Lecture# 04

Kick Theory
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Kick Theory

Influx behaviour differs depending on:

o Type of kick

o Well geometry

o Fluid in well
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What is a Kick?

Displacement of fluid @ top of hole by unwanted influx

of formation fluid

o Kick should not occur if hydrostatic pressure of fluid is

in excess of formation pressure
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Blowout

o A kick that is not recognized, or is allowed to continue,

will unload fluid from well

o When kick take place and not recognized, or if no

action is taken, then it could develop into blowout

o If well unload from one zone into another formation,

that is called underground blowout
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Determining
Nature of Kick
o Density of salt water is between 8.5 and 10.0 ppg
(1,019 and 1,198 kg/m³)

o Density of gas is less than 2.0 ppg (240 kg/m³)

o If density is between 2.0 ppg & 8.5 ppg (240 & 1019
kg/m³), then kick is mixture of gas, oil and water

o Most kicks are mixture of more than one fluid

o All kicks should be treated as gas kicks unless there is

good reason to believe otherwise
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Determining
Nature of Kick

Estimated kick length =

Pit Gain ÷ Annular Capacity (@ kick position)

Kick Density =
MW – ([SICP – SIDPP] ÷ [Kick Length × Conversion Factor])
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Example: 01
Calculate estimated density of influx given data:
o SITP = 400 psi (27.58 bar)
o SICP = 600 psi (41.37 bar)
o Hole Size = 8 1/2" (215.9 mm)
o Collar Size = 6 1/2" (165.1 mm) O.D.
o Mud Wt = 11.8 ppg (1414 kg/m³)
o Pit Gain = 15 bbls (2.38 m³)
o Annular Capacity Around Collars = 0.029 bbls/ft (0.01513
m³/m)
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Kick Length

Estimated Kick Length(ft) =

Pit Gain(bbls) ÷ Annular Capacity(bbls/ft)
= 15 ÷ 0.029 = 517 ft

Estimated Kick Length(m) =

Pit Gain(m³) ÷ Annular Capacity(m³/m)
= 2.38 ÷ 0.01513 = 157.3 m
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Kick Weight (density)

o Kick(ppg) = MW(ppg) – ([SICP(psi) – SIDPP(psi)] ÷ [Kick

Length(ft) × 0.052])
= 11.8 – ([600 – 400] ÷ [517.24 × 0.052])
= 11.8 – (200 ÷ 26.896)= 11.8 – 7.436 = 4.4 ppg

o Kick(kg/m³) = MW(kg/m³) – ([SICP(bar) – SIDPP(bar)] ÷

[Kick Length(m) × 0.0000981])
= 1414 – ([41.37 – 27.58] ÷ [157.3 × 0.0000981])
= 1414 – (13.79 ÷ 0.0154) = 1414 – 895.45 = 518.55 kg/m³
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Gas in Wellbore
Water-based Mud

o Gas is compressible fluid

o Gas volume depends on pressure imposed on it
o If pressure increases, volume decreases
o Behaviour of natural gas is approximated using inverse
proportionality
o Mean that doubling pressure compress gas to about
half original volume
o Reducing pressure by half double original volume
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General Gas law

o P1 = Original absolute pressure

o V1 = Original volume
o T1 = Original absolute temperature
o Z1 = Variation from perfect compressibility of gas @ P1 & T1
o (P, V, T, Z)2 = Values at any other conditions
o Ignoring T and Z the equation becomes
P1 × V1 = P2 × V2
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Example:
No Gas Expansion

o In 10,000 foot (3,048 m) well containing 10 ppg (1,198

kg/m³) fluid, 1 barrel (0.159 m³) of gas is swabbed in

o Well is shut in & gas bubble is allowed to migrate to

surface

o It is circulated to surface holding pit volume constant

mean gas will not be allowed to expand

o For sake of simplicity, ignore effects of temperature

and compressibility although they affect answer!
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Example:
No Gas Expansion

When bubble reach to surface:

o Surface pressure will be 5,200 psi (358.54 bar)

o Bottomhole pressure 10,400 psi (717.08 bar) which is

equivalent to a 20 ppg (2397 kg/m³) fluid

o In most cases, before gas reach surface, breakdown

of weaker formations would occur or casing could
burst
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Example:
No Gas Expansion

Lessons Learnt:

o Do not try to kill well with constant pit volume

o Do not allow well to stay shut in for long time if

pressures are continuing to rise

o Rising pressures probably mean gas migrating up hole

o If pressures rise, keep tubing pressure constant by using

proper bleed-off procedures at choke
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Example:
Uncontrolled Expansion

o Opposite of not allowing gas to expand is to circulate

gas out without holding any backpressure on it

o 1 barrel (0.159 m³) of gas is swabbed into wellbore

o Well is not shut in

o Pump has started to circulate bubble out of hole

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Questions?

1. If bubble is expanding, and displacing fluid from

well, how much hydrostatic pressure has been lost?

2. Can this loss of hydrostatic pressure cause well to

flow?

Note: With uncontrolled expansion, 90% of

expansion occur in top 10% of wellbore
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Controlled Expansion

o Gas must be allowed to expand to maintain BHP

equal to, or slightly above, formation pressure

o Pit volume must be allowed to increase

o More fluid is allowed to come out than is pumped in,

allowing gas to expand

o Choke hold backpressure allowing gas to expand

enough so hydrostatic pressure in well plus
backpressure is about formation pressure
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a
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Gas Migration

o A watch should always be kept on shut-in pressures

o Tubing/drillpipe pressure give best indication to

bottomhole pressure changes because it usually
contain known & consistent fluid

o Keep tubing/drillpipe pressure constant to keep BHP

constant

o Require choke manipulation to adjust pressure

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Problem: 1
Hydrostatic Pressure Loss

o Surface pressure is maintained at proper pressure

o 6 barrels (0.954 m³) gain was noted in the trip tank
o Fluid weight is 13.0 ppg (1,558 kg/m³)
o Well has 9 5/8” (244.5 mm) hole with 4 1/2” (114.3 mm)
drillpipe
o Annular capacity, 0.070 bbls/ft [36.51 m³/m]

Hydrostatic Pressure Lost = (Barrels Gained ÷ Annular

Capacity) × (Conversion Factor × Fluid Density)
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Problem: 2
Pressure @ Surface

o Calculate required surface pressure to replace

hydrostatic pressure of fluid as it is bled from well
o Same formula used in problem 1 is applied to
determine amount of surface pressure that would
have to be applied if hydrostatic is lost
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Problem: 2
Pressure @ Surface

o Gas is being controlled during migration up 9-5/8”

(244.5 mm) hole with 4-1/2” (114.3 mm) drillpipe

o Bled 10 barrels (1.59 m³) of 13.0 ppg (1,558 kg/m³) fluid

o Annular capacity is 0.070 bbls/ft (36.51 kg/m³)

Surface Pressure Increase = (Barrels Gained ÷ Annular

Capacity)× (Conversion Factor × Fluid Density)
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Liquid Kick

o Oil, water and saltwater are nearly incompressible

o Not expand to any extent as pressure is reduced

o Pumping and return rates is essentially equal

o Casing pressure not increase as is anticipated with gas

kick

o When compared with gas, liquid kicks do not migrate

up to any appreciable extent and shut-in pressures
not increase
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Gas in Wellbore
(Oil/Synthetic Oil Based Muds)

o Gas that enter wellbore go into solution, around 60%

of total gas. For example:

o With water based mud if well shut in with 10 barrel

(1.59 m³) pit gain, result in 10 barrel (1.59 m³) gas influx

o With oil based fluid, same 10 barrel (1.59 m³) gas kick
cause pit gain of 2 to 3 barrels (0.318 to 0.477 m³)

o This inconsistent pit gain can disguise severity of kick

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Gas in Wellbore
(Oil/Synthetic Oil Based Muds)
o When the gas comes out of solution, it will expand
rapidly

o If well is being circulated, result in sudden unloading of

fluid above gas as it expands

o Rapid expansion require choke adjustments to

maintain constant bottomhole pressure

o Should anticipate change from liquid to gas as kick

nears surface and prepared to make necessary
adjustments
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Estimated Max. Surface Pressure

from a Kick

o It is impossible to estimate Max. surface pressure

because pressure is regulated with pump and choke

o Solubility of kick fluid in the fluid system & temperature

reduce size of influx and therefore reduce pressure

o Kick composition, solubility of wellbore fluid, and

exact kick sizes, are never exactly known
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Max. Surface Pressure

o Max. surface pressure from gas kick killed by Driller’s

Method is greater than from Wait & Weight Method

o Pressure will be somewhat more than original Shut in

Tubing Pressure

o Maximum pressure from Concurrent Method fall

somewhere between Driller’s & Wait & Weight
Methods
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Effect of
Kick Position

o Major concern in WC is avoiding lost circulation

o During kick, pressure at any point is equal to hydrostatic

pressure above plus casing pressure at surface

o If procedure of maintaining constant bottomhole

pressure is followed (while circulating a kick or allowing
the gas to rise), pressures at weak point rise only until
gas reach weak point
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Effect of
Kick Position
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Kick Size

o The longer it takes to recognize kick, the larger kick will

be & harder to control

o The larger the kick, the higher the casing pressure

Note: If bottomhole pressure remain constant, danger

of lost circulation is reduced after kick is pumped up
into casing
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General Rules to
Determine Expected Max. Pressure

o Casing pressure increase with kick size

o Formation & circulating pressures increase with depth

o Circulating pressures increase with fluid weight

o Surface pressures are lowest with saltwater and increase

with gas kicks
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General Rules to
Determine Expected Max. Pressure

o Method of killing well affect surface pressure

o Increasing fluid weight before circulating may help

minimize surface casing pressure

o Gas migration while well is shut-in increase surface

pressures to near formation pressure

o Safety margins and extra fluid weight during kill

operations can cause higher circulating pressures
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More than One Kick

o If proper constant bottomhole pressure is not kept

when circulating influx out, 2nd kick may occur

o After circulating kill fluid to surface, pump should be

shut down and well shut-in

o If pressure is observed on casing, there is possibility that

2nd kick has been taken!

o Require 2nd circulation to get influx out

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Causes of
Secondary Kicks

o Improper start up procedures after being shut in

o Improper tubing pressure versus pump strokes

(circulating rate)

o Gas or mud exiting through choke

o Human error – incorrectly responding to mechanical

problems such as washouts, plugging, etc.
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Gas Cutting

o Small influx from bottom of hole can severely gas cut

fluid @ surface due to gas expansion near surface

o Total effect may be severe gas cut fluid at surface,

but downhole effects are almost negligible

o It is significant problem while drilling shallow wells

o Once surface casing is set, problem is minimized

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Gas Cutting

o Gas cut not cause

much reduction in
BHP
Gas Cuttings Caused by
Drilling Gas Sands
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Gas Behavior &

Solubility

Gas Solubility is function of:

o Type of fluid in use (water, oil & synthetic oil based)

o Pressure & temperature

o pH

o Types & ratios of gases (methane, H2S and CO2)

o Time that gas is exposed to liquid

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Gas Behavior &

Solubility

o If liquid gas kick is taken, kicking fluid will not migrate

or expand until it is circulated to point where gas can
no longer stay in liquid form

o Solubility changes with variables such as temperature,

pH, pressure and type of fluid

o Methane & H2S are more soluble in oil than water

o Changes in conditions (i.e., pressure) allow gas to

break back out and result in unexpected expansion
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