The Logging Tools

The variety of logging tools available to modern geoscientists and engineers is enormous.  Some tools are capable of telling us about a wide variety of rock attributes, while others are very specialized. In this section, we’ll cover some of the most important and commonly used tools.

Temperature

Downhole temperature measurements have several uses and can be measured in both open hole and cased hole situations.. For example, knowledge of the geothermal gradient can tell us something about the material properties of the rock a borehole passes through. In addition, the movement of fluids such as through a casing leak, can cause unexpected changes in temperature. Temperature readings can also help evaluate cement and hydraulic fracturing treatments due to temperature changes from pumping the associated fluids into the well.

The measurement of temperature by downhole tools is quite accurate, in theory. The temperature is measured using a standard digital thermometer sensor modified to measure temperatures exceeding 400 degrees C.

In reality, temperature measurements are representative of the temperature of the drilling mud, which is usually less than the temperature of the formation itself. As the formation rocks heat up the drilling mud or fluid in the well since this is where the tool is located, the profile eventually approaches the actual temperature profile of the surrounding rocks.

Temperature readings need to be used with caution and are typically used to supplement information gained using other methods.

Pressure

The goal of a pressure sensor is to measure the formation pore pressure at different depths. Formation pressure is critical because it affects how much oil and gas will be produced and helps ensure that the drilling mud weight remains in a safe range.

Accurate measurements of downhole pressure are essential to drilling performance and operational safety. Monitoring pressure is important for maintaining fluid column hydrostatic pressure and the formation pressure to prevent the influx of fluids from the formation into the borehole

Pressure measurements provide real time measurements that can be used to:

  • Avoid pressure swabs (decreases in well pressure) and surges (increases in well pressure)
  • Detect gas kicks and shallow water flows
  • Determine formation integrity
  • Reduce wellbore instability (i.e. the potential for the well to collapse)
  • Ensure equivalent circulation density is accurately calculated and remains within safe operating systems
  • Monitor the well bore for blockages

Traditionally, pressure was measured during a drill-stem test, in which the entire borehole was “opened up”, allowing fluids to be produced from the formation under consideration. Although this method may still be used in the final stages of formation evaluation, the expense of drill stem tests, along with the danger of a blowout, has led drillers to seek alternative means of testing pressure.

A modern pressure tool allows formation pressure to be tested without making a direct connection between the formation and the surface. Wireline operations must still stop temporarily to take measurements, but this is better than making a round trip in the well to deploy drill stem technology.

Here’s how a typical wireline pressure tool works:

First, a packer, which is typically a rubber pad with a hole in the middle, is extended out of the downhole tool assembly until it presses tightly against the borehole wall, making a tight seal.

Once the packer is seated, a series of valves are opened, allowing fluids to enter the tool through the hole in the center of the packer.

Next, the pressure inside the tool equilibrates with the formation pressure.

Once equilibrium is reached, a pressure gauge inside the tool records the final pressure.

One of the weaknesses of wireline pressure gauges is that if the seal made by the packer is not tight, the pressure exerted by the drilling mud will penetrate to the inside of the tool. If measurements of pressure within the formation are very close or identical to the pressure expected at the bottom of the mud column, operators may begin to suspect a poor seal.

Near the surface, the pressure profile follows the hydrostatic gradient, which is the rate at which overlying fluids cause the pressure to increase with depth. However, once we start getting into deeper formations, the pressure begins to increase faster than expected. This is because older, deeper formations are more likely to contain regions of overpressure where the pore pressure is unexpectedly high. Overpressured zones can be favorable for production purposes, but they require additional safety considerations during well operations to prevent safety hazards such as blowouts.

Caliper

Caliper tools measure the size and shape of the borehole, which, as we learned earlier, can tell us something about the local stress field. In addition to detecting borehole deformation, caliper tools can also detect zones where plastic formations like salt intrude into the borehole, and washout zones, where soft material is eroded from borehole walls resulting in caving in of the formation.

There are two types of caliper tools:

Mechanical calipers consist of four or more arms that extend from the tool to the side of the borehole. Each arm is attached to a sensor which records how far the arm extends to reach the side of the hole at any one depth.

Acoustic calipers rely on the interpretation of ultrasonic signals, which are emitted by a rotating sensor. The time it takes the first signal to return to the sensor can be used to calculate the distance from the center of the hole to its edge.

How are calipers used?

Changes in the size and shape of the borehole provide clues as to what is happening downhole. At first, it might seem like the hole would be the same size as the bit that was used to drill it but that isn’t always the case. The caliper will reveal where the hole has changed shape or been “caked up” or spalled off.

Caliper Readings

Three general cases of readings from the caliper tool describe three states of the hole.

  • Caliper = bit size — Indicates a hard and well consolidated rock
  • Caliper > bit size — Indicates a softer rock where the drilling fluids are eroding the sides of the well, and the hole is washing out, and getting bigger
  • Caliper < bit size — Indicates a permeable rock like sandstone — where the drilling mudcake is building up around the inside of in the borehole; can also indicate a ductile formation material is being extruded into the wellbore

Sandstone is generally permeable, therefore the caliper should be slightly smaller than the bit size because mudcake has built up in the borehole.

Shale will typically fall into the borehole, especially in the direction of minimum horizontal stress. This results in an elliptically-shaped borehole.

Limestone doesn’t show mudcake even though it can be permeable. The mud will build up on the large pores, called vugs or molds, rather than the whole borehole.

Cemented rocks like siltstone are hard, and will remain in gauge.

Halite and potassium rich salts may be washed out if dilute water-based drilling muds have been used, resulting in significant salt saturation changes in the drilling fluid and large un-oriented washouts in the borehole. Salt-saturated and oil-based muds may keep the hole in gauge.

Resistivity

Resistivity logs are used to calculate hydrocarbon saturation and learn about the porosity and permeability of the rock being examined.

As a review from the video, a resistivity sensor passes an electric current through the rocks surrounding the borehole. Changes in resistivity are interpreted as changes in the saturation of a rock with hydrocarbons (highly resistive; less conductive) or saline water (less resistive; more conductive). If the curves differ with the depth of investigation, it is likely that deeper regions are outside the zone of formation invasion. Given knowledge of the size of the zone of invasion, well loggers can estimate the formation permeability or at least the presence of permeability.

Resistivity Tool Designs

There are a wide variety of resistivity tool designs. The major difference between them lies in their depth of investigation, or how far the measurement extends beyond the borehole wall, and their vertical resolution. These characteristics become important because of the process of formation invasion by drilling mud. The invaded fluid can displace some or all of the formation water or hydrocarbons present. Because they are measuring resistivity values, these tools can only be used in open hole situations where a casing string (which is very conductive) does not impact the readings.

To measure the uninvaded portion of the rock from the borehole, a resistivity device must include a large volume of formation, and incorporate devices with at least three or more depths of investigation.

The deep-reading focused devices include:

  • The deep laterolog device (Lld)
  • The deep induction (ILd) device

Medium-depth devices include:

  • The shallow laterolog (LLs)
  • The medium induction (ILm)

The shallow devices include:

  • The microresistivity device
  • The spherically focused log (SFL)

The latest laterolog and induction tools include arrays focused at many depths of investigation—from five to eight depths—measured simultaneously. These allow a better description of the entire invaded zone and allow for interpretation of complex invasion profiles.

The shallowest resistivity device most likely records the highest resistivity because it responds mostly to the invaded drilling mud and mud cake. The medium and deep devices will record responses from deeper in the formation, which will provide close to the true resistivity of the portion of the formation that has not been invaded by drilling fluids.

Sonic

Sonic logging tools record the rate at which sound travels through rock. This attribute, known as the interval transit time, varies between different types of rock formation, and can be used for correlation. The inverse of interval transit time is the velocity of the sound wave. Both “compressional” or the first sound wave arrival (Vp) and “shear” or the second sound wave arrival (Vs) are frequently measured with a sonic logging tool.

The below chart shows the interval transit time for common geologic materials. The waves move most quickly (have the lowest transit time) through limestones, dolomites and basalts (right side of the chart). In shale and sandstone, they move more slowly. Sonic tools consist of a transmitter, which emits a pulse of sound waves, and two receivers, which record the waves as they arrive. The reason there are two receivers is that this allows for elimination of the portion of the signal associated with movement through the drilling mud. Once this signal is removed, the remaining signal is due to transmission of sound through the rock itself.

2-4sonic-velocity-chart

Some Average Sonic Transit Times

MaterialTime in μsec/ft
Sandstone55 μsec/ft
Limestone45 μsec/ft
Dolomite40 μsec/ft
Salt67 μsec/ft
Salt water189 μsec/ft
Methane626 μsec/ft
Oil238 μsec/ft
Fresh water218 μsec/ft

Porosity from Transit Time

In order to calculate porosity (Φ) from transit time of the sound waves emitted by the tool, we use a little math called the Wyllie time-average equation to relate the sonic log velocities to the porosities of the rock. This can be done assuming that the sonic log provides information about two velocities: the velocity of the fluids and the velocity of the rock matrix. The time-average equation can therefore be expressed as:

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Where:
VL is the velocity of the rock from the well log
Vf is the velocity in the fluid
Vm is the velocity in the rock matrix

For calculation of porosity, the time average equation is converted to:

Where:
tlog is the transit time from the well log
tma is the transit time of the wave in the rock matrix
tfl is the velocity in fluid

You may not need to memorize these equations, but you should know why and how they are being done. Also, note that while the tlog value is provided by the log, the tma and tfl values must be assumed when calculating the porosity value. Generally, another log will be used to help determine the appropriate rock matrix type (i.e. sandstone, limestone, shale, etc.) while frequently salt water is assumed to be the fluid in the rock pores.

Sonic tools were once used extensively for porosity estimation, but their use has declined as more accurate tools such as density and NMR tools have become available for that purpose. Sonic tools can also be used to determine rock mechanical properties such as Young’s modulus and Poisson’s ratio which are critical in hydraulic fracturing propagation calculations.

The above descriptions are focused on reservoir rock properties, however, a different type of sonic tool measurement is used in determining the presence of cement when a casing bond log is run.

Density

Density logging tools can be used to determine the bulk (or overall) density of the rock surrounding the borehole. Since the fluids filling the pore spaces of a rock are almost always less dense than the rock itself, the overall bulk density of a rock is closely related to the porosity, which is what geoscientists and engineers are really most interested in. As with all logs, we’re not actually measuring the property that we would like to measure. We are measuring a variety of proxies in an attempt to get answers about the formation characteristics we really want or would like to know.

How do they work?

Density logging tools rely on Compton scattering or on photoelectric absorption. The tools consist of a radioactive source (typically cesium 137) that is surrounded by shielding. A small window in the shielding emits a known amount of gamma rays – about 50 billion per second.

These gamma rays pass into the rock formation and interact with electrons associated with the atoms in the rocks. Some of the gamma rays are reflected back towards the sensor. The higher the density of the rock, the higher the fraction of gamma rays that are reflected. Even in very dense rocks, only a few hundred of the fifty billion gamma rays emitted per second happen to reflect back at the right angle to trigger any of the sensors, which are usually around 1.5-2 feet above the source on the tool.

The flux of the gamma rays to each detector therefore has been attenuated, or reduced, by the rock formation and the amount of attenuation is dependent on the density of electrons in the rock formation.

A formation with a high bulk density will have a lot of electrons. It will significantly attenuate the gamma rays, and a low gamma ray count is received at the detector.

Conversely, a formation with a low bulk density has a relatively lower number of electrons. It will attenuate the gamma rays less, resulting in a higher gamma ray count received at the detector.

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The number of gamma rays that arrive at the detector located further away is inversely proportional to the electron density, which is in turn proportional to the density of the rock formation.

Once we know the density, we go back and calculate porosity. Because bulk density depends on the mineral composition of the rock matrix and the porosity and density of the fluids filling the pores, the density tool helps us determine the porosity of the formation of interest. If a rock is saturated with low-density fluids such as gas, then scientists can more accurately identify lithology.

Some Sample Densities

Average ρeDensity(g/cc)Lithology
1.82.65Sandstone
4.82.71Limestone
3.02.87Dolomite
4.62.03Salt

A density tool is known as a “pad” tool, where the logging tool has a pad on an arm that extends out from the main tool. The pad then rides along the side of the wellbore. Because of this, density tools can only be run in open hole wells before casing is run. Additionally, density tools are susceptible to errors if the mud cake on the formation is too thick for the tools to read through or where wash outs occur and the tool pad cannot adequately touch the borehole wall.

Neutron

Neutron logs record the concentration of hydrogen atoms in a region surrounding the wellbore. Since hydrogen atoms are found in water (the H in H20) and in hydrocarbons (the “hydro” portion of the word, and very few are found within rocks, the presence of hydrogen implies that these fluids are present. Given the overall density of the rock, we’re able to figure out what the porosity would need to be in order for the rock to hold the observed amount of water or hydrocarbons.

Ultimately, the purpose of a neutron tool is to determine the porosity or, given the porosity, to derive the fluid saturation. In neutron logging, a radioactive neutron source, typically beryllium, emits neutrons into the formation. These neutrons interact with the neutrons in hydrogen atoms and ultimately release gamma rays. Sensors record the intensity of gamma ray returns, which is proportional to the number of hydrogen atoms in the formation.

In addition to measuring porosity, neutron logs can be used to determine rock type for a rock with known porosity and saturation. Each type of rock has a hydrogen index, which describes the amount of hydrogen contained within the minerals that make up the rock itself. When combined with information collected by other logging tools, the hydrogen index can be used to roughly determine the lithology of the unit under consideration.

NMR

Nuclear magnetic resonance, known as NMR, is an advanced technique that provides very detailed information about the porosity or permeability of rock. It is also called magnetic resonance imaging, or MRI, and is based on the same science as an MRI scanner at a hospital, albeit with a much different purpose.

A permanent magnet is contained within the NMR tool. As the tool comes near a rock layer, the magnet causes protons in the surrounding atoms to align with its magnetic field. After the protons are aligned, the tool emits an electromagnetic pulse. This pulse temporarily knocks protons out of alignment with the field. As the protons realign, they release the energy they absorbed from the pulse.

The amplitude of this energy release is directly related to the number of protons in the rock. Since all atoms contain protons, the amplitude is essentially related to the amount of matter in a given volume of rock – in other words, the density.

The tool sensor also measures the die-off pattern of the energy release. It turns out that protons in solid matter realign with the field more slowly than protons contained in fluids such as water. Protons in the middle of a pore space realign fastest, while those at the edges realign more slowly but still faster than those in the solid rock surrounding the pores.

By studying the distribution in time of the energy returns, we’re able to figure out the size distribution of pores within the rock. When combined with the amplitude, which is proportional to the hydrogen nuclei in the formation, the porosity characteristics of the rock can be estimated, with higher amplitude suggesting higher pore space, and in turn, higher hydrocarbon content.

Gamma Ray

Gamma ray (GR) logging measures naturally occurring radiation associated with uranium, thorium, and potassium within the formation rocks. Each type of rock within a given formation has a characteristic radioactivity. For example, shales typically have a significantly higher level of radioactivity than other sedimentary rocks. Most of the rocks and minerals that make up the Earth’s crust and the surficial materials derived from them contain some traces of radioactive elements.

The GR tool consists of a sensor called a “scintillation counter”. This is a cylindrical crystal of sodium iodide that naturally produces flashes of light whenever gamma rays pass through it. A photomultiplier amplifies these flashes, converting them into an electronic signal. The frequency of gamma rays (measured in decays/sec) is what actually ends up being recorded. More advanced sensors are able to differentiate between gamma rays emitted by each of the three radioactive elements, which allows rock units to be “fingerprinted”.

Radioactive elements are typically concentrated in clay minerals, which results in a higher gamma ray signature in shales than other types of rocks. With enough correlation from other types of logs, gamma ray logs can be used to identify specific rock units.

Gamma ray tools can work in both open hole and cased hole situations. This is critical to well operations as they are the main way to calibrate between measurements taken during an open hole logging operation and those that are performed once a well is cased. It may seem like depth is a better way to calibrate such, however, keep in mind that wireline can stretch to different depths during operations. Therefore, having the bottom hole measurements of a gamma ray tool are critical to linking these pieces of data.  

Spontaneous Potential

The spontaneous potential (SP) log measures the natural electrical potential (in millivolts) between rock units and a fixed electrode on the surface of the earth. The SP log will only work if the drilling fluids are water-based and there are no air spaces or pockets along the wellbore profile.

Depending on whether a formation is permeable or impermeable, a positive or negative electric potential will build up along the inner walls of the wellbore. In rocks containing hydrocarbons, which are non-conductive, the total potential recorded by the tool will be reduced. This fact means that, in conjunction with data collected by other sensors, the SP tool can be used to diagnose the presence or absence of hydrocarbons.

The tool itself is simply an electrical conductor that is allowed to electrically interact with the wellbore fluids at the depth of the tool. The conductor is run up to the surface, where simple meters can be used to measure the spontaneous potential.

The Science of Electrical Potential

Spontaneous potential occurs when two aqueous solutions with different ionic concentrations are placed in contact through a porous, semi-permeable membrane. In SP logging, these are the drilling mud filtrate and the formation water, or connate water. In nature these ions flow from low to high concentrations, where the net effect is a current flow from the more dilute solution to the more concentrated solution. In most boreholes, the drilling mud filtrate is the weaker solution and the formation waters the stronger solution. The greater the contrast between the two fluids, the greater the spontaneous potential will be.

The direction in which the SP curve is deflected is dependent on whether the drilling mud contains more or less salt, or ions, than the formation water. If the ionic concentration of the well bore fluid is greater than the formation fluid then the deflection of the curve will be negative. If the formation fluid has an ionic concentration greater than the well bore fluid, the deflection will be positive. The amplitudes of the line made by the changing spontaneous potential will vary from formation to formation.

Interpretation of spontaneous potential first relies on determining the baseline reading of a shale formation, which will form a relatively straight line on the log. Shale spontaneous potential will typically shift very little over the depth of a borehole. The spontaneous potential of shale is not significant and the shale baseline is assumed to be zero, so deflections from baseline can show permeable layers.

The potential differences at the contact between a shale and sand layer will deflect the SP from the shale baseline. The deflection is negative for a normal salinity contrast, when the drilling mud has less salt than the formation water, and reversed if formation fluids are fresher. Shallow sands may reflect a positive deflection from the shale baseline if they contain fresh water.

If the drilling mud salinity is the same as the formation salinity, the spontaneous potential will have a very low amplitude with no obvious relationship to beds. Little change occurs within a sand interval, so a clean sand shows a straight-line, sometimes referred to as a “sand line”.

In carbonate and evaporate formations, the spontaneous potential log is less useful due to the absence of boundaries between shale beds and permeable beds, and the SP curve has no sharp, useable deflections.


Citations

1. Alberty, M. W., 1994, Standard interpretation; part 4 – wireline methods, in D. Morton-Thompson and A. M. Woods, eds., Development Geology Reference Manual: AAPG Methods in Exploration Series 10, 180–185.

2. Bjørlykke, K., & SpringerLink, 2015, Petroleum geoscience: From sedimentary environments to rock physics (2nd 2015. ed.): Berlin, Heidelberg, Springer Berlin Heidelberg, 666 p.

Images: “Logging Tools” by Michael Black