ohbasic presentation

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 ?

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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

GAPI

150

Shaly Sand Shale Clean Sand Sandy Shale Limestone Volcanic Ash Dolomite Coal Anhydrite / Salt Gypsum

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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.

00

GAPI GAPI

150 150

Clean Clean Formation Formation

Shale Shale

Uranium Uranium Rich Rich Clean Clean Formation Formation

Potassium Potassium Rich Rich Clean Clean Formation Formation Potassium Potassium Thorium Thorium Uranium Uranium

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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 (Φ) 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;

Φ=(tLOG -t ma)/(tff-tma ) LOG ma ma Where: Φ tLOG tma tfl

= porosity =sonic travel time read from the log =sonic travel time in a clean 0 porosity matrix =sonic travel time in the wellbore fluid

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Some common values for sonic travel times (∆t) are: Sand Limestone Dolomite Anhydrite Fresh muds

∆t = 182 µs/m ∆t = 156 µs/m ∆t = 143 µs/m ∆t = 164 µs/m ∆t = 620 µs/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 µs/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. 00

µµs/m s/m

GAPI GAPI 150 150

GR GR

500 500

∆∆tt

100 100

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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 7

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 . GAPI GAPI

% %

00

150 150

GR GR

60 60

00

NPOR NPOR

Limestone Limestone

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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 (ρma), and having a porosity (Φ) that contains a fluid of density (ρf), the formation bulk density (ρb) will be:

ρb = Φρf + (1-Φ Φ)ρ ρma or, re writing this for porosity, we can use:

ΦD = ρma - ρb / ρma - ρfl Where:ΦD = Density porosity ρma = density of matrix material ρb = measured by density tool ρfl = density of fluid in the borehole Some common Densities ( ρ ) 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.

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Convert the following bulk densities to porosity. Calculate for sandstone, limestone, and dolomite. Fluid is fresh water.

00

GAPI GAPI

GR GR

150 150

2000 2000

K/m3 K/m3

3000 3000

rhob rhob

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.

10

GAPI GAPI

00

00 150 150

PEF PEF

10 10 % %

60 60

00

MDEN=2650 MDEN=2650 GR GR

PEF PEF

DPHI DPHI

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)

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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. Total Total Porosity Porosity Neutron Neutron Porosity Porosity

Gamma Gamma Ray Ray GAPI GAPI 00

150 150

% %

Density Density Porosity Porosity Sonic Sonic Porosity Porosity

60 60

00

Uncompacted Uncompacted Shale Shale Uncompacted Uncompacted Clean Clean Sand Sand Compacted Compacted Shaly Shaly Sand Sand Compacted Compacted Clean Clean Sand Sand

Gas Gas Oil Oil // Water Water Gas Gas Oil Oil // Water Water Gas Gas Oil Oil // Water Water

Compacted CompactedShale Shale

Carbonate Carbonate

Intercrystaline Intercrystaline

Gas Gas Oil Oil // Water Water Gas Gas

Vugy Vugy

Oil Oil // Water 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 ΦD is available, use ΦTotal = ΦN

–

If only ΦN and ∆t are available, use ΦTotal = ΦS with compaction corrections.

In a carbonate, for initial computations: –

ΦN+Φ ΦD)/2 If ΦN and ΦD are available, then use ΦTotal = (Φ

–

If only ∆t is available, use ΦTotal = ΦS + Estimated ΦVugs

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. 13

Shale Shale

Sand Sand

Shale Shale Rmf Rmf == Rw Rw

Rmf Rmf > Rw Rw Fresh Fresh mud mud (most (most common) common)

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. 14

On the following logs, pick the apparently permeable zones. OHMm OHMm 00

20 20 Micorinverse Micorinverse

SP SP

Micronormal Micronormal

GR GR

Caliper Caliper Bit Bit Size Size

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: 15

Consider a cube of water (Φ = 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 α Rw Now, take the cube and put some rock in it. Since rock is an insulator, as we add rock (decrease Φ) we increase the total resistivity.

Rt α 1/Φ 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 α 1/Sw So if we combine these equations, we get; Rt a Rw * 1/Φ Φ * 1/Sw or re-writing it for Sw

Sw α Rw / Φ 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.

Sw Swnn == aa ** Rw Rw // Φ Φmm ** Rt Rt 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 Φ 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 17

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 18

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 = Φm * 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. 19

Quick Look Method for Evaluating Wireline Logs in the Western Canadian Sedimentary Basin 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