where you find it, not always where you look for it.
Rocks, Oil, Gas, and Energy,
All of my 50+ year career has been involved with the science of
Petrophysics, literally the physics of rocks, in some way or
another. Petrophysics is a branch of Geoscience and intimately
linked to geology, geophysics, and petroleum / mining
engineering. There is no degree granted in pure petrophysics, so
people in this field are often graduates of a closely related
specialty and are self-taught from there.
Petrophysics is mainly used in petroleum exploitation, but also
in defining mining and ground water resources.
To understand petrophysics, you need to understand rocks and the
fluids they contain, how the earth's surface and subsurface
change shape, and how pressure, temperature, and chemical
reactions change rocks and fluids over eons of time. That's a
are formed in several ways, but usually end up as moderately flat
layers, at least initially (mountain building comes later). As
successive layers are laid on top of each other, the Earth
builds a sequence of rocks with varying physical properties.
Some layers will have open spaces, called pores or porosity,
that contain fluids (water, oil, or gas). A rock on Earth with
porosity cannot be "empty" -- they must contain something, even
if it is only air.
Microphotograph of a rock -- black colour is the porosity
oil, gas, and water can be held inside the rock
Think of a porous rock as similar to a
huge sponge full of holes that can soak up fluids. Although we
often talk about "oil pools", these are not tanks of oil
underground -- they are porous rocks. The porosity, or quantity
of open space relative to the total rock volume, can range from
near zero to as much as 40%. Obviously, higher values of this
physical property of a rock are good news.
rocks have very little porosity and do not hold much in the way
of fluids. These are often called "tight" rocks. Both tight and
porous rocks can contain animal and plant residue that are
ultimately transformed into hydrocarbons such as coal, oil, or
natural gas that we can extract and use to power vehicles and
heat our homes. As the plant and animal residues mature into oil
or gas, they may migrate through porosity or natural fractures
in the rock until trapped by a non-porous rock structure.
Sometimes a rock only sources itself or an adjacent porous rock,
so little migration occurs.
An anticline, the simplest form of petroleum trap
Rocks that are capable of holding hydrocarbons in economic
quantities are called reservoir rocks. Rocks in which the plant
and animal residue has not been fully converted to useful
hydrocarbons are called source rocks. Some rocks are both source
and reservoir: others are barren of hydrocarbons, and some
others may act as the trapping mechanism that keeps hydrocarbons
from migrating to the surface and escaping.
A trap is what keeps oil and gas in the rocks until we drill
wells to extract the hydrocarbons. Coal, being a solid, doesn't
need a trap to be kept in place.
that contain oil or gas also contain water. The quantity of
water relative to the porosity is called the water saturation.
In the illustrations, the brown colour is solid rock grains and
the space around the grains is the porosity. The black colour is
the hydrocarbon and the white is the water, which forms a thin
film coating the surfaces of each rock grain. This is a
water-wet reservoir (left). In an oil-wet reservoir, the black
and white colours are reversed (right).
Finding and evaluating the economics of such reservoirs is the
job of teams of geoscientists and engineers in petroleum and
mining companies. A petrophysicist, or someone playing this
role, will be part of that team.
Once a useful accumulation has been found, drilling, completion,
and production engineers take over to put wells on stream. Oil
production may initially flow to surface due to the pressure in
the reservoir. Some oil pools do not have enough pressure to do
this and need to be pumped. Depending on the reservoir drive
mechanism, some wells that start flowing will later need to be
pumped. Water may be produced with the oil. It is separated and
disposed of by re-injection into a nearby unproductive reservoir
layer. You can't just dump the water in the nearest swamp.
Aquifer Drive -- Before ... and After some production
Gas Cap Drive
Gas Expansion Drive
An aquifer drive mechanism usually maintains the reservoir
pressure for some time but may drop off gradually. Recovery factors vary from 30 to 80% of the oil in place. The oil water
contact rises as production depletes the oil. A gas cap drive
pushes oil out as the gas expands. Recovery factor is similar to
aquifer drive. There may or may not be some aquifer support.
the gas oil contact drops as the oil is depleted. Gas expansion
reservoirs do not have aquifer or gas cap support. Gas dissolved
in the oil expels oil into the well bore because the pressure at
the well bore is below the reservoir pressure. Recovery factor is
awful - usually less than 10%, but this can be improved to maybe
20% by injecting water nearby to increase or maintain the
reservoir pressure. Water floods, carbon dioxide injection, and
re-injection of produced gas or water can be used in nearly any
reservoir to improve recovery efficiency.
Gas wells do not need pumps, but if they also produce water, a
special process called artificial lift is used to get the water
out. That water is also disposed of legally.
economics of a reservoir varies with improving technology.
Bypassed reservoirs, discovered and ignored years ago, are now
economic due to technical improvements in drilling practices and
reservoir stimulation techniques. Horizontal wells and deep
water drilling are now common. The use of heat or steam to assist
production of heavy oil or bitumen, and multi-stage hydraulic fracturing to
stimulate production in tighter reservoirs are relatively new
techniques and relatively economic today. Obviously the specific
price of oil or gas after delivery to the customer plays an
important role in how much effort can be expended to recover oil
and gas from underground.
There is controversy, of course, about new technology. Just as
the Luddites resisted the weaving machines in the early 1800's,
modern Luddites insist that the old ways of oil and gas
extraction are best, while at the same time complaining loudly
about the price of gasoline at the pumps or the cost of
electricity for their air conditioners. You can't have low-cost
and low-tech at the same time.
"Last week, I couldn't spell Petrophysicist. Now I are one."
That describes me in 1962 as I moved from Montreal to Red Deer,
Alberta to run well logs for a company called Schlumberger. The
word petrophysics had been coined 12 years earlier by a
geologist named Gus Archie and it wasn't used much back in the
day. Lately it has attained a certain cachet, denoting a professional
level career path.
What is a "well log" you ask. It is a record of measurements of
physical properties of rocks taken in a well bore, usually
drilled for oil or gas, but possibly for ground water or
minerals. Think of a ship's log. The first record of such a log
dates back to 1846 when Lord Kelvin measured temperature
versus depth in water wells in England, from which he deduced
that the Earth was 7000 years old. The fact that he was wrong is
not important. Log analysis is an imperfect science.
Illustration of a wireline logging job: logging truck with
computer cabin, cable and winch (right), cable strung from
winch into drilling rig derrick and lowered into bore hole, with
logging tool at the end of the cable. Logs are recording while
pulling the tool up the hole. Logs can also be run with special
tools located at the bottom of the drilling string, or
conventional tools can be conveyed on coiled tubing or drill
The first logs for oil field investigation were run by the
Schlumberger brothers, Marcel and Conrad, in 1928 in
Pechebron, France. Soon, the service migrated to North and South
America, Russia, and other locations in Asia. At that time, the
only measurement that could be made was of the electrical
resistivity of the rocks. High resistivity meant porous rock
with oil or gas, or porous rock with fresh water, or tight rock
with very low porosity. Low resistivity meant porous rock with
salty water or shale. Take your pick. Local knowledge helped.
One virtue of the well log was that the top
and bottom of each rock layer could be defined quite accurately.
When the log and depths were compared to the rock sample chips
created by the drilling process, a reasonable geological
interpretation might be possible, but was far from infallible.
By 1932, the spontaneous potential (SP) measurement was added.
The analysis rules expanded: low SP meant shale, or tight rock,
or fresh water. High values meant salt water with or without
oil or gas in a porous rock. The resistivity could then be used
to decide on water versus hydrocarbons. Perfect. Except there
were lots of shades of grey and the SP was not always capable of
1932 in Oil City-Titusville area, Pennsylvania, the location of
Edwin Drake's "First Oil Well" (in the USA - 6 other countries had
oil wells predating this one). His well was only 69 feet deep, so it
penetrated just to the top of these logs, which found deeper and
more prolific reservoirs. Each pair of curves represents the
measured data versus depth for one well. The SP is the left hand
curve of each pair; deflections to the left (shaded) show porous
rock. The resistivity is the curve on the right of each pair.
Deflections to the right (shaded) show high resistivity, and when
combined with a good SP deflection, indicate oil zones. Some good
quality rocks in this example do not have high resistivity and are
most likely water bearing.
The gamma ray log
appeared in 1936. The rules were easy: low value equaled porous
reservoir or tight rocks. High values were shale. It said
nothing about fluid content.
By 1942, Gus Archie had defined a couple of quantitative methods
that turned analysis into a mathematical game, instead of just
some simple rules of thumb. His major work established a
relationship between resistivity, water saturation, and
porosity. If we knew porosity from rock samples measured in the
lab, and a few other parameters, we could calculate water
saturation from the resistivity log values. This was really new
He even attempted to calculate porosity from the resistivity
log. This worked in high quality (high porosity) reservoirs but
had problems in low quality rocks or heavy oil.
Just after 1945, a method that investigated the response of
rocks to neutron bombardment became available. The neutron log
was the first porosity indicating well log. High values meant
low porosity or high porosity with gas. Low values meant high
porosity with oil or water, or shale. Add the gamma ray log, SP,
and resistivity and again the world was perfect, except for all
those shades of grey. Calibrating the response to porosity
depended on a lot of well bore environmental parameters (hole
size, mud weight, temperature) so it was not terribly accurate.
This is an example of a modern sonic log with gamma ray and
caliper curves (far left), shear and compressional sonic travel
time curves (middle) and sonic waveform image log (right).
Depths are shown in the narrow track next to the gamma ray
It wasn't until 1958 that the measurement of the velocity (or
travel time) of sound through rocks in a well bore was achieved.
It turned out that the travel time was a linear function of
porosity and a few other factors.
Shortly after 1960, another
porosity indicating log appeared that measured the apparent
density of the rocks. Porosity was a linear function of density
-- higher density meant lower porosity.
Both sonic travel time
and density as measured by these logs could be transformed into
moderately accurate porosity values, using the gamma ray to
discount shale, and the resistivity to distinguish between
salty water and oil. Fresh water was still a problem and gas
zones could only be located if a neutron log was also run.
This was the state of petrophysics when I entered the scene in
1962. The rules were obvious, the
math was easy. And running the logging tools into the well bore
meant lots of travel. I loved the job. There were no computers
on every desk, calculators were bigger and heavier than
typewriters, so the quantitative work was done with penciland
paper or sliderule. Anybody know what a sliderule is?
Later, with sidetracks into seismic data processing, reservoir
engineering, project management, and seismic data center
management, I finally noticed that petrophysics was the underlying
foundation of much of geology, geophysics, and reservoir
That realization led me to my consulting and teaching career. I got to see a lot of
the world, wrote
a dozen or more
software packages, analyzed the log data from thousands of
wells, and saw even more more of the world,
This may be the only editorial
cartoon ever published in a newspaper (Calgary Herald, circa
1974 - 75) concerning petrophysical analysis.
That`s me peering down a borehole on Melville Island NWT,
estimating the gas reserves to be "four trillion cubic feet".
The final value was closer to 17 trillion. I was the log analyst
and logging supervisor on about 140 wells in the Canadian Arctic
across a 10 year period. We didn`t use our eyeballs to look into
the wellbores directly, of course; we used well logs and calcualtions based on those measurements
to do what our eyes could not.
computers and dumb terminals were really unfriendly
environments. It was
apparent that some portable form of computer was needed to do
the math and make pretty images of our results to show to
management and team members. Five years
before the IBM-PC, the HP9825 calculator became a computer and LOG/MATE,
"The Friendly Log Analysis System", was born (1976).
Today, far more sophisticated and powrerful systems are commont,
but LOG/MATE was the first.
Adverisemenys for my two major forays into the software
business: LOG/MATE 1976 (left), META/LOG (1986)
We now call the business "Integrated Petrophysics" because we
use much more than log data to get our answers. Lab data from
core analysis, such as porosity, permeability and grain density,
are critical input parameters used to calibrate our work. More
exotic lab measurements have become more common as we move into
unconventional reservoir types like shale gas and tight oil
TYPES and USES OF WELL
LOG and LABORATORY DATA
below might not mean too much to someone who is not in the oil
and gas business, but it will give everyone an idea of the scope
of work, wealth of data types, and the multiplicity of uses that
petrophysical data can be applied to.
DATA USES - General Outline
DATA USES -
Irreducible Water Saturation
Water Cut / Relative Permeability
Permeability / Productivity
Fracture Intensity / Orientation
Fluid Contacts - Original and Dated
Pore Volume / Hydrocarbon Pore Volume
Where Are The Reserves?
How Much Does This Well Contribute?
DATA USES - Geophysical Applications
Velocity and Density
Editing Logs for Seismic
Bad Hole Condition
Missing Log Data
Modeling Hypothetical Rock Sequences
Modeling Hypothetical Fluid Content
Vertical Seismic Profiles
Seismic While Drilling
Calibrating Seismic Inversion
Calibrating Seismic Attributes
Amplitude versus Offset Models
Is the Seismic Interpretation Realistic?
DATA USES - Geological Applications
Structure and Stratigraphy
Dip and Direction
Bedding Type / Orientation
Cross Sections / Fence Diagrams
Correlation and Mapping
What Are the Geologic Risks?
DATA USES - Drilling Applications
Designing Vertical Wells
Designing Deviated Wells
Designing Horizontal Wells
Stress Regimes / Fractures
Where Are The Drilling Risks?
DATA USES - Engineering Applications
Calculating Cash Flow
Reservoir Simulation / Modeling
Is The Well/Pool/Project Any Good?
DATA USES - Completion Applications
Stress Regime / Orientation
Hydraulic Fracture Design
Acidizing / Other Treatments
Are There More Targets?
Is production maximized?
DATA USES - Production Applications
Through Casing Reservoir Description
Flow and Production Analysis
Gas Leak Detection
How Do We Repair The Well?
DATA TYPES General Outline
Air / Satellite Images
Tops, Tests, Cores, Perfs, Logs, Status
Logs - Many Variations
Cores - Many Types of Analyses
Data Gathering Considerations
DATA TYPES - ENGINEERING
Wellhead / Bottomhole Pressures
Facilities In Place / Needed
Economics / Costs / Prices
Measurements While Drilling
Logging While Drilling
Seismic While Drilling
Conventional Open Hole Logs
Thin Bed Tools and Processing
Petrophysical Analysis Results
Geological Correlations / Maps
Seismic Analysis / VSP
Core Analysis Results
DATA TYPES - Open Hole Logs
Resistivity and Resistivity Imaging
Acoustic and Full Wave Acoustic
Natural and Spectral Gamma Ray
Formation Density and Litho Density
Dipmeter and Deviation Surveys
Formation Imager and Televiewer
Nuclear Magnetic Resonance
Induced Gamma Ray Spectroscopy
Pulsed Neutron and Activation
Pressure Profiles / Sample Taker
DATA TYPES After Completion
Cased Hole Logging
Reservoir Description Logs
Casing / Cement Evaluation Logs
Bottom Hole Pressure Survey
Well Test Results
Initial Production / AOF / IPR
DATA TYPES Special Cases
Horizontal / Deviated Wells
Logging Through Drill Pipe
Coiled Tubing Logging
DATA TYPES Core Data
Conventional Core Analysis
Permeability, Porosity, Saturation
Grain Density Lithology Description
Special Core Analysis
Thin Section Petrography
Scanning Electron Micrographs
Ultra Violet Light
DATA TYPES Fluid Properties
Water Resistivity, Chemical Analysis
Oil / Gas Analyses
DATA TYPES Pressure Transient
Pressure versus Time
Buildup or Drawdown
Horner / Ramey Plots
PBU Modeling / Curve Fitting
Static Wellhead Pressure
Static Bottom Hole Pressure
DATA TYPES Production Data
Oil / Gas / Water Rates
Changes With Time
Well / Pool / Reservoir Summaries
Deliverability Analysis Results
BASIC VISUAL LOG
I have been
teaching the practical application of petrophysics since 1967.
The seminars always start with "What is a log?" and "What do we
do with them?". The first question was answered in the previous
section. Here, I'll try to provide an answer to the second, just
as it s done in the seminar. We use the rules as developed over
the last 80 years and apply them to the individual log curves as
we see them on paper or on a computer screen.
The step by step procedure using Crain's Rules will reduce the
complexcity considerably and give you a straight forward path
toward your goal. The illustration below is to give you a few of
the basic rules in one single illustration. Further on there is
a more detailed coverage of the Rules.
start with just 3 curves - the gamma ray (GR), resistivity, and
a porosity indicating log (a sonic in this example). The GR is
at the far left and the sonic is the left edge of the red
shading. The resistivity and sonic have been overlaid to make it
easier to see the shape of the two curves relative to each
"A": When GR (or SP) deflect to the left the zone is clean and
might be a reservoir quality rock. When GR deflects to the
right, the zone is usually shale (not a reservoir quality rock).
There are exceptions to this rule, of course.
Basic Rule "B": Porosity logs are
scaled to show higher porosity to the left and lower porosity to
the right. Clean and porous is good, so compare the GR to the
porosity log and mark clean+porous zones.
Basic Rule "C": Resistivity logs
are scaled to show higher resistivity toward the right. Higher
resistivities mean hydrocarbons or low porosity. Low resistivity
means shale or water zones. So clean+porous+high resistivity are
good. There are exceptions to this rule too.
The exceptions are what makes the
job interesting. There are low resistivity pay zones,
radioactive (high GR) pay zones, gas shales, oil shales, coal
bed methane, and low porosity zones that produce for years. Some
of these are shown in the illustration. See if you can figure
logic behind each of the interpretations shown here before you
move on to the more formal rules.
The more detailed Crain's Rules are described here with reference to
the logs shown below.
Crain’s Rule “Minus 1”: Identify log curves available, and determine their scales.
The left half of this image shows a resistivity log
with spontaneous potential (SP) in Track 1 and shallow, medium,
and deep resistivity (RESS, RESM, RESD) on a logarithmic track
to the right of the depth track. The right half of the image
shows a density neutron log with gamma ray (GR) and caliper
(CAL) in Track 1. Photo electric effect (PE) is in Track 2 with
neutron porosity (PHIN) and density porosity (PHID)
Tracks 2 and 3.
Crain’s Rule #0:
Gamma ray or SP deflections to the left indicate cleaner
sands, deflections to the right are shaly. "Shay Sands" fall
in between these two extremes. Draw clean and
shale lines, then interpolate linearly between clean and
shale lines to visually estimate Shale Volume (Vsh).
To find clean zones versus shale zones, examine
the spontaneous potential (SP) response, gamma ray (GR)
response, and density neutron separation. Low values of GR,
highly negative values of SP, or density neutron curves falling
close to each other usually indicate low shale volume. High GR
values, no SP deflection, or large separation on density neutron
curves normally indicate high shale volume.
Very shaly beds are not “Zones of Interest”.
Everything else, including shaly sands (Vsh < 0.50) and
even obvious water zones, are interesting. Although a zone may
be water bearing, it is still a useful source of log analysis
information, and is still a zone of interest at this stage.
Crain’s Rule #1:
The average of density and neutron porosity in a clean zone
(regardless of mineralogy) is a good first estimate for
Effective Porosity (PHIe).
Crain’s Rule #2:
The density porosity in a shaly sand is a good first
estimate for Effective Porosity (PHIe), provided logs are on
"Sandstone Units" scale.
For zones of interest, draw bed boundaries
(horizontal lines). Then review the porosity logs: sonic,
density, and neutron. All porosity logs deflect to the left for
increased porosity. If density neutron data is available,
estimate porosity in clean sands by averaging the two log
values. In shaly sands, read the density porosity.
This is just an estimate and not a final answer -- computer
programs will do the work more accurately, especia;;y pn shaly
Scale the sonic log based on the assumed matrix
lithology. Mark coal and salt beds, which appear to have very
high porosity -- they don't; it is just an artifact of the log
scale combined with their unique petrophysical properties. Identify zones which show high medium,
low, or no porosity. Low porosity, high shale content, coal, and
salt beds are no longer “interesting” as conventional reservoirs.
Crain’s Rule #3:
Tracking of porosity with resistivity on an overlay usually
indicates water or shale.
resistivity with moderate to high porosity usually indicates
water or shale.
Crain’s Rule #4:
Crossover of porosity on a resistivity--porosity overlay usually
resistivity with moderate to high porosity usually indicates
Raw logs showing resistivity--porosity overlay. Red
shading indicates possible hydrocarbon zones. The density or
density porosity (solid red curve) is placed on top of the deep
resistivity curve (dashed red curve). Line up the two curves so
that they lie on top of each other in obvious water zones. If
there are no obvious water zones, line them up in the shale
zones. If the porosity curve falls to the LEFT of the
resistivity curve, as in Layers A and B, hydrocarbons are
To find hydrocarbon indications and obvious water
zones, compare deep resistivity to porosity, by mentally or
physically overlaying the density porosity on top of the
resistivity log. High porosity (deflections on the density log
to the left) and high resistivity (deflections to the right)
usually indicate oil or gas, or fresh water. See red shaded
area on resistivity track on the log above.
Layer A above is a shaly sand and has
medium porosity. Layers B and C are clean sands and have high
porosity. All other layers are shale with no useful porosity.
The average of density and neutron porosity in
Layers B is 24 %; Layer C is 19%. This is close to the final answer
because there is not much shale in these zones. The average in
Layer A is 16 % - much higher than the truth due to the
influence of the shale in the shaly sand. The density porosity is
about 11%, pretty close to the core data. Therefore all our
analysis must make use of shale correction methods. Crain's Rule
#1 handles visual analysis of clean sands (up to about 25%
shale) and Crain's Rule #2 handles shaly sands.
Low resistivity and high porosity usually means
water, as in Layer C. Known DST, production, or mud log
indications of oil or gas are helpful indicators.
Layer B and Layer A show crossover when the
porosity is traced on the resistivity log, so these zones remain
interesting. In fresher water formations, it is often difficult
or impossible to spot hydrocarbons visually. If it was easy, log
analysts would be out of work!
Crossover on the density neutron log sometimes
means gas (not seen on the above example). Watch for rough hole problems, sandstone recorded on
a limestone scale, or limestone recorded on a dolomite scale,
which can also show crossover – not caused by gas.
Water zones with high porosity and low
resistivity are called “obvious water zones”. Fresh water may
look like hydrocarbons, particularly in shallow zones. The lack
of SP development will often help distinguish fresh water zones.
Low porosity water zones may not be obvious.
Crain’s Rule #5:
Approximate Water Saturation (SWa) in an obvious hydrocarbon
zone is estimated from: SWa = Constant / PHIe / (1 -
Constant is in the range from 0.0100 to 0.1200.
as a first try in sands,
0.0600 to 0.0800 in shaly sands, and 0.0250 in
In computer programs, water saturation is usually calculated from the Archie equation
or a shale corrected version of it. This is not easy to do with
mental arithmetic. An easier estimate of water saturation
Crain's Rule # 5: In obvious hydrocarbon zones use a method attributed
to Buckles, SWa = Constant /PHIe. In obvious water zones, SWa =
1.00. If it is not obvious, get professional advice.
Here is the
computer output from the data in the logs used in the visual
analysis shown above.
This depth plot is
typical of a straight forward petrophysical analysis. Some raw data
curves are presented because most people find them helpful in
correlating the zones of interest. From left to right are gamma ray
(GR), spontaneous potential (SP), then three different resistivity
curves (RESD, RESM, RESS) with the depth numbers in between them and
the GR / SP track.
Next come some answers,
from left to right, water saturation (SW), porosity (PHIe),
permeability (Perm), and the mineral breakdown on the right. This
latter track shows only shale and quartz in this example.
The solid red shading in
the porosity track is the oil in the porosity. More red is good
news. The white area to the right of the oil is the water volume in
Using the curve colour
codes and scales at the top of the log, you can identify each curve
and read values for the answers. For example the upper oil zone has
about 10% porosity, 40% water saturation. The zone is 50-60% shale
with the balance being quartz.
The lower oil zone has 24%
porosity, 17% water saturation, nearly zero shale. The white area
underneath the red, indicates a watrer zone under the oil zone.
Coloured dots represent
lab analysis data for [orosity and permeability. The close agreement
with the log analysis means we did a good job. This may have taken a
few iterations to get all the parameters just right.
MORE ADVANCED STUFF
The mineral makeup of
the rocks can often be determined if the petrophysicist becomes
familiar with a few more rules, and can memorize some numerical
values that represent individual minerals.
Crain’s Rule #6:
On Limestone Units logs, the density neutron separation for
limestone is near zero, dolomite is 8 to 12 porosity units,
and anhydrite is 15 or more. Sandstone has up to 7 porosity
Sandstone Units logs, separation for sandstone is near zero,
limestone is about 7 porosity units, dolomite is 15 or more,
and anhydrite is 22 or more.
Visual determination of lithology (in addition to
identifying shale as discussed earlier) is done by noting the
quantity of density neutron separation and/or by noting absolute
values of the photo electric curve. The rules take a little
You must know whether the density neutron log is
recorded on Sandstone, Limestone, or Dolomite porosity scales,
before you apply Crain’s Rule #5. The porosity scale on the log
is a function of choices made at the time of logging and have
nothing to do with the rocks being logged. Ideally, sand-shale
sequences are logged on Sandstone scales and carbonate sequences
on Limestone scales. The real world is far from ideal, so you
could find any porosity scale in any rock sequence. Take care!
SANDSTONE SCALE LOG
Sand – shale identification from gamma ray and
density-neutron separation. Small amounts of density neutron
separation with a low gamma ray may indicate some heavy minerals
in a sandstone. Most minerals are heavier than quartz, so any
cementing materials, volcanic rock fragments, or mica will cause
some separation. Both pure quartz (no separation) and quartz
with heavy minerals (some separation) are
LIMESTONE SCALE LOG
Lithology identification is accomplished by
observation of density neutron separation and the gamma ray
response, along with a review of core and sample descriptions.
The photoelectric effect is often a direct
Crain’s Rule #7: PE below 1 is coal, near 2 is sandstone, near
3 is dolomite or shale, and near 5 is limestone or
anhydrite. The high density (negative density porosity) of
anhydrite will distinguish anhydrite from limestone. High
gamma ray will distinguish shale from dolomite.
SUMMARY OF LITHOLOGY RULES
ROCK N–D N–D PE GR
SAND 0 --7 2 LO
LIME 7 0 5 LO
DOLO 15+ 8+ 3 LO
ANHY 22+ 15+ 5 LO
SALT --37 --45 4.5 LO
SHLE 20+ 13+ 3.5 HI
table, or keep a copy in your wallet. Practice the skill and use it
in your daily work.
THINK LIKE A
1. Find the evidence
2. Assess the evidence
3. Postulate all possibilities
4. Eliminate the impossible
5: Select the answer that fits best with the evidence
Remember: logs are
not perfect and these rules are not perfect. Adjust the rules to
suit your experience. Mineral mixtures are common, so think in terms
of what is possible in each case.
On the log at the
right, the evidence and conclusion is shown for 6 layers with
This is a
LIMESTONE scale log
RULE EXCEPTIONS: High GR log readings coupled with density neutron
log readings that are close together, are a sign of radioactive
sandstone or limestone. To tell radioactive dolomite zones from
shale zones, use a gamma ray spectral log, since the density
neutron log will show separation in both cases. The PE value can
help differentiate between radioactive dolomite and chlorite
shale but not between dolomite and illite rich shale. High
thorium values on the gamma ray spectral log indicate the shale.
Crain’s Rule #8: If it is porous, it is probably permeable.
A quicklook equation for permeability in intergranular or
intercrystalline porosity is: Perm = 100 000 * (PHIe^6) / (Sw^2).
To find signs of permeability, look for
indications of porosity, mudcake shown by the caliper,
separation on the resistivity log curves, known production or
tested intervals, sample descriptions, and hydrocarbon shows in
A quicklook equation for permeability
Perm in milliDarcies = 100 000 * (Porosity ^ 6) /
(Water Saturation ^ 2)
Crain’s Rule #9: If the logs are noisy, blame it on fractures.
To check for indications of fractures, look for
sonic log skips, density neutron crossover in carbonates, hashy
dipmeter curves, hashy resistivity curves, or caved hole in
Crain’s Rule #10: Check your work and revise your assumptions,
then refine rules for each project.
When lab data is available,
checking the answers is relatively easy. If the match between
the log analysis results and lab data is poor, then some
parameters in the analyis model need to be refined. That's where
the "Art of Petrophysics" takes over from the "Science of
Petrophysics". Below is an exaample of the core data (coloured
dots) matching the log data, or vice versa.
“Tight Oil” example showing raw log data on left half of image
and petrophysical properties (answers) derived from that data on
the right half. Raw data includes (from left to right) gamma
ray, caliper, shallow and deep resistivity, photo electric
effect, neutron porosity, density porosity, and sonic travel
time. In this example, high resistivity represents organic rich
source rock (shale) and lower values are found in the oil zone.
The answers are (from left to right) porosity, oil volume in
porosity (shaded red), water volume in porosity (shaded white),
water saturation, permeability, and mineralogy (various colour
symbols) at right of image. Core porosity (black dots), core oil saturation (red dots).
core water saturation (blue dots), and core permeability (red dots)
are plotted on the log analysis results to demonstrate how well
the mathematical model matches ground truth. The model and
parameters can then be used on other wells that do not have this
type of control data. My first colour plot, considerably less
elaborate than this one, was generated from my own
software-hardware package (LOG/MATE) in 1976 from a minicomputer
with only 8 Kb RAM. IBM didn't "invent" the PC until 1981.