7B. Other Abnormal Pressure Detection Methods

8/9/2019 7B. Other Abnormal Pressure Detection Methods

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TAMU - PemexWell Control

Lesson 7BOther Abnormal Pressure

Detection Methods


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Contents

Moores Equation - Drilling rate Gas in the Drilling Fluid

Rock Sample Characteristics

Use of Surge and Swab Pressure todetermine Overbalance

Changes in Drilling Fluid Properties Temperature Indications

Hole Conditions


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Moores Equation

Moore proposed a practical method for

maintaining pore pressure overbalance

while drilling into a transition.

If drilling parameters are kept constant

while drilling into an abnormal pressurezone, the drilling rate will increase.


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Moores Equation

Moore suggests that we increase themud weight sufficiently to keep the

drilling rate from increasing.

The increase in mud weight will then be

a measure of the abnormal pore

pressure.

But how much do we increase the mud

weight?


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Moores

Equation

Transition zoneBegin weighting up

Weight up complete


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Ex.

2.10

?


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Example 2.10

Bit parameters prior to transition were

Bit Weight = 4,700 lbf/in

Rotary Speed = 80 rpm

Transition detected at 9,100 ft and theoperator immediately reduced the bit

weight to 2,900 lbf/in


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Example 2.10

Determine the extrapolated normal

penetration rate at a depth of 9,250 ft

if the bit weight is reduced from itscurrent value of 4,700 to 2,900 lbf.

Use the data in Fig. 2.46 andMoores penetration rate model.


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Solution

The extrapolatednormal penetrationrate at 9,250 is 15.7ft/hr, at 4,700 lbfbitweight.

This would have been

the target rate had thebit weight remainedconstant.

15.7

Fig. 2.46

9,250


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Solution contdThe target penetration rate at the reduced bit

weight of 2,900 lbf is calculated below:

Na

b

Nd

WKR

=

Na

R = 8080700,4 900,27.15

The target rate would revert back to 15.7 ft/hr if

the operator resumes drilling at 4,700 lbf/in.

23.2.' EqsMoore

ft/hr9.7=R(assumes R W)


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Example 2.11 - Fig. 2.46

At 8,300 ft (under normal conditions);

increase the ECD from 9.6 to 10.1 ppg.

In response, the drilling rate decreases from

20.5 ft/hr to 18.5 ft/hr

What is the shale compaction coefficient, c?

2211 loglog RRcc 24.2.Eq

How much should we increase the mud weight? (Moore)


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Solution

ECD changes from 1= 9.6 to 2= 10.1 ppgCalculate c, the shale compaction coefficient

(9.6)clog 20.5 = (10.1)

clog 18.5

(10.1/9.6)c= log 20.5 / log 18.5 = 1.035

c * log 1.052 = log 1.035

c = 0.679

2211 loglog RRcc

Now use Eq. 2.24 to calculate therequired change in mud weight

c

R

R

1

2

112

log

log

2

1

1

2

log

log

R

Rc =

47.1

2

112

log

log

R

R

gal

lb1.10


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Example 2.12

At 9,090 ft the normal

penetration rate is 16.5ft/hr

Actual penetration rate is

18.0 ft/hr, using a mud

weight of 9.6 ppg

Normal MW = 8.3 ppg

16.5

Fig. 2.46

9,090

47.1

2

112log

log

R

R

ppg0.105.16log

0.18log6.9

47.1

2 =

=

p= 8.3 + 0.4 = 8.7 ppg = (10.0 - 9.6) = 0.4 ppg


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Other predictors of

abnormal pressure

Drilling rate is not the only available

predictor of abnormal pressure.

Properties of shale cuttings can be

used:


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Shale density

Transition

OffshoreNigeria

_shaledensityfrom Boatman

n o - g/cm3Density - g/cm3


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Example

2.15

n =2.54

o = 2.44

pp_14,000 = ?


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Solution

At 14,000, n = 2.54 and o = 2.44 g/cm3

so, = 0.1 g/cm3

From Fig. 2.48:

p14,000 = 0.052*14.6*14,000

p14,000 = 10,629 psig


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shale densityfrom Boatman


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Shale density measurement

1. Fill a standard API

mud balance with

shale cuttings (wash

and dry with a towel)until balance reads

8.33 ppg.

2. Fill the cup to top

with water and

record reading

(e.g. 13.3 ppg).

8.33

Calculate S.G. of shale

cuttings:

S.G. = 8.33/(16.66 - 13.3)

S.G. = 2.48


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Possible Sources

of Gas in aDrilling Fluid

Drilled gas,

Produced gas

Recycled gas

Contamination gas


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Drilled gas, cuttings gas, or liberated gas refers to

gas released from rock cuttings generated by the bit.

Usually small volumes. Increasing MW will not help.

Produced gas refers to gas which enters the wellbore

from the walls of the hole. Increasing MW will reducethe quantity.

Recycled gas is any wellbore gas that remains in the

mud after at least one pass through the surface

equipment.

Contamination gas is gas released from any volatile

hydrocarbons intentionally added to the system (mud

additives).

Possible Sources of Gas in a Drilling Fluid


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Gas in Mud

Connection gas - gas that has enteredthe wellbore when pumps are shut down

to make a connection, can be detected in

a gas trap.

Trip gas - gas that entered the wellbore

during a trip; can also be detected.

Background gas - gas baseline

concentration in the mud usually small.


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Example 2.17

Determine the density of the gas-cutmud returns from a well at a depth of 2 ft

below flowline outlet if:

Clean MW = 12.0 ppg

Flowline MW = 7.0 ppg

Atmospheric press = 14.7 psia

Sample temperature = 100 deg F

Gas gravity = 0.6


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Solution At the Surface

From Eq. 1.22,

g = g * p/(2.77 * Z * T)

g,surface = 0.6*14.7/(2.77*1*560)

g,surface = 0.00569 ppg


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Solution At the Surface

From Eq. 2.26,

gm = m (1 - fg) + g fg

fg = ( m - gm)/ ( m - g)

= (12.0 7.0/(12.0 - 0.00569) = 0.417

This is the gas fraction at the surface, but

fg varies with depth.


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Solution contd

By definition, fg = Vg /(1+Vg)

so, Vg = fg / (1- fg), but, pV = ZnRT

n = fg *p / [ ZRT(1- fg )]

n = 0.000234 lb-moles/gal of mud

This parameter stays constant with depth

provided the downhole gas entry rate

remains constant.


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Assuming the density of the mud-gasmixture does not change appreciably

over two ft of depth.

p2ft = 14.7 + 0.052 * 7.0 * 2

= 15.43 psia

g,2ft = 0.6 * 15.43 / (2.77 * 1 * 560)

= .00597 lbm/gal

Solution 2 ft down


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fg,2ft = [(1 * 0.000234 * 80.275 * 560) / 15.43]

[1+(1 * 0.000234 * 80.275 * 560) / 15.43]

fg,2ft

= 0.405 (down from 0.417 at the surface)

2ft = 12 * (1 - 0.405) + 0.00597 * 0.405

2ft = 7.14 ppg

This is an increase of 0.14 ppg in just 2.

See Fig. 2.51 for plot of entire range

Example 2.17 contd


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Clearly most of the

gas expansion is

near the top of thewellbore.

At 10,000,

MW = 11.9+ ppg.What is the

resulting reduction

in BHP due to the

gas?


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Example 2.18

What is the total change in HSP at the

bottom of the well described in Ex. 2.17?

Average temperature is 150 deg F.

From Eq. 2.28

( ) +

= ssgm

ssg

____

sgreduc

p

ppln

TZf1

TZpfp


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In the annulus, without, gas

BHP = 12 * 10,000 / 19.25

= 6,233.8 psig

BHP = 6,248 psia

Average pressure = (14.7 + 6,248) / 2

= 3,131 psia

From Fig. 1.6, Zavg = 0.868

Example 2.18 contd


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Example 2.18

contd

If pgm = 6,248 psia, then

pred = 60 psi

pgm = 6,248 - 60 = 6,188 psia

EMW = (6,188 14.7) / (0.052 * 10,000)= 11.87 ppg

( ) + 7.14 7.14248,6ln560*1*417.01 610*868.0*7.14*417.0 sreducp

( )

+

=s

sgm

ssg

____

sg

reducp

ppln

TZf1

TZpfp


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Gas cut mud

A second iteration is generally notnecessary if the assumed value for pgm is

reasonably close to the calculated

value.

Furthermore, adding gas to a drillingfluid will increase viscosity, so the

annular friction drop will increase,partially off-setting any reduction in BHPdue to gas.


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Gas cut mud

Another factor that will tend to offset the

reduction in mud density is drilled

cuttings.

At a moderate to high drilling rate, the

quantity of cuttings present in the mud

at any time, may be significant.


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Gas in mud

Gas in mud is monitored as the mudexits the flowline. A gas trap is placed

to sample the gas before the mud

passes over the shale shaker.

The gas concentration is recorded in

arbitrary gas units.

Look for relative changes.


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Gas detection unit

Gas detectorlocated in

the shale shakers

possum belly.

BBG = Background gas

This is the baseline gas

concentration in the mud,

and is usually in the orderof a few gas units.

CG = Connection Gas


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CG = constant

BGG = constant

Overbalanced

CG increases

BGG increases

Underbalanced

CG increases

BGG constant

?

CG increases

BGG increases

Transition zone


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Measuring Surge Pressure

Swab pressure is

hard to measure, but

surge is not.

Run one stand of pipein hole at constant

velocity.

Repeat at different

velocities.

Plot surge pressure

vs. pipe velocity.

Mud Level

Flowline

Closed Safety Valve

Pressure Recorder Sub

Drillpipe


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Measuring Surge Pressure

By assuming

surge = swab,

we can predict

the swabpressure at

different pipe

pulling speeds.

Surge/S

wabPressur e

,psi

Pipe Velocity, ft/sec

E l


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Example

67 sec/std

59 sec/std

48 sec/std

452 min-units

1,036 min-units

2,132 min-units


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Example

Estimate the pore pressure at TD if

MW = 11.7 ppg

The length of each stand is 90 ft.

V1 = 90 ft / 48 sec = 1.88 ft/sec

V2 = 90 / 59 = 1.53 ft/sec

V3 = 90 / 67 = 1.34 ft/sec


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Example

From Figure:

p1 = 405 psi

p2 = 300 psi

p3 = 242 psi

Surge/S

wab

Pressur e

,psi

Pipe Velocity, ft/sec


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Example

From Figure, plotof gas units vs.swab pressure,

when line isextrapolated tozero velocity (zerogas), overbalance

is found to be 197psi

197

0

Pressure, psi

GasUnits


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Example

With an overbalance of 197 psi:

Pore pressure = MW - (overbalance)

0.052 * TD

Pore pressure = 11.7 - (197 / 0.052 * 13,600)

pp = 11.4 ppg.


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Changes in drilling fluid properties

Gas in mud

reduced density

increased viscosity

Salt water inflow chloride content


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Salt water inflow

Chloride content

Flocculation of sodium bentonite clay increases yield point

increases gel strength

increases water loss

poor filter cake

pH change



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Drilled rock salt can have similar effect

CO2 and H2S may reduce pH

H2S is very poisonous and is corrosive

Raise pH and precipitate out any solublesulfides using scavengers.


Temperature and abnormal press


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Temperature and abnormal press.

Geothermaltemperature

vs. depth

Undercompacted rockLower thermal conductivity

Rock conducts heat better

than pore fluid

Poor conductivityrequires higher

temperature

gradient to maintain

constant heat flux.


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Temperature indicators

Temperature gradient tends to increasewithin a pore pressure transition

Rock grains have a much higherthermal conductivity than pore fluids

Well planning predictions may beassisted by downhole temperaturemeasurements in offset wells

T t i di t


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Temperature indicatorsNote that wellbore

circulation of fluids will

distort the true

temperature profile.

The drilling fluid

temperature increases asthe fluid moves down the

drillpipe.

As fluid enters the annulus

its temperature increasesfor a short while.

Higher up the annulus

temperature decreases

Fl li t t f N th S ll


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Flowline temperature from a North Sea well

Predictable increase in

temperature of mud returns as

depth increases

A deviation from

the normal

temperature trendmay signal

abnormal pore

pressure

Important tool if

no shales are

present


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Hole Conditions

Drilling torque when rotating pipe, and

drag during trips or connections, result

from friction between the drillstring or bitand the walls of the hole.

Torque and drag (T&D) will generally

increase with depth, gradually.


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Hole Conditions

A sudden increase in T&D may becaused by hole instability.

Circulate bottoms up and observesamples.

If abnormal pressure caused anincrease in T&D, the rock samples willhelp to tell the story.


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Sample Shale Cuttings

Normally pressured shales Abnormally pressured shales

Documents

7B. Other Abnormal Pressure Detection Methods