Ch 6 Well Control

Assoc. Prof. Abdul Razak Ismail, UTM

SKPP 3413 - DRILLING ENGINEERING

Chapter 6 – Well Control

Assoc. Prof. Abdul Razak Ismail

Petroleum Engineering Dept.

Faculty of Petroleum & Renewable Energy Eng.

Universiti Teknologi Malaysia


Contents

Types of well control

Causes of well kicks

Warning signs of kicks

Methods of killing kicks

Blowout prevention equipment and well control

procedures

2


What is Well Control?

The technique used in oil and gas operations to

maintain the fluid column hydrostatic pressure and

formation pressure to prevent influx of formation

fluids into the wellbore

Technique involves the estimation of formation fluid

pressures, the strength of the subsurface formations

and the use of casing and mud density to offset those

pressures in a predictable fashion

Understanding of pressure and pressure relationships

are very important in well control

3


4


What is kick?

• An unscheduled entry of formation fluid(s) into the wellbore

• The pressure found within the drilled rock is greater than the mud hydrostatic pressure acting on the borehole or face of the rock

• Therefore, the formation pressure has a tendency to force formation fluids into the wellbore

• If the flow is successfully controlled the kick has been killed, if not BLOWOUT !!!

5


What is Blow Out ?• Any uncontrolled pressure

or formation fluids that

enter into the well during

drilling operation and starts

to explode

6


What turns a kick into a blowout?

The key objectives in blowout prevention are:

– To detect the kick as soon as possible

– To take steps to control the circulation of the kick out of the

well

– To take steps to increase the density of the fluid in the well

to prevent further fluids from entering the well

Lack of proper control !!

All kicks in some way are related to drilling fluid

7


8


Why a kick occur?

9

• The pressure inside the wellbore is lower than the formation pore pressure (in a permeable formation):

Pw < Pf

How a kick occur?• Mud density is too low

• Fluid level is too low - trips or lost circulation

• Swabbing on trips

• Circulation stopped - ECD too low


The severity of the kick depends upon

several factors:

The ability of the rock (porosity, permeability) to

allow fluid flow to occur

– A rock with high porosity and permeability has a greater

potential for severe kick (e.g. sandstone is considered to

have a greater kick potential than shale)

The amount of pressure differential involved

10


How do we prevent kicks?

Maintain the Pw > Pf

Do not allow the Pw to exceed the fracture pressure

This is done by controlling the Phyd of the drilling

fluid, and isolating weak formations with casing

11


Causes of kicks

1. Insufficient mud weight

2. Improper hole fill-up during trips

3. Swabbing

4. Cut mud

5. Lost circulation

12


1. Insufficient mud weight

One of the predominant causes of kicks

Pressure imbalance fluids begin to flow into the wellbore

Normally associated with abnormal formation pressures

Very high mud weight (overbalance) cannot be used because:

– High mud weight may exceed the fracture gradient of the

formation and induce an underground blowout

– Slightly reduce penetration rates

– Pipe sticking

Therefore, maintain the mud weight slightly greater than the

formation pressure until that time the mud weight begins to approach

the fracture gradient requiring an additional string of casing

13


2. Improper hole fill-up during trips

As the drill pipe is pulled out of the hole, the mud

level falls because the drill pipe steel had displaced

some amount of mud

With the pipe no longer in the hole, the overall mud

level will reduce, therefore, the hydrostatic pressure

of the mud will decrease

Therefore, it is necessary to fill the hole with mud periodically

to avoid decreasing of hydrostatic pressure

14


3. Swabbing

Swab pressures are pressures created by pulling the drill string from the borehole

This action will reduce the effective hydrostatic pressure throughout the hole below the bit

If this pressure decrease is large enough, there will be potential kick

Reasons

– Pipe pulling speed

– Mud properties

– Hole configuration (large swab pressure for small hole)

– Bit balling effect

15


4. Cut mud

Gas contaminated mud will occasionally cause a kick

although this occurrence is rare

Mud density will decrease

As gas is circulated to the surface, it may expand and

decrease the overall hydrostatic pressure to a point

sufficient to allow a kick to occur

Although the mud weight is cut severely at the

surface, the total hydrostatic pressure is not decreased

significantly since most of the gas expansion occurs

near the surface and not at the bottom of the hole

16


5 Lost circulation

Decreased hydrostatic pressure occurs due to a

shorter column of mud

When a kick occurs as a result of lost circulation, the

problem may become extremely severe since a large

amount of kick fluid may enter the hole before the

rising mud level is observed at the surface

17


Warning signs of kicks

1. Flow rate increase

2. Pit volume increase

3. Flowing well with pumps off

4. Pump pressure decrease and pump stroke increase

5. Improper hole fill-up on trips

6. String weight change

7. Drilling break

8. Cut mud weight

18


1. Flow rate increase

• When pumping at a constant rate, the flow rate increase more than

normal i.e. formation is aiding the rig pumps in moving the fluid up

the annulus by forcing formation fluids into the wellbore

2. Pit volume increase

• If the volume of fluid in the pits is not changed as a result of surface

controlled actions, therefore, an increase in pit volume indicates that

a kick is occurring

• The fluids entering the wellbore as a result of the kick displace an

equal volume of mud at the flow line and result in a pit gain

3. Flowing well with pumps off

• When the rig pumps are not moving the mud, a continued flow from

the well indicates that a kick is in progress

19


4. Pump pressure decrease and pump stroke increase

• A pump pressure change may indicate a kick

• The initial entry of the kick fluids into the borehole may cause the

mud to flocculate and temporarily increase the pump pressure

• As the flow continues, the low density influx will displace the heavier

mud and the pump pressure may begin to decrease

• As the fluid in the annulus become less dense, the mud in the drill

pipe will tend to fall and the pump speed may increase

5. Improper hole fill-up on trips

• When the drill string is pulled out of the hole, the mud level should

decrease by a volume equivalent to the amount of steel removed

• If the hole does not require the calculated volume of mud to bring the

level back to the surface, a kick fluid has entered the hole and filled

the displacement volume of the drill string

20


6. String weight change

• The mud provide a buoyant effect to the drill string, heavier muds

have a greater buoyant force than less dense muds

• When kick occurs, the mud density will decrease and as a result, the

string weight observed at the surface begin to increase

7. Drilling break

• An abrupt increase in bit penetration rate (shows a new rock type),

called a drilling break, is a warning sign of possible kick

• Although the drilling break occur, it is not certain that a kick will

occur, therefore, it is recommended to drill 3 – 5 ft into the sand and

stop to check for flowing formation fluids

8. Cut mud weight

• Decreased mud weight observed at the flow line has occasionally

caused a kick to occur

• Possible causes is gas (also oil and water) entering the formation

• However cut mud weight have small effect

21


Typical Kick Sequence

1. Kick indication

2. Kick detection - (confirmation)

3. Kick containment - (stop kick influx)

4. Removal of kick from wellbore

5. Replace old mud with kill mud (heavier)

22


Procedures in the event of a kick

At the first indication of a kick– Stop drilling

– Raise the bit off the bottom of the well (to shut in the well)

– Stop the pumps and check to see if there is a flow from the well

– If the well does flow, close the BOP and shut in the well

Readings are taken to stabilize shut in drill pipe and

casing pressures

Calculation are made to determine the density of the

mud that will be used to kill the well

Calculations are also made to determine the kick out,

and to fill the hole with new mud

23


Handling procedures of a kick may vary, and no one

method can be employed to each kick situation

Factors affecting kill procedures are:

– The area where the well is being drilled

– The depth of the well

– The operational procedures adopted by the contractor

– The equipment available

24


25

Typical Fluid Gradient

Gas 0.075 – 0.150 psi/ft

Oil 0.3 – 0.4 psi/ft

Water 0.433 – 0.520 psi/ftDep

th

Pressure


Kick Detection and Control

26

Kick Detection Kick ControlKick Detection Kick Control


1. Circulate kick out of hole

27

Keep the BHP constant throughout


2. Circulate Old Mud out of hole

28

Keep the BHP constant throughoutChapter 6: Well Control


Dynamic Kick Control

[Kill well “on the fly”]

29

For use in controlling shallow gas kicks

No competent casing seat

No surface casing - only conductor

Use diverter (not BOP’s)

Do not shut well in!


Dynamic Kick Control

30

For use in controlling shallow gas

kicks

Keep pumping. Increase rate!

(higher ECD)

Increase mud density, » 0.3 #/gal

per circulation

Check for flow after each

complete circulation

If still flowing, repeat 2-4.


Conventional Kick Control(Surface Casing and BOP Stack are in place)

31

Shut in well for pressure readings

Remove kick fluid from wellbore

Replace old mud with kill weight mud

Use choke to keep BHP constant


Calculations

Example: What overbalance would there be in a hole

drilling at 7,000 ft if the mud weight is 9.5

ppg and the formation pressure is 3,255 psi?

Solution:

DP = 0.052 (9.5) (7,000) – 3,225 = 203 psi

32


Example: A well is drilling at 5,000 ft using 10 ppg mud. A kick occurs and the well is closed in. The SIDPP builds up to 400 psi. What is the bottomhole formation pressure and what mud weight will be required to balance? What mud weight will be required to enable us to drill ahead using 150 psi overbalance?

Solution:

33

f hydP = P + SIDPP

= 0.052 (10) (5,000) + 400 = 3,000 psi

f

P = 0.052 h

P 3,000 ρ = = = 11.54 ppg

0.052 h 0.052 (5,000)

ob fP = P + P

= 3,000+ 150 = 3,150 psi

P = 0.052 h

P 3,150 ρ = = = 12.1 ppg

0.052 h 0.052 (5,000)


Example:

A well was cased at 4,500 ft. using 9 ¾ in. casing and then cemented. The

drilling was continued using 8 ¾ in. bit. Drill collars are 6 ¼ in. O.D., 2 ½ in.

I.D. and 500 ft. long and the drillpipe is 4 ½ in. OD, 3 ¾ in. ID, 16.6 lb/ft. The

mud density used in drilling this well is 9.5 ppg. When the drilling approaches

5,500 ft., a gas kick occured and the influx is 6 bbl of gas having a pressure

gradient of 0.075 psi/ft. were recorded. The well is shut-in and the surface

shut-in drill pipe pressure (SIDPP) builds up to 250 psi.

Based on the above information, calculate:

a. The bottomhole formation pressure.

b. The height of gas column.

c. The annular surface pressure/casing shut-in pressure (CSIP).

d. The pressure on the formation at the casing shoe.

e. The mud density required to just balance the formation pressure.

f. The mud density required to give 400 psi overbalance pressure.

34


Solution:

35

(a) f hydP = P + SIDPP

= 0.052 (9.5) (5,500) + 250

= 2,967 psi

d/c open hole hole d/c

2 2

2

gas kick d/c open hole gas kick

gas kick

gas kick

d/c open hole

A = A - A

8.75 6.25 = - = 0.2045 ft

4 12 4 12

V = (A ) (h )

V h =

A

3

2

ft6 bbl 5.615

bbl = 0.2045 ft

= 165 ft.

(b)


36

(c)

(d) @ shoe i.e. 4,500' hyd.P = P + CSIP

= 0.052 (9.5) (4,500) + 319

= 2,542 psi before adding a new mud

f hyd. gas hyd. orig. mud

f hyd. gas hyd.orig. mud

P = CSIP + P + P

CSIP = P - P - P

psi = 2,967 - 0.075 165 ft - 0.052 (9.5) (5,500 -165)

ft

= 319 psi before adding a new mud

P 2,967P = 0.052 h ρ = = = 10.4 ppg

0.052 h 0.052 (5,500)

f(e)

(f) ob fP = P + P

= 2,967 + 400 = 3,367 psi

P 3,367P = 0.052 h ρ = = = 11.8 ppg

0.052 h 0.052 (5,500)


Example: Whilst drilling the 10½” hole section of a vertical well the mud pit level

indicators indicate that the well is flowing. When the well is made safe, the

following information were gathered:

Surface readings: SIDPP = 200 psi, SICP = 400 psi, Mud wt. = 10 ppg

Pit gain = 20 bbls, Tsurface = 75oF, T gradient = 1.2 oF/100 ft

Hole/drill string: Hole size = 10 ½ “, Depth of kick = 10,500’, Previous casing

shoe = 4,500’, 13 3/8”, 68 lb/ft, d/c = 500’ of 8”, d/p = 4.5”

Capacities: Drillpipe = 0.01422 bbl/ft, drillcollar = 0.01190 bbl/ft,

Collar/Hole = 0.04493 bbl/ft, Drillpipe/Hole = 0.08743 bbl/ft,

Drillpipe/Casing = 0.13006 bbl/ft

Fracture gradient: at 4,500’ = 0.7 psi/ft

By using Wait and Weight method to circulate the influx out of the hole,

a. Determine what type of formation fluid has entered the wellbore.

b. What is the pressure at casing seat when the influx is still at the bottom?

c. What is the pressure at the surface when the influx is still at the bottom?

37


38

i

3

Vol. of influx 20(a) Height of kick, h 445 ft.

V 0.04493

i OM

i

(CSIP DPSIP)Fluid influx gradient, G G

h

(400 200)(10)(0.052)

445

0.071 psi/ft

Types of influx fluid is a , which will be expanded when reach at the sur

g se

afac

(b) Bottomhole pressure, BHP

@ shoe i.e. 4,500' hyd.P = P + CSIP

= 0.052 (10) (4,500) + 400

= 2,740 psi before adding a new mud


39

or,

(c) Pressure at surface (0’) when bubble at bottom, P0

0'P CSIP 400 psi (as recorded at the surface i.e. given)

f hyd. gas hyd. orig. mud

f hyd. gas hyd.orig. mud

P = CSIP + P + P

CSIP = P - P - P

psi = 5,660 - 0.071 445 ft - 0.052 (10) (10,500 - 445)

ft

= 400 psi before adding a new mud

f hydP = P + SIDPP

= 0.052 (10) (10,500) + 200

= 5,660 psi


Methods of killing kicks

There are many kick-killing methods, some of these have utilized systematic conventional approach while others were based on logical, but perhaps unsound, principles

Commonly used methods:

1. One circulation method

2. Two circulation method

3. Concurrent method

If applied properly, each of these 3 methods will achieve the constant pressure at the hole bottom and will not allow any additional influx into the well

40


1. One circulation method After the kick is shut in, weight the mud to kill density, then pump

out the kick fluid in one circulation using the kill mud

Other names: wait and weight method, engineer’s method, graphical

method, constant drill pipe pressure method

2. Two circulation method After the kick is shut in, the kick fluid is pump out of the hole before

the mud density is increased

Other names: driller’s method

3. Concurrent method Pumping begins immediately after the kick is shut in and the

pressures are recorded

The mud density is increased as rapidly as possible while pumping

the kick fluid out of the well

41


1. One circulation method• At point 1, the SIDPP is used to calculate the kill mud weight, after which

the mud weight is increased to kill density in the suction pit

• As the kill mud is pumped down the drill pipe, the static DPP is controlled

to decrease linearly, until at point 2 the DPP would be zero

• This results from heavy mud having killed the DPP

• Point 3 illustrate that the initial pumping pressure on the drill pipe would be

the total of the SIDPP plus the kill rate pressure, or 1,500 psi:

Initial pumping P = SIDPP + kill rate P

= 500 + 1,000

= 1,500 psi

• While pumping kill mud down the pipe, the circulating pressure should

reduce until at point 4, only the pumping pressure remains

• From the time that the kill mud reaches the bit until the kill mud reaches the

flow line, the choke controls the DPP at the circulating pressure while the

driller insures that the pump remains at the kill speed

42


Drill pipe pressure graph of the one circulation method of well control

43


One Circulation Method (Engineer’s Method)

1Cp

DPSIP

CSIP

2Cp

Phase 1 Phase 2

Pre

ssu

re (

psi

)

Time (min)

Phase 3 Phase 4

OB

K M

DPSIP pG G

d

Phase 1: Displacing drillstring to

killer/heavier mud

Phase 2: Pumping heavy mud into

annulus until influx reaches

the choke

Phase 3: Time taken for all the influx

to be removed from the

annulus

Phase 4: Stage between all the influx

being expelled and

killer/heavier mud reaching

surface

Dri

llp

ipe

pre

ssu

reC

ho

ke

pre

ssu

re

GK = Kill gradient psi/ft

GM = Mud gradient psi/ft

POB = Over balance pressure, psi


2. Two circulation method

Kill mud is not added in the first circulation, i.e. DPP

will not decrease during this period

The purpose of this circulation is to remove the kick

fluid from the annulus

In the second circulation, the mud weight is increased

and causes a decrease from the initial pumping

pressure at 1 to the final circulating pressure at 2

The final circulating pressure is held constant

thereafter while the annulus is displaced with the kill

mud

45


Drill pipe pressure graph of the two circulation method of well control

46


1Cp

DPSIP

CSIP

2Cp

Phase 1: Time for the influx to

reach surface

Phase 2: Time to discharge influx

Phase 3: Time to fill drillstring

with killer/heavier mud

Phase 4: Time to fill annulus with

killer/heavier mudPhase 1 Phase 2 Phase 3 Phase 4

1st circulation 2nd circulation

Pre

ssu

re (

psi

)

Time (min)

Dri

llpip

e pre

ssure

Choke

pre

ssure

Oil or Water

Gas

OB

K M

DPSIP pG G

d

GK = Kill gradient psi/ft

GM = Mud gradient psi/ft

POB = Over balance pressure, psi

Two Circulation Method (Driller’s Method)


3. Concurrent method

As soon as the kick is shut-in, pumping begins immediately after reading the pressures and the mud density is pumped as rapidly as possible

However, it is difficult to determine mud density being circulated and its relative position in the drill pipe

Since this position determines the DPP, it will give irregular pressure drops

As a new density arrives at the bit or some predetermined depth, the DPP is decreased by an amount equal to the hydrostatic pressure of the new mud density increment

When the drill pipe is completely displaced with kill mud, the pumping pressure is maintained constant until kill mud reaches the flow line

48


Drill pipe pressure graph of the concurrent method of well control

49


Choice of method

Determining the best control method, suitable for the

most frequently met situations, involves several

important considerations:

– The time required to execute the entire kill procedure

– The surface pressures arising from the kick

– The complexity of the procedure itself, relative to the ease

of carrying it out

– The downhole stresses applied to the formation during the

kick killing process

All of these factors must be analyzed before a

procedure can be selected

50


Advantages and disadvantages

of driller’s method

• Simple to teach and

understand

• Very few calculations

• In case of saltwater, the

contaminant is moved out

quickly to prevent sand

settling around drilling

assembly

• Higher casing shoe pressure

(kick)

• Higher annular pressure

(kick)

• Takes two circulations

Advantages Disadvantages

51



of wait-and-weight method

• Lowest casing pressure

• Lowest casing seat pressure

• Less lost circulation (if not

over killed)

• Killed with one circulation

if contaminant does not

string out in washed out

sections of hole

• Requires the longest non-

circulating time while

mixing heavy mud

• Pipe could stick due to

settling of sand, shale,

anhydrite or salt while not

circulating

• Requires a little more

arithmetic


52



of concurrent method

• Minimum of non-circulating time

• Excellent for large increases in mud weight (under balanced drilling)

• Mud condition (viscosity and gels) can be maintained along with mud density

• Less casing pressure than driller’s method

• Can be easily switched to weight-and-weight method

• Arithmetic is a little more complicated

• Requires more, on-choke, circulating time

• Higher casing and casing seat pressure than wait-and-weight method


53


Well Killing Procedures

When kick detected, shut-in the well

After the pressures stabilized, record DPSIP

& CSIP

Calculate the required kill mud weight, GK

(psi/ft)

(One Circulation Method vs

Two Circulation Method)


Example (killing kick)1. Determine the pressure at the casing seat at 4,000’ when using the Driller’s

Method versus using the Engineer’s Method to circulate a gas kick out of the

hole (assume ideal gas law).

2. Determine the casing pressure at the surface when the top of the gas bubble has

just reached the surface, for the same two mud weights used above.

Wellbore & formation data

Well depth = 10,000’

Hole size = 10.5”

Drill pipe = 4.5”, 16.60 lb/ft

Drill Collars = 8” x 3.5” x 500 ft

Surface casing = 4,000’, 13-3/8”, 68 lb/ft, ID = 12.415 in.

Mud Weight = 10 ppg

Fracture gradient @ 4,000’ = 0.7 psi/ft

DPSIP = 200 psi

CSIP = 400 psi

Pit level increase = 20 bbl

T at surface = 70 oF

Temperature gradient = 1.2 oF/100 ft


Solution: Initial (closed-in) conditions:

vdp.csg = 0.13006 bbl/ft

vdc,hole = 0.04493 bbl/ft

vdp,hole = 0.08743 bbl/ft

4,000’

9,500’

10,000’

DPSIP

CSIP

Driller’s Method Engineer’s Method

Bottom Hole Pressure, BHP

10,000 OM OBP P P

(0.052)(10)(10000) 2005400 psi

Bottom Hole Pressure, BHP

OM

OB

P Old mud hydrostatic pressure, psiP Overbalanced pressure, psi

10,000 OM OBP P P

(0.052)(10)(10000) 2005400 psi

Notes:For initial conditions,

calculation technique for

both method are the same


Driller’s Method Engineer’s Method

2 2 2

dc-oh 3

gal bblv (10.5 8 )in (12 in)

4 231 in 42 gal

0.04493 bbl/ft

Annular volume/ft outside drill collars:

2 2 2

dc-oh 3

gal bblv (10.5 8 )in (12 in)

4 231 in 42 gal

0.04493 bbl/ft

Height of Kick Fluid,

10,000

20 bblh 445 ft

0.04493 bbl/ft

Height of Kick Fluid,

10,000

20 bblh 445 ft

0.04493 bbl/ft

Hydrostatics in the Annulus,

f OM kick

kick_10,000

P = BHP CSIP ΔP ΔP5400 400 + (0.052)(10)(10000 445) P

D

Hydrostatic Pressure across Kick Fluid,

Hydrostatics in the Annulus,

kick_10,000P 5400 400 (0.052)(10)(9,555)

31. 4 psi

D

Hydrostatic Pressure across Kick Fluid,

kick_10,000P 5400 400 (0.052)(10)(9,555)

31. 4 psi

D

Weight of kick fluid, W, in lb,

2 2 2

2

W Pressure AreaPressure DC-OH Annular Area

lb= 31.4 10.5 8 in

in 41,141 lb

DC Drill collar

OH Open hole

Weight of kick fluid, W, in lb,

Annular volume/ft outside drill collars:

2 2 2

2

W Pressure AreaPressure DC-OH Annular Area

lb= 31.4 10.5 8 in

in 41,141 lb

F = DP * A = W

f OM kick

kick_10,000

P = BHP CSIP ΔP ΔP5400 400 + (0.052)(10)(10000 445) P

D


Kick at Bottom

9555'

h 445' ΔP 31.4 psi

DPSIP 200 psi

CSIP 400 psi

4000'

9500'

10000'

BHP 10000'P P 5,400 psi

Graphical illustration of kick at bottom forDriller’s and Engineer’s methods.

kick_10,000P 31. 4 psiD


Kick at top of 4,000’ casing seat

4000'

9500'

10000'

Graphical illustration of

kick at top of 4,000’

casing seat for Driller’s

method.

What is the pressure at 4,000 ft when the top of

the kick fluid first reaches that point?

4,000

4,000

1,098,444h

P

4,000

4,000

5,400 70 48 4600.08743h 20

P 70 120 460

1 2

PV PV

T T

For ideal gas law:

10,000 4,000

4,000 10,000

4,000 10,000

P TV V

P T

Whe the gas rises, it expands due to P & T

2 2

4,000 4,000 4,000 OH OD 4,000

2 2

4,000 4,0003

V A h d d h4

gal bbl10.5 4.5 (12 in) h 0.08743h

4 231 in 42 gal

p


Kick at Top of 4000’ Casing Seat ….(cont.)

4000'

9500'

10000'


kick at top of 4000’


method.

Again

K_4,000

2 2 2

weight weightP

area DP-OH Annulus area

1,141 lbs16.1 psi

π10.5 4.5 in

4

D

4,000 K_4,000 OMBHP P ΔP ΔP

OM Old mudDP Drill pipeOH Open hole

4,000

4,000

1,098,4442,264 P (0.52)

P

4,000 4,0005,384 P 3,120 0.52(h )

4,000 4,0005400 P 16 (0.052)(10)(6,000 h )

This results in the quadratic Eqn:

2

4,000 4,000P 2,264 P 571,191 0

22 4

If 0, then 2

b b acax bx c x

a


Kick at Top of 4000’ Casing Seat ….(cont.)

4000'

9500'

10000'


kick at top of 4000’


method.

This results in the quadratic Eqn:

2

4,000 4,000P 2,264 P 571,191 0

With the solutions:

2

4,000

2264 2264 (4)(1)(571,191)P

2(1)2493 psi

1(2493 psi)

4000 ft0.6233 psi/ft0.7 psi/ft

22 4

If 0, then 2

b b acax bx c x

a

4,000

4,000

1,098,444 1,098,444h 441 ft

P 2493

Height of kick at 4000'


Graphical illustration of kick at top of 4000’ casing seat for Driller’s method.

BHP 10000'P P 5400 psi

4000'

9500'

10000'

h 441' ΔP 16 psi

4,000P 2493 psi

4,000h 441 ft

K_4,000P 16 psiD

0,annP = ?

Kick at Top of 4,000’ Casing Seat ….(cont.)


Top Kick at Surface

4000'

9500'

10000'


kick at surface for

Driller’s method.

When the bubble rises, it expands. The volume of the bubble at the surface is given by:

0

0

677,084h --- (1)

P

0

0

5400 70 460(0.13006) h 20

P 70 120 460

10,000 00 10,000

0 10,000

P TV V

P T

Z constant

Again

K_0

2 2 2

weight 1,141 lbP 10.85 psi 11 psi

πarea12.415 4.5 in

4

D

0 K_0 OMBHP P ΔP ΔP

0 05400 P 11 (0.052)(10)(10,000 h )

c

2 2

0 0 0 ID OD 0

2 2

0 03

V A h d d h4

gal bbl12.415 4.5 (12 in) h 0.13006h

4 231 in 42 gal

p


Top Kick at Surface … (cont)

4000'

9500'

10000'


kick at surface for

Driller’s method.

0 05400 P 11 (0.052)(10)(10,000 h )

2

0 0P 189 P 352,084 0

2

0 05,400 5,200 11 P P 352,084

0

0

677,0845,400 P 11 0.52 10,000

P

0Substitute h from eq. 1:

By solving the quadratic eqn.:

2

0

189 189 (4)(1)(352,084)P 695.34 psi 695 psi

2(1)

0

0

677,084 677,084h 973.74 ft 974 ft

P 695.34

Height of kick at surface


Top Kick at Surface … (cont)

4000'

9500'

10000'


kick at surface for

Driller’s method.

When the bubble reach at surface, the pressure at 4000 ft is given by:

4,000 0 K0P P (0.052)(10)(4,000 974) ΔP

695 1,574 11

2,280 psi ( 0.57 psi/ft)

4,000 10,000P P (0.52)(10)(10,000 4,000)

5,400 3,120

2,280 psi

Alternatively,


Graphical illustration of kick at surface for Driller’s method.

4,000P 2280 psi

0h 974 ft

K_0P 11 psiD

Top Kick at Surface ….(cont.)

BHP 10000'P P 5400 psi

0h 974'

ΔP 16 psi

4000'

9500'

10000'

K,OΔP 11 psi

10,000P = ?

P0,ann = 695 psi


Kick at Top of 4,000’ Casing Seat

What is the pressure at 4,000 ft when the top

of the kick fluid first reaches that point?

4,000

4,000

1,098,444h

P

4,000

4,000

5,400 70 48 4600.08743h 20

P 650

1 2

PV PV

T T

For ideal gas law

10,000 4,000

4,000 10,000

4,000 10,000

P TV V

P T

When the gas rises, it expands due to P & T

Old Mud, OM

New Mud or Killer Mud, KM

Kick4000'

9500'

10000'

Graphical illustration of kick at top of 4000’ casing seat for

Engineer’s method.

BHP 10000'P P 5400 psi

….. (6)


Engineer’s method - Pressure at top of kick

- kick at 4,000 ft

4,000 K_4,000 M M1

K_4,000

M

But,

BHP P ΔP ΔP ΔP

As before, P 16 psi

141 bbl P 0.052*10*

0.08743 bbl/ft

839 psi

D

D

….. (7)


Engineer’s method - Pressure at top of kick

- kick at 4,000 ft

psi/ft 0.61 psi 2,422

2

940,592 * 4177,2177,2

0592,940P 2,177P

P

1,098,444 (0.5398)P2,177

h(0.5398)2,36883916P5,400

......(7) ΔPΔPΔPPBHP

0.08743

141h6,000 (10.38) 0.052ΔP

2

000,4

4,000

2

4,000

4,000

000 4

4,0004,000

M1MK_4,0004,000

4,000M1

P


4,000’

9,500’

10,000’Kill Mud

Old Mud

Engineer’s method - Top of kick at surface


Engineer’s method - kick at surface

Capacity inside drill string = DP_cap. + DC_cap.

bubble. thebelow mud gal

lb 10.0 ofQuantity

bbl 141

ft 500 ft

bbl0.0119ft 9,500

ft

bbl0.01422

ppg 10.38100.38

10 (10,000) 0.052

SIDPP

wt.)mud (old wt.)mud (new weightmud Kill



Volume of gas bubble at surface:

(4)--- P

677,084h

650

530

P

5,40020h 0.13006

T

T

P

PVV

0

0

0

0

10,000

0

0

10,000

10,0000

psi 11PΔ

(5)--- PΔPΔPΔPP

K,0

M1MK0010,000

As before,

Assume all 10 lb mud is inside 13 3/8” csg. Then the height of 10 lb mud

ft 1,084 bbl/ft0.13006

bbl 141.0h M



1,084)h(10,000*10.38*0.052ΔP

psi 564 1,084*10*0.052ΔP

0M1

M

Hydrostatic head across the mud columns:

(old mud)

(kill mud)

00

00

M1MK0010,000

(0.5398)hP12.14

)h(8,916*0.539856411P5,400

ΔPΔPΔPPP

Hydrostatic in the annulus:



psi 611 610.59 P

2

365,490 * 41212P

0365,49012PP

P

677,084(0.5398)P12

0

2

1 2

0

0

2

0

0

0

From Eq. 4, substituting for h0

Height of bubble at surface:

ft 1,109610.59

677,084

P

677,084h

0

0

ok) (lookspsi/ft 0.54 psi 2,161

1,093)-1,109-(4,000 (10.38) 0.05256911611

ΔPΔPΔPPP M1MK004,000


Kill Mud

Old Mud

4,000’

9,500’

10,000’

h0 = 1,109 ft

DPK,0 = 11 psi

P0,ann = 611 psi

P 4,000 = 2,161 psi

P10,000 = ?

DPOld Mud = 569 psi

Engineer’s method – Top of kick at surface


Summary

Driller’s

method

Engineer’s

method

Bubble at bottom

hole (10,000’)

P4,000’ 2,480 2,480

P0’ 400 400

Top of bubble at

casing shoe (4,000’)

P4,000’ 2,493 2,422

P0’ 413 342

Top of bubble at

surface (0’)

P4,000’ 2,280 2,161

P0’ 695 611


Causes of BlowoutUnderbalance (low density mud, water, foam, air)– Reduce formation damage

– Save money but the risk of occur blowout increased

Overbalance– Safety but has its limitation

– If overbalance pressure is too high may break the formation and cause lost circulation lead to a blowout

Swabbing (tripping out)– Pulling the drill string too fast out of the hole will cause suction

– Reduce the pressure below the bit invites a kick

Going too fast in the hole (tripping in)– Break the formation can cause lost circulation

Falling object hitting and ruining the BOP

Equipment, such as plugs, BOP, DHSV fails in a critical moment

77


Why well control and blow out

prevention is important?

Higher drilling costs

Injuries and possible loss of life

Lost of revenue

Waste of natural resources when blow out occur

Environmental effects

Government regulation and restriction

78


How to prevent blowout?

The best solution is to prevent before it happen

– Develop a drilling plan, including a drilling fluid design

– The proficiency of rigs crew and supervisors and their

ability to put contingency to work

– Added precautions often taken in drilling exploratory wells

– Identify the presence of shallow gas

79


Types of well control

Firstly, well control can refer to the prevention of

formation fluids entering the well bore referred to

as primary control

Secondly, should primary control fail and fluids enter

the well bore, there is the requirement to be able to

allow the influx to be discharged at surface in a

controlled manner and concurrently to prevent

additional influx of fluid into the well bore referred

to as secondary control

The control of a well refers to the ability to prevent

formation fluids flowing up the well bore and being

released at the surface

80


Primary control

This is the prevention of the influx of formation

fluids into the wellbore by ensuring that the

hydrostatic pressure in the wellbore is at all times

greater than the formation pressure:

Phyd > Pf

The hydrostatic pressure may be too low because of

the following reasons:

1. Insufficient fluid density

2. Insufficient height of fluid column

81


1. Insufficient fluid density

Inaccurate measurement of fluid density

High temperature encountered hence a reduction in density occurs due to fluid expansion

At watering back (after mud return, water loss due to evaporation, filtration loss, etc) excessive dilution may occur

Too fine mesh used at the shale shaker lead to removal of weighting solids

Insufficient fluid density could have been created by the

following:

82


2. Insufficient height of fluid column

Failure to keep the hole full when tripping out

Swabbing effect (drill pipe acts as a piston):

– Pulling the pipe upwards too quickly

– Using mud of very high gel strength

– Having small annular clearance

– Ineffective cleaning of the bit to remove drill cuttings (e.g. bit balling)

Loss circulation occurring into the formation

Collapse of casing or leakage into the wellbore

The majority of blowouts occurs when the height of the

fluid column reduced:

83


Secondary control

When primary control is lost, it is not normally possible to kill the well immediately

The well is then shut in to prevent further influx into the wellbore; and usually, this is only a temporary measure

Secondary control therefore refers to the use of mechanical devices used to close off the well

This device is called a blowout preventer (BOP)

The safety and efficiency of the control depends on the integrity of the casing strings, well head and fittings

84


Secondary control could be lost due to several reasons:

Mechanical failure of the BOP

Late identification of the influx

Casing fails to burst which will render a loss to the

annular pressure seal, hence the BOP will be

ineffective

Bad cement bond – the influx will channel through

the cement, hence it will be discharged uncontrollably

85


Operational guidelines to the maintenance of primary control

Maintenance of the correct mud weight

– Gas cutting

– Solids removal

– Excessive dilution

Maintenance of sufficient height of mud column

– Precautions whilst drilling

– Precautions before tripping

– Precautions whilst tripping

– Precautions whilst running casing

– Lost of circulation

– Drilling break

Careful attention should be paid to the following factors to ensure that primary

control is maintained:

86


To bring oil and gas to the surface drill hole

When the rock on earth that hold back formation

pressures are removed:

– The pressure will be released and free to flow

– To control use drilling fluid (create hydrostatic column

of sufficient weight)

Generally, the deeper the well goes, the higher the

formation pressures that must be retained, therefore,

mud weight must be increased to keep the well

formation pressure

87


Some blowouts stop by themselves by one of

these reasons:

Depletion of source

Bridging of the well bore by cave-in of open hole

Choking of the formation by entrained material

Choking the well bore by entrained sand, etc

88


Who shall stop blowouts ?

When a blowout occurs, the operators shall leave the

location immediately and never make heroic attempts

to stop it. That would simply be too risky!

In the stressed situation the possibility of making

fatal mistakes is overwhelming

Any attempt to stop a blowout required proper

planning, equipment and a special type of people

89


Placement of blow out

preventer stack, complete with

remotely operated accumulator

hook up; followed by

installation of mud kill line.

Cooling down wellhead with

high pressure water

jets/monitors

90


Kuwait blowout, 1991

91


BP's “Deepwater Horizon” Blowout – April 2010

92


“Deepwater Horizon” Blowout

93


Relief wells are special directional wells planned to drill to hit the blow out well.

When the blowout well is drilled into, a special well control procedure will be

conducted to control the blowout well. There are several examples as in

Macondo well (blow out incident on 20 April 2010).

94

A BP graphic shows how relief wells

have been drilled to intercept the

Macondo well that had been leaking

millions of gallons of oil and gas into

the Gulf of Mexico.


BLOW OUT PREVENTER (BOP)

95


What is BOP?• The BOPs are a series of powerful sealing elements designed

to closed off the annular space between the drill pipe and the

hole through which the mud normally returns to the surface

• Valves are installed on the pipe or wellhead to prevent the

escape of pressure either in the annular space between the

casing and drill pipe or in open hole during drilling,

completion and work over operations

• By closing this valve, the drilling crew usually regains control

of the reservoir with increase the mud density until it is

possible to open the BOP and retain pressure control the

formation

• They can be hydraulically, manual or air operated and in some

cases a combination of all three

96


97


98


BOPs rating

The bursting pressure of the casing will often be the determining

factor for rating the working pressure of the assembly.

API Bulletin D13 gives the pressure ratings for BOP equipment:

99

API Class Working pressure

105 Pa (psi)

Service condition

2 M 138 (2,000) Light duty

3 M 207 (3,000) Low pressure

5 M 345 (5,000) Medium pressure

10 M 689 (10,000) High pressure

15 M 1,034 (15,000) Extreme pressure


Types of BOPBOPs come in a variety of styles, size and pressure ratings

Some BOPs can effectively close over an open wellbore, some are designed to sealed around tubular components in the well (drill pipe, casing and tubing) and others are fitted with hardened steel shearing surface that can actually cut through drill pipe

Two basic types

1. Annular type or

2. Ram type

A combination of both types are commonly used to make up a 'BOP stack' alias X-mas Tree

100


Annular Surface Blowout Prenventor

Pipe Ram Blind Ram Shear Ram

Ram-Type Surface Blowout Preventor

Surface BOP Downhole BOP

BOP

101


1. Annular preventers

A large valve used to control wellbore fluids

Design to shut off around any size of equipment run through the hole

Most blowout preventer (BOP) stack contains at least one annular BOP at the top of the BOP stack, and one more ram-type preventers below

It can close around drill pipe, drill collars and casing, and also pack off an open hole

Is a well’s master valve and normally closed first in the event of a well kick, owing to flexibility of the closing rubbers

It can only be closed hydraulically by directing fluid under pressure to the operating cylinder through the closing chamber

102


103


This mud-drenched annular preventer is located near the top of the BOP

stack (left). The red annular BOP (right) awaits installation

104


2. Ram-type preventer

Three types:

a. Pipe rams - which seal off around a pipe and

annulus

b. Blind rams - which completely close off the

wellbore when there is no pipe in the hole

c. Shear rams - which are the same as blind rams

except that they can cut through drillpipe for

emergency release as a last resort

105

A set of pipe rams may be installed below the shear rams to

suspend the severed drillstring


Ram-type preventer (ctd)

106

Blind Ram Pipe Ram Dual Offset Ram

Hydryl Vacuum Ram Lower Shear Blade Upper Shear Blade


Ram-type preventer (ctd)

107

Shear Rams in action


2a. Pipe rams

Design to close around a particular size of drill pipe, tubing or casing

The pack off is provided by two steel ram blocks containing semi-circular openings with each ram being fitted with a two-piece rubber seal

The semi-circular openings can seal around the outside diameter of the drill pipe, tubing, drill collar, kelly or casing, depending on the size of the rams chosen

It can be close manually or hydraulically to seal off the annular

108


109


Pipe rams

110


2b. Blind ramsQuiet similar to pipe rams

Except that packer are replaced by ones that have no cutouts

in the rubber

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 drill string

Designed to seal off the bore when no drill string or casing is

present

111


2c. Shear rams

A BOP closing element fitted with hardened tool steel blades

Designed to cut the drill pipe when the BOP is closed

Normally used as a last resort to regain pressure control of a well that is flowing

Once the drill pipe is cut, it is usually left hanging in the BOP stack and kill operations become more difficult

The joint of drill pipe is destroyed in the process, but the rest of the drill sting is unharmed by the operation of shear rams

112


113


114

Bottom pipe ram, shear rams & annular 13-58 BOP stack 10,000 psi rating


BOP safety

Well control equipment that is to be install must be rate

above the maximum expected formation pressure of the

well about to be drilled

Tested immediately after installation

Maintained ready for use until drilling operations are

completed

Control panel must be located at sufficient distance from

well head

BOP equipment must be pressure tested

115

Ch 6 Well Control

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Transcript of Ch 6 Well Control