The sixth step in a log analysis is to estimate permeability and productivity. These values determine whether a zone is commercially attractive. There are a number of methods for calculating matrix permeability.
Although it is not a quantitative measure of permeability, the separation between the two microlog curves is an excellent indicator. The log can still be run today as part of a density log survey.
Log analysis matrix permeability is calibrated to maximum core permeability (absolute permeability or air permeability). Allowance must be made to eliminate fractured samples from the core data set. Permeability to liquids is lower than absolute permeability. Flow capacity from logs (KH) can be compared to pressure buildup analysis. Again fractures will cause a difference.
The general form of this equation has been used by many authors, with various correlations between log and core data. Individual analysts routinely calibrate their core and log data to this equation.
STEP 1: Calculate permeability 1: PERMw = CPERM * (PHIe ^ DPERM) / (SWir ^ EPERM)
If we recall that SWir = KBUCKL / PHIe, we see that this equation is strictly a function of porosity if KBUCKL is a constant. However, KBUCKL varies with shale volume and grain size, so Perm will vary also.
he permeability from the Wyllie method (PERMw) is called the effective permeability, Perm. The result is in millidarcies. It can be calibrated to air, absolute, maximum, or Klinkenberg corrected permeability from core analysis, You should state which type of core analysis you calibrated to.
· Use anytime, usually when no core data is available.
· Not reliable in fractures or heterogeneous reservoirs.
· Calibrate to core by adjusting CPERM, DPERM, and EPERM. Sw, PHIe and Vsh should have been accomplished earlier.
* OIL or WATER GAS
Morris-Biggs 65000 6500 6.0 2.0 Timur 6500 650 4.5 2.0
Values of CPERM as low as 10 000 and as high as 1 000 000 have been used in the Morris - Biggs equation. It is also called the Tixier equation.
Permeability is often a semi-logarithmic function of porosity, unfortunately with a fairly large deviation. Core data is usually plotted to determine the equation of the best fit line: it can be calibrated to air, absolute, maximum, or Klinkenberg corrected permeability from core analysis,
STEP 1: Calculate permeability 1: PERMp = 10 ^ (HPERM * PHIe + JPERM)
The permeability from the Porosity method (PERMp) is called the effective permeability, Perm. The result is in millidarcies.
· Use anytime that parameters can be calibrated to core, especially in low porosity.
· Not reliable in fractures or heterogeneous reservoirs.
· A best fit line of the logarithm of core permeability vs. core porosity is often used to obtain this relationship for a particular zone.
Sandstones
Carbonates
Very fine grain Chalky 3.00 16 Fine grain Cryptocrystalline- 2.50 18 Medium grain Intercrystalline 2.20 20 Coarse grain Sucrosic- 2.00 22 Conglomerate Fine vuggy 1.80 24 Unconsolidated Coarse vuggy 1.50 26 Fractured Fractured 1.00 30
The medium grain parameters approximate the Wyllie - Rose equation. These parameters should be calibrated to core data whenever possible.
This is a simplification of an earlier method proposed by Dumanoir and Coates. It is more optimistic than other methods in low porosity. 1: PERMc = 5000 * (PHIe ^ 4) * ((PHIt PHIe * SWir) / (PHIe * SWir)) ^ 2
OR in clean zones: 2: PERMc = 5000 * (PHIe ^ 4) * ((1 - SWir) / SWir) ^ 2
Heslop (pere et fils) fitted core data in very young sediments in two wells and obtained parameters for an equation similar to the Coates equation (caution: there was no low or high porosity data in the calibration data set):
3: PERMh = 100
000 * (PHIe ^ 3.9) * (1 - SWir) ^ 3.9
The permeability from the Coates method (PERMc) is called the effective permeability, Perm. The result is in millidarcies.
· Not reliable in fractured or heterogeneous reservoirs.
· Parameters need to be calibrated to core data for most zones.
There are a few published methods for calculating fracture permeability from conventional open hole logs or from some arbitrary estimate of fracture porosity. The only correct approach is to use formation micro-scanner fracture aperture and frequency data: 1: Kfrac = 833 * 10^11 * PHIfrac^3 / (Df^2 * KF1^2) 2: Kfrac = 833 * 10^5 * PHIfrac * Wf^2 3: Kfrac = 833 * 10^2 * Wf^3 * Df * KF1
Where: KF1 = number of main fracture directions = 1 for sub-horizontal or sub-vertical = 2 for orthogonal sub-vertical = 3 for chaotic or brecciated PHIfrac = fracture porosity (fractional) Df = fracture frequency (fractures per meter)
Wf = fracture aperture (millimeters)
Kfrac can be many thousands of millidarcies.
Equations 1, 2, 3 give identical results. |
||||

Page Views ---- Since 01 Jan 2015
Copyright 1978 - 2022 E. R. Crain, P.Eng. All Rights Reserved |