4. Introduction
The knowledge of the formations to penetrate,
their strength properties as well as their behaviour
when in contact with various drilling fluids is
essential to properly plan and complete a
successful drilling project. Parameters like pore
pressure and formation strength determine aspects
like:
Choice of mud weight profile,
Determination of casing setting depths,
Design of optimal casing strings,
Selection of the drill bit,
Cementing additives and procedures.
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5. pressures as gradients
The way how the formations react to drilling mud
influences the selection of mud additives, borehole
stability and therefore well control aspects.
Within drilling, it is common to express pressures
as gradients.
With this concept, the hydrostatic pressure can be given
as equivalent density which is independent of the depth
and thus makes its comprehension and correlations of
various concepts easier.
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6. reference depth
On the other hand, when gradients are applied, it
has to be always kept in mind that they are referred
to a specific depth.
Knowing this reference depth is essential to compute
back the corresponding downhole pressures.
Within drilling engineering, the drilling floor or rotary table
(RKB) is the most often used reference depth.
Geologists and geophysicists generally prefer to use their data
in reference to ground floor or mean sea level (MSL).
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7. Geology Prediction
Normally when a well is to be drilled, the drilling
engineer is supplied from the geology department (or
the geologist within the project team) with a sequence
of predicted subsurface formations, their characteristics
and markers, as well as knowledge about where special
care has to be taken.
Geologists draw this information from studying
the local geology (deposition history),
seismic mappings (2D or 3D surveys) and
perform well to well correlations (geological maps).
Whenever new information is gained (due to drilling
and evaluation of a new well or further geophysical
measurements) these maps are updated.
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8. Typical geological profile
to plan a well
Typical geological profile
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Seismic record to determine the subsurface structure
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9.
10. local subsurface pressure regimes
To understand the local subsurface pressure
regimes, the geologic processes along with the
depositional history and tectonic abnormalities
have to be studied.
When the well is located within shallow sediments
that were laid down slowly within a deltaic
depositional environment, the subsurface
formation pressures can be assumed to be
hydrostatic.
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11. Hydrostatic Pressure
By definition, a hydrostatic pressure is developed
due to the own weight of a fluid at a certain depth.
This relationship is expressed as:
𝑝 = 𝜌. 𝑔. ℎ = 9.81. 𝜌. ℎ
Or in field units:
𝑝 = 0.052. 𝜌 𝑓𝑙 . 𝐷
where:
•
•
•
•
•
•
𝜌 𝑓𝑙 [ppg]
𝜌 [kg/m3]
D [ft]
h [m]
p [psi]
g [m/s2]
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density of the fluid causing hydrostatic pressure
average fluid density
depth at which hydrostatic pressure occurs (TVD)
vertical height of column of liquid
hydrostatic pressure
acceleration due to gravity
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12. hydrostatically pressured formation
When the weight of the solid particles buried are
supported by grain-to-grain contacts and the
particles buried water has free hydraulic contact to
the surface, the formation is considered as
hydrostatically pressured.
As it can be seen, the formation pressure, when
hydrostatically pressured, depends only on
the density of the formation fluid (usually in the range of
1.00 [g/cm3] to 1.08 [g/cm3]) and
the depth in TVD.
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13. overburden stress
When the burial depth
increases, the overlaying
pressure (overburden stress)
increases.
This decreases the pore space
between the grains and thus the
porosity of the formation.
The overburden stress can be
calculated assuming an average
bulk density ρb of the
overlaying formations as:
Porosity profile
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14. average bulk density
The average bulk density is normally found by
integration of the density log readings.
When density logs were not run
(e.g. at shallow formations),
sonic log correlation methods,
together with lithology and
mineralogical evaluations are applied to determine 𝜌 𝑏
During burial of the sediments, formation water is
constantly expelled due to the reduction of
formation porosity, as see in next slide.
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15. Volume of fluid expelled during
compaction of an argillaceous
sediment
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16. abnormally pressured
As long as formation water can be expelled, the
formations are hydrostatic (or normally) pressured.
When drilling a well, formations
are often encountered that are under
a different pressure regime.
These formations are named to be
“abnormally pressured”.
Abnormal pressures can be positive
• (actual formation pressures are higher than hydrostatic pressure)
or negative “subnormal pressure”
• (actual formation pressures are lower than hydrostatic pressure).
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17. Abnormally Mechanisms
Some mechanisms that lead to abnormally pressured
formations are:
1. Compaction effects,
2. Aquathermal expansion,
3. Diagenetic effects,
4. Differential density effects (Osmosis),
5. Fluid migration effects,
6. Evaporite Deposits,
7. Organic matter transformation,
8. Tectonics,
9. Connection to depleted reservoirs,
10. Others.
From the various effects mentioned above, the compaction
one is considered to be often the governing one.
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18.
19.
20. normally pressured formations
while burying of the sediments,
formation water is expelled
with increasing depth and temperatures
due to reduction in
pore space and diagenesis of the rock materials.
As long as the permeability and the effective
porosity of the rock is high enough so that the
formation water can escape as quickly as the
natural compaction takes place,
the formations are normally pressured.
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22. abnormally pressured formations
When the formation water can not escape
as quickly as the pore space is reduced,
it is trapped inside the formations.
In this scenario, the increasing overburden stress will
pressurize the formation water and the formation will
become abnormally pressured.
In this situation, the porosity of the formation will not follow
the natural compaction trend (porosity at abnormally
pressured formations will be higher than at normally
pressured ones).
Along with the higher porosity, the bulk density as well as the
formation resistivity will be lower at abnormally pressured
formations.
These circumstances are often applied to detect and estimate
the abnormal formation pressures.
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23. formation pore pressures
The actual measurement of formation pore
pressure is very expensive and possible only after
the formations have been drilled.
In this respect, pore pressures have to be estimated
before drilling to properly plan
the mud weights,
casing setting depths,
casing design, etc.
as well as being closely monitored during drilling.
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24. pore pressure estimation
To estimate the pore pressure and most important,
define where abnormal pore pressures are to be
expected,
porosity logs and
seismic measurements are applied most often.
shale formations tend to follow a defined porosity
reduction trend with increasing depth.
When this trend is interrupted, abnormally pressured
formations are to be expected.
The knowledge of its depths are important since they may
lead to a necessary setting of casing and weighting up the
mud system.
The amount of how much the mud weight has to be increased
depends on the amount of abnormal pressure expected and the
contingency of the well.
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25. Abnormal pressure detection
while drilling
When the well is in progress
and abnormal formation
pressures are expected,
various parameters are
observed and cross-plotted.
Some of these while drilling
detection methods are:
(a) Penetration rate,
(b) “d” exponent,
(c) Sigmalog,
(d) Various drilling rate
normalisations,
(e) Torque measurements,
(f) Overpull and drag,
(g) Hole fill,
(h) Pit level – differential flow
– pump pressure,
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(i) Measurements while
drilling,
(j) Mud gas,
(k) Mud density,
(l) Mud temperature,
(m) Mud resistivity,
(n) Lithology,
(o) Shale density,
(p) Shale factor (CEC),
(q) Shape, size and
abundance of cuttings,
(r) Cuttings gas,
(s) X-ray diffraction,
(t) Oil show analyzer,
(u) Nuclear magnetic
resonance.
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26. Abnormal pressure evaluation
After an abnormal pressure is detected or the well is
completed, various wireline log measurements are used
to evaluate the amount of overpressures present.
Among the most common ones are:
(a) Resistivity, conductivity log,
(b) Sonic log,
(c) Density log,
(d) Neutron porosity log,
(e) Gamma ray, spectrometer,
(f) Velocity survey or checkshot,
(g) Vertical seismic profile.
With these log measurements trend lines are
established and the amount the values deviate at the
abnormally pressured formations from the trend line
are applied to determine the value of overpressure.
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27. Schematic responses of wireline logs
in an undercompacted zone
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28.
29. Leak-off data
Normally, after a casing is set and cemented, a so
called leak-off test (LOT) is performed.
The main issue of a LOT is to check the strength of
the formation at the casing shoe.
With this knowledge,
the maximum kick pressure allowed that
does not fracture the formation is determined.
It is also the key parameter in
stress modelling and borehole integrity evaluation.
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30. leakoff test
A test to determine the strength or fracture pressure of
the open formation, usually conducted immediately
after drilling below a new casing shoe.
During the test, the well is shut in and
fluid is pumped into the wellbore to gradually
increase the pressure that the formation experiences.
At some pressure, fluid will enter the formation,
or leak off, either moving through permeable paths
in the rock or by creating a space by fracturing the rock.
The results of the leakoff test dictate the maximum
pressure or mud weight that may be applied to the well
during drilling operations.
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31. formation integrity test
Sometimes the LOT test is not continued until leakoff (especially when oil based muds are used) and
the formation is only pressured up until a certain
value.
This test is called formation integrity test (FIT).
In this way, when fracture strength is evaluated, it
is important to distinguish LOT data and FIT data.
The pressure where fractures are initiated is
commonly called leak-off pressure and when
referred to the individual depth, named fracture
gradient.
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32. LOT data set groups
Since casings are often set into competent shale
formations and the LOT are carried out at them,
but on the other hand lost circulation often takes
place in permeable sandstone formations,
the evaluation of LOT data to determine fracture
gradients should be carried out by separating the
data into two groups,
one concerning the competent shale formations with
higher fracture gradients and
a second one for permeable sandstone (coal, chalk, etc.)
formations exhibiting weaker fracture gradients.
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33. Horizontal stresses
When the borehole is vertical, as well as a hydrostatic
stress state is assumed, the LOT values can be
expressed as:
LOT [psi] ... leak-off test value
σa [psi] ... average horizontal stress
Po [psi] ... pore pressure
Since when the LOT is carried out, the pore pressure is
known or measured as well, the horizontal stress can be
evaluated by
The horizontal stress as derived above can also be used
for a correlation when plotted vs. depth.
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34. fracture gradient
The pressure where fractures are initiated is
commonly called leak-off pressure and
when referred to the individual depth,
named fracture gradient.
The determination of fracture gradients for shallow
depth is often difficult since very little data exists.
This is due to the circumstance that at shallow depth,
blowout preventers are often not installed and thus no
pressure testing can be carried out.
Especially at offshore wells, the knowledge of shallow
fracture gradients are important since the margin
between pore pressure and fracture gradient is narrow
and the danger of shallow gas pockets exists.
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35. 1. Dipl.-Ing. Wolfgang F. Prassl. “Drilling
Engineering.” Master of Petroleum
Engineering. Curtin University of Technology,
2001. Chapter 3
36. 1. Mud Weight Planning
2. drilling hydraulics:
A. the hydrostatic pressure
