Difference between revisions of "Mobility Ratio"

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[[Mobility Ratio]] determines the relative rate of one fluid to another (etc. water to oil).
 
[[Mobility Ratio]] determines the relative rate of one fluid to another (etc. water to oil).
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The waterflood is driven by pore volumes of injected fluid. Everything that is of practical interest occurs between zero to three pore volumes injected <ref name=DW/>.
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:<math> M \le 1</math> oil is dominant flowing phase, stable flow.
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:<math> M > 1</math> water preferentially flows in the reservoir, unstable flow, fingering.
  
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===Equation===
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==Equation==
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:<math> M = \frac{k_w/ \mu_w}{k_o/ \mu_o}=\frac{k_{rw}}/ \mu_w}{k_{ro}}/ \mu_o}=\frac{q_w B_w{q_o B_o}</math>
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:<math> M = \frac{k_w/ \mu_w}{k_o/ \mu_o}=\frac{k_{rw}/ \mu_w}{k_{ro}/ \mu_o}=\frac{q_w B_w}{q_o B_o}</math>
  
 
where
 
where
  
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:<math> A </math> = Area, m2
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:<math> B_o </math> = oil formation volume factor, m3/m3
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:<math> B_{wi} </math> = Injected water formation oil factor, m3/m3
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:<math> B_w </math> = water formation volume factor, m3/m3
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:<math> h </math> = Net pay, oil saturated thickness, m
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:<math> k_{rw} </math> = relative water phase permeability, function of the phase saturation, fraction
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:<math> HCPV </math> = Hydrocarbon pore volume, m3
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:<math> k_o </math> = oil phase permeability, function of the phase saturation, fraction
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:<math> HCPV_{inj} </math> = Injected hydrocarbon pore volumes, fraction
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:<math> k_o </math> = relative oil phase permeability, function of the phase saturation, mD
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:<math> W_i </math> = Cumulative water injection volume, m3
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:<math> k_w </math> = water phase permeability, function of the phase saturation, mD
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:<math> \phi </math> = Porosity, fraction
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:<math> M </math>= mobility ratio, fraction
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:<math> S_o </math> = Oil saturation, fraction
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:<math> \mu_o </math> = oil viscosity, cP
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:<math> \mu_w </math> = water viscosity, cP
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:<math> q_o </math> = oil rate, cc/sec
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:<math> q_w </math> = water rate, cc/sec
  
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===Related definitions===
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Rule of thumb:
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Dimensionless injected pore volume:
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:<math> M = 0.333 \mu_o</math>
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:<math> W_{iD} = \frac{W_i * B_{wi}}{PV} = \frac{W_i * B_{wi}}{A * h * \phi}</math>
 
  
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Injected movable pore volume:
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==Example==
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:<math> MOPV_{inj} = \frac{W_i * B_{wi}}{MOPV} = \frac{W_i * B_{wi}}{A * h * \phi *(1-S_{wc}-S_{orw})}</math>
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Determine the [[Mobility Ratio]] using the following data<ref name=DW/>:<BR>
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Core is at 70% water and 30% oil saturation. Water phase permeability is 248 mD, oil phase permeability is 50 mD. Water viscosity is 1 cP, oil viscosity is 3 cP.
  
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where
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:<math> M = \frac{248/1}{50/3} =15 </math>
  
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:<math> S_{wc} </math> = Connate water saturation, fraction
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In this case the mobility of water is 15 times higher than the mobility of water.
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:<math> S_{orw} </math> = Residual oil saturation to water, fraction
 
  
 
==See Also==
 
==See Also==

Latest revision as of 09:02, 4 April 2022

Brief

Mobility Ratio determines the relative rate of one fluid to another (etc. water to oil).

M \le 1 oil is dominant flowing phase, stable flow.
M > 1 water preferentially flows in the reservoir, unstable flow, fingering.

Equation

M = \frac{k_w/ \mu_w}{k_o/ \mu_o}=\frac{k_{rw}/ \mu_w}{k_{ro}/ \mu_o}=\frac{q_w B_w}{q_o B_o}

where

B_o = oil formation volume factor, m3/m3
B_w = water formation volume factor, m3/m3
k_{rw} = relative water phase permeability, function of the phase saturation, fraction
k_o = oil phase permeability, function of the phase saturation, fraction
k_o = relative oil phase permeability, function of the phase saturation, mD
k_w = water phase permeability, function of the phase saturation, mD
M = mobility ratio, fraction
\mu_o = oil viscosity, cP
\mu_w = water viscosity, cP
q_o = oil rate, cc/sec
q_w = water rate, cc/sec

Rule of thumb:

M = 0.333 \mu_o

Example

Determine the Mobility Ratio using the following data[1]:
Core is at 70% water and 30% oil saturation. Water phase permeability is 248 mD, oil phase permeability is 50 mD. Water viscosity is 1 cP, oil viscosity is 3 cP.

M = \frac{248/1}{50/3} =15

In this case the mobility of water is 15 times higher than the mobility of water.

See Also

References

  1. ↑ Wolcott, Don (2009). Applied Waterflood Field DevelopmentPaid subscription required. Houston: Energy Tribune Publishing Inc. 


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