2

Why are we Logging Wells ?

Wireline logging can be used in a number of ways by a number

of people to provide solutions to questions they have about a particular

well. Some of the ways different people in an office will use these logs

are:

Geophysics look to logs for:

– Where are my tops (as predicted?)

– Does seismic interpretation agree with log data?

– How is my synthetic doing with this new information?

Geologists look to logs for:

– Where are my tops ?

– Do I have any reservoir ?

– Is there any Hydrocarbon in the well ?

– What type of Hydrocarbon(s) is there ?

– How good is my reservoir ?

– What kind of reserves do I have ?

– How does this tie in to my offsets ?

Drilling Engineers are looking for:

– What is my hole volume (cement) ?

– What is my dog leg severity ?

– Where can I get a good packer seat for testing ?

– Where can I set up my whipstock ?

Production Engineers are looking for:

– Where should complete this well ?

– What will be my expected production rates ?

– Will I have to deal with water ?

– How should I complete this well ?

– Do I need to stimulate this well ?

– How should I stimulate it ?

3

In this course, we are going to be concentrating on reservoir

characterization and quality aspect of these uses. Specifically, we will be

learning a method to quickly interpret open hole wireline logs to determine

if there is a potential reservoir and then how to evaluate it for hydrocarbon

production. To do this, we will look at the basic tools used in open hole

logging, and then find out how to interpret the readings from these tools

and combine them to evaluate your well. The first step along this path will

be looking at open hole logs and determining if we could possibly have a

reservoir.

The Gamma Ray Log

One of the first things we need to look for when we look at a log is

a suitable reservoir. Preferably this will be a ‘clean’ (little to no shale)

formation. The Gamma Ray log can help give an indication of this. The

tool itself reads the natural gamma radiation in the formation adjacent to

the detector. Since clays and shales tend to accumulate radioactive

materials, the gamma ray (GR) log is used as a shale indicator with a high

gamma ray indicating shale (around 100 GAPI) and low gamma ray

indicating clean formation (~30 GAPI in sands, and about ~15 GAPI in

carbonates). Some typical GR values are shown below.

0 150

GAPI

Shaly Sand

Shale

Clean Sand

Sandy Shale

Limestone

Volcanic Ash

Coal

Anhydrite / Salt

Gypsum

Dolomite

4

Other materials commonly found in the well bore also affect the

GR log. For example, volcanic ash can be very radioactive and thus

cause an unusually high GR reading. As well, feldspar (mineral) that is

common some sands can cause the GR to read high in a clean sand (an

example of this is the granite wash around the peace river arch). Coal,

Anhydrite, Salt, and Gypsum are typically contain little radioactive material

and thus show up as clean.

In some cases, it is valuable to know not only that there are

radioactive elements present in the formation, but also the amount of the

particular radioactive mineral is present. This allows us to do things like

minimizing the effect of feldspar (potassium) to determine a clean sand, or

to actually get the clay type in any particular shale (I.e. swelling shales,

brittle shales, shales prone to collapse). To do this, it splits the natural

gamma rays into there respective energy spectrum and quantifies the

three main radioactive elements; Thorium, Potassium, and Uranium.

0 150 GAPI

Potassium

Thorium

Uranium

Clean Formation

Shale

Uranium Rich Clean Formation

Potassium Rich Clean Formation

5

Now that we know how to identify clean formations, the next thing

to look at is weather or not these formations have any storage space.

Porosity Logs

In any reservoir, we need to have a certain amount of open space

so that hydrocarbons have some where to exist. We call this storage

space porosity, and typically use three basic tools to determine what

porosity (F) might be. These are the Neutron tool, the Density tool, and

the Sonic tool. While all of these tools give a porosity output, they only

infer this from different properties of the rock and fluid in the rock.

The Sonic Log

The Sonic log, as the name implies, uses the travel time of sound

through the formation to infer porosity. That is, it sends a sound pulse or

a ‘click’ out from a transmitter, and then measures the time it takes to

travel through the formation and back to a receiver on the tool. By

comparing how fast the ‘click’ travels through the rock to how fast it

should travel if there were no porosity, and knowing how fast sound will

travel through fluid, we can infer a liquid filled porosity. Since sound

travels at different speeds through different types of rock, it is important to

know rock type (sandstone, limestone, or dolomite). Also, it is important

to note that whatever is in the pore space (porosity) will also have a small

affect on the porosity (for example, sound travels through gas at lower

rates than through fluid, therefore porosity estimates in gas will appear

high). The equation for finding porosity (commonly we use the Wyllie

Time-Average Equation which is based on laboratory measurements) is a

follows;

Where: F = porosity

tLOG =sonic travel time read from the log

tma =sonic travel time in a clean 0 porosity matrix

tfl =sonic travel time in the wellbore fluid

F=(tLOG-tma)/(tf-tma)

6

Some common values for sonic travel times (Dt) are:

Sand Dt = 182 ms/m

Limestone Dt = 156 ms/m

Dolomite Dt = 143 ms/m

Anhydrite Dt = 164 ms/m

Fresh muds Dt = 620 ms/m

In sand, you can have formations that are not fully compacted.

That is, the sand grains are not perfectly packed on top of each other as

they were in Wyllie’s measurements. To correct for this, we look at

adjacent shale beds (where sound velocity is highly effected by

compaction) and divide the sonic velocity read from the log by 328 ms/m.

The porosity from the Wyllie equation is then divided by this Bulk

Compaction Factor (Bcp) to give a more realistic porosity.

Alternately, we can use the Raymer - Hunt transform from chart

Por -3m (the red ‘field observations’ lines). This chart is actually an easy

way to calculate porosity from a sonic log using either method. The

advantage to using the ‘field observations’ is that they have used a

transform based on field data to eliminate bulk compaction factor from the

equation.

Use chart Por-3m and/or the equation above to find porosity in the clean

zones below.

500 100

GR Dt

0 150

GAPI ms/m

7

Since we only infer porosity from sonic travel time measurements,

a number of factors can affect the sonic porosity:

– Fluid type; since the depth of investigation of the sonic log is fairly shallow,

most of the fluid seen by the sonic will be mud filtrate. Residual gas will cause

the sonic to read slightly high porosity's.

– Compaction; lack of compaction will cause the porosity reading to be high

unless compaction is factored in, either using the Bcp or field observation

transform.

– Secondary porosity; secondary porosity (such as vugy porosity) will not be

detected by the sonic because there is always a travel path for the sound waves

past the pore space. This fact actually benefits us by allowing us to determine

how much secondary porosity there is by comparing the sonic porosity to the

porosity from another tool.

– Borehole; The condition of the borehole is usually corrected for with modern

tools however highly rugose boreholes will affect the sonic travel time and cause

unreliable sonic porosity's.

The Neutron Log

The second porosity tool we will look at is the Neutron porosity

tool. The neutron tool uses the amount of hydrogen in a formation to infer

porosity. Since water / oil has a relatively constant amount of hydrogen

atoms by volume, the amount of hydrogen can be used to infer the

amount of fluid in a formation, which in a clean formation is the porosity.

Neutron tool theory can be summed up as follows. Neutrons are

electrically neutral particles having a mass almost identical to the mass of

a hydrogen atom. High energy (fast) neutrons are continuously emitted

from a radioactive source within the tool. These neutrons collide with the

nuclei of the formation materials in what may be thought of as elastic

billiard ball collisions. With each collision the Neutron looses some of its

energy. The amount of energy lost per collision depends on the relative

mass of the nucleus with which the neutron collides. The greater energy

loss occurs when the neutron strikes a nucleus of equal (or almost equal)

mass ( Hydrogen). Since collisions with larger or smaller nuclei do not

affect the energy of the Neutron much, the slowing of the neutron is

largely due to the amount of Hydrogen in the formation. Within a few

micro seconds, the neutrons have been slowed through successive

collisions to energies of about 0.025 eV. They then float around until they

are captured by the nuclei of atoms such as Chlorine, Hydrogen, or

8

Silicon. By using a detector that measures the amount of low energy

Neutrons, and by knowing what quantity of neutron capture elements

(Chlorine, Silicon, etc.) in the formation material, we can say how much

hydrogen is in the formation. The amount of hydrogen in the formation is

also known as the Hydrogen Index (HI), which is the measurement of the

amount of Hydrogen per unit volume of formation.

The Neutron log is presented in porosity units based on a

particular matrix type (sandstone, limestone, or dolomite). Since the

amount of neutron absorbers in the formation greatly affect the porosity

readings of the log, it is essential that the correct matrix be used.

The factors that may affect the neutron log are are:

– Lithology; A single known matrix must be present to accurately determine

porosity’s. Large errors may occur if matrix selection is incorrect.

– Shale; The presence of chemically bound water in shales causes the the

neutron log to read high porosity’s in shales or shaly formations.

– Fluid Type; since liquid hydrocarbons contain similar hydrogen concentration to

water, they do not affect the porosity readings. Gas hydrogen concentration is

much lower than that of water and therefore will give low porosity’s.

Chart Por-13b allows you to convert between different matrices to arrive

at a true porosity for the particular matrix type present.

Use Chart Por-13b to convert the following to both sandstone and dolomite porosity’s

.

0 150 60 0

GAPI %

GR NPOR Limestone

9

The Density Log

The third common type of porosity tool is the Density tool. The

density tool, as its name implies, uses the electron density of the

formation to infer a porosity. It makes use of a radioactive source which

emits medium energy gamma rays into the formation. The amount of

number of gamma rays that are received at the detector indicates the

formation density. This density that the tool reads is a combination of the

density of the matrix (solid portion of the formation), the porosity of the

formation, and the density of the fluid in the pore space. So, for a clean

formation of known matrix density (rma), and having a porosity (F) that

contains a fluid of density (rf), the formation bulk density (rb) will be:

rb = Frf + (1-F)rma

or, re writing this for porosity, we can use:

FD = rma - rb / rma - rfl

Where:FD = Density porosity

rma = density of matrix material

rb = measured by density tool

rfl = density of fluid in the borehole

Some common Densities ( r ) are:

Sandstone - 2650 Kg/m3

Limestone - 2710 Kg/m3

Dolomite - 2870 Kg/m3

Fresh Water - 1000 Kg/m3

Oil - 850 Kg/m3

Appendix B in the Chart book has density values for various rocks. As

well, Chart Por-5 may be used to calculate porosity from bulk density.

10

Convert the following bulk densities to porosity. Calculate for sandstone, limestone,

and dolomite. Fluid is fresh water.

Typically, the bulk density will be converted to porosity and presented with

the neutron porosity log. The matrix density used for the porosity

calculation should be noted on the bottom and top of the logs.

In addition to the bulk density measurement, the toll also

measures the photoelectric absorption index, which can be related to

lithology. The photoelectric absorption factor is presented on the log as a

PEF curve and can be used in conjunction with the bulk density to

indicate the matrix type. Appendix B in the chart book gives different

values of bulk density and PEF values. The values for the common

matrix types are:

Sandstone PEF ~ 1.8 RHOB ~ 2650 Kg/m3

Limestone PEF ~ 5.1 RHOB ~ 2710 Kg/m3

Dolomite PEF ~ 3.1 RHOB ~ 2850 Kg/m3

On the following log, check the lithology and determine the proper porosity readings.

Assume fluid density of 1000 Kg/m3.

0 150 2000 3000 GAPI K/m3

GR rhob

11

Factors that may effect the Density Log are:

– Lithology; the correct matrix density must be known to get a correct porosity.

– Shale; the density of shale ranges from 2200 to 2650 Kg/m3 but is usually close

to 2650. This means the shale appears as matrix to the density tool and it gives

a good indication of effective porosity

– Fluid type; since the depth of investigation of the density tool is shallow, the fluid

generally seen is the mud filtrate. If residual fluid is in the area of investigation,

it will have the following effect;

• Oil; residual oil will drive the density porosity high.

• Salt water will drive the density porosity low

• Gas; residual gas will drive the porosity reading high.

– Borehole effect; in very rough boreholes, the density tool may lift off the

formation wall causing incorrect bulk density readings. (Density porosity will be

high)

0 10 PEF

0 150 60 0

% GAPI

GR PEF DPHI

MDEN=2650

12

Total Porosity Determination

We have now seen that the basic porosity measurements are

inferred from measurements of bulk density, hydrogen concentration, and

acoustic travel time. These porosity’s are valid under the following

conditions:

– The porosity type is intergranular, not fractured or secondary.

– The matrix type is known and constant

– The rock is clean (I.e. no shale present)

– The porosity is filled with fluid

If any one of these conditions are not met, the porosity measurements will

disagree in one fashion or another. This difference can be used to

determine a number of factors including: lithology, primary/secondary

porosity, gas vs. liquid filled porosity, etc. The following is a table of the

responses of the basic tools in various situations.

0 150 60 0 GAPI %

Gamma Ray Total Porosity

Neutron Porosity

Density Porosity

Sonic Porosity

Uncompacted

Shale

Uncompacted

Clean

Sand

Compacted

Shaly

Sand

Compacted

Clean

Sand

Compacted Shale

Carb

on

ate

Intercrystaline

Vugy

Gas

Oil / Water

Gas

Oil / Water

Gas

Oil / Water

Gas

Oil / Water

Gas

Oil / Water

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So, which porosity measurement should be used? Depending on

the formation and the tools available, we use the following.

In a sand shale sequence, for initial computations:

– If FD is available, use FTotal = FN

– If only FN and Dt are available, use FTotal = FS with compaction

corrections.

In a carbonate, for initial computations:

– If FN and FD are available, then use FTotal = (FN+FD)/2

– If only Dt is available, use FTotal = FS + Estimated FVugs

So now we can pick a clean formation and we can determine

weather or not the formation has any pore space to contain hydrocarbon.

Now, how do we tell if the formation fluid can actually move?

Permeability Indicators

Permeability is the measurement of how well fluid moves through

a formation. The greater the permeability, the easier it is for fluid to move

in the formation. Although there are quantitative ways to determine an

actual number for permeability, we will only deal with relative permeability

in this course.

Spontaneous Potential

One of the first indicators of permeability we look at is the

Spontaneous Potential (SP) curve. A spontaneous potential is created

when fluids of different salinity come in contact with each other, either

directly, or through a permeable membrane such as a shale. Ion transfer

between the fluids causes a electric potential to be created at the

boundary. Because Ion movement must occur, this becomes a good

indicator of permeable zones. The difference between the mud filtrate

resistivity and the formation fluid resistivity will affect the amount and

direction of the SP deflection.

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As well as the SP, some other common logs can be used for permeability

indication.

Microlog

The Microlog tool measures resistivity at two depths, then

compares them to indicate permeability. If there is permeability, then

mudcake should build up. Therefore, the shallow reading on the microlog

(Microinverse) will read the mud cake (generally lower) and the deeper

reading (Micronormal) will read the invaded formation (generally higher)

producing a positive curve separation.

Caliper

Another good indicator of permeability is the caliper device. Since

permeability produces mudcake, the borehole should be constricted

where a permeable formation is. So if we look at the caliper curve and it

is smaller than the bit size in a porous zone, than that zone is most likely

permeable.

Shale

Sand

Shale

Rmf = Rw Rmf < Rw Rmf > Rw

Salt mud Fresh mud

(most common)

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On the following logs, pick the apparently permeable zones.

So, we now have a clean, porous, permeable formation. All we

have to do now is find out what will come out of it.

Water Saturation Calculations

To find out weather pore space will contain water or hydrocarbon,

we need to look at a few of the physical properties of the formation and

the fluids it may contain.

1) Rock does not conduct electricity

2) Hydrocarbon does not conduct electricity

3) Water does conduct electricity

So, to begin looking at what it is in the pore space, we need to look at

what we can measure, the water saturation or Sw. We measure it using

the Archie equation. It can be derived as follows:

Micorinverse

Micronormal

GR

SP

Caliper

Bit Size

0 20

OHMm

16

Consider a cube of water (F = 100%, Sw = 100%). If we measure the

resistance across it, we get a resistivity we will call Rt. If we vary the

resistivity of the water in the cube, the total resistivity of the cube will vary

proportionately.

Rt a Rw

Now, take the cube and put some rock in it. Since rock is an insulator, as

we add rock (decrease F) we increase the total resistivity.

Rt a 1/F

If we replace some of the fluid with hydrocarbon (an insulator) we are

effectively decreasing Sw. Since rock is an insulator, a decrease in Sw

will increase Rt.

Rt a 1/Sw

So if we combine these equations, we get; Rt a Rw * 1/F * 1/Sw

or re-writing it for Sw

Sw a Rw / F Rt

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Archie did some laboratory work and placed a few constants in the

equation to remove the proportionality and provide a solvable formula.

Where:

Sw = water saturation

Rw = water resistivity

Rt = total resistivity

F = porosity

m = cementation factor

n = saturation exponent

a = constant of proportionality

For basic interpretation, we use a n of 2.

Depending on the formation, we use different values for a & m.

For sands a = .62 m = 2.15

or a = .81 m = 2

For carbonates a = 1 m = 2

So, we know how to find F for this equation, what we need to find is Rt

and Rw.

Resistivty Tools

Resistivity tools are tools that directly or indirectly measure the

resistivity of a formation. Tools that measure this directly are generally

called Laterolog tools, and tools that induce current to flow in the

formation are called Induction tools. The primary constraint for using one

or the other is the mud fluid type. In order to carry current directly to the

formation, we need to have a conductive mud. The more conductive, the

Swn = a * Rw / Fm * Rt

18

better the readings. If there is not a good conductive path (fresh water,

invert mud system, foam, gas, etc.) than we need to read the resistivity in

another fashion. Since the basic principle of the laterolog (direct current

device) is fairly simple (you measure the resistivity between two

electrodes) we will skip to the Induction device.

The induction device uses a coil to create a magnetic field. The

magnetic field created from current passing through this coil causes

current to flow in the formation in ground loops. These ground loops in

turn create a magnetic field that causes current to flow in a receiver coil in

the tool. Since the strength of the current in the receiver coil is directly

related to how much current is flowing in the formation, and we know how

strong a current was used to create the current flow in the formation, we

can get the resistivity of the formation.

The resistivity of the formation, if read deep enough to eliminate

any effects of the borehole and invasion, is then the Rt in the Archie

equation. Generally, we use the deepest reading of the induction or

laterolog tool to estimate Rt.

The last step, then, is to find the last piece of the Archie equation,

the formation water resistivity (Rw)

Formation Water Resistivity

One of the keys to identifying hydrocarbon in the formation is knowing the

correct water resistivity (Rw). There are a number of ways to find this

number.

One of the most common ways (in Western Canada) is to use the

Formation Water Resistivities Catalogue. This is a compilation of water

resistivities from formations all over the Western Canadian Sedimentary

Basin. To use this, you find the formation you want an Rw for, turn to the

page that the formation is mapped on, and then use the location to find

the Rw. You then need to correct the Rw to the temperature of the

formation you are looking at. To do this, Chart Gen-9 is helpful. First go

to the bottom and mark a vertical line at 25C. Then mark your

19

resistivity from the catalogue on the left hand side (careful with the

scales). The point at which they intersect will be the salinity of the

formation. We use salinity because it is fixed for a given water despite

temperature. Mark another point on the bottom where your formation

temperature is (I.e. 40C) and draw a vertical line. Now take your point

from the Rw catalogue and follow it down the blue lines (constant salinity)

until it intersects the formation temperature line (vertical). Take this point

a draw a line straight to the left edge and read the Rw at your formation

temperature. If you prefer to use a calculator, you can use the equation

R2 = R1 [(T1+21.5)/(T2+21.5)]

where R2 = Rw at formation temperature

R1 = Rw from the water catalogue

T1 = Temperature in water catalogue

T2 = Formation temperature

Another method of finding Rw is by using actual water sample

from the well. Be careful that this reading is at the correct temperature as

well.

One more method can be used if there is a clean, 100% wet zone

present nearby. In this case (using the Archie equation)

Rw = Fm * Rt

We now know how to pick a clean zone, check for porosity and

permeability, and evaluate it for Hydrocarbon content. In other words, we

now can start do quick look evaluations of Open Hole logs. One thing to

remember, however, is that this is only a quick look method. As seen

through the beginning of this course, many things can affect the logs and

throw the interpretation off. Even so, you now have a place to start from.

The next page summarizes a method of performing quick look

evaluations in the Western Canadian Sedimentary Basin.

20

1) Pick out all the zones that are not shale using the GR

2) Use the porosity log to pick the zones in step 1 that are porous

Sandstone - use the density log if possible

- eliminate all zones with <9% porosity

Carbonate - use the neutron and density porosity's

- eliminate all zones with <3% porosity

3) For zones left from step 2, pick the zones that are permeable using

the SP (and / or any of the other methods)

4) From the zones left from step 3, pick out the zones with high

resistivity. These should be your Hydrocarbon bearing zones.

5) We now have our zones of interest. The Neutron and Density (or

neutron/sonic) logs can be used to identify gas zones (cross over).

6) Water Saturation Calculations

for sands Sw = (.62 * Rw)/(F2.15 * Rt)

for carbonates Sw = (1 * Rw) / (F2 * Rt)

Quick Look Method for Evaluating Wireline Logs in the

Western Canadian Sedimentary Basin

21

Will it Produce ??

In Sandstones

If Sw > 0.35 Usually no water will be produced; only

hydrocarbon.

If Sw = 0.6 - 1.0 The Zone will produce only water.

In Carbonates with Vugy Porosity

If Sw = 0.1 The zone will produce only hydrocarbon.

If Sw = 0.35 - 1.0 The zone will produce only water.

In Carbonates with Intergranular or Intercrystaline porosity

If Sw < 0.35 Usually no water will be produced; only

hydrocarbon.

If Sw = 0.60 - 1.0 The zone will produce only water.