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RESERVOIR ROCK
PROPERTIES
RESERVOIR ROCK
P0ROSITY
APE-1 APE-2
LECTURE-0312.08.2014
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POROSITY
Storage capacity of medium
An exclusive rock property
Expressed in Fraction or %
Statistical property based on
the rock volume*.
Used for resave estimate.
Effects hydrocarbon recovery
Part of the total porous rock volume which is
not occupied by rock grains or fine mud
rock, acting as cement between grainparticles.
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* If the selected volume is too small the calculated
porosity can deviate greatly from the true value
* If the volume is too large the porosity may deviatefrom the real value due to the influence of
heterogeneity.
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Physically following types of porosity can be
distinguished:
Inter granular porosity.
Fracture porosity.
Micro-porosity.
Vugular porosity. Intra granular porosity.
Utility wise following types of porosity can be
distinguished:
Absolute Porosity Effective Porosity
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Characteristics of Porous MediaGeometric character of rock
inter granular intra granular
fractured.Mechanical properties of rock
consolidated
unconsolidatedHeterogeneity
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Models of Porous Media
1. Represented by Parallel Cylindrical Pores*
Idealized Porous Medium
where r is the pipe radius and mn is the number of cylinders contained in the bulk volume.12.08.2014
14.08.2014
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2. Represented by Regular Cubic-Packed Spheres
where Vm is the "matrix volume or the volume of bulk space
occupied by the rock.
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3. Represented by Regular Orthorhombic -Packed Spheres
Where h is the height of the orthorhombic-packed spheres .
The matrix volume is unchanged. And thus,
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4. Represented by Regular Rhombohedral -Packed Spheres
Where h is the height in the tetrahedron and is given by
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5. Represented by Irregular - Packed Spheres with
Different Radii
Real reservoir rock exhibits a complex structure anda substantial variation in grain sizes as well as their
packing, which results in variation of porosity and
other important reservoir properties , often related
to the heterogeneity of porous medium.
By drawing a graph with radii of the spheres plotted
on the horizontal axis and heights equal to the
corresponding frequencies of their appearance
plotted on the vertical axis ,one can obtain a
histogram of distribution of particles (spheres) in
sizes.
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EXAMPLE
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Porosity: relations/presentation
Porosity = x 100Pore volumeBulk volume
1
2
1
Pore volume, Bulk volume
Bulk volume, Grain volume
Pore volume, Grain volume
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Utility limits of porosity
The effective porosity of rocks variesbetween less than 1% to 40%.
It is often stated that the porosity is:
(a)Low if < 5%(b)Mediocre if 5% < < 10 %
(c)Average if 10%< < 20 %
(d)Good if 20%< < 30 %
(e)Excellent > 30%
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Physical Impacts
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1. Porosity and hydraulic conductivity
Normally Porosity can be
proportional to hydraulicconductivity: two similar
sandy aquifers, the one
with a higher porosity
will typically have a
higher conductivity **Grain size decreases the proportionality between pore throat radii
and porosity begins to fail and therefore the proportionalitybetween porosity and hydraulic conductivity failsExample: Clays typically have very low hydraulic conductivity (due to their small
pore throat radii) but also have very high porosities (due to the structured
nature of clay)which means clays can hold a large volume of water per
volume of bulk material, but they do not release water rapidlyas they havelow hydraulic conductivity.
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2. Sorting and porosity
Grains of approximately all one size materials
have higher porosity than similarly sized poorlysorted materials which drastically reducing
porosity.
3. Consolidation of rocks
Consolidated rocks have more complex porosities
Rocks have decrease in porosity with age and
depth of burialThere may be exceptions to this rule, usually
because of thermal history.
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1. Primary porosity :The original porosity of the system
2. Secondary porosity
A subsequent or separate porosity system
in a rock, often enhancing overall porosity
of a rock.
This can be a result of chemical leaching
of minerals.This can replace the primary porosity or
coexist with it (see dual porosity below).
Types of geologic porosities
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3. Fracture porosity
This is porosity associated with a fracture
system or faulting.4. Vuggy porosity
This is secondary porosity generated by
dissolution of large features (such asmacrofossils) in carbonate rocks leaving
large holes, vugs , or even caves.
5. Open porosityRefers to the fraction of the total volume in
which fluid flow is effectively and excludes
closed pores .
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6. Closed porosity
Fraction of the total volume in which fluids
or gases are present but in which fluid flow
can not effectively take place and includes
the closed pores.
7. Dual porosity
Refers to the porosity of two overlapping
reservoirs -fractured rock , leaky aquiferresults in dual porosity systems.
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8. Macro porosity
Refers to pores greater than 50 nm* in
diameter. Flow through macropores isdescribed by bulk diffusion.
9. Meso porosity
Refers to pores greater than 2 nm and lessthan 50 nm in diameter. Flow through
mesopores is described by diffusion.
10 Micro porosity
Refers to pores smaller than 2 nm in
diameter. Movement in micropores is by
activated diffusion.
* 1.0 10-7centimetres
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Measurement of Porosity
Well LogsCore Analysis
In situ Surface
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POROSITY DETERMINATION
FROM LOGS
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A wire line truck with a spool of logging
cable is setup so that the measuring equipmentcan be lowered into the wellbore.
The logging tools measure different
properties, such as spontaneous potential andformation resistivity, and the equipment is
brought to the surface.
The information is processed by acomputer in the logging vehicle, and is
interpreted by an Formation engineer or
geologist.
The basic setup of logging process
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Well Log
SP Resistivity
OPENHOLE LOG EVALUATION
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A decrease in radioactivity from thegamma ray log could indicate the
presence of a sandstone formation.
An increase in resistivity may indicate
the presence of hydrocarbons.
An increase in a porosity log might
indicate that the formation has porosity
and is permeable.
Interpretation
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Oil sand
Gamma
ray
Resistivity Porosity
Increasing
radioactivity
Increasing
resistivityIncreasing
porosity
Shale
Shale
POROSITY DETERMINATION BY LOGGING
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POROSITY LOG TYPES
Bulk density
Sonic (acoustic)
Compensated neutron
Formation lithology
Nature of the Fluid in pores.
Essential Requirements
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Density log, the neutron log*,
and the sonic logs do not
measure porosity. Rather,
porosity is calculated frommeasurements such as electron
density, hydrogen index andsonic travel time.
* A precallibrated Neutron log directly provides
limestone porososity in carbonates.
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CORES
Allow direct measurement of reservoirproperties
Used to correlate indirect measurements,
such as wire line/LWD logs
Used to test compatibility of injection fluids
Used to predict borehole stability
Used to estimate probability of formationfailure and sand production
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Following equation is used:
On a sample of generally simple geometric form, two of thethree values Vp, Vsand VTare therefore determined.
The standard sample (plug) is cylindrical, Its cross sectionmeasures about 4 to 12 cm2and its length is varies between2 to 5 cm.
The plugs are first washed and dried.The measuring instruments are coupled to microcomputers
to process the results rapidly.
ESTIMATING POROSITY FROM
CORE ANALYSIS
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A. Measurement of VT
(a) Measurement of the buoyancy exerted by mercury on the sample
immersed in it
APPARATUSThe apparatus has a frame C connected by arod to a float Fimmersed in a beakercontaining mercury.A reference index R is Fixed to the rod. Aplate B is suspended from the plate.
(a) First measurement: the sample is placedon plate B with a weight P1 to bring R in,incontact with the mercury.(b) Second measurement: the sample isplaced under the hooks of float F, and the
weight P2 is placed on plate B to bring R in tocontact with the mercury.If Hg is the density of mercury atmeasurement temperature.Then:
VT
VT
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Method:
Without a sample using the piston,
mercury is pushed to mark, indicated on the reference valve (V).
The vernier of the pump is set at zero.With the sample in place, the mercury is again pushed to same
mark. The vernier of the pump is read and the volume VT is
obtained.
The measurement is only valid if mercury does notpenetrate into the pores.
The accuracy is 0.01 cm3.
(b) Use of positive
displacement pump VT
M
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(c) Measurement:
The foregoing methods are unsuitable if the rock
contains fissures or macro pores, becausemercury will penetrate into them.
Here a piece of cylindrical cores diameter d
and height h can be measured using slidingcaliper:
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B. Measurement of VSMeasurement of the buoyancy exerted on the sample by
a solvent with which it is saturated. VS by immersion method
The method is most accurate but difficult
and time consuming to achieve complete
saturation.The operations are normally
standardized.
The difference between the weights of sample in air (P air)
and the solvent in which it is immersed (P immersed) gives
VS as :
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Regardless of specific apparatus used i.e. singe cell or double
chamber, the sample is subjected to known initial pressure by
gas, which was originally at atmospheric pressure.
The pressure is then changed by varying the volume of gas in
chamber.
The variation in volume and pressure are measured by using
Boyles law.
P1 V1 = P2 V2The equipments using single cell and double are shown in
next slide.
(b)Use of compression chamber and Boyle law
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1 is chamber for core
2 is constant volume chamber
3 is core
4 & 5 is pressure manometers
6 is source of gas
1 is chamber for core
2 is core
3 is volume plunger
4 is pressure gauge
Use of compression chamber and
Boyle lawUse of single cell Use of double cell
1
2
3
4,5
62
4
3
1
C D i i f V
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b. Measurement by weighing a liquid filling the
effective poresThis liquid is often brine
c. Measurementby mercury injection
In this case the mercury never totally invade the
interconnected pores. Hence the value obtained
for the parameter is under par.
a. Measurement of air in the
poresThe mercury positive displacement pump is used forthis purpose. After measuring VT ,the valve of the
sample core holder is closed and the air in the
interconnected pores is expanded. The variation in
volume and pressure are measured using Boyleslaw
C. Determination of VP
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Fluid Summation Method
The method involves the analysis of a FRESHsample containing water, oil and gas.
The distribution of these fluids is not thesame as in the reservoir. because the core
has been invaded by the mud filtrate anddecomposed when pulled out.
Still/but the sum of the volumes of thesethree fluids, for a unit volume of rock, gives
the effective porosity of the sample. The total volume is determined by mercury
displacement pump.
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(1) VP = Vw + VO + VG
(1) Sw + SO + SG = 100%
Special Method :Determination of VP
Relation of Fluid Summation and porosity
Sw
= Vw
/ VP
SO
= Vo
/ VP
SG
= VG
/ VP
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ELECTRICAL METHOD
Formation Resistivity Factor
Formation Resistivity Factor : is the ratio ofthe resistivity of clean formation(core sample)
fully saturated with brine to the resistivity
observed with brine solution of same salinity. i.e.
F.F. = Ro/ RwWhere
Ro= Resistivity of clean formation sample fullysaturated with brine of specific salinity,
Rw= Resistivity of brine of same salinity
(without core)
1
2
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Formation Resistivity Factor : is also
related to the POROSITY by Archie
Equation given as under:
FF = a/m
Where
a = Tortuosity Factor
(Path Complexity)
m= Cementation Factor(Grain Size)
Higher is the value of ahigher is the
value of m.
2
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a
m
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Formation
ResistivityFactor :is also greatly
effected byover burden
pressure and
in turn withPOROSITY.
3
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POROSITY AVERAGING
1
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If the Bedding planes show large variations in
porosity vertically then arithmetic average porosity
The thickness - weighted average porosity is used
to describe the average reservoir porosity.
If porosity in one portion of the reservoir to be
greatly different from that in another area due to
sedimentation conditions, the areal weighted
average
The volume-weighted average porosity is used to
characterize the average rock porosity.
1
3
4
2
MATHEMATICAL EXPRESSIONS
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averaging techniques are expressedmathematically in the following forms:
Arithmetic average
Thickness-weighted average
Areal-weighted average
Volumetric-weighted average
MATHEMATICAL EXPRESSIONS
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POROSITY APPLICATIONS
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APPLICATION OF EFFECTIVE POROSITY
For a reservoir with an areal extent of Aacres and an average thickness of h feet
Bulk volume = 43,560 Ah, ft3
OR= 7,758 Ah, bbl
The reservoir pore volume PV in cubic feet :
PV = 43,560 Ah, ft3The reservoir pore volume PV in bbl is given as :
PV = 7,758 Ah, bbl
b ( )
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Porosity Distribution (Histogram)
The multiple sampling of porosity measurements for
reservoir rocks at different depths and in differentwells gives a data set that can then be plotted as a
histogram , to reveal the porositys Frequency
distribution.Such histograms may be constructed separately for
the individual zones, or units, distinguished within
the reservoir, and thus give a good basis for
statistical estimates
(mean porosity values, standard deviations, etc.).
A LICA ION
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APPLICATION
1. Zone Analysis
Histogram
2. Reservoir Simulation
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Simulation of fluid flow
in porous media,
require a realistic
picture of the rock
porosity
The grouping ofporosity data according
to the reservoir zones,
depth variation orgraphical co-ordination,
yield spatial trends.
2. Reservoir Simulation
Trends of porosity
distribution in thedepth profiles of
two reservoir sand
stone.
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Mechanical digenesis
(compaction)/ chemical
digenesis (cementation)
have a profound effect
on a sedimentary rocksporosity. This burial
effect is illustrated by
the two typicalExamples of sand and
clay deposits,
3. Sediment compaction
4 Exploration leads
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Development of a bulk and realistic
picture of the reservoir to evaluate -
Early Reserves Estimates Exploration
leads Expected Recoveries, well
treatments , IOR and EORBoundaries of
Sand ridges are
shown as separate
units / porosity
zones - numberedas zone 1 , zone2,
zone3 and zone 4,
indicating their
areal extent.
4. Exploration leads
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REMARKS
Rock at reservoir conditions is subject to overburden
pressure stresses, while the core recovered at surfacetends to be stress relived; therefore laboratorydetermined porosity values are generally expected to
be higher than in-situ values.
If R represent porosity at reservoir condition, L beporosity at reservoir condition, rock compressibility asCp (V/V/psi) and net overburden pressure as PN ( overburden pressure fluid pressure) psi; then we may
use the following relation:
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LECTURE 03 A
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ENGINEERINGUPES
DEHRADUN
LECTURE-03 A
RESERVOIR
POROSITYROCK
EXERCISES
Example 1
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The grain volume of rock sample of
1.5dia and 5.6 cm length was foundto be 56.24 cc and bulk volume of the
sample using mercury displacement
method was measured 73.80 cc.
If dry weight of the sample is149.88
gms, find the grain density. Calculatethe pore volume and porosity of the
sample.
Example
1
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SOLUTION -1
*Pore volume = Bulk volume-Grain volume=73.8056.24=17,56 cc
*Porosity,% =(Pore volume/bulk volume) x
100=(17.56/73.80)X100 = 23.79%
*Grain density=Dry weight of sample/Grain
volume= 149.88/56.24
= 2.665 gms/cc
Example 2
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Example-2
Weight of the dry sample in air is
20.0gms.
The weight of the sample when
saturated with water is 22.5gms.Weight of saturated sample in water
at 40 degree F is 12.6 gms.Find the Bulk volume.
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SOLUTION-2
Weight of the water displaced
= 22.5- 12.5= 9.9gms
Volume of water displaced
=9.9/1= 9.9cc
Will be the bulk volume of the sample.
l 3
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Example-3
A core sample immersed in water hasits weight in air as 20gms
Dry sample when coated with paraffin
weighs 20,9 gms (density of paraffinbeing 0.9gm/cc).
If weight of the immersed sample in
water at 40 F be given as 10 gms.
Find the bulk volume of core sample.
SOLUTION 3
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SOLUTION -3
Weight of the paraffin=20.9-20.0=0.9gms
Volume of paraffin=0.9/0.9=1cc
Weight of water displaced=20.9-10.0
=10.9gmsVolume of water displaced= 10.9/1.0
=10.9cc
Therefore bulk volume of rock will be:Volume of water displacedvolume of
paraffin=10.9-1=9.9cc
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EXAMPLE- 4
Determine the total porosity of
sample when the grain density is
2.67 gms/cc.Weight of the dry sample in air is 20
gms.Bulk volume of the sample is 9.9cc
SOLUTION 4
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SOLUTION -4
*Grain volume of the sample
= Weight of dry sample in
air/Sand density
=7.5* Total porosity=
(Bulk volume-grain volume)/Bulk
volume X 100=(9.97.5)/ 9.9 X 100
= 24.2%
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Example -5
Calculate the weight of 1 m3 of
Sand stone of 14% porosity.Given that the sand density is
2.65 gm/cm3
SOLUTION 5
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Volume of sand stone BVs=1m3
Porosity(PV) =14%
Density of sand grains=2.65.
BV= PV + GVGV = BV - PV
= 1- 0.14 = 0.86 m3
Ws = Density of sand grains x GV=2.65gm/cm3x 0.86 x 106gm
=2.279 x 0.86 x 106gm
SOLUTION-5
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Example-6
A petroleum reservoir has an areal
extent of 20,000 ft2 and a pay
thickness of 100ft.The reservoir rock
has a uniform porosity of 35%. Find
the pore volume of this reservoir
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Pore volume
= 7758 Ahbbl.=7758 x 20,000 x 100 x 35/100
=54306 x 105bbl.
SOLUTION - 6
Example 7
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Example7An oil reservoir exists at its bubble-point
pressure of 3000 psia and temperature of160F. The oil has an API gravity of 42 and
gas-oil ratio of 600 scf/STB. The specific
gravity of the solution gas is 0.65. Thefollowing additional data are also available
Reservoir area = 640 acres
Average thickness = 10 ft Connate water saturation = 0.25
Effective porosity = 15%
Calculate the initial oil in place in STB.
SOLUTION - 7
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SOLUTION 7Step 1. Determine the specific gravity of the
stock-tank oil as 0.8156
Step 2. Calculate the initial oil formation volume
factor as 1.306 bbl /STB
Step 3. Calculate the pore volume
= 7758 (640) (10) (0.15) = 7,447,680 bblStep 4. Calculate the initial oil in place Initial oil in
place = 12,412,800 (1 - 0.25)/1.306 = 4,276,998 STB
Example 8
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Example 8
Calculate the arithmetic average and
thickness-weighted average from thefollowing measurements
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Solution -8
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Porosity = void volume soil volume
Porosity = 0.3 cubic meters 1.0 cubic meters
Porosity = 0.3
LECTURE-03 B
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ROCKPOROSITY
DENSITY LOGS1
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DENSITY LOGS
Radioactive source is used to generategamma rays
Gamma ray collides with electrons information, losing energy
Detector measures intensity of back-
scattered gamma rays, which isrelated to electron density of theformation
1
Electron density is a measure of
bulk density
DENSITY LOG
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GRAPI0 200
CALIXIN6 16
CALIY
IN6 16
RHOBG/C32 3
DRHOG/C3-0.25 0.25
4100
4200
DENSITY LOG
Caliper
Density
correction
Gamma ray Density
DENSITY OGS PRINCIP E
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DENSITY LOGS: PRINCIPLE
Bulk density, b, is dependent upon:Lithology
Porosity
Density and saturation*of fluids in
pores
* Saturation is fraction of pore
volume occupied by a particular
fluid
BULK DENSITY
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BULK DENSITY
Bulk density varies with lithology
Sandstone 2.65 g/cc
Limestone 2.71 g/cc
Dolomite 2.87 g/cc
fmab
1
MatrixFluids in
flushed zone
POROSITY FROM DENSITY LOG
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POROSITY FROM DENSITY LOG
Porosity equation
xohxomff S1S
fma
bma
Fluid density equation
mf is the mud filtrate density, g/cc
h is the hydrocarbon density, g/cc
Sxo is the saturation of the flush/zone, decimal
Fluid density (f) is between 1.0 and 1.1.If gas is
present, the actual f will be < 1.0 and the
calculated porosity will be too high.
Where
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Formation (b)
Long spacingdetector
Short spacing
detector
Mud cake(mc+ hmc)
Source
Actuality
Efficiency
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1. Minimizing the influence of the mud column
Efficiency
i) Source and detector, mounted on a skid,
are shielded
ii) The openings of the shields are applied
against the wall of the borehole by means
of an eccentering arm
2. A correction for due to mal instrument contact
and formation or roughness of the borehole wall
The use of two detectors is advisable to over comethis problem.
3. Account for all of the effects of borehole breakouts,
washouts, and rugosity
Working equation (hydrocarbon zone)
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Working equation (hydrocarbon zone)
b = Recorded parameter (bulk volume)
Sxomf = Mud filtrate component
(1 - Sxo
) hc
= Hydrocarbon component
Vshsh = Shale component
1 - - Vsh = Matrix component
DENSITY LOGS
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If minimal shale, Vsh0
If hcmff, then
b= f- (1 - ) ma
fma
bmad
P it f d it l f ti
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d = Porosity from density log, fraction
ma = Density of formation matrix, g/cm3
b = Bulk density from log measurement,g/cm3
f = Density of fluid in rock pores, g/cm3
hc = Density of hydrocarbons in rock pores,g/cm3
mf = Density of mud filtrate, g/cm3
sh = Density of shale, g/cm3
Vsh = Volume of shale, fraction
Sxo = Mud filtrate saturation in zone invaded
by mud filtrate, fraction
BULK DENSITY LOG: EXAMPLE
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GRC0 150
SPC
MV-160 40ACAL
6 16
ILDC0.2 200
SNC
0.2 200MLLCF
0.2 200
RHOC1.95 2.95
CNLLC
0.45 -0.15
DTus/f150 50
001) BONANZA 1
10700
10800
10900
BULK DENSITY LOG: EXAMPLE
Bulk Density
Log
RHOC
1.95 2.95
NEUTRON LOG2
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NEUTRON LOGUses a radioactive source to
bombard the formation withneutrons
For a given formation,
amount of hydrogen in the
formation (i.e. hydrogen
index) impacts the number of
neutrons that reach the
receiverA large hydrogen index
implies a large liquid-filled
porosity (oil or water)TOOL
PRINCIPLE
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PRINCIPLE Logging tool emits high energy neutrons into
formation. Neutrons collide with nuclei of formationsatoms
Neutrons lose energy (velocity) with each collision of
hydrogen atom. The most energy is lost when colliding with a
hydrogen atom nucleus
Neutrons are slowed sufficiently to be capturedby nuclei.
Capturing nuclei become excited and emit
gamma rays
ACTIVITIES
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1. Depending on type of logging tool eithergamma rays or non-captured neutrons are
recorded
2. Log records porosity based on neutronscaptured by formation
3. If hydrogen is in pore space, porosity isrelated to the ratio of neutrons emitted tothose counted as captured
Neutron log reports porosity, calibrated assumingcalcite matrix and fresh water in pores, if theseassumptions are invalid we must correct the neutron
porosity value
REMARKS
Theoretical equation
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Theoretical equation
where
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where= True porosity of rock
N = Porosity from neutron logmeasurement, fraction
Nma = Porosity of matrix fraction
Nhc= Porosity of formation saturated with
hydrocarbon fluid, fraction
Nmf = Porosity saturated with mud filtrate,
fraction
Vsh = Volume of shale, fractionSxo = Mud filtrate saturation in zone
invaded by mud filtrate, fraction
POROSITY FROM NEUTRON LOG
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GRC0 150
SPC
MV-160 40ACAL
6 16
ILDC0.2 200
SNC
0.2 200MLLCF
0.2 200
RHOC1.95 2.95
CNLLC
0.45 -0.15
DTus/f150 50
001) BONANZA 1
10700
10800
10900
POROSITY FROM NEUTRON LOG
Neutron
Log
CNLLC
0.45 -0.15
EXAMPLE
lithology is
sandstone
or
dolomite
ACOUSTIC (SONIC) LOG3
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( )
These logs are usually borehole
compensated (BHC) where in effects athole size changes as well as errors due
to sonde tilt is substantially reduced..
system uses two transmitters, one aboveand one below a pair of sonic receivers
The travel time elapsed between thesound reaching the receiver is recorded
and used for porosity calculations.
ACOUSTIC (SONIC) LOG:TOOL
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Upper
transmitter
Lower
transmitter
R1
R2
R3
R4
( )
Tool usually consists of one soundtransmitter (above) and tworeceivers (below)
Sound is generated, travelsthrough formation
Elapsed time between sound wave
at receiver 1 vs receiver 2 isdependent upon density of mediumthrough which the sound traveled.
BHC METHODOLOGY
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When one of the transmitters is pulsed, the sound wave
enters the formation, travels along the wellbore and
triggers both of the receivers; the time elapsed
between the sound reaching each receiver is recorded.
Since the speed of sound in the sonic sonde and mud isless than that in the formations, the first arrivals of
sound energy the receivers corresponds to the sound-
travel paths in the formation near the borehole wall.
The transmitters are pulsed alternately, and the
differential time or delta t readings are obtained and
averaged. This leads the tool is compensated for tilt.
COMMON LITHOLOGY MATRIX
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Lithology Typical Matrix Travel
Time, tma, sec/ftSandstone 55.5Limestone 47.5Dolomite 43.5
Anydridte 50.0Salt 66.7
TRAVEL TIMES USED
MODIFICATION
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If Vsh= 0 and if hydrocarbon is
liquid (i.e. tmf tf), then
tL= tf+ (1 - ) tmaor
maf
maL
s tt
tt
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s= Porosity calculated from sonic
log reading, fraction
tL = Travel time reading from
log, microseconds/ft
tma = Travel time in matrix,
microseconds/ft
tf = Travel time in fluid,
microseconds/ ft
EXAMPLE: ACOUSTIC (SONIC) LOG
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DT
USFT140 40
SPHI
%30 10
4100
4200
GR
API0 200
CALIX
IN6 16
EXAMPLE: ACOUSTIC (SONIC) LOG
Sonic travel time
Sonicporosity
Caliper
GammaRay
SONIC LOG:TIME RESPONSE
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The response can be written as follows:
fmalog t1tt
maf
ma
tttt
log
tlog = log reading, sec/ft
tma =the matrix travel time, sec/ft
tf = the fluid travel time, sec/ft
= porosity
SONIC LOG
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Sonic log - measures the slowness of a
compressional wave to travel in theformation.
Matrix travel time (tma) is a function of
lithology
SONIC LOG
CHARACTERISTICS
h l h d l
SONIC LOG :SPECIALITY
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There are several more sophisticated sonic logs
that couple/ determine both the shear wave
arrival and the compressional wave arrival.
This log analyst can determine rock properties
such as Poissons ratio, Youngs modulus, and
bulk modulus.
These values are very important when
designing hydraulic fracture treatments orwhen trying to determine when a well may
start to produce sand.
EXAMPLE: SONIC LOG
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GRC0 150
SPC
MV-160 40ACAL
6 16
ILDC0.2 200
SNC
0.2 200MLLCF
0.2 200
RHOC1.95 2.95
CNLLC
0.45 -0.15
DTus/f150 50
001) BONANZA 1
10700
10800
10900
Sonic
Log
DT
150 50us/f
FACTORS AFFECTING SONIC
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FACTORS AFFECTING SONIC
LOG RESPONSE
Unconsolidated formations
Naturally fractured formations
Hydrocarbons (especially gas)
Salt sections
LET IT BE KNOWN
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LET IT BE KNOWN
The three porosity logs: Respond differently to different matrix
compositions
Respond differently to presence of gas orlight oils
Combinations of logs can:
Imply composition of matrix Indicate the type of hydrocarbon in pores
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GAS EFFECT Density - is too high
Neutron - is too low
Sonic - is not significantly
affected by gas