9. well control.ppt

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PETE 661

Drilling Engineering

Lesson 9Well Control Concepts



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Lesson 9 - Well Control Concepts

The Anatomy of a KICK

Kicks - Definition

Kick Detection

Kick Control

(a) Dynamic Kick Control

(b) Other Kick Control Methods

* Driller’s Method

* Engineer’s Method



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Read:

Applied Drilling Engineering, Ch.6

HW # 6

Kick Control

due Monday, Oct. 13, 2003



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Causes of Kicks



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Causes of Kicks



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Causes of Kicks



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What?

What is a kick?

An unscheduled

entry of

formation

fluid(s) into the

wellbore



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Why?

Why does a kick occur?

The pressure inside thewellbore is lower

than the formation

pore pressure (in apermeable formation).

pw < pf



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How?

How can this occur?

Mud density is too low

Fluid level is too low - trips or lost circ.

Swabbing on trips

Circulation stopped - ECD too low

)pp( FW



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What ?

What happens if a kick is not

controlled?

BLOWOUT !!!



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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)



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Kick Detection and Control

Kick Detection Kick Control



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1. Circulate Kick out of hole

Keep the BHP constant throughout



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2. Circulate Old Mud out of hole

Keep the BHP constant throughout



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Kick Detection

Some of the preliminary events that maybe associated with a well-control

problem, not necessarily in the order of

occurrence, are:

1. Pit gain;

2. Increase in flow of mud from the well

3. Drilling break (sudden increase in

drilling rate)



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Kick Detection

5. Shows of gas, oil, or salt water

6. Well flows after mud pumphas been shut down

7. Increase in hook load8. Incorrect fill-up on trips

4. Decrease in circulating pressure;



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Dynamic Kick Control[Kill well “on the fly”]

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!



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Dynamic Kick Control

1. Keep pumping. Increase rate!

(higher ECD)

2. Increase mud density0.3 #/gal per circulation

3. Check for flow after each

complete circulation

4. If still flowing, repeat 2-4.



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Conventional Kick Control{Surface Casing and BOP Stack are in place}

Shut in well for pressure readings.

(a) Remove kick fluid from wellbore;

(b) Replace old mud with kill weight mud

Use choke to keep BHP constant.



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Conventional Kick Control

1. DRILLER’S METHOD

** TWO complete circulations **

Circulate kick out of hole

using old mud

Circulate old mud out of hole

using kill weight mud



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Conventional Kick Control

2. WAIT AND WEIGHT METHOD

(Engineer’s Method)

** ONE complete circulation **

Circulate kick out of hole

using kill weight mud



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Driller’s Method - Constant Geometry

Information required:

Well Data:

Depth = 10,000 ft.

Hole size = 12.415 in. (constant)

Drill Pipe = 4 1/2” O.D., 16.60 #/ft

Surface Csg.: 4,000 ft. of 13 3/8” O.D. 68 #/ft

(12.415 in I.D.)



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Driller’s Method - Constant Geometry

Kick Data:

Original mud weight = 10.0 #/gal

Shut-in annulus press. = 600 psi

Shut-in drill pipe press. = 500 psi

Kick size = 30 bbl (pit gain)

Additional Information required:



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Constant

Annular

Geometry.

Initial

conditions:

Kick has just

entered the

wellbore

Pressures

have

stabilized



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Successful Well Control

1. At no time during the process of

removing the kick fluid from the

wellbore will the pressure exceed the

pressure capability of

the formation

the casing

the wellhead equipment



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Successful Well Control

2. When the process is complete the wellboreis completely filled with a fluid of

sufficient density (kill mud) to control the

formation pressure.

Under these conditions the well will not flow

when the BOP’s are opened.

3. Keep the BHP constant throughout.



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Calculations

From the initial shut-in data we can

calculate:

• Bottom hole pressure

• Casing seat pressure

• Height of kick• Density of kick fluid



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PB = SIDPP + Hydrostatic Pressure in DP

= 500

+ 0.052 * 10.0 * 10,000

= 500 + 5,200

PB = 5,700 psig

Calculate New Bottom Hole Pressure



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Calculate Pressure at Casing Seat

P4,000 = P0 + DPHYDR. ANN. 0-4,000

= SICP + 0.052 * 10 * 4,000

= 600 + 2,080

P4,000

= 2,680 psig



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This corresponds to a pressure gradient of

Equivalent Mud Weight (EMW) =

psi/ft670.0ft

psi

000,4

680,2

lb/gal88.12)gal/lb)(ft/psi(

ft/psi 052.0

670.0

Calculate EMW at Casing Seat

( rmud = 10.0 lb/gal )



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Annular capacity per ft of hole:

bbls/ft0.13006

gal42

bbl

in231

gal*in12*)5.4415.12(

4

L)DD(4v

3

322

2

P

2

Hx

Calculate Initial Height of Kick



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ft231

ft7.230bbl/ft0.13006

bbl30

v

Vh

x

BB

hole,of bottomatkick of Height

Calculate Height of Kick

hB



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Calculate Density of Kick Fluid

The bottom hole pressure is the pressure at

the surface plus the total hydrostatic pressure

between the surface and the bottom:

Annulus Drill String

P SICP P P SIDPP PB MA KB MD D D D

600 0052 10

. *

*(10,000-231) P 500 (0.052*10*10,000)KBD

600 5,080 P 500 5,200KB D



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Density of Kick Fluid

(must be primarily gas!)

lb/gal67.1231*052.0

20KB r

DP psiKB 20



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NOTE:

The bottom hole

pressure is kept

constant while the kickfluid is circulated out of

the hole!

In this case

BHP = 5,700 psig

Circulate Kick Out of Hole



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Constant

Annular Geometry

Driller’s Method.

Conditions When

Top of Kick Fluid

Reaches the Surface

BHP = const.



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Top of Kick at Surface

As the kick fluid moves up the annulus, it

expands. If the expansion follows the gas

law, then

[bottom] ]surface[

RTnZ

VP

RTnZ

VP

BBB

BB

000

00



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Ignoring changes due to compressibility

factor (Z) and temperature, we get:

Since cross-sectional area = constant

.)constv(v

hPhP.e.i

hvPhvP VPVP

B0

BB00

BBB000

BB00

f S f



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We are now dealing two unknowns, P0

and

h0. We have one equation, and need a

second one.

BHP = Surface Pressure + Hydrostatic Head

5,700 = Po + DPKO + DPMA

5,700 = Po

+ 20 + 0.052 * 10 * (10,000 - hO

)

5,700 - 20 - 5,200 = Po - 0.52 *o

BB

P

hP

T f Ki k S f



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psi102,1862240P

2

684,684*4480480P

0684684P480P

231*5700*52.0PP480

0

2

0

0

2

0

2

00



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40 1,200502,000/40 2,000

8001,100

40

1,200 + 800 2,000

800 / (0.052 * 14,000) 1.10

13.514.6

1,200 * 14.6 / 13.5

1,298 psi



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50

2,000

bbls200

1,298

0

0

0

5 10 15 20 30 4025 35 45



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Csg DS DS Csg

Pressure When Circulating

Static Pressure

First Circulation Second Circulation

Driller’s

Method



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Csg DS DS Csg

Volume Pumped, Strokes

Drillpipe Pressure

Driller’s

Method



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2

Engineer’s

Method

9. well control.ppt

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