Well

Front 1

tally

Back 1

A list containing details of tubulars that have been prepared for running, or that have been retrieved from the wellbore. Eachtubing joint is numbered and the corresponding length and other pertinent details noted alongside.

Front 2

through-flowine(TFL)

Back 2

Pertaining to treatments performed on subsea wells where the fluids and associated pump-down equipment, such as plugs or darts, are pumped through the flowline normally used for production fluids.

Front 3

travel joint

Back 3

Also known as slip joint, a completion component designed to accommodate tubing movement or length changes while maintaining a hydraulic seal between the production conduit and the annulus. The size or length of the slip joint depends on the wellbore conditions and completion characteristics.

Front 4

tubing puncher

Back 4

A special perforating gun, or charge, that is designed for limited penetration to allow an inner tubing or casing string to be perforated without damaging a surrounding outer string. These guns often are used in remedial or workover operations in which downhole communication devices, such as sliding sleeves, cannot be opened to allow circulation of well-kill fluids.

Front 5

tapered string

Back 5

A string comprising tubing or components of varying size or dimension. A tapered production string may be configured with larger OD tubing joints in the upper wellbore area to optimize the hydraulic performance of the string. Although a taperedcoiled tubing string will have the same tubing outside diameter throughout, the upper portion of the string may have a greater wall thickness to support the load of the string below.

Front 6

through-tubing

Back 6

Pertaining to any reservoir or wellbore treatment performed through the tubing string. Through-tubing treatments are generally associated with live-well operations, thereby causing minimal interruption to production and eliminating the need to kill the well.

Front 7

tubing broach

Back 7

A downhole tool used to repair damaged or collapsed tubing. The tubing broach incorporates a cutter profile that is forced inside the tubing by jarring or hydraulic force to re-form the tubing wall by removing tubing wall material and forcing the tubing wall into place.

Front 8

tubing seal assembly

Back 8

A system of seals arranged on the component that engages in a sealbore to isolate the production-tubing conduit from the annulus. The seal assembly is typically longer than the sealbore to enable some movement of the components while maintaining an efficient seal.

Front 9

tell tale

Back 9

A device used to indicate the position or function of mechanical components that cannot be easily observed, such as to indicate the launch of a cementing plug or dart.

Front 10

tie back liner

Back 10

A section of liner that is run from a liner hanger back to the wellhead after the initial liner and hanger system have been installed and cemented. A tie-back liner may be required to provide the necessary pressure capacity during a flow-test period or for special treatments, and is typically not cemented in place. In some cases, a tie-back liner will be installed as a remedial treatment when the integrity of the intermediate casing string is in doubt.

Front 11

tubing end locator (TEL)

Back 11

A downhole tool frequently used in slickline or coiled tubing tool assemblies to confirm or correlate the tool position on depth-sensitive applications. With the end of the production tubing as a known reference point, any error in measurement that may occur in reaching the treatment depth will be significantly less than what may have resulted if measuring from surface.

Front 12

tubing thread

Back 12

The threaded connection used to assemble the tubing string from individual tubing joints. Various tubing thread types have evolved to suit the wellbore conditions and functions required of the tubing string, both during installation and while the well is in production.

Front 13

tell-tale

Back 13

A device used to indicate the position or function of mechanical components that cannot be easily observed, such as to indicate the launch of a cementing plug or dart.

Front 14

tie back packer

Back 14

A specially designed packer assembly used in conjunction with a tie-back liner. The tie-back packer can be integral to the original liner hanger, or if the tie-back is a remedial treatment, it can be a separate component set above the liner hanger.

Front 15

tubing grade

Back 15

A system of classifying the material specifications for steel alloys used in the manufacture of tubing.

Front 16

tubingless completion

Back 16

A completion design in which the reservoir fluids are produced through small-diameter casing. The absence of a separate tubing string significantly limits the operating and contingency options available for the well.

Front 17

tension-set packer

Back 17

A type of packer that is set by applying tension to the running string. These packers are less common than compression-set packers due to the potential difficulties associated with retrieval. However, in applications where there is insufficient string weight to set a compression packer, a tension packer is a useful option.

Front 18

tie-back liner

Back 18

A section of liner that is run from a liner hanger back to the wellhead after the initial liner and hanger system have been installed and cemented. A tie-back liner may be required to provide the necessary pressure capacity during a flow-test period or for special treatments, and is typically not cemented in place. In some cases, a tie-back liner will be installed as a remedial treatment when the integrity of the intermediate casing string is in doubt.

Front 19

tubing hanger

Back 19

A device attached to the topmost tubing joint in the wellhead to support the tubing string. The tubing hanger typically is located in the tubing head, with both components incorporating a sealing system to ensure that the tubing conduit and annulus are hydraulically isolated.

Front 20

tubing-retrievable safety valve (TRSV)

Back 20

A type of subsurface safety valve that is run and retrieved as part of the production tubing string. The TRSV body is integral part of the completion that enables the internal components to be configured to provide near fullbore access through the valve. An external control line is secured to the running string for connection to a surface-control system.

Front 21

thread protector

Back 21

A protective sleeve or cap generally made up on the threads of tubular goods during transport and storage. Thread protectors are available in metal, plastic, or a combination of both.

Front 22

tie-back packer

Back 22

A specially designed packer assembly used in conjunction with a tie-back liner. The tie-back packer can be integral to the original liner hanger, or if the tie-back is a remedial treatment, it can be a separate component set above the liner hanger.

Front 23

tubing head

Back 23

A wellhead component that supports the tubing hanger and provides a means of attaching the Christmas tree to the wellhead.

Front 24

turbulent flow

Back 24

A fluid-flow regime characterized by swirling or chaotic motion as the fluid moves along the pipe or conduit. The linear velocity of the fluid particles is similar regardless of position in the conduit, although particles close to the conduit walls have a lower velocity. This characteristic makes turbulent flow an efficient flow regime for the pickup and transport of solids. However, the potential for erosion may be significant, especially with abrasive fluids and a tortuous flow path.

Front 25

natural completion

Back 25

A completion system designed to utilize the natural flow capability of the reservoir.

Front 26

nipple down

Back 26

The process of disassembling well-control or pressure-control equipment on the wellhead. Depending on the configuration of the wellhead and casing strings, it may be necessary to nipple-down and nipple-up the blowout preventer (BOP) system as each casing string is run.

Front 27

nitrogen cushion

Back 27

A column of high-pressure nitrogen typically applied to a tubing string in preparation for drillstem testing or perforating operations in which the reservoir formation is to be opened to the tubing string. The nitrogen cushion allows a precise pressure differential to be applied before opening flow from the reservoir. Once flow begins, the nitrogen cushion pressure can be easily and safely bled down to flow formation fluids under a high degree of control.

Front 28

no go landing nipple

Back 28

A nipple that incorporates a reduced diameter internal profile that provides a positive indication of seating by preventing the tool or device to be set from passing through the nipple. In many completions, a no-go landing nipple is preferred for the deepest nipple location, providing a no-go barrier to protect against a tool string being run or dropped below the tubing string.

Front 29

naturally occurring radioactive materials (NORM)

Back 29

Materials typically found in certain types of barium or strontium scales that may be deposited in the wellbore or productiontubulars. Any attempt to remove and dispose of NORM materials should be performed according to the legislation and policies associated with such potentially hazardous materials.

Front 30

nipple up

Back 30

The process of assembling well-control or pressure-control equipment on the wellhead.

Front 31

nitrogen kickoff

Back 31

Another term for nitrogen lift, the use of nitrogen gas circulated into the production conduit to displace liquids and reduce the hydrostatic pressure created by the fluid column. Nitrogen lifting is a common technique used to initiate production on a well following workover or overbalanced completion. A coiled tubing string is generally used to apply the treatment, which involves running to depth while pumping high-pressure nitrogen gas. Once the kill-fluid column is unloaded and the well is capable of natural flow, the coiled tubing string is removed and the well is prepared for production.

Front 32

NODAL* analysis

Back 32

An analytical tool used in forecasting the performance of the various elements comprising the completion and productionsystem. NODAL* analysis is used to optimize the completion design to suit the reservoir deliverability, identify restrictions or limits present in the production system and identify any means of improving production efficiency. *NODAL (production system analysis) is a mark of Schlumberger.

Front 33

neutral point

Back 33

The point on a string of tubulars at which there are neither tension nor compression forces present. Below the neutral point, there will be compression forces that build toward the bottom of the wellbore. Above the neutral point, tensile forces build to a maximum applied at the hanger or as hook load.

Front 34

nipple-down

Back 34

The process of disassembling well-control or pressure-control equipment on the wellhead. Depending on the configuration of the wellhead and casing strings, it may be necessary to nipple-down and nipple-up the blowout preventer (BOP) system as each casing string is run.

Front 35

nitrogen lift

Back 35

The use of nitrogen gas circulated into the production conduit to displace liquids and reduce the hydrostatic pressure created by the fluid column. Nitrogen lifting is a common technique used to initiate production on a well following workover or overbalanced completion. A coiled tubing string is generally used to apply the treatment, which involves running to depth while pumping high-pressure nitrogen gas. Once the kill-fluid column is unloaded and the well is capable of natural flow, the coiled tubing string is removed and the well is prepared for production.

Front 36

no-go landing nipple

Back 36

A nipple that incorporates a reduced diameter internal profile that provides a positive indication of seating by preventing the tool or device to be set from passing through the nipple. In many completions, a no-go landing nipple is preferred for the deepest nipple location, providing a no-go barrier to protect against a tool string being run or dropped below the tubing string.

Front 37

nipple

Back 37

A completion component fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile. Landing nipples are included in most completions at predetermined intervals to enable the installation of flow-control devices, such as plugs and chokes. Three basic types of landing nipple are commonly used: no-go nipples, selective-landing nipples and ported or safety-valve nipples.

Front 38

nipple-up

Back 38

The process of assembling well-control or pressure-control equipment on the wellhead.

Front 39

nitrogen unit

Back 39

A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of unit are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high-pressure nitrogen gas.

Front 40

O ring

Back 40

A type of circular seal commonly found in downhole tools and a wide range of surface equipment applications. The specification of O-ring material depends on the conditions for which the seal is intended, such as system operating temperature and pressure. Various backup systems are used to support the O-ring seal in either dynamic or static sealing applications.

Front 41

openhole completion

Back 41

A well completion that has no casing or liner set across the reservoirformation, allowing the produced fluids to flow directly into the wellbore. This type of completion suffers the major disadvantage that the sandface is unsupported and may collapse. Also, without any casing or liner installed, selective treatments or remedial work within the reservoir section are more difficult.

Front 42

openhole test

Back 42

A drillstem test performed in an openhole section of the wellbore. The test once was a popular method of assessing the productivity of exploration wells without the need to run casing or liner across the reservoir interval. Openhole testing now is less common because of the risks and limits associated with fluid flow from an unsupported formation.

Front 43

orifice valve

Back 43

A type of valve, typically found on small-diameter pipework, that incorporates an orifice or flow-restriction device to control fluid flow.

Front 44

open flow potential

Back 44

The calculated maximum flow rate that a system may provide in the absence of restrictions. The term may be qualified as relating to a specific zone, such as a perforated interval or be used in referring to the production capability of the well.

Front 45

openhole gravel pack

Back 45

A type of sand-control completion in which the gravel pack screen is packed off in an openhole section with no casing or liner to support the producing formation. The openhole interval is often prepared by underreaming a section of reservoir below the last casing shoe. When the treatment is to be applied on an existing well, a section of casing may be milled out.

Front 46

opening bomb

Back 46

A device used in stage cementing to open the stage collar or diverting valve through which the second or subsequent cement stage is placed. The opening bomb is dropped down the casing string to land in a seat within the stage collar. Applying pump pressure then activates a sliding collar that opens access ports, enabling circulation across the upper casing interval.

Front 47

O-ring

Back 47

A type of circular seal commonly found in downhole tools and a wide range of surface equipment applications. The specification of O-ring material depends on the conditions for which the seal is intended, such as system operating temperature and pressure. Various backup systems are used to support the O-ring seal in either dynamic or static sealing applications.

Front 48

open-flow potential

Back 48

The calculated maximum flow rate that a system may provide in the absence of restrictions. The term may be qualified as relating to a specific zone, such as a perforated interval or be used in referring to the production capability of the well.

Front 49

openhole packer

Back 49

A type of packer designed for use in openhole applications such as drillstem testing. Openhole packers are typically configured with one large element that can be deformed easily to contact the uneven formation surface, yet retain strength and sufficient integrity to withstand the anticipated differential pressures.

Front 50

operating gas-lift valve (OGLV)

Back 50

The lowermost gas-lift valve in a gas-lift completion through which the lift gas is injected during normal production. During startup, the upper gas-lift valves open in sequence, from the top down, to enable the tubing fluids to be displaced. At predetermined pressures, each of the upper valves closes to eventually route all lift gas through the operating valve, which is placed at the optimal depth for the reservoir and completion conditions.

Front 51

oxygen scavenger

Back 51

A chemical agent used in some brines and completion fluids to reduce corrosion resulting from, or exacerbated by, dissolved oxygen. Oxygen scavengers capture the dissolved oxygen in a harmless chemical reaction that renders the oxygen unavailable for corrosive reactions. The use of oxygen scavengers is more critical in applications in which fluids are to be circulated in the wellbore. Additional oxygen may be dissolved during agitation at surface.

Front 52

unload

Back 52

To initiate flow from a reservoir by removing the column of kill fluid from the wellbore. Several methods of unloading the well are used, including circulation of lower density fluid, nitrogen lifting and swabbing. The method used will depend on thecompletion design, reservoir characteristics and local availability.

Front 53

upstream

Back 53

Pertaining to equipment, facilities or systems located in the wellbore or production train before the surface choke or Christmas tree.

Front 54

velocity string

Back 54

A small-diameter tubing string run inside the production tubing of a well as a remedial treatment to resolve liquid-loading problems. As the reservoir pressure in a gas well depletes, there may be insufficient velocity to transport all liquids from the wellbore. In time these liquids accumulate and impair production. Installing a velocity string reduces the flow area and increases the flow velocity to enable liquids to be carried from the wellbore. Velocity strings are commonly run using coiled tubing as a velocity string conduit. Safe live-well working and rapid mobilization enable coiled tubing velocity strings to provide a cost effective solution to liquid loading in gas wells.

Front 55

vertical lift

Back 55

The vertical distance between two points in a horizontal or deviated wellbore. Any calculations relating to wellbore pressure or downhole pump performance will be based on the vertical lift rather than the distance traveled through the wellbore.

Front 56

wait on cement

Back 56

To suspend operations while a cement slurry to develops sufficient compressive strength to allow drilling or other wellbore activity to continue. The WOC time is generally used to test the surface pressure-control equipment, such as the BOP stack. Attempting to drill out the float or guide shoe before the cement has developed sufficient bond strength may result in backing off a casing joint.

Front 57

water flood

Back 57

A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Potential problems associated with waterflood techniques include inefficient recovery due to variable permeability, or similar conditions affecting fluid transport within the reservoir, and early water breakthrough that may cause production and surface processing problems

Front 58

water-wet

Back 58

Pertaining to the adhesion of a liquid to the surface of a solid. In water-wet conditions, a thin film of water coats the surface of the formation matrix, a condition that is desirable for efficient oil transport. Treatments that change the wettability of the formation from water-wet to oil-wet can significantly impair productivity.

Front 59

wire wrapped screen

Back 59

A type of screen used in sand control applications to support the gravel pack. The profiled wire is wrapped and welded in place on a perforated liner. Screens are available in a range of sizes and specifications, including outside diameter, material type and the geometry and dimension of the screen slots. The space between each wire wrap must be small enough to retain the gravel placed behind the screen, yet minimize any restriction to production.

Front 60

water block

Back 60

A condition caused by an increase in water saturation in the near-wellbore area. Water block typically forms during the drilling phase of a well, when the near-wellbore area is exposed to a relatively high volume of filtrate from the drilling fluid. The increased presence of water causes fine clay crystals that may be present in the formation, such as illite, to swell and cause a reduction in permeability. Water-block treatments typically use surfactants to reduce the surface tension between the oil and water, helping to displace the water from the near-wellbore area.

Front 61

water wet

Back 61

Pertaining to the adhesion of a liquid to the surface of a solid. In water-wet conditions, a thin film of water coats the surface of the formation matrix, a condition that is desirable for efficient oil transport. Treatments that change the wettability of the formation from water-wet to oil-wet can significantly impair productivity.

Front 62

well stimulation

Back 62

A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

Front 63

wireline retrievable safety valve (WRSV)

Back 63

A type of safety valve in which the principal components can be run and retrieved by wireline or slickline. The valve assembly is landed in a ported nipple that is equipped with a control line connected to the surface control system. This configuration enables the safety valve to be easily retrieved for repair or maintenance, but the resulting internal bore of the WRSV must be relatively small.

Front 64

water coning

Back 64

The change in the oil-water contact profile as a result ofdrawdown pressures during production. Coning occurs in vertical or slightly deviated wells and is affected by the characteristics of the fluids involved and the ratio of horizontal to vertical permeability.

Front 65

waterdrive

Back 65

A reservoir-drive mechanism whereby the oil is driven through the reservoir by an active aquifer. As the reservoir depletes, the water moving in from the aquifer below displaces the oil until the aquifer energy is expended or the well eventually produces too much water to be viable.

Front 66

wellbore diagram

Back 66

A schematic diagram that identifies the main completion components installed in a wellbore. The information included in the wellbore diagram relates to the principal dimensions of the components and the depth at which the components are located. A current wellbore diagram should be available for any well intervention operation to enable engineers and equipment operators to select the most appropriate equipment and prepare operating procedures that are compatible with any downhole restrictions.

Front 67

wireline-retrievable safety valve (WRSV)

Back 67

A type of safety valve in which the principal components can be run and retrieved by wireline or slickline. The valve assembly is landed in a ported nipple that is equipped with a control line connected to the surface control system. This configuration enables the safety valve to be easily retrieved for repair or maintenance, but the resulting internal bore of the WRSV must be relatively small.

Front 68

water cushion

Back 68

A volume of water placed in a tubing string prior to conducting a drillstem test or opening a well to flow. The water cushion is designed to reduce and control the pressure drawdown applied to the reservoir when the downhole valve or tester valve is opened to initiate flow.

Front 69

wellhead

Back 69

The surface termination of a wellbore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow-control facilities in preparation for the production phase of the well.

Front 70

wire-wrapped screen

Back 70

A type of screen used in sand control applications to support the gravel pack. To form the screen, a profiled wire is wrapped and welded in place on a perforated liner. Screens are available in a range of sizes and specifications, including outside diameter, material type and the geometry and dimension of the screen slots. The space between each wire wrap must be small enough to retain the gravel placed behind the screen, yet minimize any restriction to production.

Front 71

water drive

Back 71

A reservoir-drive mechanism whereby the oil is driven through the reservoir by an active aquifer. As the reservoir depletes, the water moving in from the aquifer below displaces the oil until the aquifer energy is expended or the well eventually produces too much water to be viable.

Front 72

waterflooding

Back 72

A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Potential problems associated withwaterflood techniques include inefficient recovery due to variable permeability, or similar conditions affecting fluid transport within the reservoir, and early water breakthrough that may cause production and surface processing problems.

Front 73

wing valve

Back 73

A valve located on the side of a Christmas tree or temporary surface flow equipment, such as may be used for a drillstem test. Two wing valves are generally fitted to a Christmas tree. A flowing wing valve is used to control and isolate production, and the kill wing valve fitted on the opposite side of the Christmas tree is available for treatment or well-control purposes. The term wing valve typically is used when referring to the flowing wing.

Front 74

waterflood

Back 74

A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Potential problems associated with waterflood techniques include inefficient recovery due to variable permeability, or similar conditions affecting fluid transport within the reservoir, and early water breakthrough that may cause production and surface processing problems.