Well Logging Tools & Techniques (Special Open Hole Tools)

Special Open Hole Tools

Caliper Logs

The caliper log measures the diameter of the borehole. The first caliper logs were developed to determine borehole size in holes shot with nitroglycerin. These early logs showed large variations in hole size, even in the portions of the hole that had not been shot. This illustrated the need for the caliper log over the entire hole.

Methods of Recording Several types of caliper are currently in use. One type consists of three or four spring-driven arms that contact the wall of the borehole. The instrument is lowered to the total depth, and the arms are released either mechanically or electrically. The spring tension against the arms centers the tool in the well. The arms move in and out with the change in wellbore diameter. The arm motion is transmitted to a rheostat so that change in the resistance of an electric circuit is proportional to the hole diameter. The borehole diameter is recorded at the surface by measuring the potential across this resistance.

Another instrument uses three flexible springs that contact the wall of the borehole. These springs are connected to a plunger that moves up or down as the springs expand or contract with changes in borehole diameter. The plunger passes through two coils. When an alternating current is passed through one coil, an electromotive force (emf) is induced in the other coil. The amount of this induced emf is a function of the plunger position and is proportional to borehole diameter.

Both of these instruments may be adjusted to record borehole area rather than hole diameter. If the caliper log is used to determine hole volume, it is desirable to record area on a linear scale. If the caliper log is used to determine hole configuration, the hole diameter is recorded on a linear scale.

A third type of caliper log, the microcaliper, is discussed in connection with the electrical-log microdevices. This instrument uses two pads rather than arms or flexible springs. Hole diameter is determined by the movement of these pads, which are held against the borehole wall by springs.

Typical Configuration on the Borehole A schematic drawing of a typical borehole ( Figure 1 ) shows that some formations cave considerably, causing enlarged holes. Other formations do not cave, and because of the presence of mudcake, the hole size may actually be reduced to less than bit size. Some formations (not shown here) may swell, causing reduction in hole size.

The primary cause of formation caving is the action of the drilling fluid, bit, and drillpipe. Most drilling muds, composed primarily of water, exert chemical action on shales (hydration of the shales), often causing them to disintegrate and slough into the hole. The amount and rate of this sloughing depend on the nature of the mud and shale. "Heaving" shales swell rather than disintegrate.

If a fresh-water mud is used to drill a salt section, it dissolves salt until the mud becomes salt-saturated. The drilling fluid does not "react" with rock such as limestone, dolomite, and sandstone. If those formations are permeable, however, a mudcake will rapidly form ( Figure 1 ). Mudcake character (density and thickness) varies with the mud used to drill the well, and its thickness is limited by erosion of the circulating drilling fluid.

If/when shallow portions of the hole are drilled with water, loosely cemented sands encountered may cave.

The action of the bit is not very important, but if a thin sand is surrounded by shales that have caved, the bit probably knocks off part of the sand ledge with each round trip.

Action of the drillpipe against the side of the hole causes some enlargement even in sandstones and limestone. Though this enlargement may not be great enough to affect hole volume appreciably, it may cause keyseating and necessitate a fishing job. Formation "wear" by the drillpipe causes the hole to be noncylindrical, in which case a four-arm caliper will display the long and short axes of the hole.

Interpretation and Application of Caliper Logs

Caliper logs are usually recorded on vertical scales from 1 in. = 100 ft to 5 in. - 100 ft. The horizontal scale is selected to show a detailed picture of hole diameter and is usually in the order of 1 in. = 4 in. Because of the difference in scales, it is easy to get the impression from caliper logs that tremendous cavities are created. Keep in mind that when a normal borehole is plotted on the same horizontal and vertical scales, it is evident that it is quite "regular."

The primary uses of the caliper log are:

• to compute hole volume to determine the amount of cement needed to fill up to a certain depth
  

to determine hole diameter accurately for use in interpreting other logs

to locate permeable zones as evidenced by the presence of a filter cake

Other applications of the caliper log include proper location of casing centralizers and packer seats for openhole drillstem tests.

 

Caliper logs are referred to as borehole geometry logs in conjunction with hole deviation and hole azimuth measurements. Figure 1 is an example of such a log using a standard three-track presentation. The borehole orientation is displayed in track 1 while the two independent orthogonal caliper readings are recorded in track 2 with a standard scaling. The caliper data in track 3 show a reduced sensitivity, and are displayed together with the bit size and future casing size. This visual display, enhanced by the shading between the calipers and the bit size, quickly gives a clear impression of the borehole shape. Within the depth track, the total hole volume integration is recorded along the edge of track 1, and the cement volume (the difference between the total hole volume and future casing volume) is presented along the edge of track 2.

Nuclear Magnetic Resonance

Nuclear magnetic resonance logging measures the signal generated by hydrogen nuclei as they rotate (process) about the earth's magnetic field after a field that aligned them is shut off. The tool measures how many hydrogen nuclei stay aligned long enough to be measured and how long it takes to align them.

The signal reflects all the hydrogen nuclei except

• those in water in intimate contact with surfaces. The tool does not see the fluid in a shale and does not see the irreducible water in a sand. Thus, the fluid it does see is called free fluid. In a clean carbonate, even a very fine-grained one, the tool sees all the fluid.
  

those in oil more viscous than about 500 Cp at reservoir temperature. Oil heavier than l4-l8 API is usually not seen except at high temperatures.

Nuclear magnetic resonance can be used for various purposes.

Identification of Permeable Formations The free fluid index (FFI) presented on the log represents. the portion of total pore fluids free to flow. FFI is thus zero except where fluids in pores flow in response to a pressure gradient.

Reflection of Permeability Differences Measurements enable prediction of sandstone permeability. Several empirical relations have been shown to reflect how permeability increases with increasing FFI, and time alignment of hydrogen nuclei (Tl). Each permeability representation depends on parameters determined from comparisons with core-measured permeability.

Recognition of Zones with Heavy Oil Containing Movable Water The signal from very viscous oil decays so rapidly that it is difficult to detect it. Thus, these tools show movable water only and can be used to predict the response to injected steam.

Measurement of Residual Oil Chemicals can be added to the mud in order to cause rapid decay of the signal from mud filtrate. A recording after invasion of such mud filtrate measures accurately the residual oil target for tertiary recovery.

Measurement of Carbonate Porosity Total porosity in clean carbonates independent of whether they are limestone or dolomite.

Simplification of Log Interpretation in Lithologies Where Other Logs are Ambiguous Potentially, the magnetic resonance logging can simplify log interpretation in diatomites, chalks, and other special lithologies.

Borehole Gravimeter (BHGM)

By measuring the acceleration due to gravity, G, at two different stations in a well, the density of the slab of rock between these stations can be calculated. Since the variations in G due to rock density are very small, a very sensitive device is required. The nominal value of G at the surface of the earth is 980 cm/sec² or 980 gal. To be of practical use, a BHGM tool needs to measure microgals. Assuming such measurements can be made in an accurate and repeatable fashion, the average density of a layer of rock between two points in a well can be calculated. Figure 1 illustrates the principle.

The further apart the two measurements are made, the greater the accuracy of the result calculated. For example, if the difference in G between two stations, G, is measured to an accuracy of 7 microgals, then the corresponding accuracy for the calculated density of the layer of rock encompassed between those two stations is 0.028 gm/cc if the spacing is 10 ft, but 0.014 gm/cc if the spacing is 20 ft. This interplay of tool accuracy (sensitivity), station spacing, and detectable density variation is illustrated in Figure 2 .

 

The volume of rock investigated by BHGM surveys is a function of the spacing between stations. Short spacing measurements investigate small rock volumes, longer measurements larger volumes. Figure 3 illustrates this concept. If measurements are made at the top and bottom of a slab of formation 100 ft thick, 90% of the measured G effect will come from within an annulus round the borehole of 500 ft radius. For a 30 ft station difference, the 90% response is from within a radius of 150 ft. A rough rule of thumb is that the BHGM "reads out" to five times the spacing between stations.

 

At all events the tool investigates a very large volume of rock compared to a conventional formation density tool, which reads a few inches at most into the formation.

There are currently two main applications for the BHGM:

• obtaining formation density in completed wells not logged with a modern logging suite
  

  detecting lithology, porosity, and fluid changes in the formation some distance from the borehole
  

An example of the first application is the detection of gas zones in an old well that has only an electric log. At the time these wells were logged and completed, gas production was not an economic proposition. Now that it is, the question remains of how to distinguish high-resistivity zones seen on the old ES log that are gas-bearing from low-porosity tight zones that have the same high resistivity. A BHGM survey can determine formation density over 10 to 20 ft intervals. Gas-bearing zones are likely to show densities closer to 2.0 gm/cc than the 2.5 gm/cc or more shown in tight zones.

An example of the second application is the detection of better porosity or gas some distance from an otherwise dry well. (The BHGM has been particularly successful in the Niagaran Reef plays in Michigan.) If the density distant from the borehole is calculated to be less than the density indicated by the conventional density log, then the well may be fractured over the more attractive gas-bearing or higher porosity zones.

Two tools are commercially available. They are the vibrating string type and the Lacoste-Romberg zero-length spring type. The Lacoste-Romberg device is the one used most frequently, due to its superior accuracy, repeatability, and temperature rating. Figure 4 illustrates the principal components of this device.

 

Figure 5 illustrates both an electric log and BHGM survey in a Gulf Coast Miocene sand/shale series. Of interest are the two high-resistivity kicks seen at 2735-2750 ft and 2765-2780 ft. Either could be hydrocarbon-bearing or tight. The BHGM survey successfully predicted gas production from the upper sand from the calculated density of 2.08 gm/cc in contrast to the 2.38 gm/cc density in the lower sand. The well was perforated in the upper sand for an absolute open-flow potential (AOF) of 1.7 MMscf/D.

 

Figure 6 illustrates a carbonate well in which a featureless zone (6732-6750 ft) on the formation-density-compensated (FDC) log was successfully completed for 1.5 MMscf/D because of the disparity between the BHGM density of 2.58 gm/cc and the FDC density of 2.72 gm/cc.

 

Borehole Televiewer (BHTV)

The BHTV is an acoustic device that scans the surface of the wellbore or casing by rotating an acoustic source (transducer) in the horizontal plane while the tool is moved vertically along the wellbore axis ( Figure 1 ). The amplitude and/or travel time of the acoustic signal reflected from the borehole or casing wall is displayed as a photograph of the section logged. With the help of a flux gate compass, an oriented acoustic picture of the inside of the wellbore is provided as if it were split vertically along the north axis and laid flat.

The acoustic picture is presented in shades of gray and is a record of the amount of acoustic energy reflected from the borehole wall. A smooth surface reflects better than a rough one, a hard surface better than a soft, and a normal surface produces larger reflections than an oblique or slanted surface.

When a smooth, normal borehole wall is scanned, maximum energy is reflected, and the resulting image is a series of bright lines. However, when a feature such as a fracture with its attendant discontinuities is surveyed, a minimum amount of energy is reflected, and the feature appears as a dark line (dark represents reduced reflected energy).

In addition to fractures, features such as vugs, bedding planes, and changes in lithology, as well as perforations, ruptures, or pits in casing can be seen on the televiewer log.

In openhole, the BHTV is used to detect and measure the dip of fractures and bedding planes. Figure 2 is an isometric sketch of a wellbore intersected by a nonvertical fracture or bedding plane and a corresponding BHTV log. To determine dip, one merely finds the minimum of the sinusoid (indicated by the arrow) and reads the direction from the azimuth scale at the bottom of the log. Dip angle is determined by measuring the peak-to-peak amplitude, h, of the sinusoid and combining it with the diameter, d, of the wellbore:

dip angle = tan-1(h/d)

 

 

Figure 3 is a view of a high-angle fracture or bedding plane intersecting the wellbore with north dip. If a high-angle fracture intersects the wellbore with west dip, the BHTV anomaly is a full sine wave with a minimum to the west and a maximum peak occurring to the east, as shown in Figure 4 . In the case of a fracture or bedding plane dipping to the east, the minimum would be to the east and the maximum to the west.

 

Figure 5 is an isometric view of a vertical fracture intersecting the wellbore in an east-west direction and a corresponding BHTV log. The fracture appears as two vertical dark lines 1800 apart.

 

In a cased hole the BHTV may be used to detect perforations ( Figure 6 ), or evaluate damaged casing ( Figure 7 ).

The BHTV can be run in any gas-free liquid such as fresh water, saturated brine, crude oil, or drilling mud. Operating limits for various mud weights and hole sizes may be determined from published charts.

            

Prerequisites for a top-quality log are a centered tool in a round hole. The log shown in Figure 8 meets these requirements. There is a dark area on the left side of the log caused by the tool being slightly off center. Otherwise, the symmetrical intensity from left to right indicates a centered tool in a round hole.