Reservoir Rock Porosity

RESERVOIR ROCK P0ROSITY

APE-1

12.08.2014

APE-2

RESERVOIR ROCK PROPERTIES

LECTURE-03

Part of the total porous rock volume which is not occupied by rock grains or fine mud rock, acting as cement between grain particles.

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

* 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 deviate from the real value due to the influence of heterogeneity.

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

Characteristics of Porous Media Geometric character of rock •inter granular – intra granular •fractured. Mechanical properties of rock •consolidated •unconsolidated Heterogeneity

Models of Porous Media

14.08.2014

Idealized Porous Medium 1. Represented by Parallel Cylindrical Pores*

12.08.2014

where r is the pipe radius and m·n is the number of cylinders contained in the bulk volume.

2. Represented by Regular Cubic-Packed Spheres

where Vm is the "matrix“ volume or the volume of bulk space occupied by the rock.

3. Represented by Regular Orthorhombic -Packed Spheres

Where h is the height of the orthorhombic-packed spheres . The matrix volume is unchanged. And thus,

4. Represented by Regular Rhombohedral -Packed Spheres

Where h is the height in the tetrahedron and is given by

5. Represented by Irregular - Packed Spheres with Different Radii Real reservoir rock exhibits a complex structure and a 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.

EXAMPLE

Porosity: relations/presentation Porosity =

1

2

1

Pore volume x 100 Bulk volume Pore volume, Bulk volume

Bulk volume, Grain volume Pore volume, Grain volume

Utility limits of porosity • •

The effective porosity of rocks varies between less than 1% to 40%. It is often stated that the porosity is: (a)Low if Φ < 5% (b)Mediocre if 5% < Φ < 10 % (c)Average if 10%< Φ < 20 % (d)Good if 20%< Φ < 30 % (e)Excellent Φ > 30%

Physical Impacts

1. Porosity and hydraulic conductivity Normally Porosity can be proportional to hydraulic conductivity: 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 proportionality between porosity and hydraulic conductivity fails Example: 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 rapidly as they have low hydraulic conductivity.

2. Sorting and porosity Grains of approximately all one size materials have higher porosity than similarly sized poorly sorted 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 burial There may be exceptions to this rule, usually because of thermal history.

Types of geologic porosities 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).

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 as macrofossils) in carbonate rocks leaving large holes, vugs , or even caves. 5. Open porosity Refers to the fraction of the total volume in which fluid flow is effectively and excludes closed pores .

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 aquifer results in dual porosity systems.

8. Macro porosity Refers to pores greater than 50 nm* in diameter. Flow through macropores is described by bulk diffusion. 9. Meso porosity Refers to pores greater than 2 nm and less than 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 × 10-7 centimetres

Measurement of Porosity

In situ

Well Logs

Surface

Core Analysis

POROSITY DETERMINATION FROM LOGS

The basic setup of logging process A wire line truck with a spool of logging cable is setup so that the measuring equipment can be lowered into the wellbore. The logging tools measure different properties, such as spontaneous potential and formation resistivity, and the equipment is brought to the surface. The information is processed by a computer in the logging vehicle, and is interpreted by an Formation engineer or geologist.

OPENHOLE LOG EVALUATION Well Log SP

Resistivity

Interpretation A decrease in radioactivity from the gamma 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.

POROSITY DETERMINATION BY LOGGING Increasing radioactivity

Increasing resistivity

Increasing porosity

Shale

Oil sand Shale

Gamma ray

Resistivity

Porosity

POROSITY LOG TYPES • Bulk density

• Sonic (acoustic) • Compensated neutron

Essential Requirements • Formation lithology • Nature of the Fluid in pores.

Density log, the neutron log*, and the sonic logs do not measure porosity. Rather, porosity is calculated from measurements such as electron density, hydrogen index and sonic travel time. * A precallibrated Neutron log directly provides limestone porososity in carbonates.

CORES • Allow direct measurement of reservoir properties • 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 formation failure and sand production

ESTIMATING POROSITY FROM CORE ANALYSIS

► Following equation is used: Φ

► On a sample of generally simple geometric form, two of the three values Vp , Vs and VT are therefore determined. ►The standard sample (plug) is cylindrical, Its cross section measures about 4 to 12 cm2 and its length is varies between 2 to 5 cm. ►The plugs are first washed and dried. ►The measuring instruments are coupled to microcomputers to process the results rapidly.

A. Measurement of VT (a) Measurement of the buoyancy exerted by immersed in it

mercury on the sample

The apparatus has a frame C connected by a rod to a float F immersed in a beaker containing mercury. A reference index R is Fixed to the rod. A plate B is suspended from the plate. (a) First measurement: the sample is placed on plate B with a weight P1 to bring R in,in contact with the mercury. (b) Second measurement: the sample is placed under the hooks of float F, and the weight P2 is placed on plate B to bring R in to contact with the mercury. If ρHg is the density of mercury at measurement temperature. Then: VT

APPARATUS

VT

(b) Use of positive displacement pump

M VT

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 not penetrate into the pores. The accuracy is ± 0.01 cm3.

(c) Measurement: The foregoing methods are unsuitable if the rock contains fissures or macro pores, because mercury will penetrate into them. Here a piece of cylindrical core’s diameter “d” and height “h” can be measured using sliding caliper:

B. Measurement of VS

Measurement of the buoyancy exerted on the sample by VS by immersion method a solvent with which it is saturated. 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 :

(b)Use of compression chamber and Boyle’ law 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 Boyle’s law.

P1 V1 = P2 V2 The equipments using single cell and double are shown in next slide.

Use of compression chamber and Boyle’ law Use of single cell

Use of double cell

4,5

4

2

6

1

3 1

3

1 is chamber for core 2 is core 3 is volume plunger 4 is pressure gauge

2

1 is chamber for core 2 is constant volume chamber 3 is core 4 & 5 is pressure manometers 6 is source of gas

C. Determination of VP

a. Measurement of air in the pores

The mercury positive displacement pump is used for this 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 Boyle’s law b. Measurement by weighing a liquid filling the effective pores This liquid is often brine c. Measurement by mercury injection In this case the mercury never totally invade the interconnected pores. Hence the value obtained for the parameter is under par.

Fluid Summation Method • The method involves the analysis of a FRESH sample containing water, oil and gas. • The distribution of these fluids is not the same as in the reservoir. because the core has been invaded by the mud filtrate and decomposed when pulled out. • Still/but the sum of the volumes of these three fluids, for a unit volume of rock, gives the effective porosity of the sample. • The total volume is determined by mercury displacement pump.

Special Method :Determination of VP Relation of Fluid Summation and porosity

(1) VP = Vw + VO + VG (1) Sw + SO + SG = 100%

Sw = Vw/ VP

SO = Vo/ VP

SG = VG/ VP

1

ELECTRICAL METHOD Formation Resistivity Factor

Formation Resistivity Factor : is the ratio of the 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 / Rw Where Ro= Resistivity of clean formation sample fully saturated with brine of specific salinity, Rw= Resistivity of brine of same salinity (without core)

2

Formation Resistivity Factor : is also related to the POROSITY by Archie Equation given as under: FF = a/Φm Where a = Tortuosity Factor (Path Complexity) m= Cementation Factor (Grain Size) Higher is the value of ‘a’ higher is the value of ‘m’ .

a

m

3

Formation Resistivity Factor : is also greatly effected by over burden pressure and in turn with POROSITY.

POROSITY AVERAGING

1

If the Bedding planes show large variations in porosity vertically then arithmetic average porosity 2

The thickness - weighted average porosity is used to describe the average reservoir porosity. 3

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 4

The volume-weighted average porosity is used to characterize the average rock porosity.

MATHEMATICAL EXPRESSIONS averaging techniques are expressed mathematically in the following forms: Arithmetic average Thickness-weighted average Areal-weighted average Volumetric-weighted average

POROSITY APPLICATIONS

APPLICATION OF EFFECTIVE POROSITY For a reservoir with an areal extent of A acres 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 AhФ, ft3 The reservoir pore volume PV in bbl is given as :

PV = 7,758 AhФ, bbl

Porosity Distribution (Histogram) The multiple sampling of porosity measurements for reservoir rocks at different depths and in different wells gives a data set that can then be plotted as a histogram , to reveal the porosity’s 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.).

APPLICATION 1. Zone Analysis

Histogram

2. Reservoir Simulation Simulation of fluid flow in porous media, require a realistic picture of the rock porosity The grouping of porosity data according to the reservoir zones, depth variation or graphical co-ordination, yield spatial trends.

Trends of porosity distribution in the depth profiles of two reservoir sand stone.

3. Sediment compaction Mechanical digenesis (compaction)/ chemical digenesis (cementation) have a profound effect on a sedimentary rock’s porosity. This burial effect is illustrated by the two typical Examples of sand and clay deposits,

4. Exploration leads Development of a bulk and realistic picture of the reservoir to evaluate Early Reserves Estimates Exploration leads Expected Recoveries, well treatments , IOR and EOR Boundaries of Sand ridges are shown as separate units / porosity zones - numbered as zone 1 , zone2, zone3 and zone 4, indicating their areal extent.

REMARKS Rock at reservoir conditions is subject to overburden pressure stresses, while the core recovered at surface tends to be stress relived; therefore laboratory determined porosity values are generally expected to be higher than in-situ values. If ΦR represent porosity at reservoir condition, ΦL be porosity at reservoir condition, rock compressibility as Cp (V/V/psi) and net overburden pressure as ∆PN ( over burden pressure – fluid pressure) psi; then we may use the following relation:

LECTURE-03 A

RESERVOIR

ENGINEERING

ROCK

POROSITY

UPES DEHRADUN

EXERCISES

Example 1 The grain volume of rock sample of 1.5” dia and 5.6 cm length was found to 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. Calculate the pore volume and porosity of the sample.

SOLUTION -1 *Pore volume = Bulk volume-Grain volume =73.80 – 56.24=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

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.

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.

Example-3 A core sample immersed in water has its weight in air as 20gms Dry sample when coated with paraffin weighs 20,9 gms (density of paraffin being 0.9gm/cc). If weight of the immersed sample in water at 40 ºF be given as 10 gms. Find the bulk volume of core sample.

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 =10.9gms Volume of water displaced= 10.9/1.0 =10.9cc Therefore bulk volume of rock will be: Volume of water displaced – volume of paraffin=10.9-1=9.9cc

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 *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 =(9.9 – 7.5)/ 9.9 X 100 = 24.2%

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 Volume of sand stone BVs=1m3 PorosityΦ(PV) =14% Density of sand grains=2.65. BV= PV + GV GV = BV - PV = 1- 0.14 = 0.86 m3 Ws = Density of sand grains x GV =2.65gm/cm3 x 0.86 x 106gm =2.279 x 0.86 x 106gm

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

SOLUTION - 6

Pore volume = 7758 AhΦ bbl. =7758 x 20,000 x 100 x 35/100 =54306 x 105 bbl.

Example – 7

An oil reservoir exists at its bubble-point pressure of 3000 psia and temperature of 160°F. 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. The following 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

Step 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 bbl Step 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 Calculate the arithmetic average and thickness-weighted average from the following measurements

Solution -8

Porosity = void volume ÷ soil volume Porosity = 0.3 cubic meters ÷ 1.0 cubic meters Porosity = 0.3

LECTURE-03 B

ROCK POROSITY

1

DENSITY LOGS Electron density is a measure of bulk density • Radioactive source is used to generate gamma rays • Gamma ray collides with electrons in formation, losing energy • Detector measures intensity of backscattered gamma rays, which is related to electron density of the formation

DENSITY LOG 0

GR API

6

CALIX IN

16

6

CALIY IN

16

200

2

RHOB G/C3 -0.25

3 DRHO G/C3

0.25

4100

Gamma ray

Density correction 4200

Caliper

Density

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 Bulk density varies with lithology –Sandstone 2.65 g/cc –Limestone 2.71 g/cc

–Dolomite 2.87 g/cc

b  ma 1     f  Matrix

Fluids in flushed zone

POROSITY FROM DENSITY LOG Porosity equation

ma  b  ma   f

Fluid density equation Where

 f  mf Sxo  h 1  Sxo 

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.

Mud cake (mc + hmc)

Actuality Formation (b)

Long spacing detector

Short spacing detector Source

Efficiency 1. Minimizing the influence of the mud column 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 come this problem. 3. Account for all of the effects of borehole breakouts, washouts, and rugosity

Working equation (hydrocarbon zone)

b

=

 Sxo mf

Recorded parameter (bulk volume) =

Mud filtrate component

 (1 - Sxo) hc = Hydrocarbon component Vsh sh

=

1 -  - Vsh =

Shale component Matrix component

DENSITY LOGS • If minimal shale, Vsh  0 • If hc  mf  f, then • b =  f - (1 - ) ma

ma  b   d  ma   f

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 001) BONANZA 1 GRC 0 150 SPC -160 MV 40 ACAL 6 16 10700

0.2

0.2 0.2

ILDC SNC MLLCF

200

200

RHOC 1.95 2.95 CNLLC 0.45 -0.15

DT 150 us/f 50

200

RHOC

1.95

10800

10900

Bulk Density Log

2.95

2

NEUTRON LOG

TOOL

Uses a radioactive source to bombard the formation with neutrons For a given formation, amount of hydrogen in the formation (i.e. hydrogen index) impacts the number of neutrons that reach the receiver A large hydrogen index implies a large liquid-filled porosity (oil or water)

PRINCIPLE • Logging tool emits high energy neutrons into formation.

• Neutrons collide with nuclei of formation’s atoms • 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 captured by nuclei. • Capturing nuclei become excited and emit gamma rays

ACTIVITIES 1. Depending on type of logging tool either gamma rays or non-captured neutrons are recorded 2. Log records porosity based on neutrons captured by formation

3. If hydrogen is in pore space, porosity is related to the ratio of neutrons emitted to those counted as captured REMARKS

Neutron log reports porosity, calibrated assuming calcite matrix and fresh water in pores, if these assumptions are invalid we must correct the neutron porosity value

Theoretical equation

where  N

Nma Nhc Nmf

Vsh Sxo

= True porosity of rock = Porosity from neutron log measurement, fraction = Porosity of matrix fraction = Porosity of formation saturated with hydrocarbon fluid, fraction = Porosity saturated with mud filtrate, fraction = Volume of shale, fraction = Mud filtrate saturation in zone invaded by mud filtrate, fraction

POROSITY FROM NEUTRON LOG 001) BONANZA 1 GRC 0 150 SPC -160 MV 40 ACAL 6 16 10700

0.2

0.2 0.2

ILDC SNC MLLCF

200

200

RHOC 1.95 2.95 CNLLC 0.45 -0.15

DT 150 us/f 50

200

CNLLC

0.45

-0.15

EXAMPLE 10800

10900

Neutron Log

lithology is sandstone or dolomite

3

ACOUSTIC (SONIC) LOG These logs are usually borehole compensated (BHC) where in effects at hole size changes as well as errors due to sonde tilt is substantially reduced.. system uses two transmitters, one above and one below a pair of sonic receivers The travel time elapsed between the sound reaching the receiver is recorded and used for porosity calculations.

ACOUSTIC (SONIC) LOG:TOOL

Upper transmitter R1 R2 R3 R4

Lower transmitter

•

Tool usually consists of one sound transmitter (above) and two receivers (below)

•

Sound is generated, travels through formation

•

Elapsed time between sound wave at receiver 1 vs receiver 2 is dependent upon density of medium through which the sound traveled.

BHC METHODOLOGY

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 is less than that in the formations, the first arrivals of sound energy the receivers corresponds to the soundtravel 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 TRAVEL TIMES USED

Lithology Sandstone Limestone Dolomite Anydridte Salt

Typical Matrix Travel Time, tma, sec/ft 55.5 47.5 43.5 50.0 66.7

MODIFICATION

• If Vsh = 0 and if hydrocarbon is liquid (i.e. tmf  tf), then • tL =  tf + (1 - ) tma or

t L  t ma s    t f  t ma

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 0

GR API

6

CALIX IN

DT 200

16

140

USFT

40

30

SPHI %

10

4100 Sonic travel time Gamma Ray Sonic porosity

4200

Caliper

SONIC LOG:TIME RESPONSE The response can be written as follows:

tlog  tma 1    t f  

t log  t ma t f  t ma

tlog = log reading, sec/ft

tma = the matrix travel time, sec/ft tf = the fluid travel time, sec/ft  = porosity

SONIC LOG CHARACTERISTICS Sonic log - measures the slowness of a compressional wave to travel in the formation. Matrix travel time (tma) is a function of lithology

SONIC LOG :SPECIALITY 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 Poisson’s ratio, Young’s modulus, and bulk modulus. These values are very important when designing hydraulic fracture treatments or when trying to determine when a well may start to produce sand.

EXAMPLE: SONIC LOG 001) BONANZA 1 GRC 0 150 SPC -160 MV 40 ACAL 6 16

0.2

0.2 0.2

ILDC SNC MLLCF

200

200

RHOC 1.95 2.95 CNLLC 0.45 -0.15

DT 150 us/f 50

200

10700

150

10800

Sonic Log 10900

DT us/f

50

FACTORS AFFECTING SONIC LOG RESPONSE • Unconsolidated formations

• Naturally fractured formations • Hydrocarbons (especially gas) • Salt sections

LET IT BE KNOWN The three porosity logs: – Respond differently to different matrix compositions – Respond differently to presence of gas or light oils

Combinations of logs can: – Imply composition of matrix – Indicate the type of hydrocarbon in pores

GAS EFFECT • Density -  is too high • Neutron -  is too low • Sonic

-  is not significantly affected by gas