typically has an ID compatiblewith the tubular used. Outer body components are supported by the mandrel

Back 45

Mandrel

Front 46

This packer element initiates the setting sequence when desired during installation.

Back 46

Setting mechanism

Front 47

This packers do not have releasing mechanisms and are not retrievable from surface. In these the tubing can be removed from the well without releasing the packer. Permanent packers can only be removed by destroying their integrity through milling or drilling.

Back 47

Permanent packer

Front 48

These packers are in integral part of the tubing string. The packer is set, released and pulled with the tubing string.

Back 48

Retrievable packer

Front 49

These packers are designed to meet general or specific well conditions and provide a long operational life in those conditions. They are manufactured from a variety of materials to meet operational life expectancy in different environments.

Back 49

Production packer

Front 50

These packers are used to perform specialized functions, these are commonly used to pressure test casing and repair if a leak exists; temporarily suspend producing intervals; and protect the casing string from high pressures during hydraulic fracturing.

Back 50

Service packer

Front 51

In this packer set application, tubing movement is used to create the force necessary to set the packer and energize the element

Back 51

Mechanical set

Front 52

In this packer set application, force is generated internally within the packer by applying fluid pressure to set the slips and energize the element.

Back 52

Hydraulic set

Front 53

In this packer set application, an electric pressure setting tool is used. An electric current ignites a powder charge to create a gas pressure within the setting tool. The gas pressure then acts on a hydraulic piston to create a force sufficient to set the packer slips, energize the element and shear the setting tool from the packer.

Back 53

Wireline set

Front 54

This effect is the result of pressure changes, which occur inside the tubing string and annulus at the packer. The result of this effect is either an up or down force at the packer.

Back 54

Piston effect

Front 55

A device in a length of pipe that allows some pipe length expansion or contraction.

Back 55

Expansion joint

Front 56

In this effect the hydrostatic pressure in the well acts on the end area of the tubing string. This creates an upward pressure-related effect, resulting in a reduction in the weight of the tubing string as well as a shortening of the overall length of the tubing string. How is known this effect?

Back 56

Buoyancy

Front 57

This eefect will occur due to two different force distributions. One is the compressive force mechanically applied to the end of the tubing, and the other is the internal pressure that results in a force distribution on the ID area of the tubing

Back 57

Buckling

Front 58

This tubing effect will occur when the pressure inside a tubing string is greater than the pressure outside the tubing and also fo the compressive force applied to the end of the tubing.

Back 58

Buckling

Front 59

This is defined as tubing that is bowed from its original straight condition. The tubing will bow outward until it contacts the casing wall at which point it will begin to coil.

Back 59

Buckled tubing

Front 60

A tubing will buckle or bow outward until it contacts the casing wall at which point it will begin to coil. How is referred this coiling of the tubing?

Back 60

Corkscrewing

Front 61

Above this point in the tubing, buckling does not occur. How is known this point.

Back 61

Neutral point

Front 62

This effect occurs when pressure is applied to the inside of a tubing string: The pressure differential creates forces within the tubing string, which are trying to burst the tubing. The burst forces created within the tubing string due to the differential pressure causes the tubing to swell.

Back 62

Balloning

Front 63

In this effect exists a pressure differential on the outside of the tubing string, then the force created is attempting to collapse the tubing.As the tubing tries to collapse, it lengthens if it is free to move. How is known this effect?

Back 63

Reverse ballooning.

Front 64

This is a continuous length of steel tubing with no joints. In general, this is fabricated to the length needed for a particular well application and rolled onto a reel for transport to a well site for placement in the well.

Back 64

Coiled tubing