21-10-2016, 01:44 PM
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Abstract
Any method that intends to minimize the uncertainty and enhances the preparedness to deal critical situation has
always drawn attention in subsurface exploration. Showing no exception, in oil and gas drilling industry, pore pressure
prediction has always been of immense importance as it provides insights to deal with probable high pressure zone, which
are capable of creating disasters. The present study is an attempt to minimize such uncertainty in one of the exploration
block of Indian Oil Corporation Limited in Cambay Basin where data availability is limited. With the limited data available
in the nearby wells within the block and outside it, a study has been carried out which indicates the study area is likely to be
in normal hydrostatic pressure regime. Accordingly, all drilling plans have been lined up. However, the model will be
st updated after drilling of the 1 well.
Concept
Formations penetrated during the drilling of an oil and
gas well exhibit pressure which may vary in magnitude
depending on geological setting, depth of occurrence,
location and proximity to other structures.
1. Hydrostatic Pressure
Hydrostatic pressure is defined as pressure exerted by
a column of fluid. This pressure is function of average fluid
density and depth or vertical height of the fluid column.
p is the hydrostatic pressure (Pa),
ρ is the fluid density (kg/m3),
g is gravitational acceleration (m/s2),
Ais the test area (m2),
z is the height (parallel to the direction of gravity) of the
test area (m) &
z0 is the height of the zero reference point of the pressure
(m).
Further simplifying assuming (a) since many liquids can
be considered incompressible, a constant density throughout
the liquid is assumed. (b) Since the height h of the fluid
column between z and z0 is often reasonably small compared
to the radius of the Earth, one can neglect the variation of g.
Under these circumstances, the integral boils down to the
simple formula:
ρ = ρgh,
2. Overburden Pressure
The overburden pressure is defined as the pressure
exerted by the total weight of the overlying formations above
the point of interest. The total weight is the combined weight of the formation solids (rock matrix) and formation fluids in
the pore space. The density of the combined weight is
referred to as bulk density.
A. Methods fordetermining Overburden Pressure
(i) Extrapolated density
Density is extrapolated up to mud line using the
following geometric fit.
a
ρ = ρ + A × (TVD - AirGap - WaterDepth) extrapolated mudline 0
Where
ρ is the density at the sea floor or ground level; mudline
A and aare fitting parameters. 0
(ii) Amoco empirical relation
The average bulk density below the sea floor is estimated
by an empirical equation obtained from statistical data from
the Gulf of Mexico.
a
ρ = ρ + [(TVD - AirGap - WaterDepth)/3125] Amoco mudline
Where ρAmoco is in ppg and all depths are in feet, and
ρ : mud line density in ppg (default 16.33 ppg) mudline
a: exponent coefficient (default 0.6)
(iii) Gardnerdensity from sonic or seismic
b
ρGardner = a × V
Where ρ is in g/cm3 and α and β are two fitting Gardner
parameters named velocity factor and velocity exponent
respectively, Vis sonic or seismic formation velocity in ft/s.
In Gardner's original equation, a= 0.23 and b =0.25
When compressional slowness is provided as an input,
then it is converted into velocity before use in this equation.
) Millerdensity
Miller density is calculated from porosity as follows:
ρMiller = ρmatrix (1 - fMiller) +ρwater fMiller
with :
1
(-k* (TVD - AirGap - waterDepth) N)
f = f +f e Miller a b
and where depth is in ft, bulk density in g/cc and:
ρ : matrix density (default 2.65 g/cc) matrix
ρ : density of pore water (default 1.03 g/cc) water
f : sediment porosity at great depth a
f : sediment porosity fitting parameter equal to mud line b
porosity minus fa
K: porosity decline parameter
N: curvature parameter
(v) Constant density
In this mode, the user can create a density curve which
has a constant value along depth.
B. Overburden stress calculation
The overburden stress is calculated from the bulk density
as below:
TVD
σv
= gò0 ρb
(z)dz
where
- σv
is the vertical stress / overburden stress at depth TVD
- σ is the bulk density (including the water section above b
sea floor.
- g is the gravitational constant.
The input for the overburden stress estimation is the
"best density", which is often a composite log from actual
density measurement and a synthetic density where no
density log is available (RBCP_COMP).
Pore Pressure
Pore pressure is the pressure on the fluids in the pore
spaces of the rock. However, the above definition stands good
for a reservoir rock like sandstone. For shale that has
extremely small pores, intense chemical effects, dominance
of bound water, make this easy definition unsatisfactory.
Better answer for shale pore pressure is the fluid pressure in
permeable zone in long-term equilibrium with the shale.
This answer reflects the hazard that elevated shale pressures
bring to drilling operations.
Depending on the magnitude of the pressure, it can be
described as either being normal or abnormal or subnormal.
A. Normal Pore Pressure - Normal pore pressure is the
pressure exerted by the column of the fluid extending
from the surface to the subsurface being considered.
Normal pore pressure is not constant. The magnitude of
normal pore pressure varies with the concentration of
dissolved solids, type of fluids, gases present and
temperature gradient.
B. Abnormal Pore Pressure - Abnormal pore pressure is
defined as any pore pressure that is greater than
hydrostatic pressure of the formation water occupying
the pore space. Abnormal pore pressure is sometimes
referred to as overpressure or geo-pressure. Abnormal
pressure is thought of as being made up of normal
hydrostatic component plus an extra amount of pressure.
This excess pressure is the reason why surface control
equipments (e.g. BOPs) are required when drilling oil
and gas in wells.
The cause of abnormal pressure is attributed to a
combination of various geological, geochemical, geothermal
and mechanical changes. However for any abnormal pressure
to develop there has to be an interruption to or disturbance of
the normal compaction and de-watering.
C. Subnormal Pore Pressure - Subnormal pore pressure is
defined as any formation pressure that is less than the
corresponding fluid hydrostatic pressure at the given
depth.
Subnormal pore pressures are encountered less
frequently than abnormal pore pressure and are often
developed long after the formation is deposited. Subnormal
pressure may have natural cause related to the stratigraphic,
tectonic and geochemical history of an area or may have been
caused artificially by the production of reservoir fluids.
l Depositional effects
l Diagenetic effects
l Tectonic effects
l Structural causes
l Thermodynamic effects
D. Importance of Pore Pressure - Uncertainties cannot be
avoided but preparedness to tackle the situation becomes
very important. Pore pressure prediction is very
important to determine the mud weight with which
drilling is to be carried out. Improper analysis may lead
to the following:
a. If the pore pressure is underestimated i.e. if mud weight
is less than pore pressure, problems like caving, flows
from Formation to wellbore, kicks, blowout, all
threatening hole stability and safety issues.
b. If pore pressure is overestimated and actually if it
touches fracture pressure of a Formation again hole
stability is threatened and Formation is damaged.
Furthermore, high mud weight damage the Formation
(reservoir) hence basic purpose of well is not met.
c. Improper analyses of pore pressure, fracture pressure
and overburden pressure leads to drilling complications
like stuck pipe/lost in hole, low ROP(rate of penetration)
because of unnecessary high mud weight, improper
casing design all leading to additional time for drilling
operations and results in high cost implications.
E. Pressure Prediction Methods
Several methods of pressure prediction are available.
These methods can be logically grouped as follows:
l Areal analysis from seismic data
l Offset well correlation
l Log analysis
l Drilling parameter evaluation
l Production or test data
l Real time evaluation
(i) Seismic Analysis
Geophysical method such as seismic can be used to
detect presence and top of the abnormally pressured
formations and to evaluate the magnitude of pressures. The
techniques are similar to acoustic well logging but utilize
different frequencies and wavelength.
The interval velocity from seismic profiles is the
reciprocal of the interval travel time. The reciprocated values
can be plotted v/s depth to indicate the presence of abnormal
pressures. A normal environment exhibits increase in
velocity as compaction occurs. Therefore the travel time
should decrease. An abnormal pressure zone has lower
velocities than normal pressure zone for the specific depth
and causes higher travel times.
(ii) Log analysis
Log analysis is a common procedure for pore pressure
estimation in both offset wells and while well drilling. New
MWD (measurement while drilling) tools implement log
analysis technique in a real time drilling mode. The
techniques use the effect of the abnormally high porosities on
rock properties such as electrical conductivity, sonic travel
time and bulk density. Both the resistivity (reciprocated
conductivity) log and the sonic log are based on these
principles. Log dependent primarily on porosities for its
response and can be used in a quantitative evaluation of
formation pressures.
Resistivity log was originally used in pressure
prediction. Log response is based on electrical resistivity of
the total sample, which includes the rock matrix and fluid
filled porosity. If zone is penetrated that has abnormally high
porosity (and associated high pressure) then resistivity of the
rock will be reduced due to greater conductivity of water than
rock matrix (provided water is saline). Upon penetrating an
abnormal zone a deviation of divergence is noted (from the
normal trend). The degree of divergence is noted to estimate
the magnitude of pressure.
a. Eaton's Method
It is one of the most widely used pore pressure estimation
method in the industry and is based on the Eaton's work in the Gulf of Mexico. Eaton's method uses a semilogerithmic normal
trendline.Thevariouslogmeasurements®usedbythe Eaton's
Method are resistivity, sonic or seismic interval velocity.
Eaton assumes there is a normal pore pressure with a
fixed gradient, and the pore pressure is calculated as below:
n
P = s -(s )*a*(R/R ) p v v-Ppnorm norm
Where:
R = measurement value
Rnorm = normal pore pressure
a = Eaton factor
n = Eaton exponent
Default values for a & n are 1 & 1.2 for Eaton method
using resistivity and 1 & 3 using compressional slowness.
b. Bowers Method
Bowers method accounts for overpressure generated by
both under compaction, and pore fluid compaction (which
may be caused by temperature changes, hydrocarbon
maturation and / or clay diagenesis). The effective stress and
pore pressure can be calculated as following :
, 1/B
s' =(V-V /A) v ο
Pp= (sv
- s'
v)/α
Where:
V Velocity in ft/s at zero effective stress, ο =
A, B are fitting parameters.
α= is the Biot constant.
c. Traugott Resistivity Method
This method calculates Normal compaction trend line
for resistivity based on an empirical model of decreasing
porosity, then uses Eaton equation to calculate pore pressure
based on resistivity. Uplift and tectonic stress can be taken
into account in the calculation.
4. Fracture Gradient
Fracture gradient (FG), pressure required to induce
fractures at a given depth is calculated from pore pressure
and overburden gradient using the following formula:
FG = K *( sv
αPp) + αPp
Where α is Biot coefficient and K is called the stress ratio
(unitless), which is horizontal effective matrix stress over the
effective vertical stress.
All methods for calculating Fracture Pressure are only
different in computation of value of K.
A. Fracture Gradient / Pressure estimation
(i) Matthews & Kelley
In realizing that cohesiveness of rock matrix is usually
related to matrix stress and varies only with degree of compaction. Matthews and Kelley developed the following
equation for calculating fracture gradients in sedimentary
formations:
F=P/D+Kiα/D
where
P= formation pressure at point of interest, psi
D= Depth of interest, feet
α= matrix stress at point of interest, psi
K matrix stress coefficient for the depth at which value i=
of α would be normal matrix stress, dimensionless
F= fracture gradient at point of stress, psi/foot
(ii) Eaton
Eaton extended the concept of Matthews and Kelley to
introduce Poisson's ratio into the expression of fracture
pressure gradient,
F=S-D/P(ν/1-ν)+P/D
where
P= wellbore pressure, psi
S=overburden stress, psi
D= depth, foot
ν= poisson's ratio
F= fracture gradient, psi/foot
Eaton assumed that both overburden stress and Poissons
ratio were variable with depth. Eaton's method or its
modification is perhaps the most widely used procedure in
the industry. It has proved successful in both onshore and
offshore throughout the world.
B. Field determinations of fracture gradient
The most common procedure used for determination of
fracture gradient is leak off test (LOT). In the test the blow out
preventers are closed and then the pressure is applied
incrementally to the shut in system until the formation
initially accepts the fluid.