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Pore Pressure Determination Methods


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Overpressure situation can be created in both clastic and non-clastic reservoirs when at some depth the formation pressure exceeds what is expected for a hydrostatic (normal/lithostatic) pressure scenario. Likewise an underpressure situation has also been reported from reservoirs after sufficient hydrocarbons have been extracted. Over- and underpressure can develop by both tectonic (e.g., horizontal or vertical stress) and atectonic processes (e.g., mineral phase change, kerogen maturation). Presence or withdrawal of water (saline and freshwater) and hydrocarbon can produce over- and underpressure. Fracture pressure and its gradient are important in planning well-drilling programmes. Pore pressure estimation has become an active field of research in the present day oil industry and several methods exist for such estimation.
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Pore Pressure Determination
Overpressure situation can be created in both
clastic and non-clastic reservoirs when at
some depth the formation pressure exceeds
what is expected for a hydrostatic (normal/
lithostatic) pressure scenario. Likewise an
underpressure situation has also been reported
from reservoirs after sufcient hydrocarbons
have been extracted. Over- and underpressure
can develop by both tectonic (e.g., horizontal
or vertical stress) and atectonic processes
(e.g., mineral phase change, kerogen matura-
tion). Presence or withdrawal of water (saline
and freshwater) and hydrocarbon can produce
over- and underpressure. Fracture pressure
and its gradient are important in planning
well-drilling programmes. Pore pressure esti-
mation has become an active eld of research
in the present day oil industry and several
methods exist for such estimation.
3.1 Introduction
This chapter mainly deals with the basic aspects
required for pore pressure understanding/
calculations starting from normal pressure to
abnormal pressure scenarios. The estimation of
pore pressure is important for well planning. In wild
cat exploratory wells pore pressures are estimated
using the seismic velocities whereas in known
areas, offset welldata including information of logs,
cuttings, seismic velocities help in building pore
pressure curves to avoid events such as blow-outs
while drilling.
In porous formations, the uid pressures in the
pore spaces dene the pore pressure. There is a
huge variation in pore pressure, right from
hydrostatic pressure and beyond, and also in
overpressure scenarios. The different causal
mechanisms of pore pressure generation along
with the different methodologies/techniques are
highlighted in this chapter.
3.2 Normal Pressure
Hydrostatic/lithostatic/normal pressure (Zhang
2011) is the pressure exerted by the height of
column of water/rockon the formation under
consideration (Donaldson et al. 2002).
ρh =ɣw X h ð3:1Þ
hydrostatic pressure (lb/ft
specic weight of water (lb/ft
h height of column of water (feet).
The hydrostatic pressure gradient is referred
to as G
Gh =ɣw /144 ð3:2Þ
Abnormal pore pressure is a pressure that
differs from the hydrostatic pressure whereas
©Springer Nature Switzerland AG 2020
T. Dasgupta and S. Mukherjee, Sediment Compaction and Applications in Petroleum Geoscience,
Advances in Oil and Gas Exploration & Production,
overpressure is the situation when the formation
pore pressure exceeds normal pressure (Zhang
2011). The pore pressure prediction principle
works based on Terzaghis and Biots effective
stress relations (Biot 1941; Terzaghi et al. 1996).
According to this theory, the pore pressure is a
function of total stress or overburden stress and
effective stress. The simple expression relating
overburden stress, effective vertical stress and
pore pressure is
P pore pressure
overburden stress
effective stress
athe Biot effective stress coefcient.
Commonly a= 1 is taken (Zhang 2011).
The combined pressure effect of grain to grain
matrix and the uid present in it causes the
pressure to be 1 psi/ft (0.2351 kg/cm
According to Swarbrick and Osborne (1998) the
lithostatic pressure gradient reaches 0.7 psi/ft at
very shallow depth with 6070% porosity.
If the overburden stress and the effective
stress are known pore pressure can be calculated
by Eq. 3.3. In relatively younger basins the pore
pressure prole resembles that of Fig. 3.1 where
up to 2000 m the pore pressure is nearly hydro-
static. As shown in Fig. 3.1, effective stress is the
difference between overburden stress and pore
3.3 Overpressure
According to Dickinson (1953), overpressure
corresponds to the formation pressure when it is
more than hydrostatic pressure with water or brine
in the formation (Fig. 3.2). In a disequilibrium
state, the uid retention capability of the imper-
meable beds leads to overpressure scenarios
(Swarbrick et al. 2002). These highly overpres-
sured zones are often termed as the abnormally
high formation pressured zones(AHFPs) (Don-
aldson et al. 2002). The pressure in such reservoirs
develops when an impermeable zone exists and
the AHFP zones are isolated. These barriers may
be due to chemical and/or physical processes
(Louden 1972). Overpressure develops by many
processes such as (i) sediment compaction
(Mukherjee and Kumar 2018), (ii) tectonic com-
pression, (iii) faulting, (iv) diapirism (Mukherjee
et al. 2010; Mukherjee 2011), (v) mineral phase
change, (vi) kerogen maturation and hydrocarbon
generation, (vii) osmosis etc. (Swarbrick and
Osborne 1998; Donaldson et al. 2002). Any
combination of these processes causes physico-
chemical changes in pore pressure generation
(Fertl 1976).
Pore pressure information is very critical for
well planning and drilling. Drillers study the pore
pressure gradient as it is convenient for calcu-
lating the mud weight. Three types of studies are
made, i.e., pre-drill, during drilling and post well
pore pressure analyses (Zhang 2011).
Worldwide overpressured zones are present in
both carbonate and clastic reservoirs (Swarbrick
and Osborne 1998). According to Hunt (1990),
180 basins are overpressured in America, Africa,
Middle East, Far East, Europe, Australia, Asia
and the age of the rocks range from Pleistocene
to Cambrian. Overpressures are often associated
with hydrocarbon bearing reservoirs, such as the
Fig. 3.1 Typical hydrostatic pressure, pore pressure,
overburden stress in a borehole well (Zhang 2011)
20 3 Pore Pressure Determination Methods
deeper and highly overpressured reservoirs con-
taining oil and gas in the Northern and Central
North sea (Swarbrick and Osborne 1998). Law
et al. (1998) stated that in US Gulf coast seven
highly overpressured Jurassic to Recent strati-
graphic zones.
3.4 Underpressure
When the pore pressure is less than the hydrostatic
pressure (Fig. 3.2), underpressure scenarios
develop (Swarbrick and Osborne 1998) and are also
termed abnormally low formation pressures
(ALFPs), (Donaldson et al. 2002). Underpressure
reservoirsare mostly encountered after depletion of
oil and gas after production. Naturally underpres-
sured reservoirs also exist, particularly in Canada,
U.S.A. and Alberta. In many regions, uid with-
drawal produced subsidence such as the Po delta of
Italy, Bolivar coast of Lake Maracaibo (Vene-
zuela), Galveston Bay (Texas), Taiwan, Long
Beach, California, etc.
Fracture pressure is the pressure, which
develops fractures in the lithological unit and
ultimately results in mud loss in the borehole
(Zhang 2011). Fracture gradient is to be known
during well planning and drilling, which helps to
design the mud weight. Fracture gradient is
obtained by dividing the true vertical depth by
fracture pressure. Tensile fractures tend to form
in the borehole if the mud weight exceeds the
formation pressure leading ultimately to mud
losses. Leak off test (LOT) helps in determining
the ultimate fracture pressure and is a pre-drilling
According to Swarbrick and Osbrone (1998),
overpressure formation can be explained by four
aspects of rocks and uids: (i) causal mecha-
nisms, (ii) sealing capacity of the rock can be
explained by rock permeability, (iii) uid type,
and (iv) timing of the evolution or rate of ow.
(i) Causal mechanism: The extent of over-
pressure generation mechanism depends
upon causal mechanism and can be grouped
into three categories:
1. Stress related mechanism, which mainly
reduces the pore volume:
(a) Vertical stress related mechanism
categorized mainly as disequilibrium
(b) Lateral stress related mechanism:
mainly tectonic stresses.
2. Increase in uid volume:
(a) Aquathermal processes.
(b) Oil to gas cracking.
(c) Hydrocarbon generation resulting in
an increase in uid volume.
(d) Mineral transformation.
3. Fluid movements, buoyancy related
(a) Osmosis.
(b) Hydraulic head.
(c) Density contrasts resulting in
Fig. 3.2 Pressure versus depth plot showing overpres-
surezones when the pressure is more than hydrostatic.
Underpressure zonesdevelops when the pressure is less
than the hydrostatic pressure (Swarbrick and Osborne
1998; Swarbrick et al. 2002)
3.3 Overpressure 21
The above mentioned causal mechanisms are
explained in Table 3.1 (Swarbrick and Osborne
(ii) Sealing capacity of the rock in relation to
dynamic property like permeability: Rock
permeability depends on size and shape of
grains and on the tortuosity of uid ow,
and on the dynamic viscosity and density
(therefore also kinematic viscosity, which
equals dynamic viscosity divided by den-
sity) of the uids. Overpressure generation
in non-reservoir rocks such as shale is
mainly because of uid retention in such
rocks also referred as seals/cap rocks in
hydrocarbon geosciences. The overpres-
sure can be dissipated by either fracturing
or connecting porous media in between.
Byerlee (1993) mentioned overpressure
dissipation by tectonic activities such as
fault reactivation. Hydraulic fracturing is
possible in rocks if the overpressure extent
reaches the fracture gradient and releases
the amount of stored uid that ultimately
releases the pressure (Engelder 1993).
(iii) Fluid type: The most common uid
occurring in nature is water, which could
be either fresh or saline. Hydrocarbons are
always associated with water and their
ow depends on the hydrocarbon compo-
sition, temperature in the in situ condi-
tions, hydrocarbon saturation and the
relative permeabilities of the uids.
Buoyancy has an inverse relationship with
density and the capillary pressure controls
the entry pressure and relative permeabil-
ity and also the effective sealing capacity.
Gas and light to medium oil are lighter
than water and this leads to overpressure
(Fig. 3.3) (Osborne and Swarbrick 1997).
(vi) Timing and rate: Overpressure develop-
ment depends upon the rate at which a
system develops a non-permeable situa-
tion mostly in non-reservoir rock or pres-
ence of a shale zone. Swarbrick and
Osborne (1998) stated that overpressure in
a system involves dynamic processes
where the rst stage is the overpressure
buildup phase during its generation and
later with time there is overpressure
Table 3.1 Different overpressure generation mechanisms, tabulated in different categories. Modied after (Swarbrick
and Osborne 1998)
Stress related Fluid volume increase mechanisms Fluid movement and buoyancy
Disequilibrium compaction (vertical
loading): Disequilibrium between
uid expulsion rate and sediment
compaction due to fast burial. Fluids
cannot be expelled and leads to
Temperature increase: Thermal
expansion of water
Osmosis: Large contrasts in the
formation uids from dilute to
saltier water across a semi
permeable membrane
Lateral compressive stress:
Incomplete dewatering on reduction
of pore volume by horizontal
Mineral transformation: smectite
dehydration (Powers 1967) stated
two to three pulses of water can
signicantly lead to overpressure in
completely sealed sediments
Gypsum to Anhydrite
dehydration-loss of bound water
Smectite-lllite transformation:
Volume of water is released from
smectite to illite
Hydraulic head: Recharge area
pressure is exerted if it is overlain
by seal
Hydrocarbon generation: Volume
increase during kerogen maturation
during both oil and gas generation
22 3 Pore Pressure Determination Methods
dissipation when there is leakage, as hap-
pens in shales. They also stated that the
present scenario of an overpressured basin
may depend on the present stress distri-
bution of the area.
3.5 Pore Pressure Estimation
Pore pressure estimation started becoming pop-
ular after the work of Hottman and Johnsons
(1965), which was referred in the review by
Zhang (2011). Hottman and Johnson (1965)
studied the Oligocene and Miocene shales of
Upper Texas and Louisiana Gulf coast. They
plotted the sonic data against depth and found
that porosity decreases with depth. This is a
general phenomenon of normally compacting
sediments (normal compaction trend). Any
data that deviates from this normal compaction
trend line represents the abnormal zone with high
uid pressure.
Any attribute relating the change in pore
pressure is used as pore pressure indicator. The
estimation procedures involve two main approa-
ches (Bowers 2001).
(i) Direct method: Two direct methods are
commonly used, i.e., the Hottman and
Johnson (1965) method and overlay method
by Pennebaker (1968). These methods relate
the deviation of the pore pressure indicator
from the normal compaction trend line.
(ii) Effective stress methods: It works on the
Terzaghis principle where the difference
between the total conning stress and
the pore pressure controls the compaction of
the sediments. It corresponds to the total
stress carried out by mineral grains. These
methods involve computational methods in
three steps. (A) Effective stress (r) calcula-
tion from pore pressure indicators, (B) bulk
density is used to calculate the overburden
stress, (C) pore uid pressure (PP) is
obtained from the algebraic difference
between overburden stress and effective
stress, as mentioned earlier in this section.
Late 1960s onwards all the pore pressure
methods are based on effective stress methods
and these are broadly divided into three cate-
gories (i) Vertical methods, (ii) Horizontal
methods, and (iii) Other methods. We will very
briey mention below the rst two methods.
(i) Vertical Methods: Foster and Whalens
(1966) Equivalent Depth method where the
normal compaction trend value is used as
the same as the pore pressure indicator
value (Fig. 3.4).
Fig. 3.3 Maximum pressure generation due to hydrocar-
bon buoyancy in North Sea (Swarbrick and Osborne 1998)
3.4 Underpressure 23
(ii) Horizontal Methods: Eatons method
(Eaton 1975) is one of the horizontal
methods where the effective stress is cal-
culated from the normal trend at the depth
of interest (Fig. 3.4).
The classication of different pore pressure
estimation methods is given as follows.
(a) Direct method by Hottman and Johnson
and the Equivalent depth method
This methodology commonly deals with the
departure of the pore pressure gradient from the
normal velocity trend. This departure is empiri-
cally correlated and thus is not affected by pore
pressure generation processes (Bowers 1995).
The Hottman and Johnson (1965) analysis can be
explained in terms of an X and a Y-axis
(Fig. 3.4), where the X-axis represents the nor-
mal compaction trend, and the Y-axis the pore
pressure gradient. This methodology is used for
both sonic as well as resistivity data.
For resistivity data the equation is
X¼Rn=R;Y¼Pore pressure gradient (psi=ft)
For sonic data the equation becomes
Y¼Pore pressure gradient (psi=ft) ð3:5Þ
Subscript nvalue of normal trend.
Pore pressure development is not the same in
every geological setting. Mathews and Kelly
(1967) found that the chart for every area is
different. The relationship of sonic and resistivity
data in relation to the pore pressure gradient for
different areas are shown in Figs. 3.5 and 3.6,
Eaton (1972) and Lane and Macpherson
(1976) made a suggestion regarding the Hottman
and Johnson method: the results or the output can
Fig. 3.4 Vertical and
horizontal methods of pore
pressure estimation. Pore
pressure indicator is used as
the same value as the normal
trend (point A) in vertical
method of pore pressure
estimation. Whereas, in
horizontal method, the
effective stress data is
estimated from the normal
trend (point B) (Bowers 2001)
24 3 Pore Pressure Determination Methods
be more accurate if the data of overburden gra-
dient is also used as an input. The H&J crossplots
vary with the overburden gradient and this is
particularly important in areas where the water
depth and salt thicknesses changes within few
Another form of Hottman and Johnson data
was represented by Gardner et al. (1974):
Fig. 3.5 Pore pressure
versus resistivity crossplot
(Owolabi et al. 1990)
Fig. 3.6 Published pore
pressure crossplots for sonic
transit time (Owolabi et al.
3.5 Pore Pressure Estimation Methods 25
Pf¼rvavbðÞA1B1ln DtðÞ
formation uid pressure (psi)
normal overburden stress
gradient (psi/ft)
bnormal uid pressure gradient
Z depth (ft)
Dt sonic transit time (µs/ft)
A, B
A1 = 82,776, B1 = 15,695.
(b) Pennebaker
Pennebaker (1968) predicted pore pressure from
seismic velocity. He computed the pore pressure
from X-Y crossplot similar to that of Hottman
and Johnson.
X¼Dt=Dtnand Y is the pore pressure gradient
The approximate equation of the crossplot is
Y¼1:017 0:531 X5:486 ð3:8Þ
Pennebakers relations were based on the well
data of Lousiana Gulf coast and Texas. He
assumed that for similar rock type, the normal
trend of interval transit time when plotted against
depth is the same. With change in geological age
and lithology, transit time would shift. Thus he
proposed a single trend line usage for lithology
worldwide. However, it was understood later that
a single trend cannot be used for all types of
(c) Vertical effective stress methods
This method assumes that in the case of both
normally pressured and abnormally pressured
scenarios, compaction takes place as a function
of effective stress (Fig. 3.7; Bowers 1999).
Sometimes, normally pressured and over-
pressured sediments may not follow the same
effective stress relationship and Fig. 3.8 shows
that the pore pressure can be under-estimated by
the effective stress relationship.
(d) Equivalent depth method
The effective stress can be graphically solved by
the equivalent depth method. From Fig. 3.6a the
intersection of the vertical projection of the pore
pressure and its normal trend, point A as indi-
cated in Fig. 3.6 is termed as equivalent depth
hydrostatic normal pore pressure at point
Overburden pressure at point B
Overburden pressure at point A.
The equivalent depth method was rst used by
Foster and Whalen (1966). Later Ham (1966)
used this method with sonic, resistivity and
density data.
(e) Mean stress equivalent depth
The modied version of equivalent depth was
proposed by Traugot (1997). He dened:
mean effective stress
rvertical effective stress
minimum horizontal stress
maximum horizontal effective stress.
(f) Bellotti and Giaccas approach
Sonic wireline data is less sensitive to hole size
variation, formation temperature and salinity of
formation water, Fertl (1976) chose sonic data
for pore pressure estimation. Out of the two sonic
26 3 Pore Pressure Determination Methods
based pore pressure estimation methods dis-
cussed in this part, one is by Bellotti and Giacca
(1978) and the other one is by Hart et al. (1995).
V¼Vmin þVmaxr=ArþBðÞð3:11Þ
minimum and maximum sonic
velocity of the rock matrix, respectively
A, B additional calibration parameters
Rvertical effective stress.
ðÞB=Vmax AVVmin
The density-velocity relation was also estab-
lished by Bellotti and Giacca (1978) and derived
Fig. 3.7 Vertical effective stress methods (Bowers 2001)
Fig. 3.8 Scenario where vertical effective stress method fails
3.5 Pore Pressure Estimation Methods 27
the following equation for density from interval
transit data.
1:228 qmax qf
Zhang (2011) reviewed methods on pore
pressure prediction. Different methods on pore
pressure estimation methods from (interval)
transit time were also included.
(g) Eatons(1975) method
Sonic compressional transit time is used to pre-
dict pore pressure:
Ppg ¼OBG OBG Png
interval transit time for the normal pressure
in shales
Dt transit time of shale.
Zhang mentioned that Eq. 3.14 has a working
limitation in those petroleum basins where the
pore pressure generation is due to secondary
mechanism (Detail in Chap. 4).
(h) Bowers(1995) method
A power relationship between sonic velocity and
effective stress is presented:
Vp¼Vml þArBe ð3:15Þ
compressional wave velocity
mudline velocity
parameters which are calibrated with
offset velocity and the effective stress
data. V
is generally taken as
1520 ms
: equivalent to velocity near
the sea oor. Using the equation
p, the velocity dependent
pore pressure can be derived from:
ðÞ ð3:16Þ
The values A = 1020 and B = 0.70.75 are
taken from the Gulf of Mexico wells and the units
for pressure measurements (p) and the effective
stress r
are in psi. Velocities v
and v
are in
ft s
. The most common velocity measurement in
wireline logs is sonic and it is in the form of transit
time, the above Eq. 3.16 can be expressed in
transit time by substituting the velocities v
/Δt and 10
, respectively.
The mudline compressional transit time is
generally denoted by Δt
and the value
is *200 µsft
To address the effect of unloading effect,
Bowers (1995) introduced an empirical equation:
Vp¼Vml þArmaxðre=rmax Þ1=UÞ
U parameter representing uplift of the
rmax ¼ðVmax Vml=AÞ1=Bð3:19Þ
and V
are effective stress and veloc-
ity respectively and represent the starting point of
unloading and the pore pressure for the unload-
ing case can be estimated from the
Pulo ¼rvVpVml=A
where P
represents the pore pressure due to
unloading behaviour (Zhang 2011).
(i) Millers method
This method shows an inter-relation between
velocity and effective stress and this relationship
can be used to correlate thesonic/seismic transit
28 3 Pore Pressure Determination Methods
time to formation pore pressure (Zhang 2011).
The pore pressure can be obtained from:
 ð3:21Þ
sonic interval velocity with the shale
14,000 to 16,000 ft s
compressional wave velocity at a particular
depth and the rate of increase of velocity
with effective stress is normally taken as
0.00025. Another important parameter that
controls the occurrence of unloading is the
maximum velocity depth(d
). If d
is less than the depth (Z) and there is no
unloading (overpressure generated due to
secondary mechanisms) then the pore
pressure can be estimated from Eq. 3.21.
If unloading happens where the d
then the pore pressure is:
Pulo ¼rv1
kln am1VpVulo=VmVml
ratio of the loading and unloading
velocities in the effective stress curves r
where the values a
= 1.8 and a
and V
is the velocity where
unloading begins. r
represents the
effective stress due to unloading of the
sediment (Zhang 2011).
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... The mechanisms for overpressure developed in sedimentary basins are commonly classified into disequilibrium compaction, tectonic movement, buoyancy, overpressure transfer, hydrothermal pressuring, hydraulic head, hydrocarbon generation, and diagenesis [9,12,30]. However, marine sediments are water-saturated, and the sediment pores are generally hydraulically connected in the longitudinal direction. ...
... The overpressure developments associated with chemical and biological processes are closely related with temperature, sedimentary history and rate. Therefore, these factors should also be taken into account [30]. ...
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Overpressure is widely developed in marine sediments; it is not only a critical factor related to hydrocarbon accumulation, but also a serious safety issue for oil/gas exploration and exploitation. Although the mechanisms for overpressure development in sedimentary basins have been intensively studied, some new mechanisms are proposed for overpressure development with the advancements in marine geological investigation, e.g., natural gas hydrate formation and microbial activity. In this study, the mechanisms for overpressure development are reviewed and further classified as being related to associated physical, chemical, and biological processes. The physical overpressure mechanisms include disequilibrium compaction, hydrate formation sealing, degasification, buoyancy, hydrothermal pressuring, tectonic movement, overpressure transfer, etc. The chemical overpressure mechanisms are ascribed to hydrate decomposition, diagenesis, hydrocarbon generation, etc. The biological overpressure mechanisms are mainly induced by microbial gas production and microbial plugging. In gas hydrate-bearing sediments, overpressure is a critical factor affecting the formation and distribution of gas hydrate. The mechanisms for overpressure development in marine gas hydrate systems are associated with permeability deterioration due to hydrate formation and free gas accumulation below bottom-simulating reflectors (BSR). In marine sediments, overpressure developments are generally related to a sediment layer of low permeability above and natural gas accumulation below, and overpressure is mainly developed below a sulphate–methane interface (SMI), because methane will be consumed by anaerobic oxidation above SMI.
... (1) Effective stress calculation from pore pressure indicators, (2) bulk density, calculation of the overburden stress. (3) The difference between overburden stress and effective stress gives pore fluid pressure (Das and Mukherjee 2020;Radwan and Sen 2021). Bowers (1995) calculated the effective stress using measured shale pore pressure and overburden pressure (Terzaghi and Peck 1948) and analyzed the corresponding acoustic velocities using the well data in the Gulf of Mexico. ...
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The drilling engineers favor a quantifiable understanding of the subsurface overpressure zones to avoid drilling hazards. The conventional pore pressure estimation techniques in carbonate reservoirs are prone to uncertainties that affect the calculated pore pressure model resolution and are still far from satisfactory. Basically, in carbonate reservoirs, the effect of chemical process and cementation on porosity is more important than the mechanical compaction, so the conventional pore pressure prediction methods based on the normal compaction trend mostly do not provide acceptable results. Using the conventional methods for carbonate reservoirs can yield large errors, even suggesting a reduction in abnormal pressure in overpressure zones where considerable attention must be paid. Conventional methods need to model density and velocity to calculate the effective and overburden pressures. Converting acoustic impedance to density and velocity is always associated with errors and generally provides low resolution, which adds substantial uncertainties to the pressure prediction. Although pore pressure measurements are usually associated with low resolution, additional error-prone steps can be dropped if used directly. This research outlines the pore pressure estimation of a famous Iranian carbonate reservoir using direct acoustic impedance without inverting it to density and velocity. Finally, this method gives acceptable results in carbonate formations compared to the results of the Repeat Formation Test (RFT) in this region. The results show a zone of overpressure between the two low-pressure intervals of the carbonate reservoir. This result can be of great help in determining reservoir boundaries as well as in planning for drilling trajectory for new wells. Furthermore, the pore pressure estimation results also show pressure reduction in the central part of the seismic section. The proposed approach is a viable alternative to the conventional method and is in line with the geological field report, where the ratio of hydrocarbon potential of total rock on the reservoir sides is higher than its middle part. In this study, we want to emphasize that the calibrated function obtained in our area can be used in similar basins with carbonate reservoirs.
... These circumstances cause the overpressured for shales and embedded sands within shales [20]. Overpressure can be generated in clastic (sandstone and shale) and non-clastic formations [49]. Slotnick [50] established that the wave velocity rises with depth. ...
Offset data of oil wells are investigated in detail to determine the rock properties and stresses to construct a one-dimensional mechanical earth model (1DMEM). 1DMEMs are integrated to build a three-dimensional model to characterize the field geomechanical parameters. Besides, uncertainty analysis and history matching are executed on the inputs and outputs, respectively.
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Pore pressure prediction is one of the most critical steps while planning new well delivery activity in exploration fields in order to achieve the well target by delivering a safe well. It is very important to understand the structural and stratigraphic complexity that may influence formation pressure differences in the study area. Also, it is critical to have a range of uncertainty in prediction to mitigate any kind of drilling problems and operational risks. In this case study, the target is to predict the pore pressure gradient for four proposed exploration wells in West Nile Delta Raven field. The workflow has been applied utilizing tilted transverse isotropic seismic velocity and a high-resolution full waveform seismic inverted velocity. It is important as well to compare different methodologies where each one will have its own limitations. A manually picked normal compaction trend with the conventional Eaton pressure transform method was applied and compared with a BP internal normal compaction trend with a modified Eaton (Presgraf) pressure transform method in the Predrill prediction. The pre-drill pore pressure is finally compared with the actual measured pore pressure data that yields a good match.
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We deduce algebraic expressions for temperature rise for ideal cases of uniform and spatially varying compression of sediments of single mineralogy. According to the results of the present work, the temperature rise is related to the coefficient of volume expansion, isothermal compressibility, dimension, bulk density and specific heat of the sediment columns. Rise of temperature due to compression of sediment is effectively inversely proportional to the volume coefficient of expansion (or contraction) of sediments. Compression-related temperature rise is expected to augment diagenesis. A more realistic model of temperature rise dealing with the rate of compression of sediments that of the pore fluid(s) and the vacant pore space individually would be required.
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This report sets out the basic methodology for determining pore pressure and fracture pressure in deep water. It also describes a new centroid model and lists ideas for future improvements. Two main points are made: 1) a well drilled directly at the crest of a large overpressured structure is at considerable risk of mechanical failure, and 2) models for pressure prediction require a precise value for overburden pressure.
The application of current knowledge of clay colloid chemistry and mineralogy to the question of how water escapes from muddy sediments suggests two conclusions. (1) The alteration of montmorillonite to illite takes place after deep burial and involves the transfer of large amounts of bound water from montmorillonite surfaces to interparticle areas where it is normal water. This water transfer has an important bearing on the porosity, permeability, abnormal fluid pressure, and initial release of hydrocarbons from mudrocks. (2) In deposits of primary illite, water is compacted out of clay soon after burial, before the formation of hydrocarbons comparable with those found in reservoirs. These points are important in petroleum exploration in new areas because it appears that the development of a shale source rock requires the initial deposition of a montmorillonitic organic mud, and its subsequent alteration to illite after deep burial. Abnormally high fluid pressures may easily be caused by a volume increase associated with the desorption of the last few monomolecular layers of water from montmorillonite during its diagenesis to illite. This understanding of mineralogical characteristics makes it possible to make meaningful interpretations of data on the bulk properties of compacting mudrocks.
After introducing the various stress regimes in the lithosphere, the book shows how their extent in the upper crust is demarcated by direct measurements of four types: hydraulic fracture, borehole-logging, strain-relaxation, and rigid-inclusion measurements. The relationship between lithospheric stress and the properties of rocks is then presented in terms of micro-crack related phenomena and residual stress. Lithospheric stress is also inferred from the analsyis of earthquakes. Finally, lithospheric stress is placed in the context of large-scale stress fields and plate tectonics. -Publisher