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Propping agents are required to "prop open" the [[Hydraulic fracturing|fracture]] once the pumps are shut down and the fracture begins to close. The ideal propping agent is strong, resistant to crushing, resistant to corrosion, has a low density, and is readily available at low cost.<ref name="r1" /> The products that best meet these desired traits are silica sand, resin-coated sand (RCS), and ceramic proppants.
Propping agents are required to "prop open" the [[Hydraulic_fracturing|fracture]] once the pumps are shut down and the fracture begins to close. The ideal propping agent is strong, resistant to crushing, resistant to corrosion, has a low density, and is readily available at low cost.<ref name="r1">_</ref> The products that best meet these desired traits are silica sand, resin-coated sand (RCS), and ceramic proppants.
 
== Types of propping agents ==


==Types of propping agents==
Silica sand is obtamust be tested to be sure it has the necessary compressive strength to be used in any specific situation. Generally, sand is used to prop open fractures in shallow formations. Sand is much less expensive per pound than RCS or ceramic proppants.
Silica sand is obtamust be tested to be sure it has the necessary compressive strength to be used in any specific situation. Generally, sand is used to prop open fractures in shallow formations. Sand is much less expensive per pound than RCS or ceramic proppants.


Line 7: Line 8:


Ceramic proppants consist of:
Ceramic proppants consist of:
* Sintered bauxite
* Intermediate-strength proppant (ISP)
* Lightweight proppant (LWP)


The strength of a ceramic proppant is proportional to its density. Also, the higher-strength proppants, like sintered bauxite, cost more than ISP and LWP. Ceramic proppants are used to stimulate deep (<nowiki>></nowiki> 8,000 ft) wells where large values of in-situ stresses will apply large forces on the propping agent.
*Sintered bauxite
*Intermediate-strength proppant (ISP)
*Lightweight proppant (LWP)


==Factors affecting fracture conductivity==
The strength of a ceramic proppant is proportional to its density. Also, the higher-strength proppants, like sintered bauxite, cost more than ISP and LWP. Ceramic proppants are used to stimulate deep (
<nowiki>></nowiki>
8,000 ft) wells where large values of in-situ stresses will apply large forces on the propping agent.
== Factors affecting fracture conductivity ==


The fracture conductivity is the product of propped fracture width and the permeability of the propping agent, as '''Fig. 1''' illustrates. The permeability of all the commonly used propping agents (sand, RCS, and the ceramic proppants) will be 100 to 200<nowiki>+</nowiki> darcies when no stress has been applied to the propping agent. However, the conductivity of the fracture will be reduced during the life of the well because of:
The fracture conductivity is the product of propped fracture width and the permeability of the propping agent, as '''Fig. 1''' illustrates. The permeability of all the commonly used propping agents (sand, RCS, and the ceramic proppants) will be 100 to 200
* Increasing stress on the propping agents
<nowiki>+</nowiki>
* Stress corrosion affecting the proppant strength
darcies when no stress has been applied to the propping agent. However, the conductivity of the fracture will be reduced during the life of the well because of:
* Proppant crushing
*Increasing stress on the propping agents
* Proppant embedment into the formation
*Stress corrosion affecting the proppant strength
* Damage resulting from gel residue or fluid-loss additives
*Proppant crushing
*Proppant embedment into the formation
*Damage resulting from gel residue or fluid-loss additives


The effective stress on the propping agent is the difference between the in-situ stress and the flowing pressure in the fracture, as '''Fig. 2''' illustrates. As the well is produced, the effective stress on the propping agent will normally increase because the value of the flowing bottomhole pressure will be decreasing. However, as '''Eq. 1''' shows, the in-situ stress will decrease with time as the reservoir pressure declines. This phenomenon of decreasing in-situ stress as the reservoir pressure declines was proven conclusively by Salz.<ref name="r2" /> '''Fig. 3''' illustrates the differences in fracture conductivity as effective stress increases on the propping agent for a variety of commonly used propping agents. The data in '''Fig. 3''' clearly show that for shallow wells, where the effective stress is less than 6,000 psi, sand can be used to create high-conductivity fractures. As the effective stress increases to larger and larger values, then the higher-strength, more-expensive propping agents must be used to create a high conductivity fracture.
The effective stress on the propping agent is the difference between the in-situ stress and the flowing pressure in the fracture, as '''Fig. 2''' illustrates. As the well is produced, the effective stress on the propping agent will normally increase because the value of the flowing bottomhole pressure will be decreasing. However, as '''Eq. 1''' shows, the in-situ stress will decrease with time as the reservoir pressure declines. This phenomenon of decreasing in-situ stress as the reservoir pressure declines was proven conclusively by Salz.<ref name="r2">_</ref> '''Fig. 3''' illustrates the differences in fracture conductivity as effective stress increases on the propping agent for a variety of commonly used propping agents. The data in '''Fig. 3''' clearly show that for shallow wells, where the effective stress is less than 6,000 psi, sand can be used to create high-conductivity fractures. As the effective stress increases to larger and larger values, then the higher-strength, more-expensive propping agents must be used to create a high conductivity fracture.


[[File:Vol4 page 0329 eq 001.png]]....................(1)
[[File:Vol4 page 0329 eq 001.png|RTENOTITLE]]....................(1)


where
where
Line 30: Line 35:
''σ''<sub>min</sub> = the minimum horizontal stress,
''σ''<sub>min</sub> = the minimum horizontal stress,


''ν'' = Poisson<nowiki>’</nowiki>s ratio,
''ν'' = Poisson
 
<nowiki>’</nowiki>
s ratio,
''σ''<sub>1</sub> = overburden stress,
''σ''<sub>1</sub> = overburden stress,


''α'' = Biot<nowiki>’</nowiki>s constant,
''α'' = Biot
 
<nowiki>’</nowiki>
s constant,
''p''<sub>''p''</sub> = reservoir fluid pressure or pore pressure, and
''p''<sub>''p''</sub> = reservoir fluid pressure or pore pressure, and


''σ''<sub>ext</sub> = tectonic stress.
''σ''<sub>ext</sub> = tectonic stress.


 
<gallery widths="300px" heights="200px">
<gallery widths=300px heights=200px>
File:Vol4prt Page 342 Image 0002.png|'''Fig. 2—Effective stress on the propping agent.'''
File:Vol4prt Page 342 Image 0002.png|'''Fig. 2—Effective stress on the propping agent.'''
File:Vol4prt Page 343 Image 0001.png|'''Fig. 3—Effect of stress on fracture conductivity from common propping agents.'''
File:Vol4prt Page 343 Image 0001.png|'''Fig. 3—Effect of stress on fracture conductivity from common propping agents.'''
Line 48: Line 54:
When choosing a propping agent, a proppant that will maintain enough conductivity after all crushing and embedment occurs must be chosen. The effects of non-Darcy flow, multiphase flow, and gel residue damage should also be considered.
When choosing a propping agent, a proppant that will maintain enough conductivity after all crushing and embedment occurs must be chosen. The effects of non-Darcy flow, multiphase flow, and gel residue damage should also be considered.


==Proppant transport==
== Proppant transport ==
 
To create a hydraulic fracture, fluid is injected at high rate and pressure into a wellbore and into a formation that is open to the wellbore. Viscous fluid flow within the fracture and tip effects create the net pressure required to generate the created width profile and the created fracture height. The volume of fluid pumped will affect the created fracture length. However, without pumping a propping agent into the fracture, the created fracture will close once the pumping operation ceases. The flow of oil and gas from the formation into the fracture is dependent on the propped fracture dimensions. The really important characteristics of a fracture are the propped width, height, and length distributions; therefore, proppant transport considerations are very important in designing a hydraulic fracture treatment. '''Fig. 4''' illustrates the difference between the created fracture dimensions and the propped fracture dimensions.
To create a hydraulic fracture, fluid is injected at high rate and pressure into a wellbore and into a formation that is open to the wellbore. Viscous fluid flow within the fracture and tip effects create the net pressure required to generate the created width profile and the created fracture height. The volume of fluid pumped will affect the created fracture length. However, without pumping a propping agent into the fracture, the created fracture will close once the pumping operation ceases. The flow of oil and gas from the formation into the fracture is dependent on the propped fracture dimensions. The really important characteristics of a fracture are the propped width, height, and length distributions; therefore, proppant transport considerations are very important in designing a hydraulic fracture treatment. '''Fig. 4''' illustrates the difference between the created fracture dimensions and the propped fracture dimensions.


<gallery widths=300px heights=200px>
<gallery widths="300px" heights="200px">
File:Vol4prt Page 344 Image 0001.png|'''Fig. 4—Difference between created and propped fracture dimensions.'''
File:Vol4prt Page 344 Image 0001.png|'''Fig. 4—Difference between created and propped fracture dimensions.'''
</gallery>
</gallery>


The first fluid pumped into a well during a fracture treatment is called the "prepad." The prepad is used to fill the [[Casing and tubing|casing and tubing]], test the system for pressure, and break down the formation. Next, the pad fluid, which is the viscous [[Fracturing fluids and additives|fracturing fluid]] used during the treatment, is pumped. No propping agent has been added to the pad. The purpose of the pad is to create a tall, wide fracture that will accept the propping agent. Following the pad, the fluid containing propping agent, which is called the slurry, is pumped. The slurry moves into the fracture, transporting the propping agent. The particles move up, out, and down the fracture with the slurry. The particles also can settle in the fracture as a result of gravitational forces.
The first fluid pumped into a well during a fracture treatment is called the "prepad." The prepad is used to fill the [[Casing_and_tubing|casing and tubing]], test the system for pressure, and break down the formation. Next, the pad fluid, which is the viscous [[Fracturing_fluids_and_additives|fracturing fluid]] used during the treatment, is pumped. No propping agent has been added to the pad. The purpose of the pad is to create a tall, wide fracture that will accept the propping agent. Following the pad, the fluid containing propping agent, which is called the slurry, is pumped. The slurry moves into the fracture, transporting the propping agent. The particles move up, out, and down the fracture with the slurry. The particles also can settle in the fracture as a result of gravitational forces.


Daneshy<ref name="r3" /> provided a thorough summary of proppant transport issues. The effects of gravity on proppant settling can be computed by beginning with Stokes<nowiki>’</nowiki> law. '''Eq. 2''' is Stokes<nowiki>’</nowiki> law for a single spherical particle of diameter ''d''<sub>p</sub> and density ''ρ''<sub>p</sub> settling in a Newtonian fluid with a density of ''ρ''<sub>f</sub> and a viscosity of ''μ''.
Daneshy<ref name="r3">_</ref> provided a thorough summary of proppant transport issues. The effects of gravity on proppant settling can be computed by beginning with Stokes
 
<nowiki>’</nowiki>
[[File:Vol4 page 0342 eq 001.png]]....................(2)
law. '''Eq. 2''' is Stokes<nowiki>’</nowiki>
law for a single spherical particle of diameter ''d''<sub>p</sub> and density ''ρ''<sub>p</sub> settling in a Newtonian fluid with a density of ''ρ''<sub>f</sub> and a viscosity of ''μ''.
[[File:Vol4 page 0342 eq 001.png|RTENOTITLE]]....................(2)


'''Eq. 2''' shows that the settling velocity will increase as the diameter and density of the propping agent increase and as the density and viscosity of the fracturing fluid decrease. To minimize proppant settling, propping agents that are smaller in diameter and/or less dense, as well as a more viscous fluid, can be used.
'''Eq. 2''' shows that the settling velocity will increase as the diameter and density of the propping agent increase and as the density and viscosity of the fracturing fluid decrease. To minimize proppant settling, propping agents that are smaller in diameter and/or less dense, as well as a more viscous fluid, can be used.


However, Stokes<nowiki>’</nowiki> law must be modified with the use of non-Newtonian fluids and to account for the other particles in suspension in the slurry during the pumping operation. Ref. 3<ref name="r3" /> provides a complete discussion on the factors that affect proppant transport and how Stokes<nowiki>’</nowiki> law has been modified to account for many important factors. For example, at low proppant concentrations (1 to 3 ppg), the viscosity of the slurry is relatively unchanged. At high proppant concentrations (8 to 14 ppg), the slurry viscosity can be 3 to 10 times more than the viscosity of the clean fluid. Such factors must be recognized and included in any [[Fracture propagation models|fracture-propagation design model]].
However, Stokes
<nowiki>’</nowiki>
law must be modified with the use of non-Newtonian fluids and to account for the other particles in suspension in the slurry during the pumping operation. Ref. 3<ref name="r3">_</ref> provides a complete discussion on the factors that affect proppant transport and how Stokes<nowiki>’</nowiki>
law has been modified to account for many important factors. For example, at low proppant concentrations (1 to 3 ppg), the viscosity of the slurry is relatively unchanged. At high proppant concentrations (8 to 14 ppg), the slurry viscosity can be 3 to 10 times more than the viscosity of the clean fluid. Such factors must be recognized and included in any [[Fracture_propagation_models|fracture-propagation design model]].
There are other factors that must be included when trying to compute the propped fracture dimensions. The type of fracture fluid will affect proppant transport. Linear fracture fluid will not transport proppants as well as fluids with structure, such as crosslinked fluids or viscoelastic surfactant fluids. Geologic realities also must be considered. For example, no fracture is exactly vertical, and the walls of a fracture are rarely smooth. If there are turns and ledges along the fracture walls, these geologic features tend to reduce proppant settling when compared with the theoretical equations for transport in smooth-wall, parallel-plate systems. Smith ''et al.''<ref name="r4">_</ref> discussed other issues and presented several case histories in which fracture-treatment data were analyzed to determine the propped fracture dimensions. Smith stated that fracture height growth during and after pumping operations, fluid loss in layered formations, and slurry viscosity all affect the propped fracture dimensions.


There are other factors that must be included when trying to compute the propped fracture dimensions. The type of fracture fluid will affect proppant transport. Linear fracture fluid will not transport proppants as well as fluids with structure, such as crosslinked fluids or viscoelastic surfactant fluids. Geologic realities also must be considered. For example, no fracture is exactly vertical, and the walls of a fracture are rarely smooth. If there are turns and ledges along the fracture walls, these geologic features tend to reduce proppant settling when compared with the theoretical equations for transport in smooth-wall, parallel-plate systems. Smith ''et al.''<ref name="r4" /> discussed other issues and presented several case histories in which fracture-treatment data were analyzed to determine the propped fracture dimensions. Smith stated that fracture height growth during and after pumping operations, fluid loss in layered formations, and slurry viscosity all affect the propped fracture dimensions.
== Nomenclature ==
 
==Nomenclature==


{|
{|
|''d''<sub>''p''</sub>
|=
|proppant diameter, L
|-
|-
|''g''
| ''d''<sub>''p''</sub>
|=
| =
|gravitational constant
| proppant diameter, L
|-
|-
|''ρ''<sub>''p''</sub>
| ''g''
|=
| =
|proppant density, m/L<sup>3</sup>
| gravitational constant
|-
|-
|''ρ''<sub>''f''</sub>
| ''ρ''<sub>''p''</sub>
|=
| =
|fluid density, m/L<sup>3</sup>
| proppant density, m/L<sup>3</sup>
|-
|-
|''σ''<sub>min</sub>
| ''ρ''<sub>''f''</sub>
|=
| =
|minimum horizontal stress (in-situ stress), m/Lt<sup>2</sup>
| fluid density, m/L<sup>3</sup>
|-
|-
|''σ''<sub>ext</sub>
| ''σ''<sub>min</sub>
|=
| =
|tectonic stress, m/Lt<sup>2</sup>
| minimum horizontal stress (in-situ stress), m/Lt<sup>2</sup>
|-
|-
|''σ''<sub>min</sub>
| ''σ''<sub>ext</sub>
|=
| =
|minimum horizontal stress (in-situ stress), m/Lt<sup>2</sup>
| tectonic stress, m/Lt<sup>2</sup>
|-
|-
|''μ''
| ''σ''<sub>min</sub>
|=
| =
|fluid viscosity, m/Lt
| minimum horizontal stress (in-situ stress), m/Lt<sup>2</sup>
|-
|-
|''α''
| ''μ''
|=
| =
|Biot<nowiki>’</nowiki>s constant
| fluid viscosity, m/Lt
|-
|-
|''ν''
| ''α''
|=
| =
|Poisson<nowiki>’</nowiki>s ratio
| Biot<nowiki>’</nowiki>
s constant
|-
|-
|''v''<sub>''t''</sub>
| ''ν''
|=
| =
|terminal settling velocity, ft/min
| Poisson<nowiki>’</nowiki>
s ratio
|-
| ''v''<sub>''t''</sub>
| =
| terminal settling velocity, ft/min
|}
|}


==References==
== References ==
<references>
 
<ref name="r1">Holditch, S.A. 1979. ''Criteria for propping agent selection.'' Dallas, Texas: Norton Co.</ref>
<references />
<ref name="r2">Veatch Jr., R.W. and Moschovidis, Z.A. 1986. An Overview of Recent Advances in Hydraulic Fracturing Technology. Presented at the International Meeting on Petroleum Engineering, Beijing, China, 17-20 March. SPE-14085-MS. http://dx.doi.org/10.2118/14085-MS.</ref>
 
<ref name="r3">Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. Proppant Transport. In ''Recent Advances in Hydraulic Fracturing,'' 12. Chap. 10, 210. Richardson, Texas: Monograph Series, SPE.</ref>
== Noteworthy papers in OnePetro ==
<ref name="r4">Smith, M.B., Bale, A., Britt, L.K. et al. 1997. Enhanced 2D Proppant Transport Simulation: The Key To Understanding Proppant Flowback and Post-Frac Productivity. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October. SPE-38610-MS. http://dx.doi.org/10.2118/38610-MS.</ref>
</references>


==Noteworthy papers in OnePetro==
SPE 77675 Review of 80 Field Studies demonstrating importance Increased Frac conductivity
SPE 77675 Review of 80 Field Studies demonstrating importance Increased Frac conductivity


Line 130: Line 141:
SPE 119242 How to use and misuse Proppant Crush Tests
SPE 119242 How to use and misuse Proppant Crush Tests


==External links==
== External links ==
 
[http://store.spe.org/Recent-Advances-In-Hydraulic-Fracturing--P66.aspx Recent Advances In Hydraulic Fracturing]
[http://store.spe.org/Recent-Advances-In-Hydraulic-Fracturing--P66.aspx Recent Advances In Hydraulic Fracturing]


http://www.barree.net/images/documents/c9-predicting-final-fracture-conductivity.pdf
[http://www.barree.net/images/documents/c9-predicting-final-fracture-conductivity.pdf http://www.barree.net/images/documents/c9-predicting-final-fracture-conductivity.pdf]
 
== See also ==
 
[[Fracture_treatment_design|Fracture treatment design]]


==See also==
[[Fracturing_fluids_and_additives|Fracturing fluids and additives]]
[[Fracture treatment design]]


[[Fracturing fluids and additives]]
[[Fracture_diagnostic_techniques|Fracture diagnostic techniques]]


[[Fracture diagnostic techniques]]
[[Fracture_mechanics|Fracture mechanics]]


[[Fracture mechanics]]
[[Fracture_propagation_models|Fracture propagation models]]


[[Fracture propagation models]]
[[Post-fracture_well_behavior|Post-fracture well behavior]]


[[Post-fracture well behavior]]
[[Hydraulic_fracturing|Hydraulic fracturing]]


[[Hydraulic fracturing]]
[[Fracture_treatment_design|Fracture treatment design]]


[[Fracture treatment design]]
[[PEH:Hydraulic_Fracturing]]


[[PEH:Hydraulic Fracturing]]
[[Category:2.5.2 Fracturing Materials (Fluids, Proppant)]]

Revision as of 15:09, 1 June 2015

Propping agents are required to "prop open" the fracture once the pumps are shut down and the fracture begins to close. The ideal propping agent is strong, resistant to crushing, resistant to corrosion, has a low density, and is readily available at low cost.[1] The products that best meet these desired traits are silica sand, resin-coated sand (RCS), and ceramic proppants.

Types of propping agents

Silica sand is obtamust be tested to be sure it has the necessary compressive strength to be used in any specific situation. Generally, sand is used to prop open fractures in shallow formations. Sand is much less expensive per pound than RCS or ceramic proppants.

RCS is stronger than sand and is used where more compressive strength is required to minimize proppant crushing. Some resins can be used to form a consolidated pack in the fracture, which will help to eliminate proppant flow back into the wellbore. RCS is more expensive than sand, but it has an effective density that is less than sand.

Ceramic proppants consist of:

  • Sintered bauxite
  • Intermediate-strength proppant (ISP)
  • Lightweight proppant (LWP)

The strength of a ceramic proppant is proportional to its density. Also, the higher-strength proppants, like sintered bauxite, cost more than ISP and LWP. Ceramic proppants are used to stimulate deep ( > 8,000 ft) wells where large values of in-situ stresses will apply large forces on the propping agent.

Factors affecting fracture conductivity

The fracture conductivity is the product of propped fracture width and the permeability of the propping agent, as Fig. 1 illustrates. The permeability of all the commonly used propping agents (sand, RCS, and the ceramic proppants) will be 100 to 200 + darcies when no stress has been applied to the propping agent. However, the conductivity of the fracture will be reduced during the life of the well because of:

  • Increasing stress on the propping agents
  • Stress corrosion affecting the proppant strength
  • Proppant crushing
  • Proppant embedment into the formation
  • Damage resulting from gel residue or fluid-loss additives

The effective stress on the propping agent is the difference between the in-situ stress and the flowing pressure in the fracture, as Fig. 2 illustrates. As the well is produced, the effective stress on the propping agent will normally increase because the value of the flowing bottomhole pressure will be decreasing. However, as Eq. 1 shows, the in-situ stress will decrease with time as the reservoir pressure declines. This phenomenon of decreasing in-situ stress as the reservoir pressure declines was proven conclusively by Salz.[2] Fig. 3 illustrates the differences in fracture conductivity as effective stress increases on the propping agent for a variety of commonly used propping agents. The data in Fig. 3 clearly show that for shallow wells, where the effective stress is less than 6,000 psi, sand can be used to create high-conductivity fractures. As the effective stress increases to larger and larger values, then the higher-strength, more-expensive propping agents must be used to create a high conductivity fracture.

RTENOTITLE....................(1)

where

σmin = the minimum horizontal stress,

ν = Poisson ’ s ratio, σ1 = overburden stress,

α = Biot ’ s constant, pp = reservoir fluid pressure or pore pressure, and

σext = tectonic stress.

  • Fig. 2—Effective stress on the propping agent.

    Fig. 2—Effective stress on the propping agent.

  • Fig. 3—Effect of stress on fracture conductivity from common propping agents.

    Fig. 3—Effect of stress on fracture conductivity from common propping agents.

When choosing a propping agent, a proppant that will maintain enough conductivity after all crushing and embedment occurs must be chosen. The effects of non-Darcy flow, multiphase flow, and gel residue damage should also be considered.

Proppant transport

To create a hydraulic fracture, fluid is injected at high rate and pressure into a wellbore and into a formation that is open to the wellbore. Viscous fluid flow within the fracture and tip effects create the net pressure required to generate the created width profile and the created fracture height. The volume of fluid pumped will affect the created fracture length. However, without pumping a propping agent into the fracture, the created fracture will close once the pumping operation ceases. The flow of oil and gas from the formation into the fracture is dependent on the propped fracture dimensions. The really important characteristics of a fracture are the propped width, height, and length distributions; therefore, proppant transport considerations are very important in designing a hydraulic fracture treatment. Fig. 4 illustrates the difference between the created fracture dimensions and the propped fracture dimensions.

  • Fig. 4—Difference between created and propped fracture dimensions.

    Fig. 4—Difference between created and propped fracture dimensions.

The first fluid pumped into a well during a fracture treatment is called the "prepad." The prepad is used to fill the casing and tubing, test the system for pressure, and break down the formation. Next, the pad fluid, which is the viscous fracturing fluid used during the treatment, is pumped. No propping agent has been added to the pad. The purpose of the pad is to create a tall, wide fracture that will accept the propping agent. Following the pad, the fluid containing propping agent, which is called the slurry, is pumped. The slurry moves into the fracture, transporting the propping agent. The particles move up, out, and down the fracture with the slurry. The particles also can settle in the fracture as a result of gravitational forces.

Daneshy[3] provided a thorough summary of proppant transport issues. The effects of gravity on proppant settling can be computed by beginning with Stokes ’ law. Eq. 2 is Stokes’ law for a single spherical particle of diameter dp and density ρp settling in a Newtonian fluid with a density of ρf and a viscosity of μ. RTENOTITLE....................(2)

Eq. 2 shows that the settling velocity will increase as the diameter and density of the propping agent increase and as the density and viscosity of the fracturing fluid decrease. To minimize proppant settling, propping agents that are smaller in diameter and/or less dense, as well as a more viscous fluid, can be used.

However, Stokes ’ law must be modified with the use of non-Newtonian fluids and to account for the other particles in suspension in the slurry during the pumping operation. Ref. 3[3] provides a complete discussion on the factors that affect proppant transport and how Stokes’ law has been modified to account for many important factors. For example, at low proppant concentrations (1 to 3 ppg), the viscosity of the slurry is relatively unchanged. At high proppant concentrations (8 to 14 ppg), the slurry viscosity can be 3 to 10 times more than the viscosity of the clean fluid. Such factors must be recognized and included in any fracture-propagation design model. There are other factors that must be included when trying to compute the propped fracture dimensions. The type of fracture fluid will affect proppant transport. Linear fracture fluid will not transport proppants as well as fluids with structure, such as crosslinked fluids or viscoelastic surfactant fluids. Geologic realities also must be considered. For example, no fracture is exactly vertical, and the walls of a fracture are rarely smooth. If there are turns and ledges along the fracture walls, these geologic features tend to reduce proppant settling when compared with the theoretical equations for transport in smooth-wall, parallel-plate systems. Smith et al.[4] discussed other issues and presented several case histories in which fracture-treatment data were analyzed to determine the propped fracture dimensions. Smith stated that fracture height growth during and after pumping operations, fluid loss in layered formations, and slurry viscosity all affect the propped fracture dimensions.

Nomenclature

dp = proppant diameter, L
g = gravitational constant
ρp = proppant density, m/L3
ρf = fluid density, m/L3
σmin = minimum horizontal stress (in-situ stress), m/Lt2
σext = tectonic stress, m/Lt2
σmin = minimum horizontal stress (in-situ stress), m/Lt2
μ = fluid viscosity, m/Lt
α = Biot’

s constant

ν = Poisson’

s ratio

vt = terminal settling velocity, ft/min

References

  1. ↑ _
  2. ↑ _
  3. ↑ 3.0 3.1 _
  4. ↑ _

Noteworthy papers in OnePetro

SPE 77675 Review of 80 Field Studies demonstrating importance Increased Frac conductivity

SPE 90620_Investigating the Benefits of Increased Fracture Conductivity in the Low-Permeability Sandstones

SPE 119242 How to use and misuse Proppant Crush Tests

External links

Recent Advances In Hydraulic Fracturing

http://www.barree.net/images/documents/c9-predicting-final-fracture-conductivity.pdf

See also

Fracture treatment design

Fracturing fluids and additives

Fracture diagnostic techniques

Fracture mechanics

Fracture propagation models

Post-fracture well behavior

Hydraulic fracturing

Fracture treatment design

PEH:Hydraulic_Fracturing

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