C HAPTER
3
3-1
D ETECTION
OF K ICKS
I
n order to detect a kick in its earliest
stages, we must be aware of the indicators
that can warn us that the well is flowing.
If one or more of these warning signs is
Minimizing the observed, it should be assumed that the well
could be flowing. The correct action at this
amount of influx point is to check for flow. If the well is flowing,
but we are not pumping, that is a sure sign
significantly increases that a kick is in progress. However, in certain
areas a ballooning effect is common. That is,
the well will flow for a considerable length of
the chances of time before stabilizing. Field experience will
dictate exact techniques for flowchecks on any
a successful well well. Never try to explain warning signs as
being another type of problem until it is proven
control operation. that the well is not kicking. In some regions,
warning signs that would be an indicator of
a kick are considered normal for that area.
Always assume the well is kicking until it can
be proven otherwise.
C HAPTER 3
3-2
1-2
Near right: a
geolograph
records real time
events for future
use.
Far right: a change
in rate of
penetration; note
the drilling break
at approximately 8
and150 feet.
PENETRATION RATE CHANGE
An abrupt change in the rate of penetration
usually indicates a formation change, often
encountered while drilling. Many things,
including bit type, affect penetration rate.
The term drilling break has been used when
penetration rate increased, indicating a low-
density formation. If a drilling break was
encountered, a flowcheck was performed. With
today's newer PDC/TSP bits, a slowdown or
decrease in penetration rate may be experienced
in low-density formations. Now drillers may not
only perform flowchecks for drilling breaks,
but for reverse drilling breaks as well. When
in doubt, flowcheck the well each time a
new formation is encountered or the rate of
penetration changes.
FLOW RATE INCREASE VOLUME GAIN
Penetration rate: When the pump is running at a constant Formation fluid entering the well will
feet per hour at rate, it displaces a fixed amount of fluid into displace or kick fluid out of the hole, resulting
which the drill the well every minute. Since the injection rate in a gain in pit volume. The increase in total
bit deepens the of fluid into the well is constant, the rate of pit volume warns the crew that a kick may
wellbore. fluid return should also be constant. The rate be occurring. All circulating tanks should be
of flow at surface is measured. Formation fluid measured and marked so additional increases
may be feeding in if an increase in fluid volume will be promptly noticed. Pit-volume totalizer
is seen (more flows out than we pump in) while systems (PVTs) are required by regulations and
the pump rate has not changed operators for many activities and in various
False indications of high flow can be due to areas. They will keep track of the total volume
large pieces of formation or junk getting hung of mud in the active mud system. In addition,
up under paddle type flow sensors. Regardless, both audible and visual alarms can be set to
a flowcheck should be performed until it has activate at desired gains (for kicks) and losses
been proven that the well is not flowing. (for lost returns).
D ETECTION OF K ICKS
3-3
1-3
Notify proper rig personnel when transferring time then it must be assumed the formation
fluids. Also, use measured quantities of material is kicking and the well must be shut in. A
when adjusting the fluid density or adding flowcheck is one early way a kick can be
chemicals. In this way, additional increases detected. Any of the other indicators will come
can be tracked and excess or unexpected gains later.
recognized. There can be cases of flow from the
It should be cautioned that pit levels may annulus not due to the formation kicking.
be difficult to use as kick indicators when These include:
mixing, transferring or in certain formations 1. Charging pumps that did not shut down Flow check
that have hydrating clays adding volume to the when rig pumps were turned off. while drilling:
system. 2. U-tubing of heavier fluid in the string • stop rotating
to the annulus. This is most frequent when • pick up off
some gas cutting of returns at surface has bottom
FLOW – PUMP OFF been experienced. A favorite method of rig • shut down
hands to check for U-tubing is to hit the pipe the pump(s)
with a hammer. If the pipe has a hollow ring, • observe the
Whenever a drilling break or a reverse break
U-tubing is indicated. If it has more of a well carefully
is encountered, it is recommended that the
driller stops drilling immediately and performs dull thud, the pipe is full of mud dampening
a flowcheck. The flowcheck is performed by the sound, so there is no U-tubing. Another
stopping rotation, picking up the pipe to indication of U-tubing is that the rate of
connection height, shutting down the mud annular flow decreases appreciably after only
pumps and watching for flow from the annulus a few barrels
after allowing for the usual drainback. If flow 3. Flowback of mud due to ballooning.
ceases, then drilling will probably be resumed. Ballooning has been attributed to mud being
If the flow persists after the usual drainback lost into fractures or elasticity of the formation
far left, a float
type pit level
sensor
left, a flow rate
sensor
below, an influx of
formation fluid will
cause an increase
in flow from the
Return Flow Rate Check well
C HAPTER 3
3-4
that balloons the wellbore by the annular and minimizes the amount of ballooning. After
friction pressure. When the pumps are stopped, the first bottoms up has been circulated out,
the annular friction pressure is removed. This the shut-in pressures should be lower than on
allows either the fracture to close up and the initial shut in. This is because the annular
squeeze mud back into the wellbore or the friction pressure loss will be lower at the kill
ballooned wellbore to return to its original size. rate than at the drilling pump rate.
The flowback can be quite extensive. If ballooning is suspected after the first
Ballooning: the
If this is the first incident of ballooning circulation, slowly bleed volume from the
tendency of
encountered at this location, it must be treated annulus. Carefully observe the flow rate to
some formations
as a genuine kick and must be circulated out see if flow decreases appreciably after a few
to apparently
as a kick. Ballooning may be indicated by low barrels, thereby indicating ballooning and not
accept drilling
fluid when
shut-in pressures, i.e. pressures below annular a kick.
circulating, then friction pressure loss. Shut-in drillpipe pressure Obviously, ballooning must always be treated
give it back would be nearly the same as shut-in casing with caution. It can present a confusing
when the pump pressure and would show no increase due to situation that consumes considerable rig time.
is shut down. gas migration. When circulated out, the mud Circulating a deep, hot hole with cold
returns will not show any appreciable gas, oil fluid can give the appearance of flow as the
or water contamination. cold fluid heats and expands.
Maintaining a mud gain/loss log may
be helpful in determining the existence of
ballooning since flowback should equal mud SPEED/PRESSURE CHANGE
loss. Mud loss can be difficult to detect because
of mud making formations and also because of An influx of formation fluid will usually
mud mixing operations. decrease the density of the fluid column. As
If ballooning is suspected, the Driller's this occurs, the hydrostatic pressure exerted by
Method is preferred to circulate the first the fluid column decreases. As the annular
bottoms up, to avoid mud weight increase hydrostatic decreases, the mud in the string
usually caused by other methods. Mud weight tends to U-tube into the annulus. When this
increase will probably increase the ballooning occurs, the pump pressure will decrease and
effect. an increase in pump speed may be noted. This
Slower circulating rates (and consequently effect will also be aided by the expansion of gas
less circulating pressure) should be considered upwards, lifting some of the fluid and further
because this equates lower annular pressures reducing the fluid column's total pressure.
Well flowing with pump off
Gain in Volume
An increase in pit volume may indicate that the well is flowing.
Well
Flowing PIT Pit Gain
with
Pump
Off
D ETECTION OF
Increase
K ICKS
in Gas TRU-VUE
Unitized Pressure Gauge 3-5
Oil in
Return
3000 3000
2 4 2 4
5000 1000 5000
1000
6 0 6
Gas Units
Depth
80 88
Pump Speed Pump Speed
An increase in gas and signs of oil in pits Change in pump pressure/speed due to a kicking well
It should be noted that the initial surface to blow out. However, a kick is the unwanted
indication could be a momentary increase in feed-in of formation fluid. Gas/oil shows could
pump pressure. The pump pressure is seldom be indicators of a kick, and should be treated
noticed because of the short duration, but as such. Circulating through the choke may
it has been seen on some pump pressure be wise to safely remove gas or oil away from
charts after a kick was detected. This was the work area.
followed by a gradual decrease in pump pressure Besides mechanical means of observing
accompanied by an increase in pump speed. returns, a rig may use a shaker hand. The
This same drop in pump pressure and shaker hand is able to observe the mud and
increase in pump speed is also characteristic for determine if it is gas-cut, or if signs of formation
pumping a slug or, when there is a hole in the oil are in the returns.
string, commonly referred to as a washout. In
either case, a flowcheck must be performed to
determine if a kick is in progress. IMPROPER FILL AMOUNTS
Tripping out of the hole may be the most
GAS/OIL SHOWS – CIRCULATING hazardous time on a rig and one of the most
common causes of kicks. Contributing factors
In many areas and activities, a gas detector include: loss of circulating pressures, swabbing
is required to monitor the fluid returning from effect of pulling pipe, and improper fill-up that
the well, and to help detect abnormal pressure reduces hydrostatic pressure. With these factors
trends. When an increase in gas is detected, oil working against us, a trip tally of stands pulled
If the well is
or gas may be feeding in because of insufficient versus fluid to fill, plus visual verification is not taking the
pressure imposed on the well. While it is true imperative. Often regulations require the use proper amount
that gas-cut mud rarely starts a kick, if severe of mechanical devices to accurately determine of fluid to fill we
or shallow enough, it may cause a further the hole fill on trips. Also, the amount of fluid can assume
decrease in hydrostatic pressure. As more gas it takes to fill the hole for specific lengths (e.g., that formation
feeds in and expands, the hydrostatic pressure five stands of drillpipe) of both wet and dry fluid is invading
will continue to drop until the well starts to pipe as well as the length of pipe pulled before the wellbore.
flow. a reduction in hydrostatic pressure (e.g., 75 psi
Some zones exhibit a slow feed-in of or 5.17 bar) is reached must be posted.
formation fluid and rarely will cause a well
C HAPTER 3
3-6
1-6
Stand Starting Trip Finish Trip Difference Theortical Trend Accumulated Remarks (Comment when change
No. Tank Reading Tank Reading (Calculated) (Difference) Trend of pipe, problems, etc.)
5 50 48.5 1.5 3.56 -2.06 -2.06 Pull DP off bottom - may be balled
10 48.5 42.9 5.6 3.56 +2.04 -0.2 Seems OK
15 42.9 39.2 3.7 3.56 +.14 .12
20 39.2 35.9 3.3 3.56 -.26 -.14
25 33.2 30.5 2.7 3.56 -.86 -.96 Possible swab
30 33.2 32.3 .9 3.56 -2.66 -3.62 Hole not taking proper fluid, stop
Trip and check for flow
Trip log while tripping out of the hole
If the well is not taking the proper amount
of fluid we can assume that formation fluid is KICKS – OUT OF THE HOLE
invading the well (or that we are losing fluid
Well kicks occurring when out of the hole
if it is taking excess fluid to fill the hole).
often began during the trip out but were not
However, it must be cautioned that proper
noticed. The kick may have started during the
data must be used for calculating the steel
early part of the trip out. More likely, the kick
displacement and internal capacity values. Trip
started when the hole was not filled frequently
book records should be kept onsite and used
enough towards the end of the trip or while
to confirm that the hole is taking at least as
handling the collars.
much mud as on previous trips. Often prior
Similar situations may occur during lengthy
records may indicate an excess of as much
logging, wireline or fishing operations. Frequent
as twenty five percent. If prior records are
trips in and out of the hole with these tools can
available, the first indication of a kick while
swab formation fluids into the well, causing
tripping out will be that the hole takes less to
a kick.
fill than recorded at that depth on previous
The indicator of a kick when out of the
trips.
hole is flow from the well. When out of the
hole, it is good practice to close the blind rams
and monitor pressure at the choke. Closing the
Kicks noticed STRING WON’T PULL DRY blind rams prevents objects from falling into
while out of the wellbore and will prevent flow if the choke
the hole usually
When tripping out, it is possible for the is in the closed position.
are the result of
formation fluid to enter the well at a rate great If the choke is closed, it is a good idea
the trip out.
enough to prevent the fluid inside the pipe to have a pressure sensitive alarm to monitor
from falling. Also, when a flow begins it may pressure buildup on the shut-in system. If the
be easier for the flow to enter the string, when choke is left open, a watch should be set to
pulling large diameter tools and packers, than check for flow from the choke manifold. The
to flow around them. If the string should pull pit alarm should be set to its lowest alarm
dry at first, but then it begins to pull wet later, setting.
the trip should be suspended. A full opening Regardless of the procedure, never open
safety valve should be installed on the pipe, the BOPs to rig personnel until the area below
and well conditions evaluated. has been vented to a safe location.
D ETECTION OF K ICKS
3-7
1-7
Often in workover operations, and in areas
where lost circulation is a problem, circulation
STRING WEIGHT CHANGE
across the stack – pumping from and returning
The fluid in the hole provides buoyancy.
to the same tank – will ensure the well stays
full. If this system is used, alarms for gain and This means that the string weight of the pipe
loss should be set on the circulating tank. in the fluid decreases by an amount equal to Flow check
the weight of the fluid displaced by the pipe. while tripping:
• stop trip
The heavier the fluid (or the higher its density),
• set pipe in slips
DISPLACEMENT – TRIP IN the more buoyancy the fluid will provide. If a
• stab full
string weight increase is noticed, the increase opening safety
As pipe is run into the well, it should could be due to an influx of formation fluid valve and
displace fluid out equal to pipe's displacement decreasing the density of the fluid surrounding close
if no floats are in use. If pipe is lowered too the pipe. As the fluid density decreases, the • observe the
fast, fluid may be forced into the formation ability of the fluid to provide buoyancy is well carefully
ahead of the pipe due to surge pressures. reduced, resulting in an increase of weight that
This can result in lowering the fluid column will be noticed at surface. This weight increase
and reduction of hydrostatic pressure. If this may be noticeable depending on the amount
decrease lowers the pressure exerted by the of influx, the influx density and the length it
fluid to a point below formation pressure, well occupies. Generally, in a larger wellbore this
will begin to flow. will not be as pronounced as in a smaller
With an influx in the hole, more volume
diameter wellbore.
will be displaced out of the hole than the pipe's
If there is a decrease in string weight,
displacement. This is due to gas expansion
the decrease could be due to formation fluids
and/or a flowing well.
forcing upwards against the pipe. The well
Proper tripping procedures cannot be
overemphasized. The well should be monitored should be shut in without delay and control
continuously. If the fluid displaced out does procedures evaluated.
not match the displacement of pipe going in,
there is a problem. The fluid being displaced
Kicks While Out of Hole
out of the hole should always be measured.
Kicks while
out of the hole
Swab
C HAPTER 3
3-8
KICKS WHILE LOGGING KICKS WHILE RUNNING CASING
OR WIRELINING
Kicks that occur while running casing are
While running similar to kicks while tripping. An important
Well kicks that occur while logging and
casing the focus point to remember about kicks while running
during wireline activities are the result of:
is not on kick casing is that rig operations are oriented to
detection. • The swabbing action of the tools being running casing, not to detecting a well kick or
Remember to pulled through a tight section of hole. shutting in a well.
monitor returns When running casing, a well kick can be
• The swabbing effect of tools being pulled
and check
too fast. detected by observing that the flow of displaced
against
mud does not stop between joints of casing.
calculations. • Failing to keep the hole full during such Be sure to use the flow sensor and pit volume
activities. totalizer while running casing. Good procedures
A major concern is that the kick may have require that calculations be made for the
been allowed to progress. It may become quite displacement of the casing and couplings. A
large before someone notices it or makes the log comparing theoretical and actual displaced
decision to shut the well in. Always monitor volumes will help to determine that proper
the hole and keep it full. volumes are being displaced. If a kick is
Consideration should always be given to
the use of a wireline lubricator. A lubricator
Wireline
detected, the well should be shut in using casing
rams or the annular preventer. A circulating
long enough to encompass the tools will allow
the string to be pulled from the well, if a kick
Unit
swage should be available on the rig floor to
occurs, without having to cut the wireline to
shut in the well.
Right: using a lubricator
can prevent blowouts.
Below: casing operations.
D ETECTION OF K ICKS
3-9
Cementing
unit
fit the casing being run. A high pressure, low begin and if flow is noticed, it is often attributed
torque valve should be made up on the swage, to temperature expansion. Regulations may
checked for proper operation and noted on the dictate time requirements prohibiting nippling
drilling report prior to running. down activities and allowing the cement to
Caution should be used if the annular set. Under no circumstance should stack be
preventer is to be closed. Closing pressures nippled down until the possibility of a kick is
should be checked against collapse ratings of eliminated. If the well does flow, conventional
larger and lower grades of casing. circulating techniques cannot be used. So
techniques such as bullheading, lubricate
and bleed or volumetric procedures must be
KICKS WHILE CEMENTING considered.
Kicks that occur while cementing are the
result of reducing the mud column pressure SUMMARY
during the operation. This reduction of mud
column pressure can result from light cement Kick detection is everybody's responsibility. A sure sign that
slurries, lost circulation, improperly weighted Rigs have been lost because of a failure to alert a kick is in
spacer or the mechanics of the cement setting the supervisors that the well may be flowing. progress is if the
up. It is important to recognize warning signs of well flows with
When pumping cement the flow sensor kicks. If one or more of these warning signs are the pump off.
should be monitored for increases. Pit volume present, the crew and rig are in danger. Always
increases and cement displaced should be take the time to check these signs to determine
monitored to make sure volume of mud if the well is kicking. Remember, a sure sign
displaced is essentially equal to cement volume that a kick is in progress is if the well flows
pumped. with the pump off. We must check for flow.
Another complication is that once the top Proper action to shut the well in may be the
plug has bumped, nipple down procedures may next step. t
