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PETE 411

Well Drilling

Lesson 24

Kicks and Well Control

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Kicks and Well Control Methods

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.4

HW #13dc - Exponent

due Nov. 6, 2002

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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 the wellbore is lower than the formation pore pressure (in a permeable 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 may be 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 pump has been shut down

7. Increase in hook load

8. 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 density

0.3 #/gal per circulation

3. Check for flow after each

complete circulation

4. If still flowing, repeat 2-4.

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Dynamic Kick Control

Other ways that shallow gas kicks

may be stopped:

1. The well may breach with the

wellbore essentially collapsing.

2. The reservoir may deplete to the

point where flow stops.

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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

SIDPP = 500 psi

SICP = 600 psi

4,000 ft

10,000 ft

DP OD= 4.5 in

Hole dia= 12.415 in

AnnularCapacity= 0.13006

bbl/ft

231 ft

BHP = 5,700 psig

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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 wellbore is 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 + PHYDR. 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/ft 670.0ft

psi

000,4

680,2

lb/gal 88.12)gal/lb)(ft/psi(

ft/psi

052.0

670.0

Calculate EMW at Casing Seat

mud = 10.0 lb/gal )

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Annular capacity per ft of hole:

bbls/ft 0.13006

gal 42

bbl

in 231

gal*in 12*)5.4415.12(

4

L)DD(4

v

3322

2P

2Hx

Calculate Initial Height of Kick

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ft 231

ft 7.230bbl/ft 0.13006

bbl 30

v

Vh

x

BB

hole, of bottomat kick ofHeight

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

PB = SICP + PMA + PKB PB = SIDPP + PMD

600 0 052 10

. *

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

600 5,080 P 500 5,200KB

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Density of Kick Fluid

(must be primarily gas!)

lb/gal 67.1231*052.0

20KB

P psiKB 20

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NOTE:

The bottom hole pressure is kept constant while the kick fluid 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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Top of Kick at Surface

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

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Top of Kick at Surface

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 + PKO + PMA

5,700 = Po + 20 + 0.052 * 10 * (10,000 - hO )

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

BB

P

hP

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Top of Kick at Surface

psi 102,1862240P

2

684,684*4480480P

0684684P 480P

231*5700*52.0PP 480

0

2

0

02

0

200

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Well Control Worksheet

Example:

When circulating at a Kill Rate of 40 strokes per

minute, the circulating pressure = 1,200 psi

The capacity of the drillstring = 2,000 strokes

Mud Weight = 13.5 lb/gal

Well Depth = 14,000 ft

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Aggie Drilling Research PRESSURE CONTROL WORKSHEETDivision of PETE Dept., TAMU DATE: College Station, TX 77843-3116 TIME WELL CLOSED IN:

1. PRE-RECORDED INFORMATION System Pressure Loss @ 40 stks = 1,200

psi STROKES - Surface to Bit = 2,000 stks TIME - Surface to Bit - 2,000 stks / 40 stks/min = 50 min

2. MEASURE Shut-in Drill Pipe Pressure (SIDPP) = 800

psi Shut-in Casing Pressure (SICP) = 1,100 psi Pit Volume Increase (Kick Size) = 40 bbl

3. CALCULATE INITIAL CIRCULATING PRESSURE (ICP) ICP = System Pressure Loss + SIDPP = 1,200 + 800 = 2,000

psi4. CALCULATE KILL MUD DENSITY (New MW) Mud Weight Increase = SIDPP / (0.052 * Depth) = 800/(0.052*14,000) = 1.10 lb/gal

Kill Mud Density (New MW) = Old MW + MW Increase = 13.5 + 1.10 = 14.6 lb/gal

5. CALCULATE FINAL CIRCULATING PRESSURE (FCP) FCP = System Pressure Loss * (New MW / Old MW)

= 1,200 * (14.6 / 13.5) = 1,298 psi

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1,298

0

Graphical Analysis

Fin

al C

irc.

Pre

ss.,

FC

P,

ps

i

Init

ial C

irc

. Pre

ss

., IC

P,

psi

3,000

2,000

1,000

0

3,000

2,000

1,000

0 5 10 15 20 25 30 35 40 45 50 minutes

0 2,000 pump stks.

0 bbls

2,000 1,298 psi

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Csg DS DS Csg

Pressure When Circulating

Static Pressure

First Circulation Second Circulation

Dri

llPip

e P

ress

ure

Driller’sMethod

1,298

2,000

800

2,000 stks

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Csg DS DS CsgC

asi n

g P

r ess

ur e

Volume Pumped, Strokes

Drillpipe Pressure

Driller’sMethod

800

1,100

0 psi

800

DP

Pr e

ss.

0 psi

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1

65

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2

Engineer’sMethod