Drilling Flashcards
Reservoir pore fluid pressure that is not similar to normal saltwater gradient pressure. The term is usually associated with higher than normal pressure, increased complexity for the well designer and an increased risk of well control problems. Pressure gradients in excess of around 10 pounds per gallon equivalent fluid density (0.52 psi/foot of depth) are considered abnormal. Gradients below normal are commonly called subnormal
abnormal pressure
A valve usually used in well control operations to reduce the
pressure of a fluid from high pressure in the closed wellbore to
atmospheric pressure. It may be adjusted (opened or closed) to
closely control the pressure drop.
adjustable choke
A drilling technique whereby gases (typically compressed air or
nitrogen) are used to cool the drill bit and lift cuttings out of the
wellbore, instead of the more conventional use of liquids.
air drilling
A large valve used to control wellbore fluids. In this type of valve,
the sealing element resembles a large rubber doughnut that is
mechanically squeezed inward to seal on either pipe (drill collar,
drillpipe, casing, or tubing) or the openhole. The ability to seal
on a variety of pipe sizes is one advantage the annular blowout
preventer has over the ram blowout preventer. Most blowout pre-
venter (BOP) stacks contain at least one annular BOP at the top
of the BOP stack, and one or more ram-type preventers below.
While not considered as reliable in sealing over the openhole as
around tubulars, the elastomeric sealing doughnut is required by
API specifications to seal adequately over the openhole as part of
its certification process
annular blowout preventer
The speed at which drilling fluid or cement moves in the annulus.
It is important to monitor annular velocity to ensure that the hole
is being properly cleaned of cuttings, cavings and other debris
while avoiding erosion of the borehole wall. The annular velocity is
commonly expressed in units of feet per minute or, less commonly,
meters per minute. The term is distinct from volumetric flow.
annular velocity
A flow of formation gas in the annulus between a casing string
and the borehole wall. Annular gas flows occur when there is
insufficient hydrostatic pressure to restrain the gas. They can
occur in uncemented intervals and even in cemented sections if
the cement bond is poor. After cementing, as the cement begins to
harden, a gel-like structure forms that effectively supports the solid
material in the cement slurry. However, during this initial gelling
period, the cement has no appreciable strength. Hence, with the
solid (weighting) material now supported by the gel structure, the
effective density of the slurry that the reservoir experiences falls
rather suddenly to the density of the mix water of the cement,
which is usually fresh water, whose density is 8.34 lbm/gal, or a
gradient of 0.434 psi/ft of vertical column height. Various chemical
additives have been developed to reduce annular gas flow.
annular gas flow
The space between two concentric objects, such as between the
wellbore and casing or between casing and tubing, where fluid can
flow. Pipe may consist of drill collars, drillpipe, casing or tubing.
Annulus
A drill bit, usually polycrystalline diamond compact bit (PDC) type,
designed such that the individual cutting elements on the bit create
a net imbalance force. This imbalance force pushes the bit against
the side of the borehole, which in turn creates a stable rotating
condition that resists backwards whirling, wobbling and down-
hole vibration. Antiwhirl bits allow faster rates of penetration, yet
achieve longer bit life than more conventional bits, which are not
dynamically biased to run smoothly, are inherently unstable, are
vibration-prone and thus have shorter lives. No bit is whirl-proof,
however.
antiwhirl bit
any water-bearing formation encountered while drilling. Drillers of-
ten are concerned about aquifers and are required to take special
precautions in the design and execution of the well plan to protect
fresh water aquifers from contamination by wellbore fluids. Water
in aquifers can flow into the wellbore, contaminate drilling fluids
and cause well control problems.
Aquifer
The compass direction of a directional survey or of the wellbore
as planned or measured by a directional survey.
azimuth
The direction in which a deviated or horizontal well is drilled
relative to magnetic north.
azimuth
To unscrew drillstring components downhole. The drillstring, in-
cluding drillpipe and the bottomhole assembly, are coupled by
various threadforms known as connections, or tool joints. Often
when a drillstring becomes stuck it is necessary to “back off” the
string as deep as possible to recover as much of the string as
possible. To facilitate the fishing or recovery operation, the backoff
is usually accomplished by applying reverse torque and detonating
an explosive charge inside a selected threaded connection. The
force of the explosion enlarges the female (outer) thread enough
that the threaded connection unscrews instantly. A torqueless
backoff may be performed as well. In that case, tension is applied,
and the threads slide by each other without turning when the
explosive detonates. Backing off can also occur unintentionally.
back off/ break out
An average or baseline measure of gas entrained in circulating
mud. This baseline trend pertains to gas that is liberated downhole
while drilling through a uniform lithologic interval at a constant
rate of penetration. The gas is typically obtained from a suction
line above the gas trap located immediately upstream of the shale
shaker screens, where the gas evolves out of the mud. Oil-base
mud systems tend to produce higher background gas values than
do water-base muds. Deviations from the background gas trend
likely indicate changes in porosity or permeability, or changes in
drilling conditions; any of which merits further investigation. A drift
or gradual shift of the background gas trend toward higher values
may indicate a slow gas influx into the mud column, which can
eventually lead to a kick or blowout. When annotated on mud logs,
background gas is usually abbreviated as BGG.
background gas (BGG)
Another term for reverse circulation, the intentional pumping of
wellbore fluids down the annulus and back up through theÂ
drillpipe. (n. [drilling])
backwash
Referring to openhole or without casing,
barefoot
A tool run into the wellbore to retrieve junk from the bottom of the
hole.
Basket sub/junk basket
An enlarged pipe at the top of a casing string that serves as a
funnel to guide drilling tools into the top of a well. The bell nipple is
usually fitted with a side outlet to permit drilling fluids to flow back
to the surface mud treating equipment through another inclined
pipe called a flowline.
bell nipple
An integral bit and eccentric reamer used to simultaneously drill
and underream the hole.
bicenter bit
The tool used to crush or cut rock. Everything on a drilling rig
directly or indirectly assists the bit in crushing or cutting the rock.
The bit is on the bottom of the drillstring and must be changed
when it becomes excessively dull or stops making progress. Most
bits work by scraping or crushing the rock, or both, usually as part
of a rotational motion. Some bits, known as hammer bits, poundthe rock vertically in much the same fashion as a construction site
air hammer.
bit
A container, usually made of steel and fitted with a sturdy lock,
to store drill bits, especially higher cost PDC and diamond bits.
These bits are extremely costly but often small in size, so they are
prone to theft.
bit box
A special tool used by the rig crew to prevent the drill bit from
turning while the bit sub on top of it is tightened or loosened. Bits
have noncylindrical shapes, so the conventional wrenches used
by the rig crew to tighten cylindrical shapes like pipes do not fit
the bits properly. In addition, some bits, such as PDC bits, have a
wide range of unusual and asymmetric shapes or profiles. The bit
breaker must match the bit profile or the bit may be ruined before
ever being used.
bit breaker
The part of the bit that includes a hole or opening for drilling fluid
to exit. The hole is usually small (around 0.25 in. in diameter) and
the pressure of the fluid inside the bit is usually high, leading to a
high exit velocity through the nozzles that creates a high-velocity
jet below the nozzles. This high-velocity jet of fluid cleans both
the bit teeth and the bottom of the hole. The sizes of the nozzles
are usually measured in 1/32-in. increments (although some are
recorded in millimeters), are always reported in “thirty-seconds”
of size (i.e., fractional denominators are not reduced), and usually
range from 6/32 to 32/32.
bit nozzle/ jet nozzle
A historical record of how a bit performed in a particular wellbore.
The bit record includes such data as the depth the bit was put
into the well, the distance the bit drilled, the hours the bit was
being used “on bottom” or “rotating”, the mud type and weight,
the nozzle sizes, the weight placed on the bit, the rotating speed
and hydraulic flow information. The data are usually updated daily.
When the bit is pulled at the end of its use, the condition of the bit
and the reason it was pulled out of the hole are also recorded. Bit
records are often shared among operators and bit companies and
are one of many valuable sources of data from offset wells for well
design engineers.
bit record
The process of pulling the drillstring out of the wellbore for the
purpose of changing a worn or underperforming drill bit. Upon
reaching the surface, the bit is usually inspected and graded on
the basis of how worn the teeth are, whether it is still in gauge and
whether its components are still intact. On drilling reports, this trip
may be abbreviated as TFNB (trip for new bit).
bit trip
A thick, heavy steel component of a conventional ram blowout
preventer. In a normal pipe ram, the two blocks of steel that meet
in the center of the wellbore to seal the well have a hole (one-half
of the hole on each piece) through which the pipe fits. The blind
ram has no space for pipe and is instead blanked off in order to be
able to close over a well that does not contain a drillstring. It may
be loosely thought of as the sliding gate on a gate valve.
blind ram
A set of pulleys used to gain mechanical advantage in lifting or
dragging heavy objects. There are two large blocks on a drilling rig,
the crown block and the traveling block. Each has several sheaves
that are rigged with steel drilling cable or line such that the traveling
block may be raised (or lowered) by reeling in (or out) a spool of
drilling line on the drawworks.
block
An uncontrolled flow of reservoir fluids into the wellbore, and
sometimes catastrophically to the surface. A blowout may consist
of salt water, oil, gas or a mixture of these. Blowouts occur in
all types of exploration and production operations, not just during
drilling operations. If reservoir fluids flow into another formationand do not flow to the surface, the result is called an underground
blowout. If the well experiencing a blowout has significant open-
hole intervals, it is possible that the well will bridge over (or seal
itself with rock fragments from collapsing formations) downhole
and intervention efforts will be averted.
blowout
A large valve at the top of a well that may be closed if the drilling
crew loses control of formation fluids. By closing this valve (usually
operated remotely via hydraulic actuators), the drilling crew usu-
ally regains control of the reservoir, and procedures can then be
initiated to increase the mud density until it is possible to open the
BOP and retain pressure control of the formation. BOPs come in a
variety of styles, sizes and pressure ratings. Some can effectively
close over an open wellbore, some are designed to seal around
tubular components in the well (drillpipe, casing or tubing) and
others are fitted with hardened steel shearing surfaces that can
actually cut through drillpipe. Since BOPs are critically important
to the safety of the crew, the rig and the wellbore itself, BOPs are
inspected, tested and refurbished at regular intervals determined
by a combination of risk assessment, local practice, well type and
legal requirements. BOP tests vary from daily function testing on
critical wells to monthly or less frequent testing on wells thought
to have low probability of well control problems.
Blow out preventer
A set of two or more BOPs used to ensure pressure control of a
well. A typical stack might consist of one to six ram-type preventers
and, optionally, one or two annular-type preventers. A typical stack
configuration has the ram preventers on the bottom and the annu-
lar preventers at the top. The configuration of the stack preventers
is optimized to provide maximum pressure integrity, safety and
flexibility in the event of a well control incident. For example, in
a multiple ram configuration, one set of rams might be fitted to
close on 5-in. diameter drillpipe, another set configured for 4 1/2-in.
drillpipe, a third fitted with blind rams to close on the openhole
and a fourth fitted with a shear ram that can cut and hang-off the
drillpipe as a last resort. It is common to have an annular preventer
or two on the top of the stack since annulars can be closed over
a wide range of tubular sizes and the openhole, but are typically
not rated for pressures as high as ram preventers. The BOP stack
also includes various spools, adapters and piping outlets to permit
the circulation of wellbore fluids under pressure in the event of a
well control incident.
BOP stack
The wellbore itself, including the openhole or uncased portion of
the well. It may refer to the inside diameter of the wellbore
wall, the rock face that bounds the drilled hole.
Borehole/ Wellbore
The lower portion of the drillstring, consisting of (from the bottom
up in a vertical well) the bit, bit sub, a mud motor (in certain
cases), stabilizers, drill collar, heavy-weight drillpipe, jarring de-
vices (“jars”) and crossovers for various threadforms. The bot-
tomhole assembly must provide force for the bit to break the
rock (weight on bit), survive a hostile mechanical environment
and provide the driller with directional control of the well. Often-
times the assembly includes a mud motor, directional drilling and
measuring equipment, measurements-while-drilling tools, log-
ging-while-drilling tools and other specialized devices. A simple
BHA consisting of a bit, various crossovers, and drill collars may
be relatively inexpensive (less than $100,000 US in 1999), while
a complex one may cost ten or more times that amount.
Bottomhole assembly (BHA)
The temperature of the circulating fluid (air, mud, cement or water)
at the bottom of the wellbore after several hours of circulation.
This temperature is lower than the bottomhole static temperature.
Therefore, in extremely harsh environments, a component or fluid
that would not ordinarily be suitable under bottomhole static con-
ditions may be used with great care in circulating conditions. Simi-
larly, a high-temperature well may be cooled down in an attempt to
allow logging tools to function. The BHCT is also important in the
design of operations to cement casing because the setting time
for cement is temperature-dependent. The BHCT and bottomhole
static temperature (BHST) are important parameters when placing
large volumes of temperature-sensitive treatment fluids.
Bottomhole circulating temperature (BHCT)
The pressure, usually measured in pounds per square inch (psi),
at the bottom of the hole. This pressure may be calculated in a
static, fluid-filled wellbore with the equation: BHP = MW * Depth *
0.052
Bottomhole pressure (BHP)
The temperature of the undisturbed formation at the final depth
in a well. The formation cools during drilling and most of the
cooling dissipates after about 24 hours of static conditions, al-
though it is theoretically impossible for the temperature to return to
undisturbed conditions. This temperature is measured under static
conditions after sufficient time has elapsed to negate any effects
from circulating fluids. Tables, charts and computer routines are
used to predict BHST as functions of depth, geographic area
and various time functions. The BHST is generally higher than
the bottomhole circulating temperature, and can be an important
factor when using temperature-sensitive tools or treatments.
Bottomhole static temperature (BHST)
Pertaining to the mud and cuttings that are calculated or measured
to come from the bottom of the hole since the start of circulation.
Circulation may be initiated after a static period, such as a trip,
or from a given depth while drilling. This latter type is particularly
useful to mud loggers and others trying to discern the lithology
being drilled, so mud loggers or mud engineers often retrieve what
is referred to as a “bottoms-up sample” of the cuttings or the
drilling fluid.
bottoms up
A metal strip shaped like a hunting bow and attached to a tool or
to the outside of casing. They are used to keep
casing in the center of a wellbore or casing (“centralized”) prior to
and during a cement job.
Bow-spring centralizer
A female threadform (internally threaded) for tubular goods and
drillstring components.
box
(n) The mechanism on the drawworks that permits the driller to
control the speed and motion of the drilling line and the drillstring,
or the brake handle that the driller operates to control the brake
mechanism. (adj) To apply the brake to slow the motion of the
brake
To establish circulation of drilling fluids after a period of static
conditions. Circulation may resume after a short break, such as
taking a survey or making a mousehole connection, or after a
prolonged interruption, such as after a round trip. The operation
is of more concern to drillers and well planners with longer static
intervals, since immobile drilling fluid tends to become less fluid
and more gelatinous or semisolid with time.
Break circulation / mousehole connection
A clutching mechanism that permits the driller to apply high torque
to a connection using the power of the drawworks motor.
Breakout cathead
Large capacity self-locking wrenches used to grip drillstring com-
ponents and apply torque. The breakout tongs are the active tongs
during breakout operations. A similar set of tongs is tied off to
a deadline anchor during breakout operations to provide backup
to the connection, not unlike the way a plumber uses two pipe
wrenches in an opposing manner to tighten or loosen water pipes,
except that breakout tongs are much larger.
Breakout tongs
(n) The gangplank or stairway connecting a jackup rig to a fixed
platform. (vb) To intentionally or accidentally plug off pore spaces
or fluid paths in a rock formation, or to make a restriction in
a wellbore or annulus. A bridge may be partial or total, and is
usually caused by solids (drilled solids, cuttings, cavings or junk)
becoming lodged together in a narrow spot or geometry change
in the wellbore.
Bridge
Saline liquid usually used in completion operations and, increas-
ingly, when penetrating a pay zone. Brines are preferred be-
cause they have higher densities than fresh water but lack solid
particles that might damage producible formations. Classes of
brines include chloride brines (calcium and sodium), bromides and
formates.
Brine
To forcibly pump fluids into a formation, usually formation fluids
that have entered the wellbore during a well control event. Though
bullheading is intrinsically risky, it is performed if the formation
fluids are suspected to contain hydrogen sulfide gas to prevent the
toxic gas from reaching the surface. Bullheading is also performed
if normal circulation cannot occur, such as after a borehole col-
lapse. The primary risk in bullheading is that the drilling crew has
no control over where the fluid goes and the fluid being pumped
downhole usually enters the weakest formation. In addition, if only
shallow casing is cemented in the well, the bullheading operation
can cause wellbore fluids to broach around the casing shoe and
reach the surface. This broaching to the surface has the effect of
fluidizing and destabilizing the soil (or the subsea floor), and can
lead to the formation of a crater and loss of equipment and life.
Bullhead
An electromechanical device used to connect an electrical tool
string to a logging cable, electrical wireline or coiled tubing string
equipped with an electrical conductor. It provides attachments to
both the mechanical armor wires (which give logging cable its
tensile strength) and the outer mechanical housing of a logging
tool, usually by means of threads. This connection to the logging
tool results in a good electrical path from the electrical conductors
of the logging cable to the electrical contacts of the logging tool,
and shields this electrical path from contact with conductive fluids,
such as certain drilling muds. The basic requirements of most
cable heads include providing reliable electrical and mechanical
connectivity between the running string and tool string. Another
attribute of cable heads is that they serve as a “weak link,” so that
if a logging tool becomes irretrievably stuck in a well, the operator
may intentionally pull in excess of the breaking strength of the
logging cable head, causing the cable to pull out of the cable head
in a controlled fashion.
Cable head
A method of drilling whereby an impact tool or bit, suspended in
the well from a steel cable, is dropped repeatedly on the bottom
of the hole to crush the rock. The tool is usually fitted with some
sort of cuttings basket to trap the cuttings along the side of the
tool. After a few impacts on the bottom of the hole, the cable is
reeled in and the cuttings basket emptied, or a bailer is used to
remove cuttings from the well. The tool is reeled back to the bottom
of the hole and the process repeated. Due to the increasing time
required to retrieve and deploy the bit as the well is deepened,
the cable-tool method is limited to shallow depths. Though largelyobsolete, cable-tool operations are still used to drill holes for
explosive charge placement (such as for acquisition of surface
seismic data) and water wells.
Cable-tool drilling (basket sub)
A representation of the measured diameter of a borehole along
its depth. They are usually measured mechanically, with
only a few using sonic devices. The tools measure diameter at
a specific chord across the well. Since wellbores are usually
irregular (rugose), it is important to have a tool that measures
diameter at several different locations simultaneously. Such a tool
is called a multifinger caliper. Drilling engineers or rigsite person-
nel use caliper measurement as a qualitative indication of both
the condition of the wellbore and the degree to which the mud
system has maintained hole stability. Caliper data are integrated
to determine the volume of the openhole, which is then used in
planning cementing operations.
Caliper log
A test performed by the mudlogger or wellsite geologist, used
to calculate sample lag. The lag period can be measured as a
function of time or pump strokes. Acetylene is commonly used as
a tracer gas for this purpose. This gas is generated by calcium
carbide, a man-made product that reacts with water. Usually, a
small paper packet containing calcium carbide is inserted into the
drillstring when the kelly is unscrewed from the pipe to make a
connection, and the time is noted, along with the pump-stroke
count on the mud pump. Once the connection is made and drilling
resumes, the packet is pumped downhole with the drilling fluid.
Along the way, the drilling fluid breaks down the paper and reacts
with the calcium carbide. The resulting acetylene gas circulates
with the drilling fluid until it reaches the surface, where it is de-
tected at the gas trap, causing a rapid increase or spike in gas
readings. The time and pump-stroke count are again noted, and
the cuttings sample lag interval is calculated.
Carbide lag test
The portion of the wellbore that has had metal casing placed and
cemented to protect the openhole from fluids, pressures, wellbore
stability problems or a combination of these.
Cased hole
Large-diameter pipe lowered into an openhole and cemented in
place. The well designer must design casing to withstand a variety
of forces, such as collapse, burst, and tensile failure, as well as
chemically aggressive brines. Most casing joints are fabricated
with male threads on each end, and short-length casing couplings
with female threads are used to join the individual joints of casing
together, or joints of casing may be fabricated with male threads
on one end and female threads on the other. Casing is run to
protect fresh water formations, isolate a zone of lost returns or
isolate formations with significantly different pressure gradients.
The operation during which the casing is put into the wellbore is
commonly called “running pipe.” Casing is usually manufactured
from plain carbon steel that is heat-treated to varying streng
Casing
A mechanical device that keeps casing from contacting the well-
bore wall. A continuous 360-degree annular space around casing
allows cement to completely seal the casing to the borehole wall.
There are two distinct classes of centralizers. The older and more
common is a simple, low-cost bow-spring design. Since the bow
springs are slightly larger than the wellbore, they can provide com-
plete centralization in vertical or slightly deviated wells. However,
they do not support the weight of the casing very well in deviated
wellbores. The second type is a rigid blade design. This type is
rugged and works well even in deviated wellbores, but since the
centralizers are smaller than the wellbore, they will not provide
as good centralization as bow-spring type centralizers in vertical
wells. Rigid-blade casing centralizers are slightly more expensiveand can cause trouble downhole if the wellbore is not in excellent
condition.
Casing centralizer
The threaded collar used to connect two joints of casing. The
resulting connection must provide adequate mechanical strength
to enable the casing string to be run and cemented in place.
The casing collar must also provide sufficient hydraulic isolation
under the design conditions determined by internal and external
pressure conditions and fluid characteristics.
casing collar
A short length of pipe used to connect two joints of casing. It has internal threads (female threadform) machined
to match the external threads (male threadform) of the long joints
of casing. The two joints of casing are threaded into opposite ends
of the casing coupling.
Casing coupling
A system of identifying and categorizing the strength of casing
materials. Since most oilfield casing is of approximately the same
chemistry (typically steel), and differs only in the heat treatment
applied, the grading system provides for standardized strengths
of casing to be manufactured and used in wellbores. The first part
of the nomenclature, a letter, refers to the tensile strength. The
second part of the designation, a number, refers to the minimum
yield strength of the metal (after heat treatment) at 1000 psi [6895
KPa]. For example, the casing grade J-55 has minimum yield
strength of 55,000 psi [379,211 KPa]. The casing grade P-110
designates a higher strength pipe with minimum yield strength
of 110,000 psi [758,422 KPa]. The appropriate casing grade for
any application typically is based on pressure and corrosion re-
quirements. Since the well designer is concerned about the pipe
yielding under various loading conditions, the casing grade is the
number that is used in most calculations. High-strength casing
materials are more expensive, so a casing string may incorporate
two or more casing grades to optimize costs while maintaining
adequate mechanical performance over the length of the string.
It is also important to note that, in general, the higher the yield
strength, the more susceptible the casing is to sulfide stress
cracking (H2S-induced cracking). Therefore, if H2S is anticipated,
the well designer may not be able to use tubulars with strength as
high as he or she would like.
casing grade
The adapter between the first casing string and either the BOP
stack (during drilling) or the wellhead (after completion). This
adapter may be threaded or welded onto the casing, and may
have a flanged or clamped connection to match the BOP stack
or wellhead.
Casing head / casinghead
The location, or depth, at which drilling an interval of a particular
diameter hole ceases, so that casing of a given size can be run
and cemented. Establishing correct casing points is important in
the design of the drilling fluid program. The casing point may be a
predetermined depth, or it may be selected onsite by a pressure
hunt team, selected onsite according to geological observations
or dictated by problems in the openhole section. In many cases,
weak or underpressure zones must be protected by casing to
enable mud weight adjustments that control unstable formations
or overpressure zones deeper in the wellbore.
Casing point
The bottom of the casing string, including the cement around it, or
the equipment run at the bottom of the casing string.
Casing shoe (shoe)
An assembled length of steel pipe configured to suit a specific
wellbore.
casing string
A relatively thin cable used with other equipment to move small rig
and drillstring components and to provide tension on the tongs for
tightening or loosening threaded connections.
Cat line / catline
A clutched spool connected to the drawworks power system used
to tension chains, cables and softline rope.
Cathead
A long, rectangular platform about 3 ft [0.9 m] high, usually made
of steel and located perpendicular to the vee-door at the bottom
of the slide. This platform is used as a staging area for rig and
drillstring tools, components that are about to be picked up and
run, or components that have been run and are being laid down.
A catwalk is also the functionally similar staging area, especially
on offshore drilling rigs, that may not be a separate or raised
structure.
catwalk
A dug-out area, possibly lined with wood, cement or very large
diameter (6 ft [1.8 m]) thin-wall pipe, located below the rig. The
cellar serves as a cavity in which the casing spool and casinghead
reside. The depth of the cellar is such that the master valve of the
Christmas tree are easy to reach from ground level. On smaller
rigs, the cellar also serves as the place where the lower part of
the BOP stack resides, which reduces the rig height necessary
to clear the BOP stack on the top. Prior to setting surface casing,
the cellar also takes mud returns from the well, which are pumped
back to the surface mud equipment.
cellar
The material used to permanently seal annular spaces between
casing and borehole walls. It is also used to seal formations
to prevent loss of drilling fluid and for operations ranging from
setting kick-off plugs to plug and abandonment. The most common
type by far is API Oilwell Cement, known informally as Portland
cement. Generally speaking, oilfield cement is thinner and exhibits
far less strength than cement or concrete used for construction
due to the requirement that it be highly pumpable in relatively
narrow annulus over long distances. Various additives are used
to control density, setting time, strength and flow properties. Addi-
tionally, special additives are often used to reduce the occurrence
of annular gas flow. The cement slurry, commonly formed by mix-
ing Portland cement, water and assorted dry and liquid additives,
is pumped into place and allowed to solidify (typically for 12 to 24
hours) before additional drilling activity can resume. The cement
usually must reach a strength of 5000 psi [34,474 KPa] before
drilling or perforating. More advanced oilfield cements achieve
higher set-cement compressive strengths by blending a variety of
particle types and sizes with less water than conventional mixtures
of Portland cement, water and chemical additives.
cement
A representation of the integrity of the cement job, especially
whether the cement is adhering solidly to the outside of the casing.
The log is typically obtained from one of a variety of sonic-type
tools. The newer versions, called cement evaluation logs, along
with their processing software, can give detailed, 360-degree
representations of the integrity of the cement job, whereas older
versions may display a single line representing the integrated
integrity around the casing.
Cement bond log (cement evaluation log)
A device fitted to the top joint of a casing string to hold a cement
plug before it is pumped down the casing during the cementing
operation. In most operations, a bottom plug is launched before the
spacer or cement slurry. The top plug is released from the cement
head after the spacer fluid. Most cement heads can hold both the
top and bottom plugs. A manifold incorporated into the cement
head assembly allows connection of a fluid circulation line.
cement head
The colloquial term for the crew member in charge of a specialized
cementing crew and trucks.
Cementer (cementing engineer)
To prepare and pump cement into place in a wellbore. Cementing
operations may be undertaken to seal the annulus after a casing
string has been run, to seal a lost circulation zone, to set a plug
in an existing well from which to push off with directional tools
or to plug a well so that it may be abandoned. Before cementing
operations commence, engineers determine the volume of ce-
ment (commonly with the help of a caliper log) to be placed in
the wellbore and the physical properties of both the slurry and the
set cement needed, including density and viscosity. A cementing
crew uses special mixers and pumps to displace drilling fluids and
place cement in the wellbore.
cementing
A type of pipe wrench used for hand-tightening various threaded
connections around the rigsite. It consists of a handle, a set of
gripping die teeth, a length of flat chain and a hooking slot where
the chain may be adjusted to fit the pipe.
Chain tongs
A high-pressure pipe leading from an outlet on the BOP stack
to the backpressure choke and associated manifold. During
well-control operations, the fluid under pressure in the wellbore
flows out of the well through the choke line to the choke, reducing
the fluid pressure to atmospheric pressure. In floating offshore
operations, the choke and kill lines exit the subsea BOP stack and
then run along the outside of the drilling riser to the surface. The
volumetric and frictional effects of these long choke and kill lines
must be considered to control the well properly.q
choke line
A set of high-pressure valves and associated piping that usually
includes at least two adjustable chokes, arranged such that one
adjustable choke may be isolated and taken out of service for
repair and refurbishment while well flow is directed through the
other one.
choke manifold
The set of valves, spools and fittings connected to the top of a well
to direct and control the flow of formation fluids from the well.
christmas tree
To pump fluid through the whole active fluid system, including
the borehole and all the surface tanks that constitute the primary
system.
circulate
To pump the drilling fluid until a sample from the bottom of the hole
reaches the surface. This is commonly performed when drilling
has ceased so that the wellsite geologist may collect a cuttings
sample from the formation being drilled, or when the driller sus-
pects that a small amount of gas has entered the wellbore. Thus,
by circulating out, the gas bubble is eased out of the wellbore
safely.
circulate out
The loss of drilling fluid to a formation, usually caused when the
hydrostatic head pressure of the column of drilling fluid exceeds
the formation pressure. This loss of fluid may be loosely classified
as seepage losses, partial losses or catastrophic losses, each of
which is handled differently depending on the risk to the rig and
personnel and the economics of the drilling fluid and each possible
solution.
Circulation loss / lost circulation
The complete, circuitous path that the drilling fluid travels. Start-
ing at the main rig pumps, major components include sur-
face piping, the standpipe, the kelly hose (rotary), the kelly, the
drillpipe, drill collars, bit nozzles, the various annular geometries
of the openhole and casing strings, the bell nipple, the flow-
line, the mud-cleaning equipment, the mud tanks, the centrifugal
precharge pumps and, finally, the positive displacement main rig
pumps.
Circulation system
A long, continuous length of pipe wound on a spool. The pipe is
straightened prior to pushing into a wellbore and rewound to coil
the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled
tubing can range from 2,000 ft to 15,000 ft [610 to 4,570 m] or
greater length.
Coiled tubing (CT) / endless tubing
The use of coiled tubing with downhole mud motors to turn the
bit to deepen a wellbore. Coiled tubing drilling operations proceed
quickly compared to using a jointed pipe drilling rig because con-
nection time is eliminated during tripping. Coiled tubing drilling is
economical in several applications, such as drilling slimmer wells,
areas where a small rig footprint is essential, reentering wells and
drilling underbalanced.
Coiled tubing drilling
Tapered string
Combination string
The representative of the oil company or operator on a drilling
location. For land operations, the company man is responsible for
operational issues on the location, including the safety and effi-
ciency of the project. Even administrative managers are expected
to respond to the direction of the company man when they are on
the rigsite. Offshore, depending on the regulatory requirements,
there may be an offshore installation manager, who supervises
the company man on safety and vessel integrity issues, but not on
operational issues.
Company man / company reprsentative
The hardware used to optimize the production of hydrocarbons
from the well. This may range from nothing but a packer on tubing
above an openhole completion (“barefoot” completion), to a sys-
tem of mechanical filtering elements outside of perforated pipe, to
a fully automated measurement and control system that optimizes
reservoir economics without human intervention (an “intelligent”
completion).
completion
Having the same center, such as when the casing and the wellbore
have a common center point and, therefore, a uniform annular
dimension.
concentric
The casing string that is usually put into the well first, particularly
on land wells, to prevent the sides of the hole from caving into the
wellbore. This casing, sometimes called drive pipe, is generally a
short length and is sometimes driven into the ground. Conductor
pipe is run because the shallow section of most wells onshore is
drilled in unconsolidated sediment or soil rather than consolidated
strata typically encountered deeper. Offshore, the drive pipe or
structural casing may be installed prior to the conductor for similar
reasons.
conductor pipe
Any threaded or nonthreaded union or joint that connects two
tubular components.
connection
The act of adding a joint or stand of drillpipe to the top of the
drillstring, also described as “making a connection.”
connection
A brief influx of gas that is introduced into the drilling fluid when a
pipe connection is made. Before making a connection, the driller
stops the mud pumps, thereby allowing gas to enter the wellbore at
depth. Gas may also be drawn into the wellbore by minor swabbing
effects resulting from short movements of the drillstring that occur
during the connection. Connection gas usually occurs after one
lag interval following the connection. On a mud log, it will appear
as a short peak above background levels. This peak often appears
at 30-foot intervals, depending on the lengths of drillpipe being
connected as the well is drilled.
connection gas
Gas that is introduced into the drilling mud from a source oth-
er than the formation. Contamination gas normally evolves as a by-product of oil-base mud systems and those using volatile
additives such as diesel fuel or other lubricants.
Contamination gas
The depth in a drilling well at which the drilling contractor receives
a lump-sum payment for reaching a particular milestone. The con-
tract depth is specified in a legal agreement between the operator,
who pays for the well, and the drilling contractor, who owns and
operates the drilling rig. Contract depth may be the final or total
depth (TD) of the well, an intermediate point in the well or another
milestone, such as running well-logging tools to the bottom of the
hole. In the case of an intermediate contract depth, the work to
deepen the well would likely be done on a day rate basis, or a
“time and materials” contract
contract depth
To deepen the wellbore by way of collecting a cylindrical sample
of rock. A core bit is used to accomplish this, in conjunction with a
core barrel and core catcher. The bit is usually a drag bit fitted with
either PDC or natural diamond cutting structures, but the core bit
is unusual in that it has a hole in its center. This allows the bit to
drill around a central cylinder of rock, which is taken in through the
bit and into the core barrel. The core barrel itself may be thought of
as a special storage chamber for holding the rock core. The core
catcher serves to grip the bottom of the core and, as tension is
applied to the drillstring, the rock under the core breaks away from
the undrilled formation below it. The core catcher also retains the
core so that it does not fall out the bottom of the drillstring, which
is open in the middle at that point.
core
Antiquated term for a deviated wellbore, usually used to describe
a well deviated accidentally during the drilling process.
Crooked hole
The flow of fluid across the bottom of the bit after it exits the bit
nozzles, strikes the bottom or sides of the hole and turns upwards
to the annulus. Modern, well-designed bits maximize crossflow
using an asymmetric nozzle arrangement.
Crossflow
The fixed set of pulleys (called sheaves) located at the top of the
derrick or mast, over which the drilling line is threaded. The com-
panion blocks to these pulleys are the traveling blocks. By using
two sets of blocks in this fashion, great mechanical advantage is
gained, enabling the use of relatively small drilling line (3/4 to 1 1/2
in. diameter steel cable) to hoist loads many times heavier than
the cable could support as a single strand.
Crown block
The rubblized rock just below the tooth of a rock bit. Rock in this fails due to the high compressive stress placed on
it by the bit tooth (in the case of a roller-cone bit). The effective
creation of and removal of crushed zone rock is important to the
efficiency of the drill bit. If the rock is not broken and removed
efficiently, the result is akin to effectively drilling the hole twice.
crushed zone
A method for recovering wireline stuck in a wellbore. In this, the wireline is gripped securely with
a special tool and cut at the surface. The cut end is threaded
through a stand of drillpipe. While the pipe hangs in the well-
bore, the wireline is threaded through another stand of drillpipe,
which is screwed onto the stand in the wellbore. The process is
repeated until the stuck wireline is recovered. This technique, while
dangerous and time-consuming, is known to improve greatly the
chances of full recovery of the wireline and the tool at its end in
the shortest overall time compared with trying to grab the wireline
in the openhole with fishing tools.
Cut-and-thread fishing technique
Small pieces of rock that break away due to the action of the bit
teeth. They are screened out of the liquid mud system at the
shale shakers and are monitored for composition, size, shape,
color, texture, hydrocarbon content and other properties by the mud engineer, the mud logger and other on-site personnel. The
mud logger usually captures samples of cuttings for subsequent
analysis and archiving.
Cuttings
The daily cost to the operator of renting the drilling rig and the
associated costs of personnel and routine supplies. This cost may
or may not include fuel, and usually does not include capital goods,
such as casing and wellheads, or special services, such as logging
or cementing. In most of the world, the day rate represents roughly
half of the cost of the well. Similarly, the total daily cost to drill a
well (spread rate) is roughly double what the rig day-rate amount
is.
Day rate
A device that removes air or gases (methane, H2S, CO2 and
others) from drilling liquids. There are two generic types that work
by both expanding the size of the gas bubbles entrained in the
mud (by pulling a vacuum on the mud) and by increasing the
surface area available to the mud so that bubbles escape (through
the use of various cascading baffle plates). If the gas content in
the mud is high, a mud gas separator or “poor boy degasser” is
used, because it has a higher capacity than standard degassers
and routes the evolved gases away from the rig to a flaring area
complete with an ignition source.
Degasser
The structure used to support the crown blocks and the drillstring
of a drilling rig. They are usually pyramidal in shape, and offer
a good strength-to-weight ratio. If the derrick design does not
allow it to be moved easily in one piece, special ironworkers must
assemble them piece by piece, and in some cases disassemble
them if they are to be moved.
derrick
rig floor
derrick floor
One of the rig crew members who gets his name from the fact
that he works on a platform attached to the derrick or mast,
typically 85 ft [26 m] above the rig floor, during trips. On small
land drilling crews, the derrickman is second in rank to the driller.
Larger offshore crews may have an assistant driller between the
derrickman and the driller. In a typical trip out of the hole (TOH),
the derrickman wears a special safety harness that enables him
to lean out from the work platform (called the monkeyboard) to
reach the drillpipe in the center of the derrick or mast, throw
a line around the pipe and pull it back into its storage location
(the fingerboards) until it is time to run the pipe back into the
well. In terms of skill, physical exertion and perceived danger,
a derrickman has one of the most demanding jobs on the rig
crew. Some modern drilling rigs have automated pipe-handling
equipment such that the derrickman controls the machinery rather
than physically handling the pipe. In an emergency, the derrickman
can quickly reach the ground by an escape line often called the
Geronimo line.
Derrickman
A hydrocyclone device that removes large drill solids from the
whole mud system. The desander should be located downstream
of the shale shakers and degassers, but before the desilters or
mud cleaners. A volume of mud is pumped into the wide upper
section of the hydrocylone at an angle roughly tangent to its
circumference. As the mud flows around and gradually down the
inside of the cone shape, solids are separated from the liquid by
centrifugal forces. The solids continue around and down until they
exit the bottom of the hydrocyclone (along with small amounts of
liquid) and are discarded. The cleaner and lighter density liquid
mud travels up through a vortex in the center of the hydrocyclone,
exits through piping at the top of the hydrocyclone and is then rout-
ed to the mud tanks and the next mud-cleaning device, usually a
desilter. Various size desander and desilter cones are functionally identical, with the size of the cone determining the size of particles
the device removes from the mud system.
Desander
A hydrocyclone much like a desander except that its design incor-
porates a greater number of smaller cones. As with the desander,
its purpose is to remove unwanted solids from the mud system.
The smaller cones allow the desilter to efficiently remove smaller
diameter drill solids than a desander does. For that reason, the
desilter is located downstream from the desander in the surface
mud system.
Desilter
A wellbore that is not vertical. The term usually indicates a wellbore
intentionally drilled away from vertical.
Deviated hole
survey
Deviation survey
A tool for drilling rock that works by scraping industrial grade
diamonds against the bottom of the hole. The diamonds are em-
bedded into the metal structure (usually a sintered or powdered
carbide base matrix) during the manufacture of the bit. The bit
designer has virtually unlimited combinations of bit shape, the
placement of hydraulic jetting ports, the amount of diamonds and
the size of the diamonds used (usually expressed as diamonds
per carat). In general, a diamond bit that drills faster has a shorter
lifetime. Similarly, a bit designed for extremely long life will typically
drill at a slower rate. If a bit has a relatively high number of
diamonds compared with other bits, it is said to be “heavy-set”
and has higher durability. A “light-set” bit, on the other hand, drills
more aggressively, but wears out faster because fewer diamonds
do the work.
diamond bit
- In general, a measurement of fluid force per unit area (measured
in units such as pounds per square in.) subtracted from a higher
measurement of fluid force per unit area. This comparison could
be made between pressures outside and inside a pipe, a pressure
vessel, before and after an obstruction in a flow path, or simply
between two points along any fluid path, such as two points along
the inside of a pipe or across a packer.
Differential pressure
- The change in force per unit area measured before and after
drilling fluid passes through small-diameter bit nozzles.
Differential pressure
- The change in force per unit area measured across vari-
ous downhole tools such as measurements-while-drilling (MWD)
tools, downhole turbines and mud motors.
- The change in force per unit area between the reservoir pore
pressure and the wellbore fluid pressure. If this measurement
becomes negative in value (that is, the reservoir pressure exceeds
the wellbore fluid pressure), then a flow of reservoir fluids into the
wellbore can result.
Differential pressure
A condition whereby the drillstring cannot be moved (rotated or
reciprocated) along the axis of the wellbore.It
typically occurs when high-contact forces caused by low reservoir
pressures, high wellbore pressures, or both, are exerted over a
sufficiently large area of the drillstring. Differential sticking is, for
most drilling organizations, the greatest drilling problem worldwide
in terms of time and financial cost. It is important to note that
the sticking force is a product of the differential pressure between
the wellbore and the reservoir and the area that the differential
pressure is acting upon. This means that a relatively low differential
pressure (delta p) applied over a large working area can be just
as effective in sticking the pipe as can a high differential pressure
applied over a small area.
Differential sticking / differential pressure sticking / wall sticking
An individual trained in the science and art of intentionally drilling
a well along a predetermined path in three-dimensional space,
usually involving deviating the well from vertical and directing it
in a specific compass direction or heading. The directional driller
considers such parameters as rotary speed, weight on bit, control
drilling and when to stop drilling and take surveys of the wellpath,
and works closely with the toolpusher.
directional driller
The intentional deviation of a wellbore from the path it would
naturally take. This is accomplished through the use of whip-
stocks, bottomhole assembly (BHA) configurations, instruments
to measure the path of the wellbore in three-dimensional space,
data links to communicate measurements taken downhole to the
surface, mud motors and special BHA components and drill bits,
including rotary steerable systems, and drill bits. The directional
driller also exploits drilling parameters such as weight on bit and
rotary speed to deflect the bit away from the axis of the existing
wellbore. In some cases, such as drilling steeply dipping forma-
tions or unpredictable deviation in conventional drilling operations,
directional-drilling techniques may be employed to ensure that the
hole is drilled vertically. While many techniques can accomplish
this, the general concept is simple: point the bit in the direction that
one wants to drill. The most common way is through the use of a
bend near the bit in a downhole steerable mud motor. The bend
points the bit in a direction different from the axis of the wellbore
when the entire drillstring is not rotating. By pumping mud through
the mud motor, the bit turns while the drillstring does not rotate,
allowing the bit to drill in the direction it points. When a particular
wellbore direction is achieved, that direction may be maintained
by rotating the entire drillstring (including the bent section) so that
the bit does not drill in a single direction off the wellbore axis,
but instead sweeps around and its net direction coincides with
the existing wellbore. Rotary steerable tools allow steering while
rotating, usually with higher rates of penetration and ultimately
smoother boreholes.
directional drilling
is common in shale reservoirs because it allows
drillers to place the borehole in contact with the most productive
reservoir rock.
Directional drilling
A wellbore that requires the use of special tools or techniques to
ensure that the wellbore path hits a particular subsurface target,
typically located away from (as opposed to directly under) the
surface location of the well.
directional well
Directional survey survey
Directional survey survey
- The shortest distance from the surface location of a well to the
vertical projection of the bottom of the well (or other point in the
well) to the Earth’s surface. Horizontal wells often have total dis-
placements of 1000 ft [305 m] or more from the surface location,
and the world record exceeds 10 km [6.2 miles] of displacement
displacement
- The act of removing one fluid (usually liquid) from a wellbore
and replacing it with another. This is accomplished by pumping
a spacer fluid that is benign to both the first and second fluid,
followed by the new fluid, down the drillstring and out the bottom
of the drillstring or bit. While the spacer and second fluid are
pumped into the top of the wellbore, the first fluid is forced out of
the annulus between the drillstring and the wellbore or casing. In
some cases, this general procedure may be reversed by pumping
in the top of the annulus and taking fluid back from the drillstring.
Since this is the reverse of the normal circulation path, this is
referred to as “reversing out” or “reverse circulation.”
displacement
- The act of forcing a cement slurry that has been pumped into
a casing string or drillstring to exit the bottom of the casing or
drillstring by pumping another fluid behind it. Cement displace-
ment is similar to definition 5 above, with the noted exception that
the cement slurry would not normally be pumped out the top of
the annulus, but would instead be placed in a particular location
in the annulus. This location might be the entire annulus on a
short casing string, or filling only a bottom portion of the casing
on longer casing strings.
displacement
The fluid, usually drilling mud, used to force a cement slurry out
of the casing string and into the annulus.
Displacement fluid
The steel-sided room adjacent to the rig floor, usually having an
access door close to the driller’s controls. This general-purpose
shelter is a combination tool shed, office, communications center,
coffee room, lunchroom and general meeting place for the driller
and his crew. It is at the same elevation as the rig floor, usually
cantilevered out from the main substructure supporting the rig.
dog house
A particularly crooked place in a wellbore where the trajectory of
the wellbore in three-dimensional space changes rapidly. While a
dogleg is sometimes created intentionally by directional drillers,
the term more commonly refers to a section of the hole that
changes direction faster than anticipated or desired, usually with
harmful side effects. In surveying wellbore trajectories, a stan-
dard calculation of dogleg severity is made, usually expressed
in two-dimensional degrees per 100 feet [degrees per 30 m] of
wellbore length.
dog leg
There are several difficulties associated with doglegs. First, the
wellbore is not located in the planned path. Second is the possi-
bility that a planned casing string may no longer easily fit through
the curved section. Third, repeated abrasion by the drillstring in
a particular location of the dogleg results in a worn spot called a
keyseat, in which the bottomhole assembly components may be-
come stuck as they are pulled through the section. Fourth, casing
successfully cemented through the dogleg may wear unusually
quickly due to higher contact forces between the drillstring and
the inner diameter (ID) of the casing through the dogleg. Fifth,
a relatively stiff bottomhole assembly may not easily fit through
the dogleg section drilled with a relatively limber BHA. Sixth,
excessive doglegs increase the overall friction to the drillstring, in-
creasing the likelihood of getting stuck or not reaching the planned
total depth. Usually these problems are manageable. If the dogleg
impairs the well, remedial action can be taken, such as reaming or
underreaming through the dogleg, or even sidetracking in extreme
situations
There are several difficulties associated with doglegs. First, the
wellbore is not located in the planned path. Second is the possi-
bility that a planned casing string may no longer easily fit through
the curved section. Third, repeated abrasion by the drillstring in
a particular location of the dogleg results in a worn spot called a
keyseat, in which the bottomhole assembly components may be-
come stuck as they are pulled through the section. Fourth, casing
successfully cemented through the dogleg may wear unusually
quickly due to higher contact forces between the drillstring and
the inner diameter (ID) of the casing through the dogleg. Fifth,
a relatively stiff bottomhole assembly may not easily fit through
the dogleg section drilled with a relatively limber BHA. Sixth,
excessive doglegs increase the overall friction to the drillstring, in-
creasing the likelihood of getting stuck or not reaching the planned
total depth. Usually these problems are manageable. If the dogleg
impairs the well, remedial action can be taken, such as reaming or
underreaming through the dogleg, or even sidetracking in extreme
situations
a specially formulated blend of lubricating grease and
fine metallic particles that prevents thread galling (a particular form
of metal-to-metal damage) and seals the roots or void spaces of
threads. The American Petroleum Institute (API) specifies proper-
ties of pipe dope, including its coefficient of friction. The rig crew
applies copious amounts of pipe dope to the drillpipe tool joints
every time a connection is made
dope or Pipe dope,
A drilling tool that uses polycrystalline diamond compact (PDC)
cutters to shear rock with a continuous scraping motion. These
cutters are synthetic diamond disks about 1/8-in. thick and about
1/2 to 1 in. in diameter. PDC bits are effective at drilling shale
formations, especially when used in combination with oil-base
muds.
Drag bit / fixed-cutter bit
The machine on the rig consisting of a large-diameter steel spool,
brakes, a power source and assorted auxiliary devices. The pri-
mary function of the drawworks is to reel out and reel in the drilling
line, a large diameter wire rope, in a controlled fashion. The drilling
line is reeled over the crown block and traveling block to gain
mechanical advantage in a “block and tackle” or “pulley” fashion.
This reeling out and in of the drilling line causes the traveling block,
and whatever may be hanging underneath it, to be lowered into
or raised out of the wellbore. The reeling out of the drilling line is
powered by gravity and reeling in by an electric motor or diesel
engine.
Drawworks
A term to describe the inclination from vertical of a wellbore.
Drift
- To guarantee the inside diameter of a pipe or other cylindrical
tool by pulling a cylinder or pipe (often called a rabbit) of known
outside diameter through it. The drift diameter is the inside diam-
eter (ID) that the pipe manufacturer guarantees per specifications.
Note that the nominal inside diameter is not the same as the
drift diameter but is always slightly larger. The drift diameter is
used by the well planner to determine what size tools or casing
strings can later be run through the casing, whereas the nominal
inside diameter is used for fluid volume calculations such as mud
circulating times and cement slurry placement calculations
drift
- To pass a gauge through casing, tubulars and completion com-
ponents to ensure minimum-diameter specifications are within
tolerance, as described in definition 2. This task is also performed
to ensure that there is no junk, dried cement, dirt, rocks or other
debris inside the pipe
drift
A component of a drillstring that provides weight on bit for drilling.
They are thick-walled tubular pieces machined from solid
bars of steel, usually plain carbon steel but sometimes of nonmag-
netic nickel-copper alloy or other nonmagnetic premium alloys.
The bars of steel are drilled from end to end to provide a passage
to pumping drilling fluids through the collars. The outside diameter
of the steel bars may be machined slightly to ensure roundness,
and in some cases may be machined with helical grooves (“spiral
collars”). Last, threaded connections, male on one end and female
on the other, are cut so multiple collars can be screwed together
along with other downhole tools to make a bottomhole assembly
(BHA). Gravity acts on the large mass of the collars to provide the
downward force needed for the bits to efficiently break rock. To
accurately control the amount of force applied to the bit, the driller
carefully monitors the surface weight measured while the bit is just
off the bottom of the wellbore. Next, the drillstring (and the drill
bit), is slowly and carefully lowered until it touches bottom. After
that point, as the driller continues to lower the top of the drillstring,
more and more weight is applied to the bit, and correspondingly
less weight is measured as hanging at the surface. If the surface
measurement shows 20,000 pounds [9080 kg] less weight than
with the bit off bottom, then there should be 20,000 pounds force
on the bit (in a vertical hole). Downhole MWD sensors measure
weight-on-bit more accurately and transmit the data to the surface.
drill collar
The supervisor of the rig crew. The driller is responsible for the ef-
ficient operation of the rigsite as well as the safety of the crew and
typically has many years of rigsite experience. Most drillers have
worked their way up from other rigsite jobs. While the driller must
know how to perform each of the jobs on the rig, his or her role is
to supervise the work and control the major rig systems. The driller
operates the pumps, drawworks, and rotary table via the drillers
console-a control room of gauges, control levers, rheostats, and
other pneumatic, hydraulic and electronic instrumentation. The
driller also operates the drawworks brake using a long-handled lever. Hence, the driller is sometimes referred to as the person
who is “on the brake.”
driller
A sudden increase in the rate of penetration during drilling.
When this increase is significant (two or more times the normal
speed, depending on local conditions), it may indicate a formation
change, a change in the pore pressure of the formation fluids, or
both. It is commonly interpreted as an indication of the bit drilling
sand (high-speed drilling) rather than shale (low-speed drilling).
The fast-drilling formation may or may not contain high-pressure
fluids. Therefore, the driller commonly stops drilling and performs
a flow check to determine if the formation is flowing. If the well is
flowing, or if the results are uncertain, the driller may close the
blowout preventers or circulate bottoms-up. Depending on the bit
being used and the formations being drilled, a formation, even if
sand, may sometimes drill slower rather than faster. This slowing
of drilling progress, while technically also a drilling break, is usually
referred to as a “reverse drilling break”, or simply “reverse break.”
drilling break
The company that owns and operates a drilling rig. The drilling
contractor usually charges a fixed daily rate for its hardware (the
rig) and software (the people), plus certain extraordinary expens-
es. Under this arrangement, the cost of the well is largely a function
of the time it takes to drill and complete the well. The other primary
contracting methods are footage rates (where the contractor re-
ceives an agreed upon amount per foot of hole drilled), or turnkey
operations, where the contractor may assume substantial risk of
the operations and receives a lump sum payment upon supplying
a well of a given specification to the operator.
drilling contractor
Personnel who operate the drilling rig. The crew typically consists
of roustabouts, roughnecks, floor hands, lead tong operators, mo-
tormen, derrickmen, assistant drillers, and the driller. Since drilling
rigs operate around the clock, there are at least two crews (twelve
hour work shifts called tours, more common when operating off-
shore), or three crews (eight hour tours, more common onshore).
In addition, drilling contractors must be able to supply relief crews
from time to time when crew members are unavailable. Though
less common now than in years past, the drilling contractor may
opt to hire only a driller, and the driller in turn is responsible for
hiring everyone reporting to him.
drilling crew
drilling companyman
Drilling foreman
The engineering plan for constructing the wellbore. The plan in-
cludes well geometries, casing programs, mud considerations,
well control concerns, initial bit selections, offset well information,
pore pressure estimations, economics and special procedures
that may be needed during the course of the well. Although drilling
procedures are carefully developed, they are subject to change if
drilling conditions dictate
Drilling procedure / drilling program
The speed at which the drill bit can break the rock under it and
thus deepen the wellbore. This speed is usually
Drilling rate / penetration rate / rate of penetration
A large-diameter pipe that connects the subsea BOP stack to a
floating surface rig to take mud returns to the surface. Without the
riser, the mud would simply spill out of the top of the stack onto
the seafloor. The riser might be loosely considered a temporary
extension of the wellbore to the surface.
Drilling riser / marine drilling riser
Tubular steel conduit fitted with special threaded ends called tool
joints. The drillpipe connects the rig surface equipment with the
bottomhole assembly and the bit, both to pump drilling fluid to
the bit and to be able to raise, lower and rotate the bottomhole
assembly and bit.
Drillpipe
A maritime vessel modified to include a drilling rig and special
station-keeping equipment. The vessel is typically capable of op-
erating in deep water. A drillship must stay relatively stationary on
location in the water for extended periods of time. This positioning
may be accomplished with multiple anchors, dynamic propulsion
(thrusters) or a combination of these. Drillships typically carry
larger payloads than semisubmersible drilling vessels, but their
motion characteristics are usually inferior.
Drillship
The combination of the drillpipe, the bottomhole assembly and
any other tools used to make the drill bit turn at the bottom of the
wellbore.
Drillstring
A wellbore that has not encountered hydrocarbons in economi-
cally producible quantities. Most wells contain salt water in some
zones. In addition, the wellbore usually encounters small amounts
of crude oil and natural gas. Whether the well is a “duster” depends
on many factors of the economic equation, including proximity to
transport and processing infrastructures, local market conditions,
expected completion costs, tax and investment recovery condi-
tions of the jurisdiction and projected oil and gas prices during the
productive life of the well.
Dry hole
Slang term for dry hole
Duster
The stationing of a vessel, especially a drillship or semisub-
mersible drilling rig, at a specific location in the sea by the use
of computer-controlled propulsion units called thrusters. Though
drilling vessels have varying sea and weather state design con-
ditions, most remain relatively stable even under high wind, wave
and current loading conditions. Inability to maintain stationkeep-
ing, whether due to excessive natural forces or failure of one or
more electromechanical systems, leads to a “drive off” condition
that requires emergency procedures to disconnect the riser from
the subsea BOP stack, or worse, drop the riser from the vessel
altogether.
Dynamic positioning
The term used to describe how off-center a pipe is within another
pipe or the openhole. It is usually expressed as a percentage. A
pipe would be considered to be fully (100%) eccentric if it were
lying against the inside diameter of the enclosing pipe or hole.
A pipe would be said to be concentric (0% eccentric) if it were
perfectly centered in the outer pipe or hole. Eccentricity becomes
important to the well designer in estimating casing wear, wear and
tear on the drillstring, and the removal of cuttings from the low
side of an inclined hole. In the latter case, if the drillpipe lies on
the low side of the hole (100% eccentric), the eccentricity results
in low-velocity fluid flow on the low side. Gravity pulls cuttings to
the low side of the hole, building a bed of small rock chips on
the low side of the hole known as a cuttings bed. This cuttings
bed becomes difficult to clean out of the annulus and can lead to
significant problems for the drilling operation if the pipe becomes
stuck in the cuttings bed.
Eccentricity
An electric motor that acts as a brake. Braking is accomplished
by reversing the electric fields on the motor, effectively turning
it into a generator. The usage of the generated power, either
in useful applications or dissipation as heat, restrains the mo-
tor-turned-generator and provides a braking action.
Electrodynamic brake
A hinged mechanism that may be closed around drillpipe or other
drillstring components to facilitate lowering them into the wellbore
or lifting them out of the wellbore. In the closed position, the
elevator arms are latched together to form a load-bearing ring
around the component. A shoulder or taper on the component to
be lifted is larger in size than the inside diameter of the closed elevator. In the open position, the device splits roughly into two
halves and may be swung away from the drillstring component.
elevator
The process whereby steel components become less resistant to
breakage and generally much weaker in tensile strength. While
embrittlement has many causes, in the oil field it is usually the
result of exposure to gaseous or liquid hydrogen sulfide [H2S]. On
a molecular level, hydrogen ions work their way between the grain
boundaries of the steel, where hydrogen ions recombine into mol-
ecular hydrogen [H2], taking up more space and weakening the
bonds between the grains. The formation of molecular hydrogen
can cause sudden metal failure due to cracking when the metal is
subjected to tensile stress.
embrittlement
coiled tubing
Endless tubing
The wearing away of material, usually rock or steel, by the contin-
uous abrasive action of a solids-laden slurry. For erosion to occur
usually requires a high fluid velocity, on the order of hundreds of
feet per second, and some solids content, especially sand. Erosion
may also occur in gas streams, again assuming the presence
of sand particles. It is usually difficult to erode the wellbore wall
significantly with drilling mud alone due to its relatively low velocity
and high viscosity. There is also a dramatic “self-limiting” effect
because even slight enlargement of the original gauge wellbore
dramatically decreases fluid velocities.
Erode / erosion
A steel cable attached to the rig derrick or mast near the work
platform for the derrickman. This cable is anchored at surface level
(on a vessel or the Earth) away from the mast in a loose catenary
profile, and fitted with a handle and hand brake that is stored
at the top. The escape line provides a rapid escape path for the
derrickman should well conditions or massive mechanical failure
warrant. In such a case the derrickman would disconnect his safety
belt from the rig, rehook it over the escape line if time permitted,
firmly grip the tee-bar handle and ride the trolley down the cable
while holding on to the handle with his hands.
Escape line / Geronimo line
The speed the drilling fluid attains when accelerated through bit
nozzles. This is typically in the low-hundreds of feet
per second. It has been reported that in certain shaly formations,
an impingement velocity on the order of 250 feet per second is
required to effectively remove newly created rock chips from the
bottom of the hole. This impingement velocity is not, however, the
same as the exit velocity, since the high-energy fluid jet loses ve-
locity through viscous losses and conversions from kinetic energy
to forms of potential energy occur once the fluid leaves the bit.
For this reason, the well designer generally seeks to maximize the
fluid velocity (or other measure of jet energy) to achieve maximum
cleaning at the bottom of the hole.
Exit velocity
The working platform approximately halfway up the derrick or mast
in which the derrickman stores drillpipe and drill collars in an
orderly fashion during trips out of the hole. The entire platform con-
sists of a small section from which the derrickman works (called
the monkeyboard), and several steel fingers with slots between
them that keep the tops of the drillpipe in place.
Fingerboard
Anything left in a wellbore. It does not matter whether the fish
consists of junk metal, a hand tool, a length of drillpipe or drill
collars, or an expensive MWD and directional drilling package.
Once the component is lost, it is properly referred to as simply “the
fish.” Typically, anything put into the hole is accurately measured
and sketched, so that appropriate fishing tools can be selected if
the item must be fished out of the hole
Fish
To attempt to retrieve a _________ from a wellbore. Where available,
specially skilled individuals, aptly called fishermen, are called onto
location to direct and assist with the fishing operations. Depending
on the type of fish, the manner in which it was lost, regulatory
requirements (for example a fish that includes a nuclear source,
such as certain well logging tools), and the value of the fish if
recovered, fishing operations may be immediately successful or
may be attempted unsuccessfully for several days or even weeks
fish
A general term for special mechanical devices used to aid the
recovery of equipment lost downhole. These devices generally fall
into four classes: diagnostic, inside grappling, outside grappling,
and force intensifiers or jars. Diagnostic devices may range from a
simple impression block made in a soft metal, usually lead, that is
dropped rapidly onto the top of the fish so that upon inspection at
the surface, the fisherman may be able to custom design a tool to
facilitate attachment to and removal of the fish. Other diagnostic
tools may include electronic instruments and even downhole sonic
or visual-bandwidth cameras. Inside grappling devices, usually
called spears, generally have a tapered and threaded profile,
enabling the fisherman to first guide the tool into the top of the
fish, and then thread the fishing tool into the top of the fish so that
recovery may be attempted. Outside grappling devices, usually
called overshots, are fitted with threads or another shape that
“swallows” the fish and does not release it as it is pulled out of
the hole. Overshots are also fitted with a crude drilling surface at
the bottom, so that the overshot may be lightly drilled over the
fish, sometimes to remove rock or metallic junk that may be part of
the sticking mechanism. Jars are mechanical downhole hammers,
which enable the fisherman to deliver high-impact loads to the fish,
far in excess of what could be applied in a quasi-static pull from
the surface.
Fishing tool
drag bit
Fixed-cutter bit
A check valve that has a spring-loaded plate that
may be pumped through, generally in the downhole direction, but
closes if the fluid attempts to flow back through the drillstring to
the surface. This reverse flow might be encountered either due to
a U-tube effect when the bulk density of the mud in the annulus is
higher than that inside the drillpipe, or a well control event.
Flapper valve
A full-sized length of casing placed at the bottom of the casing
string that is usually left full of cement on the inside to ensure
that good cement remains on the outside of the bottom of the
casing. If cement were not left inside the casing in this manner, the
risk of overdisplacing the cement (due to improper casing volume
calculations, displacement mud volume measurements, or both)
would be significantly higher. Hence, the well designer plans on a
safety margin of cement left inside the casing to guarantee that the
fluid left outside the casing is good-quality cement. A float collar
is placed at the top of the float joint and a float shoe placed at the
bottom to prevent reverse flow of cement back into the casing after
placement. There can be one, two or three joints of casing used
for this purpose.
Float joint / shoe joint / shoe track
The large-diameter metal pipe that connects the bell nipple under
the rotary table to the possum belly at the mud tanks. The flowline
is simply an inclined, gravity-flow conduit to direct mud coming
out the top of the wellbore to the mud surface-treating equipment.
When drilling certain highly reactive clays, called “gumbo,” the
flowline may become plugged and require considerable effort by
the rig crew to keep it open and flowing. In addition, the flowline
is usually fitted with a crude paddle-type flow-measuring device
commonly called a “flow show” that may give the driller the first
indication that the well is flowing.
Flow line / mud return line
Alteration of the far-field or virgin characteristics of a producing
formation, usually by exposure to drilling fluids. The water or solid
particles in the drilling fluids, or both, tend to decrease the pore
volume and effective permeability of the producible formation in
the near-wellbore region. At least two mechanisms are at work.
First, solid particles from the drilling fluid physically plug or bridge
across flowpaths in the porous formation. Second, when water
contacts certain clay minerals in the formation, the clay typically
swells, increasing in volume and decreasing the pore volume.
Third, chemical reactions between the drilling fluid and the for-
mation rock and fluids can precipitate solids or semisolids that
plug pore spaces. One approach to minimize formation damage
is to use drill-in or completion fluids that are specially formulated
to avoid damage to the formation when drilling pay zones, rather
than ordinary drilling fluids.
Formation damage
Logging while drilling
Formation evaluation while drilling
