bj fundamental of logging.pdf

1

FUNDAMENTAL OF LOGGING

SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 Sage Brush RoadYukon, OK 73099

405 324-5828Fax 324-2360

[email protected]

CONSULTANTS

2

TABLE OF CONTENTS

Page

Log Parameters 1

Resistivity Logs 13

Water Saturation Approximation 30

Porosity and Lithology Determination 35

Log Interpretation Exercise #1 57

Water Production Estimation 60

Log Interpretation Exercise #2 65

Summary 66

3

WIRELINE LOGGING

4

Are hydrocarbons present in commercial quantities?

Need to define:

Type of rock

Type of fluid in pores

Type of pore space

LOGGING ANSWERS

RESERVOIR ROCK

PORE WATER?

OIL? GAS?

GASOIL

WATER

5

RW x LRT = x SW

RO = WATER SATURATED RESISTIVITY

SOME WATERSATURATION AND

SOME HYDROCARBON

RO =RW x L

100% SATURATED WITHFORMATION WATER

6

d

di

Hmc

ADJACENTFORMATION

Uninvaded Zone

Flushed Zone

Borehole

UN

INV

AD

ED

ZO

NE

TR

AN

SIT

ION

ZO

NE

FL

USH

ED

ZO

NE

RxoRmfSxo

RtRwSw

SCHEMATIC OF BOREHOLE

d - Hole diameter, inchesd

i- Diameter of invaded zone

Hmc

- Thickness of mudcake

Rmf

- Resistivity of mud filtrateR

xo- Resistivity, flushed zone, ohm-meter

Sxo

- Water saturation of flushed zone

Rt

- Resistivity undisturbed zoneR

w- Resistivity of formation water

Sw

- Water saturation, uninvaded zone

7

RESISTIVITYSP

A SHALE

B SHALY SAND

C

D

FRESHWATERSAND

OIL SAND

ESALTWATER

SAND

F HARDLIMESTONE

GANHYDRITE

ORGYPSUM

BASIC RESISTIVITY LOG

8

POROSITY(Storage Space)

Fine grained Poorly-sorted

IntragranularIntergranular

IntercrystallineFractureSolution

Primary

Secondary

Coarse-grained, well sorted

Good permeability Poor permeability

PERMEABILITY(Fluid Mobility)

9

SAND GRAIN SIZE, STACKING,AND SORTING EFFECT POROSITY

MINIMUM POROSITY OF 25.9 PERCENT

MAXIMUM POROSITY OF 47.6 PERCENT

10

OIL ACCUMULATION IN POROUS ZONES IN LIMESTONE

OIL

ANGULAR AND SUBANGULAR GRAIN PACKING

RESERVOIR ROCKS

SANDSTONE

DOLOMITES AND LIMES

11

GAMMA RAY LOG

RADIOACTIVITY

SHALE VOLUME(Gamma Ray Index)

GR - GR clean

GR sh - GR cleanGI=

GR clean

GR sh

ZONE A

12

LAMINAR SHALE

DISPERSED SHALE

13

RESISTIVITYLOGS

14

RESISTIVITY

THE MEASURE OF THE RESISTANCE OF A GIVEN VOLUME OF MATERIAL

The resistivity of any formation is a function of the amount ofwater in that formation and the resistivity (salinity) of the water it-self. Formation water (salt water) is conductive, while the rock andhydrocarbon are normally insulators.

15

RESISTIVITY DEVICES

Todays drilling programs use either highly conductive fluids (salt muds) or low tonon-conductive fluids (fresh mud, oil base mud, air).

For fresh muds the Dual Induction tool is recommended, since electrical currentscannot be passed through non conductors. It is necessary to set up a ground loop withinduced currents. Deep induction (ILD) and the medium Induction (ILM) are such mea-surements. The shallow measurement is an electrical measurement and requires a con-ductive borehole fluid.

The Dual Laterolog measurements (LLD) deep laterolog and (LLS) shallow laterologare electrical measurements and require conductive fluids. Therefore, it is recommendedfor salt muds. Generally, a salinity of 50,000 ppm or greater is considered a salt mud.

The deep measurement from either device may require correction to read the resistiv-ity of the uninvaded zone(Rt) when invasion has occurred. In most cases this correction isminimal.

In order to get an accurate reading of the flushed zone (where the original fluids havebeen replaced by mud filtrate), a resistivity device reading very near the borehole is rec-ommended. For fresh muds that would be the Proximity Log, while with salt muds, therecommended device would be the Microlaterolog.

16

DUAL INDUCTION - FRESH MUD - AIR

BO

RE

HO

LE

ILMILD

SFL*

* Shallow measurement is not an induction deviceand needs a conductor in the borehole.

17

RESISTIVITY - SATURATION PROFILES

Distance from BoreholeT

rans

itio

n Z

one

Invaded ZonePermeability

Indicator

Und

istu

rbed

Zon

e

Flu

shed

Zon

e

Water Zone

Distance from Borehole

Distance from Borehole

Hydrocarbon Mobility(Permeability to Hydocarbons)

S W o

r S X

OB

oreh

ole

100%

0%

RXO RT

100%

0%

S W o

r S X

O

SXO

SW

18

SHALLOW

0.2

0.2

OHM-M 2000

20000.2

DEEP

MEDIUM

OHM-M 2000

OHM-M

-]20[+

SP

150API0

GAMMA RAY

DUAL INDUCTION LOG

GAMMA RAY SP

DEEP

MEDIUMSHALLOW

19

SHALLOW

0.2

0.2

OHM-M 2000

20000.2

DEEP

MEDIUM

OHM-M 2000

OHM-M

-]20[+

SP

150API0

GAMMA RAY

DUAL INDUCTION LOG

DEEP

GAMMA RAYMEDIUM

SPSHALLOW

20

DUAL INDUCTION LOG

SHALLOW

DEEP

MEDIUM

2000

-]20[+

SP

0.2

0.2 2000

2000

SP

MEDIUM

SHALLOW

DEEP

OHM-M

OHM-M

OHM-M0.2

21

INDUCTION LOG WITHAUTOMATIC CORRECTIONS

GAMMA RAY 0 150

CORRECTED DEEP.2 1.0 10 100 1000

MEDIUM

.2 1.0 10 100 1000

UNCORRECTED DEEP.2 1.0 10 100 1000

22

RXO

MEASUREMENTSPAD RESISTIVITY DEVICES

Pad resistivity devices have very shallow depths of investigation (reading very nearthe borehole) and hence are used to measure the resistivity of the flushed zone (RXO). Thedevices have soft rubber pads designed not to cut through the mudcake (the solids of themud left of the borehole wall from invasion). If invasion has occurred and a zone haspermeability.

A difference of hydrocarbon content in the flushed zone (1-SXO) and the hydrocarboncontent in the undisturbed zone (1-SW) indicates that the hydrocarbons near the boreholewere replaced by filtrates. Hence the is moved oil and, therefore, the zone has perme-ability to hydrocarbons.

A tow-armed (single diameter) caliper log is ran indicating mud cake thickness (HMC).

MICRO-SPHERICALLY FOCUSED LOG

The MSFL can be combined with a Dual Induction or a Dual Laterolog to give anaccurate reading of the resistivity in the flushed zone (RXO). Since this resistivity is verynear the borehole it can easily detect invasion and, therefore, when a zone has permeabil-ity. The shallow measurement hive this tool good vertical resolution allowing good detec-tion of thin beds. A MSFL works better in fresh mud than in salt muds.

MICRO-LATEROLOG

The micro-laterolog can give accurate resistivities in the flushed zone when salt mudsare used. It is essentially a laterolog device with a limited depth of investigation. Thistool is influenced by mud cakes greater than 1/4 inch thick. The micro-laterolog has evenbetter vertical resolution than the microlog.

PROXIMITY LOG

For fresh mud systems, the proximity log read the invaded or flushed zone. Theproximity log has more focusing and has a deeper reading (further form the borehole). Inaddition, it has a vertical resolution on the order of inches.

23

SHALE

TIGHT

PERMEABLE

SHALE

TIGHT

SHALE

PERMEABLE

PERMEABLE

PERMEABLE(WATER - NO INVASION) ?

MICRO - NORMAL

MICRO - INVERSE40

400

0

TYPICAL MICROLOG RESPONSES

SHALE

These are the oldest of the pad type devices. They combine two resistivitymeasurements with different depths of investigation. The Micro Inverse (solid coding)measures roughly 1.5 inches from the pad while the Miconormal (dashed coding)reads approximately 4 inches from the pad. When the pad is across a mud cake(permeable zone) a separation of the curves occurs.

This separation of the dashed curve reading higher resistivity than the solid curve iscalled "positive separation" and indicates mud cake. Therefore, these devices areexcellent permeability indicators.

24

MICRO - NORMAL

MICRO - INVERSE0

40CALIPER

GAMMA RAY

00 150

16 406

MICROLOG

MICROINVERSE

CALIPER

MICRONORMAL

GAMMA RAY

25

20

20

0

0

16.06.0 .2 1.0 10 100 20 001000

PROXIMITY

MICRO INVERSE

CALIPER

MICRO NORMAL

MICROINVERSE

CALIPER

MICRONORMAL

BIT SIZE

PROX

PROXIMITY MICROLOG

26

SPONTANEOUS POTENTIAL

The Spontaneous Potential (SP), also known as Self Potential is a record of thenatural occuring currents downhole. SP measures the potential difference betweenan electrode at the surface and an electrode in the conductive mud. Shales willgive a constant value (base line) and potential reservoir rocks will deviate fromthis base line. This deviation is usually in a negative direction.

SP CURVE

MV

SHALE

SAND

SHALEBASE LINE

IDENTIFY RESERVOIR ROCKS(Sandstone, Limestone, Dolomite, etc.)

27

SPONTANEOUS POTENTIAL (SP) LOG

SALINITY INDICATOR PERM INDICATOR

IMPERMEABLELIMESTONE

SHALE

SHALE

SHALE

PERMEABLE BED

SHALE

SHALE

FRESH WATER

SALTY WATER

SHALE

SALTY WATER

SALTY WATER

SHALE

SHALE

SHALE

WATER

SHALE

HYDROCARBONS

RMF vs RW

HYDROCARBON EFFECT

28

DETERMINATION OF RESISTIVITY

The formation RT (true resistivity) was measured using the deep reading from a dualinduction (fresh muds) or a deep reading from a dual laterolog (salt muds). Correction forinvasion, bed thickness (shoulder beds) or hole size may need to be considered.

The resistivity of the water in the uninvaded zone RW cannot be measured directly.Produced waters are measured at the surface and listed in a RW catalog by zone. Thesevalues can vary from one area to another and are sometimes contaminated, hence givingwrong readings. Ideally, a 100% water zone will exist and a RW can be "back calculated"from saturation formulas. Logging companies have experience with RW values whichbest predict production. These "whatever works" values are the second choice. The leastdesireable choice in most cases is an RW value derived from the SP.

The resistivity of the flushed zone (RXO) is calculated using the "tornado" chart or witha proximity log (fresh mud) or a micro laterlog (salt mud). The water in the flushed zoneis RMF and is then measured by pressing the liquids (filtrate) out of a mud sample. Itsresistivity is then measured with a "mud checker" in the logging truck. This RMF valueand the temperature at which the measurement were made are noted on the resistivity logheading.

29

USES OF RESISTIVITY

PERMEABILITY INDICATOR

Invasion of a zone cannot occur unless permeability exists. The separation ofthe medium (dotted) and the deep (dashed) induction or the deep and shallow laterologcurves indicates permeability. The positive separation of the microlog curves or acaliper reading less than bit size is an indication or permeability. The deflection of theSP curve from the shale base line may indicate permeability.

PREDICTION OF WATER CUT

Bulk volume water is the percent of the total volume (including rock) which iswater. By comparing the bulk volume water in a given zone versus water productionfrom various producing wells, a prediction of water cut can be made in a given field.

A critical BVW is BVWIRR which is the maximum amount of water a formationwill hold without producing water (irreducible water saturation). The relation tobulk volume water and resistivity is as follows:

These two values will be approximately the same unless there is permeability tohydrocarbons (moved oil).

WATER SATURATION APPROXIMATION (RATIO METHOD)

The separation between the shallow resistivity (solid) and the deep resistivity(dashed) on a dual induction or dual laterolog can indicate water saturation. Thefurther the separation between these two curves, the more likely it is water. Thecloser the curves, the more likely it is hydrocarbon bearing.

This is only a approximation for specific conditions, but can be useful for manyapplications. This method could allow the determination of oil water contacts in a zoneor give you an easy method of detecting hydrocarbons. It could be especially importantin the presence of conductive minerals where Archie methods will not work.

WATER SATURATION CALCULATIONS (ARCHIE SOLUTION)

Bulk volume water is also the product of water saturation times porosity.Therefore, with the resistivity and porosity a quantification of water saturation can bemade and the reserves in a given well can be calculated.

BVW = * SW = RW/RT

30

WATER SATURATION APPROXIMATION

The ratio method is considered an approximate or qualitative method fordetermining water saturation. This technique requires that a normal invasion profileand a resistivity contrast (Rmf - Rw). In other words, zone of low permeability as wellas zone of low or high porosity could have inaccurate advantages since no porositiesare required and no m (Archie method) is required.

Two ratios are needed for this calculation. The first ratio is of the invaded zoneRXO and the undisturbed zone RT. This allows a quick look at the relativeseparation between the deep (dashed) and shallow (solid) resistivity readings. Thewider the separation between these two readings, the more potential for water. Thesevalues are from the respective resistivity measurement with corrections made wherenecessary.

The second is a ratio of the water resistivity in the invaded zone (RMF) and theuninvaded zone (RW). Both of these values must be corrected for the temperature forthe zone you are calculating. Neither of these values come from the logs.

31

RATIO SW METHOD

SW = SXO =F X RMF

RXOF X RW

RT

THEN

SXO

= (SW

)15

SW =1.6 RXO

RW

RT RMF)(58RXO

RW

RT RMFXX OR

ASSUMING

&

32

DETERMINING WATER VS OIL

SHALLOW

DEEP

MEDIUM

2000

OHM-M

OHM-M

2000

OHM-M 20000.2

0.2

0.2

-]20[+

SP

RMF = .52

RW = .04

DEEP

MEDIUM

SHALLOW

SP

A

B

C

D

EF

G

IN SPECIAL CASES: Bulk Volume Water =RWRT

33

RATIO METHOD EXAMPLE

CALCULATE BULK VOLUME WATER

POINT SHALLOW / DEEP BVW RATIOSW*

A 20/6 ________ 33

B 30/6 ________ 43

C 15/9 ________ 20

D 25/5.3 ________ 42

E 38/4 ________ 66

F 19/2 ________ 66

G 20/1.5 ________ 83

GIVEN: RW = .04

*APPROXIMATE SW

34

RESISTIVITY

1. Consists of several curves with different distances of investigation.

A. Deep (dashed curve) measures deepest, a reading of 6-12 ft. approximates theuninvaded zone (RT) and usually reads further to the left.

B. Medium (dotted curve) measures deeper than the shallow (usually betweenthe deep and shallow).

C. Shallow (solid curve) measures near the wellbore, usually reading the furthestto the right. The addition of a MSFL* (Micro Spherically Focused Log) willgive a good approximation of RXO.

*MSFL can be added to a dual induction or a laterolog for RXO

measurements.

2. Modern log scales are on a logarithmic grid.

3. Relative amounts of separation between the medium and the deep (DIL) or shallow(DLL) indicates invasion, therefore, permeability.

4. Another indication of permeability is the separation of the MSFL from the shallow ormedium.

5. The SP identifies potential reservoir rocks by deviating from a shale base line.

DUAL LATEROLOG

DEEP LATEROLOG

SHALLOW LATEROLOG

*MSFLMICRO LATEROLOG (ATLAS)

DUAL INDUCTION

DEEP INDUCTION

MEDIUM INDUCTION

SFL / GUARD

*MFSL

DEEP

MEDIUM

SHALLOW

VERY SHALLOW

35

POROSITY & LITHOLOGYIDENTIFICATION

36

POROSITY

TOTAL VOLUME OCCUPIED BY PORES,EXPRESSED IN PERCENT

"HOLES IN THE ROCK"

37

DETERMINATION AND USES OFPOROSITY

Porosity cannot be measured directly, but rather a parameter related to porosity is mea-sured. Each porosity device responds to the type of rock and the fluid in the rock aswell as porosity. Because complex rock types and shaliness can mislead the interpreta-tion of a single device, two or more porosity devices may be required.

By using two or more porosity devices a more accurate porosity as well as the rock typeof lithology (rock type) can be determined. In many cases the detection of gas in theporosity is possible.

There are two types of porosity. Primary porosity resulting from the deposition of thematerial and secondary resulting from some later mechanical or chemical change. Frac-tures would be an example of secondary porosity.

The combination of porosity and resistivity allows for the calculation of the percent ofwater in the porosity (Sw). The percent of hydrocarbons in the porosity So then isdefined by 1-Sw. This information can then be used to determine the economics of awell and the subsequent development of a field.

The number of barrels of stock tank oil in place (BSTO) can be calculated the followingformula:

A simple equation for oil reservoirs would be:

BSTO = 7758 A h So / FVF

BSTO = BARRELS OF STOCK TANK OILA = DRAINAGE AREAh = THICKNESS OF PAY = POROSITYSo = OIL SATURATION (1-Sw)FVF = FORMATION VOLUME FACTOR

38

POROSITY MEASURING DEVICES

I. LITHO TYPE DENSITY TOOL

II. COMPENSATED NEUTRON TOOL

III. BOREHOLE COMPENSATED SONIC (BHC)

39

DENSITY POROSITY DEVICE

S D

b = f + (1-) ma

ma - bma - f

= =

40

Mud Cake(mc * hmc)

)

) Short SpacingDetector

Long SpacingDetector

Formation

Source

41

PHOTO ELECTRIC USES

The Pe measurement is strongly related to the nature of the formationrock type. Therefore, methods of interpretation have been developedto yield better answers for lithology and hydrocarbon type.

1. As a matrix indicator (the lithology curve)

2. In combination with density b as a two-mineral model for a better determination of the porosity

3. In combination with the density neutron to analyze more complex rock types for a solution to three-mineral models

4. For easier distinction between oil and gas in the formation

42

THE LITHO TYPE DENSITY LOG

The density of a formation is a function of the density of the rock material, theamount of porosity, and the density of the fluid in the pores. A density tool responds tothe electron density (number of electrons per cubic centimeter) as a function of the num-ber of Compton-scattering collisions. The electron density is then related to the true bulkdensity or Pb expressed in grams per cubic centimeter.

The litho type tool has a additional measurement from the lower energy gamma rays.This measurement is a function of the photo electric cross section of different elements.The Pe curve is an index of this cross section.

The litho type density log can help determine rock type (lithology) as well as poros-ity. Evaluation of shaley sands, oil shales, complex rock types, and gas detection areaided by the density log.

SWS - LITHODENSITY LOG

HLS - SPECTRAL DENSITY LOG

ATLAS - Z-DENSITY

43

2.71

2.641.81

3.14 2.88

1.00.358

0.67

WATER (FRESH)

GAS (CH4)

SHALE

DOLOMITE

CALCITE (LS)

QUARTZ (SS)

Pe ma

5.08

OIL (n(CH2))

COMMON Pe AND

ma VALUES

VariableAbout 3

-0.060.095

0.119

44

LITHO DENSITY LOG

0

GAMMA RAY

CALIPER

C

B

A

BULK DENISTY

Pe

CORRECTION

GAMMA RAY

CALIPER

3.02.0

150

166

BULK DENISTY

2700

2.5

CORRECTION +.250-.250

PHOTO ELECTRIC1050

45

0

6

BULK DENISTY

GAMMA RAY

CALIPER

E

D

CALIPER

LITHO DENSITY LOG

CORRECTION

PHOTO ELECTRIC BULK DENISTY

150

16 2.0 3.0

CORRECTION +.250-.250

PHOTO ELECTRIC

0 105

2.5

3600

GAMMA RAY

46

NEUTRON POROSITY

Neutron logging devices react to the hydrogen in the formation. Since hydrogenis present in water and hydrocarbbons the tools are responding to the total fluid andhence the porosity in the rock.

FEW HYDROGEN MOLECULES IN THE FORMATION = LOW POROSITYMANY HYDROGEN MOLECULES IN THE FORMATION = HIGH POROSITY

In a gas there are 1/5 to 1/10 as many molecules as with a liquid. Therefore, theporosity from a neutron device will be too low. For example a zone with 15% porositycould appear to be 5 - 10% using a neutron device.

A combination of the neutron and density porosity devices can give areasonable estimate of porosity. A determination of the rock type (lithology) and gasdetection become reasonable with the assumption of a two mineral model.

Since shale contains a great deal of trapped water (hydrogen) a little shale canmake the neutron porosity too high. The above methods then become too high. In ashaley zone the density porosity alone becomes a better estimate of porosity.

TRUE POROSITY QUICKLY ESTIMATED BY

= 1/2 (D + N)

IF A ZONE IS GAS PRODUCTIVE USE THE "2/3 METHOD"

= 1/3(2D + N)

47

COMBINED WITHDENSITY AND

DUAL INDUCTION"TRIPLE COMBO"

OTHER TOOLS

COMPENSATED NEUTRON LOG

BOREHOLE FORMATION

3 3/8" Dia

FAR DETECTOR

NEAR DETECTOR

SOURCE

48

NEUTRON POROSITYMATRIX LIME

DENSITY POROSITYMATRIX 2.71

DOLOMITE

NO

GA

S

GAMMA RAY0 150

Pe30

30

-10

-10

LIMESTONE

Pe

DENSITY

ANHYDRITE

SHALE

SAND

SALT

GAS SAND

NEUTRON

LIMESTONEOR

GASSY DOLOMITE ?

GAMMA RAY

LITHOLOGY LOGGINGFINDING THE ROCK TYPE

0 5

49

MATRIX 2.71

NEUTRON DENSITY

GAMMA RAY

CALIPER

GAMMA RAY0 150

CALIPER6 16 30

30

0 10

-10

-10

DENSITY

NEUTRON

Pe

DENSITY POROSITY

Pe

MATRIX LIME

NEUTRON POROSITY

50

NEUTRON - DENSITY LOG WITH Pe

MATRIX LIME

MATRIX 2.71

0

GAMMA RAY

CALIPER

100

30

30

-10

-10

GAMMA RAY

CALIPER6 16

150

DENSITY

Pe

NEUTRON

D

Pe

NEUTRON POROSITY

DENSITY POROSITY

A

B

C

51

MATRIX LIME

MATRIX 2.71

NEUTRON - DENSITY LOG WITH Pe

GAMMA RAY

CALIPER

NEUTRON

Pe

DENSITY

16

10

-10

-10

30

30

0

150GAMMA RAY

CALIPER6

0

A

B

C

Pe

DENSITY POROSITY

NEUTRON POROSITY

52

T1

R1

R2

R3

R4

T2

FO

RM

AT

ION

5'

3'5'

3'

BOREHOLE COMPENSATED SONIC

TRAVEL TIME MEASURED THROUGH 1 FT. OF FORMATION

53

tlog

= tma

= 1/Vma

SANDSTONES 18,000 - 19,500 55.6 - 51.3LIMESTONES 21,000 - 23,000 47.6 - 43.5DOLOMITES 23,000 - 26,000 43.5 - 38.5STEEL 57.0

Vma

tma

RT

SONIC

SONIC LOG(SPEED OF SOUND)

54

RT

tlog

= tfluid

+ (1-)tmatrix

=tlog - tmatf - tma

SONIC POROSITY

CpX

1( )

Cp

1= 1 for Limes, Dolomites and Shales where Tshale < 100 msec/ft

Cp = 1 Tshale /100 msec/ft if > Tshale 100 msec/ft

55

T

TRAVEL TIMEsec/ft

SONIC LOGTRAVEL TIME THROUGH 1 FT. OF FORMATION

CALIPER

GAMMA RAY

150

16

GAMMA RAY

CALIPER6

0

100 4070

A-

C-

B-

56

POROSITY AND LITHOLOGY IDENIFICATION1. Three types of porosity logs:

A. Density: Utilizes a pad device which cuts through mudcake. Two arm caliper usuallly reads the large side of the hole. Too high in gas.

B. Neutron: Responds to hydrogen. Shale makes porosity too high. Too low in gas.

C. Sonic: Travel time of sound through one foot of formation. Shale makes porosity too high. Uncompacted sands are a particular problem. Very operation sensitive and poor response equation.

2. Porosity cannot be computed from a single porosity tool without knowing thetype of rock.

3. Porosity can be estimated with a neutron density by the following:

A. Fluid filled (no gas): = (D + N)/2* = (2D + N)/3*

* When a zone is shaley, will be too high.4. The photoelectric (Pe) curve can be used for better estimation of the rock type (especially in gas)

LITHOLOGY

DolomiteCalaite (LS)

*Quartz (SS)

Shale

1.18

3.14

~3* Sandstone can be 2.2 to 2.6 when cemented with calcite.

Gamma Ray Log

Shale line (Average reading in shales) can be used to determine percent shale.3. Furthest to left clean zone indicating good permeability.

2. Radioactivity or shaliness increases left to right.

1. Measures natural radioactivity usually associated with shale.

5.08

Pe

57

OPEN HOLE

INTERPRETATION

REFERENCE

58

COMMON Pe AND

ma VALUES

2.71

2.641.81

3.14 2.88

1.00.358

0.67

WATER (FRESH)

GAS (CH4)

SHALE

DOLOMITE

CALCITE (LS)

QUARTZ (SS)

PE

ma

5.08

OIL (N(CH2))

-0.060.095

0.119

VARIABLEABOUT 3

59

MATRIX 2.71

GAMMA RAY

DOLOMITE

LIMESTONE

ANHYDRITE

SHALE

SAND

SALT

GAS SAND

DENSITY

0

30

30

5

-10

-10

GAMMA RAY 1500

Pe

NEUTRON

SHALE

Pe

MATRIX LIME

LIMESTONEOR

GASSY DOLOMITE?

NEUTRON POROSITY

DENSITY POROSITY

LITHOLOGY LOGGINGFINDING THE ROCK TYPE

NO

GA

S

60

SATURATION DETERMINATIONFOR CLEAN LIMES AND DOLOMITES

Sw

Porosity

RtR

o

FRw

61

ARCHIE'S RELATIONSHIP

It has been established experimentally that the resistivity of a clean formation is proportional to theresistivity of the salt water with which it is fully saturated (R

O). The constant of proportionality is called

the formation resistivity factor, or F, where RW = Resistivity of the formation water.

F = Ro / R

w

In a formation containing oil or gas, both of which are electrical insulators, resistivity is a function notonly of the formation factor F and the water resistivity R

W, but also the water saturation SW. SW is the

fraction of the pore volume occupied by formation water. G. E. Archie determined experimentally thatthe water saturation of a clean formation can be expressed in terms of its true resistivity (RT).

Sw = (FR

w / R

t)1/n

Since RO = F * RW, water saturation can be expressed as:

Sw = (R

o / R

t)1/n

For a given porosity, the ratio of RO to R

W remains nearly constant. The porosity of a rock is the total

volume occupied by the pores or voids. Formation factor is a function of porosity and also of porestructure and pore size distribution. Archie has proposed the following formula:

F = a / m

The constant "a" is an empirically derived constant that normally equals 1. Usually in Limes and Dolomitesthe cementation factor "m" = "n" = 2 therefore:

Sw = (R

w / R

t)1/2 /

Humble determined that "a" = 0.62 in Sandstone formations and "m" = 2.15 which is rewritten as:

Sw = (.81R

w / R

t)1/2 /

62

GAMMA RAY

B

3900

20000.2 1 10 100

0 API 150

-]20[+

SP

MEDIUM

0.2

SHALLOW

OHM-M

2000

20000.2

DEEP

OHM-M

4000

A

C

D

E

DUAL INDUCTON LOG

63

3900

2.71DPHI -1030

LIMENPHI30 -10

10 -.025 .025

SDL PE COM0

NEUTRON DENSITY LOG

010

INCHESCALIPER

6 16

GAMMA RAY

0 150API

DELTA RHOGM/CC

4000

64

TENSION10000 POUNDS 0

3900

4000

MICRO NORMAL0 OHM-M 40

GAMMA 0 API 150

CALIPER 6 INCHES 16

MICRO INVERSE0 OHM-M 40

MICROLOG

65

LOG INTERPRETATION PRACTICEDETERMINATION OF SW

GIVEN: RW = .04 (READ VALUES AT A DEPTH OF 4020)

A. ON THE LOG ON PAGE 63 READ:1. Neutron Porosity (Dotted) = __________2. Density Porosity (Solid) = __________3. Photo Electric Index = Pe = __________

B. USING THE LOG ILLUSTRATION ON PAGE 59 DETERMINE:1. The rock type __________2. Is there gas in the porosity? __________

C. USING EITHER THE 1/2 OR THE 2/3 RULE (IF GAS) DETERMINE:1. Actual Porosity = __________

D. USING THE LOG ON PAGE 62 READ THE DEEP INDUCTION:1. RILD (Dashed) = __________

E. USING THE LOGS ON PAGE 62 AND 64:1. Is there a separation between the deep (dashed and the Medium (Dotted) indicating permeability? __________2. Does the Microlog show positive separation at the same depths indicating permeability? __________

F. USING THE NOMOGRAPH ON PAGE 60:1. Connect RW (.04) with the Porosity from step C above2. Extend this line to find RO = __________3. Connect the RO found in step 2 with the RILD (approximate Rt) found in Question D4. Extend this line to find SW = __________

G. AT WHAT DEPTH IS THERE MOST LIKELY WATER? __________

H. IF WE ASSUME THAT DEPTH TO BE 100% WATER WE CAN USE THE NOMOGRAPH (GOING BACKWARDS) ON PAGE 61 TO CALCULATE RW:

1. Read the deep induction from the log on page 62. _______________2. Connect the Rt in Step 1 with SW = 100% and extend the line to find RO = __________3. Read the Neutron Porosity and Density Porosity from the log on page 63, use the 1/2 rule and find = __________4. Connect the RO Found in step 2 with found in step 3 and extend this line to find RW = __________

66

SUMMARY INTERPRETATION AT A GLANCE

Resistivity1. Consists of several curves with different distances of investigation.

A. Deep (dashed curve) deepest reading of 6-12 ft. Approximates the uninvaded zone(Rt) usually reads furthers to the left.

B. Medium (dotted curve) measures deeper than the shallow, usually between the deepand shallow.

C. Shallow (solid curve) measures near the wellbore usually reading the furthest to theright. The addition of a MSFL *(micro spherically focused log) will give a goodapproximation of Rxo.

*MSFL can be added to a dual induction or a laterolog for Rxo measurements.

2. Modern log scales are on a logarithmic grid.

3. Relative amounts of separation between the medium and the deep (DIL) or shallow deep(DLL) indicates invasion, therefore, permeability.

4. Another indication of permeability is the separation of the MSFL from the shallow or medium.

5. The SP identifies potential reservoir rocks by deviating from a shale base line.

Gamma Ray Logs1. Measures naturally occurring radioactivity. Usually due to clay or shale.

2. Lower gamma ray usually indicates less clay, therefore, better permeability.

Medium Induction

SFL / GUARD

*MSFL

Deep LaterologDual Induction

Dual LaterologDual Induction

Shallow Laterolog

Very Shallow

Shallow

Medium

Deep

Micro Laterolog (Atlas)*MSFL

67

SUMMARYINTERPRETATION AT A GLANCE

A. Identify Radioactive ReservoirsB. Facies and MineralogiesC. Better Permeability Indication

Gamma Ray (Continued)3. Percent clay determination by picking shale line (Average reading in shales) and clean line

(lowest gamma ray in a zone.

4. Spectral Gamma Ray - Thorium, Potassium, and Uranium

*Sandstone can be greater than 2 when cemented with calcite.

*Quartz (SS)

Dolomite

1.81

3.14

Calcite (LS)

LITHOLOGY Pe

5.08

About 3

Porosity and Lithology Identification1. Three types of porosity logs:

A. Density: Utilizes a pad device which cuts through mudcake. Two arm caliper usually readsthe large side of the hole. Too high in gas.

B. Neutron: Responds to hydrogen. Shale makes porosity too high. Too low in gas.

C. Sonic: Travel time of sound through one foot of formation. Shale makes porosity toohigh. Uncompacted sands are a particular problem. Very operation sensitive and poorresponse equation.

2. Porosity cannot be computed from a single porosity tool without knowing the type of rock.

3. Porosity can be estimated with a neutron density by the following:

A. Fluid filled (no gas): = (D +

N) / 2*

= (2D +

N) / 3*

*When a zone is shaly, will be too high

Porosity and Lithollogy Identification1. Three types of porosity logs

Shale

68

X900

Y000

Y100

BULKVOLUMEWATER

V

V

25 3APPARENT GRAIN DENSITY DIFFERENTIAL CALIPER

-20 20

X800

GASFLAGVOLUME MATRIX

0 % 1

VOLUME SHALE 0 % 1

DEPTH

RO 0 1000

Rt 0 1000

BULKVOLUME

WATER 50 % 0

EFFECTIVEPOROSITY

50 % 0

DIFFERENTIALCALIPER

EFFECTIVEPOROSITY

WATERSATURATION

HYDROCARBONSRtRO

VOLUMESHALE

GRAINDENSITY

VOLUMEMATRIX

TODAY'S COMPUTER INTERPRETATIONS

69

OPEN HOLE

INTERPRETATION

EXERCISE

70

2 BVW = * SW CONSULTANTSSIMPLIFIED TRAINING FOR IMMEDIATE USE

405 324-5828FAX 324-2360

704 SAGE BRUSH RDYUKON, OK 73099

3 SW =

LOCATION:

FIELD:

COMPANY:

COUNTY:

WELL:

SEC: TWP:

STATE:

RGE:

RTRILDRWZONE RMF RILM RSFL RXO SW

WATER SATURATION (RATIO)3RESISTIVITY

BVW2SW

SW (ARCHIE)1

ND X LITH

POROSITY

(RW / RT)1/2

(.81 RW / RT)1/2

1 SANDSTONE SW =

1 LIMES AND DOLOMITES SW = ( )RXO RW 5/8 RT * RMF

RWRT

RWRMF

RXORT

71

OPEN HOLE LOGINTERPRETATION EXERCISE

FIND:WATER ZONE?HYDROCARBON ZONE?FRACTURES?LITHOLOGY?ARE THE LOGS EFFECTED BY GAS?

USE EITHER 1/2 OR 2/3 RULE TO FIND POROSITY ATPOINTS INDICATED

MAKE COMMENTS ABOUT PERMEABILITY ANDPRODUCIBILITY

72

EXERCISE #1

SHALLOW FOCUSED LOG .2 1.0 10 100 1000

MEDIUM INDUCTION LOG .2 1.0 10 100 1000

DEEP INDUCTION LOG .2 1.0 10 100 1000

GAMMA RAY 0 150

SP-]20[+

ILD

ILM

SFLSP

GR

94003

2

1

4

9300

73

GAMMA RAY 0 150

NEUTRON POROSITY 30 20 10 0 -10

DENSITY POROSITY 30 20 10 0 -10

CALIPER 5 INCHES 15

EXERCISE #1

GR

CAL

DENSITY

9400

NEUTRON

9300

1

2

3

4

LIME MATRIX

MATRIX 2.71

74

EXERCISE #2

SHALLOW FOCUSED LOG .2 1.0 10 100 1000

MEDIUM INDUCTION LOG .2 1.0 10 100 1000

DEEP INDUCTION LOG .2 1.0 10 100 1000

GAMMA RAY 0 150

SP-]20[+

9600

9700

SFL

ILMILD

GR

SP

5

8

7

6

75

EXERCISE #2

DENSITY POROSITY MATRIX 2.71 30 20 10 0 -10

CALIPER 5 INCHES 15

GAMMA RAY 0 150

NNEUTRON

9600

9700

CAL

DDENSITY

NEUTRON POROSITY 30 20 10 0 -10

5

6

7

8

GR

LIME MATRIX

76

MINERAL IDENTIFICATION PLOT

77

GAMMA RAY NEUTRON POROSITY

MATRIX 2.71

Pe

Pe

NEUTRON

SANDSTONE

GAMMA RAY

LIMESTONE

DOLOMITE

50

MATRIX LIME

30

DENSITY POROSITY30 -10

-101250

DENSITY

LITHOLOGY PRESENTATION

78

EXERCISE #3

SHALLOW FOCUSED LOG .2 2000

MEDIUM INDUCTION LOG .2 2000

DEEP INDUCTION LOG .2 2000

GAMMA RAY 0 150

SP-]20[+

4100

3

1

4200

2

79

EXERCISE #3

PEF 0 10 20

CALIPER 6 INCHES 16

GAMMA RAY 0 150

4100

4200

NEUTRON POROSITY .30 .20 .10 0 -.10

DENSITY POROSITY .30 .20 .10 0 -.10

3

1

2

80

EXERCISE #3

MICRO INVERSE 0 (ohmm) 40

GAMMA RAY 0 150

CALIPER 6 16

4100

4200

MICRO NORMAL 0 (ohmm) 40

3

1

2

82

OHM-M

DEEP

OHM-M

0.2

OHM-M0.2

0.2

GAMMA RAY

EXERCISE #4

DEEP

SHALLOW

MEDIUM

4700

2

1

SP

MEDIUM

SHALLOW

4600

2000

2000

2000

API

GAMMA RAY

-]20[+

SP

0 150

83

CALIPER

GAMMA RAY

0

0 150

166

MATRIX LIMEDENSITY POROSITY

MATRIX 2.71

PE

NEUTRON POROSITY

NEUTRON

EXERCISE #4

GAMMA RAY

CALIPER

DENSITY

4700

2

1

10

4600

30

30

Pe

-10

-10

84

EXERCISE #4

MICRO INVERSE 0 (ohmm) 40

GAMMA RAY 0 150

CALIPER 6 16

4700

MICRO NORMAL 0 (ohmm) 40

4600

1

2

85

LOGINTERPRETATION

ANSWERS

86

ANSWERS TO OPEN HOLEINTERPRETATION PRACTICE

POINT SWR SW BVW(Ratio)

EXERCISE #1

Upper zone fracturedLower zone bed correctionsGassed effect both zones

1 99 55 .0553 45 .06

Ra = 40 Rt = 160 4 17 .027

EXERCISE #2

Upper zone no perm no SPLithology unclear Pe could clarifyLower zone fractured in topObviously wet in bottom

Water free production 6 16 .023Wet! 8 100 .105

EXERCISE #3

Low resistivity pay excellent permResistivity constant porosity: 18% / Lower 2Top 6 ft. 1MMCFPD no water

1 45 752 70 100

EXERCISE #4

Good microlog perm upper zoneBottom zone low porosity no ML permClassic example: water in bottom transition zone oil in top

1 21 .0452 82 .17

87

SATURATION DETERMINATION

FOR CLEAN SANDSTONE

RW FR%

RO RtSW%

0.81

2F =

OR

88

SATURATION DETERMINATION

FOR CLEAN LIMES AND DOLOMITES

RW F RORt

SW

POROSITY

M = 2

89

DEVELOPMENT

OF THE

PERMEABILITY PROFILE

90

PERMEABILITY ESTIMATE APPLICATIONS

I. Productivity profile -

Where are the producing zones and water zones located?

II. Productivity estimate -

What effect will a fracture treatment have on productionand is it cost effective?

III. Fluid efficiency distribution-

Where will the fracture fluid leak off?

IV. Pore pressure distribution -

Where is the pore pressure depletion taking place thatwill affect the in-situ stress distribution?

91

I. PRODUCTIVITY PROFILE

LOCATE THE PRODUCING ZONE(S)

Moved Water

Hydrocarbons

K

0.01 MD 10.0Deep Resistivity

0.2 OHMM 2000.0 PermGR

0.0 GAPI 150

0.2 e or BVW 0.0

92

II. PRODUCTIVITY ESTIMATE

HYDRAULIC FRACTURE EFFECTS ON PRODUCTIVITY

FLOW RATE IS DIRECTLY RELATED TO:

Reservoir permeability-thickness

Fracture length and conductivity

Reservoir PVT parameters

93

III. FLUID EFFICIENCY DISTRIBUTION

FRAC FLUID LEAKOFF

94

IV. PORE PRESSURE DISTRIBUTION

FOR STRESS CALCULATIONS

95

LOG DERIVED PERMEABILITY

Permeability can be derived from logs using the following inputs:

*The 'C' factor is used to correlate the log derived permeability estimate to welltest or apparent permeability. In other words, it corrects a permeability from thelogs on offset wells based on empirical data.

1. Effective porosity (e)2. Bulk Volume Water Irreducible (BVI)3. Correlation factor (C)*

96

SOURCES OF PERMEABILITY

FOR FINDING THE "C" FACTOR

USE ONE OF THE FOLLOWINGTO CORRELATE LOG DERIVED PERMEABILITY:

A. WELL TEST DATA (WHEN POSSIBLE)

OR IN LOW PERM

B. PRODUCTION HISTORY MATCH ON OFFSET WELL

C. CORES CAN WORK WELL FOR DRY GAS

97


SANDSTONE RESERVOIR CALCULATION

keff = C X e2 X

where:

keff = Effective permeability (md)e = Effective porosity (shale corrected crossplot)BVI = Bulk volume water irreducibleC = A constant for each reservoir type

e and BVI are expressed in fractional unitskeff is permeability to total fluids.Permeability to hydrocarbons requires a water cut input.

To match core permeability to air set C = 100

The above equation is a derivation of the relationship by Coates an Denoo (1981)

BVI

(((((e-BVI)[ ]2

If e is greater than BVI the zone is permeable

If e is less than BVI the zone is impermeable

98

LOG PERMEABILITY EXERCISE # 1

Sandstone oil reservoir with the following parameters:

BVI = 0.05 (Column C)C = 17.1 (Cell C4)

keff = C X e2 X

Using this equation in the "Permeability Calculator" Workbook:Estimate effective permeability for the following effective porosities:

e = .07 keff = __________ md

e = .10 keff = __________ md

e = .12 keff = __________ md

e = .15 keff = __________ md

With a permeability cutoff for net pay of 0.001 md:

What is the porosity cutoff? _______ %

BVI

(((((e-BVI)[ ]2

99

LOG DERIVED PERMEABILITY OUTPUT

FOR OIL SAND

Where: BVI = 0.05 and C = 17.1

Will this produce water?

BVI

BVI

100


UNFRACTURED CARBONATE RESERVOIRS

keff = C X sonic2 X

where:

keff = Effective permeability (md)sonic = Sonic porosity*BVI = Bulk volume water irreducibleC = A constant for each reservoir type

* Sonic porosity is recommended to avoid including secondaryporosity in the permeability estimate.

sonic - BVI

BVI[ ]2

A well test may be of more value in carbonates

The permeability estimate in carbonates is qualitative due to complex porethroat structures. Many carbonates have there permeability dominated byfractures and unless a pre-frac well test is performed the results may be poor.

101

PERMEABILITY FROM NMR

1. Using the MRIL

k = [( ) ( )]MPHIAC

MFFIBVI

C

Where MPHI = Porosity from MRIL MFFI = Free Fluid Index ( e - BVI) C = Usually 2 A = Usually 10

2. Using the CMR

Where T2 = Log Mean T2

B = Usually 4

C = Usually 2

k = C NMR T2CB

102

PERM CALIBRATION FOR NMRService Company Calibrations

1. With the MRIL Perm adjust the A factor to get effectiveperm.

2. With the CMR perm adjust the C factor to get effectiveperm.

3. Porosity Considerations

A. NMR Porosity is close to e

B. NMR Porosity may be too low in gas.

C. NMR Porosity can be replaced by shale corrected neutron-density porosity.

D. Use neutron-density porosity in gas zones or when waittime is too short.

4. Alternately use e from NMR and BVI in spreadsheet forcalculating perm.

103

PERMEABILITY EXERCISE

NET PAY ESTIMATION

WATER CUT PREDICTION

104


FINDING WATER PRODUCING ZONES

There is no water production when: BVW < or = BVI

Bulk Volume Water (BVW) = e X Sw

e

{ tSw

105

Using the BVW on pages 106 and 107 and the Relative Permgraphic below, circle the produced fluids for each zone.

No water production - < 6% > 10% - 100% water production

NOTE: This Relative Permgraphic is for the specificarea of these logs.


CALCULATING LOG DERIVED PERMEABILITY

Part I

Part II

Calculate log derived permeability for each zone using theworkbook "Permeability Calculator"

Using: keff = [C X e2 X ((e - BVI) / BVI)]2

Where: C = 17.5 (Cell C1)and BVI = 0.06 (Column C)

106

PERMEABILITY AND WATER CUT

C = 17.5 and BVI = 0.06

Depth BVW Fluid(s) e keff (md) keff (md) Produced BVI = 0.6 BVI=BVW

1 7579 .104 Oil / Water .177 _____ _____

2 7588 .098 Oil / Water .168 _____ _____

3 7611 .132 Oil / Water .191 _____ _____

4 7624 .091 Oil / Water .140 _____ _____

5 7648 .110 Oil / Water .155 _____ _____

1

5

4

3

2

.177 .104

.098.168

.132

.091

.110

.191

.140

.155

107

Depth BVW Fluid(s) e keff (md) keff (md) Produced BVI = 0.6 BVI=BVW

6 7680 .089 Oil / Water .150 _____ _____

7 7705 .087 Oil / Water .154 _____ _____

8 7755 .082 Oil / Water .156 _____ _____

6

7

8

.150

.154

.156

.089

.087

.082

PERMEABILITY AND WATER CUT

C = 17.5 and BVI = 0.06

108


PERM EXERCISE ANSWER SHEET

SCALE FACTOR (C) 17.5

PERM AVERAGES 0.64 MDKH TOTAL 3.87 MDFTKH WELL TEST 3.87 MDFT

DEPTH PHIE BVI PERM FLUID

7579 0.177 1.950 1.143 Water7588 0.168 1.800 0.790 Oil & Water7611 0.191 2.183 1.943 Water7624 0.140 1.333 0.209 Oil & Water7648 0.155 1.583 0.443 Water7680 0.150 1.500 0.349 Oil & Water7705 0.154 1.567 0.423 Oil & Water7755 0.156 1.600 0.464 Oil & Water7835 0.180 2.000 1.286 Oil & Water7865 0.141 1.350 0.221 Oil & Water7955 0.141 1.350 0.221 Oil7975 0.143 1.383 0.245 Oil

109

CALIBRATED LOG PERMEABILITY

The objective is to avoid growing into a permeable water zone

with a propped fracture. At what depth should the frac stop

growing? __________

Moved Water

Hydrocarbons

K

0.01 MD 10.0Deep Resistivity

0.2 OHMM 2000.0 PermGR

0.0 GAPI 150

0.2 e or BVW 0.0

7600

7700

7800

7900

110

PERM SPREADSHEET EXERCISE

1. Mark the following page with the layers that are permeableand impermeable for your upper or lower portion.

2. Using the Log Analysis Calculations Blank input the Cfactor of 3.8 into Cell AC4. The calculated Perm Archiewill be effective permeability assuming BVW = BVI.

3. Use the Excel paste function to average the ModifiedSimandoux Perm for each layer marked and write theaverage permeability in the worksheet.(FracProPT will use this perm to calculate leakoff)

4. Mark the permeability layers with an X to indicate leakoffwill occur.

5. Mark the Pore Pressure Gradient (PP) in the various

layers. This PP will later be used in the stress calculations.

111


1. Write the Pore Pressure Gradient in each layerWireline pressures were measured in this well

A. The lower sand has a PP of 0.82 (higher pressure)B. The upper sand has a PP of 0.79 (higher pressure)C. Assume all impermeable layers PP is 0.82

Where PP = Pore Pressure Gradient

2. Mark an X in a layer if it is going to leak off. PERM LAYERSLeakoff PP

AVG.

PERM

.001 .01 .1 1

11600

11500

11400

112

EAST TEXAS SAND - CV TAYLORWater Frac or Sand / Gel Frac

Which Would You Recommend?

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.06 md

.05 md

NMR Perms were Calibrated to Cores and Corrected for GasGamma RayCaliper, SP

&

VShale Dual Induction

Neutron / DensityMRIL Porosity

Hint: Look at the Clay and the Perm

Permeability.002 2

113

NMR

BVI, POROSITYMOVABLE WATERHYDROCARBONS

114

IDEALIZED ECHO TRAIN

T2R

Free Fluid (FFI)

TE

Bulk Volume Irreducible (BVI)

Time

Am

plit

ud

e

NMR Porosity

N

S

Sign

al A

mpl

itud

e

Time (ms)

Spin Echoes

RF Pulses

1) Permanent magnet polarizeshydrogen nuclei

2) Transmit train of RF pulses,record returning spin echoes

3) Wait for re-polarization

4) Repeat steps 1-3

The Basic NMR Experiment

115

ECHO TO T2 INVERSION

Spin

-ech

o d

ata

T2

Spec

tru

mI

nver

sion

P

roce

ssin

g

tim

e

mul

tiex

pone

ntia

l fit

to s

pin-

echo

am

plit

udes

larg

e-po

re (

mob

ile fl

uid

) sig

nal

smal

l-po

re (i

rred

ucib

le f

luid

) sig

nal

clay

-bou

nd w

ater

NM

R p

oros

ity

0.00

0.50

1.00

1.50

2.00

0.1

110

100

1000

1000

0

T2

[mse

c]Incremental Porosity [pu]

FF

IB

VI

116

EFFECTS OF OIL ON T2 DISTRIBUTIONOil and Water Saturation Effects

0.1 1 10 100 1000 10,000

T2 (ms)

1.8 ms4304 cp.

40 ms35 cp

609 ms2.7 cp

Oil Viscosity Effects

0.6

2.1

7.4

26.6

95.4

341.

8

1224

.80.0

1.0

2.0

3.0

4.0

Incr

emen

tal

Por

osit

y %

T2Distribution

Sw = 100%

Sw = 84.3%

Sw = 65.4%

Sw = 56.9%

117

Clay VolumeEffective PorosityGamma Ray1234

123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234

Dual InductionT2 DistributionVariable Density

T2 CUTOFFS AND DISTRIBUTIONBulk Volume Irreducible and Free Fluid

Movable Water

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Gas

Gas

Gas

118

0

20 40 60 80

100

0100

200300

400500

600T

ime (m

s)

Incremental Porosity %

Sm

all Po

re Size =

Rap

id D

ecay Rate

Larg

e Po

re Size =

Slo

w D

ecay Rate

Water F

illed P

ores

T2 - RELATIVE TO SURFACE AREA

119

Clay VolumeEffective PorosityGamma Ray Dual Induction

T2 DistributionVariable Density

T2 TIME SLICES CALLED BINSSmaller Pore Surfaces - Shorter T2Larger Pore Surfaces - Longer T2

Larger PoreSurfaces

Larger PoreSurfaces

Small PoreSurfaces

Small PoreSurfaces

Finest Grains

Finest Grains

Movable Water

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Hydrocarbons e

Gas

Gas

Gas

Perm Indicator

120

T2 (ms) 0.1 1.0 10 100 1000

Clay bound water

Montmorillonite/Smectite Illite Cholrite Kaolinite

Capillary bound water

Small grains Large grains

Free water - sands

Free water - carbonatessucrosic vuggy

Gas

Light Oil

Medium Oil

Heavy Oil

Oil Wetting

T2 OF ROCKS AND FLUIDSNMR Summary

121

MRIL ANALYSIS - MRIAN

IN TRACK 4Clay Bound Water in Green

Capillary Bound Water GrayMovable Hydrocarbons in Red

Movable Water in Blue

Raw Bins andCorrelation

Resistivity andPermeability

T2 VDL.5 msec 1024 msec Porosity50% 0%

Track 4

First 3 Divisions Clay Spectrum

Exercise:Are the Sands fining downwards or coarsening upwards?Which part of each sand has the largest grain size and therefore permeability?

122

Platform ExpressData

LOW RESISTIVITY PAY WITH NMRMcClish Sand Open Hole Logs

Look at the Upper Part of the SandDoes it appear to be wet?

123

CMR Analysis

LOW RESISTIVITY PAY WITH NMRCMR Calculations

Waveform instead of VDL

Show Movable Hydrocarbons when Water was SuspectedPermeabilities are Tied to Cores

How do we know if they are right?

124

IP:3 mmcf/dayNo Water

LOW RESISTIVITY PAY WITH NMRCalibrated CMR Permeabilities

Match Permeability from Post Frac Test

Buildups run after perforating indicated average reservoir perm 7-10 md

125

MRIL Prime Hydrocarbon TypingCalibrated Perm Compared to actual ProductionHydrocarbon Typing from Differential Spectrum

Low PermWater 4 BWPD

350 BOPD200 MCFPD

126

Hand CalculationsHand Calculations

RW=.035

RT SW BVW4 19 49 .093

7 18 39 .07

5 20 41 .084

Conclusion:Well should producea considerable amount of waterand some HC. Traditional BVIRRcuttoff for most Granite Wash is.05 .

GR-SP AIT GR-SP AIT .3 TLD-CNL TLD-CNL -.1 ML ML

ANALYSIS WITHOUT NMRWould you expect a lot of water?

Traditional BVI = 5%

Quick lookAnalysis

How many stress layers?

127

CMR ELAN INTERPRETATIONNot using NMR Porosity

Lithology for stress layers and heat transferZones Tested Separately

400400 mcf mcf/day/dayOil & No WaterOil & No Water

200200 mcf mcf/day/day140 bbl Oil 140 bbl Oil 1 bbl Water1 bbl Water

Would NMR Porosity have helped?

129

THE ROLE OF STRESS

DIRECTION

AND

FINDING STRESS DIRECTION

130

THE ROLE OF IN-SITU STRESS

In Drilling and Stimulation

Hydraulic fractures propagate in the direction of the maximumprincipal stress and generate width in the direction of theminimum principal stress.

A. CRITICAL IN-SITU STRESS MODEL PARAMETERS

1. Horizontal in-situ stress magnitude and distribution

2. Vertical in-situ stress magnitude and deviation fromvertical

B. Other roles of stress1. Bore hole stability -want minimum difference in stress2. Minimum difference in stress minimum sand

production

131

THREE PRINCIPAL STRESSES

VERTICAL (Overburden)

Usually larger and therefore vertical fractures are createdIf less than horizontal stress a horizontal fracture results

A. Maximum stress on Horizontal well boresB. Maximum stress for creating sanding potential

HORIZONTAL in Fracturing

Maximum - determines lateral direction of propagation

Minimum - determines the direction of creating width

(Preferred Drilling Direction)

132

VERTICAL STRESS or OVERBURDEN

!!!!! "Vertical" growth of fracture if greater than horizontal stress

!!!!! If deviated from the borehole, so is the fracture height growth

! ! ! ! ! Maximum factor in borehole stability for deviated boreholes

! ! ! ! ! Plays a large role along with drawdown for sand production

133

HORIZONTAL STRESS MAGNITUDE

THE MOST CRITICAL INPUT IN 3-D SIMULATORS

SH = Minimum Horizontal Stress

SH

SH

The magnitude and distribution of the minimumhorizontal stress will determine the vertical

fracture propagation and height growth

134

MAX HORIZONTAL STRESS DIRECTION

FOR WELLSITE PLACEMENT

Offset Well Drainage Patterns

Single Fracture

Single Fracture

SingleT shapedMultiple

ReorientationMultiple fractures(away from wellbore)

Reorientationmultiple (at wellbore) min

Hmax

v

Fractures in Horizontal Wells

135


FOR PERFORATION STRATEGY

Near wellbore entry problems (tortuosity)

Place Perforations In Max Stress Direction

1. Lower initiation pressures

2. Fewer premature screenouts

3. Higher sand concentrations near the wellbore

Don't Create Initial Width against Maximum Stress !!

136


METHODS FOR FINDING THE DIRECTION

A. Logs

1. Borehole images of induced fractures

2. Borehole breakout direction with calipers

3. Directional Gamma Ray after frac

4. Dipole Acoustic Anisotropy

B. Oriented Cores

1. Direction of maximum relaxation (strain gauges to sample)

2. Velocity variations in minimum (ultrasonic pulse direction)

3. Remove core after frac

C. Production/Testing results

D. Geological Data

1. Relationship to faults

2. Direction from Dipmeters

137

LOGS FOR FINDING STRESS DIRECTION

BOREHOLE BREAKOUT

Multiple Arm Caliper - Direction Information

Extensional Fracture (Natural Fractures)

Shear Fractures (No Natural Fractures)

SHmax

SHmin

SHmin

SHmaxElliptical Enlargement

Elliptical Enlargement

138


BOREHOLE IMAGING TOOLS

Halliburton- CAST-V or EMI

Schlumberger- FMI

Baker Atlas- CBIL

Natural fractures, Drilling Induced, or Log after Minifrac

N E S W N

139


Perms Calibrated to Cores allows Production Prediction

140

FR

AC

TU

RE

FR

AC

DIR

EC

TIO

N


ROTO SCAN - DIRECTION OF THE FRACRadioactive material in the frac wings

141

TORTUOSITY IN THE BOTTOM ZONE

Perforations in Zone B were 90o to the Initiation Direction.

A

B

142

EXCESS PRESSURE TO CREATE WIDTHFracs Change Direction if it doesn't Screenout

70 degrees to Perfs 90 degrees to perf

143

FINDING MAXIMUM STRESS DIRECTION

PRODUCTION/TESTING RESULTS

A. Production decrease or an increase in Gas Oil Ratio in anoffset following the completion

B. Premature breakthrough in offset wells(water or CO2 floods, or even Frac job)

C. Interference testing(pressure gauges in offsets during pump-in)

144

FINDING MAXIMUM STRESS DIRECTION

GEOLOGICAL INFORMATION(Assumes stress state hasn't changed since faulting)

A. Reverse or Thrust Fault1. Compressional tectonic environment2. Maximum stress perpendicular to the fault

B. Normal or Growth Fault1. Extensional tectonic environment2. Maximum stress parallel to the fault

145

ESTIMATING AN

IN-SITU STRESS PROFILE

146

MINIMUM HORIZONTAL IN-SITU STRESS

DEVELOPING THE STRESS PROFILE

ADVANCED TECHNIQUE:

Microfracture treatments in all layers using small fluidvolumes at low rates.

PRACTICAL SOLUTION:

1. Low cost small volume pump-in test through perforations.

2. Log derived estimates calibrated to the pump-in test

1. With tubing and packers in casing

2. With wireline inflatable packers and pump in openhole

147

POREPRESSURE

STRESSPROFILE

OVERBURDENPOISSON'S

RATIO

Pext frompump-in testcalibration

COMPONENTS OF HORIZONTAL STRESS

148

POISSON'S RATIO -

A MATHEMATICAL FUNCTION TO COMPUTE HORIZONTAL STRESS

Horizontal stress is a result of the vertical stress

= Squash / Squish

is calculated using the shear and compressional sonic data

OVERBURDEN PRESSURE (Squash)

HORIZONTAL STRESS (Squish)

149

RT

1 Foot

VELOCITY OR SLOWNESS(Travel times through one foot)

SONIC WAVE TRAVEL TIMES

tlog = tfluid + (1-)tmatrix

150

FULL WAVE WITH DIPOLE

The ratio between the shear and compressional sonic travel timesis a function of the lithology and the elastic rock properties.Poisson's Ratio () is a measurement that indicates the degree ofelasticity.

EarlierQuieter

LaterLouder

PREFERRED:Dipole sonic tools (open or cased hole)

SECOND CHOICE:Full wave sonic tools (open hole only)

Monopole

Dipole

151

WHY THE DIPOLE SONIC IS PREFERRED

Compressional Shear Fluid

Time ()

CAN GET A SHEAR MEASUREMENT WHEN OTHER LOGS CAN'T

!!!!! t increases with porosity

!!!!! Shales and high porosity sands have long t(Above 140 msec/ft. - No Fullwave Sonics)

!!!!! Measurements were often not made in shales and sands(no data from half of the log in Case Study 2)

Experience with Dipole Sonics

1. Significantly better shear measurement in casing

(see next page)

2. Data is more consistent from well to well

3. Deeper depth of investigation

4. Better correlation to stress test data

(less adjustment of stress profile to pump in test)

5. Can find natural fractures (anisotropy)

6. Somewhat directional and gives direction of least principal stress

7. Cross Dipole can get direction within 5 degrees

152

DIPOLE SONICS IN CASED HOLE

Need fluid in the wellbore and some cement

Comparison of open and cased hole shear-wave logs

1/S in Microseconds / Ft. Travel Time in Milliseconds

153

POISSONS RATIO ESTIMATION

Calculate Poissons ratio from shear and compressional sonictravel times using the worksheet "Poisson's and Young's fromDipole".

= [(0.5 X (ts/tc)2)-1] / [(ts/tc)2-1]

where:

ts = Delta T Shear (microsec/ft)tc = Delta T Compressional (microsec/ft)

POISSONS RATIOESTIMATION EXERCISE

Delta T Compressional = 65 microsec/ft (Cell B7)

Delta T Shear = 107 microsec/ft (Cell C7)

Shear - Compr Ratio = _________ (Cell D7)

Poissons Ratio = _________ (Cell F7)

154

POISSON'S RATIO VSSHEAR/COMPRESSIONAL RATIO

PO

ISSO

N'S

RA

TIO

SHEAR/COMPRESSIONAL RATIO

Shal

es

Soft

San

dsH

ard

Sand

s Silt

ston

esD

olo L

imeAnh

155

SONIC QUALITY CONTROL

What Should Poisson's Ratio read in the shale?

BADDATAFLAG

PoorCoherence

MissingData

156

POISSONS RATIO GAS CORRECTION

Comparison with stress test data suggest that a Poisson's ratio less than 0.179 (Ts/Tc ratio of 1.60) reflects gas effect and not rock mechanical properties.

A practical correction method involves calibration to a lowporosity, oil, or water sand with the same lithology as the affectedgas sand.

tshear

tco

mpr

= [(0.5 X (ts/tc)2)-1] / [(ts/tc)2-1]

Gas Effect On Ratio Of Shear To Compressional Travel Times

Gas increases both compressional and shear travel times (can be used to detectgas as in cased hole) and as a result the measured Poisson's Ratio is lower, andsometimes unrealistically low.

157

POISSON'S RATIOCORRELATION TECHNIQUE

1. Full Wave or Dipole sonic data will not be on all wells

2. Existing Poisson's ratio data (on an offset well) will need to becorrelated to the frac well using lithology.

Lithology : Poisson's Ratio

Sandstones : 0.18-0.22 (Hard Rock)0.22-0.40 (Soft Rock)

Siltstones : 0.20-0.28

Shales : 0.26-0.40

Dolomites : 0.283

Limestones : 0.31

Anhydrite : 0.319

Poisson's Ratio for various types of lithology

3. Spreadsheet calculations Poisson's in sand/shale lithology

158

IS RELATED TO LITHOLOGY

LITHOLOGY DATA IS NEEDED FOR CORRELATIONS

Poisson's ratio is independent of porosity.

OFFSET WELL

FRAC WELL

0.26

0.29

0.31

Write in the appropriate Poisson's Ratio for the Frac Well

159

POISSON`S VS GAMMA RAY SHALE INDEX

Sand and Shale LithologyUsing the equation 0.17 + 0.17(GI) Poisson's was calculated

Exercise: Find and mark bad sonic data below

Gamma Ray

Gamma Ray Sonic Edyn

0 150

.15 .35

0 10

160

GEOLOGY EFFECTS CORRELATIONS

CORRELATIONS MORE DIFFICULT IN COMPLEX LITHOLOGY

161

ROCK COMPONENT OF STRESS

OVERBURDEN PRESSURE (Squash)

HORIZONTAL STRESS (Squish)

STRESS = ++RockComponentCalibration

Component

Fluid

Component

The rock component is a functionof overburden and Poisson's Ratio

Defined by:

1-X OBG

OBG = Overburden Gradient = Vertical Stress/Depth

162

OVERBURDEN GRADIENT VS ROCK TYPE

Overburden Gradient (OBG) should be reasonably constant inan area. Therefore, offset data can be used.

OBG = (Bulk Density* / 1.1) x 0.465

*The average density from the top of the pay zone to the surface.

Lithology Porosity Overburden

Anhydrite 0% 1.26 psi/ftShale 0% 1.23 psi/ftDolomite 0% 1.21 psi/ftLimestone 0% 1.15 psi/ftSandstone 0% 1.12 psi/ftSandstone 10% 1.05 psi/ftSandstone 20% 0.98 psi/ftSandstone 30% 0.91 psi/ftSalt 0% 0.86 psi/ft

The overburden gradient is determined by rock type and porosity.An accurate gradient can be obtained from a density log.

163

OVERBURDEN GRADIENT EXAMPLE

MOST OVERBURDEN GRADIENTS ARE NEAR 1.0 PSI/FT

Sandstone0.91 psi/ft

2000 ft

PayZone

Shale1.23 psi/ft

2000 ft

Anhydrite1.26 psi/ft

2000 ft

AverageGradient1.13 psi/ft

Field examples of Measured Overburden

Val Verde Basin W. Texas : 1.09Black Warrior Basin Coal : 1.20Offshore Louisiana : 0.93South Texas: : 1.00Wyoming Frontier : 1.00

Values can vary with depth.

164

PORE PRESSURE STRESS COMPONENT

This Component is a function of the pore pressure gradient. (Pp)

Usually is determined from one or more of the following:

1. Bottom hole pressure measurements

2. Salt water gradient

3. Drilling mud gradient (over estimate)

4. Drilling mud gradient during gas kicks (under estimate)

Pore Pressure in Impermeable Zones

The pore pressure gradient in impermeable layers should be setequal to the original reservoir pressure for the field. This can beobtained from historical field data or from the highest measuredpore pressure in a virgin zone.

STRESS = ++RockComponentCalibration

Component

Pore Pressure

Component

Defined by:

1-X Pp1 -[ ]

165

PORE PRESSURE CHANGES

CRITICAL WHEN PARTIAL DEPLETION HAS OCCURREDUsing formula on page 164, calculate pore pressure component of stress

Pore pressure can be measured with wireline formation tester

510 psi

2780 psi

FORMATIONTEST

PRESSURES

Depletion in the Travis Peak of E. Texas

Pressure change of 400% in less than 100 feet

7700

7800

Calculate: 1. Pore Pressure Gradient (Pp) for: A. ______ B. ______Assuming = 0.22 for sands. 2. Calculate thePressure component of the stress gradient for: A. ______ B. ______3. Log Derived Stress (pressure component) for A. ______ B. ______

A

B

Exercise: How much does the stress change from pore pressure? __________

166

ROCK

1-

X Pp1-

X OBG

FLUID

LOGDERIVEDCLOSURE

STRESSGRADIENT

+

EQUALS

* From a full wave sonic or correlation to a nearby sonic.

LOG DERIVED STRESS PROFILE

1 -[ ]

The key inputs required at least once in a field are:

1. Poisson's ratio * - 2. Overburden gradient - OBG3. Pore pressure gradient - Pp4. Calibration Component - Pext

167

CLOSURE STRESS GRADIENT (CSG)

A PRIMARY INPUT FOR 3-D FRAC MODELS

The wireline measurements can be used to determine theminimum horizontal stress profile for all zones above and belowthe perforated interval. Since this is inherently wrong a pump-incalibration is necessary.

A pump-in test will benecessary to find Pext

ACTUAL CSG (in tectonically relaxed areas) is:

CSG = 1-] X Pp

1-X OBG [1 -+ + Pext

ROCK FLUID CALIBRATION++

*

*

168

STRESS EXERCISE #1

Closure Stress Gradient (CSG) Estimation from Log Data

Use the worksheet "Rock Properties for FracPro"

Poissons ratio from log: 0.20

Overburden gradient: 1.1 psi/ft

Pore pressure gradient: 0.40 psi/ft

No calibration component

What is the calculated closure stress gradient?

CSG = ________ psi/ft

CSG = [/(1-)] X OBG + (1-[/(1-)]) X Pp + Pext

If the depth is 8,700', what is the closure stress? _______

169

STRESS EXERCISE #2

PORE PRESSURE INPUT TO CLOSURE

1. A reduced pore pressure increases stress contrast. Hence, fracture containment can be improved.

2. Impermeable zones will not deplete and therefore should be atoriginal field pore pressure.

GIVEN:

Poissons ratio from log: 0.20Overburden gradient: 1.1 psi/ftPore pressure gradient: 0.20 psi/ft*No calibration component

* was 0.4 in previous exercise

Calculate the closure stress gradient with the lower pore pressure gradient.

CSG = (/1-) X OBG + (1-(/1-)) X Pp + Pext

CSG = ________ psi/ft

If the depth is 8,700', what is the closure stress? _______

170

Flow Chart for Stress Calculation

CoherentMeasured

Pore PressureGradient

OverburdenGradient

Log StressGradient

Calibrate withPump-In

Stress forModel

DepthPext

171

STRESS EXERCISE # 3

STRESS STRESS

Compare the different stress values

A. _____ ______ _____B. _____ ______ _____

C. _____ ______ _____D. _____ ______ _____

E. _____ ______ _____F. _____ ______ _____G. _____ ______ _____

H. _____ ______ _____

LOG Pext = 0 Pext = .09

Find Poisson's ratio change in a shale to equala change in stress of 100 psi.

Average Shale Above_____ ______ _____


Average Shale Below_____ ______ _____


AB

CD

EFG

H

Caliper

Inches6 16

Corrected GRAPI0 100

Shale Volume

0 1SHALE

SAND

Poissons Ratio

0 .2 0 .4

11400

11500

11600

11700

11300

172

0.2

0.22

0.24

0.26

0.280.3

0.32

0.34

0.36

0.38

GI

NPH

IDPH

I

DIPO

LE

SONIC, GAMMA RAY, NEUTRON DENSITYCOMPARISON OF THREE METHODS FOR POISSON`S

DE

PT

H

POISSON'S RATIO

173

YOUNG'S MODULUS DEVELOPMENT

174

ROLE OF YOUNG'S MODULUS

1. Used with stress to estimate fracture width.

2. Used to estimate the variable tectonic component.

175

YOUNGS MODULUS ESTIMATION

DYNAMIC OR LOG DERIVED

INPUTS REQUIRED ARE:

1. Full wave sonic TSHEAR and TCOMPRESSIONAL2. Bulk Density (b)

FORMULA:

Edyn = 2 X G X (1+)G = 13400 X (b/TS2) (Shear Modulus)

Units are in PSI X E6 T shear = DTS T comp = DTC or DT

WHERE:

b = Bulk density (g/cc) = RHOBTS = Delta T Shear ===== Poisson's ratio

Dynamic Young's Modulus calculated from logs must be convertedto Static Young's Modulus for use in 3-D models.

(Dynamic Young's Modulus)

176

YOUNG'S EXERCISE # 1DYNAMIC YOUNG'S MODULUS

GIVEN:

Delta T Compressional (Cell B7) = 65 microsec/ft

Delta T Shear (Cell C7) = 107 microsec/ft

Bulk density (Cell E7) = 2.5 g/cc

Calculate Poissons ratio (Cell F7) = 0.20

USING:

G = 13400 X (b /TS2)

Edyn = 2 X G X (1+)

Using worksheet "Poisson's and Young's from Dipole"calculate:

Shear modulus (Cell G7) = _______ X E6 psi

Dynamic Youngs Modulus (Cell H7) = _______ X E6 psi

177

The log derived dynamic Youngs modulus estimate cannot beused directly as an input to the 3-D models. It must first becorrected to static.

The static estimate can range from 15% to 100% of the dynamicestimate.

Two options are available to correct the log Young's Modulus toa static:*

1. Use published core data (practical method)Refer to the chart on page 178 to obtain theLab Ratio

Estatic = Edyn X (Lab Ratio)

2. Using actual core data (preferred method)

Static to Dynamic Ratios (SDR)

Estatic = Edyn X SDR

DYNAMIC VS A STATIC YOUNGS

178

STATIC TO DYNAMIC YOUNG'S MODULUSTwo Correlations of Conversions

0 4,000,000 8,000,000 12,000,000 16,000,000

120%

140%

100%

0%

20%

40%

60%

80% 0 - 14%Porosity

15 - 24%Porosity

25 - 35%Porosity

Dynamic Youngs Modulus

Stat

ic %

of

Dyn

amic

10

8

6

4

2

00 2 4 86 10

Static Young's Modulus, millions of psi

Dyn

amic

You

ng's

Mod

ulus

, mill

ions

of p

si

From GRI Studies (Tight Gas Sands)

Lab Data from SPE 26561

179

STATIC TO DYNAMIC YOUNG'S MODULUSComposite of both Correlation Studies

The above forumula is incorporated in the spreadsheet "RockProperties for FracPro. It is used to calculate the static to dynamicratio and this ratio is then multiplied times the dynamic ratioand converted to millios of psi.

y = -0.0003x4 + 0.0052x3 - 0.0203x2 + 0.0312x + 0.4765R2 = 0.9145

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 2 4 6 8 10 12

Stat

ic/D

ynam

ic R

atio

Dynamic Youngs Modulus x E6 psi

180

Flow Chart for Youngs Calculation

PoissonsRatio

TCompressional

TShear

DynamicPoissons

Convert to Static

Youngs forModel

GRIData

SPEData

181

YOUNG'S EXERCISE # 2

YOUNG'SDYNAMIC

YOUNGSSTATIC

SDR

A. _____ ______ _____ _____B. _____ ______ _____ _____

C. _____ ______ _____ _____D. _____ ______ _____ _____

E. _____ ______ _____ _____F. _____ ______ _____ _____G. _____ ______ _____ _____

H. _____ ______ _____ _____

Dynamic Young's modulus from Dipole Sonic (1) Young's modulus from Sonic log Converted to Static (2)

Static to Dynamic Ratio (SDR) Based on Porosity (3)

(1) (2) (3)

YOUNG'SDYNAMIC

YOUNGSSTATIC

SDR

(1) (2) (3)





AB

CD

EFG

H

Caliper

Inches6 16

Corrected GRAPI0 100

Shale Volume

0 1SHALE

SAND

Poissons Ratio

0.2 0.4

11400

11500

11600

11700

11300

182

YOUNG'S MODULUS INPUT TO MODELUsing the same Layers as the Stress Profile

183

BUILDING PROFILES FOR

3-D MODELS

184

LOW PERMEABILITY GAS SANDS

Multiple Zones over a Long Interval

Objectives:

1. Calculate the average Poisson's, dynamic young's andpermeability for each layer.

2. Estimate pore pressure for each layer.

3. Convert the dynamic young's to static for use inFracProPT.

4. Estimate the stress for each layer.

Background:

A comprehensive evaluation program was run on this well and onan offset well. This well had the following information:

Open hole porosity, lithology, and resistivityFull wave sonic over lower zones (bad data over pay)Pre-frac well test - 108 ft of 0.017 md gas permPre-frac pump in test with gelled fluidReal time BHP during minifrac and main frac (dead string)Post frac pressure transient test 435 ft frac length with 145 md-ft for kh.

The offset has all of the above along with a complete full wave sonicand several microfracture tests.

185

DY

NA

MIC

YO

UN

GS

VS

SON

IC P

OIS

SON

'S

y = -21.783x + 11.364R2 = 0.893

4

4.5

5

5.5

6

6.5

7

7.5

8

8.5

0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.29 0.31

Dyn

amic

You

ngs

Mod

ulus

E6

PSI

Poissons Ratio from Full Wave Sonic

DEVELOPED FROM OFFSET WELL WITH FULL WAVE SONIC

186

STATIC TO DYNAMIC YOUNG'S

10

8

6

4

2

00 2 4 86 10

Static Young's Modulus, millions of psi

Dyn

amic

You

ng's

Mod

ulus

, mill

ions

of p

si

0 4,000,000 8,000,000 12,000,000 16,000,000

120%

140%

100%

0%

20%

40%

60%

80% 0 - 14%Porosity

15 - 24%Porosity

25 - 35%Porosity

Dynamic Youngs Modulus

Stat

ic %

of

Dyn

amic

187

LOG STRESS PROFILE DEVELOPMENT

Since the shear wave arrival time and the fluid wave arrival time wereclose the full wave sonic data was not available over this intervalsabove 6000 feet.

A correlation was established below that depth between PoissonsRatio and the Gamma Ray shale index (GI). This correlation is shownon the following page.

The relationship developed for Poissons ratio from the GI was:

= 0.17 + (GI X .17)

Poisson's Ratio for: 100% Sand=________

Poisson's Ratio for: 100% Shale=________

For the calculation of GI: GR clean = 25 GR shale = 150

ADVANTAGES OF THE GAMMA RAY INDEX POISSON'S

1. Allows the full wave sonic data to be used on wells withoutfull wave sonic data.

2. Removes incoherent data if correlation is made where thedata is good.

3. Replaces values where gas correction is needed in sand.

188

POISSON'S RATIO FROM SONIC AND GR

Where is the sonic log probably not valid?

Gamma Ray

Gamma Ray Sonic

Edyn0 150.15 .35 0 10

189

GammaRay

Gamma Ray

Caliper

Neutron PorosityGI GR

keff

Perm

Density Porosity

Pe

FINDING STRESS LAYERS - FRAC WELL

Determine layers for stress/Young's mark on log

Mark Layersfor

Stress Changes .15 .35.001 .1 0 10

.3 0

5400

5450

5350

5300

5250

190

PERMEABILITY AND BULK VOLUME WATER

Sandstone

Shale

ResistivityShale Volume keff

Perm

Eff Porosity

H/C

BVWMark Perm

Layers.1 00.2 200

0.001 1.0

1. Determine layers for permeability and mark on log

2. Mark Pore Pressure gradient for each layer

in permeable zone Pp

=.30

in impermeable zone Pp=.375

3. Where will leak off occur and mark with an X4. What is BVI and will it produce water?

191

FINDING STRESS LAYERS - FRAC WELL

LabelLithology

Using exercise on the following page :1. Average Poisson's for zones A through F2. Calculate stress for zone A through F3. Average Perm for layers A through F

B

C

D

E

F

A

5250

5300

5350

5400

5450

Gamma RayGamma Ray

Caliper

Neutron PorosityGI GR

bj fundamental of logging.pdf

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