S
Hydraulic Fracturing Design for
Optimum Well Productivity
Frank E. Syfan, Jr., PE, SPEE
Syfan Engineering, LLC
February 26, 2015
Outline

Critical Fracture Design Parameters





Case Histories:






Rock Mechanics
Fracture Mechanics
Fluid Systems
Proppant Selection
Case A:
Case B:
Case C:
Case D:
Marcellus Shale
Eagle Ford Shale
Bakken
Cotton Valley
Summary
Conclusions
2
Critical Fracture Parameters
Rock Mechanics

Mineralogy
 Content: Quartz, calcite, clay (??)
 Shales: Many are not in strictest geological sense!

Poisson’s Ratio
𝝏𝜺𝒕𝒓𝒂𝒏𝒔
𝒗=−
𝝏𝜺𝒂𝒙𝒊𝒂𝒍

Modulus of Elasticity (Young’s Modulus)
𝒎

𝑺𝒕𝒓𝒆𝒔𝒔 𝝈
≝
=𝑬
𝑺𝒕𝒓𝒂𝒊𝒏 𝜺
In-Situ Stress
𝒗
𝝈𝑯 =
𝝈 − 𝑷𝒑 + 𝑷𝒑 + 𝝈𝝉
𝟏−𝒗 𝒗
3
Critical Fracture Parameters
Fracture Mechanics

Fracture Face Skin
𝑺𝑭𝒂𝒄𝒆

𝒌𝒓
−𝟏
𝒌𝑫
Choked Fracture Skin
𝑺𝒄𝒉

𝝅𝒀𝒙
=
𝑿𝒇
𝒉 𝟏
𝒉
𝝅
=
𝒍𝒏
−
𝑿𝒇 𝑪𝒇𝑫
𝟐𝒓𝒘
𝟐
Half-Length & Width
 What is optimum length?
 Perkins & Kern (1961)

Fracture Conductivity!!!
 wkf
 CfD
4
Critical Fracture Parameters
Fluid Systems

Fluid & Additive Design

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
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
Slickwater DOESN’T Work Everywhere!
Chemical and Fluid Compatibility
Gel Stability and Breaker Tests
Temperature Ranges
Nano-Fluid Non-Emulsifiers
Polyacrylamide Breakers
ISO 13503-1, 13503-3, 13503-4
5
Critical Fracture Parameters
Proppant Selection
Ceramic
Resin
Coated
a-Qtz
6
Critical Fracture Parameters
Proppant Selection
Ceramics
RC Ceramics
Incr. Closure Pressure, Kpsi
Bauxite
13+
12
Intermediate
RC a-Qtz
LWC
Premium
Economy
8
Intermediate
a-Qtz
5
4
0
Incr. Cost & Performance
7
Critical Fracture Parameters
Proppant Selection

The Ideal Proppant






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


Crush resistance / high strength
Slightly deformable, not brittle
No embedment
Low specific gravity
Chemical resistance
No flowback
Complete system compatibility
Ready availability
Cost effective
Reality: The Ideal Proppant Doesn’t Exist!!
8
Critical Fracture Parameters
Proppant Selection




Infinite vs. Finite Conductivity
Formation Permeability
Depth/Closure Stress
Formation Ductility/Embedment
 What is Brinell Hardness?
9
Critical Fracture Parameters
Proppant Selection





Median Particle Diameter
Cyclic Stress
Multi-Phase Flow
Proppant Flowback
Non-Darcy Effects
 Beta Factor
10
Critical Fracture Parameters
Conductivity

Fracture Conductivity – Wkf
 Single Most Important Factor to Achieve!

Dimensionless Conductivity
 Fracture Flow Capacity Divided by Reservoir Flow
Capacity.
 Considered “Infinite” the fracture deliverability
exceeds reservoir deliverability with negligible
pressure loss.
C fD 
k f wf
k x f
11
Critical Fracture Parameters
Conductivity: McGuire & Sikora (1960)

Dimensionless Productivity
Index vs. Dimensionless
Conductivity
 (Square Reservoir)


Dimensionless Productivity
Index vs. Dimensionless
Conductivity
(Rectangular Reservoir – 1/10)
12
Critical Fracture Parameters
Fines
Intermediate Strength
Ceramic – 8,000 psi
12/20 Hickory/Brady – 6,000 psi
RC Proppant – 8,000 psi
StimLab Proppant Consortium, 1997 – 2006
13
Critical Fracture Parameters
Depth/Closure Stress


Brown vs. Northern White?
API 19C (ISO 13503-2) Guidelines Are Specific!!

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
Sieve Distribution
Krumbein Factors
Turbidity
Acid Solubility
K-Value (Also Called Crush Resistance)
 Point Where Fines >10.0%
 Relative Number Only!!
14
Critical Fracture Parameters
Median Particle Diameter

SPE 84304 (2003)
 Particle Sieve Distribution Variations
Field Samples – 20/40 N. White @ 25X
0.703 mm
0.545
mm
Courtesy: PropTester – Houston TX
15
Critical Fracture Parameters
Median Particle Diameter
Each Proppant Sample Passes ISO 13503-2 Guidelines!
MPD = 0.710 mm
45
% Particle Distribution
40
MPD = 0.543 mm
35
30
25
20
15
10
5
0
16
20
25
30
35
40
50
PAN
Sie v e Size
Public Domain
Job Sample
Flow Capacity Decreases
Courtesy: PropTester – Houston TX
16
Critical Fracture Parameters
Median Particle Diameter
Conductivity (md-ft)
10,000
Published Data
MPD = 0.710 mm
1,000
Actual Data
MPD = 0.543 mm
100
2,000
4,000
6,000
8,000
10,000
Closure Stress (psi)
Courtesy: PropTester – Houston TX
17
Critical Fracture Parameters
Beta Factor


A Quantity Relating Pressure Loss In The Fracture to
Liquid or Gas Production Rates (velocities).
Governed by Forchheimer’s Equation
 Darcy Effects
 Non-Darcy Effects
• Inertial Effect
• 2 - Dominate!
• PSD Effects Beta
Pfrac
X frac
 fluid .v fluid
2

  fluid v fluid
k frac
18
Outline

Critical Fracture Design Parameters





Case Histories:






Rock Mechanics
Fracture Mechanics
Fluid Systems
Proppant Selection
Case A:
Case B:
Case C:
Case D:
Marcellus Shale
Eagle Ford Shale
Bakken
Cotton Valley
Summary
Conclusions
19
Case History A: Marcellus Shale
Reservoir & Fracture Parameters
Description
Value
Reservoir Depth, ft
7.876
Fracture & Reservoir Match
Description
Value
Reservoir Permeability, nD
583.0
0.094
Reservoir Thickness, ft
162
Permeability-Thickness, md-ft
Hydrocarbon Porosity, %
4.2
Propped Length, ft
320
4.726
Fracture Conductivity, md-ft
3.77
Temperature, oF
175
Dimensionless Conductivity
20.2
Drainage Area, ac
80
Aspect Ratio (xe/ye)
¼
Pore Pressure, psi
BHFP, psi
Choked Skin, dim
1,450 – 530
Lateral Length, ft
2,100
Number of Stages
7
Clusters per Stage
5
Equivalent Fractures
SPE 166107
+0.096
6
20
Case History A: Marcellus Shale
Predicted Gas Production Rate
SPE 166107
Predicted Cum. Gas Production
21
Case History A: Marcellus Shale
SPE 166107
22
Case History B: Eagle Ford Shale
Reservoir & Fracture Parameters
Description
Value
Reservoir Depth, ft
10,875
Fracture & Reservoir Match
Description
Permeability-Thickness, md-ft
Value
0.0049
Reservoir Thickness, ft
283
Propped Length, ft
131
Hydrocarbon Porosity, %
5.76
Fracture Conductivity, md-ft
0.86
Pore Pressure, psi
8,350
Dimensionless Conductivity
382
Temperature, oF
285
Drainage Area, ac
80
Aspect Ratio (xe/ye)
¼
BHFP, psi
Choked Skin, dim
Equivalent Fractures
+0.0254
40
3,900 – 1,500
Lateral Length, ft
4,000
Number of Stages
10
Clusters per Stage
4
SPE 166107
23
Case History B: Eagle Ford Shale
Predicted Gas Production Rate
SPE 166107
Predicted Cum. Gas Production
24
Case History C: Bakken Shale
Reservoir & Fracture Parameters
Description
Reservoir Depth, ft
Value
9,881
Description
Drainage Area, ac
640
Reservoir Thickness, ft
46
Rsvr. Permeability, D
0.002
Effective Frac. Length, ft
420
5.0
Frac. Conductivity, md-ft
200
Dimensionless Conductivity
238
Porosity, %
Pore Pressure, psi
Temperature, oF
Rsvr. Compressibility, 1/psi
Rsvr. Viscosity, cP
4,900
209
2.0 E-05
BHFP, psi
Value
Lateral Length, ft
Transverse Fractures
1,500
5,000
12
0.30
SPE 166107
25
Case History C: Bakken Shale
Predicted Oil Production Rate
Predicted Cum. Oil Production
SPE 166107
26
Case History D: E. TX Cotton Valley
Reservoir & Fracture Parameters
Description
Reservoir Depth, ft
Value
9,000
Description
Value
BHFP, psi
1,500
Reservoir Thickness, ft
100
Effective Frac. Length, ft
1,500
Rsvr. Permeability, D
0.001
Frac. Conductivity, md-ft
114
Dimensionless Conductivity
76
Porosity, %
Pore Pressure, psi
7.0
6,000
Temperature, oF
285
Drainage Area, ac
640
Lateral Length, ft
Transverse Fractures
SPE 166107
2,000
7
27
Case History D: E. TX Cotton Valley
Predicted Gas Production Rate
SPE 166107
Predicted Cum. Gas Production
28
Outline

Critical Fracture Design Parameters





Case Histories:






Rock Mechanics
Fracture Mechanics
Fluid Systems
Proppant Selection
Case A:
Case B:
Case C:
Case D:
Marcellus Shale
Eagle Ford Shale
Bakken
Cotton Valley
Summary
Conclusions
29
Summary



Proper fracture design and ultimately, fracture
optimization, cannot and will not happen without
sound engineering practices!
Without sound engineering, initial production rates,
ultimate recovery, NPV, and rate-of-return will be
compromised.
At the End of the Day……
SPE 166107
30
Conclusions



Understanding the rock mechanics is essential to
consistently achieving high conductivity fractures.
McGuire and Sikora (1960) holds true regardless of
reservoir type and ultimately dictates reservoir and
production performance.
Fracture conductivity and dimensionless fracture
conductivity ultimately govern the initial production
rates and ultimate recoveries regardless of the type
of reservoir lithology.
SPE 166107
31
Conclusions


Case A (Marcellus Shale) and Case B (Eagle Ford
Shale) matches, illustrate the importance of
achieving high conductivity transverse fractures in a
horizontal wellbores.
Increasing fracture conductivity, regardless of
reservoir type, results in a significant positive impact
on ROR and NPV.
SPE 166107
32
THANK YOU FOR YOUR TIME AND
TO THE FORT WORTH SPE
SECTION FOR INVITING ME TO
MAKE THIS PRESENTATION.
QUESTIONS??
33