7a. pore pressure prediction

TAMU - Pemex

Well Control

Lesson 7Pore Pressure Prediction

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Contents

Porosity

Shale Compaction

Equivalent Depth Method

Ratio Method

Drilling Rate

dC-Exponent

Moore’s Technique

Comb’s Method

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Pore pressure prediction methods

Most pore pressure prediction techniques rely on measured or inferred porosity.

The shale compaction theory is the basis for these predictions.

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Pore pressure prediction methods

Measure the porosity indicator (e.g. density) in normally pressured, clean shales to establish a normal trend line.

When the indicator suggests porosity values that are higher than the trend, then abnormal pressures are suspected to be present.

The magnitude of the deviation from the normal trend line is used to quantify the abnormal pressure.

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2. Extrapolate normal trend

line

1. Establish “Normal” Trend Line in good

“clean” shale

Transition

Porosity should decrease with

depth in normally pressured shales

3. Determine the magnitude

of the deviation

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Older shales have had more time to compact, so porosities would tend to be lower (at a particular depth).

Use the trend line closest to the transition.

Lines may or may not be parallel.

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D

De

Equivalent Depth Method

The normally compacted shale at depth De has the same compaction as the abnormally pressured shale at D. Thus,

V = Ve

i.e., ob - pp = obe - pne

pp = pne + (ob - obe)

ob = V + pp

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Example 2.6

Estimate the pore pressure at 10,200’ if the equivalent depth is 9,100’. The normal pore pressure gradient is 0.433 psi/ft. The overburden gradient is 1.0 psi/ft.

At 9,100’, pne = 0.433 * 9,100 = 3,940 psig

At 9,100’, obe = 1.00 * 9,100 = 9,100 psig

At 10,200’, ob = 1.00*10,200 = 10,200 psig

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Solution pp = pne + (ob - obe) ……………. (2.13)

= 3,940 + (10,200 – 9,100)

pp = 5,040 psig

The pressure gradient, gp = 5,040/10,200

= 0.494 psi/ft

EMW = 0.494/0.052 = 9.5 ppg

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XnXo

The Ratio Method

uses (Xo/Xn) to predict the magnitude of the abnormal pressure

We can use:

• drilling rate

• resistivities

• conductivities

• sonic speeds

Shale Porosity Indicator

Dep

th

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Pore pressures can be predicted:

Before drilling (planning)

During drilling.

After drilling

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Before drilling the well (planning)

Information from nearby wells

Analogy to known characteristics of the geologic basin

Seismic data

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Table 2.6 – Cont’d

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Seismic Surveys, as used in conventional geophysical prospecting, can yield much information about underground structures, and depths to those structures. Faults, diapirs, etc. may indicate possible locations of abnormal pressures

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Typical Seismic Section

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Under normal compaction, density increases with depth. For this reason the interval velocity also increases with depth, so travel time decreases

t = tma(1-) + tf

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Sound moves faster in more dense medium

In air at sea level,

Vsound = 1,100 ft/sec

In distilled water,

Vsound = 4,600 ft/sec

In low density, high porosity rocks,

Vsound = 6,000 ft/sec

In dense dolomites,

Vsound = 20,000 ft/sec

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Example 2.7

Use the data in Table 2.7 to determine the top of the transition zone, and estimate the pore pressure at 19,000’

using the equivalent depth method

using Pennebaker’s empirical correlation

Ignore the data between 9,000’ and 11,000’. Assume Eaton’s Gulf Coast overburden gradient.

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SolutionPlot interval travel time vs. depth on

semilog paper (Fig. 2.31)

Plot normal trend line using the 6,000-9,000 data.

From Fig. 2.20, at 19,000’, gob = 0.995 psi/ft

(ob)19,000 = 0.995 * 19,000 = 18,905 psig

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Use

Ignore

Equivalent Depth Method:

From the vertical line, De = 2,000’

obe = 0.875 * 2,000

=1,750 (Fig. 2.20)

But,

pne = 0.465 * 2,000

= 930 psig

pp = 930 + (18,905-1,750)

pp = 18,085 psig

tnto

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Pennebaker’s correlation for Gulf Coast sediments

Higher travel time means more porosity and higher pore pressure gradient

Example 2.7 (Table 2.7)

to = 95 sec/ft @ 19,000’tn = 65 sec/ft @ 19,000’

to/ tn = 95/65 = 1.46

pp = 0.95 * 19,000

= 18,050 psig

0.95

Fig. 2.30

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Comparison

Pore Pressure at a depth of 19,000 ft:

Pennebaker:

18,050 psi or 0.950 psi/ft or 18.3 ppg

Equivalent Depth Method:

18,085 psi or 0.952 psi/ft or 18.3 ppg

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While Drilling

dc-exponent

MWD & LWD

Kicks

Other drilling rate factors (Table 2.5)

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TABLE 2.5 -

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Penetration rate and abnormal pressure

Bits drill through overpressured rock faster than through normally pressured rock (if everything else remains the same).

When drilling in clean shales this fact can be utilized to detect the presence of abnormal pressure, and even to estimate the magnitude of the overpressure.

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Note, that many factors can influence the drilling rate, and some of these factors are outside the control of the operator.

TABLE 2.8 -

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Effect of bit weight and hydraulics on penetration rate

Inadequate hydraulics or excessive imbedding of the bit teeth in the rock

Drilling rate increases more or less linearly with increasing bit weight.

A significant deviation from this trend may be caused by poor bottom hole cleaning

0

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Effect of Differential Pressure on Drilling Rate

Differential pressure is the difference between wellbore pressure and pore fluid pressure

Decrease can be due to:

• The chip hold down effect

• The effect of wellbore pressure on rock strength

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Drilling underbalanced can further increase the drilling rate.

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The chip hold-down effect

The mud pressure acting on the bottom of the hole tends to hold the rock chips in place

Important hold-down parameters:

Overbalance Drilling fluid filtration rate

Permeability Method of breaking rock (shear or crushing)

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• Drilling rates are influenced by rock strengths.

• Only drilling rates in relatively clean shales are useful for predicting abnormal pore pressures.

TABLE 2.9 -

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ob is generally the maximum in situ principal stress in undisturbed rock

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Stresses on Subsurface Rocks

ob, H1, H2 and p all tend to increase with depth

ob is in general the maximum in situ principal stress.

Since the confining stresses H1 and H2 increase with depth, rock strength increases.

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Stresses on Subsurface RocksThe pore pressure, p, cannot produce

shear in the rock, and cannot deform the rock.

Mohr-Coulomb behavior is controlled by the the effective stresses (matrix).

When drilling occurs the stresses change.

ob is replaced by dynamic drilling fluid pressure.

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The degree of overbalance now controls the strength of the rock ahead of the bit.

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Rock failure caused by roller cone bit.

The differential pressure from above provides the normal stress, o

Formation fracture is resisted by the shear stress, o, which is a function of the rock cohesion and the friction between the plates. This friction depends on o.

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Fig. 2.41 - Differential Pressure 0.1 in below the bit.

When ob is replaced by phyd (lower) the rock immediately below the bit will undergo an increase in pore volume, associated with a reduction in pore pressure.

In sandstone this pressure is increased by fluid loss from the mud.

(Induced Differential Pressure in

Impermeable rock.

FEM Study)

Vertical Stress = 10,000 psiHorizontal Stress = 7,000 psiPore Pressure = 4,700 psiWellbore Pressure = 4,700 psi

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Drilling Rate as a Pore Pressure Predictor

Penetration rate depends on a number of different parameters.

R = K(P1)a1 (P2)a2 (P3)a3… (Pn)an

A modified version of this equation is:d

bd

WNKR

3

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Drilling Rate as a Pore Pressure Predictor

Or, in its most

used form:

in Diameter,Bit d

lbf ,Bit WeightW

exponentdd

rpmN

ft/hrR

1012

log

60log

b

6

bdWNR

d

d

bd

WNKR

3

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d-exponent

The d-exponent normalizes R for any variations in W, db and N

Under normal compaction, R should decrease with depth. This would cause d to increase with depth.

Any deviation from the trend could be caused by abnormal pressure.

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d-exponent

Mud weight also affects R…..

An adjustment to d may be made:

dc = d (n /c)

where

dc = exponent corrected for mud density

n = normal pore pressure gradient

c = effective mud density in use

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Example While drilling in a Gulf Coast shale,

R = 50 ft/hr

W = 20,000 lbf

N = 100 RPM

ECD = 10.1 ppg (Equivalent Circulating Density)

db = 8.5 in

Calculate d and dc

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Solution

34.1d

554.1

079.2

5.8*10000,20*12

log

100*6050

logd

6

bdWN

R

d

61012

log

60log

c

nc dd

19.1d

1.10*052.0

465.034.1d

c

c

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Example 2.9

Predict pore pressure at 6,050 ft (ppg): from data in Table 2.10 using:

Rhem and McClendon’s correlation

Zamora’s correlation

The equivalent depth method

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TABLE 2.10

d-EXPONENT AND MUD DENSITY DATA FOR A WELL LOCATED OFFSHORE LOUISIANA

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Step 1 is to plot the data on Cartesian paper (Fig. 2.43).

Transition at 4,700 ft?

…or is it a fault?

Seismic data and geological indicators suggest a possible transition at 5,700 ft.

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Fig. 2.43Slope of 0.000038 ft-1

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Rehm and McClendon

gp = 0.398 log (dcn-dco) + 0.86

= 0.398 log (1.18 - 0.95) + 0.86

gp = 0.606 psi/ft

p = 0.606 / 0.052 = 11.7 ppg

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Zamora

From Fig. 2.44

gp = gn (dcn/dco)

= 0.465 * (1.18/.95)

gp = 0.578 psi/ft

p = 0.578/0.052

p = 11.1 ppg

1.180.95

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Equivalent Depth Method

From Fig. 2.20, at 6,050 ft,

gob = 0.915 psi/ft

ob = 0.915 * 6,050 = 5,536 psi

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Equivalent Depth Method

From Fig. 2.43, Equivalent Depth = 750 ft

At 750 ft,

obe = 0.86 * 750 = 645 psi

pne = 0.465 * 750 = 349 psig

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Equivalent Depth Method

From Eq. 2.13, at 6,050 ft pp = pne + (ob - obe)

pp = 349 + (5,536 - 645) = 5,240 psig

p = 19.25 * (5,240 / 6,050) = 16.7 ppg

Perhaps the equivalent depth method is not always suitable for pp prediction using dc !!

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Overlays such as this can be handy, but

be careful that the scale is correct for the graph paper being used;

the slope is correct for normal trends;

the correct overlay for the formation is utilized.

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To improve pore pressure predictions using variations in drilling rate:

Try to keep bit weight and rpm relatively constant when making measurements

Use downhole (MWD) bit weights when these are available. (Frictional drag in directional wells can cause large errors)

Add geological interpretation when possible. MWD can help here also.

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Improved pore pressure predictions

Keep in mind that tooth wear can greatly influence penetration rates.

Use common sense and engineering judgment.

Use several techniques and compare results.

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Moore’s TechniqueFig. 2.45

Moore proposed a practical method for maintaining a pore-pressure overbalance while drilling into a transition.

Drilling parameters must be kept constant for this technique to work.

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Comb’s Method

Combs attempted to improve on the use of drilling rate for pore pressure by correcting for:

hydraulics

differential pressure

bit wear

in addition to W, db, and N

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Comb’s Method

Nd

a

nb

aa

bd tfpf

dd96

q

200

N

d500,3

WRR

qNW

q = circulating rate

dn = diameter of one bit nozzle

f(pd) = function related to the differential pressure

f(tN) = function related to bit wear

aW = bit weight exponent = 1.0 for offshore Louisiana

aN = rotating speed exponent = 0.6 for offshore Louisiana

aq = flow rate exponent = 0.3 for offshore Louisiana

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Tooth wear factor

Correction would depend upon bit type, rock hardness, and abrasiveness

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Differential pressure factor

Method is too complicated and too site specific.