Identification Of Fractures wiTh open hole logs
Most well logs respond in some way to the presence of fractures. Each major log type is discussed in the following Sections with respect to its fracture response. Not all logs detect fractures in all situations, and very few see all fractures present in the logged interval. Bear in mind that other borehole and formation responses will be superimposed on each log. Moreover, it is not normal to analyze a single log in isolation, but to review all log curves together to synthesize the best, most coherent, result. The list of possibilities is shown here:
   1. spontaneous potential
   2. caliper
   3. micro resistivity
   4. dipmeter and fracture identification log
   5. density, neutron, and photoelectric effect
   6. gamma ray and spectral gamma ray
   7. resistivity
   8. temperature
   9. sonic travel time
   10. sonic amplitude, and sonic wave train
   11. formation microscanner (resistivity images)
   12. borehole televiewer (acoustic images)

Because we are stuck with the existing logs in the well files, this Chapter covers the assessment of fractures from all these commonly available logs, even though image logs are usually the tool of choice today. On new wells in which fractures may be significant, we would run the correct log suite for fracture identification. Depending on local experience, this would be one or more of those on the following list:

   1. High resolution laterolog (HRLL) or azimuthal resistivity image (ARI) log with micro-SFLand gamma ray - required for fracture detection and water saturation, ARI helpful for fracture orientation

   2. Density neutron log (CNL-LDT) with photo-electric effect, gamma ray, and caliper -required for matrix porosity, lithology, helpful for fracture detection

   3. Dipole shear sonic image log (DSI) with gamma ray, caliper, amplitude, waveform or variable density display - required for porosity and mechanical properties calculation, helpful for fracture detection and orientation

   4. Natural gamma ray spectral log (NGT) -helpful for fracture detection, certain areas only, helpful in granite reservoirs to identify granite type, required in uranium-rich rocks.

   5. Formation micro-scanner image log (FMI) with gamma ray plus fracture aperture and frequency post-processing (FracVue) - strongly recommended, required for quantitative fracture porosity and permeability, required for fracture orientation

OR 5A. Ultra-sonic borehole imager (UBI) or televiewer log with gamma ray plus dipmeter post-processing - cheaper than micro-scanner but less sensitive, not quantitative

Usually at least two of these would be run for confirmation, but the microscanner or televiewer are often sufficient when run alone. Caliper, gamma ray, porosity, and resistivity logs are usually available as well, so there is no shortage of data!

There are a number of mechanical methods for locating fractures, which will not be discussed further in this Chapter, except for the brief outline given below. There is extensive literature on the subject, especially on well testing, which should be referred to. However, the log analyst needs to be aware of the possibility and confirmation of fractures from these sources:


Identification Of Fractures BY other methods

1. Drilling Characteristics
The occurrence of lost circulation or mud loss, abrupt drilling breaks, bit bouncing or torqueing, mud weight reduction, well kicks, oil on the mud pit surface, large de-gasser volumes, oil or gas shows on mud logs, calcite in well cuttings coming from fracture incrustations or veins may be indications of fractures. A review of the well history file is an important source of knowledge for the log analyst.

2. Sample Descriptions
Observation of fractures, slickensides, calcite in healed fractures, blocky or fissile texture may indicate fractures.

3. Inflatable Packers
An impression of the borehole wall can be imprinted on the rubber when the packer is set in place. If fractures are present, they will be seen, but there is no way to tell if they were induced by drilling or were present before drilling.

4. Drill Stem Testing
Analysis of pressure transient data from flow and buildup tests has been used extensively to indicate the presence of fracturing.

5. Core Analysis
Conventional core analysis can provide much information about fractures. Visual observation of open and healed fractures, stylolites, slickensides, fracture density, and fracture dip angle can be made at the wellsite or in the laboratory. They can also be described from core photographs under natural light, and when oil is present, under ultraviolet light.


Core examination and core description show fractures

If the core itself is not available for direct observation, you may find clues in the core analysis report or core descriptions, where the words fractured, frac, rubble, or lost core are clues to the presence of fractures. Descriptive information may not be transferred into all data bases, so it pays to check the original documents.

A high permeability value in an otherwise low permeability environment is another clue, as is an asterisk in the permeability column, indicating a fractured core sample in which permeability could not be measured. Large differences between maximum horizontal, minimum horizontal, and vertical permeability also may indicate fractures not seen by eye.

CORE ANALYSIS DATA FOR 10-22-39-26W4

10223926W4

 

 

 

 

 

 

 

 

 

 

 

S#

Top

Base

Len

Kmax

K90

Kvert

Porosi

GrDen

BkDen

Soil

Swtr

Lithology

 

meters

meters

meter

mD

mD

mD

frac

Kg/m3

Kg/m3

frac

frac

 

25

2122.00

2122.28

0.28

120.00

50.70

28.80

0.101

2810

2627

0.001

0.412

DOL I VUG CARB VFRAC

26

2122.28

2122.64

0.36

11.30

5.64

8.23

0.064

2830

2713

0.001

0.182

DOL I PPV LV VFRAC

27

2122.64

2122.86

0.22

547.00

82.00

92.20

0.105

2830

2638

0.106

0.212

DOL I VUG STY VFRAC

28

2122.86

2123.05

0.19

2110.0

2110.0

2110.0

0.147

2810

2544

0.000

0.103

DOL I PPV SV CARB

29

2123.05

2123.47

0.42

5350.0

2880.0

32.70

0.146

2810

2546

0.087

0.174

DOL I VUG CARB STY VFRAC

30

2123.47

2123.67

0.20

560.00

166.00

443.30

0.148

2790

2525

0.080

0.353

DOL I MV LV CARB VFRAC

31

2123.67

2124.10

0.43

16.00

11.30

12.00

0.074

2820

2685

0.001

0.247

DOL I VUG CARB VFRAC

32

2124.10

2124.53

0.43

15.90

14.20

11.06

0.104

2840

2649

0.000

0.205

DOL I VUG

33

2124.53

2124.80

0.27

5.27

3.36

1.02

0.048

2890

2799

0.000

0.133

DOL I PPV SV ANHY

34

2124.80

2125.18

0.38

267.00

113.00

11.70

0.129

2830

2594

0.001

0.290

DOL I VUG

35

2125.18

2125.44

0.26

192.00

130.00

11.80

0.079

2840

2695

0.113

0.271

DOL I VUG STY

36

2125.44

2125.70

0.26

421.00

95.50

25.90

0.071

2830

2700

0.001

0.410

DOL I VUG STY VFRAC

37

2125.70

2126.00

0.30

572.00

572.00

1282.0

0.129

2830

2594

0.001

0.560

DOL I VUG

38

2126.00

2126.21

0.21

10000

10000

5.81

0.116

2830

2618

0.001

0.273

DOL I VUG

39

2126.21

2126.42

0.21

2.49

2.12

0.81

0.070

2830

2702

0.000

0.250

DOL I VUG

40

2126.42

2126.75

0.33

55.60

30.80

2.12

0.097

2840

2662

0.053

0.191

DOL I VUG

41

2126.75

2126.95

0.20

82.20

17.00

1.88

0.144

2840

2575

0.043

0.072

DOL I VUG

42

2126.95

2127.19

0.24

196.00

48.10

0.44

0.133

2840

2595

0.062

0.198

DOL I VUG

43

2127.19

2127.38

0.19

8.35

7.63

0.06

0.118

2840

2623

0.077

0.196

DOL I VUG

44

2127.38

2127.70

0.32

1840.0

1700.0

0.21

0.103

2830

2642

0.047

0.207

DOL I VUG

45

2127.70

2127.94

0.24

23.60

20.50

0.23

0.117

2830

2616

0.001

0.182

DOL I VUG FOSS

46

2127.94

2128.09

0.15

27.90

21.00

0.96

0.153

2830

2550

0.108

0.432

DOL I VUG

47

2128.09

2128.38

0.29

107.00

8.50

0.07

0.130

2830

2592

0.000

0.285

DOL I VUG

48

2128.38

2128.79

0.41

533.00

338.00

102.00

0.075

2840

2702

0.000

0.504

DOL I PPV MV

49

2128.79

2129.26

0.47

40.20

11.30

5.19

0.068

2830

2706

0.046

0.130

DOL I VUG STY VFRAC

50

2129.26

2129.76

0.50

2340.0

1800.0

99.70

0.097

2820

2643

0.068

0.370

DOL I VUG

51

2129.76

2130.32

0.56

1670.0

708.00

532.00

0.122

2820

2598

0.055

0.398

DOL I VUG CARB VFRAC

52

2130.32

2130.83

0.51

62.30

19.80

6.16

0.086

2810

2654

0.000

0.427

DOL I VUG CARB VFRAC

53

2130.83

2131.14

0.31

2110.0

1770.0

698.00

0.142

2820

2562

0.000

0.534

DOL I VUG CARB

54

2131.14

2131.60

0.46

226.00

20.90

6.76

0.075

2830

2693

0.121

0.338

DOL I VUG

55

2131.60

2131.94

0.34

37.50

16.30

5.62

0.075

2840

2702

0.118

0.037

DOL I VUG

56

2131.94

2132.15

0.21

90.40

36.40

7.00

0.062

2830

2717

0.204

0.082

DOL I VUG

57

2132.15

2132.54

0.39

30.80

16.60

1.92

0.073

2830

2696

0.261

0.104

DOL I PPV LV VFRAC

58

2132.54

2132.67

0.13

81.90

48.10

88.90

0.129

2840

2603

0.180

0.072

DOL I PPV SV VFRAC

 

 

 

 

 

 

 

 

 

 

 

 

 

Arithmetic Averages

 

0.36

875.1

672.8

165.8

0.104

2830

2640

0.054

0.260

 

Core data listing for Carbonate Reef Example partial listing over gas-oil contact.


Notice the high permeability streaks on the core analysis caused by fractures. Lower values show matrix permeability. The VFRAC (vertical fracture) notations in the description column are a pretty good clue, too.

 

Observation of the core porosity versus permeability crossplot is another good piece of evidence; a shotgun pattern ias a really good indicator of fractures.

 

Core porosity versus permeability
crossplot in a fractured reservoir ==>

 

The dip direction and strike can be determined, if the core has been oriented with directional data. Cores can also be oriented by comparing observed bedding plane and fracture dips with those from a dipmeter analysis or by paleomagnetic orientation. Bedding plane and fracture plane dip angle and direction are determined by tracing the visible portion of the plane on the core surface with a goniometer, a fancy word for a three axis (X-Y-Z) digitizer. Originally mechanical devices, they are now electronic and interfaced to computers for calculation of the best fit dip plane and subsequent presentation of data listings and displays.

6. Thin Section Petrology
Special core and sample analysis techniques are used in fractured reservoirs, in addition to those normally performed to obtain porosity, permeability, and electrical characteristics. The major technique involves epoxy injection at formation pressure to fill all pores and open fractures. Whole slabs or thin sections are viewed or photographed under plane or ultraviolet light. Pore structure, fracture connections to isolated pores, fracture intensity, width, extent, and direction, and anhydrite or calcite filled fractures are recorded. Results are plotted versus depth and on rose diagrams.


Epoxy filled thin section for fracture location

7. X-Ray Tomography (CAT Scans)
X-ray tomography of cores, a non destructive, non invasive technique, may see fractures not visible to the naked eye. Open fractures with sufficient width and macro porosity appear as dark (fluid filled) pixels on the computer screen. Both horizontal slices and vertical reconstructed slices can be viewed on the computer screen. Micro porosity and narrow fractures may not be distinctly visible because the resolution is on the order of a millimeter or larger, not as good as the photomicrographs described above.


X-Ray tomography for fracture detection


More X-Ray tomography for fracture

Analysis by colour coded partitioning of histograms is commonly used to highlight particular features, such as porosity, mineralogy, or invaded fluids. Since the colour coding used to represent the X-ray count rate is proportional to density, healed or filled fractures are easily identified when the filling mineral is different than the matrix. Fractures and porosity are shown in black, calcite filled fractures as yellow, and dolomite matrix as orange.

The bottom left image portrays an anhydrite filled fracture (blue) with vuggy porosity (black) and mud invasion (also blue). The matrix, dolomite, is color coded yellow. Colors will vary under user control, so be sure you understand where the color break points are and what they are supposed to represent. Some ambiguity may exist, as in this last example. Visual examination is used to corroborate problematic situations.

Invasive X-ray tomography, using an aqueous sodium iodide solution to fill pores and fractures, is also used. A pressure sleeve is required, but resolution is better than the native state method, due to the high X-ray response of the injected fluid.
 

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