Jerry Rusnak will give a short lecture on What do we mean when we say we are going to Hydraulically Fracture a formation (rock)? Why would we do this? When we frac what data do we need to consider? How do we design a frac job? How do we analyze/evaluate a frac job?

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2. 2
Outline
• Brief Introduction to PetroTeach
• Biography of Distinguished Instructors Jerry Rusnak
• Webinar Presentation (45 - 60 min.)
• Course Agenda on “Hydraulic Fracturing”
• Q&A (15 - 20 min.)

3. Introduction to PetroTeach
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5. Hydraulic Fracturing
Webinar
Jerry Rusnak
Instructor

6. Objectives
•What do we mean when we say we are
going to Hydraulically Fracture a
formation (rock)?
•Why would we do this?
•When we frac what data do we need to
consider?
•How do we design a frac job?
•How do we analyze/evaluate a frac job?
Reservoir............ 6

7. Introduction
•What do we mean when we say we are
going to Hydraulically Fracture a
formation (rock)?
•We are going to apply fluid pressure (Pf)
to the rock that “exceeds” its
“mechanical strength”.
Reservoir............ 7

8. Mechanical Strength—The three principal
compressive stresses.
8

9. In-Situ Stresses
• A hydraulic fracture will propagate perpendicular to
the minimum principal stress (σ2)
• For a vertical fracture, the minimum horizontal
stress can be estimated with
9

10. Where:
• σmin = the minimum horizontal stress,
• ν = Poisson ’s ratio,
• σ1 = overburden stress,
• α = Biot’s poro-elastic constant,
• pp = reservoir fluid pressure or pore
pressure,
• σext = tectonic stress.
10

11. Poisson ’s ratio
• Poisson ’s ratio is defined as "the ratio of
lateral expansion to longitudinal
contraction for a rock under a uniaxial
stress condition."
• The value of Poisson’ s ratio is used to
convert the effective vertical stress
component into an effective horizontal
stress component.
• The value ranges from 0.15 – 0.35 for a
sandstone and 0.28 – 0.43 for a shale.
11

12. Biot's Constant
•The ratio of the volume change of the
fluid filled porosity to the volume
change of the rock when the fluid is free
to move out of the rock.
•It ranges between 0 (solid rock without
pores) and 1 (extremely compliant
porous solid).
12

13. Young’s modulus
•Young’s modulus is defined as "the ratio
of stress to strain for uniaxial stress."
•This modulus of a material is a measure
of the stiffness of the material.
•If the modulus is large, the material is
stiff.
13

14. Young’s modulus
•In hydraulic fracturing, a stiff rock
results in more narrow fractures.
•If the modulus is low, the fractures are
wider.
•Ranges from 1x106 – 10x106 psi
14

15. Why would we do this?
•Hydraulic fracture treatments are
used to:
•increase the productivity index of
a producing well
•or the injectivity index of an
injection well.
15

16. What is the PI
• Productivity Index = J = Q/(Pe-Pwf)
• J = Productivity Index, STB/day/psi
• Q = Surface flowrate at standard
conditions, STB/D
• Pe = External boundary radius pressure,
psi
• Pwf = Well sand-face mid-perf pressure,
psi
16

17. Why would we Frac a well?
• Hydraulic fracturing can;
• Increase the flow rate of oil and/or gas
from low-permeability reservoirs,
• Increase the flow rate of oil and/or gas
from wells that have been damaged,
• Connect the natural fractures and/or
cleats in a formation to the wellbore,
• Decrease the pressure drop around the
well to minimize sand production,
• Enhance gravel-packing sand placement,
17

18. When we frac what data do we
need to consider?
•The data required to run both the
fracture design model and the reservoir
simulation model can be divided into
two groups:
•data that can be "controlled" by the
engineer
•data that must be measured or
estimated but cannot be controlled.
18

19. Developing Data Sets
• The primary data that can be controlled by the engineer are;
• the well completion details,
• treatment volume,
• pad volume,
• injection rate,
• fracture fluid viscosity,
• fracture fluid density,
• fluid-loss additives,
• propping agent type,
• propping agent volume.
19

20. Developing Data Sets
• The data that must be measured or estimated are;
• formation depth (TVD),
• formation permeability,
• in-situ stresses in the pay zone,
• in-situ stresses in the surrounding layers,
• formation modulus,
• reservoir pressure,
• formation porosity,
• formation compressibility,
• reservoir thickness.
20

21. Developing Data Sets
• The most critical data for the design of a fracture treatment
(roughly in order of importance) are;
• the in-situ stress profile,
• formation permeability,
• fluid-loss characteristics,
• total fluid volume pumped,
• propping agent type and amount,
• pad volume,
• fracture fluid viscosity,
• injection rate,
• formation modulus.
21

22. Candidate Selection
• The best candidate wells for hydraulic
fracturing treatments have substantial
reserves but need to increase the
productivity index in order to be
economically successful.
22

23. Candidate Selection
•Reservoirs that are poor candidates
for hydraulic fracturing are those
with little oil and/or gas in place
because;
•thin reservoirs,
•low reservoir pressure,
•small areal extent.
23

24. Candidate Selection
•Unconventional reservoirs are an
exception to theses rules because:
•Economical extended reach
horizontal drilling,
•Massive hydraulic fracturing using
inexpensive fluids and proppants,
•Advances in “rigless” completion
systems.
24

25. How do we design a frac job?
•Choose frac fluids
•Choose frac proppants
•Choose Pumping equipment
Reservoir............ 25

26. Properties of a Fracturing Fluid
• The ideal fracturing fluid should be;
• compatible with the formation rock and fluid,
• generate enough pressure drop down the
fracture to create a wide fracture,
• be able to transport the propping agent in the
fracture,
• break back to a low-viscosity fluid for cleanup
after the treatment,
• be cost-effective.
26

27. Properties of a Fracturing Fluid
•The family of fracture fluids
available consist of;
•water-based fluids,
•oil-based fluids,
•acid-based fluids,
•foam fluids.
27

28. Fracture-Fluid Additives
28

29. Propping Agents and Fracture
Conductivity
•Propping agents are required to "prop
open" the fracture once the pumps are
shut down and the fracture begins to
close.
29

30. Propping Agents and Fracture
Conductivity
•The ideal propping agent is;
•strong,
•resistant to crushing,
•resistant to corrosion,
•has a low density,
•is readily available at low cost.
30

31. Propping Agents and Fracture
Conductivity
•The products that best meet
these desired traits are;
•silica sand,
•resin-coated sand (RCS),
•ceramic proppants.
31

32. Fig. 8.15—Effect of stress on fracture conductivity from common propping
agents.
32

33. Equipment
Reservoir............ 33

34. What does a typical design
include?
• Pad volume to
propagate the
fracture.
• Slurry (blended fluid
& prop) volume
placed behind the pad
to hold open the
fracture.
• Displacement volume
to clear wellbore of
slurry down to top of
formation.
D&C 34

35. Job Design
Reservoir............ 35

36. How do we predict where these volumes will go?
36

37. Developing
Data Sets
• To design a
fracture
treatment, most
use pseudo-
three-
dimensional
(P3D) models.
• To use a P3D
model, the data
must be entered
by reservoir layer.
37

38. Developing Data Sets
• The fracture
treatment would be
started in the
sandstone reservoir.
• The fracture would
typically grow up and
down until a barrier
is reached to prevent
vertical fracture
growth.
• In many cases, thick
marine shale is a
barrier to vertical
fracture growth.
38

39. How do we optimize the process?
39

40. Fracture Treatment Optimization
• The method used to optimize the size of a fracture
treatment and clearly shows the following:
• As the propped length of a fracture increases, the
cumulative production will increase, and the revenue
from hydrocarbon sales will increase.
40

41. Fracture Treatment Optimization
• As the fracture length increases, the incremental benefit
(amount of revenue generated per foot of additional
propped fracture length) decreases.
41

42. Fracture Treatment Optimization
• As the treatment volume increases, the propped
fracture length increases.
42

43. Fracture Treatment Optimization
• As the fracture length increases, the incremental cost of
each foot of fracture (cost/ft of additional propped
fracture length) increases.
43

44. Fracture Treatment Optimization
• When the incremental cost of the treatment is
compared with the incremental benefit of increasing the
treatment volume, an optimum propped fracture length
can be found for every situation.
44

45. How do we “pump” a job?
• After the optimum fracture treatment has been
designed, it must be pumped into the well
successfully.
• A successful field operation requires planning,
coordination, and cooperation of all parties.
• Treatment supervision and the use of quality control
measures will improve the successful application of
hydraulic fracturing.
45

46. Field Considerations
•Safety is always the primary concern in
the field, and it begins with a thorough
understanding by all parties of their
duties.
•A Job Safety and Environmental Analysis
(JSEA) performed prior to the job is the
best means of accomplishing this.
46

47. Field Considerations
•A safety meeting is always held to:
•Review the treatment procedure,
•Establish a chain of command,
•Ensure everyone knows his/her job
responsibilities for the day,
•Establish a plan for emergencies.
47

48. Screen-Out
•Screen-out refers to a condition where
continued injection of fluid inside the
fracture requires pressures in excess of
the safe limitations of the wellbore or
wellhead equipment.
Reservoir............ 48

49. Screen-Out
Reservoir............ 49

50. Field Considerations
• The safety meeting also should be used to discuss:
• The well completion details,
• The maximum allowable injection rate and pressures,
• The maximum pressures to be held as backup in the
annulus if applicable.
50

51. Field Considerations
• All casing, tubing, wellheads, valves, and weak
links, such as liner tops, should be tested
thoroughly before starting the fracturing
treatment.
• Mechanical failures during a treatment can be costly and
dangerous.
• All mechanical problems should be discovered during
testing and repaired before pumping the fracture
treatment.
51

52. Field Considerations
• Before pumping the treatment, the engineer in
charge should conduct a detailed inventory of all
the equipment and materials on location.
• The inventory should be compared with the design
and the prognosis.
• After the treatment has concluded, another
inventory of all the materials left on location should
be conducted.
52

53. Field Considerations
• In most cases, the difference in the two inventories
can be used to verify what was mixed and pumped
into the wellbore and the hydrocarbon-bearing
formation.
• In addition to an inventory, samples of the base
fracturing fluid (usually water) should be taken and
analyzed.
53

54. How do we analyze/evaluate a frac
job?
•Direct Far-Field Techniques.
•Indirect Fracture Modeling Techniques.
54

55. Direct Far-Field Techniques
• Fracture Modeling
incorporates event
magnitudes and
geomechanical analysis to help
determine fracture size and
orientation.
• Estimates stimulated rock
volume.
• Incorporates magnitudes, rock
properties, and fluid
properties to map hydraulic
fractures.
• Estimates propped half-length.
55

56. Indirect Fracture Techniques
•Because the fracture-treatment data
and the post-fracture production data
are normally available on every well,
the indirect fracture diagnostic
techniques are the most widely used
methods to determine the shape and
dimensions of both the created and the
propped hydraulic fracture.
56

57. Indirect Fracture Techniques
Indirect fracture techniques consist of
hydraulic fracture modeling of:
•Net pressures,
•Pressure-transient-test analyses,
•Production-data analyses.
57

58. Indirect Fracture Techniques
•The fracture-treatment data can be
analyzed with a P3D fracture
propagation model to determine the
shape and dimensions of the created
fracture.
•The P3D model is used to history match
the fracturing data, such as injection
rates and injection pressures.
58

59. Net Pressure
• One of the best methods to analyze a fracture
treatment is to use a fracture propagation model to
analyze the net pressures measured during a
fracture treatment.
59

60. Net Pressure
• In many formations,
the pressure drop
down the fracture is
dominated by the
pressure increases
near the tip of the
fracture as
propagation occurs.
• The net pressure
profile controls both
the fracture height
and fracture width
distribution along
the fracture length.
60

61. Fig. 8.12—Length and height distribution from a P3D model.
61

62. Post-Fracture Well-Test Analyses
• Post-fracture well-test analyses are used to
compute estimates of the propped fracture
length, fracture conductivity, and drainage
area of the formation.
• It is important to keep good records of the
flow rates of oil, gas, and water, as well as
the flowing pressures after the fracture
treatment.
62

63. Post-Fracture Well-Test Analyses
•If possible, a pressure-buildup test
should be run after the well cleanup
following the fracture treatment.
63

64. Hydraulic Fracturing (online)
12 - 16 Oct. 2020
11 – 15 Jan. 2021
Register@petro-teach.com
Course Overview:
This course teaches understanding the concepts and practical knowledge of how to get the optimum design of hydraulic fracture
treatment for various reservoir types in order to improve well productivity. The course will cover the physics, chemistry, job design,
execution and post treatment evaluation. Recognition of well candidates for stimulation is emphasized.
The course is designed to provide attendees with a working knowledge of fracturing design and fracturing procedures.
Attendees will learn the practical application of different types of fracturing jobs and use of additives to produce specific
fracturing fluid properties. Attendees will learn how to evaluate the success or failure of a fracturing job.
 The learning objectives of the top-most level content of the course are:
 Hydraulic fracturing selection criteria
 Determining In-Situ stresses
 Fracturing fluids and additives properties and selection
 Proppant properties and selection
 Hydraulic fracture treatment design
 Acid fracturing
 Hydraulic fracture treatment execution
 Post treatment evaluation
 Course price (Euro):
• Normal registration: 1490+VAT
• 20% DISCOUNT for PhD students, Group (≥ 3 person) and early bird registrants (1 week before)
64Hydraulic Fracturing Webinar

65. Thank You
Any Questions ?
Hydraulic Fracturing Webinar 65

66. 66
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