|
|
P O R O S I T Y - T O T A L V S . E F F E C T I V E
One of the most common debates in Petrophysics is whether to use Total
or Effective Porosity. This article discusses the differences between
the two. It explains why total porosities should always be calculated
and why some companies use effective porosity to improve their insight
into reservoir behaviour.
Definitions
Total porosity may be defined as all the pore space containing fluids
(water, oil or gas), whether or not they are mobile. This pore space
includes any hydrocarbon fluids, mobile water, capillary bound water
and clay-bound water.
There are various definitions of 'effective' porosity e.g.Juhasz
(1986), Hill-Shirley-Klein (1979), Clavier-Coates-Dumanoir (1977).
However, the most common definition is:
fE = fT - VD,
where fT is the total porosity of clean (clay free) sand and VD
is the volume of dispersed clay in the sand pore space expressed as a
fraction of the bulk volume. In other words, effective porosity is
total porosity less the volume of clay-bound water.
Of course, when you decrease porosity by converting from a total
porosity to an effective porosity, the hydrocarbon saturations must
increase, since the same amount of hydrocarbon is present. In other
words, the hydrocarbon volumes estimated using either a total or
effective porosity system are the same (i.e. ShT·fT·h = ShE·fE·h), it should make no difference which system is utilised.
Core Calibration of Porosity
To have the most confidence in your log evaluations, the core derived
measurements should agree with those from your wireline logs. Since it
is not possible to measure effective porosities in a reliable and
repeatable manner, calibration with core analyses is best achieved by
measuring total porosities on core plugs and comparing these with total
porosities estimated from logs.
Calculating Total Porosity
The best way to calculate total porosity is using the density log,
correcting for lithology (using grain density) and fluid density (using
invaded zone resistivity or neutron logs). For completeness the formula
recommended is:
fT = (rma - r)/
(rma - (rhc·(1-Sxo)+rmf·Sxo))
where rma is the grain density (normally determined from laboratory measurements on core material), r is the density log measurement, rhc is the in-situ hydrocarbon density (from pressure data or sampling), rmf is the mud filtrate density (from correlation charts normally) and Sxo is the invaded zone water saturation.
Of course, solving this equation properly requires iteration since Sxo is dependent on fT,
no matter which saturation model you use (Archie, Dual-Water,
Indonesia, Waxman-Smits etc.). Unfortunately, this requirement is also
why this type of solution is not more commonly used. In actuality, the
maths is very straightforward to program nowadays.
In the absence of density log (or NMR) data, total porosities are best calculated by empirical calibration to core data.
Determining Effective Porosity
From the first equation, to estimate the effective porosity, some estimate of VD
must be made. Typically the density neutron separation or the gamma ray
logs are used to make this estimate. Actually, in the industry today,
over 20 different models for the shale fraction VD are in
use. A lot of time is spent in discussions between personnel as to
which model is most appropriate in any particular circumstance.
Of course, once fE is known, along with fT and ShT, ShE can be readily calculated from the second equation.
Porosity & Water Saturations
Once a total or effective porosity has been determined, it must be used
in a water saturation equation to determine hydrocarbon saturations. If
you've used a total porosity model, then there's no concern about which
shale fraction model you've used. If you've gone down the effective
porosity route too early, you must adjust the saturation model to
account for the conductivity of the clay-bound water that is measured
by the resistivity logs, but not accounted for in the porosity.
Effective Porosity, Permeability & Mobile Fluids
So why bother with effective porosity at all? - There are a number of reasons:
Effective porosity is primarily used as a tool to help people
understand whether or not the hydrocarbons are likely to flow. In this
respect, formation pressure tests or NMR measurements would be more
diagnostic.
Since effective porosity refers to the fluids that are not bound to the
rock matrix, there is typically a better correlation between effective
porosity and permeability than there is using total porosity - unless
there is negligible shale present. Hence, if you're having trouble
working out a decent porosity to permeability transform, effective
porosity may reduce your difficulties.
Summary
Since a total porosity system is more reliably calibrated to core and
simpler to work in, this is the approach recommended for petrophysical
evaluation. If there are conductive shales present, correct for these
using total porosity and either the Waxman-Smits or Dual Water models
to get water saturations. Use effective porosity only to calibrate a
permeability transform. If you need effective porosities and water
saturations for some other reason (e.g. your volumetric model is
"effective"), calculate them from your calibrated total porosity system.
References
Clavier, C., Coates, G., and Dumanoir, J.:
“Theoretical and Experimental Bases for the
Dual-Water Model for Interpretation of Shaly
Sands,” SPE-6859, 52nd annual meeting
[Denver] preprint 16 p., 1977.
Hill, H.J., Shirley, O.J., Klein, G.E.:
“Bound Water in Shaley Sands - Its Relation to Qv
and Other Formation Properties,” Log
Analyst, May-June 1979.
Juhasz, I.: "Assessment of the distribution of
shale, porosity and hydrocarbon saturation in
shaly sands,' paper AA, in 10th European formation evaluation
symposium transactions, Society of Professional
Well Log Analysts, Aberdeen Chapter, 15 p. 1986.
Schlumberger Educational Services: “Log
Interpretation Principles/Applications,”
Schlumberger manual, 1989.
Waxman, M.H., and Smits, L.J.M.; "Electrical
conductivities in oil-bearing shaly sands,"
Society of Petroleum Engineers Journal, v.
8(2), p. 107-122, 1968.
|
|
|
