Archie equation
Exploring for Oil and Gas Traps  
Series  Treatise in Petroleum Geology 

Part  Predicting the occurrence of oil and gas traps 
Chapter  Predicting reservoir system quality and performance 
Author  Dan J. Hartmann, Edward A. Beaumont 
Link  Web page 
Store  AAPG Store 
Contents
What is the Archie equation?
Archie^{[1]} developed his famous equation to calculate, from well log parameters, the water saturation (S_{w}) of the uninvaded zone in a formation next to a borehole. The Archie equation can be expressed as follows:
where:
 S_{w} = water saturation of the uninvaded zone
 n = saturation exponent, which varies from 1.8 to 4.0 but normally is 2.0
 R_{w} = formation water resistivity at formation temperature
 Φ = porosity
 m = cementation exponent, which varies from 1.7 to 3.0 but normally is 2.0
 R_{t} = true resistivity of the formation, corrected for invasion, borehole, thin bed, and other effects
Limitations of the Archie equation
Even though numerous other relationships have been developed over the years, the Archie equation remains the most flexible and generally useful approach. Yet its proper application requires knowledge of its limitations. The equation was empirical in origin and therefore needs modification in rock–fluid combinations different from Archie's experiments. Modifications need to be made in rocks with the following characteristics:
 NonArchie pore geometries (i.e., not intergranular or intercrystalline) (See Pore systems.)
 Conductive minerals such as clays and pyrite
 Very fresh (i.e., nonsaline) formation waters
Caveat
This section discusses the Archie equation in general terms; suggested methods are most useful when dealing with modern log suites of good quality.
Deriving values for Archie variables
Values for the five Archie variables are relatively easy to derive when a formation is thick, has a clayfree matrix, and/or is dominated by intergranular or intercrystalline porosity (Archie porosity). Formations that are thin bedded (i.e., below limits of logging tool resolution), have clay in their matrix, or have moldic, vuggy, or fracture porosity require adjustments. The table below lists the five variables and methods for deriving or estimating them.
Step  Find  Use…  If…  Then… 

1  n  Not sure of rock type  Use 2.0  
2  R_{w} 

Thin beds, hydrocarbons in zone, or fresh formation waters make SP calculations uncertain  Use thinbed correction or another method 
3  Φ  Value derived from cores, density, density–neutron, or sonic logs (See Basic open hole tools.)  Density–neutron log matrix setting does not match formation matrix  Use density– neutron crossplot (See Determining porosity from densityneutron logs.) 
4  m 

Not sure of rock type or pore geometry  Use 2.0 
5  R_{t}  Value derived from deep resistivity log such as RILD or RLLD  Beds are thin, invasion occurred or borehole has washouts  Use chartbook corrections 
See also
 Determining water saturation
 Determining Rt
 Calculating Rw from SP logs
 Constructing a Pickett plot
 Pore systems
References
 ↑ Archie, G. E., 1952, Classification of carbonate reservoir rocks and petrophysical considerations: AAPG Bulletin, vol. 36, no. 2, p. 218–298. A classic paper written way before its time.