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Difference between revisions of "Fluid flow with formation damage"

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[[Formation damage]] caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability.  
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[[Formation_damage|Formation damage]] caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability.
  
==Permeability reduction and formation damage==
+
== Permeability reduction and formation damage ==
When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
 
  
The production process may also reduce permeability and introduce a positive skin factor. For example, in an otherwise undersaturated oil reservoir, pressure near the well may be below the bubblepoint pressure, causing a free-gas saturation and reducing the effective permeability to oil. In a retrograde gas reservoir, the pressure near the wellbore may drop below the dewpoint and an immobile liquid phase may form and reduce the effective permeability to gas near the wellbore.  
+
When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
  
Injection can also cause damage. The water injected may be dirty; that is, it may contain fines that may plug the formation and reduce permeability. In other cases, the injected water may be incompatible with the formation water, causing solids to precipitate and plug the formation. In still other cases, the injected water may be incompatible with clays in the formation (e.g., fresh water can destabilize some clays, causing fines to migrate and plug the formation).  
+
The production process may also reduce permeability and introduce a positive skin factor. For example, in an otherwise undersaturated oil reservoir, pressure near the well may be below the bubblepoint pressure, causing a free-gas saturation and reducing the effective permeability to oil. In a retrograde gas reservoir, the pressure near the wellbore may drop below the dewpoint and an immobile liquid phase may form and reduce the effective permeability to gas near the wellbore.
 +
 
 +
Injection can also cause damage. The water injected may be dirty; that is, it may contain fines that may plug the formation and reduce permeability. In other cases, the injected water may be incompatible with the formation water, causing solids to precipitate and plug the formation. In still other cases, the injected water may be incompatible with clays in the formation (e.g., fresh water can destabilize some clays, causing fines to migrate and plug the formation).
  
 
== Altered zone and skin effect ==
 
== Altered zone and skin effect ==
A two-region reservoir model ('''Fig. 1''') is a convenient representation of a damaged well (and some stimulated wells with radially symmetric permeability alteration around the wellbore). In this model, the altered zone around the wellbore is assumed to have uniform permeability ''k''<sub>''s''</sub> out to a radius ''r''<sub>''s''</sub>, beyond which the formation permeability, ''k'', is unaltered.  
+
 
 +
A two-region reservoir model ('''Fig. 1''') is a convenient representation of a damaged well (and some stimulated wells with radially symmetric permeability alteration around the wellbore). In this model, the altered zone around the wellbore is assumed to have uniform permeability ''k''<sub>''s''</sub> out to a radius ''r''<sub>''s''</sub>, beyond which the formation permeability, ''k'', is unaltered.
  
 
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For a damaged well, the reduced permeability in the altered zone causes an additional pressure drop, Δ''p''<sub>''s''</sub> ('''Fig. 2'''). The dimensionless skin factor, ''s'', and the additional pressure drop across the altered zone are related by
 
For a damaged well, the reduced permeability in the altered zone causes an additional pressure drop, Δ''p''<sub>''s''</sub> ('''Fig. 2'''). The dimensionless skin factor, ''s'', and the additional pressure drop across the altered zone are related by
  
[[File:Vol5 page 0748 eq 002.png]]....................(1)
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[[File:Vol5 page 0748 eq 002.png|RTENOTITLE]]....................(1)
  
For a well with a known skin factor, ''s'', '''Eq. 1''' provides a method of translating the somewhat abstract dimensionless skin factor into a more concrete characterization of the practical effect of damage or stimulation.  
+
For a well with a known skin factor, ''s'', '''Eq. 1''' provides a method of translating the somewhat abstract dimensionless skin factor into a more concrete characterization of the practical effect of damage or stimulation.
  
 
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In a two-region reservoir model, the skin factor, ''s'', is related to the properties of the altered zone:
 
In a two-region reservoir model, the skin factor, ''s'', is related to the properties of the altered zone:
  
[[File:Vol5 page 0750 eq 001.png]]....................(2)
+
[[File:Vol5 page 0750 eq 001.png|RTENOTITLE]]....................(2)
  
 
Rearrange '''Eq. 2''' and solve for the permeability of the altered zone:
 
Rearrange '''Eq. 2''' and solve for the permeability of the altered zone:
  
[[File:Vol5 page 0750 eq 002.png]]....................(3)
+
[[File:Vol5 page 0750 eq 002.png|RTENOTITLE]]....................(3)
  
 
Rearrangements of '''Eq. 2''' provide a second method of translating skin into a more concrete characterization of a well with altered permeability near the wellbore. If the depth of damage can be estimated for a well with a known skin factor, ''s'', the permeability of the altered zone can be estimated. Even if the depth of permeability alteration, ''r''<sub>''s''</sub>, is estimated '''Eq. 3''' can still provide a reasonable estimate of altered zone permeability because ''r''<sub>''s''</sub> appears in a logarithmic term. Alternatively, an estimate of the permeability reduction ratio (for example, from laboratory tests on cores) can produce an estimate of the depth of damage from another rearrangement of '''Eq. 2''',
 
Rearrangements of '''Eq. 2''' provide a second method of translating skin into a more concrete characterization of a well with altered permeability near the wellbore. If the depth of damage can be estimated for a well with a known skin factor, ''s'', the permeability of the altered zone can be estimated. Even if the depth of permeability alteration, ''r''<sub>''s''</sub>, is estimated '''Eq. 3''' can still provide a reasonable estimate of altered zone permeability because ''r''<sub>''s''</sub> appears in a logarithmic term. Alternatively, an estimate of the permeability reduction ratio (for example, from laboratory tests on cores) can produce an estimate of the depth of damage from another rearrangement of '''Eq. 2''',
  
[[File:Vol5 page 0750 eq 003.png]]....................(4)
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[[File:Vol5 page 0750 eq 003.png|RTENOTITLE]]....................(4)
  
 
== Apparent wellbore radius ==
 
== Apparent wellbore radius ==
 +
 
A third method of translating skin to a more concrete characterization of near-well conditions is to calculate apparent or effective wellbore radius, ''r''<sub>''wa''</sub>. Apparent wellbore radius is defined as
 
A third method of translating skin to a more concrete characterization of near-well conditions is to calculate apparent or effective wellbore radius, ''r''<sub>''wa''</sub>. Apparent wellbore radius is defined as
  
[[File:Vol5 page 0750 eq 004.png]]....................(5)
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[[File:Vol5 page 0750 eq 004.png|RTENOTITLE]]....................(5)
  
[[File:Vol5 page 0750 eq 005.png]]....................(6)
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[[File:Vol5 page 0750 eq 005.png|RTENOTITLE]]....................(6)
  
For a stimulated well, the pressure drawdown at the wellbore is the same as it would be in a formation with unaltered permeability but with wellbore radius equal to the apparent wellbore radius. This concept has value in some simulation applications. Note that ''r''<sub>''wa''</sub> can be calculated from the actual wellbore radius and skin factor.  
+
For a stimulated well, the pressure drawdown at the wellbore is the same as it would be in a formation with unaltered permeability but with wellbore radius equal to the apparent wellbore radius. This concept has value in some simulation applications. Note that ''r''<sub>''wa''</sub> can be calculated from the actual wellbore radius and skin factor.
  
 
'''Eqs. 5''' and '''6''' are also useful to illustrate the minimum (i.e., the most-negative possible) skin factor. This minimum skin, ''s''<sub>min</sub>, occurs when the apparent wellbore radius is equal to the drainage radius of the well:
 
'''Eqs. 5''' and '''6''' are also useful to illustrate the minimum (i.e., the most-negative possible) skin factor. This minimum skin, ''s''<sub>min</sub>, occurs when the apparent wellbore radius is equal to the drainage radius of the well:
  
[[File:Vol5 page 0750 eq 006.png]]....................(7)
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[[File:Vol5 page 0750 eq 006.png|RTENOTITLE]]....................(7)
  
For a well with a circular drainage area of 40 acres for which ''r''<sub>''e''</sub> is 745 ft and a wellbore radius of 0.3 ft, the minimum skin (maximum stimulation) is ''s''<sub>min</sub> = - ln(''r''<sub>''e''</sub>/''r''<sub>''w''</sub>) = −(745/0.3) = −7.82. Such a skin implies increasing the permeability throughout the entire altered zone to infinity—clearly an idealistic "upper limit." More realistically, research<ref name="r1" /> has shown that the half-length, ''L''<sub>''f''</sub>, of a highly conductive vertical fracture is related to ''r''<sub>''wa''</sub> by
+
For a well with a circular drainage area of 40 acres for which ''r''<sub>''e''</sub> is 745 ft and a wellbore radius of 0.3 ft, the minimum skin (maximum stimulation) is ''s''<sub>min</sub> = - ln(''r''<sub>''e''</sub>/''r''<sub>''w''</sub>) = −(745/0.3) = −7.82. Such a skin implies increasing the permeability throughout the entire altered zone to infinity—clearly an idealistic "upper limit." More realistically, research<ref name="r1">Prats, M., Hazebroek, P., and Strickler, W.R. 1962. Effect of Vertical Fractures on Reservoir Behavior--Compressible-Fluid Case. SPE J. 2 (2): 87-94. http://dx.doi.org/10.2118/98-PA</ref> has shown that the half-length, ''L''<sub>''f''</sub>, of a highly conductive vertical fracture is related to ''r''<sub>''wa''</sub> by
  
[[File:Vol5 page 0751 eq 001.png]]....................(8)
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[[File:Vol5 page 0751 eq 001.png|RTENOTITLE]]....................(8)
  
or [[File:Vol5 page 0751 eq 002.png]]....................(9)
+
or [[File:Vol5 page 0751 eq 002.png|RTENOTITLE]]....................(9)
  
Thus, for ''L''<sub>''f''</sub> = ''r''<sub>''e''</sub> = 745 ft, ''s'' = −7.12 is a more realistic minimum (for the given drainage radius and wellbore radius).  
+
Thus, for ''L''<sub>''f''</sub> = ''r''<sub>''e''</sub> = 745 ft, ''s'' = −7.12 is a more realistic minimum (for the given drainage radius and wellbore radius).
  
 
== Flow efficiency ==
 
== Flow efficiency ==
 +
 
A fourth way to characterize a well with nonzero skin is to calculate the flow efficiency of the well. Flow efficiency, ''E''<sub>''f''</sub>, is defined as the ratio of the actual productivity index of the well (including skin) to the ideal productivity index if the skin factor were zero. Because the productivity index is the ratio of stabilized flow rate to pressure drop required to sustain that stabilized rate,
 
A fourth way to characterize a well with nonzero skin is to calculate the flow efficiency of the well. Flow efficiency, ''E''<sub>''f''</sub>, is defined as the ratio of the actual productivity index of the well (including skin) to the ideal productivity index if the skin factor were zero. Because the productivity index is the ratio of stabilized flow rate to pressure drop required to sustain that stabilized rate,
  
[[File:Vol5 page 0751 eq 003.png]]....................(10)
+
[[File:Vol5 page 0751 eq 003.png|RTENOTITLE]]....................(10)
  
[[File:Vol5 page 0751 eq 004.png]]....................(11)
+
[[File:Vol5 page 0751 eq 004.png|RTENOTITLE]]....................(11)
  
and [[File:Vol5 page 0751 eq 005.png]]....................(12)
+
and [[File:Vol5 page 0751 eq 005.png|RTENOTITLE]]....................(12)
  
For a well with neither damage nor stimulation, ''E''<sub>''f''</sub> = 1; for a damaged well, ''E''<sub>''f''</sub> < 1; and for a stimulated well, ''E''<sub>''f''</sub> > 1.  
+
For a well with neither damage nor stimulation, ''E''<sub>''f''</sub> = 1; for a damaged well, ''E''<sub>''f''</sub> < 1; and for a stimulated well, ''E''<sub>''f''</sub> > 1.
  
 
== Geometric skin ==
 
== Geometric skin ==
When the area open to flow decreases, the pressure drop is greater than when the area is unchanged all the way to the formation face. Examples include flow converging to perforations ('''Fig. 3'''), partial penetration ('''Fig. 4'''), and an incompletely perforated interval ('''Fig. 5''').  
+
 
 +
When the area open to flow decreases, the pressure drop is greater than when the area is unchanged all the way to the formation face. Examples include flow converging to perforations ('''Fig. 3'''), partial penetration ('''Fig. 4'''), and an incompletely perforated interval ('''Fig. 5''').
  
 
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</gallery>
 
</gallery>
  
'''Fig. 3''' illustrates flow converging into perforations. When the perforation spacing is too large, this converging flow results in a positive skin factor. The skin increases as vertical permeability decreases and increases as shot density decreases.  
+
'''Fig. 3''' illustrates flow converging into perforations. When the perforation spacing is too large, this converging flow results in a positive skin factor. The skin increases as vertical permeability decreases and increases as shot density decreases.
  
===Partial penetration===
+
=== Partial penetration ===
'''Fig. 4''' illustrates flow converging into an interval that is only partly penetrated by perforations. When a well is completed in only a fraction of the productive interval, the flow must converge through a smaller area, increasing the pressure drop near the well (compared to a fully completed interval). The additional pressure drop near the well results in a more positive skin. It increases as the vertical permeability decreases and as the perforated interval as a fraction of the total interval decreases. Formation damage (reduced permeability) near the completion face can significantly increase the additional pressure drop and thus the calculated skin factor.  
+
 
 +
'''Fig. 4''' illustrates flow converging into an interval that is only partly penetrated by perforations. When a well is completed in only a fraction of the productive interval, the flow must converge through a smaller area, increasing the pressure drop near the well (compared to a fully completed interval). The additional pressure drop near the well results in a more positive skin. It increases as the vertical permeability decreases and as the perforated interval as a fraction of the total interval decreases. Formation damage (reduced permeability) near the completion face can significantly increase the additional pressure drop and thus the calculated skin factor.
 +
 
 +
=== Incompletely perforated interval ===
  
===Incompletely perforated interval===
 
 
Partial penetration is a special case of an incompletely perforated interval ('''Fig. 5'''). In the general case, the well is perforated starting at a distance ''h''<sub>1</sub> from the top of the productive interval and has perforations extending over a distance, ''h''<sub>''p''</sub>, in an interval of total thickness, ''h''. The total skin for the well in this general situation is
 
Partial penetration is a special case of an incompletely perforated interval ('''Fig. 5'''). In the general case, the well is perforated starting at a distance ''h''<sub>1</sub> from the top of the productive interval and has perforations extending over a distance, ''h''<sub>''p''</sub>, in an interval of total thickness, ''h''. The total skin for the well in this general situation is
  
[[File:Vol5 page 0753 eq 001.png]]....................(13)
+
[[File:Vol5 page 0753 eq 001.png|RTENOTITLE]]....................(13)
 +
 
 +
In '''Eq. 13''', ''s''<sub>''d''</sub> is the skin caused by formation damage, and s p is the skin resulting from an incompletely perforated interval. This equation is not valid for a stimulated well.
  
In '''Eq. 13''', ''s''<sub>''d''</sub> is the skin caused by formation damage, and s p is the skin resulting from an incompletely perforated interval. This equation is not valid for a stimulated well.  
+
The skin factor for an incompletely perforated interval, ''s''<sub>''p''</sub>, can be quantified by<ref name="r2">Papatzacos, P. 1987. Approximate Partial-Penetration Pseudoskin for Infinite-Conductivity Wells. SPE Res Eng 2 (2): 227–234. SPE-13956-PA. http://dx.doi.org/10.2118/13956-PA</ref>
  
The skin factor for an incompletely perforated interval, ''s''<sub>''p''</sub>, can be quantified by<ref name="r2" />
+
[[File:Vol5 page 0753 eq 002.png|RTENOTITLE]]....................(14)
  
[[File:Vol5 page 0753 eq 002.png]]....................(14)
+
where [[File:Vol5 page 0753 eq 003.png|RTENOTITLE]]....................(15)
  
where [[File:Vol5 page 0753 eq 003.png]]....................(15)
+
[[File:Vol5 page 0753 eq 004.png|RTENOTITLE]]....................(16)
  
[[File:Vol5 page 0753 eq 004.png]]....................(16)
+
[[File:Vol5 page 0753 eq 005.png|RTENOTITLE]]....................(17)
  
[[File:Vol5 page 0753 eq 005.png]]....................(17)
+
[[File:Vol5 page 0753 eq 006.png|RTENOTITLE]]....................(18)
  
[[File:Vol5 page 0753 eq 006.png]]....................(18)
+
and [[File:Vol5 page 0753 eq 007.png|RTENOTITLE]]....................(19)
  
and [[File:Vol5 page 0753 eq 007.png]]....................(19)
+
The most significant limitation in applying '''Eq. 14''' in practice is the difficulty in estimating accurately the vertical-to-horizontal-permeability ratio, ''k''<sub>''v''</sub>/''k''<sub>''h''</sub>. Fortunately, this ratio appears only in a logarithmic term in '''Eq. 14''', so errors will not seriously distort the calculated value of ''s''<sub>''p''</sub>.
  
The most significant limitation in applying '''Eq. 14''' in practice is the difficulty in estimating accurately the vertical-to-horizontal-permeability ratio, ''k''<sub>''v''</sub>/''k''<sub>''h''</sub>. Fortunately, this ratio appears only in a logarithmic term in '''Eq. 14''', so errors will not seriously distort the calculated value of ''s''<sub>''p''</sub>.
+
=== Deviated well ===
  
===Deviated well===
 
 
For a deviated well ('''Fig. 6'''), which penetrates the formation at an angle other than 90°, more surface is in contact with the formation. This introduces a negative skin factor, ''s''<sub>''θ''</sub>, which makes the total skin factor, ''s'', more negative.
 
For a deviated well ('''Fig. 6'''), which penetrates the formation at an angle other than 90°, more surface is in contact with the formation. This introduces a negative skin factor, ''s''<sub>''θ''</sub>, which makes the total skin factor, ''s'', more negative.
  
[[File:Vol5 page 0753 eq 008.png]]....................(20)
+
[[File:Vol5 page 0753 eq 008.png|RTENOTITLE]]....................(20)
 +
 
 +
The effect increases as the vertical permeability increases and increases as the angle from the vertical, ''θ''<sub>''w''</sub>, increases. The deviated well skin factor, ''s''<sub>''θ''</sub>, is given by a correlation of simulated results<ref name="r3">Cinco, H., Miller, F.G., and Ramey, H.J. Jr.: "Unsteady-State Pressure Distribution Created by a Directionally Drilled Well," JPT (November 1975) 1392; Trans., AIME, 259. SPE-5131-PA. http://dx.doi.org/10.2118/5131-PA</ref> (valid for ''θ''<sub>''w''</sub> < 75°):
  
The effect increases as the vertical permeability increases and increases as the angle from the vertical, ''θ''<sub>''w''</sub>, increases. The deviated well skin factor, ''s''<sub>''θ''</sub>, is given by a correlation of simulated results<ref name="r3" /> (valid for ''θ''<sub>''w''</sub> < 75°):
+
[[File:Vol5 page 0753 eq 009.png|RTENOTITLE]]....................(21)
  
[[File:Vol5 page 0753 eq 009.png]]....................(21)
+
where [[File:Vol5 page 0753 eq 010.png|RTENOTITLE]]....................(22)
  
where [[File:Vol5 page 0753 eq 010.png]]....................(22)
+
and [[File:Vol5 page 0753 eq 011.png|RTENOTITLE]]....................(23)
  
and [[File:Vol5 page 0753 eq 011.png]]....................(23)
+
=== Gravel-pack skin ===
  
===Gravel-pack skin===
+
When a well is gravel packed ('''Fig. 7'''), there is a pressure drop through the gravel pack within the perforations, given by<ref name="r4">Brown, K.E. 1984. The Technology of Artificial Lift Methods, Vol. 4, 134. Tulsa, Oklahoma: PennWell.</ref>
When a well is gravel packed ('''Fig. 7'''), there is a pressure drop through the gravel pack within the perforations, given by<ref name="r4" />
 
  
[[File:Vol5 page 0754 eq 001.png]]....................(24)
+
[[File:Vol5 page 0754 eq 001.png|RTENOTITLE]]....................(24)
  
where ''s''<sub>''gp''</sub> is the skin factor because of Darcy flow through the gravel pack; ''h'', the net pay thickness, ft; ''k''<sub>''gp''</sub>, the permeability of the gravel in the gravel pack, md; ''k'', the reservoir permeability, md; ''L''<sub>''g''</sub>, the length of the flow path through the gravel pack, ft; ''n'', the number of perforations open; and ''r''<sub>''p''</sub>, the radius of the perforation tunnel, ft. '''Eq. 24''' does not include the effects of non-Darcy flow, which may be extremely important in high-rate gas wells.  
+
where ''s''<sub>''gp''</sub> is the skin factor because of Darcy flow through the gravel pack; ''h'', the net pay thickness, ft; ''k''<sub>''gp''</sub>, the permeability of the gravel in the gravel pack, md; ''k'', the reservoir permeability, md; ''L''<sub>''g''</sub>, the length of the flow path through the gravel pack, ft; ''n'', the number of perforations open; and ''r''<sub>''p''</sub>, the radius of the perforation tunnel, ft. '''Eq. 24''' does not include the effects of non-Darcy flow, which may be extremely important in high-rate gas wells.
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
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</gallery>
 
</gallery>
  
===Completion skin===
+
=== Completion skin ===
For a perforated well, any reduced permeability, ''k''<sub>''dp''</sub>, in the zone surrounding the perforations ('''Fig. 8''') introduces an additional pressure drop. The additional skin is<ref name="r5" />
+
 
 +
For a perforated well, any reduced permeability, ''k''<sub>''dp''</sub>, in the zone surrounding the perforations ('''Fig. 8''') introduces an additional pressure drop. The additional skin is<ref name="r5">McLeod, H.O.J. 1983. The Effect of Perforating Conditions on Well Performance. Journal of Petroleum Technology 35 (1): 31–39. SPE-10649-PA. http://dx.doi.org/10.2118/10649-PA</ref>
  
[[File:Vol5 page 0754 eq 002.png]]....................(25)
+
[[File:Vol5 page 0754 eq 002.png|RTENOTITLE]]....................(25)
  
and [[File:Vol5 page 0754 eq 003.png]]....................(26)
+
and [[File:Vol5 page 0754 eq 003.png|RTENOTITLE]]....................(26)
  
where ''s''<sub>''p''</sub> is the geometric skin from flow converging to the perforations; ''s''<sub>''d''</sub>, the damage skin; ''s''<sub>''dp''</sub>, perforation damage skin; ''k''<sub>''d''</sub>, permeability of the damaged zone around the wellbore, md; ''k''<sub>''dp''</sub>, permeability of the damaged zone around perforation tunnels, md; ''k'', reservoir permeability, md; ''L''<sub>''p''</sub>, length of perforation tunnel, ft; ''n'', number of perforations; ''h'', formation thickness, ft; ''r''<sub>''d''</sub>, radius of the damaged zone around the wellbore, ft; ''r''<sub>''dp''</sub>, radius of the damages zone around the perforation tunnel, ft; ''r''<sub>''p''</sub>, radius of the perforation tunnel, ft; and ''r''<sub>''w''</sub>, wellbore radius, ft. '''Eq. 26''' does not include the effects of non-Darcy flow.  
+
where ''s''<sub>''p''</sub> is the geometric skin from flow converging to the perforations; ''s''<sub>''d''</sub>, the damage skin; ''s''<sub>''dp''</sub>, perforation damage skin; ''k''<sub>''d''</sub>, permeability of the damaged zone around the wellbore, md; ''k''<sub>''dp''</sub>, permeability of the damaged zone around perforation tunnels, md; ''k'', reservoir permeability, md; ''L''<sub>''p''</sub>, length of perforation tunnel, ft; ''n'', number of perforations; ''h'', formation thickness, ft; ''r''<sub>''d''</sub>, radius of the damaged zone around the wellbore, ft; ''r''<sub>''dp''</sub>, radius of the damages zone around the perforation tunnel, ft; ''r''<sub>''p''</sub>, radius of the perforation tunnel, ft; and ''r''<sub>''w''</sub>, wellbore radius, ft. '''Eq. 26''' does not include the effects of non-Darcy flow.
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
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</gallery>
 
</gallery>
  
===Hydraulically fractured wells===
+
=== Hydraulically fractured wells ===
Wells are frequently [[Hydraulic fracturing|fractured hydraulically]] to improve their productivity, especially in low-permeability formations where fractures increase the effective drained area and in high-permeability formations where they penetrate near-well damage or promote sand control. These fractures, almost always vertical ('''Fig. 9'''), are high-conductivity paths between the reservoir and the wellbore. If the fracture conductivity is large enough relative to the formation permeability and fracture length, the pressure drop within the fracture will be negligible. This distributes the pressure drop caused by fluid influx into the wellbore over a much larger area, resulting in a negative skin factor, which is interpreted as a geometric skin.  
+
 
 +
Wells are frequently [[Hydraulic_fracturing|fractured hydraulically]] to improve their productivity, especially in low-permeability formations where fractures increase the effective drained area and in high-permeability formations where they penetrate near-well damage or promote sand control. These fractures, almost always vertical ('''Fig. 9'''), are high-conductivity paths between the reservoir and the wellbore. If the fracture conductivity is large enough relative to the formation permeability and fracture length, the pressure drop within the fracture will be negligible. This distributes the pressure drop caused by fluid influx into the wellbore over a much larger area, resulting in a negative skin factor, which is interpreted as a geometric skin.
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
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Dimensionless fracture conductivity, ''C''<sub>''r''</sub>, is defined by
 
Dimensionless fracture conductivity, ''C''<sub>''r''</sub>, is defined by
  
[[File:Vol5 page 0756 eq 001.png]]....................(27)
+
[[File:Vol5 page 0756 eq 001.png|RTENOTITLE]]....................(27)
  
where ''w''<sub>''f''</sub> is the fracture length, ft; ''k''<sub>''f''</sub>, the permeability of the proppant in the fracture; ''k'', the formation permeability, md; and ''L''<sub>''f''</sub>, the fracture half-length, ft. Pressure drop in the fracture is negligible for ''C''<sub>''r''</sub> > 100.  
+
where ''w''<sub>''f''</sub> is the fracture length, ft; ''k''<sub>''f''</sub>, the permeability of the proppant in the fracture; ''k'', the formation permeability, md; and ''L''<sub>''f''</sub>, the fracture half-length, ft. Pressure drop in the fracture is negligible for ''C''<sub>''r''</sub> > 100.
 +
 
 +
== Nomenclature ==
  
==Nomenclature==
 
 
{|
 
{|
|''B''
 
|=
 
|formation volume factor, res vol/surface vol
 
 
|-
 
|-
|''c''<sub>''t''</sub>
+
| ''B''
|=  
+
| =
|''S''<sub>''o''</sub>''c''<sub>''o''</sub> + ''S''<sub>''w''</sub>''c''<sub>''w''</sub> +  ''S''<sub>''g''</sub>''c''<sub>''g''</sub> + ''c''<sub>''f''</sub> = total compressibility, psi<sup>–1</sup>
+
| formation volume factor, res vol/surface vol
 
|-
 
|-
|''C''  
+
| ''c''<sub>''t''</sub>
|=  
+
| =
|performance coefficient in gas-well deliverability equation, or wellbore storage coefficient, bbl/psi
+
| ''S''<sub>''o''</sub>''c''<sub>''o''</sub> + ''S''<sub>''w''</sub>''c''<sub>''w''</sub> + ''S''<sub>''g''</sub>''c''<sub>''g''</sub> + ''c''<sub>''f''</sub> = total compressibility, psi<sup>–1</sup>
 
|-
 
|-
|''C''<sub>''D''</sub>
+
| ''C''
|=  
+
| =
|0.8936 ''C''/''ϕc''<sub>''t''</sub>''hr''<sub>''w''</sub><sup>2</sup> , dimensionless wellbore storage coefficient  
+
| performance coefficient in gas-well deliverability equation, or wellbore storage coefficient, bbl/psi
 
|-
 
|-
|''C''<sub>''r''</sub>  
+
| ''C''<sub>''D''</sub>
|=  
+
| =
|''w''<sub>''f''</sub>''k''<sub>''f''</sub>/''πkL''<sub>''f''</sub>, fracture conductivity, dimensionless  
+
| 0.8936 ''C''/''ϕc''<sub>''t''</sub>''hr''<sub>''w''</sub><sup>2</sup> , dimensionless wellbore storage coefficient
 
|-
 
|-
|''Ei''(–''x'')
+
| ''C''<sub>''r''</sub>
|=  
+
| =
|[[File:Vol5 page 0881 inline 001.png]], the exponential integral
+
| ''w''<sub>''f''</sub>''k''<sub>''f''</sub>/''πkL''<sub>''f''</sub>, fracture conductivity, dimensionless
 
|-
 
|-
|''h''  
+
| ''Ei''(–''x'')
|=  
+
| =
|net formation thickness, ft
+
| [[File:Vol5 page 0881 inline 001.png|RTENOTITLE]], the exponential integral
 
|-
 
|-
|''h''<sub>''p''</sub>
+
| ''h''
|=  
+
| =
|perforated interval thickness, ft  
+
| net formation thickness, ft
 
|-
 
|-
|''h''<sub>''pD''</sub>  
+
| ''h''<sub>''p''</sub>
|=  
+
| =
|''h''<sub>''p''</sub>/''h''<sub>''t''</sub>
+
| perforated interval thickness, ft
 
|-
 
|-
|''h''<sub>''t''</sub>  
+
| ''h''<sub>''pD''</sub>
|=  
+
| =
|total formation thickness, ft
+
| ''h''<sub>''p''</sub>/''h''<sub>''t''</sub>
 
|-
 
|-
|''J''  
+
| ''h''<sub>''t''</sub>
|=  
+
| =
|productivity index, STB/D, psi
+
| total formation thickness, ft
 
|-
 
|-
|''J''<sub>actual</sub>
+
| ''J''
|=  
+
| =
|actual well productivity index, STB/D-psi  
+
| productivity index, STB/D, psi
 
|-
 
|-
|''J''<sub>ideal</sub>  
+
| ''J''<sub>actual</sub>
|=  
+
| =
|ideal productivity index (''s'' = 0), STB/D-psi  
+
| actual well productivity index, STB/D-psi
 
|-
 
|-
|''k''  
+
| ''J''<sub>ideal</sub>
|=  
+
| =
|matrix permeability, md
+
| ideal productivity index (''s'' = 0), STB/D-psi
 
|-
 
|-
|''k''<sub>''h''</sub>
+
| ''k''
|=  
+
| =
|horizontal permeability, md  
+
| matrix permeability, md
 
|-
 
|-
|''k''<sub>''s''</sub>  
+
| ''k''<sub>''h''</sub>
|=  
+
| =
|permeability of altered zone, md  
+
| horizontal permeability, md
 
|-
 
|-
|''L''<sub>''f''</sub>  
+
| ''k''<sub>''s''</sub>
|=  
+
| =
|fracture half length, ft
+
| permeability of altered zone, md
 
|-
 
|-
|''p''  
+
| ''L''<sub>''f''</sub>
|=  
+
| =
|pressure, psi
+
| fracture half length, ft
 
|-
 
|-
|''p''<sub>''wf''</sub>
+
| ''p''
|=  
+
| =
|flowing BHP, psi  
+
| pressure, psi
 
|-
 
|-
|''p''<sub>''D''</sub>  
+
| ''p''<sub>''wf''</sub>
|=  
+
| =
|0.00708 ''kh''(''p''<sub>''i''</sub> – ''p'')/''qBμ'', dimensionless pressure as defined for constant-rate production
+
| flowing BHP, psi
 
|-
 
|-
|''p''<sub>''s''</sub>  
+
| ''p''<sub>''D''</sub>
|=  
+
| =
|stabilized shut-in BHP measured just before start of a deliverability test, psia
+
| 0.00708 ''kh''(''p''<sub>''i''</sub> – ''p'')/''qBμ'', dimensionless pressure as defined for constant-rate production
 
|-
 
|-
|''q''  
+
| ''p''<sub>''s''</sub>
|=  
+
| =
|flow rate at surface, STB/D
+
| stabilized shut-in BHP measured just before start of a deliverability test, psia
 
|-
 
|-
|''r''  
+
| ''q''
|=  
+
| =
|distance from the center of wellbore, ft
+
| flow rate at surface, STB/D
 
|-
 
|-
|''r''<sub>''e''</sub>
+
| ''r''
|=  
+
| =
|external drainage radius, ft  
+
| distance from the center of wellbore, ft
 
|-
 
|-
|''r''<sub>''w''</sub>  
+
| ''r''<sub>''e''</sub>
|=  
+
| =
|wellbore radius, ft  
+
| external drainage radius, ft
 
|-
 
|-
|''r''<sub>''wa''</sub>  
+
| ''r''<sub>''w''</sub>
|=  
+
| =
|apparent or effective wellbore radius, ft  
+
| wellbore radius, ft
 
|-
 
|-
|''r''<sub>''D''</sub>  
+
| ''r''<sub>''wa''</sub>
|=  
+
| =
|''r''/''r''<sub>''w''</sub>, dimensionless radius
+
| apparent or effective wellbore radius, ft
 
|-
 
|-
|''r''<sub>''s''</sub>  
+
| ''r''<sub>''D''</sub>
|=  
+
| =
|outer radius of the altered zone, ft
+
| ''r''/''r''<sub>''w''</sub>, dimensionless radius
 
|-
 
|-
|''s''  
+
| ''r''<sub>''s''</sub>
|=  
+
| =
|skin factor, dimensionless
+
| outer radius of the altered zone, ft
 
|-
 
|-
|''s''<sub>''d''</sub>
+
| ''s''
|=  
+
| =
|skin caused by formation damage, dimensionless  
+
| skin factor, dimensionless
 
|-
 
|-
|''s''<sub>''dp''</sub>  
+
| ''s''<sub>''d''</sub>
|=  
+
| =
|perforation damage skin, dimensionless  
+
| skin caused by formation damage, dimensionless
 
|-
 
|-
|''s''<sub>''p''</sub>  
+
| ''s''<sub>''dp''</sub>
|=  
+
| =
|skin resulting from an incompletely perforated interval, dimensionless  
+
| perforation damage skin, dimensionless
 
|-
 
|-
|''s''<sub>''θ''</sub>  
+
| ''s''<sub>''p''</sub>
|=  
+
| =
|skin factor resulting from well inclination, dimensionless  
+
| skin resulting from an incompletely perforated interval, dimensionless
 
|-
 
|-
|''t''  
+
| ''s''<sub>''θ''</sub>
|=  
+
| =
|elapsed time, hours
+
| skin factor resulting from well inclination, dimensionless
 
|-
 
|-
|''t''<sub>''D''</sub>
+
| ''t''
|=  
+
| =
|0.0002637''kt''/''ϕμc''<sub>''t''</sub>''r''<sub>''w''</sub><sup>2</sup>, dimensionless time
+
| elapsed time, hours
 
|-
 
|-
|''t''<sub>''p''</sub>  
+
| ''t''<sub>''D''</sub>
|=  
+
| =
|pseudoproducing time, hours
+
| 0.0002637''kt''/''ϕμc''<sub>''t''</sub>''r''<sub>''w''</sub><sup>2</sup>, dimensionless time
 
|-
 
|-
|''t''<sub>''e''</sub>  
+
| ''t''<sub>''p''</sub>
|=  
+
| =
|equivalent time, hours  
+
| pseudoproducing time, hours
 
|-
 
|-
|''μ''  
+
| ''t''<sub>''e''</sub>
|=  
+
| =
|viscosity, cp
+
| equivalent time, hours
 
|-
 
|-
|''ϕ''  
+
| ''μ''
|=  
+
| =
|porosity, dimensionless  
+
| viscosity, cp
 +
|-
 +
| ''ϕ''
 +
| =
 +
| porosity, dimensionless
 
|}
 
|}
  
==References==
+
== References ==
<references>
 
<ref name="r1">Prats, M., Hazebroek, P., and  Strickler, W.R. 1962. Effect of Vertical Fractures on Reservoir Behavior--Compressible-Fluid Case. ''SPE J.'' '''2''' (2): 87-94. http://dx.doi.org/10.2118/98-PA </ref>
 
  
<ref name="r2">Papatzacos, P. 1987. Approximate Partial-Penetration Pseudoskin for Infinite-Conductivity Wells. ''SPE Res Eng'' '''2''' (2): 227–234. SPE-13956-PA. http://dx.doi.org/10.2118/13956-PA </ref>
+
<references />
  
<ref name="r3">Cinco, H., Miller, F.G., and Ramey, H.J. Jr.: "Unsteady-State Pressure Distribution Created by a Directionally Drilled Well," ''JPT'' (November 1975) 1392; ''Trans.'', AIME, '''259'''. SPE-5131-PA. http://dx.doi.org/10.2118/5131-PA</ref>
+
== Noteworthy papers in OnePetro ==
  
<ref name="r4">Brown, K.E. 1984. ''The Technology of Artificial Lift Methods'', Vol. 4, 134. Tulsa, Oklahoma: PennWell. </ref>
+
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
  
<ref name="r5">McLeod, H.O.J. 1983. The Effect of Perforating Conditions on Well Performance. ''Journal of Petroleum Technology'' '''35''' (1): 31–39. SPE-10649-PA. http://dx.doi.org/10.2118/10649-PA </ref>
+
== External links ==
</references>
 
  
==Noteworthy papers in OnePetro==
+
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
+
 
 +
== See also ==
  
==External links==
+
[[Fluid_flow_through_permeable_media|Fluid flow through permeable media]]
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
 
  
==See also==
+
[[Fluid_flow_in_naturally_fractured_reservoirs|Fluid flow in naturally fractured reservoirs]]
[[Fluid flow through permeable media]]
 
  
[[Fluid flow in naturally fractured reservoirs]]
+
[[Fluid_flow_in_hydraulically_fractured_wells|Fluid flow in hydraulically fractured wells]]
  
[[Fluid flow in hydraulically fractured wells]]
+
[[Fluid_flow_in_horizontal_wells|Fluid flow in horizontal wells]]
  
[[Fluid flow in horizontal wells]]
+
[[PEH:Fluid_Flow_Through_Permeable_Media]]
  
[[PEH:Fluid Flow Through Permeable Media]]
+
==Category==
 +
[[Category:1.8 Formation damage]] [[Category:5.3 Reservoir fluid dynamics]] [[Category:YR]]

Latest revision as of 10:10, 29 June 2015

Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability.

Permeability reduction and formation damage

When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

The production process may also reduce permeability and introduce a positive skin factor. For example, in an otherwise undersaturated oil reservoir, pressure near the well may be below the bubblepoint pressure, causing a free-gas saturation and reducing the effective permeability to oil. In a retrograde gas reservoir, the pressure near the wellbore may drop below the dewpoint and an immobile liquid phase may form and reduce the effective permeability to gas near the wellbore.

Injection can also cause damage. The water injected may be dirty; that is, it may contain fines that may plug the formation and reduce permeability. In other cases, the injected water may be incompatible with the formation water, causing solids to precipitate and plug the formation. In still other cases, the injected water may be incompatible with clays in the formation (e.g., fresh water can destabilize some clays, causing fines to migrate and plug the formation).

Altered zone and skin effect

A two-region reservoir model (Fig. 1) is a convenient representation of a damaged well (and some stimulated wells with radially symmetric permeability alteration around the wellbore). In this model, the altered zone around the wellbore is assumed to have uniform permeability ks out to a radius rs, beyond which the formation permeability, k, is unaltered.

For a damaged well, the reduced permeability in the altered zone causes an additional pressure drop, Δps (Fig. 2). The dimensionless skin factor, s, and the additional pressure drop across the altered zone are related by

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

For a well with a known skin factor, s, Eq. 1 provides a method of translating the somewhat abstract dimensionless skin factor into a more concrete characterization of the practical effect of damage or stimulation.

In a two-region reservoir model, the skin factor, s, is related to the properties of the altered zone:

RTENOTITLE....................(2)

Rearrange Eq. 2 and solve for the permeability of the altered zone:

RTENOTITLE....................(3)

Rearrangements of Eq. 2 provide a second method of translating skin into a more concrete characterization of a well with altered permeability near the wellbore. If the depth of damage can be estimated for a well with a known skin factor, s, the permeability of the altered zone can be estimated. Even if the depth of permeability alteration, rs, is estimated Eq. 3 can still provide a reasonable estimate of altered zone permeability because rs appears in a logarithmic term. Alternatively, an estimate of the permeability reduction ratio (for example, from laboratory tests on cores) can produce an estimate of the depth of damage from another rearrangement of Eq. 2,

RTENOTITLE....................(4)

Apparent wellbore radius

A third method of translating skin to a more concrete characterization of near-well conditions is to calculate apparent or effective wellbore radius, rwa. Apparent wellbore radius is defined as

RTENOTITLE....................(5)

RTENOTITLE....................(6)

For a stimulated well, the pressure drawdown at the wellbore is the same as it would be in a formation with unaltered permeability but with wellbore radius equal to the apparent wellbore radius. This concept has value in some simulation applications. Note that rwa can be calculated from the actual wellbore radius and skin factor.

Eqs. 5 and 6 are also useful to illustrate the minimum (i.e., the most-negative possible) skin factor. This minimum skin, smin, occurs when the apparent wellbore radius is equal to the drainage radius of the well:

RTENOTITLE....................(7)

For a well with a circular drainage area of 40 acres for which re is 745 ft and a wellbore radius of 0.3 ft, the minimum skin (maximum stimulation) is smin = - ln(re/rw) = −(745/0.3) = −7.82. Such a skin implies increasing the permeability throughout the entire altered zone to infinity—clearly an idealistic "upper limit." More realistically, research[1] has shown that the half-length, Lf, of a highly conductive vertical fracture is related to rwa by

RTENOTITLE....................(8)

or RTENOTITLE....................(9)

Thus, for Lf = re = 745 ft, s = −7.12 is a more realistic minimum (for the given drainage radius and wellbore radius).

Flow efficiency

A fourth way to characterize a well with nonzero skin is to calculate the flow efficiency of the well. Flow efficiency, Ef, is defined as the ratio of the actual productivity index of the well (including skin) to the ideal productivity index if the skin factor were zero. Because the productivity index is the ratio of stabilized flow rate to pressure drop required to sustain that stabilized rate,

RTENOTITLE....................(10)

RTENOTITLE....................(11)

and RTENOTITLE....................(12)

For a well with neither damage nor stimulation, Ef = 1; for a damaged well, Ef < 1; and for a stimulated well, Ef > 1.

Geometric skin

When the area open to flow decreases, the pressure drop is greater than when the area is unchanged all the way to the formation face. Examples include flow converging to perforations (Fig. 3), partial penetration (Fig. 4), and an incompletely perforated interval (Fig. 5).

Fig. 3 illustrates flow converging into perforations. When the perforation spacing is too large, this converging flow results in a positive skin factor. The skin increases as vertical permeability decreases and increases as shot density decreases.

Partial penetration

Fig. 4 illustrates flow converging into an interval that is only partly penetrated by perforations. When a well is completed in only a fraction of the productive interval, the flow must converge through a smaller area, increasing the pressure drop near the well (compared to a fully completed interval). The additional pressure drop near the well results in a more positive skin. It increases as the vertical permeability decreases and as the perforated interval as a fraction of the total interval decreases. Formation damage (reduced permeability) near the completion face can significantly increase the additional pressure drop and thus the calculated skin factor.

Incompletely perforated interval

Partial penetration is a special case of an incompletely perforated interval (Fig. 5). In the general case, the well is perforated starting at a distance h1 from the top of the productive interval and has perforations extending over a distance, hp, in an interval of total thickness, h. The total skin for the well in this general situation is

RTENOTITLE....................(13)

In Eq. 13, sd is the skin caused by formation damage, and s p is the skin resulting from an incompletely perforated interval. This equation is not valid for a stimulated well.

The skin factor for an incompletely perforated interval, sp, can be quantified by[2]

RTENOTITLE....................(14)

where RTENOTITLE....................(15)

RTENOTITLE....................(16)

RTENOTITLE....................(17)

RTENOTITLE....................(18)

and RTENOTITLE....................(19)

The most significant limitation in applying Eq. 14 in practice is the difficulty in estimating accurately the vertical-to-horizontal-permeability ratio, kv/kh. Fortunately, this ratio appears only in a logarithmic term in Eq. 14, so errors will not seriously distort the calculated value of sp.

Deviated well

For a deviated well (Fig. 6), which penetrates the formation at an angle other than 90°, more surface is in contact with the formation. This introduces a negative skin factor, sθ, which makes the total skin factor, s, more negative.

RTENOTITLE....................(20)

The effect increases as the vertical permeability increases and increases as the angle from the vertical, θw, increases. The deviated well skin factor, sθ, is given by a correlation of simulated results[3] (valid for θw < 75°):

RTENOTITLE....................(21)

where RTENOTITLE....................(22)

and RTENOTITLE....................(23)

Gravel-pack skin

When a well is gravel packed (Fig. 7), there is a pressure drop through the gravel pack within the perforations, given by[4]

RTENOTITLE....................(24)

where sgp is the skin factor because of Darcy flow through the gravel pack; h, the net pay thickness, ft; kgp, the permeability of the gravel in the gravel pack, md; k, the reservoir permeability, md; Lg, the length of the flow path through the gravel pack, ft; n, the number of perforations open; and rp, the radius of the perforation tunnel, ft. Eq. 24 does not include the effects of non-Darcy flow, which may be extremely important in high-rate gas wells.

Completion skin

For a perforated well, any reduced permeability, kdp, in the zone surrounding the perforations (Fig. 8) introduces an additional pressure drop. The additional skin is[5]

RTENOTITLE....................(25)

and RTENOTITLE....................(26)

where sp is the geometric skin from flow converging to the perforations; sd, the damage skin; sdp, perforation damage skin; kd, permeability of the damaged zone around the wellbore, md; kdp, permeability of the damaged zone around perforation tunnels, md; k, reservoir permeability, md; Lp, length of perforation tunnel, ft; n, number of perforations; h, formation thickness, ft; rd, radius of the damaged zone around the wellbore, ft; rdp, radius of the damages zone around the perforation tunnel, ft; rp, radius of the perforation tunnel, ft; and rw, wellbore radius, ft. Eq. 26 does not include the effects of non-Darcy flow.

Hydraulically fractured wells

Wells are frequently fractured hydraulically to improve their productivity, especially in low-permeability formations where fractures increase the effective drained area and in high-permeability formations where they penetrate near-well damage or promote sand control. These fractures, almost always vertical (Fig. 9), are high-conductivity paths between the reservoir and the wellbore. If the fracture conductivity is large enough relative to the formation permeability and fracture length, the pressure drop within the fracture will be negligible. This distributes the pressure drop caused by fluid influx into the wellbore over a much larger area, resulting in a negative skin factor, which is interpreted as a geometric skin.

Dimensionless fracture conductivity, Cr, is defined by

RTENOTITLE....................(27)

where wf is the fracture length, ft; kf, the permeability of the proppant in the fracture; k, the formation permeability, md; and Lf, the fracture half-length, ft. Pressure drop in the fracture is negligible for Cr > 100.

Nomenclature

B = formation volume factor, res vol/surface vol
ct = Soco + Swcw + Sgcg + cf = total compressibility, psi–1
C = performance coefficient in gas-well deliverability equation, or wellbore storage coefficient, bbl/psi
CD = 0.8936 C/ϕcthrw2 , dimensionless wellbore storage coefficient
Cr = wfkf/πkLf, fracture conductivity, dimensionless
Ei(–x) = RTENOTITLE, the exponential integral
h = net formation thickness, ft
hp = perforated interval thickness, ft
hpD = hp/ht
ht = total formation thickness, ft
J = productivity index, STB/D, psi
Jactual = actual well productivity index, STB/D-psi
Jideal = ideal productivity index (s = 0), STB/D-psi
k = matrix permeability, md
kh = horizontal permeability, md
ks = permeability of altered zone, md
Lf = fracture half length, ft
p = pressure, psi
pwf = flowing BHP, psi
pD = 0.00708 kh(pip)/qBμ, dimensionless pressure as defined for constant-rate production
ps = stabilized shut-in BHP measured just before start of a deliverability test, psia
q = flow rate at surface, STB/D
r = distance from the center of wellbore, ft
re = external drainage radius, ft
rw = wellbore radius, ft
rwa = apparent or effective wellbore radius, ft
rD = r/rw, dimensionless radius
rs = outer radius of the altered zone, ft
s = skin factor, dimensionless
sd = skin caused by formation damage, dimensionless
sdp = perforation damage skin, dimensionless
sp = skin resulting from an incompletely perforated interval, dimensionless
sθ = skin factor resulting from well inclination, dimensionless
t = elapsed time, hours
tD = 0.0002637kt/ϕμctrw2, dimensionless time
tp = pseudoproducing time, hours
te = equivalent time, hours
μ = viscosity, cp
ϕ = porosity, dimensionless

References

  1. Prats, M., Hazebroek, P., and Strickler, W.R. 1962. Effect of Vertical Fractures on Reservoir Behavior--Compressible-Fluid Case. SPE J. 2 (2): 87-94. http://dx.doi.org/10.2118/98-PA
  2. Papatzacos, P. 1987. Approximate Partial-Penetration Pseudoskin for Infinite-Conductivity Wells. SPE Res Eng 2 (2): 227–234. SPE-13956-PA. http://dx.doi.org/10.2118/13956-PA
  3. Cinco, H., Miller, F.G., and Ramey, H.J. Jr.: "Unsteady-State Pressure Distribution Created by a Directionally Drilled Well," JPT (November 1975) 1392; Trans., AIME, 259. SPE-5131-PA. http://dx.doi.org/10.2118/5131-PA
  4. Brown, K.E. 1984. The Technology of Artificial Lift Methods, Vol. 4, 134. Tulsa, Oklahoma: PennWell.
  5. McLeod, H.O.J. 1983. The Effect of Perforating Conditions on Well Performance. Journal of Petroleum Technology 35 (1): 31–39. SPE-10649-PA. http://dx.doi.org/10.2118/10649-PA

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Fluid flow through permeable media

Fluid flow in naturally fractured reservoirs

Fluid flow in hydraulically fractured wells

Fluid flow in horizontal wells

PEH:Fluid_Flow_Through_Permeable_Media

Category