Formation Evaluation (Lecture) Subsurface Methods 4233

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Formation Evaluation(Lecture)Subsurface
Methods4233
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Formation Density Log Determination of Porosity
Porosity
?b, Bulk Density g/cc
Fresh water Salt water Really messed-up water!
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Typical hydrocarbon/water contact on resistivity
log
Ro
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FORMATION EVALUATION FROM WELL LOGS
Shaliness Determined from Gamma-ray log. Not
reliably interpreted from SP in impervious strata
or in thin beds. Establish 0, 50, and 100
shale lines on the GR log. SS and LS intervals
above the 50 cutoff are shaly. Rattiness of the
GR log to the left or right of the 50 line
indicates thin beds of SS LS respectively.
These beds are too thin for accurate log
resolution but Are still very real! Shaly sands
and carbonates (gt40) are generally worthless
reservoirs despite their apparent
porosity. Formation Factor (F) needed for Sw
calculation Ways to calculate F F
Ro/Rw use only in clean, water-bearing
formations having little clay or hydrocarbons.
Formula has limited value or accuracy throughout
an actual field or large area. Cannot be used
when evaluating multiple reservoirs. Note R0
bed resistivity 100 water saturated and Rw
resistivity of formation water. F a/Fm
Archie equation or modification there-of
(best) a tortuosity constant dependent on
rock texture (grain size, sorting,
cementation, etc). Use 1 for carbonates
and .81 for most sandstones in OK. m
cementation factor (1.4 to 1.7 slightly
cemented 1.8 to1.9 moderately cemented,
2.0 to 2.2 highly cemented). Use 2 for
carbonates and sandstone in OK. Therefore for
sandstone use F .81/Ø2 for limestone
use F 1/Ø2
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Water/hydrocarbon saturation determination
Can be interpreted from SP log
difficult, incorporates too many variables. All
rock factors being equal, the SP is diminished
in hydrocarbon -filled reservoirs as compared to
when filled with water. Cores often a
bad choice since permeable rocks will be flushed
during drilling thereby distorting values
badly. Formula Best, most accurate,
and easy to use in all rock types and saturation
conditions. Uses hard numbers instead of
guesses and extrapolated values. Sw
FRw Rt solving for Rw Rw
Sw2Rt F Using this method, find a nearby
well (usually low to production) that has good
reservoir characteristics but is decidedly wet.
This zone will have the lowest resistivity for
the particular reservoir of interest and will
obviously be dry. It can safely and accurately be
assumed that Sw in this interval is between
95-100 and obviously, even an error of a few
will not result in large error in calculation of
Rw. From the same well and zone, Rt and F can
accurately be determined from well logs to
calculate Rw. Then, use the SW formula (above)
with the calculated Rw to determine hydrocarbon
saturation in the same reservoir throughout the
field.
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Determining water/hydrocarbon saturation,
continued Alternatively, find an interval of the
same rock type stratigraphically close to the
reservoir of interest that has unusually low
resistivity compared to know pay zones in the
field area. These zones may have residual
hydrocarbons but the presumed water saturation is
still high and probably in the range of 85-90
(or higher). Using this presumed water
saturation, back-calculate Rw and then use the Sw
formula to determine water/hydrocarbon
saturations. Another useful formula but of
limited value is below Sw Ro Rt Its
use should be limited to beds having similar
reservoir characteristics (texture, sorting,
cementation, porosity), and similar formation
water salinity. These conditions obviously do not
often occur in nature so the formula is
appropriate only for a thick, relatively
homogenous reservoir having oil saturation above
a water column.
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Porosity Determination In gas-filled
reservoirs use standard density and neutron
cross-plot values when available. Splitting the
difference between the two log traces will yield
sufficiently accurate values in LS strata. In
sandstone reservoirs the cross plot porosity may
have to be reduced a few porosity units to mimic
true porosity as determined from core data. In
oil reservoirs there will be little or no
density-neutron porosity cross over. If the
reservoir is clean (little shale/clay, you
probably can proceed as described above. If there
is appreciable clay/shale (as determined by the
GR log) I would ignore the neutron porosity and
rely solely upon density values since they are
not nearly as affected by clay. If
necessary, reduce the density porosity a few
units to match expected core data. Remember
that porosity logs are usually calibrated to a
limestone matrix. Therefore, theoretical porosity
in sandstone may be too high on both the density
and neutron logs and too low in dolomite.
Porosity values are also influenced by matrix
material between grains, cementation, pore
fluids, among other things. Log corrections are
NOT done by the service companies nor represented
on the log. YOU must do it if necessary. Locally,
no corrections are necessary when core porosity
mimics log porosity. If not, you may need to
subtract 2-3 porosity units from that recorded on
the density log in sandstone strata. Gas
seriously affect values on all porosity logs. If
you have only one log, say density porosity, you
must decrease its value appropriately to diminish
this gas effect. This can be done by documenting
the gas effect in other wells having both density
neutron log suites. The cross plot porosity in
the later will indicate how many porosity units
are causing the gas effect and a ratio (usually
.65 to .7) can be applied to the well having
only Density porosity. Personally, I would not
want to use strictly neutron porosity because of
its sensitivities to both clay and formation gas.

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Detecting a Depleted Gas ReservoirWhen
cross-plot porosity exceeds 10-12 porosity units,
pressure depletion can be presumed

• GR SP Porosity
• 30 20 10 0

8-10 porosity units separation normal
pressured reservoir (gas effect)
14-16 porosity units of separation pressure
depletion!
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Determination of Permeability (K)

• From cores usually the best method but cores
  are few and far-between!
• Permeability measurements are expressed in
  millidarcys - md (one thousandth of a darcy). It
  is affected by many formation attributes such as
  pressure, rock texture, and fluid content. For
  convenience, It is measured in the lab by passing
  inert gas such as helium or nitrogen through
  samples. The resulting flow is converted to
  values relevant to common air (KA). Because this
  data is often unrealistic, it is frequently
  converted into units that more accurately relate
  to liquid permeability (pure water). Note that
  the viscosity of water is similar to that of many
  oils. This liquid permeability is then called
  Klinkenberg permeability or KK. KA is
  generally quite inaccurate in tight reservoirs
  but closely approximates KK in reservoirs having
  gt a few hundred md.
• Pressure decline testing (cannot do on a
  well-by-well basis or for multiple reservoirs)
  conveniently.
• Porosity vs. Permeability Plot. Very good see
  examples provided. Need to get only one or two
  cores in the nearby area having reliable
  density-neutron log suites. You can then input
  any porosity value into the plot to get a good
  value of permeability.
• Interpreted quantitatively from micrologs,
  conventional resistivity logs (noting separation
  between the shallow and deep measurements), and
  from the caliper log (which measures mudcake
  buildup that is a function of permeability).
• From porosity and Swi (irreducible water
  saturation) This method is not easy to complete
  accurately using standard log suites. Swi is
  very, very sensitive to porosity, reservoir
  texture, oil viscosity, and just having a bad day
  in the office! I personally have not used it
  successfully and do not recommend its use.
• From SP logs. A very good qualitative method of
  estimating reservoir permeability. Limitations
  include bed thickness, fluid content, and
  resistive bounding strata.

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Porosity vs. Permeability Plots from core. This
is perhaps the best way to determine permeability
in the same formation in nearby wells having a
reliable porosity suite
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Common normal subsurface pressure gradient
Over-pressured
ppg pounds per gallon
pcf pounds per cubic ft
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