reservoir rock porosity

5/20/2018 Reservoir Rock Porosity

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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.
http://en.wikipedia.org/wiki/File:Well_sorted_vs_poorly_sorted_porosity.svg


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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
http://www.freepatentsonline.com/6639210-0-large.jpghttp://www.freepatentsonline.com/6639210-0-large.jpg


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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


92/106

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


103/106

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


106/106

GAS EFFECT Density - is too high

Neutron - is too low

Sonic - is not significantly

affected by gas

reservoir rock porosity

Documents

fracture porosity

vugular porosity

rock grains

onthe rock volume

intra granular porosity

total porous rock volume

matrix volume

bulk volume