Bj Fundamental Of Logging.pdf

FUNDAMENTAL OF LOGGING

CONSULTANTS SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 Sage Brush Road Yukon, OK 73099 405 324-5828 Fax 324-2360 [email protected]

1

TABLE OF CONTENTS

Page

2

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

WIRELINE LOGGING

3

LOGGING ANSWERS RESERVOIR ROCK

PORE

WATER?

OIL?

GAS?

GAS OIL WATER

Are hydrocarbons present in commercial quantities? Need to define: • Type of rock • Type of fluid in pores • Type of pore space

4

100% SATURATED WITH FORMATION WATER

RO = WATER SATURATED RESISTIVITY R xL RO = W φ

SOME WATER SATURATION AND SOME HYDROCARBON

RT =

RW x L φ x SW

5

SCHEMATIC OF BOREHOLE

Rxo Rmf Sxo

TRANSITION ZONE

Hmc

FLUSHED ZONE

d

UNINVADED ZONE

ADJACENT FORMATION

Rt Rw Sw

di

Borehole

Flushed Zone

Uninvaded Zone

6

d - Hole diameter, inches di - Diameter of invaded zone Hmc - Thickness of mudcake Rmf - Resistivity of mud filtrate Rxo - Resistivity, flushed zone, ohm-meter Sxo - Water saturation of flushed zone Rt - Resistivity undisturbed zone Rw - Resistivity of formation water Sw - Water saturation, uninvaded zone

BASIC RESISTIVITY LOG

RESISTIVITY

SP

A

SHALE

B

SHALY SAND

C

FRESHWATER SAND

D

OIL SAND

E

SALTWATER SAND

F

HARD LIMESTONE

G

ANHYDRITE OR GYPSUM

7

POROSITY (Storage Space) Intergranular

Intragranular

Primary

Secondary

Solution

Fracture

Intercrystalline

PERMEABILITY (Fluid Mobility)

Coarse-grained, well sorted Good permeability

8

Fine grained

Poorly-sorted

Poor permeability

SAND GRAIN SIZE, STACKING, AND SORTING EFFECT POROSITY

MAXIMUM POROSITY OF 47.6 PERCENT

MINIMUM POROSITY OF 25.9 PERCENT

9

RESERVOIR ROCKS SANDSTONE

ANGULAR AND SUBANGULAR GRAIN PACKING

DOLOMITES AND LIMES OIL

OIL ACCUMULATION IN POROUS ZONES IN LIMESTONE

10

GAMMA RAY LOG

RADIOACTIVITY

SHALE VOLUME (Gamma Ray Index)

ZONE A

GR sh GR - GR clean GI=

GR sh - GR clean

GR clean

11

LAMINAR SHALE

DISPERSED SHALE

12

RESISTIVITY LOGS

13

RESISTIVITY

THE MEASURE OF THE RESISTANCE OF A GIVEN VOLUME OF MATERIAL

The resistivity of any formation is a function of the amount of water in that formation and the resistivity (salinity) of the water itself. Formation water (salt water) is conductive, while the rock and hydrocarbon are normally insulators.

14

RESISTIVITY DEVICES

Today’s drilling programs use either highly conductive fluids (salt muds) or low to non-conductive fluids (fresh mud, oil base mud, air). For fresh muds the Dual Induction tool is recommended, since electrical currents cannot be passed through non conductors. It is necessary to set up a ground loop with induced currents. Deep induction (ILD) and the medium Induction (ILM) are such measurements. The shallow measurement is an electrical measurement and requires a conductive borehole fluid. The Dual Laterolog measurements (LLD) deep laterolog and (LLS) shallow laterolog are electrical measurements and require conductive fluids. Therefore, it is recommended for 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 resistivity of the uninvaded zone(Rt) when invasion has occurred. In most cases this correction is minimal. In order to get an accurate reading of the flushed zone (where the original fluids have been replaced by mud filtrate), a resistivity device reading very near the borehole is recommended. For fresh muds that would be the Proximity Log, while with salt muds, the recommended device would be the Microlaterolog.

15

BOREHOLE

DUAL INDUCTION - FRESH MUD - AIR

ILM ILD

SFL*

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

16

Undisturbed Zone

Transition Zone

Borehole

Flushed Zone

RESISTIVITY - SATURATION PROFILES

Permeability Indicator

Invaded Zone Distance from Borehole 100%

SW or SXO

Water Zone

RXO

RT

0% Distance from Borehole 100%

SW or SXO

SXO Hydrocarbon Mobility (Permeability to Hydocarbons)

SW

0% Distance from Borehole

17

DUAL INDUCTION LOG MEDIUM OHM-M

0.2 API

0

GAMMA RAY

150

SHALLOW 0.2

OHM-M

-]20[+ SP

OHM-M

0.2

SHALLOW MEDIUM

18

SP

2000

DEEP

DEEP

GAMMA RAY

2000

2000

DUAL INDUCTION LOG MEDIUM 0.2 0

API

150

GAMMA RAY

2000

SHALLOW 0.2

-]20[+ SP

OHM-M

OHM-M

2000

DEEP 0.2

OHM-M

2000

MEDIUM GAMMA RAY SHALLOW

SP

DEEP

19

DUAL INDUCTION LOG MEDIUM 0.2

2000

OHM-M SHALLOW

0.2 -]20[+ SP

OHM-M

2000

DEEP 0.2

OHM-M

2000

SP

DEEP

MEDIUM SHALLOW

20

INDUCTION LOG WITH AUTOMATIC CORRECTIONS .2

1.0

.2

1.0

.2

1.0

GAMMA RAY 0

150

UNCORRECTED DEEP 10 100 MEDIUM 10 100 CORRECTED DEEP 10 100

1000 1000 1000

21

RXO MEASUREMENTS PAD RESISTIVITY DEVICES Pad resistivity devices have very shallow depths of investigation (reading very near the borehole) and hence are used to measure the resistivity of the flushed zone (RXO). The devices have soft rubber pads designed not to cut through the mudcake (the solids of the mud left of the borehole wall from invasion). If invasion has occurred and a zone has permeability. A difference of hydrocarbon content in the flushed zone (1-SXO) and the hydrocarbon content in the undisturbed zone (1-SW) indicates that the hydrocarbons near the borehole were replaced by filtrates. Hence the is “moved oil” and, therefore, the zone has permeability 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 an accurate reading of the resistivity in the flushed zone (RXO). Since this resistivity is very near the borehole it can easily detect invasion and, therefore, when a zone has permeability. The shallow measurement hive this tool good vertical resolution allowing good detection 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 muds are used. It is essentially a laterolog device with a limited depth of investigation. This tool is influenced by mud cakes greater than 1/4 inch thick. The micro-laterolog has even better vertical resolution than the microlog.

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

22

TYPICAL MICROLOG RESPONSES MICRO - NORMAL 0 0

MICRO - INVERSE

40 40

SHALE

TIGHT SHALE PERMEABLE TIGHT SHALE PERMEABLE PERMEABLE PERMEABLE (WATER - NO INVASION) ?

SHALE These are the oldest of the pad type devices. They combine two resistivity measurements 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 is called "positive separation" and indicates mud cake. Therefore, these devices are excellent permeability indicators.

23

MICROLOG GAMMA RAY 0 6

CALIPER

MICRO - NORMAL 150 16

0

MICRO - INVERSE

40

0

MICRO INVERSE

CALIPER

GAMMA RAY MICRO NORMAL

24

40

PROXIMITY MICROLOG

MICRO NORMAL 20

0

MICRO INVERSE 20

0

CALIPER

PROXIMITY 16.0

6.0

.2

1.0

10

100

1000

20 00

MICRO NORMAL

CALIPER

PROX

MICRO INVERSE

BIT SIZE

25

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

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

SP CURVE MV

SHALE

SHALE BASE LINE SAND

26

SPONTANEOUS POTENTIAL (SP) LOG RMF vs RW PERM INDICATOR

SALINITY INDICATOR

SHALE PERMEABLE BED FRESH WATER SHALE

SHALE

SALTY WATER SHALE SHALE

SALTY WATER

IMPERMEABLE LIMESTONE

SHALE

SHALE

SALTY WATER SHALE HYDROCARBON EFFECT SHALE HYDROCARBONS WATER SHALE

27

DETERMINATION OF RESISTIVITY

The formation RT (true resistivity) was measured using the deep reading from a dual induction (fresh muds) or a deep reading from a dual laterolog (salt muds). Correction for invasion, 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. These values can vary from one area to another and are sometimes contaminated, hence giving wrong readings. Ideally, a 100% water zone will exist and a R W can be "back calculated" from saturation formulas. Logging companies have experience with RW values which best predict production. These "whatever works" values are the second choice. The least desireable 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 with a proximity log (fresh mud) or a micro laterlog (salt mud). The water in the flushed zone is RMF and is then measured by pressing the liquids (filtrate) out of a mud sample. Its resistivity is then measured with a "mud checker" in the logging truck. This RMF value and the temperature at which the measurement were made are noted on the resistivity log heading.

28

USES OF RESISTIVITY PERMEABILITY INDICATOR Invasion of a zone cannot occur unless permeability exists. The separation of the medium (dotted) and the deep (dashed) induction or the deep and shallow laterolog curves indicates permeability. The “positive” separation of the microlog curves or a caliper reading less than bit size is an indication or permeability. The deflection of the SP 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 is water. By comparing the bulk volume water in a given zone versus water production from 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 formation will hold without producing water (irreducible water saturation). The relation to bulk volume water and resistivity is as follows: BVW = φ * SW =

RW/RT

These two values will be approximately the same unless there is permeability to hydrocarbons (“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. The further the separation between these two curves, the more likely it is water. The closer the curves, the more likely it is hydrocarbon bearing. This is only a approximation for specific conditions, but can be useful for many applications. This method could allow the determination of oil water contacts in a zone or give you an easy method of detecting hydrocarbons. It could be especially important in 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 be made and the reserves in a given well can be calculated.

29

WATER SATURATION APPROXIMATION The ratio method is considered an approximate or qualitative method for determining water saturation. This technique requires that a “normal” invasion profile and a resistivity contrast (Rmf - Rw). In other words, zone of low permeability as well as zone of low or high porosity could have inaccurate advantages since no porosities are required and no m (Archie method) is required. Two ratios are needed for this calculation. The first ratio is of the invaded zone RXO and the undisturbed zone RT. This allows a “quick look” at the relative separation between the deep (dashed) and shallow (solid) resistivity readings. The wider the separation between these two readings, the more potential for water. These values are from the respective resistivity measurement with corrections made where necessary. The second is a ratio of the water resistivity in the invaded zone (RMF) and the uninvaded zone (RW). Both of these values must be corrected for the temperature for the zone you are calculating. Neither of these values come from the logs.

30

RATIO SW METHOD

F X RW RT

SW =

F X RMF RXO

& SXO =

ASSUMING

SXO = (SW)

1 5

THEN

1.6

SW =

RXO RT

X

RW RMF

OR

(

RXO RT

X

RW RMF

)

5 8

31

DETERMINING WATER VS OIL MEDIUM

RMF = .52

2000

OHM-M

0.2 RW = .04

SHALLOW 0.2

2000

OHM-M

-]20[+

DEEP 0.2

SP

2000

OHM-M

SP

A B C D

SHALLOW DEEP

E F MEDIUM

G

IN SPECIAL CASES: Bulk Volume Water =

32

RW RT

RATIO METHOD EXAMPLE CALCULATE BULK VOLUME WATER POINT

SHALLOW / DEEP

BVW

RATIO SW*

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

33

RESISTIVITY 1. Consists of several curves with different distances of investigation. A. Deep (dashed curve) measures deepest, a reading of 6-12 ft. approximates the uninvaded zone (RT) and usually reads further to the left. B. Medium (dotted curve) measures deeper than the shallow (usually between the deep and shallow). C. Shallow (solid curve) measures near the wellbore, usually reading the furthest to the right. The addition of a MSFL* (Micro Spherically Focused Log) will give a good approximation of RXO. DUAL INDUCTION

DUAL LATEROLOG

DEEP

DEEP INDUCTION

DEEP LATEROLOG

MEDIUM

MEDIUM INDUCTION

SHALLOW

SFL / GUARD

VERY SHALLOW

*MFSL

SHALLOW LATEROLOG *MSFL MICRO LATEROLOG (ATLAS)

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

34

POROSITY & LITHOLOGY IDENTIFICATION

35

POROSITY

TOTAL VOLUME OCCUPIED BY PORES, EXPRESSED IN PERCENT

"HOLES IN THE ROCK"

36

DETERMINATION AND USES OFPOROSITY Porosity cannot be measured directly, but rather a parameter related to porosity is measured. Each porosity device responds to the type of rock and the fluid in the rock as well as porosity. Because complex rock types and shaliness can mislead the interpretation 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 type of lithology (rock type) can be determined. In many cases the detection of gas in the porosity is possible. There are two types of porosity. Primary porosity resulting from the deposition of the material and secondary resulting from some later mechanical or chemical change. Fractures would be an example of secondary porosity. The combination of porosity and resistivity allows for the calculation of the percent of water in the porosity (Sw). The percent of hydrocarbons in the porosity So then is defined by 1-Sw. This information can then be used to determine the economics of a well and the subsequent development of a field. The number of barrels of stock tank oil in place (BSTO) can be calculated the following formula:

A simple equation for oil reservoirs would be:

BSTO = 7758 A h φ So / FVF BSTO A h φ So FVF

= = = = = =

BARRELS OF STOCK TANK OIL DRAINAGE AREA THICKNESS OF PAY POROSITY OIL SATURATION (1-Sw) FORMATION VOLUME FACTOR

37

POROSITY MEASURING DEVICES

I. LITHO TYPE DENSITY TOOL

II. COMPENSATED NEUTRON TOOL

III. BOREHOLE COMPENSATED SONIC (BHC)

38

DENSITY POROSITY DEVICE

D

S

ρb = φρf + (1-φ ρ φ) ma

φ=

ρma - ρb ρma - ρf

39

Mud Cake (ρmc * hmc)

Formation

) )

Short Spacing Detector

Source

40

Long Spacing Detector

PHOTO ELECTRIC USES

The P e measurement is strongly related to the nature of the formation rock type. Therefore, methods of interpretation have been developed to yield better answers for lithology and hydrocarbon type.

1. As a matrix indicator (the lithology curve) 2. In combination with density ρb 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

41

THE LITHO TYPE DENSITY LOG

The density of a formation is a function of the density of the rock material, the amount of porosity, and the density of the fluid in the pores. A density tool responds to the electron density (number of electrons per cubic centimeter) as a function of the number of Compton-scattering collisions. The electron density is then related to the true bulk density 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 porosity. Evaluation of shaley sands, oil shales, complex rock types, and gas detection are aided by the density log.

42

SWS

-

LITHODENSITY LOG

HLS

-

SPECTRAL DENSITY LOG

ATLAS

-

Z-DENSITY

COMMON P AND ρ VALUES e ma

Pe

ρma

QUARTZ (SS)

1.81

2.64

CALCITE (LS)

5.08

2.71

DOLOMITE

3.14

2.88

WATER (FRESH)

0.358 0.119

1.0

OIL (n(CH2)) GAS (CH4) SHALE

0.67

0.095 -0.06 About 3 Variable

43

LITHO DENSITY LOG -.250 ○

150

0

○

CORRECTION

○

○

○

○

○

16

2.0

5 2.5

CORRECTION

BULK DENISTY

C GAMMA RAY

Pe

B

2700 CALIPER

44

○

○

○

○

○

○

+.250 ○

○

○

○

10

BULK DENISTY

CALIPER 6

○

PHOTO ELECTRIC

GAMMA RAY 0

○

A

3.0

○

LITHO DENSITY LOG CORRECTION PHOTO ELECTRIC -.250 ○

GAMMA RAY 0

0

150

CALIPER 6

○

○

○

○

○

○

○

○

5

○

○

○

○

○

○

○

+.250 ○

○

○

○

10

BULK DENISTY 16

2.0

3.0

2.5

E

GAMMA RAY

PHOTO ELECTRIC

D

BULK DENISTY

CORRECTION

3600 CALIPER

45

NEUTRON POROSITY Neutron logging devices react to the hydrogen in the formation. Since hydrogen is present in water and hydrocarbbons the tools are responding to the total fluid and hence the porosity in the rock. FEW HYDROGEN MOLECULES IN THE FORMATION = LOW POROSITY MANY 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, the porosity from a neutron device will be too low. For example a zone with 15% porosity could appear to be 5 - 10% using a neutron device. A combination of the neutron and density porosity devices can give a reasonable estimate of porosity. A determination of the rock type (lithology) and gas detection become reasonable with the assumption of a two mineral model.

TRUE POROSITY QUICKLY ESTIMATED BY

φ = 1/2 (φ φD + φN) IF A ZONE IS GAS PRODUCTIVE USE THE "2/3 METHOD"

φ = 1/3(2φ φD + φN) Since shale contains a great deal of trapped water (hydrogen) a little shale can make the neutron porosity too high. The above methods then become too high. In a shaley zone the density porosity alone becomes a better estimate of porosity.

46

COMPENSATED NEUTRON LOG BOREHOLE

FORMATION 3 3/8" Dia

FAR DETECTOR

NEAR DETECTOR

SOURCE

OTHER TOOLS COMBINED WITH DENSITY AND DUAL INDUCTION "TRIPLE COMBO" 47

LITHOLOGY LOGGING FINDING THE ROCK TYPE 0○

○

0

GAMMA RAY

○

○

○

○

30

150

○

○

Pe 5 NEUTRON POROSITY ○

○

○

○

○

○

○

○

○

○

-10

MATRIX LIME 30

DENSITY POROSITY

-10

MATRIX 2.71

GAMMA RAY

LIMESTONE φ DENSITY

DOLOMITE ANHYDRITE

Pe

SAND

SALT GAS SAND

LIMESTONE OR GASSY DOLOMITE ?

48

φ NEUTRON

NO GAS

SHALE

NEUTRON DENSITY

○

0

GAMMA RAY

6

CALIPER

0

○

○

○

○

○

○

○

○

○

Pe ○

○

○

○

○

○

○

○

○

10 ○

150

30

NEUTRON POROSITY

16

30

DENSITY POROSITY

-10

MATRIX LIME

-10

MATRIX 2.71

Pe

φ DENSITY GAMMA RAY

φ NEUTRON

CALIPER

49

NEUTRON - DENSITY LOG WITH Pe

0 0 6

GAMMA RAY CALIPER

30

150

Pe

10

NEUTRON POROSITY

-10

MATRIX LIME

30

16

DENSITY POROSITY

-10

MATRIX 2.71

A CALIPER

GAMMA RAY

B

φ DENSITY

Pe φ NEUTRON

C

D

50

NEUTRON - DENSITY LOG WITH Pe

○

0

GAMMA RAY

0○

Pe ○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

10 ○

NEUTRON POROSITY

30

150

○

-10

MATRIX LIME

6

CALIPER

DENSITY POROSITY

30

16

-10

MATRIX 2.71

φ DENSITY

GAMMA RAY

Pe

φ NEUTRON

A

CALIPER

B

C

51

BOREHOLE COMPENSATED SONIC TRAVEL TIME MEASURED THROUGH 1 FT. OF FORMATION

R1 3'

5' R2 R3

5'

3' R4

T2

52

FORMATION

T1

SONIC LOG (SPEED OF SOUND)

R

T

SONIC

∆tlog = ∆tma = 1/Vma Vma SANDSTONES LIMESTONES DOLOMITES STEEL

18,000 - 19,500 21,000 - 23,000 23,000 - 26,000

∆tma 55.6 - 51.3 47.6 - 43.5 43.5 - 38.5 57.0

53

SONIC POROSITY

R

T

∆tlog = φ∆tfluid + (1-φ φ)∆ ∆tmatrix φ =

54

∆tlog - ∆tma X ∆tf - ∆tma

( ) 1 Cp

1 Cp

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

Cp

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

SONIC LOG TRAVEL TIME THROUGH 1 FT. OF FORMATION 0 GAMMA RAY 150 6

CALIPER

TRAVEL TIME µsec/ft

16 100

70

40

∆T

GAMMA RAY

A-

BC-

CALIPER

55

POROSITY AND LITHOLOGY IDENIFICATION 1. 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 the type of rock. 3. Porosity can be estimated with a neutron density by the following: A. Fluid filled (no gas):

φ = (φ φD + φN)/2* φ = (2φ φD + φN)/3*

* When a zone is shaley, φ will be too high. 4. The photoelectric (Pe) curve can be used for better estimation of the rock type (especially in gas) Pe LITHOLOGY *Quartz (SS) 1.18 5.08 Calaite (LS) 3.14 Dolomite Shale ~3 * Sandstone can be 2.2 to 2.6 when cemented with calcite. Gamma Ray Log 1. Measures natural radioactivity usually associated with shale. 2. Radioactivity or shaliness increases left to right. 3. Furthest to left clean zone indicating good permeability. Shale line (Average reading in shales) can be used to determine percent shale.

56

OPEN HOLE INTERPRETATION REFERENCE

57

VALUES COMMON P AND ρ ma e

PE

ma

QUARTZ (SS)

1.81

2.64

CALCITE (LS)

5.08

2.71

DOLOMITE

3.14

2.88

WATER (FRESH)

1.0

OIL (N(CH2))

0.358 0.119

GAS (CH4)

0.095

-0.06

ABOUT 3

VARIABLE

SHALE

58

ρ

0.67

LITHOLOGY LOGGING FINDING THE ROCK TYPE ○

GAMMA RAY

150

Pe ○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

5○

30

NEUTRON POROSITY

30

DENSITY POROSITY

-10

MATRIX LIME

-10

MATRIX 2.71

GAMMA RAY

LIMESTONE φ DENSITY

DOLOMITE ANHYDRITE

Pe

SHALE SAND SALT

φ NEUTRON

NO GAS

0

0○

GAS SAND

LIMESTONE OR GASSY DOLOMITE?

SHALE 59

SATURATION DETERMINATION FOR CLEAN LIMES AND DOLOMITES

Ro Rw

60

φ Porosity

F

Rt

Sw

ARCHIE'S RELATIONSHIP

It has been established experimentally that the resistivity of a clean formation is proportional to the resistivity of the salt water with which it is fully saturated (RO). The constant of proportionality is called the formation resistivity factor, or F, where RW = Resistivity of the formation water.

F = Ro / Rw In a formation containing oil or gas, both of which are electrical insulators, resistivity is a function not only of the formation factor F and the water resistivity RW, but also the water saturation SW. SW is the fraction of the pore volume occupied by formation water. G. E. Archie determined experimentally that the water saturation of a clean formation can be expressed in terms of its true resistivity (RT).

Sw = (FRw / Rt)1/n Since RO = F * RW, water saturation can be expressed as:

Sw = (Ro / Rt)1/n For a given porosity, the ratio of RO to RW 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 pore structure and pore size distribution. Archie has proposed the following formula:

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

Sw = (Rw / Rt)1/2 / φ Humble determined that "a" = 0.62 in Sandstone formations and "m" = 2.15 which is rewritten as:

Sw = (.81Rw / Rt)1/2 / φ

61

DUAL INDUCTON LOG

3900

MEDIUM 0.2 0

API

2000

150

SHALLOW 0.2

GAMMA RAY

OHM-M

-]20[+

DEEP

SP

A 4000

B

C D E 62

2000

0.2

1

OHM-M 10

100

2000

NEUTRON DENSITY LOG

3900

SDL PE COM

0

API

10 -.025

150

30

NPHI LIME

-10

16

30

DPHI 2.71 10

-10

GAMMA RAY 6

INCHES CALIPER

DELTA RHO GM/CC

0

.025

0

4000

63

MICROLOG

3900

10000

0

GAMMA API

150

6

CALIPER INCHES

16

4000

64

TENSION POUNDS

0

0

MICRO INVERSE OHM-M

40

0

MICRO NORMAL OHM-M

40

LOG INTERPRETATION PRACTICE DETERMINATION 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 above 2. Extend this line to find RO = __________ 3. Connect the RO found in step 2 with the RILD (approximate Rt) found in Question D 4. 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 φ = __________ 4. Connect the RO Found in step 2 with φ found in step 3 and extend this line to find RW = __________

65

SUMMARY INTERPRETATION AT A GLANCE Resistivity 1.

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 deep and shallow.

C.

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

Dual Induction

Dual Laterolog

Deep

Dual Induction

Medium

Medium Induction

Shallow

SFL / GUARD

Shallow Laterolog

Very Shallow

*MSFL

*MSFL Micro Laterolog (Atlas)

Deep Laterolog

*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 Logs

66

1.

Measures naturally occurring radioactivity. Usually due to clay or shale.

2.

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

SUMMARY INTERPRETATION AT A GLANCE 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 A. B. C.

Identify Radioactive Reservoirs Facies and Mineralogies Better Permeability Indication

Porosity and Lithology Identification Porosity and Lithollogy Identification Three types of porosity logs: 1. Three1.types of porosity logs A.

Density: Utilizes a pad device which cuts through mudcake. Two arm caliper usually 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 the type of rock. 3. Porosity can be estimated with a neutron density by the following: A.

Fluid filled (no gas): φ

= (φ φD + φN) / 2* φ = (2φ φD +φ φN) / 3*

*When a zone is shaly, φ will be too high

LITHOLOGY

Pe

*Quartz (SS) Calcite (LS)

1.81 5.08

Dolomite

3.14

Shale

About 3

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

67

TODAY'S COMPUTER INTERPRETATIONS APPARENT GRAIN DENSITY 25

DIFFERENTIAL CALIPER -20 20 EFFECTIVE POROSITY 50 % 0

3

0

VOLUME MATRIX %

0

VOLUME SHALE %

GAS FLAG

1

RO 0

1 DEPTH

1000 Rt

0

1000

BULK VOLUME WATER 50 % 0

X800

DIFFERENTIAL CALIPER

V

VOLUME SHALE

X900

WATER SATURATION

V

EFFECTIVE POROSITY

RO GRAIN DENSITY

HYDROCARBONS

Y000

BULK VOLUME WATER

VOLUME MATRIX

Y100

68

Rt

OPEN HOLE INTERPRETATION EXERCISE

69

COMPANY:

WELL:

FIELD:

COUNTY:

LOCATION:

SEC:

1

1

RT

RW RT

SANDSTONE SW =

φD φN

φX

LITH

SW

(.81 RW / R T)1/2

LIMES AND DOLOMITES SW =

2

φ

(RW / RT)1/2

φ

3

WATER SATURATION (RATIO)3

BVW2

RMF

BVW = φ * SW

SW =

(

RXO RT

*

RGE:

)

RW R MF

RW RMF

RILM

RSFL

RXO

RXO RT

SW

CONSULTANTS 5/8

SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 SAGE BRUSH RD 405 324-5828 YUKON, OK 73099 FAX 324-2360

70

RW RILD

ZONE

TWP:

SW (ARCHIE)1

POROSITY

RESISTIVITY

STATE:

OPEN HOLE LOG INTERPRETATION 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 AT POINTS INDICATED MAKE COMMENTS ABOUT PERMEABILITY AND PRODUCIBILITY

71

EXERCISE #1 SP -]20[+ GAMMA RAY 0

150

.2

1.0

.2

1.0

.2

1.0

MEDIUM INDUCTION LOG 10 100 DEEP INDUCTION LOG 10 100

1000 1000

SHALLOW FOCUSED LOG 10 100

1000

9300

1

2 9400

3

ILM SP GR

72

4

ILD

SFL

EXERCISE #1 5 0

CALIPER INCHES GAMMA RAY

15

30

20

150

30

20

LIME MATRIX NEUTRON POROSITY 10 DENSITY POROSITY 10 MATRIX 2.71

0

-10

0

-10

9300

GR CAL

1 NEUTRON

2 9400

DENSITY

3

4

73

EXERCISE #2 SP -]20[+ GAMMA RAY 0

150

GR 9600

.2

1.0

.2

1.0

MEDIUM INDUCTION LOG 10 100 DEEP INDUCTION LOG 10 100

.2

1.0

SHALLOW FOCUSED LOG 10 100

1000 1000 1000

5

SP

ILD ILM

9700

6

7

8

74

SFL

EXERCISE #2 5

CALIPER INCHES GAMMA RAY

15

0

30

20

LIME MATRIX NEUTRON POROSITY 10

30

20

DENSITY POROSITY MATRIX 2.71 10

150

0

-10 0

-10

GR CAL 9600 5

φN NEUTRON φD DENSITY

9700

6

7

8

75

MINERAL IDENTIFICATION PLOT

76

LITHOLOGY PRESENTATION 0 ○

0

GAMMA RAY

125

○

○

○

○

○

○

○

Pe ○

○

○

○

○

○

○

○

○

5○

30

NEUTRON POROSITY

30

DENSITY POROSITY

-10

MATRIX LIME

-10

MATRIX 2.71

DOLOMITE

LIMESTONE

Pe

GAMMA RAY

SANDSTONE

Φ

DENSITY

Φ

NEUTRON

77

EXERCISE #3 MEDIUM INDUCTION LOG .2 SP -]20[+ GAMMA RAY 0

.2

2000 SHALLOW FOCUSED LOG

150

.2

4100

3 1

4200

2

78

2000 DEEP INDUCTION LOG

2000

EXERCISE #3 6 0

CALIPER INCHES GAMMA RAY

.30

.20

.30

.20

16 150

○

○

0

○

○

○

○

○

○

○

○

NEUTRON POROSITY .10 DENSITY POROSITY .10 ○

○

○

○

○

○

○

○

○

PEF ○ ○ 10

○

○

○

○

○

○

○

○

0

-.10

0

-.10

○

○

○

○

○

○

○

○

○

○

○

20

4100

3 1

4200

2

79

EXERCISE #3 CALIPER 6

16

0

MICRO NORMAL (ohmm)

40

0

MICRO INVERSE (ohmm)

40

GAMMA RAY 0

150

4100

3 1

4200

2

80

81

EXERCISE #4 MEDIUM 0.2 0

2000

OHM-M

API 150

SHALLOW

GAMMA RAY

2000

OHM-M

0.2

DEEP

-]20[+ SP

2000

OHM-M

0.2

SP

4600

1

DEEP

SHALLOW

2 MEDIUM

4700 GAMMA RAY

82

EXERCISE #4 Pe ○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

○

10

0

GAMMA RAY

NEUTRON POROSITY 0

150 30

MATRIX LIME DENSITY POROSITY

-10

30

MATRIX 2.71

-10

CALIPER 6

16

CALIPER

PE

4600

φDENSITY φNEUTRON

1

2

4700 GAMMA RAY

83

EXERCISE #4 CALIPER 6

16

0

GAMMA RAY 0

150

0

4600

1

2

4700

84

MICRO NORMAL (ohmm) MICRO INVERSE (ohmm)

40 40

LOG INTERPRETATION ANSWERS

85

ANSWERS TO OPEN HOLE INTERPRETATION PRACTICE POINT

SWR

SW

BVW

55 45 17

.055 .06 .027

16 100

.023 .105

(Ratio)

EXERCISE #1 Upper zone fractured Lower zone bed corrections Gassed effect both zones

Ra = 40

Rt = 160

1 3 4

99

EXERCISE #2 Upper zone no perm no SP Lithology unclear Pe could clarify Lower zone fractured in top Obviously wet in bottom Water free production Wet!

6 8

EXERCISE #3 Low resistivity pay excellent perm Resistivity constant porosity: 18% / Lower 2 Top 6 ft. 1MMCFPD no water 1 2

45 70

75 100

EXERCISE #4 Good microlog perm upper zone Bottom zone low porosity no ML perm Classic example: water in bottom transition zone oil in top 1 2

86

21 82

.045 .17

SATURATION DETERMINATION FOR CLEAN SANDSTONE

RW

φ FR %

RO

Rt

SW%

OR 0.81 F= 2

φ

87

SATURATION DETERMINATION FOR CLEAN LIMES AND DOLOMITES SW

φ F

RW P O R O S I T Y

M=2

88

RO

Rt

DEVELOPMENT OF THE PERMEABILITY PROFILE

89

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 production and is it cost effective?

III. Fluid efficiency distributionWhere will the fracture fluid leak off?

IV. Pore pressure distribution Where is the pore pressure depletion taking place that will affect the in-situ stress distribution?

90

I. PRODUCTIVITY PROFILE LOCATE THE PRODUCING ZONE(S)

0.01 0.0

GR GAPI 150

Deep Resistivity 0.2 OHMM 2000.0

K MD Perm

0.2 10.0

Φ e or BVW 0.0 Hydrocarbons Moved Water

91

II. PRODUCTIVITY ESTIMATE HYDRAULIC FRACTURE EFFECTS ON PRODUCTIVITY

FLOW RATE IS DIRECTLY RELATED TO: Reservoir permeability-thickness Fracture length and conductivity Reservoir PVT parameters

92

III. FLUID EFFICIENCY DISTRIBUTION FRAC FLUID LEAKOFF

93

IV. PORE PRESSURE DISTRIBUTION FOR STRESS CALCULATIONS

94

LOG DERIVED PERMEABILITY

Permeability can be derived from logs using the following inputs:

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

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

95

SOURCES OF PERMEABILITY

FOR FINDING THE "C" FACTOR

USE ONE OF THE FOLLOWING TO 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

96

LOG DERIVED PERMEABILITY SANDSTONE RESERVOIR CALCULATION

keff

=

[C

X

φe2

(φe-BVI) X

BVI

]

2

where: keff φe BVI C

= = = =

Effective permeability (md) Effective porosity (shale corrected crossplot) Bulk volume water irreducible A constant for each reservoir type

φe and BVI are expressed in fractional units keff is permeability to total fluids. Permeability to hydrocarbons requires a water cut input.

To match core permeability to air set C = 100

If φe is greater than BVI the zone is permeable If φ e is less than BVI the zone is impermeable

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

97

LOG PERMEABILITY EXERCISE # 1

Sandstone oil reservoir with the following parameters:

BVI C

keff =

= =

[

0.05 (Column C) 17.1 (Cell C4)

C X φe2

(φe-BVI) X

BVI

]

2

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

φe = .07

keff =

__________ md

φe = .10

keff =

__________ md

φe = .12

keff =

__________ md

φe = .15

keff =

__________ md

With a permeability cutoff for net pay of 0.001 md: What is the porosity cutoff? _______ % 98

LOG DERIVED PERMEABILITY OUTPUT FOR OIL SAND Where: BVI = 0.05 and C = 17.1 Will this produce water?

BVI BVI

99

LOG DERIVED PERMEABILITY UNFRACTURED CARBONATE RESERVOIRS

keff

=

[C

X

φsonic2

φsonic - BVI X

BVI

]

2

where: keff φsonic BVI C

= = = =

Effective permeability (md) Sonic porosity* Bulk volume water irreducible A constant for each reservoir type

A well test may be of more value in carbonates The permeability estimate in carbonates is qualitative due to complex pore throat structures. Many carbonates have there permeability dominated by fractures and unless a pre-frac well test is performed the results may be poor.

*

100

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

PERMEABILITY FROM NMR

1.

Using the MRIL

k= Where

[(

)(

MPHI A

C

)]

MFFI BVI

C

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

2. Using the CMR

k=CΦ Where

B NMR

C

T2

T2 = Log Mean T2

B = Usually 4 C = Usually 2

101

PERM CALIBRATION FOR NMR Service Company Calibrations

1.

With the MRIL Perm adjust the “A” factor to get effective perm.

2.

With the CMR perm adjust the “C” factor to get effective perm.

3.

Porosity Considerations

4.

102

A.

NMR Porosity is close to Φe

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 wait time is too short.

Alternately use Φe from NMR and BVI in spreadsheet for calculating perm.

PERMEABILITY EXERCISE NET PAY ESTIMATION WATER CUT PREDICTION

103

PERMEABILITY EXERCISE FINDING WATER PRODUCING ZONES

Bulk Volume Water (BVW) = φe X Sw

φt

{

Sw

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

104

PERMEABILITY EXERCISE CALCULATING LOG DERIVED PERMEABILITY Part I Using the BVW on pages 106 and 107 and the Relative Perm graphic below, circle the produced fluids for each zone.

NOTE: This Relative Perm graphic is for the specific area of these logs.

No water production - < 6%

> 10% - 100% water production

Part II Calculate log derived permeability for each zone using the workbook "Permeability Calculator" Using:

keff = [C X φe2 X ((φe - BVI) / BVI)]2

Where: C = 17.5 (Cell C1) and BVI = 0.06 (Column C) 105

PERMEABILITY AND WATER CUT C = 17.5 and BVI = 0.06

106

1

.177 .104

2

.168 .098

3

.191 .132

4

.140 .091

5

.155 .110 Depth

BVW .104

Fluid(s) Produced Oil / Water

1

7579

2

7588

.098

3

7611

4 5

φe .177

k eff (md) BVI = 0.6 _____

keff (md) BVI=BVW _____

Oil / Water

.168

_____

_____

.132

Oil / Water

.191

_____

_____

7624

.091

Oil / Water

.140

_____

_____

7648

.110

Oil / Water

.155

_____

_____

PERMEABILITY AND WATER CUT C = 17.5 and BVI = 0.06

6

.150 .089

7

.154 .087

8

.156 .082

φe

.089

Fluid(s) Produced Oil / Water

7705

.087

7755

.082

Depth

BVW

6

7680

7 8

.150

keff (md) BVI = 0.6 _____

keff (md) BVI=BVW _____

Oil / Water

.154

_____

_____

Oil / Water

.156

_____

_____

107

LOG DERIVED PERMEABILITY

PERM EXERCISE ANSWER SHEET SCALE FACTOR (C)

17.5

PERM AVERAGES KH TOTAL KH WELL TEST

0.64 MD 3.87 MDFT 3.87 MDFT

108

DEPTH

PHIE

BVI

PERM

FLUID

7579 7588 7611 7624 7648 7680 7705 7755 7835 7865 7955 7975

0.177 0.168 0.191 0.140 0.155 0.150 0.154 0.156 0.180 0.141 0.141 0.143

1.950 1.800 2.183 1.333 1.583 1.500 1.567 1.600 2.000 1.350 1.350 1.383

1.143 0.790 1.943 0.209 0.443 0.349 0.423 0.464 1.286 0.221 0.221 0.245

Water Oil & Water Water Oil & Water Water Oil & Water Oil & Water Oil & Water Oil & Water Oil & Water Oil Oil

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? __________

0.01 0.0

Deep Resistivity 0.2 OHMM 2000.0

GR GAPI 150

K MD Perm

0.2 10.0

Φ e or BVW 0.0 Hydrocarbons Moved Water

7600

7700

7800

7900

109

PERM SPREADSHEET EXERCISE

1.

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

2.

Using the “Log Analysis Calculations Blank” input the “C” factor of 3.8 into Cell AC4. The calculated “Perm Archie” will be effective permeability assuming BVW = BVI.

3.

Use the Excel “paste function” to average the Modified Simandoux Perm for each layer marked and write the average permeability in the worksheet. (FracProPT will use this perm to calculate leakoff)

4.

Mark the permeability layers with an “X” to indicate leakoff will occur.

5.

Mark the Pore Pressure Gradient (PP) in the various layers. This PP will later be used in the stress calculations.

110

PERMEABILITY EXERCISE 1. Write the Pore Pressure Gradient in each layer Wireline 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 LAYERS

AVG.

Leakoff

PERM

PP

11400

11500

11600

.001

.01

.1

1

111

EAST TEXAS SAND - CV TAYLOR Water Frac or Sand / Gel Frac Which Would You Recommend? NMR Perms were Calibrated to Cores and Corrected for Gas Gamma Ray Caliper, SP & V

Shale

Hint: Look at the Clay and the Perm 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123 123

Dual Induction

.002

2

Permeability

112

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Neutron / Density MRIL Porosity

.06 md

.05 md

NMR

BVI, POROSITY MOVABLE WATER HYDROCARBONS

113

IDEALIZED ECHO TRAIN NMR Porosity

Amplitude

Free Fluid (FFI) T2R Bulk Volume Irreducible (BVI) TE

Time

The Basic NMR Experiment N

1) Permanent magnet polarizes hydrogen nuclei

S

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

Signal Amplitude

Spin Echoes

3) Wait for re-polarization 4) Repeat steps 1-3 RF Pulses

Time (ms)

114

clay-bound water

small-pore (irreducible fluid) signal

time

large-pore (mobile fluid) signal

multiexponential fit to spin-echo amplitudes

NMR porosity

Spin-echo data

Incremental Porosity [pu]

“Inversion” Processing

0.1

0.00

0.50

1.00

1.50

2.00

1

BVI

100

T2 [msec]

10

FFI

T2 Spectrum

1000 10000

ECHO TO T2 “INVERSION”

115

EFFECTS OF OIL ON T2 DISTRIBUTION

4.0

3.0

2.0

1.0

Sw = 56.9% Sw = 65.4% Sw = 84.3% 1224.8

T Distri 2 bution

Sw = 100%

341.8

95.4

26.6

2.1

7.4

0.0 0.6

Incremental Porosity %

Oil and Water Saturation Effects

Oil Viscosity Effects 609 ms 2.7 cp

40 ms 35 cp

1.8 ms 4304 cp.

0.1

1

10

100

T2 (ms)

116

1000

10,000

T2 CUTOFFS AND DISTRIBUTION Bulk Volume Irreducible and Free Fluid Gamma Ray1234Dual Induction

1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234 1234

T2 Distribution Variable Density

Clay Volume Effective Porosity Gas

Φ Hydrocarbons e Φ Hydrocarbons e Gas

Φ Hydrocarbons e Gas

Φ Hydrocarbons e Φ Hydrocarbons e

Movable Water

117

T2 - RELATIVE TO SURFACE AREA Incremental Porosity %

100

80

60

40

20

0 0

100

300

400

500

Small Pore Size = Rapid Decay Rate Large Pore Size = Slow Decay Rate

Water Filled Pores

200

Time (ms)

600

118

T2 TIME SLICES CALLED “BINS” Smaller Pore Surfaces - Shorter T2 Larger Pore Surfaces - Longer T2 Gamma Ray

Perm Indicator Dual Induction

T2 Distribution Variable Density

Clay Volume Effective Porosity Gas

Φ Hydrocarbons e Φ Hydrocarbons e Larger Pore Surfaces

Gas

Φ Hydrocarbons e Gas

Larger Pore Surfaces

Small Pore Surfaces

Φ Hydrocarbons e Φ Hydrocarbons e

Finest Grains

Finest Grains

Small Pore Surfaces

Movable Water

119

T2 OF ROCKS AND FLUIDS NMR Summary

T2 (ms) 0.1

1.0

10

100

1000

Clay bound water Montmorillonite/Smectite

Illite

Cholrite

Kaolinite

Capillary bound water Free water - sands Small grains

Large grains

Free water - carbonates sucrosic

vuggy

Gas Light Oil Medium Oil Heavy Oil

Oil Wetting

120

MRIL ANALYSIS - MRIAN IN TRACK 4 Clay Bound Water in Green Capillary Bound Water Gray Movable Hydrocarbons in Red Movable Water in Blue Raw Bins and Correlation

Resistivity and Permeability

T2 VDL .5 msec

1024 msec 50%

Track 4 Porosity

0%

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?

121

LOW RESISTIVITY PAY WITH NMR McClish Sand Open Hole Logs Look at the Upper Part of the Sand Does it appear to be wet?

Platform Express Data

122

LOW RESISTIVITY PAY WITH NMR CMR Calculations Waveform instead of VDL Show Movable Hydrocarbons when Water was Suspected Permeabilities are Tied to Cores How do we know if they are right? CMR Analysis

123

124

LOW RESISTIVITY PAY WITH NMR Calibrated CMR Permeabilities Match Permeability from Post Frac Test Buildups run after perforating indicated average reservoir perm 7-10 md

IP: 3 mmcf/day No Water

MRIL Prime Hydrocarbon Typing Calibrated Perm Compared to actual Production Hydrocarbon Typing from Differential Spectrum

Low Perm Water 4 BWPD

350 BOPD 200 MCFPD

125

ANALYSIS WITHOUT NMR Would you expect a lot of water? Traditional BVI = 5%

Quick look Hand Calculations Analysis

How many stress layers? GR-SP

AIT

.3

TLD-CNL

-.1

ML

RW=.035

RT φ SW 4 19 49

BVW .093

7

18

39

.07

5

20

41

.084

Conclusion: Well sh ould p roduc e a co nsidera ble amount of water an d some HC. T raditional BVIRR cu ttoff for most Granite Wa sh is .05 .

126

CMR ELAN INTERPRETATION Not using NMR Porosity

Lithology for stress layers and heat transfer Zones Tested Separately

400 mcf mcf/day /day Oil & No Water

200 mcf mcf/day /day 140 bbl Oil 1 bbl Water

Would NMR Porosity have helped?

127

128

THE ROLE OF STRESS DIRECTION AND FINDING STRESS DIRECTION

129

THE ROLE OF IN-SITU STRESS In Drilling and Stimulation

Hydraulic fractures propagate in the direction of the maximum principal stress and generate width in the direction of the minimum 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 from vertical B. Other roles of stress 1. Bore hole stability -want minimum difference in stress 2. Minimum difference in stress minimum sand production

130

THREE PRINCIPAL STRESSES

(Preferred Drilling Direction)

VERTICAL (Overburden) Usually larger and therefore vertical fractures are created If less than horizontal stress a horizontal fracture results A. Maximum stress on Horizontal well bores B. Maximum stress for creating sanding potential HORIZONTAL in Fracturing Maximum - determines lateral direction of propagation Minimum - determines the direction of creating width

131

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

132

HORIZONTAL STRESS MAGNITUDE THE MOST CRITICAL INPUT IN 3-D SIMULATORS

SH

SH SH = Minimum Horizontal Stress The magnitude and distribution of the minimum horizontal stress will determine the vertical fracture propagation and height growth 133

MAX HORIZONTAL STRESS DIRECTION FOR WELLSITE PLACEMENT Offset Well Drainage Patterns

Fractures in Horizontal Wells σv

Single Fracture

Single Fracture Single T shaped Multiple Reorientation multiple (at wellbore)

σHmax Reorientation Multiple fractures (away from wellbore)

134

σmin

MAX HORIZONTAL STRESS DIRECTION FOR PERFORATION STRATEGY Near wellbore entry problems (tortuosity)

Don't Create Initial Width against Maximum Stress !! Place Perforations In Max Stress Direction 1. Lower initiation pressures 2. Fewer premature screenouts 3. Higher sand concentrations near the wellbore

135

MAX HORIZONTAL STRESS DIRECTION 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 136

2. Direction from Dipmeters

LOGS FOR FINDING STRESS DIRECTION BOREHOLE BREAKOUT Multiple Arm Caliper - Direction Information Extensional Fracture (Natural Fractures)

SHmax

Elliptical Enlargement

SHmin

Shear Fractures (No Natural Fractures)

Elliptical Enlargement

SHmax

SHmin 137

LOGS FOR FINDING STRESS DIRECTION BOREHOLE IMAGING TOOLS Halliburton- CAST-V or EMI Schlumberger- FMI Baker Atlas- CBIL Natural fractures, Drilling Induced, or Log after Minifrac

N

138

E

S

W

N

MAX HORIZONTAL STRESS DIRECTION

Perms Calibrated to Cores allows Production Prediction

139

LOGS FOR FINDING STRESS DIRECTION

FRACT URE

FRAC D

IRECTIO

N

ROTO SCAN - DIRECTION OF THE FRAC Radioactive material in the frac wings

140

TORTUOSITY IN THE BOTTOM ZONE Perforations in Zone B were 90o to the Initiation Direction.

A B

141

142

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

70 degrees to Perfs

90 degrees to perf

FINDING MAXIMUM STRESS DIRECTION PRODUCTION/TESTING RESULTS

A. Production decrease or an increase in Gas Oil Ratio in an offset 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)

143

FINDING MAXIMUM STRESS DIRECTION GEOLOGICAL INFORMATION (Assumes stress state hasn't changed since faulting) A. Reverse or Thrust Fault 1. Compressional tectonic environment 2. Maximum stress perpendicular to the fault

B. Normal or Growth Fault 1. Extensional tectonic environment 2. Maximum stress parallel to the fault

144

ESTIMATING AN IN-SITU STRESS PROFILE

145

MINIMUM HORIZONTAL IN-SITU STRESS

DEVELOPING THE STRESS PROFILE

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

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

ADVANCED TECHNIQUE: Microfracture treatments in all layers using small fluid volumes at low rates. 1. With tubing and packers in casing 2. With wireline inflatable packers and pump in openhole

146

COMPONENTS OF HORIZONTAL STRESS

POISSON'S RATIO

OVERBURDEN

STRESS PROFILE

Pext from pump-in test calibration

PORE PRESSURE

147

POISSON'S RATIO - ν A MATHEMATICAL FUNCTION TO COMPUTE HORIZONTAL STRESS

Horizontal stress is a result of the vertical stress

OVERBURDEN PRESSURE (Squash)

HORIZONTAL STRESS (Squish)

ν = Squash / Squish

ν

148

is calculated using the shear and compressional sonic data

SONIC WAVE TRAVEL TIMES 1 Foot

R

T

VELOCITY OR SLOWNESS (Travel times through one foot)

∆tlog = φ∆tfluid + (1-φ)∆ ∆tmatrix

149

FULL WAVE WITH DIPOLE The ratio between the shear and compressional sonic travel times is a function of the lithology and the elastic rock properties. ν) is a measurement that indicates the degree of Poisson's Ratio (ν elasticity.

Earlier Quieter

Later Louder

Monopole PREFERRED: Dipole sonic tools (open or cased hole) Dipole

150

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

WHY THE DIPOLE SONIC IS PREFERRED CAN GET A SHEAR MEASUREMENT WHEN OTHER LOGS CAN'T Time (∆τ ∆τ) ∆τ Compressional

Shear

Fluid

! ∆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

151

DIPOLE SONICS IN CASED HOLE Need fluid in the wellbore and some cement

1/νS in Microseconds / Ft.

Travel Time in Milliseconds

Comparison of open and cased hole shear-wave logs

152

POISSON’S RATIO ESTIMATION Calculate Poisson’s ratio from shear and compressional sonic travel times using the worksheet "Poisson's and Young's from Dipole".

ν

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

=

where: ∆ ts ∆ tc

= =

Delta T Shear (microsec/ft) Delta T Compressional (microsec/ft)

POISSON’S RATIO ESTIMATION EXERCISE Delta T Compressional

=

65 microsec/ft (Cell B7)

Delta T Shear

=

107 microsec/ft (Cell C7)

Shear - Compr Ratio

=

_________

(Cell D7)

Poisson’s Ratio

=

_________

(Cell F7)

153

SHEAR/COMPRESSIONAL RATIO

154

Shales Lime

Dolo Anh Siltstones

Hard Sands

POISSON'S RATIO

Soft Sands

POISSON'S RATIO VS SHEAR/COMPRESSIONAL RATIO

SONIC QUALITY CONTROL

Poor Coherence Missing Data

What Should Poisson's Ratio read in the shale?

BAD DATA FLAG

155

POISSON’S RATIO GAS CORRECTION Gas Effect On Ratio Of Shear To Compressional Travel Times ν = [(0.5 X (∆ts/∆tc)2)-1] / [(∆ts/∆tc)2-1]

∆tcompr

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

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

A practical correction method involves calibration to a low porosity, oil, or water sand with the same lithology as the affected gas sand. 156

POISSON'S RATIO CORRELATION 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 be correlated to the frac well using lithology.

3. Spreadsheet calculations Poisson's in sand/shale lithology Poisson's Ratio for various types of 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

157

ν IS RELATED TO LITHOLOGY LITHOLOGY DATA IS NEEDED FOR CORRELATIONS Poisson's ratio is independent of porosity.

ν OFFSET WELL 0.26

0.29

0.31

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

FRAC WELL

158

POISSON`S VS GAMMA RAY SHALE INDEX Sand and Shale Lithology Using the equation 0.17 + 0.17(GI) Poisson's was calculated Exercise: Find and mark bad sonic data below

Gamma Ray 0

.15 150

ν Sonic

υ Gamma Ray

Edyn

.35 0

10

159

GEOLOGY EFFECTS CORRELATIONS CORRELATIONS MORE DIFFICULT IN COMPLEX LITHOLOGY

160

ROCK COMPONENT OF STRESS

OVERBURDEN PRESSURE (Squash)

HORIZONTAL STRESS (Squish)

STRESS =

Rock Component

+

Fluid Component

+

Calibration Component

The rock component is a function of overburden and Poisson's Ratio

Defined by:

ν X OBG ν 1-ν

OBG = Overburden Gradient = Vertical Stress/Depth 161

OVERBURDEN GRADIENT VS ROCK TYPE

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

Lithology

Porosity

Overburden

Anhydrite Shale Dolomite Limestone Sandstone Sandstone Sandstone Sandstone Salt

0% 0% 0% 0% 0% 10% 20% 30% 0%

1.26 psi/ft 1.23 psi/ft 1.21 psi/ft 1.15 psi/ft 1.12 psi/ft 1.05 psi/ft 0.98 psi/ft 0.91 psi/ft 0.86 psi/ft

Overburden Gradient (OBG) should be reasonably constant in an 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.

162

OVERBURDEN GRADIENT EXAMPLE

MOST OVERBURDEN GRADIENTS ARE NEAR 1.0 PSI/FT

Shale 1.23 psi/ft 2000 ft Average Gradient 1.13 psi/ft

Anhydrite 1.26 psi/ft 2000 ft Sandstone 0.91 psi/ft 2000 ft Pay Zone

Field examples of Measured Overburden Val Verde Basin W. Texas Black Warrior Basin Coal Offshore Louisiana South Texas: Wyoming Frontier

: : : : :

1.09 1.20 0.93 1.00 1.00

Values can vary with depth.

163

PORE PRESSURE STRESS COMPONENT

STRESS =

Rock Component

+

Pore Pressure Component

+

Calibration Component

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

[1 -

ν ν 1-ν

]

X

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 set equal to the original reservoir pressure for the field. This can be obtained from historical field data or from the highest measured pore pressure in a virgin zone.

164

PORE PRESSURE CHANGES CRITICAL WHEN PARTIAL DEPLETION HAS OCCURRED Using formula on page 164, calculate pore pressure component of stress

Pore pressure can be measured with wireline formation tester Calculate: 1. Pore Pressure Gradient (Pp) for: Assuming ν = 0.22 for sands. 2. Calculate the Pressure component of the stress gradient for: 3. Log Derived Stress (pressure component) for

A. ______ B. ______ A. ______ B. ______ A. ______ B. ______

7700

A 510 psi

FORMATION TEST PRESSURES

7800

B 2780 psi

Depletion in the Travis Peak of E. Texas Pressure change of 400% in less than 100 feet Exercise:

How much does the stress change from pore pressure? __________

165

LOG DERIVED STRESS PROFILE

ROCK ν ν 1-ν

X

OBG

+

FLUID

[1 -

ν ] ν 1-ν

X

Pp

EQUALS LOG DERIVED CLOSURE STRESS GRADIENT

The key inputs required at least once in a field are: 1. Poisson's ratio * 2. Overburden gradient 3. Pore pressure gradient 4. Calibration Component

-

ν OBG Pp Pext

* From a full wave sonic or correlation to a nearby sonic. 166

CLOSURE STRESS GRADIENT (CSG) A PRIMARY INPUT FOR 3-D FRAC MODELS The wireline measurements can be used to determine the minimum horizontal stress profile for all zones above and below the perforated interval. Since this is inherently wrong a pump-in calibration is necessary. ACTUAL CSG (in tectonically relaxed areas) is:

CSG =

ν ν 1-ν

X

OBG

ROCK

+ [1 -

ν X ] Pp ν 1-ν

+

+

FLUID

+ CALIBRATION

Pext *

* A pump-in test will be necessary to find Pext

167

STRESS EXERCISE #1 Closure Stress Gradient (CSG) Estimation from Log Data Use the worksheet "Rock Properties for FracPro"

Poisson’s 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

=

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

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

168

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 at original field pore pressure.

GIVEN: Poisson’s ratio from log: 0.20 Overburden gradient: 1.1 psi/ft Pore 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

=

ν) X OBG + (1-(ν ν/1-ν ν)) X Pp + Pext (ν ν/1-ν

CSG

=

________ psi/ft

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

169

Flow Chart for Stress Calculation Coherent Measured ν Pore Pressure Gradient

Overburden Gradient Log Stress Gradient

Calibrate with Pump-In Pext

Depth Stress for Model

170

STRESS EXERCISE # 3 Find Poisson's ratio change in a shale to equal a change in stress of 100 psi.

Shale Volume

Caliper 6

Inches

16 0

Corrected GR

11300 A B C D 11400

0

API

1 00

Poisson’s Ratio 1 0 .2

S HALE S AND

0 .4

ν

LOG

Pext = 0 STRESS

Pext = .09 STRESS

Average Shale Above _____ ______ _____ A. _____ B. _____

______ ______

_____ _____

C. _____ ______ _____ D. _____ ______ _____ Average Shale Below _____ ______ _____

11500

Compare the different stress values

E F G 11600

Average Shale Above _____ ______ _____ E. _____ ______ _____ F. _____ ______ _____ G. _____ ______ _____

H

11700

H. _____ ______ _____ Average Shale Below _____ ______ _____

171

SONIC, GAMMA RAY, NEUTRON DENSITY

POISSON'S RATIO 172

0.2

0.22

0.24

0.26

0.28

0.3

0.32

0.34

0.36

0.38

GI NPHIDPHI DIPOLE

DEPTH

COMPARISON OF THREE METHODS FOR POISSON`S

YOUNG'S MODULUS DEVELOPMENT

173

ROLE OF YOUNG'S MODULUS

1. Used with stress to estimate fracture width.

2. Used to estimate the variable tectonic component.

174

YOUNG’S MODULUS ESTIMATION DYNAMIC OR LOG DERIVED

INPUTS REQUIRED ARE: 1. Full wave sonic ∆TSHEAR and ∆TCOMPRESSIONAL 2. Bulk Density (ρb)

FORMULA: Edyn G

= =

ν) 2 X G X (1+ν 13400 X (ρb/∆TS2)

Units are in PSI X E6 ∆ ∆T shear = DTS

(Dynamic Young's Modulus) (Shear Modulus)

∆T comp = DTC or DT

WHERE:

ρb ∆TS ν

= = =

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

Dynamic Young's Modulus calculated from logs must be converted to Static Young's Modulus for use in 3-D models. 175

YOUNG'S EXERCISE # 1 DYNAMIC 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 Poisson’s ratio (Cell F7)

=

0.20

USING: ∆TS2) G = 13400 X (ρb /∆ ν) Edyn = 2 X G X (1+ν

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

_______ X E6 psi

Dynamic Young’s Modulus (Cell H7) =

_______ X E6 psi

Shear modulus (Cell G7)

176

DYNAMIC VS A STATIC YOUNG’S

The log derived dynamic Young’s modulus estimate cannot be used directly as an input to the 3-D models. It must first be corrected to static.

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

Two options are available to correct the log Young's Modulus to a static:* 1. Use published core data (practical method) Refer to the chart on page 178 to obtain the Lab Ratio Estatic

=

Edyn X (Lab Ratio)

2. Using actual core data (preferred method) Static to Dynamic Ratios (SDR) Estatic

=

Edyn X SDR

177

STATIC TO DYNAMIC YOUNG'S MODULUS Two Correlations of Conversions Lab Data from SPE 26561 140%

Static % of Dynamic

120% 100%

80%

0 - 14% Porosity

60% 15 - 24% Porosity

40%

25 - 35% Porosity

20%

Dynamic Young’s Modulus

0% 0

4,000,000

8,000,000

12,000,000

16,000,000

From GRI Studies (Tight Gas Sands) Dynamic Young's Modulus, millions of psi

10

8

6

4

2

0 0

2

4

6

8

Static Young's Modulus, millions of psi 178

10

STATIC TO DYNAMIC YOUNG'S MODULUS Composite of both Correlation Studies

1

Static/Dynamic Ratio

0.9 0.8 0.7 0.6 0.5 0.4 0.3 y = -0.0003x 4 + 0.0052x 3 - 0.0203x2 + 0.0312x + 0.4765 R2 = 0.9145

0.2 0.1 0 0

2

4

6

8

10

12

Dynamic Young’s Modulus x E6 psi

The above forumula is incorporated in the spreadsheet "Rock Properties for FracPro. It is used to calculate the static to dynamic ratio and this ratio is then multiplied times the dynamic ratio and converted to millios of psi. 179

Flow Chart for Young’s Calculation Poisson’s Ratio ∆T Compressional

∆T Shear Dynamic Poisson’s

Convert to Static SPE Data

GRI Data Young’s for Model

180

YOUNG'S EXERCISE # 2 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) Shale Volume

Caliper 6

Inches

16 0

Corrected GR

11300 A B

0

API

100

1 0.2 SHALE

(1)

Poisson’s Ratio 0.4

(2)

YOUNG'S YOUNGS DYNAMIC STATIC

(3) SDR

SAND

Average Shale Above _____ ______ _____ A. _____ B. _____

______ ______

_____ _____

_____ _____

C. _____ ______ _____ D. _____ ______ _____ Average Shale Below _____ ______ _____

_____ _____

C D 11400

11500 (1)

(2)

YOUNG'S YOUNGS DYNAMIC STATIC

E F G 11600

(3) SDR

Average Shale Above _____ ______ _____ E. _____ ______ _____ F. _____ ______ _____ G. _____ ______ _____

_____ _____ _____

H

11700

H. _____ ______ _____ Average Shale Below _____ ______ _____

_____

181

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

182

BUILDING PROFILES FOR 3-D MODELS

183

LOW PERMEABILITY GAS SANDS Multiple Zones over a Long Interval

Objectives: 1.

Calculate the average Poisson's, dynamic young's and permeability for each layer.

2.

Estimate pore pressure for each layer.

3.

Convert the dynamic young's to static for use in FracProPT.

4.

Estimate the stress for each layer.

Background: A comprehensive evaluation program was run on this well and on an offset well. This well had the following information: Open hole porosity, lithology, and resistivity Full wave sonic over lower zones (bad data over pay) Pre-frac well test - 108 ft of 0.017 md gas perm Pre-frac pump in test with gelled fluid Real 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 sonic and several microfracture tests. 184

185 8.5

Dynamic Young’s Modulus E6 PSI

DYNAMIC YOUNG’S VS SONIC POISSON'S

DEVELOPED FROM OFFSET WELL WITH FULL WAVE SONIC

8 7.5 7 6.5 6 5.5 y = -21.783x + 11.364 2 R = 0.893

5 4.5 4 0.15

0.17

0.19

0.21

0.23

0.25

0.27

Poisson’s Ratio from Full Wave Sonic

0.29

0.31

STATIC TO DYNAMIC YOUNG'S 140%

Static % of Dynamic

120% 100% 80%

0 - 14% Porosity

60% 15 - 24% Porosity

40%

25 - 35% Porosity

20%

Dynamic Young’s Modulus

0% 0

4,000,000

0

2

8,000,000

12,000,000

16,000,000

Dynamic Young's Modulus, millions of psi

10

8

6

4

2

0 4

6

8

Static Young's Modulus, millions of psi 186

10

LOG STRESS PROFILE DEVELOPMENT Since the shear wave arrival time and the fluid wave arrival time were close the full wave sonic data was not available over this intervals above 6000 feet. A correlation was established below that depth between Poisson’s Ratio and the Gamma Ray shale index (GI). This correlation is shown on the following page. The relationship developed for Poisson’s ratio from the GI was: ν = 0.17 + (GI .17) X

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 without full wave sonic data.

2.

Removes incoherent data if correlation is made where the data is good.

3.

Replaces values where gas correction is needed in sand. 187

POISSON'S RATIO FROM SONIC AND GR

Where is the sonic log probably not valid? Gamma Ray 0

188

.15 150

ν Sonic

ν Gamma Ray

.35 0

10

Edyn

FINDING STRESS LAYERS - FRAC WELL Determine layers for stress/Young's mark on log

υν

Gamma Ray Mark Layers for GI GR

Stress Changes

.15

Caliper

keff

Gamma Ray

Density Porosity .3

Perm

.35 .001

0

Neutron Porosity

.1 0

Pe

10

5250

5300

5350

5400

5450

189

PERMEABILITY AND BULK VOLUME WATER 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 X 4. What is BVI and will it produce water?

Shale Sandstone

190

keff

Resistivity

Shale Volume 0.2

200

Eff Porosity .1

Perm 0.001

1.0

BVW H/C

0

Mark Perm Layers

FINDING STRESS LAYERS - FRAC WELL Using exercise on the following page : 1. Average Poisson's for zones A through F 2. Calculate stress for zone A through F 3. Average Perm for layers A through F υ Gamma Ray

Gamma Ray 0 0 7.

GI GR Caliper

150

.15

k eff

Density Porosity .3

.35

Perm 1. 17.

.001

1.

0

0

Neutron Porosity Pe

Label Lithology

10

5250

A

5300

B

C 5350

5400

D

5450

E F

191

DEVELOPING A STRESS PROFILE Stress, Young's and Perm for 6 layers

1.

The log on page the previous page has been provided in digital form in the worksheet"Case 2 Stress and Perm Profile." Below the workshop starting at row 41 Poisson's Ratio, dynamic Young's and permeability have been calculated using the techniques as demonstrated earlier in the workshop.

2.

The upper part of the worksheet has provided space to calculate A. Stress from the average Poisson's, Pore Pressure, Pext and Overburden B. Average dynamic Young's for each layer. C. Average Permeability for each layer.

3.

For each layer, average the data from the lower part of the spreadsheet using the past function in Excel. Since there is a formula in the averages they must be pasted into the upper part of the spreadsheet using "paste special values". You can use the keyboard and type "alt+edit+s+v and then hit enter when pasting into the spreadsheet for calculations.

4.

Enter the appropriate pore pressure in each averaged layer for stress calculations.

5.

Enter an overburden gradient of 1.09 from the density and a Pext of 0.09

6.

To convert Young's from dynamic to static read the values for dynamic Young's and enter them in the chart on page 186. Read the appropriate Dynamic Young's at the bottom of the chart.

7.

Put the dynamic values in the worksheet "Case 2 Stress and Perm" in column D.

8.

The top depth of the layers, averaged Poisson's, estimated values of static Young's, permeability and stress are ready to past into the FracProPT F9 screen. Demonstrate their input into the F9 screen using data from one of the groups calculations.

192

STRESS PROFILE TABLE WORK SHEET Layer

Depth

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

5250 5254 5277 5295 5298 5335 5353 5358 5362 5383 5390 5392 5395 5399 5408 5443 5449 5453 5458 5480

A

B C

D

E F

Average Pressure Dynamic/Static Poisson's Gradient Young's E6

0.285

0.375

5.7

Average Perm. SSStress

4.0

0

4.6 4.3

.02 0

4.1 4.3 4.5 4.3 4.5 4.2 4.0 4.3

.002 .0 .01 .006 .008 .002 .001 .003

3.8 3.9

.001 0

3.7

0

/ 0.198 0.246

0.300 0.375

6.9 6.4 / /

0.247 0.228 0.209 0.236 0.216 0.245 0.263 0.228

0.375 0.375 0.300 0.375 0.375 0.375 0.375 0.375

6.0 6.4 6.8 6.2 6.7 6.0 5.6 6.4 /

0.277 0.275

0.375 0.375

5.3 5.4 / /

0.289

0.375

5.1

3935 ________ 3085 3698 _________________ _________________ 3746 3624 3212 3691 3570 3758 3883 3652 _________________ 4021 4010 _________________ _________________ 4141

193

STRESS PROFILE DEVELOPED

5200

Depth (ft)

5250 5300 5350 5400 5450 5500 3000

3200

3400

3600

3800

4000

4200

4600

Minimum Horizontal Stress (psi)

194

4800

HEIGHT, LENGTH AND WIDTH Determined Primarily by Minimum Stress Profile What is the Effective Frac Length and Height? 5200

Depth (ft)

5250 5300 5350 5400 5450 5500 0

100

200

300

400

500

600

700

Length (ft)

What is the Effective Frac Width? 5200

Depth (ft)

5250

5300

5350

5400

5450 -0.4

-0.2

0.0

0.2

0.4

Length (ft)

195

FRAC X-PERT ZONING Required FracProPT Inputs Frac X-PERT Listing 1. 2. 3. 4. 5.

Fracture Closure Pressure Estimated Static Poisson's Ratio Corrected Pore Pressure Gradient Estimated Static Young's Ratio Average Permeability Meeting Pay Limits* *May not be a calibrated "effective" permeability

1.

196

2.

4.

3.

5.

MRIL & MECHANICAL PROPERTIES Zoned by the Log Analyst

1. 2.

Mark Zones to be Fracced Which Zones have the Greatest Permeability

197

198

FRACTURING PROBLEMS THAT ARE STRESS RELATED

199

ROLE OF VERTICAL STRESS DIRECTION Creating Multiple Fractures

When the vertical stress is not parallel to the wellbore multiple fractures may result

Critical in multiple zone completions

200

VERTICAL STRESS VS FRACTURE DIP Multiple fractures can prevent the optimum fracture treatment

Created Fractures

Created Fractures

Zone A

Zone B Vertical Stress Vector

Uses fluid volumes and proppant designed for a single fracture. Zones can be under stimulated or had not been stimulated.

201

DEVIATION EFFECT ON LOGS Tracer logs have a limited depth of investigation

Tracer top

Horizontal displacement as a result of dip

100 ft Depth

1 Degree Fracture Dip

1.75 ft Horizontal Offset

202

Actual fracture height

Tracer bottom

Fracture height according to tracer

Tracer limit of investigation

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CORE AND IMAGE DATA

EVIDENCE OF DEVIATED FRACTURES

Canyon SS

5o

Miller 1991

Travis Peak SS

1o - 5o

SFE 1&2

Lost Hills Diatomite*

15o

Fast 92

Spraberry SS

5.5o

DOE 1996

Mesaverde SS

Multiple fractures in offset horizontal core

Warpinski 1991

*Numerous case studies in the Diatomite have indicated that the created fractures were: - Perpendicular to the bedding planes

203

MULTIPLE ZONE COMPLETION ISSUES Production Logs and Tracers Can be Help Resolve these Issues

1.

Should the zones be stimulated together or in separate stages?

2.

If they are stimulated in separate stages, will the treatments communicate?

3.

What is the optimum perforation strategy?

204

PRODUCTION LOGS TEMPERATURE & TRACER FOR EVALUATING TREATMENT EFFECTIVENESS

205

PRODUCTION LOGS AND RESULTS

Comparing Production to What was Expected

1.

Volumetric reserves compared to actual results

2.

Nearby water produced (or not) after frac

3.

Were all zones fracced in a multi zone completion?

4.

Fluid placement during frac

Production Log Results

206

1.

Which zones are producing?

2.

How much production is each zone contributing?

3.

Was the fracture treatment successful?

THE BEST OF THE BUNCH! ESTIMATED FLOW FROM OPEN HOLE LOGS

207

PRODUCTION WAS THE WORST!

1. What is not effectively treated?

2. What could be the problem?

3. Suggestions for a more effective treatment.

208

WAS THE COMPLETION EFFECTIVE?

209

TEMP CHANGE - FLUID MOVEMENT Temperature Logs Have a Deeper Depth of Investigation

Ran while injecting

210

WHERE IS THE TOP AND THE BOTTOM? Temperature Effects Above and Below Treatment Shut-In Temperature (OF) 100

105

110

115

120

7000

Well Shut-In Hours 1 2 3

Zone A

Zone B

7050

Zone C

Which Zones were Treated? Which survey shows best definition?

211

TEMP LOG WITH TWO ZONES Possibly Two Fractures were Created TEMPERATURE

165

175

5800 Th

ZONE A

TG

TG - Th = 4oF

∆T1

5900 Geot

6000

212

t adien al Gr

∆T2

herm

ZONE B

TRACER - INSIDE VS OUTSIDE Tracer material was inside the pipe and not in the fracture.

EXERCISE: INSIDE - OUTSIDE SOLUTION

FRACTURE HEIGHT

On the outside curves mark the tracer material outside the casing.

213

MULTIPLE FRACTURE IDENTIFICATION USING TRACER LOG

"Zero Wash" tracer with - final stage not in all zones

Conventional tracers not continuous

Tracer height less than model predicted propped fracture height indicates deviated fracture.

214

TRACER SHOWS PROPPANT PLACEMENT

Sc- 46 First Stage

Ir-192 Final Stage

1. Why is there only the first stage 1-4 ppg 20/40 proppant in zones B & C?

2. The final stage 5 ppg 20/40 resin coated sand is put away in zone A. Why do we still have the first stage present near the wellbore?

215

NEAR WELLBORE ENTRY PROBLEMS THE CAUSE OF MOST PREMATURE SCREENOUTS

Perforations oriented in the maximum stress direction will generally have the lowest initiation pressures.

o 70

216

TRACER RESULTS FROM A STEP RATE TEST DOES THE TEMP LOG INDICATE MULTIPLE FRACTURES IODINE ANTIMONY SILVER

217

MEASURED FRACTURE HEIGHT Correlation

Rt

Perm

Porosity

Temperature vs. Tracer WHAT IS THE TREND HERE? 100 7700

Fracture Height (ft)

80

60

40

20 7800

0 3200 5200 6400 7100 9200 9300 95009500 9600 11700 Well Depth (ft)

Temp

7900

218

Gamma Ray

RADIOACTIVE TRACER TECHNOLOGY PROPER APPLICATIONS There is no “typical” tight gas reservoir. Variations, in many cases extreme, occur in porosity, permeability, saturation, pore pressure, in-situ stresses, etc. which affect the optimum design and success of a hydraulic fracturing operation. As the industry has become more comfortable with the utilization of FracPro and other complex 3-D Fracture Modeling programs, the proper application of radioactive tracer technology allows the design engineer to compare what are in many cases, assumed values to input into the model, with the actual completion results in the near wellbore region. In a recent study of nearly 150 completions from four different basins, it was determined that at least 40% of these completions had one or more of the following occurrences which significantly affect the economic success of a completion: (1) Fracture Height greater than designed (2) Un-stimulated Pay Intervals (3) Under-stimulated Pay Intervals With proper application of tracer technology, one can help confirm design effectiveness, economic return, and the most asked question about a Completion “Where is my proppant?” The proper use of "Zero Wash" radioactive tracers will determine the following: Proppant Distribution at the Wellbore - By placing multiple tracers staggered throughout the frac job, one can determine whether proppant in an interval was placed early or late in the frac sequence. Are all perforation sets effectively propped at the wellbore? The effectiveness of a limited entry perforating scheme can be readily identified. Fracture Conductivity - Conductivity is a function of fracture . The correlation between gamma ray intensity from tracers and fracture width has been documented. An algorithm has been developed which estimates fracture width from gamma ray intensity using the Monte Carlo method of numerical simulation.

219

TRACER APPLICATIONS CONTINUED' Staging Efficiency - in many cases, the need to separate a frac job into multiple stages is apparent from tracer analysis. There may be a larger stress or pore pressure contrast between layers than was assumed causing inefficient stimulation in a single stage operation. Conversely, multiple stages may be unnecessary; this can be confirmed with a properly planned tracing program. Minimum Fracture Height - Radioactive tracers will always identify the minimum height of the medium pumped - either hydraulic height (pad tracers) or propped height (proppant tracers). In all but the most severe cases, this minimum height from tracers will be equal or very close to the created fracture height. Any time this minimum height is greater than designed, then it is likely that the length may be less than desired. Identifying Tortuosity - Several tracing designs have been employed to identify the presence and determine the severity of tortuosity. Changing tracers after the first 5 - 10% of the job volume has been pumped and tracing of proppant “slugs” have both been employed successfully to determine the degree to which tortuosity affects the completion. Observations can be made about the effect of perforation phasing, orientation and shot density on reducing the impact of near wellbore tortuosity. Proppant Settling - The effects of proppant settling below the perforated interval or out of the desired zone can be seen from radioactive tracers. Proppant transport issues such as convection may also be deduced from careful analysis of tracer logs. Diversion Effectiveness - An ideal use of tracers is to change isotopes each time a new diverter stage is pumped to see if the next component is entering the same interval or diverting into new intervals. Tracers are used successfully to determine the effectiveness of various diverters and ball sealers in fracturing and acidizing operations. As with all other technologies, to be beneficial, tracers must be applied properly and interpreted correctly to be most useful. Radioactive tracers are today used extensively for verification of fracture modeling results, as well as in determining completion effectiveness and economic viability of a reservoir.

220

APPLYING STRESS AND PERM STIM DESIGN IN MULTIPLE ZONES

221

MULTIPLE ZONE COMPLETION ISSUES

1. Should the zones be stimulated together or in separate stages?

2. Will treatments be redundant if treated separately?

3. What is the optimum perforation strategy?

222

FORMULA FOR SUCCESS

Reservoir Quality x Effective Stimulation = Maximum Production

223

WERE DESIRED RESULTS ACHIEVED? Were zones effectively treated

Early and late proppants were tagged with two different isotopes

224

WERE DESIRED RESULTS ACHIEVED? Was desired length achieved?

How much money was left in the ground?

225

WERE DESIRED RESULTS ACHIEVED? Is production as predicted or expected? Was this completion effective?

226

CRITICAL INPUT DATA FOR MULTIPLE ZONE COMPLETION OPTIMIZATION

Vertical in-situ stress orientation with respect to the wellbore.

Horizontal in-situ stress azimuth and distribution.

Permeability profile.

227

LIMITED INTERVAL CASE STUDY Where is the Permeability? Rt Perm

Correlation

7700

7800

7900

228

Porosity

LIMITED INTERVAL PERFORATED WELL VERSUS OFFSET AVERAGE PRODUCTION

BOPM

EUR 150 MBO

EUR 110 MBO

Months of Production

Offset Wells - One stage 275 feet 7645 - 7920 (limited entry) Optimized Well

- Two stages 10 feet each 7834-45 and 7695-7705 (limited interval)

229

PRODUCTION RESULTS

Comparing Production to What was Expected

1.

Volumetric reserves compared to actual results

2.

Nearby water produced (or not) after frac

3.

Were all zones fracced in a multi zone completion?

4.

Fluid placement during frac (particularly final stage)

Production Log Results

230

1.

Which zones are producing?

2.

How much production is each zone contributing?

3.

Was the fracture treatment successful?

WHY DO OPERATORS COMPLETE MULTIPLE ZONES SIMULTANEOUSLY? Limited entry completions are more effective than unlimited entry completions in treating large intervals.

A comfort factor with 3-D fracture model predictions of propped height growth is required prior to implementing reduced interval perforating.

COMPLETION RECOMMENDATIONS STAGING OPTIONS Treat all major pay zones separately.

Drain minor pay zones using a propped hydraulic fracture initiated from major pay zone perforations.

Integrate tracers with 3-D model propped height predictions to determine if multiple stage treatments will communicate.

231

MINIFRAC SPINNER WELL Rank zones by % of kh Lithology

Resistivity

Porosity Porosity

Perm

Poisson's

A. ___

B. ___

C. ___

.001

232

0.1

SPINNER INFLOW BY ZONE Which zone took the most of the MiniFrac?

Upper Zones %

Lower Zones % 35%

85%

30% 25% 80% 20% Lower Sand

15%

Upper 2 Sands 75%

10% 5% 0%

70% 5

10 Rate BPM

15

233

COMPLETION RECOMMENDATIONS PERF TECHNIQUES Perforate the minimum interval possible with perfs no more than 2 feet apart in the maximum stress plane.

4 wellbore diameters has been proposed as the maximum perforated interval in deviated wellbores.

In most cases, 45, 60, or 120 degree phasing is optimum, although 120 has the advantage of providing fewer entry points.

Zero degree and 180 degree phasing have been used with success in some areas

180 degree phasing is preferred when perfs can be oriented in the direction of the maximum horizontal stress.

234

EXERCISE: PERF AND STAGE SELECTION

The vertical stress and the wellbore are not parallel.

Use the stress profile and permeability log on the following pages.

Determine: 1. Which zones are permeable and productive 2. Perforation Strategy A. Length of perforation interval B. Phasing of perforations 3. Number of stages for fracture treatment

235

SPRINGER SAND STRESS PROFILE

18400

18500

18600

17000

236

18000

19000

20000

SPRINGER SAND PERMEABILITY GR/Cal

Lithology

Rt

Perm

Porosity

18400

18500

18600

237

OPTIMIZATION WORKSHEET SPRINGER SAND EXERCISE Perforation Interval

238

Frac Stage Number

PERFORMANCE COMPARISON Optimized Well VS Two Nearest Offsets

FIRST 9 MONTHS OF PRODUCTION Net Revenue

$7.7 million

Production History

17.9 mmcfpd

Initial Reservoir Pressure Feet of Gross Pay Average Daily Production (mmcf) 9 Month Net Revenue*

Optimized Well 13,400 171 17.9 $7,736,064

Offset A 14,500 131 2.8 $1,101,798

Offset B 16,000 130 2.8 $1,339,716

*Assumes $2.00/MCF and 80% NRI

239

SPRINGER SAND CASE STUDY

Offset wells completed all major pay sands in one stage

Optimized well used permeability and stress profiles to help design the treatment .

Treatment was conducted in three stages with a maximum of 10 feet of perforations per stage.

Production was increased 5 fold per foot of gross interval compared to the two offsets.

240

COMPLETION OPTIMIZATION

Reserve recovery can be increased substantially by selectively completing multiple zones.

The optimum completion strategy can be determined from the in-situ stress and permeability profiles obtained economically from readily available data.

241

ORIGINAL TREATMENT RESULTS Top perfs ineffectively treated

242

SUCCESSFUL REFRAC TREATMENT

243

RESULTS IMPROVE AFTER REFRAC Increased production and sharply reduced decline

244

SELECTIVE COMPLETIONS

Demonstrating Increased Recoverable Reserves

Ely

1000+ treatments in a wide variety of formations

Schubarth

Moxa Arch Frontier- 25% More Production

Stadulis

Red Fork/Canyon SS

Kubelka

Cotton Valley- Dramatic Production Increases

Mack Energy One zone producing 4 X as much as 2 zones South Texas

Wilcox - $8 Million more recoverable reserves

Knowles

Springer - 5 X the production per foot of pay

Barba

Permian Sand - 41K BO Increase of EUR

Barba & Praznik

Cotton Valley - Avg. Production 55% Higher Over 21 Months

245

246

CEMENT INTEGRITY

CONSULTANTS SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 Sage Brush RD YUKON, OK 73099 405 324-5828 FAX 324-2360 [email protected]

1

NEED FOR CEMENT INTEGRITY A. PREVENT PRODUCTION OF UNWANTED FLUIDS B. INCREASE TREATMENT EFFECTIVNESS C. CASING PROTECTION D. CHECK SQUEEZE EFFECTIVNESS

STEPS FOR OBTAINING USEFUL INFORMATION

A. PROPER EQUIPMENT SELECTION AND CALIBRATION B. QUALITY CONTROL INCLUDING MICRO ANNULUS CHECK C. CORRECT INTERPRETATION - USE VDL FIRST ON CBL

2

CEMENT BOND VARIABLE DENSITY LOG

3

CBL THEORY

Formation CBL

Casing

Cement

CBL PRINCIPLE The Cement Bond Log (CBL) measures the changes that occur to a sound wave that has travelled through the casing, cement and formation. The sound wave is emitted by the tool itself. The principle changes (attenuation) occurring to the sound signal are to its amplitude or "strength" and the detected travel time.

4

CBL PRINCIPLES NO CEMENT

E3 E1

T 3'

5'

Mud

R R

E2

GOOD MUD REMOVAL

Cement

T 5'

3' R

E1 E3 E2

R

Free Pipe (no cement)

-

No attenuation of sound

Some Cement (poor mud removal)

-

Partially attenuates sound

Good Cement (good mud removal)

-

Attenuates sound

5

CBL AMPLITUDE AND TRANSIT TIME Amplitude Poor Mud Removal E1

Time

Transmitter Firing

Good Mud Removal

E3 Amplitude

E1 TT

Detection Level Time CBL Time Window

E2

6

TRANSIT TIME MEASUREMENT Amplitude Detection Level E1

Time Transmitter Firing

Transit Time (tt)

CYCLE STRETCH E3

E1

}

Free Pipe

T0 Detection Level

Bonded Pipe

}

T0

E1

E2 E3 E2

Specific Time Stretch

CYCLE SKIPPING First Arrival Time at Receiver

Detection Level

Skipped Cycle

TT(µ µS) = 3FT X 57(µ µS/FT) + (CASING ID - TOOL OD)(FT) X FLUID SLOWNESS (µ µS/FT)

7

QUALITY CONTROL ISSUES TYPICAL CBL TOOL 1. TRANSMITTER - RECEIVER SPACING 2. SONDE CENTRALIZATION

Casing Cement Formation

3' Receiver - Amplitude (Pipe) Travel Time 5' Receiver - Seismic Spectrum/VDL MSG/Wavetrain

Centralizer

8

SONIC WAVE PATHS Casing Cement

Transmitter Formation 5'

Receiver Mud

Transmitter Pulse

Signal at Receiver

Mud

Casing

Cement

Formation E1 Composite Time

9

PRINCIPLE OF VDL Amplitude mV

Transmitter

Casing Arrivals

Formation Arrivals

Mud Arrivals

E1 time (µ (µ sec)

The entire composite waveform at the 5' receiver is converted into the Variable Density Log or VDL. With the E1 detection, strong positive signals appear as dark bands; strong negative signals are bright white and intermediate strength are various shades of gray. The 5' receiver is used for the VDL because it has the best formation to casing signal ratio.

10

GAMMA RAY

VARIABLE DENSITY

WAVEFORM

11

TYPICAL CEMENT BOND LOG Transit Time (µ µ sec) 400

200

0

Gamma Ray 0

12

100

3-Foot Receiver Amplitude (millivolts) Good Bond Fair Bond

100

Amplitude (millivolts) 0

5-Foot Receiver

20 200

VDL (µ µsec) 1200

CEMENT BOND TOOL DESCRIPTIONS SINGLE AND DUAL RECEIVERS

T/R OD(in) SACING BASELINE GATING (ft)

COMPANY

MODEL

ATLAS (MCCULLOUGH)

DRB SRB*

3 3/8 1 3/4

3, 5 5

E1 E1

HLS

CBL-(G) CBL-271 CBL-304* CBL-305 CBL-307*

3 1/4 3 3/8 2 1/8 3 5/8 3 1/2

3, 5 3, 5 4 3, 5 4

E2 LIGHT E2 E1 E1 E1

SLT-M

3 3/8, 3 5/8 1 11/16, 2 1/8

3, 5 3, 5 3, 5 3, 5

E1 E1

SCHLUMBERGER

WEDGE

SLT-J

DUAL RECEIVER CBL HIGH TEMP CBL*

3 1/2 2, 2 1/4

3, 5 3, 5

E2 E2

13

SUMMARY OF QUALITATIVE INTERPRETATION GUIDLINES

CEMENT CONDITION

AMPLITUDE SINGLE RECEIVER

VDL

No mud removal

High

∆T at baseline

Casing arrivals (bright parallel lines)

Complete mud removal

Low

Greater than ∆T at baseline

Varing formation arrivals

Mud removed on pipe but not formation and/or acoustically weak formation

Low

∆T at baseline

Weak to no signals

Channeling* (Partial mud removal)

Medium

∆T at baseline

Generally both casing and formation arrivals

Micro annulus

Medium to high

∆T at baseline

Generally both casing and formation arrivals

Micro annulus log run under pressure

Low (lower than above)

∆T at baseline

Generally formation arrivals only (depends on amount of pressure applied)

Fast formation

High to medium

Less than ∆T at baseline (sometimes)

Varing formation arrivals. May appear like casing arrivals

Tool off center mud not removed

Low

Less than ∆T at baseline (sometimes)

Casing arrivals possibly lighter in color

Tool off center

Verify by checking amplitude repeatability (Both main log and repeat should be identical)

*NOTE: Channeling will not change values under pressure

14

FREE PIPE Transit Time

3-Foot Receiver Amplitude (millivolts)

(µ µ sec) 400

200

0

Gamma Ray 0

100

5-Foot Receiver 100

VDL (µ µsec)

Amplitude (millivolts) 20 200

0

0

1200

Signature 200 400 600 800 1000

Casing Travel Time EXERCISE: CBL TRANSMITTER RECEIVER SPACING DETERMINE THE SPACING FOR: THE AMPLITUDE CURVE ___________ THE VARIABLE DENSITY ___________ WHAT IS THE BASELINE TRAVEL TIME? ___________

15

GOOD MUD REMOVAL BETWEEN THE CASING AND FORMATION Signature 0

200 400 600 800 1000

Casing Travel Time

Transit Time

3-Foot Receiver Amplitude (millivolts)

(µ µ sec) 400

200

0

Gamma Ray 0

16

100

5-Foot Receiver 100

VDL (µ µsec)

Amplitude (millivolts) 0

20 200

1200

NO FORMATION BOND OR POOR ACOUSTIC TRANSMITTER Signature 0

200

400

600

800

1000

Casing Travel Time

Whenever good mud removal exists, the pipe portion of the composite signal will have a low amplitude. If there is little or no mud removal on the formation or if the formation is a poor acoustic transmitter, that portion of the signal will be reduced. Hence, the VDL signal will be light in color. Unconsolidated formations, shales and fractured formations will often be poor acoustic transmitters. Gulf Coast (High Porosity)

Hard Rock (Low Porosity)

17

EXERCISE: COMMUNICATION PATHS

POOR MUD REMOVAL

POOR MUD REMOVAL

VERTICAL PERMEABILITY IN THE FORMATION

Possible paths through which communication may occur

WHICH PATH CAN BE DETECTED BY USING A CEMENT BOND LOG? A __________

18

B __________

C __________

CHANNELED CEMENT EXERCISE Variable Density

In the case of channeling, a portion of the casing at the channel behaves like free pipe. That is, it has a high E 1 and the characteristic straight lines on the VDL. The remainder of the circumference of the pipe has a low E1 amplitude and is acoustically coupled to the rocks. Hence it is characterized on the VDL by a combination of both straight and wavy lines.

USING CBL LOG FIND TWO CHANNELS ON THE LOG AND MARK THEM WITH YOUR HIGHLIGHTER Transit Time (µ µ sec) 400

5-Foot Receiver

3-Foot Receiver Amplitude (mv) 200

0

100

VDL (µ µ sec)

Good Bond Fair Bond

Gamma Ray 0

Amplitude (mv)

100 0

20

200

1200

19

MICRO ANNULUS THE #1 CAUSE OF MISINTERPRETATION

FORMATION

CASING

CEMENT

.001 - .004 inch

VDL (µ µ sec)

Amplitude (mv) 100

200

1200

FORMATION

CEMENT

CASING

0

WHAT ARE THE CAUSES OF A MICRO ANNULUS?

1. ___________________________________________________________________ 2. ___________________________________________________________________ 3. ___________________________________________________________________ 4. ___________________________________________________________________ 5. ___________________________________________________________________ 6. ___________________________________________________________________ 7. ___________________________________________________________________ 8. ___________________________________________________________________ 9. ___________________________________________________________________

20

MICRO ANNULUS Logged with 1000 PSI

Logged with 0 PSI (µ µsec) 400

5-Foot Receiver

3-Foot Receiver Amplitude (mv)

Transit Time 200 0

(µ µsec) 400 100

5-Foot Receiver

200

VDL (µµsec)

0

Gamma Ray 0

3-Foot Receiver Amplitude (mv)

Transit Time

100

VDL (µµsec)

Gamma Ray 100

0

Amplitude (mv) 0

20 200

100

1200

Amplitude (mv) 0

20 200

1200

0 PSI 1000 PSI

21

EXPANSION OF PIPE DIAMETER VS INTERNAL PRESSURE 0.1

Inches

.01

.001

.0001

100

1000 Pressure (psi) Key 1 2 3 4 5 6 7 8 9 10

22

in 2 7/8 5 1/2 4 1/2 5 1/2 7 8 5/8 7 8 5/8 8 5/8 10 3/4

Wt. (lb) 6.4 23.0 11.6 17.0 29.0 36.0 23.0 36.0 32.0 45.5

Note: Curves valid to yield point

10000

23

0.0

200.00

100.00

Gamma Ray

400.00

Transit Time (µ µsec) 20.000

0.0

100.00

Amplitude (millivolts)

0.0

3-Foot Receiver Amplitude (millivolts)

200.00

VDL (µ µsec) 1200

5-Foot Receiver

LOGGED WITH 0 PSI

0.0

200.00

100.00

Gamma Ray

400.00

Transit Time (µ µsec) 20.000

0.0

VDL (µ µsec) 1200

5-Foot Receiver

100.00 200.00

Amplitude (millivolts)

0.0

3-Foot Receiver Amplitude (millivolts)

LOGGED WITH 1500 PSI

EXERCISE: FIND AND MARK THE MICRO ANNULUS

FAST FORMATIONS TYPICAL VELOCITY VALUES Material

Non-porous solids

Anhydrite Calcite Cement (cured) Dolomite Granite Gypsum Limestone Quartz Salt Steel (infinite thickness) Casing

∆t ∆ (µ µsec/ft)

vp (ft/sec)

50.0 49.7 83.3 43.5 50.7 52.6 47.6 52.9 66.6 50.0 57.0

20,000 20,100 12,000 23,000 19,700 19,000 21,000 18,900 15,000 20,000 17,500

Signature 0

200

400

600 800 1000

Variable Density 200

Casing Travel Time

THESE FORMATIONS WILL BE LOW POROSITY LIMESTONES OR DOLOMITES 24

1200

RECOGNIZING FAST FORMATIONS IDENTIFYING RESULTS OF FAST FORMATIONS:

Fast Formation Normal Signal

∆T Level

1. TRAVEL TIME EQUAL TO OR SHORTER THAN BASELINE 2. AMPLITUDES LOW TO HIGH 3. STRONG UNIFORM VDL 4. OPEN HOLE LOGS INDICATING LOW POROSITY

Amplitude Gate Transit Time

3-Foot Receiver Amplitude (millivolts)

(µ µ sec) 400

200

0

Gamma Ray 0

100

Good Bond Fair Bond

100

Amplitude (millivolts) 0

5-Foot Receiver

20 200

VDL (µ µsec) 1200

25

EXERCISE: FAST FORMATIONS ON CBL FIND AND MARK THE AREA(S) OF FAST FORMATION Transit Time (µ µsec) 400.00 200.00

3-Foot Receiver Amplitude (millivolts) 0.0 20.000 Amplitude (millivolts)

Gamma Ray 0.0

100.00

0.0

VDL (µ µsec) 1200 100.00 200.00

Poor Cement-toFormation Bond Highly Fractured Gas?

8000

Minnekahta

Casing E1 Arrival Time

Opeche Shale

Minnelusa 8100

26

5-Foot Receiver

EFFECTS OF A CBL OFF CENTER Amplitude Tool Centered ∆t

Detection Level

Tool Eccentered Time

Transit Time ∆t

Eccentering Effect on ∆t IN FREE PIPE, ECCENTERING CAN BE DETECTED BY TRAVEL LESS THAN BASELINE, WHILE THE VDL SHOWS FREE PIPE.

Tool Eccentered

IN THE ZONE OF INTEREST, ECCENTERING CAN BE DETECTED BY COMPARING THE REPEAT SECTION WITH THE MAIN LOG. WHEN A TOOL IS CENTERED, THEY SHOULD REPEAT EXACTLY. (On the 100 MV Scale) Transit Time (µsec) 400

3-Foot Receiver 200

5-Foot Receiver

Amplitude (mv) 0

100

VDL (µ sec)

Gamma Ray 0

100

Amplitude (mv) 0

ECCENTERING EFFECTS

20 200

1200

∆T BASELINE

27

AMPLITUDE REDUCTION DUE TO TOOL CENTERING EXERCISE: ON THE LOG FIND AND MARK THE PLACES WHERE TOOL ECCENTERING HAS OCCURRED.

Transit Time 400

(µsec)

3-Foot Receiver Amplitude (millivolts)

200

0

5-Foot Receiver

100

Gamma Ray 0

100

Amplitude (millivolts) 0

VDL (µsec)

20 200

Measured Travel Time

Measured Amplitude

Expected Travel Time

28

Expected Amplitude

1200

OTHER FACTORS ON CBL AMPLITUDE The bond index is a function of % bond ONLY IF all of the following conditions are constant all around the casing and up and down the entire interval:

1. No changes in cement compressive strength 2. No changes in cement thickness 3. No cement less than 3/4" thick 4. No cement on the inside of the casing or rough coat on the outside 5. The casing is not in contact with the formation 6. The fluid inside the casing does not change 7. The casing wall thickness does not change 8. There are not formation arrivals in the amplitude gate (fast formation) 9. A transmitter or receiver on the CBL doesn't change sensitivity 10. The CBL tool is well centralized (a 1/4" off center could reduce the signal by 50%) 11. There is no gas contamination of the cement

29

BOND INDEX THEORY THEORETICAL AMPLITUDE RESPONSE IN A CHANNEL

100

Attentuation Rate (%)

80

60

(%)

40

Casing Cement

20 No Cement or Cement Not Bonded 0 0

20

40

60

80

100

Circumference Bonded (%)

BOND INDEX =

30

ATTENUATION in zone of interest (db/ft) ATTENUATION in well cemented zone (db/ft)

CHART FOR FINDING ATTENUATION USED IN COMPUTING BOND INDEX

31

CEMENT BOND LOG INTERPRETATION EXERCISE

GAMMA RAY 0

TT3 (µ µsec)

400

100

FREE PIPE AMPLITUDE IS 70mv ON THIS WELL LOGGED W/ 1500 PSI

200

0 AMPLITUDE - MV 100

TENSION 5000

0

0

C

15000

B

A

32

AMPLITUDE X5

20 200 SPECTRUM 1200

PULSE ECHO TOOL (PET) HALLIBURTON LOGGING 0

GR API

100

4.0

M DIA

6.0

150

FLUID T.T.

8000 CS-G -2000 CIRCUMFERENTIAL 0.0 DEV (DEG) 30.0 -----------------------------------BOND 0 RB (DEG) 720 8000 8000

250

CSMN CSMX

-2000 -2000

LOGGED WITH 1500 PSI

C

15000

B

A

33

POSSIBLE INTERPRETATION PROBLEMS EXERCISE: FILL IN THE SOLUTIONS Micro annulus - A very small gap between the cement and casing Symptom Causes amplitutde to increase, attenuation to decrease (looks like bad bond) but will isolate fluids Cause Cement contraction or hydrostatic head reduction Solution

Eccentering - Tool becomes eccentered in the casing Symptom Bond looks better than it should (transit time too fast) Cause Not enough centralizers on tool Solution

Thin cement (less than 3/4") Symptom Bond looks worse than true Cause Ex centered casing or tight hole Solution

34

POSSIBLE INTERPRETATION PROBLEMS EXERCISE: FILL IN THE SOLUTIONS Fast formation Symptom Bond looks bad or erratic, transit time too fast Cause Rock transit time faster than casing, amplitude, attenuation invalid Solution

Cement on inside of pipe Symptom Bond looks good, transit time and tension erratic Cause No pipe trip made Solution

Green cement - Cement not completely set Symptom Bond looks poor, but formation arrivals visable Cause Cement retarded or not enough WOC to completely set Solution

35

SUMMARY OF LOG INTERPRETATION Cement Bond Logs (CBL) 1. Travel Time Curve - Single receiver travel time used to determine eccentering or fast formations. Base line for a given tool and casing size. 2. Amplitude Curve (not a percent) a. Very low amplitude indicates good mud removal b. Very high amplitude indicates poor mud removal or free pipe c. A well centered tool will repeat very closely d. An amplified amplitude curve is a more sensitive scale 3. Variable Density Display (MSG, etc.) a. Most reliable information on CBL b. Pipe signals first to arrive are characterized by straight lines c. Formation signals arrive later and are characterized by changes in travel time (wiggly lines) d. Fast formation signals may be straight but slightly different in character to casing signals and usually can be seen shifting to the left on the VDL 4. All 3 pieces of information must be used for a proper interpretation. Was it run under pressure? 5. A channel is a problem only if it does not isolate

CONSIDERATIONS FOR A SQUEEZE DETERMINATION 1. General condition of the cement a. Do channels exist? b. Do channels connect what we are trying to isolate? c. Is cement low compressive strength (mud contaminated)? d. Is cement gas cut? 2. Where are the zones of interest? 3. What is the relative permeability and porosity of the zones to isolate. Which way will cement go if squeezed? 4. What kind of stimulation is the well going to require?

36

QUICK GUIDELINES FOR CEMENT BOND LOGS Equipment Selection 1. Use 3" or larger tool when casing sizes allow 2. The transmitter-receiver spacing for the amplitude measurement must be 3' and 5' for the variable density. 3. When deviation problems, fluid changes or fast formations are expected, a compensated tool would be preferred. 4. When casing sizes are larger than 8 5/8", then the Segmented Bond Tool would be preferred.

Operating Procedures 1. Be prepared to rerun the log under pressure (eliminate micro annulus effect). 2. Run with sufficient centralizers to prevent off-center problems. Check travel time versus amplitude in free pipe and exact repeatability. 3. Run a minimum of 200' in free pipe when available. 4. Run minimum of 200' of repeat section over the zone of interest. (May not be the bottom 200') 5. If cycle skipping occurs above 4 millivolts, slow down logging speed. If necessary, replace the equipment. 6. A hole full of fluid would be preferred. A CBL tool will not operate with gas percolating in the fluid. 7. Record cement information, tool sizes and centralizers, casing info (DV Tool), etc. on the heading of the log.

Interpretation 1. Check 3' and 5' spacings in free pipe. 2. Confirm exact repeatability in the zone of interest (at the same pressure). Confirm no travel times shorter than baseline in free pipe. 4. Eliminate micro annulus by looking for changes in the amplitude curve when re-run under pressure. Any amplitude changes indicate a micro annulus (good cement)! 5. If the amplitude has not changed, it is a channel. 6. Obtain information to determine when isolation is needed. Open hole logs are the best source. If the channel exists across two areas to be isolated, this is a cement problem. 7. Use travel time curve and comparison of the variable density in free pipe to detect fast formations. These will often exhibit high amplitudes, but they are considered to be good cement. 8. Use the amplitude or attenuation curves as a confirmation of interpretation using the above methods.

37

CEMENT INTEGRITY EVALUATION TOOL SYSTEM COMPARISON CBL’S1

COMPENSATED CBL (CBT,BAL,BAS,RBT)1,2

PAD TOOL (SBT)1,2

CENTRALIZATION

Very critical Can tolerate up to .1"

Critical Can tolerate up to .3"

Not a factor unless lose contact (high deviations)

BOREHOLE FLUID EFFECTS

Minimal unless gas cut

Not affected unless gas cut

Negligible- unless gas cut

MICRO ANNULUS

Severely affected

Severely affected

Severely affected

FAST FORMATIONS

Severely affected

Moderately affected minimized by closer T/R spacing Approx 1'

Moderately affected minimized by closer T/R spacing Approx 5"

CHANNEL DETECTION

Detection difficult due to circumferential averaging

Difficult to detect due to circumferential averaging

More easily identified over 60o segments

GAS CUT CEMENT

Minimal has to be severe

Minimal has to be severe

Minimal has to be severe

RADIAL RESOLUTION

Average over 360o

Average over 360o

Average of 60o

OPERATIONAL SENSITIVITY

Very sensitive a lot of quality control required

Less quality control required

Different quality control issues (gating)

1

Acoustic Log 2 New Generation Log

38

CEMENT INTEGRITY EVALUATION TOOL SYSTEM COMPARISON USI2,3 CAST-V

RADIAL/SECTOR BOND TOOLS1,2

ULTRASONIC (CET, PET)2,3

CENTRALIZATION

Critical can tolerate up to 0.25"

Less affected Lighter, shorter and easier to centralize. Can tolerate up to 1mm/in of casing ID

BOREHOLE FLUID EFFECTS

Minimal unless gas cut

Severely affected by Mud (13PPG water based mud) 11PPG oil based. Hvy mud kits avail.

16 PPG? Any Fluid not as affected by gas

MICRO ANNULUS

Severely affected

Less affected exaggerated if gas in micro annulus

Less

FAST FORMATIONS

Moderately affected T/R spacing 2' Use 8 T-T curves

Minimal effect PET less affected than CET but can be verified w/gas flags or VDL

None?

CHANNEL DETECTION

More easily identified over 450 segment

More easily identifiable than Pad tool segments (CET, PET) - 45o

50 segments 100 Meas.

GAS CUT CEMENT

Minimal has to be severe

Severely affected - can be detected when used with CBL Cement Scan (CET) clarifies interpretation

RADIAL RESOLUTION

Average over 450 minimum

8 single point calculations (45o) on CET, PET - 72 single point calculations

OPERATIONAL SENSITIVITY

Very sensitive quality control required

Gate setting

(50) on USI 3.60 CAST-V

1

Acoustic Log New Generation Log 3 Ultrasonic Log 2

39

40

NEW GENERATION CEMENT INTEGRITY LOGS

41

BOREHOLE COMPENSATED CBL LOGS

CEMENT BOND TOOL (CBT) - SWS RATIO BOND TOOL (RBT) - HLS BOND ATTENUATION LOG (BAL) - ATLAS

BOREHOLE COMPENSATED ADVANTAGES ELIMINATES FLUID EFFECTS TRANSDUCER SENSITIVITY TEMPERATURE AND PRESSURE EFFECTS

MINIMIZES SONDE ECCENTRALIZATION FAST FORMATION ARRIVALS

42

COMPENSATED CBL TOOLS

T1

T1 Attenuation 1 =

R1 R2

R1

Attenuation 2 =

20 Log

A12

D

A11

20 Log

A21

D

A22

D

R3 R2

T2

Attenuation 3 =

10 Log

A12 A21

D

A11A22

T2

WHAT IS THE SPACING D? _____

43

CBT LOG CURVES

AMPLITUDE (NCBL, DCBL) Indicates strength of E1 signal at receiver Good cement: low amplitudes Free pipe: high amplitudes Marginal mud removal or channeling: medium amplitude

ATTENUATION (DATN, ATTN, NATN, SATN) Computed from ratio of the amplitudes Good cement: high attenuations Free pipe: low (zero) attenuation

BOND INDEX (BI, NBI) Computed % bond

VARIABLE DENSITY LOG (VDL) Used to determine if cement to formation acoustic exists Good mud removal: gray to formations, arrivals will follow the gamma ray Free pipe: solid dark E1, chevron patterns in collars, no formation arrivals

TRANSIT TIME Used as a quality check to make sure tool is centralized Should remain constant unless tool is eccentered Helps detect fast formations

44

ILLUSTRATING CBT CURVES

80 % BOND INDEX NATN-2.4 ATTENUATION 2.4, RECEIVER TRANSIT TIME

GAMMA RAY

BOND INDEX FROM DATN

DATN DISCRIMINATED ATTENUATION

45

CBT LOG EXERCISE: DETERMINE THE MAXIMUM ATTENUATION ON THIS LOG. IS THAT AMOUNT OF ATTENUATION ENOUGH FOR ISOLATION?

GR (GAP1) 0

TT1 (US)

300

100 NATN (DB/F) 200

20

300

46

0 DATN (DB/F)

TT2 (US) 200

20

0 200

VDL (µ µs) 1200

BOND ATTENUATION LOG EXERCISE: FIND THE ATTENUATION RATE IN FREE PIPE ________ WHY IS THE ATTENUATION RATE SO LOW AT 8442-50? GAMMA RAY

NORMAL ATTENUATION

API

._._._._._._._DB/FT ._._._._._._._._._

0

100

20

TRAVEL TIME ms 290

190

0

0

PEAK AMPLITUDE MV 100

_._._._._._._._x 5 .AMPLIFIED 0

MV

VDL ( µsec)

10

200

1200

FAST FORMATION

47

THE NEED FOR NON AVERAGING TOOLS

THESE TWO CEMENT CONDITIONS WOULD LOOK THE SAME ON AN AMPLITUDE OR AN ATTENUATION CURVE. HOW CAN YOU TELL THE DIFFERENCE ON A VDL ?

48

PAD TYPE CEMENT DEVICE SEGMENTED BOND TOOL - ATLAS

THIS TOOL AVERAGES OVER 60 DEGREES RATHER THAN 360

49

SEGMENTED BOND TOOL

PRIMARY MINIMUM ATTENUATION

AVERAGE ATTENUATION

20.00 100

API

50

0.0

AMPLITUDE

0.00

100.00

MV

VARIABLE ATTENUATION

CC

ATTENUATION DB 0 |___|___|___| 21

1200 US

DB

0

VARIABLE DENSITY

0.0 200

20.0

GAMMA RAY

SEGMENTED ARRAY

2.8

8.4 5.5

11.2 0

TOOL AZIMUTH DEGREES

360

SEGMENTED BOND TOOL IN A TEST WELL MINIMUM ATTENUATION 20.0

0.0 200 DB/FT

VARIABLE ATTENUATION

VARIABLE DENSITY

DB/FT 6.0

0

300

CPS

0 |___|___|___| 21

12.7

100 9.3

MV

16.0 0

AMPLITUDE x 5

GAMMA RAY

ATTENUATION

1200 US

AMPLITUDE 0

CC

0

TOOL AZIMUTH

360

DEGREES

20 MV

A

B

C

EXERCISE: FIND THE MINIMUM ATTENUATION RATE FOR EACH CHANNEL. A _____ B _____ C _____ Which channel appears to have the largest circumference?

A

B

C

51

RADIAL AND SECTOR BOND TOOLS WEDGE WIRELINE AND COMPUTULOG

450

Cement Bond Log

MONOPOLE & SECTOR TRANSMITTERS

15 deg chan. 24.0"

450

36.0"

8 Radial Amplitudes

SECTOR RECEIVERS 60.0" 3 FOOT RECEIVER

Cement Maps 5 FOOT RECEIVER

52

EPA TEST WELL COMPARISON CET PET AND RADIAL BOND TOOL DISPLAYS O

THESE MAN MADE CHANNELS ARE 30 CIRCUMFERENCE OR LARGER

53

SECTOR BOND TOOL LOG

54

ULTRASONIC CEMENT DEVICES

CET, PET AND USI

55

ULTRASONIC CEMENT DEVICES CEMENT EVALUATION TOOL (CET) SWS PULSE ECHO TOOL (PET) HLS

Casing Ultrasonic Transducer Cement Formation

Transmit Mode

Reference Transducer

Receive Mode

56

RADIAL INVESTIGATION

Easier Channel Detection

DIAMETER AND THICKNESS AVAILABLE

2 3

1

8

CET 4

5

Mud filled Channel

7

6

Casing Inspection Capabilities

Thickness

Radius Cement

Casing

57

ACOUSTIC IMPEDANCE

Z1 = ρ1υ1 Incident

Z2 = ρ2υ2 Transmitted

COMPRESSIVE STRENGTH

Reflected

ACOUSTIC IMPEDANCE

58

TYPICAL ACOUSTIC IMPEDANCES OF SOME OIL WELL MATERIALS

Z = Sound Velocity x Density 6

2

Unit: 10 kg/m -sec = Mrayl (Mega-Rayleigh)

Zgas

=

0.1

Zwater

=

1.5

Zmud

=

2.4 (density = 1.6 gm/cc)

Zslurry

=

2.6 (C.S. = 0 psi)

Zcement

=

5.0 (C.S. ≅ 4000 psi)

Zsandstone =

17.0 (φ φ = 30%)

Zsteel

40

>

59

CEMENT INFORMATION CSMX (PSI) 10000

0.0

CSMN (PSI) 10000

0.0

CIRCUMFERENTIAL CEMENT MAP

WWM 0.0

2.0

Maxiumm Compressive Strength

WWM

Minimum Compressive Strength

*WWM (WINDOW WINDOW MEAN) - Represents the average acoustic impedance seen by the tool. It is an indicator of cement quality. CIRCUMFERENTIAL CEMENT MAP - Pictorial representaion (360 degrees ) of cement quality. MINIMUM & MAXIMUM COMPRESSIVE STRENGTH - Gives the range of compressive strength in PSI of the cement behind the casing. *FORMATION FLAGS / GAS FLAGS - Formation flags indicate energy reflections that are seen at same time interval that signals from the casing arrive. Gas flags indicate free gas behind the casing. *Only on Schlumberger's Cement Evaluation Log

60

HOLE DIRECTION INFORMATION DEVI (DEG) 0.0

20.0

RB (DEG) 0.0

360.0

CIRCUMFERENTIAL CEMENT MAP

Deviation

Relative Bearing

DEVIATION - Number of degrees from verticle RELATIVE BEARING - This is the direction recorded with reference to the first (no. 1) transducer.

61

CASING INFORMATION 0.0

OVAL (IN) 0.5000 CCLU (IN)

-0.950

0.0500

ECCE (IN) 0.0

0.5000

CALU (IN) 3.5000

4.5000

Eccentering

Mean Diameter

Ovality

Collars

ECCENTRICITY - Measures the amount of tool eccentering. ULTRASONIC CALIPER - Measures mean diameter of the casing. FLUID VELOCITY (FVEL) - A ninth transduces fires at a fixed plate, FVEL is derived.

62

USES OF ULTRASONIC CALIPERS

CET or PET CASING

Dmax - Dmin = OVALITY DIAmin

DIAmax

CET or PET

CASING

ECCENTRICITY

R1

R1 =/ R2

CET or PET R2

CASING

63

USI TOOL DIAGRAM

TELEMETRY SYSTEM AND ELECTRONIC CARTRIDGE

DOWNHOLE FLUID PROPERTIES PRINCIPLE

Target plate

Fluid properties position Sensor unit

SONDE

Compensating device

7 in. Casing

Motor assembly Rotating electrical connection Centralizer Rotating shaft

Measurement position Target plate

Sensor unit

Rotating seal

Interchangeable SUB Sensor 7.5 rps

64

7 in. Casing

ULTRASONIC IMAGING TOOL

TOOL: A transducer similar to the CET rotates 360 degrees pulsing the casing with a high frequency signal and receiving it.

THEORY: Using downhole processing the mud impedance and velocity are measured. Using the frequency and time of received signal, casing thickness and acoustic impedance of material behind pipe is determined.

ADVANTAGES OVER CET: 100% casing-cement evaluated T^3 processing eliminates fast formation concerns

65

NEW GENERATION LOGS TOOL DESCRIPTIONS

TYPE

COMPANY

MODEL

Compensated

Schlumberger

CBT-E 2 3/4 CBT-EA (HiTemp/Press)

T1-T2 = 5.8' T1-RN = .8, 2.4, 3.4

Western Atlas

BAL

2 3/4

T1-T2 = 6' T1-RN = 2.5, 3.5, 5

HLS

CCAT

3 3/8

T1-T2 = 6' T1-RN = 2.5, 3.5, 5

Pad (Segmented)

Western Atlas

SBT

3 3/8 3 5/8 w/GR

Limited to 4 1/2" 16" casing ID

Ultrasonic

HLS

PET

3 3/8

9 receivers, single helix

Schlumberger

CET

3 3/8

9 receivers, double helix

Schlumberger

USI

3 3/8

3 1/2", 4 1/2", 6 1/2", 8 1/2", and 11" rotary subs

Wedge

RAL

3 1/8

T-R = 3', 5' Radial Receivers 2'

Computalog

SSB

2 3/4

T-R = 3', 5' Radial Transmitters and Receivers 2'

Radial/Sector Bond

OD (in)

T/R SPACINGS (ft)

All tools are rated to a maximum of 350o F and 20,000 psi.

66

LOG EXAMPLES OF ULTRASONIC CEMENT LOGS AND CEMENT BOND LOGS

67

GOOD MUD REMOVAL

Transit Time (µ µsec) 400

3-Foot Receiver Amplitude (millivolts)

200

0

Gamma Ray API Units 0

100

Good Bond Fair Bond

5-Foot Receiver

100

Amplitude (millivolts) 0

20 200

Amplitude Travel Time

11400

Gamma Ray Variable Density Casing Collar

68

VDL (µ µsec) 1200

GOOD MUD REMOVAL EXERCISE: Find the average of the minimum compressive strength over the interval where the CBL appeared to be channeled. DEVI (DEG)

GAMMA RAY 0.0

0.0

150.0

○

20.000 ○

○

○

○

○

RB (DEG) ○ ○ ○ ○

○

0.0

OVAL (IN) 0.0 ○

0.0

○

○

○

○

○

ECCE (IN) ○ ○ ○ ○

○

○

○

○

360.00

CSMX (PSI) 0.5000 ○

○

○

○

○

10000

0.5000

CIRCUMFERENTIAL CEMENT MAP

0.0

CSMN (PSI)

○

CALU (IN) 3.5000

○

10000

0.0

WWM 4.5000

0.0

2.0

RELATIVE BEARING MAXIMUN COMPRESSIVE STRENGTH

AVERAGE REFLECTIVE ENERGY GAMMA RAY

ECCENTERING

MINIMUIM COMPRESSIVE STRENGTH

CASING OVALITY

69

POOR QUALITY CEMENT BOND LOG EXERCISE: Determine why the amplitude curve is so misleading. What information is missing?_____________________ What is the tool spacing? ____

Gamma Ray QUALITATIVE ONLY

Amplitude (millivolts) 0

70

100 200

VDL (µ µsec) 1200

GOOD QUALITY CEMENT BOND LOG 3-Foot Receiver Amplitude (millivolts)

Transit Time 400

(µsec)

200

0

5-Foot Receiver

100

Gamma Ray 0

100

Amplitude (millivolts) 0

20 200

VDL (µ µsec) 1200

71

NO CEMENT DEVI (DEG)

GAMMA RAY 0.0

150.0

0.0

20.000

RB (DEG) 0.0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5000

10000

0.5000

10000

72

0.0

CSMN (PSI)

CALU (IN) 3.5000

360.00

CSMX (PSI)

4.5000

0.0

WWM 0.0

2.0

CIRCUMFERENTIAL CEMENT MAP

CHANNELING EXERCISE: Find and mark two channels (Hint: one is not at 3974-4058) 3-Foot Receiver Amplitude (millivolts)

Transit Time 400

(µsec)

200

0

100 Good Bond Fair Bond

Gamma Ray 0

5-Foot Receiver

100

Amplitude (millivolts) 0

20 200

VDL (µ µsec) 1200

4000

4100

73

CHANNELING DEVI (DEG)

GAMMA RAY 0.0

0.0

150.0

20.000

RB (DEG) 0.0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5000

10000

0.0

CIRCUMFERENTIAL CEMENT MAP

CSMN (PSI) 0.5000

10000

CALU (IN) 3.5000

360.00

CSMX (PSI) 0.0

WWM

4.5000

0.0

2.0

4000

A 4100

Relative Bearing

B C A - No Porosity B - Oil C - Water 74

CHANNELING EXERCISE: On the log below, find and mark all possible channels

Gamma Ray Qualitative only

Amplitude (millivolts) 0

100

VDL (µ µsec) 200

1200

75

THE NEED FOR A 3 FT. OR LESS TRANSMITTER - RECEIVER SPACING 50

45

Using 4 ft. spacing instead of 3 ft. spacing, the amplitude measurement goes from 10 MV to 5 MV (1/2 the resolution)

40

35

Log Amplitude Millivolts

30

25

5 db/ft Attenuation

20

6 db/ft Attenuation 15 6' 5' 4'

10

3'

5 1 MV 1

2

3

4

5

6

7

8

9

10 11

12

13 14

SOUND ATTENUATION (db/ft) Amplitude response of CBL versus attenuation for different Transmitter - Receiver spacings in 7" Casing

76

15

CHANNELING EXERCISE: Find and mark all possible channels. 3-Foot Receiver Amplitude (millivolts)

Transit Time (µsec) 400

200

0

Gamma Ray 0

100

Good Bond Fair Bond

5-Foot Receiver

100

Amplitude (millivolts) 0

20 200

VDL (µ µsec) 1200

77

CHANNELING EXERCISE: Find and mark all mud channels. DEVI (DEG) 0.0

20.000

RB (DEG) 0.0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5000

10000

0.5000

0.0

10000

0.0

WWM 4.5000

0.0

A 3500

B

Hole Deviation

Relative Bearing 3600

78

720.00

CSMN (PSI)

CALU (IN) 3.5000

CSMX (PSI)

2.0

CIRCUMFERENTIAL CEMENT MAP

CONSIDERATIONS FOR A SQUEEZE DETERMINATION 1.

General condition of the mud removal and the cement. A. Do channels exist? B. Do channels connect what needs to be isolated? C. Is cement low compressive strength (mud contaminated)? D. Is cement gas cut?

2.

Relative permeability and porosity of zones to be isolated. Frac gradient of 2 zones needing isolation

3.

What kind of treatment is the well going to require? (ie., frac versus natural completion)

TO SQUEEZE OR NOT TO SQUEEZE 1.

Determine the zones which need isolating

2.

Locate the zones needing isolation from the open hole logs

3.

Determine if channeling exists between the two zones needing isolation

4.

A channel needs squeezing only if it connects what needs isolation! 79

GOOD ISOLATION? Bond Index Gamma Ray 0 320

80

Transit Time

1.0 100 220

-20 -100

Amplified Amplitude Amplitude

0 20 100

TO SQUEEZE OR NOT TO SQUEEZE? WWM

Amplitied Amplitude -10

10

0

Amplitude 0

100 Bond Index

100

10000

Variable Density 200

0

Comp Str Max

2 0

Comp Str Min

1200 10000

C C

Circumferential Cement Map

0

81

CHANNELING OR LOW COMPRESSIVE STRENGTH

3-Foot Receiver Amplitude (millivolts)

Transit Time 400

(µsec)

200

0

Gamma Ray 0

100

5000

OIL WATER

82

RED FORK SAND

100

Amplitude (millivolts) 0

---------

Good Bond Fair Bond

5-Foot Receiver

5100

20 200

VDL (µ µsec) 1200

CHANNELING OR LOW COMPRESSIVE STRENGTH Exercise: Should this Sand be squeezed? If not how could you complete it to minimize or prevent water production? DEVI (DEG) 0

20

RB (DEG) 0 0.0

ECCE (IN)

0.0

0.5

10000

0.5

10000

4.5

0

CALU (IN) 3.5

360

CSMX (PSI)

OVAL (IN)

0

CSMN (PSI) WWM

CIRCUMFERENTIAL CEMENT MAP

0 2

MINIMUM COMPRESSIVE STRENGTH

MAXIMUM COMPRESSIVE STRENGTH

RED FORK SAND

OIL

5100 WATER

83

MICRO ANNULUS (LOSS OF INTIMATE CONTACT WITH CEMENT AND CASING)

CAUSES 1. PRESSURE DIFFERENTIAL PLACED ON CASING A. HOLD PRESSURE ON CEMENT PLUG B. PRESSURE TEST CASING C. STIMULATION (ACIDIZING, FRACTURING, ETC.) 2. DIFFERENT HYDROSTATIC PRESSURES ON CASING A. REPLACE HEAVY FLUIDS WITH LIGHTER FLUIDS B. SWABBING FLUIDS OFF A WELL C. WELL TAKING FLUIDS (LOSS OF HYDROSTATIC) 3. THERMAL EXPANSION / CONTRACTION A. HEAT GENERATED DURING CURING OF CEMENT B. PUMPING FLUIDS COOLER THAN FORMATION (ACIDIZING / FRACTURING) 4. MECHANICAL A. MOVING PIPE AFTER CEMENTING (SETTING SLIPS) B. DRILL PIPE BANGING AGAINST THE CASING (DRILLING DEEPER)

RESULTS: A MICRO ANNULUS CAN EXIST ON EVERY WELL A CBL LOG WILL INDICATE WORSE THAN ACTUAL CONDITIONS

CONCLUSIONS: RE-RUN CBL UNDER PRESSURE AND COMPARE TO SEE IF MICRO ANNULUS EXIST

84

CHANNELING OR MICRO ANNULUS? 3-Foot Receiver Amplitude (millivolts)

Transit Time (µsec)

400

200

0

100

Gamma Ray 0

100

5-Foot Receiver VDL (µ µ sec)

Log Ran Under 0 PSI

Amplitude (milivolts) 0

20 200

1200

7800

7900

85

MICRO ANNULUS EXERCISE On the log below, find and mark all micro annulus and channels.

Transit Time

Amplitude

Microseconds 3' Spacing

Millivolts

400

200

0

Variable Density Microseconds 5' Spacing

100

Log Ran Under 1000 PSI

Gamma Ray API Units 0

Amplified Amplitude

100

0

86

Millivolts

20 200

1200

MICRO ANNULUS EFFECT Exercise: What is the Minimum Compressive Strength in the Micro Annulus. ____________ Is the Channel Confirmed? DEVI (DEG)

GAMMA RAY 0.0

0.0

150.0

0.0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5000

10000

0.5000

10000

CSMX (PSI)

360.00 0.0

CIRCUMFERENTIAL CEMENT MAP

CSMN (PSI)

CALU (IN) 3.5000

20.000

RB (DEG)

0.0

WWM

4.5000

0.0

2.0

7700

7800

7900

87

WRONG INTERPRETATION! DUE TO TOOL ECCENTERING Exercise: Why was this log misinterpreted Transit Time (µsec) 400

DEVI (DEG)

5-Foot Receiver

0.0

200

0

RB (DEG) 0.0

100

10000

Good Bond Fair Bond

100

10000

VDL (µ µ sec) 1200

0.0

10300

10400

10500 10500

88

0.0

WWM

10300

10600

0.0

CSMN (PSI) 200

10400

360

CSMX (PSI)

Gamma Ray 0

20

Amplitude (millivolts)

10600

2.0

CIRCUM CEMENT MAP

FAST FORMATION EXERCISE: Find and mark all the areas affected by fast formations. Highlight areas where the travel time is less than the baseline value. 3-Foot Receiver Amplitude (millivolts)

Transit Time (µsec) 400

200

0

100

0

Gamma Ray 0

Good Bond Fair Bond

5-Foot Receiver

100

Amplitude (millivolts) 20 200

VDL (µ µsec)

1200

4000

Single Receiver Travel Time

4100

89

FAST FORMATION EXERCISE: Does the ultrasonic devices evaluate the cement across the fast formation? What is causing the secondary reflection flags? DEVI (DEG) 0.0

20.000

RB (DEG) 0.0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5000

10000

0.0

CIRCUMFERENTIAL CEMENT MAP

CSMN (PSI) 0.5000

10000

CALU (IN) 3.5000

360.00

CSMX (PSI) 0.0

WWM 4.5000

0.0

2.0

4000

Secondary Reflection Flags

4100

90

FORMATION OR DOUBLE CASING STRING SECONDARY REFLECTIONS

Gates W1W3

W2

Free Pipe W2 High W1

W3 W2 High compared to W1 W1

Good mud removal W2 Low W1

W2 W3 High compared to W1 W1

Secondary reflections W2 High W1

W3 W2 Low compared to W1 W1

X1 X10 Vertical Scale 0 10 20 30 40 50 (µ µsec)

91

CHANNELING? EXERCISE: Find and mark all existing channels. 3-Foot Receiver Amplitude (millivolts)

Transit Time (µsec) 400

200

0

100

0

Gamma Ray 0

92

Good Bond Fair Bond

5-Foot Receiver

100

Amplitude (millivolts) 20 200

VDL (µ µsec) 1200

WARNING: Use the Minimum Strength Curve Not the Map

CHANNELING ON A CET Exercise: Does the minimum compressive strength curve confirm your interpretation of the VDL? ______ Why is the CBL amplitude so optimistic? DEVI (DEG) 0

20

RB (DEG) 0

OVAL (IN) 0.0

ECCE (IN)

0.0

0.5

10000

0.5

10000

0

CIRCUMFERENTIAL CEMENT MAP

CSMN (PSI)

CALU (IN) 3.5

360

CSMX (PSI)

4.5

0

WWM

0 2

12000

12100

12200

93

APPLICATIONS OF NEW GENERATION CEMENT INTEGRITY TOOLS

I. EFECTIVE IDENTIFICATION OF CEMENT PROBLEMS Channel or voids identified easier Contaminated cement identified Reliable squeezes possible Identify need for cement program changes Monitoring the effectiveness of cement program changes

II. COMPLETION DESIGN ASSISTANCE Cement integrity versus treatment design Effectiveness of treatment

III. IDENTIFICATION OF POTENTIAL CASING PROBLEMS Unwanted sizes or weights in the well Potential packer/plug setting problems Indentification of old perforations possible

94

ULTRASONIC CEMENT LOGS W1 Fire Pulse DT

Internal Radius

Resonant Frequency W3

W2

Cement Evaluation Thickness Inner Surface Condition

TOOL: Eight transducers at 45 degrees separation around the tool fire a high frequency pulse at eight points on the casing, The same transducer receives the signal and sends it to the tool for processing.

THEORY: The signal transmitted is the resonance frequency of the casing, therefore it begins to resonate, much like a tuning fork will vibrate if its key is played or sung. In a low acoustic impedance medium (air), the fork will continue to resonate. If a high acoustic impedance medium is placed behind the fork (or casing) the resonance will decay quickly. A resonance measurement is taken in two places (SWS only) and acoustic impedance is derived. Low resonance (W2) means HIGH acoustic impedance.

95

TRANSDUCER RESPONSE CHART 2.0 FREE GAS 1.8

1.6

1.4 LIQUID HYDROCARBONS 1.2 FRESH WATER 1.0 BRINES & MUDS .8 FOAM CEMENTS .6 LIGHT WEIGHT CEMENTS .4 NEAT-HIGHER COMPRESSIVE STRENGTH CEMENTS

.2

0

.2

96

.4

.6

.8

1.0

1.2

1.4

CEMENT EVALUATION TOOL W2 vs W3 (Schlumberger only) W2 = 0.65 W3 = 1.05 FOR FREE PIPE UNNORMALIZED 1.6

1.2

.8

.4

0.0

NORMALIZED 2.5

0.0

.5

1.0

1.5

2.0

2.5

3.0

2.0

1.5

1.0

.5

0.0

97

EFFECTS OF GAS ON CEMENT INTEGRITY LOGS

98

GAS CUT CEMENT CBL vs ULTRASONIC Cross-Plot For Cement Integrity

Free Casing (Gas-filled Annulus)

-2.0

-1.0

Foam Cement

Gas-cut Cement

r) oo P (

0.0

1.0

2.0

Free Casing (Fluid-filled Annulus)

) od o (G

g sin /or h a e r nd gt Inc ng a tren i nd ive S i B s % pres m Co

Size Increasing

Compressive Strength (1000 PSI)

-3.0

Micro Annulus

3.0 4.0

5.0

Increasing CBL (millivolts)

99

TWO STAGE CEMENT JOB? Transit Time

3-Foot Receiver Amplitude (millivolts)

(µ µsec)

400

200

0

100

100 Good Bond Fair Bond

Gamma Ray 0

100

Amplitude (millivolts) 0

5-Foot Receiver

20 200

VDL (µ µsec) 1200

GAS CUT CEMENT DEVI (DEG)

OVAL (IN) 0.0

0.0

0.5000 CCLU (IN)

-.950

20.000 RB (DEG)

0.0 0.5000

360 CSMX (PSI)

10000 ECCE (IN) 0.0

CSMN (PSI)

0.5000

10000

4.5000

0.0

CALU (IN) 3.5000

CIRCUMFERENTIAL CEMENT LOG 0.0 0.0

WWM 2.0

9600

Average Reflective Energy

9700

Gas Flags

101

CEMENT SCAN CSMX

Gamma Ray 0

100

10000

0.0

CSMN 10000

Distribution

Component Mix (%)

0.0

GOOD MUD GAS CUT FREE GAS

102

WHERE IS THE CEMENT CHANNEL ACCORDING TO THE VDL? Amplitude (mv) 0

5-Foot Receiver

200

Amplitude (mv) 0

Transit Time (µ µsec)

400

40

Bond Index (%) 100

200

0 200

VDL (µ µsec) 1200

Tension 10200

Transit Time

10300

103

EXERCISE: IDENTIFY 1. Good Cement

2. Gas Cut Cement

3. Gas Filled Channels

DEVI (DEG) 0.0

20.000 RB (DEG)

0.0

CCLU (IN) -.950

0.5000

360 CSMX (PSI)

10000 ECCE (IN) 0.0

CSMN (PSI)

0.5000

10000

4.5000

0.0

CALU (IN) 3.5000

104

0.0 0.0 WWM 2.0

CIRCUMFERENTIAL CEMENT LOG

DOES THIS CEMENT SCAN CONFIRM YOUR INTERPRETATION? Component Mix (%)

Distribution Map

VDL (µ µsec) 200

1200

Gas Bond Index 10200

Gas-Filled Channel

Mud Gas-Cut Cement

10300

Gas Cut

Good

Good Cement

105

GAS CUT CEMENT ON PET EXERCISE: Find zero on the compressive strength scale. What is the compressive strength at Zone C? ____ 0

GR API

100

4.0

M DIA

6.0

150

FLUID T.T.

8000 CS-G -2000 CIRCUMFERENTIAL 0.0 DEV (DEG) 30.0 -----------------------------------CEMENT MAP 0 RB (DEG) 720 8000 8000

250

C

15000

106

CSMN CSMX

-2000 -2000

LOGGED WITH 1500 PSI

IS THERE GOOD ISOLATION WITH THE FOAM CEMENT? Transit Time

3-Foot Receiver Amplitude (millivolts)

(µ µsec)

400

200

0

5-Foot Receiver 50

Gamma Ray 0

100

VDL (µ µsec)

Amplitude (millivolts) 0

20 200

1200

FOAM CEMENT

TOP TAIL

CLASS H CEMENT

107

FOAM CEMENT DEVI (DEG) 0

RB (DEG) 20

0

0.0

10000

100

0

4.5

4100

TOP TAIL

108

0

CSMN (PSI) 10000

CALU (IN) 3.5

720

CSMX (PSI)

Gamma Ray

WWM

0 2

CIRCUMFERENTIAL CEMENT MAP

109

OVAL (in) 0.5000 CCLU (in) -0.950 0.5000 ECCE (in) 0.0 0.5000 CALU (in) 3.5 4.5000

0.0

4500

4400

RB (deg) CIRCUM CEMENT MAP

OVAL (in) 0.5000 CCLU (in) -0.950 0.5000 ECCE (in) 0.0 0.5000 CALU (in) 3.5 4.5000 0.0

4500

4400

RB (deg) 360.00 CSMX (psi) 10000. 0.0 CSMN (psi) 10000. 0.0 WWM 0.0 2.0

0.0

SQUEEZED W/ 150 SKS AT 4504-05

360.00 CSMX (psi) 10000. 0.0 CSMN (psi) 10000. 0.0 WWM 0.0 2.0

0.0

BEFORE & AFTER SQUEEZE CET CIRCUM CEMENT MAP

USI IN 10 DEGREE CHANNELS (EPA Test Well)

110

ULTRASONIC CEMENT INTEGRITY LOGS A. FIXED TRANSDUCERS 1. Two logs available. a. SWS - Cement Evaluation Log (CET) b. HLS - Pulsed Echo Tool (PET)

2. Based on a focused device with 8 transducers giving azimuthal as well as vertical resolution, compared to averaging from the bond log.

3. Graphic presentation on right hand side shows distribution of cement around the pipe. When white appears look at the compressive strengths. (especially the minimum)

4. Minimum and maximum are both presented, occasionally an average. Of course the minimum being is most important.

5. Gas cut or foam cement: A bond log will show cement and a CET/PET will appear as no cement . This characteristic identifies gas cut cement.

6. On CET (SWS) the average reflective energy curve (WWM) will have a 0-2 scale left to right. a. Usually reads 1 in free pipe. b. Exhibits a "nervousness" in free gas cut cement. c. May read 1 or 1.5 with gas behind the pipe. B. ROTATING TRANSDUCERS 1. USI - Schlumberger 2. Reading every 5O (9 times that of a CET or PET) 3. Casing inspection capability 4. Indicates free gas but not gas cut cement

111

CASED HOLE INTERPRETATION EXERCISE

FIND: COMPRESSIVE STRENGTH Min. Max Good Cement Channeled Cement* Mud Contaminated Cement Gas Cut Cement

_____ _____ _____ _____

DETERMINE: Why each well requires a squeeze? Does well require squeeze? If so where are the perfs recommended? What volume is recomended

*Mark extent of channel

112

_____ _____ _____ _____

EXERCISE 1 CBL Transit Time (µ µsec) 400.00 200.00

3-Foot Receiver

CCL

Amplitude (mv) 0.0 20.00

-18.00

0.0

CET 5-Foot Receiver

DEVI (deg) 20.000 RB (deg) 0.0 360.00 CSMX (psi) 10000 0.0 CSMN (psi) 10000 0.0 WWM 0.0 2.0

OVAL (in) 0.0

0.0

0.5000 CCLU (in)

1.0000

Gamma Ray 100.00

0.0

VDL (µ µsec) Amplitude (mv) 1200 100.00 200.00

-0.950

0.5000 OVAL (in) 0.0 0.5000 OVAL (in) 3.5000 4.5000

CIRCUM CEMENT MAP

10400 10400

10500

10500

10600

10600

10700

10700

10800

10800

113

EXERCISE 2

0.0 -0.950 0.0 3.5000

OVAL (in) CCLU (in) ECCE (in) CALU (in)

0.5000 0.5000 0.5000 4.5000

0.0

10000

0.0

DEVI (deg) RB (deg) CSMX (psi) CSMN (psi) WWM

20.000

0.0

360.00

2.0

0.0

CIRCUMFERENTIAL CEMENT MAP

3-Foot Receiver

0.0 Amplitude (mv)

Transit Time (µ µsec) 400.00 200.00 1.0000

100.00

0.0

Amplitude (mv)

Gamma Ray

CCL -19.00

0.0

4000

0.0

10000

4000

4100

4200

4100 PAY

4200

20.00

100.00 200.00

5-Foot Receiver

VDL (µ µsec)

1200

114

EXERCISE 3 COLLAR LOCATOR 0

0 10

GOOD

200

FAIR

0

TRANSIT TIME 300

FORMATION AMP (MV) 100 PIPE AMP (MV) 100

AMPLIFIED PIPE AMP (MV) 0 20 200

VDL (µ µsec) 1200

WATER ZONE

PAY

8400

WATER ZONE

DEPTH WELEX

115

EXERCISE 4

DEVI (DEG) 0

20

RB (DEG) 0

OVAL (IN) 0.0

0.5

10000

0.5

10000

4.5

0

ECCE (IN) 0.0 3.5

CALU (IN)

CSMX (PSI)

720 0

CIRCUMFERENTIAL CEMENT MAP

CSMN (PSI) WWM

0 2

Oil Water Contact

116

CBL INTERPRETATION - HOW TO STEP 1 - PERFORM THE FOLLOWING CHECKS IN FREE PIPE 1. Check the spacing of the Transmitter to the Receiver A. Amplitude and travel time curve should be 3 feet B. Attenuation curves have a 2.4 feet spacing C. Variable Density / waveforms should be 5 feet 2. Identify a value of travel time - base line A. Look for a reduction in travel time form baseline and amplitude indicating poor centralization B. Look for a reduction from base line associated with an increase in amplitude below the cement top indicating fast formations 3. Identify the dead time on the VDL and identify the first 3-4 bands associated with the casing signal for later channel identification

STEP 2 - PERFORM THE FOLLOWING CHECKS ON THE REPEAT 1. Passes made under the same pressure will repeat exactly on the 0-100 scale if the tool is well centered. 2. Check for changes in amplitude with and without pressure. A change represents a Microannulus and therefore good cement integrity

CONSULTANTS SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 Sage Brush RD YUKON, OK 73099 405 324-5828 FAX 324-2360 [email protected]

117

CBL INTERPRETATION - HOW TO STEP 3 - IDENTIFY THE ZONES NEEDING ISOLATION 1. Identify the zone(s) from an interpretation of the open hole logs or comments on the open hole logs 2. Find the zone(s) from an outside source. Company representative, geologist, engineer, etc.

STEP 4 - USE THE VDL TO IDENTIFY CHANNELS

1. First compare runs under pressure to determine it is not a microannulus 2. All casing signals on the VDL (straight lines) indicate no cement around the casing 3. The dead time followed by 3-4 casing arrivals followed by formation arrivals identifies a channel. A channel indicates incomplete mud removal (cement around part of the casing) 4. Only channels between zones needing isolation are a potential problem and need a squeeze consideration.

CONSULTANTS SIMPLIFIED TRAINING FOR IMMEDIATE USE

704 Sage Brush RD YUKON, OK 73099 405 324-5828 FAX 324-2360 [email protected]

118

GLOSSARY OF TERMS CEMENT LOGS Amplitude

-

The level of sound that returns to a CBL receiver measured in milli volts. This sound is usually the portion traveling through the casing.

Analog

-

Signals from downhole tools that are recorded directly. Digital signals are digitized and then recorded, usually on magnetic tape or disk.

API Units

-

A standard scaling factor established by the American Petroleum Institute. They have set up scales for both Gamma Ray counts and Neutron counts.

Attenuation

-

The rate of reduction of a sound level. Normally caused by the cement in the annulus and expressed in decibels per foot. (DB/Ft.)

Casing Signal

-

The portion of the sound wave from a CBL tool that is traveling through the casing from the transmitter to the receiver.

Centralizers

-

A device attached to a CBL tool in order to keep in it the center of the casing. This is a important quality control issue. The centralizers may be slipped over the tool or connected in between various portions of the tool.

Correlation

-

A method of depth control for logs. The method is to correct for depth discrepancies between logs or between curves on individual logs. The result or correlation is that each “event” (Shale, Sand, etc.) occur at the same depth on all logs.

Counts

-

The number of either gamma ray particles or neutrons detected or “counted” by a radioactivity detector.

Detector

-

A portion of the logging tools that can detect a reaction. Usually these are radioactive reactions which cause gamma rays to be emitted or neutrons bounce off the atoms.

First Arrival

-

The portion of the sound which travels to the CBL receiver first. This is usually the casing signal.

Formation Signal

-

The portion of the sound which travels to the CBL receiver after traveling through the formation or “rocks”. Usually the speed of this sound changes as the rock properties change and arrives at a later time than does the casing signal.

Gain

-

The amount of amplification applied by the electronics in a tool. For example the tool may have a 1 volt signal with a 10 to 1 gain applied. The resulting signal will be 10 volts.

119

Gate

-

The time interval over which the CBL amplitude is measured. This gate should be set in free pipe so that it can represent the sound level of the casing signal.

Gamma Ray

-

A small particle from the nucleus of a atom. Gamma rays are emitted by elements that are naturally radioactive and as a result of nuclear reactions caused by logging tools. A gamma ray tool detects only naturally occurring radioactivity and it is usually associated with shale (non-reservoir rock).

Gamma Ray Detectors-

The portion of the gamma ray tool that detects (or counts) gamma ray particles. They vary from the less sensitive Geiger Muller detector to the more sensitive Scintillation detectors.

Helium 3 Detector

-

The portion of a neutron tool that detects (or counts) neutrons. A neutron tool has a neutron source which bombards the formation and the counts are a result of neutrons that are reflected back by the formation and its fluids.

Logging Speed

-

The speed at which the cable is moving on or off a logging truck. The speed is limited by the floating of a tool downhole and the detections made by the tool as it is logging. The limiting factor is usually the gamma ray or neutron detectors.

Neutron

-

One of the two largest particles in a nucleus or an atom (the proton and the neutron). Emitted by a radioactive source in a neutron tool and detected by its detector. Some neutron tools detect gamma rays and are presented in API units. The result or this neutron bombardment is a function or a formations porosity.

Pipe Signal

-

Pipe and casing are interchangeable terms. See casing signal.

Porosity

-

The amount or pore space in a formation. These “holes in the rock” are the rock’s ability to store oil, gas or water and determine the formations ability to be a reservoir or tank.

Repeat Section

-

A section of log (100-300 feet interval) which is logged twice. This is usually at the bottom of the hole, but most importantly should be over the potential “pay” zone.

Sonic

-

Sound or anything referring to sound. A sonic tool emits a sound and has a receiver that picks up the sound after it has traveled through some fluid, rocks, cement or casing. A CBL tool is a unique version or a sonic tool.

120

Sonic Wave

-

Often referred to as the sound wave or wavetrain, is a combination of the sounds which have traveled through all of the media. In cased holes sound travels in the casing fluid, the casing, the cement and through the rocks and the fluids. Sound is transmitted by two means, these are compressional and shear waves. The compressional wave is the quickest while the shear wave is the highest in strength.

Transmitter

-

The portion or a sonic or CBL tool which emits the sound which is later detected by the receiver.

Transit Time

-

Sometimes referred to as the travel time. It is the time from which a sound is emitted from a transmitter in a CBL tool (T0) until it is detected by the tool at a given amplitude. (Usually 0.5 milli volts)

VDL

-

Variable Density Log. The VDL is a graphic representation of a sound wave as it is received by the CBL receiver. It is alternating dark and light lines which represent the positive and negative portions of the sound wave. Sometimes the VDL is called a micro seismogram.

Wavetrain

-

The entire portion of the sound wave as it is received by CBL receiver. The sound wave represents both compressional and shear waves that have traveled several paths from the transmitter to the receiver. This wavetrain are sometimes presented on the logs a pictures of the sound wave rather than the VDL graphic representation.

121

POST SQUEEZE Gamma Ray 0

150 COLLAR LOCATOR

0

10 TRANSIT TIME

300

200

FORMATION AMP (MV) 100 PIPE AMP (MV) GOOD 0 100 FAIR AMPLIFIED PIPE AMP (MV) 0 20 200 0

8300

Squeeze Holes

8400

Squeeze Holes

122

VDL (µ µsec) 1200

LOG WORKSHOP CRITIQUE VG

G

OK

1. Instructor's presentation 2. Instructor's knowledge of subject matter 3. Organization 4. Thoroughness of each topic 5. Encouraged participation and discussion 6. Answered all questions satisfactorily 7. Met your expectations

What did you like most about the workshop?

What did you like least about the workshop?

Are there any areas that you would have liked to have spent more time on?

Other comments or additional log workshops you would like to see:

123