53 - Other Well Logs

Chapter 53 Other Well Logs Richard M. Bateman, vizibg IK. *

Introduction Many well logs generally are not classified as electrical, nuclear, or acoustic logs. The most important of these are discussed in this chapter. Included as miscellaneous well logs are: (1) measurements taken while drilling (MWD), (2) directional surveys, (3) dipmeter logs, (4) caliper logs, and (5) casing inspection logs. All of these are used by the petroleum engineer on occasions. The logs are discussed in the order listed, which was selected for convenience only and is unrelated to the importance of the logs.

MWD plays an increasingly important role in modem drilling practices. It allows an operator almost immediate feedback on both the geometry of the hole being drilled and the characteristics of the formations penetrated. Without MWD this kind of information is available only from conventional sources such as deviation surveys and logs that, a priori, must be run after the drilling has taken place. Of particular benefit, MWD can be applied when drilling directional wells and/or when overpressured formations are of concern.

By having the kind of information MWD can supply more or less in real time, the driller may take appropriate action, such as changing the weight on bit (WOB), increasing the mud weight, or pulling out of the hole for a conventional logging run once the desired formation has been reached.

Many different MWD measuring systems are in com- mercial use today. However, they all have common characteristics: (1) a downhole sensor sub, (2) a power source, (3) a telemetry system, and (4) surface equipment. The downhole sensor subs may contain instrumen- tation capable of measuring parameters such as torque,

*Aulhor of the OrIginal chap!er on this topic. enblled “Miscellaneous Well Logs.” I” the 1962 edilion was A.J. Pearson

WOB, borehole pressure, borehole temperature, tool face angle, natural formation gamma ray activity, formation acoustic travel time, formation resistivity, hole deviation from vertical, and hole azimuth with respect to geographic coordinates. The sensors and the telemetry system can be activated by a surface power source, a downhole turbine, or downhole batteries. In the case of a surface power source it is necessary to make electrical connections between the surface and the downhole sensors, which, in turn, requires either special drillpipe or an electric cable. With a downhole turbine the circulating mud itself drives an electric generator located in the MWD drill collar. This, in turn, leads to an increase in the hydraulic horsepower required of the mud pumps to maintain circulation. In the case of batteries no special cabling or additional mud pumping is required, but the MWD system is limited by the life of the batteries used. Once they are discharged no fmther measurements can be made and the MWD sub must be retrieved and re- dressed with fresh batteries.

The telemetry system most commonly used is that of coded mud pressure pulses. The output from a specific sensor is converted from analog to a digital form and en- coded as a series of pressure pulses, which are detected and decoded at the surface. The pressure pulses may be in the form of overpressure or underpressure anomalies introduced, respectively, by either a relief valve “shorting” the mud circulation or a check valve “choking” it.

However, coded mud pressure pulses are not the only means available for telemetry. Other methods, either in use or under experimentation, include: (1) electromagnetic e-mode (electric current) or h-mode (magnetic field); (2) acoustic telemetry through drillpipe and/or tubing in straight hole, or through the earth by seismic waves; (3) hardwire systems; (4) systems with self-energizing repeaters; and (5) hybrid systems that combine various transmission methods. ’

53-2 PETROLEUM ENGINEERING HANDBOOK

- Mud Flow

- Transmitter

._ Generator

- Turbine

.- Electrical Cable

.- Sensor Package

- Drill Collar

Fig. 53.1-Typical MWD downhole assembly.

The surface equipment consists of a decoder of the mud pulses (or other parameter, depending on the telemetry system in use) together with signal processing hardware and software that together produce the data that the drilling engineer needs. Output may be in the form of a visual display, either on the rig floor or at a remote site, or as a hard copy listing, or log, of the parameters recorded. Data also may be recorded on magnetic tape for future use.

In most systems, the transmission of data to the surface is selective. For example, a measurement of hole deviation and azimuth may require that the drilling process be suspended temporarily and the drillstring held mo- tionless for a short period. Readings then are accumulated in a “buffer’ ’ and only transmitted to the surface when mud circulation recommences.

Fig. 53.1 illustrates an MWD downhole assembly with its mud pulse transmitter, turbine generator, and sensor sub.

Fig. 53.2 shows a data transmission schematic for MWD. Typically, each measurement or “word” is transmitted as part of a data frame, which in turn consists of a synchronization word and 15 measurement words. Some measurements are transmitted more than once in each frame. Current telemetry systems are capable of transmitting a complete frame in a matter of 1 or 2 minutes. The actual sampling rate in terms of measurements per unit of depth is inversely proportional to the rate of penetration (unit of depth/ unit of time). *

Fig. 53.3 shows a complete MWD logging system schematic and integrates surface and downhole sensors, the telemetry system, the surface hardware and software (for computer processing of the data), and the final prod- uct in the form of a log. 3

Fig. 53.4 shows an MWD log on which is displayed gamma-ray, short normal resistivity, annular temperature, downhole WOB, surface WOB, and computed directional data (drift and azimuth).

-

M ” L r , P L E x E R

-

Fig. 53.2-MWD data transmission schematic.

OTHER WELL LOGS 53-3

Fig. 53.3-MWD logging system schematic

Fig. 53.5 shows a comparison between an MWD- generated computed directional survey and a multishot run in the same well. Table 53.1 illustrates a directional survey listing corresponding to the plan view shown in Fig. 53.5.

Directional Surveys Directional surveys4T5 are used to determine the location of the hole path with respect to the surface location. This information is used (1) to prove legally that the bottomhole location is under the correct surface property, (2) to ascertain the bottomhole location in purposely deviated wells, (3) to determine the radius of curvature of the hole as it affects the ability to run casing or tools, and (4) to differentiate between measured depth and true vertical depth (TVD) when using formation elevations for structural mapping.

Available Tools The two basic types of directional surveys are continuous surveys and station surveys. The station surveys can be either single shot or multishot. Single or multi refers to the number of stations recorded. Single shot surveys normally are recorded during the drilling operation and are

recorded at given depth or time intervals. These single- shot records are accumulated and used to plot the hole path. Multishot surveys are the result of several shots run at given depth intervals after the hole has been drilled. Continuous surveys are run after a portion of the hole has been drilled. These are recorded continuously over the selected interval. Although continuous, multishot, and single-shot instruments are all different, there is another classification of instruments that must be considered when choosing a survey.

Surveys run inside metal casing cannot use the magnetic compass for hole direction. Gyroscopes normally are used whenever a survey is needed inside casing. These gyroscopes must be aligned on the surface before proceeding with the survey. They also should have their alignment verified as part of the after-survey checks.

The openhole directional surveys normally use magnetic compass orientation to fix the hole direction. This requires the input of the deviation between magnetic and true north. All devices use a pendulum system for determining the angle of hole deviation.

All continuous dipmeter surveys measure data that can yield a directional survey. This directional survey is available either as part of the dipmeter or as a separate

PETROLEUM ENGINEERING HANDBOOK

Fig. 53.4-An MWD rotary drilling log.

survey over portions of the hole where formation dips are not desired. At present, this instrument does not work in a cased hole, so the survey must be tied in to known coordinates at the bottom of the casing.

Any device that uses a magnetic compass to fix direction will be affected by metal in or near the borehole. This effect must be considered when a survey is run in an open hole that has been whipstocked past abandoned drillpipe or may be near a cased wellbore.

Fig. 53.6 illustrates a gyroscopic survey tool incor- porating an accelerometer.

Legal Requirements Each state has a separate definition of what constitutes a “legal” directional survey. These definitions may include specifications such as (I) length of downhole sensor, (2) whether or not such assembly is centered, (3)

method of calculating station-type surveys, (4) profes- sional qualifications of person supervising or certifying the results, and (5) documentation, presentation, and distribution of results. These criteria must be considered when choosing a service company and a type of survey.

Computation of Results Directional surveys are available in any area where directional drilling is done or where dtpmeters are available. The field log may be a series of station readings or a continuous curve showing hole direction and deviation. The computed results will include a well plat that shows the vertical projection of the wellbore. Additional plots may show wellbore projections on a vertical plane passing through the surface location. A tabulated listing will show the wellbore coordinates and deviation angle,


NORT” -100 100 300 500 700 900 I100 1300 IS00 1700

1500

1900

1100

900

e

:3

6 100

‘ij

5

8

j so0

300

100

-100

-300

T I I j I

I ,

SOjIO LINE I /

1 opo ORTR rFpO?l YSl? FTI bR$HEO LXNE I

1

Fig. 53.5-Comparison of MWD directional with multishot directional

Methods of Calculation. There are many methods of calculating directional surveys. 6 Most companies use one of the following five basic methods.

1. Tangential Method. This method uses the inclination and azimuth angles at the bottom of each course length (distance between readings or stations). This is usually the most common and least accurate method. The error introduced increases with the inclination angle and the course length. This method is not recommended.

2. Balanced Tangential Method. This method uses the inclination and azimuth angles at both the top and bottom of each course length to tangentially balance the two sets of measurements over the course length. This method is more accurate than the tangential method but is still sensitive to the course length.

3. Angle Averaging Method. This method uses a simple mathematical average of the inclination and azimuth angles at the top and bottom of the course length to compute the survey using the tangential method. This is more accurate than the tangential method but still simple enough for hand calculations in the field. Course length should be kept as short as feasible.

4. Radius of Curvature Method. This method uses the inclination and azimuth angles at the top and bottom of the course length to generate a space curve representing the curve path. This space curve passes through the measured angles at the top and the bottom of the course length. This method usually is considered the most accurate but is still sensitive to course length.


TABLE 53.1~MWD DATA LISTING FOR DIRECTIONAL SURVEY

Readings Analysis (confidence level=99.0%)

Survey Number Deoth

90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134

5425.0 5457.5 5,478.0 5.509.0 5.540.0 5571.0 5.589.0 5,605.O 5,631.0 5.695.0 5,735.0 5,756.0 5,821.0 5,852.0 5,949.0 6932.7 6,090.O 6,117.0 6,150.2 6,216.2 6,241.8 6,272.0 6,302.O 6,337.0 6,402.O 6,455.8 6,553.3 6,600.3 6,678.3 6,708.3 6.740.3 8,771.3 6838.3 6,893.g 6,926.7 6,989.4 7,020.O 7,054.o 73084.4 7,114.2 7,153.g 7,184.8 7,240.l 73272.7 79285.8 7,316.g 7,346.0

Course Length m 30.0 32.5 20.5 31.0 31.0 31.0 18.0 16.0 26.0 64.0 40.0 21.0 65.0 31.0 97.0 83.7 57.3 27.0 33.2 66.0 25.6 30.2 30.0 35.0 65.0 53.8 97.5 47.0 78.0 30.0 32.0 31.0 67.0 55.6 32.8 62.7 30.6 34.0 30.4 29.8 39.7 30.9 55.3 32.6 13.1 31.1 29.1

Angle (degrees)

37.80 37.67 36.53 35.73 35.72 35.08 35.08 34.35 33.90 32.17 31.28 30.97 28.87 27.88 26.52 24.65 23.63 22.80 22.45 21.27 20.93 19.68 19.78 19.30 18.28 17.17 15.87 14.92 14.62 14.78 14.32 13.85 1318 12.63 12.87 12.55 12.58 12.60 12.40 11.50 10.90 10.00 7.90 7.40 7.00 7.40 5.90

Azimuth Vertical Angle Dogleg Depth

(degrees) 1100 ft (fi) ~- 41.80 43.50 43.50 44.00 41.80 42.40 42.40 42.80 43.30 46.30 47.40 46.60 45.10 47.20 45.40 46.10 48.90 47.00 46.10 46.80 46.00 48.20 44.80 46.10 41.80 49.50 50.10 59.50 47.20 53.50 5590 59.50 57.90 57.60 63.30 67.80 66.30 65.70 67.10 66.90 66.90 68.60 68.90 63.00 66.90 58.70 58.40

2.34 5,180.4 696 559 3.22 5.206.1 710 573 5.52 5,222.5 719 581 2.75 5,247.5 732 594 4.14 5,272.7 746 606 2.33 5.298.0 759 618 0.00 5,312.7 767 625 4.79 5,325.a 773 631 2.03 5,347.4 784 641 3.72 5,401.o 809 666 2.64 5,435.0 823 681 2.47 5,453.0 831 689 3.43 5,509.3 853 712 4.52 5,536.6 863 723 1.64 5,622.g 894 755 2.26 5,698.4 919 781 2.67 5,750.7 935 798 4.15 5,775.5 942 806 1.48 5,806.i 951 815 1.83 5,867.4 968 833 1.71 5,891.2 974 840 4.85 5,919.6 981 840 3.84 5,947.8 988 855 1.85 5,980.a 997 863 2.64 6,042.3 1,012 878 4.82 6,093.6 1,023 889 1.34 6,187.0 1,041 911 5.67 6,232.3 1,048 921 4.03 6,307.8 1,060 937 5.35 6,336.8 1,065 942 2.38 6,367.8 1,069 949 3.20 6,397.8 1,073 955 1.14 6,463.0 1.082 969 0.99 6,517.2 1,088 979 3.90 6,549.2 1,092 986 1.66 6,610.3 1,097 998 1.06 6,640.2 1,100 1,004 0.35 6,673.4 1,103 1,011 1.18 6,703.l 1,106 1,017 3.02 6,732.2 1,108 1,023 1.51 69771.1 1,111 1,030 3.08 6,801.5 1,113 1,035 3.80 6,856.2 1,116 1,043 2.85 6,888.5 1,118 1,047 4.81 6,901.5 1,119 1,048 3.54 6,932.3 1,121 1,052 5.15 6,961.Z 1,122 1,055

North East Vertical Maior Uncertainty Range

Axis

1.3 10.0 9.5 343 1.3 10.0 9.5 344 1.3 10.0 9.6 344 1.3 10.0 9.6 345 1.3 10.0 9.6 346 1.3 10.1 9.6 347 1.3 10.1 9.6 347 1.3 10.1 9.6 347 1.3 10.1 9.6 348 1.4 10.1 9.6 351 1.4 10.1 9.7 352 1.4 10.1 9.7 353 1.4 10.1 9.7 356 1.4 10.1 9.7 357 1.4 10.2 9.8 3 1.5 10.2 9.8 6 1.5 10.2 9.8 8 1.5 10.2 9.8 8 1.5 10.2 9.8 9 1.5 10.2 9.8 10 1.5 10.2 9.8 10 1.5 10.3 9.8 11 1.5 10.3 9.8 11 1.5 10.3 9.8 11 1.5 10.3 9.8 12 1.5 10.3 9.8 13 1.5 10.3 9.8 14 1.5 10.3 9.8 14 1.5 10.3 9.8 15 1.5 10.3 9.8 15 1.5 10.3 9.9 15 1.5 10.3 9.9 15 1.5 10.4 9.9 16 1.5 10.4 9.9 16 1.5 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16 1.6 10.4 9.9 16

5. Mercury Methods. This method is used by the U.S. Government at the Mercury Test Site in Nevada. This is a combination of the tangential and balanced tangential methods. The portion of the course length defined by the length of the surveying instrument is treated by the tangential method. The remainder of the course length is treated by the balanced tangential method.

All these methods are critical to the course length or separation between stations. As the course length increases, their inaccuracies and deviations from each other increase. As the course length decreases, they all become more accurate. On very short course lengths (10 ft or less) there is very little to choose between the methods. For this reason, directionals computed from

continuously measuring devices, such as dipmeter tools, may be more accurate than station reading devices. Dipmeter devices normally compute every 1 or 2 ft although data listings may be accumulated and listed only every 50 ft.

Presentations. Directional data are normally presented both in well sketches and tabulated data. Well sketches include two elements.

1. Plunar View. This is a vertical projection of the wellbore path on a horizontal plane. Such a projection shows the separation between the wellbore and the surface location. The wellbore path is marked with measured depths.


2. Vertical Sections. These are of two types. The first is a projection of the wellbore on a vertical plane through the surface location and aligned at various azimuths. The second is plot of depth against closure where closure is the horizontal distance of the wellbore from the surface location. The tabulated data listing will show the measured depth, vertical depth, hole azimuth, deviation angle, x and y distances, and closure distance.

Field Examples. Fig. 53.7 shows a number of presentations of deviation survey computations including: (.A) plan view,(R) vertical section, and (C)depth vs. closure. The deviation survey listing is also shown in Table 53.2.

Dipmeter Logging Introduction The dipmeter tools arc run to determine the direction and angle of formation dip from the survey of one borehole. This information is of obvious importance in the study of structural and stratigraphic problems. 7

As illustrated in Fig. 53.8, the angle of formation dip is the angle between a horizontal plane and the bedding plane of the formation. The strike of a formation is the direction of the horizontal line formed by the intersection of these two planes. Although strike is a common geologic term (particularly in surface geology), it is more convenient to use “dip azimuth” in discussing the dipmeter. The direction of dip is perpendicular to the strike. In the remainder of this section dip azimuth will be used instead of strike.

Dipmeter tools are in a class by themselves. The technique, the purpose, and the intemretation of dipmeter logs arc entirely different from those of other logging tools. The dipmeter’s purpose is to measure the dips of formations. To do this, the tool must simultaneously and continuously do two separate jobs: first, it must orient itself in space, normally with respect to magnetic north and vertical, and second, it must react to formation bedding planes.

All present dipmeter tools go about this job in the same way. An inclinometer section supplies continuous measurements of deviation, both the amount and the direction, and of the orientations of the tool’s electrode array, either with respect to the borehole direction or magnetic north (a few specialized tools for far north operations use gyroscopic orientation, nominally with true north). At the same time, an electrode array is main- tained in contact with the borehole wall by pressured linkages. The electrodes respond to resistivity variations, while the expanding linkages activate a caliper recording.

These pads, normally numbering four, are identical, and so mounted as to remain in a plane normal to the tool axis. When an anomaly is detected by at least three pads, these deflections plus the caliper reading identify three points in what is assumed to be a plane, the plane of deposition of the formation. This identification is then referred to vertical and true north, giving the true dip of the formation.

Recording correct data with a dipmeter tool is a straightforward, more or less mechanical process, though the tools used to do it are some of the most sophisticated in the industry. Interpreting the data draws heavily on computer technology.

TO ELECTRONIC5

SECTION

TOP 4

SLIP RINGS

KATE tiYH0

SPIN AXIS-

rVRCjIJl. MOTVK.

c

‘ACCELEROMETER

INPUT AXIS

\ INPUT AXIS

WY~IMBAL

-RESOLVER

Fig. .53.6-Eastman Whipstock Seeker-l.

PETROLEUM ENGINEERING HANDBOOK

Tattttt

aa

Fig. 53.7A-Deviation survey plan view

T c I

L

Fig. 53.78-Deviation survey vertical section.

Fig. 53.7C- Deviation survey depth vs. closure.

ools Available. All major service companies use four- rm dipmeter tools. Fig. 53.9 shows a typical dipmeter ool’s mechanical section with the four pads, the elec- rodes, and the caliper assembly visible. Most of these ools will operate to 20,000 psi and 350°F in holes be- ween 6 and 16 in. in diameter. Different varieties of ools handle low- and high-deviation holes by using dif-

ferent methods of measuring hole deviation and hole zimuth angles. Fig. 53.10 illustrates a monitor log and computer-answer log.

Calibration. The dipmeter is essentially a physical tool, and its calibration is physical. The inclinometer section is adjusted to read correctly in a special test jig. Special care is given to ensure that the deviation sensor registers zero with the tool held vertical. The operation of the inclinometer is checked before and after each log run, first by allowing the tool to hang vertical in the derrick, then by rotating the tool manually through at least one full revolution.

The calipers are checked as usual, by calibration jigs of known diameter. Four-arm dipmeters record a separate caliper with each opposing pair of pads, which can thus flex independently of each other while remaining in the same plane. Finally, the sensitivity of the electrodes is checked by shorting them out in sequence; this also verities the correct wiring of the electrode array.

Oil-Base Muds. Dipmeters run in oil-base muds present a special problem. Because the oil-base mud will not connect the resistivity electrodes to the formation electrically it is necessary to use special knife-edge blade


Fig. 53.8~Illustration of dip, strike, and dip azimuth

electrodes. These blades mechanically cut into the formation and make contact with the water in the formation. This method does not give the quality of data that is obtained with the conventional system in water-base mud. The reason for this is the considerable amount of noise introduced into the resistivity recording caused by the knife blade sliding along the borehole wall. The better the contact made between the knife edge and the formation, the better the quality of the resistivity measurements. Two important things can be done to im- prove this contact.

1. Make sure that the knife-edge blade is sharp Demanding new blades is the best way to ensure sharp edges. New blades are also less likely to have electrical insulation problems.

2. Have the logging company dress and adjust their dipmeter tool to apply the maximum arm pressure. This will force the knife edge electrodes into the formation mechanically. This adjustment may be made with different spring mechanisms or by applying greater pad pressure through a hydraulic linkage. Either way this is very important to obtain good resistivity data.

Because the oil-base mud dipmeter is a low-usage tool, the service company should be given maximum notice so they can prepare for the job. All special instructions and stipulations should be given at the same time.

When recording the log, it should be remembered that the final data can be expected to be only 10 to 20% as good as an ordinary dipmeter. Therefore, it is advisable to consider multiple repeats over critical zones. The data usually will be valid only for general structural use so particular attention should be paid to shale zones. All resistivity curves should have good character, although their similarity will not extend down to small details. A slow or dead curve usually indicates a faulty knife-edge electrode. The orientation curves are unchanged from an ordinary dipmeter so the same comments apply to both.

The Computed Dipmeter Log The computation of dipmeter surveys8 requires sophisticated software and a substantial computer. The task requires that the anomalies recorded on the resistivity traces at bed boundaries be correlated and the displacement of each with respect to the others along the borehole be determined. Once this step has been taken then any two pairs of displacements are sufficient to define a plane. Where more than three resistivity curves are recorded, as with most modem dipmeter tools (4-, 6-, and 8-pad tools are in use), then multiple pairs of

TABLE 53.2-DEVIATION SURVEY LISTING’

Measured Vertical Depth Depth (W (W 5000 5000

10000 10000 15000 15000 200 00 20000 25000 25000 300 00 30000 35000 350.00 40000 40000 45000 450.00 500 00 500.00 550 00 550.00 600 00 599 99 65000 649 99 70000 699 99 75000 749 99 800 00 799 99 85000 a49 98 900.00 899 98 950 00 949 98

1,000 00 993 97 1.050 00 1.049 37 1.10000 1,099 96 1.15000 1.14996 1.200 00 I.19995 1,250 00 1,249 94 1.300 00 1,299 94 1.35000 1.349 93 1.40000 1.399 92 1.45000 1.449 91 1.50000 1.499 90 1.550 00 1.549 a9 1.600 00 1.599 aa 1.650.00 1.649 87 1,700.00 1.699 86 1.75000 1,749 a4 1,800 00 1.799 83 1.850 00 1.849 82 1,900 00 1,899 a0 1.950 00 1,949 79 2.000 00 1.999 77 2.050 00 2,049 75 2.100 00 2.099 73 2.150 00 2,149 71 2.200 00 2.199 69 2,250 00 2.249 67 2,300 00 2,299 65 2.350 00 2,349 62 2,400 00 2,399 60 2.450 00 2,449 57 2.500 00 2.499 55 2.550 00 2.549 52 2,600 00 2.599 49 2.650 00 2.649 46 2.700 00 2.699 43 2.750 00 2.749 40 2.800 00 2.793 37 2.850 00 2.849 33 2.900 00 2.899 29 2.950 00 2,949 26 3.000.00 2.999 22 3 050 00 3.049 18

HOk Dlrectlon

95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 35 95 95 95 95 95 95 95 95 95 95 95 95 95 95 55 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95 95

Deuatlon Angle

(degrees)

004 0 08 011 015 0 19 023 026 0 30 034 038 041 045 0 49 053 057 0 60 0 64 068 0 72 0 75 0 79 083 087 0 90 0 94 0 98 102 106 109 1 13 1 17 121 124 128 132 136 140 143 147 1 51 155 I 58 162 166 170 1 73 1 77 181 185 i a9 192 1 96 2 00 2 04 207 2 11 215 2 19 2 22 2 26 2 30

'Referenced from RKB=l5 ft. MSL=Otl Magnetic decl!nation 0.00 degrees went of north

North East DUfi Dllfl

- 0 00 0 02 -001 0 07 -001 0 15 -002 0 26 -004 041 -005 0 59 -007 081 - 0 09 105 -012 1 33 -014 1 64 -017 199 -021 2 36 -024 2 77 -0 28 322 -0 32 365 -037 420 -041 4 74 -0 47 5 32 -052 5 92 -057 6 56 -063 7 23 -0 69 7 94 -076 868 -083 345 -090 1025 -097 1109 -105 11 96 -1 12 12 86 -1 21 13 79 -1 29 14 76 i 38 15 76

-147 16 79 -156 1786 -166 1896 -1 76 2009 -1 86 2125 -196 2245 -207 2368 -218 2494 -230 2623 -241 2756 -2 53 28 92 -265 3032 -2 78 31 74 -290 3320 -304 3463 -317 3622 -330 3777 -344 3936 -359 4099 -373 4264 -388 4433 -403 4605 -418 4780 -434 4959 -450 5141 -466 5326 -482 5514 -499 5706 -5 16 5901 -534 6099

ClOSUF2 002 007 0 15 0 26 041 0 59 081 1 06 134 165 199 2 37 2 78 323 371 422 4 76 5 34 595 659 726 797 8 71 948

1029 11 13 1200 1291 1384 1482 1582 1686 1793 1903 20 16 21 33 2253 2377 2503 2633 2767 2903 3043 31 86 3333 34.32 3635 3792 39 51 41 14 4280 4450 4623 4799 4978 51 60 5346 5536 5728 5924 61 23


Low Angle

RELATIVE AZIMUTH *xxx

BEAAINGx*X~ OF REFERENCE

y- DHD’ 4+--L-

HIGH SIDE OF TOOL

fN

- NO 1 PAD REFERENCE ELECTRODE

High Angle RELATIVE xxx

HIGH SIDE.

NO 1 PAD

\ NO 1 PAD

xx Az,m”th of hole dev,al,on-Clockwise angle fro”. ms3gnetlC North to DHD

XLX Rmtive bearmg-Clockwse angle from DHO to Reference Electrode

xxxx Arlmuth 01 Reference Electrode-Clockwse angle from magnet~c North to Reference Electrode

Fig. 53.9-Four-arm dipmeter tool.

displacements may be chosen and multiple apparent bedding planes defined. The correct choice of the most prob- able bedding plane is determined by the interpretation logic in the dipmeter program. The correlation of one resistivity curve to another is a more mechanical task and is controlled by the interpreter’s choice of three parameters-the correlation length, the search angle, and the step length-as illustrated in Fig. 53.11. A short interval of one curve is correlated to a second curve at discrete steps throughout a depth range defined by the search angle. At each step a correlation function is evaluated.

When the value of the correlation function is determined at each step, then a correlogram can be built and a search made for a maximum value. This maximum indicates the displacement of the curve sector defined on the first curve by the correlation interval from a similar section on the second curve. Successive correlations are continued in the same correlation interval with other curves and then in the next correlation interval and so forth.

Once a plane at any point in the well has been defined its orientation relative to vertical and geographic north also must be computed. This requires that the position of the tool in the hole and the deviation and azimuth of the hole itself be known. These data are supplied from the orientation section of the tool.

The dipmeter log, as recorded, is not evaluated easily for quality, so an appraisal of the computed log should be included in dipmeter quality control. A computed dipmeter log may be available on location, if a computer logging unit is available, but it is normal to wait for days or even weeks for the results if processing is done at a central computer office.

Working with the computed log, look for two distinct defects: undetected problems with the recorded data and problems with the computation. A computed dipmeter should model real-life geology; if it seems not to do that, an investigation is in order. If the problem is in the computation, it normally can be solved by repeating the computation job. Even if the problem is with log measurements, the logging company’s computer experts often can solve it by special handling.

Application of Dipmeter and Directional Data Dipmeter Patterns. Once a dipmeter log has been nm and computed then the results have to be interpreted in the light of known geological and geophysical facts. In general dipmeter results are used to find gross structural features, fine stratigraphic features, and true vertical and true stratigraphic thicknesses.

The most common method of representing computed dipmeter results is by an “arrow” or “tadpole” plot. A series of special characters is plotted as a function of depth with their origin indicating the dip magnitude and a short line indicating the dip azimuth, as illustrated in Fig. 53.12A. For the purpose of reference the uphole direction on the plot is considered north and the clockwise direction the short line points from its base is the dip azimuth angle. When viewed together as patterns, these dip vectors or L ‘tadpoles” can be interpreted in terms of gross geological structure or sedimentary detail as illustrated in Fig. 53.12B.

OTHER WELL LOGS 53-l 1

L

RESISTIVITY ARROW INCREASES - ,P PLOT iu”

Fig. 53.10-Dipmeter monitor log and computed dipmeter log

I 1 I I I SEARCH ANGLE I

CORRELATION NEXT CORRELATION INTERVAL INTERVAL

Fig. 53.1 l-Dipmeter computation terms “correlation interval,” “step,” and “search,”


YETHOD OF PLOTTfNG a

0’ 10’ 20’ + DIP MAGNlTUDE

IDIP S I

L I J EXAMPLE 10” N45”E

DIRECTION

b

/‘4 I ie i BLUE PAT,ERN

Fig. 53.12-Dipmeter interpretation rules showing (a) method of plotting dips and (b) patterns of dips.

Fig. 53.13 shows three common structures: a folded structure (anticline), an unconformity, and a normal fault. Fig. 53.14 shows three common sedimentary features: a channel cut and fill, a buried bar with shale drape, and current bedding.

Other complex patterns may develop, such as those related to: (1) missing and repeat sections (Fig. 53.15A), (2) stratigraphy of continental deposits (Fig. 53. lSB), (3) stratigraphy of continental shelf deltas (Fig. 53. IX), (4) stratigraphy of continental shelf tide/wave-dominated deposits (Figs. 53.15D and E), and (5) continental slope and abyssal environments (Fig. 53.1 SF). Other forms of representing dip data are also used to good effect, such as polar and stereographic plots and azimuth frequency diagrams.

One of the main uses for dip data as far as the reservoir engineer is concerned is in computation of reservoir volumes, which require true vertical thickness measurements (TVT). For the geologist a related measure. the true stratigraphic thickness (TST) is of immediate concern. 9-‘3

In the simple case where the wells are vertical and the bedding is horizontal, correlations can be made directly between logs of neighboring wells. Reservoir volume is calculated by multiplying reservoir thickness (directly derived from the logs) by reservoir area (delimited by other means).

However, this simple case is exceptional because (1) most reservoirs exist as the result of some structural event or accident, implying some formation dip at least at the reservoir periphery, and (2) most wells deviate to some extent from vertical, intentionally or not. As long

Folded Structure SP fCross Section N . S /Dip Pan*m

Unconformity SP 1 Cross SIctlcn SE NW

Fig. 53.13-Common geologic structures and corresponding dipmeter patterns.

OTHER WELL LOGS

Buried Bar with Shale Drape u c.ma.sadm uw-SE 1040 ?ml?mm

4 4 4 4

. .

--------- ,

, \

.-L---d 4 4

Fig. 53.15A-Missing and repeat sections.

Current Bedding Y @#-msrQn NE-SW I- I

Fig. 53.158- Stratigraphic interpretation, continental environ- ment.

Fig. 5X14- Dipmeter patterns in sedimentary features


Fig. 53.15(3- Stratigraphic interpretation, continental shelf, delta dominated.

r- z I I ,= D,,l “EFLEC, s,““cr”““‘ D,,

Fig. 53.15E- Stratigraphic interpretation, continental shelf, tidal wave dominated.

Fig. 53.15D- Stratigraphic interpretation, continental shelf, tidal wave dominated.

Fig. 53,15F- Continental slope and abyssal environments.


as dips and deviations do not exceed a few degrees, the simple vertical-horizontal case is approximated closely enough not to need corrections. But when deviations and dips exceed about 10 degrees, corrections are needed because apparent formation thicknesses measured on logs are greater than true stratigraphic thicknesses by different amounts in different wells. This adds to the dif- ficulty of well-to-well log correlation. Also, if wells are deviated from vertical, and if formations have substantial dip, apparent thicknesses differ from the vertical thicknesses needed for reservoir volume calculation, and must be corrected.

To achieve these corrections in a convenient manner, modem data processing affords three different computed log products: the true vertical depth (TVD), TST, and TVT plots. Proper interpretation of these plots requires considerable caution and may be quite difficult.

Common Principles of TVD, TST, and TVT Plots. Figs. 53.16 through 53.18 illustrate the principles of thickness transformations. Formation parameters recorded by logging tools are reproduced without alteration, but their depths are altered to suit respective purposes. Depths should be thought of as summations of overlying formation thicknesses.

Two methods exist for computation of altered depths: (1) common surj&e point, which assumes a hole drilled from the same surface point or formation top with a different course, and (2) common subsur&ace point, which assumes a hole drilled either vertically, or normal to the bed dip, from some point in the actual well course, such as a formation top, or a point of formation dip change. Depths may be reset arbitrarily at the common point. In this approach it is set to zero, thus representing only thickness as counted down from the common point.

Z’VD Plot. This plot ignores formation dip and corrects for well deviation only. Thus, it represents formations as they would look in a vertically drilled well, provided the formations had zero dip. It is useful in areas of directional drilling where dip is low, for well-to-well correlations, and for reservoir volume calculations. It usually is run only in the common surface point mode.

TST Plot. This plot accounts for formation dip, and requires knowledge of true well course, whether vertical or not. It displays formations as though the well had been drilled perpendicular to them. If a change of dip occurs, an equal and opposite change of deviation is assumed.

If only one dip is present, the plot represents the logs that would have been obtained if the well had been drilled at the same location perpendicular to that dip. If more than one dip is present, the interpretation becomes more complicated. At each dip change, some stratigraphic column must either disappear, or thin, or thicken, or even repeat itself.

17/T Plot. This plot is closely related to the TST, and as such accounts for both well deviation and formation dip. It shows formation thickness as though the well had been drilled vertically through the dipping beds. Evidently, a TVT in a vertical hole would be identical to the original log. The TVT is meant to be used for reservoir volume calculations from deviated hole logs.

Reductions in Special Cases. If the well is vertical and the formations are horizontal, all three transformed logs would be identical to the original log, and the processing

Frue Vertical Depths

Fig. 53.16-Principle of true vertical depth (TVD).

Fig. 53.17-Principle of true stratigraphic thickness (TST).

Fig. 53.16-Principle of true vertical thickness (TVT).


would be a waste of computer time. If the well is deviated and the formations arc horizontal, the TST and the TVT are identical to the TVD, and running the latter is sufficient. If the well is vertical and the formations dip, the TVD and TVT plots would be wasted computer time, but the TST may be useful in well-to-well correlations. If the well is drilled perpendicular to the formation dip (as it often tends to be in hard rocks in particular) the TST would be a waste of computer time, but the TVT is needed for reservoir calculations, and the TVD may be of use if deviation is pronounced.

Algorithms. The algorithms used for computing the TVD, TST, and TVT have been covered well in the literature. I4 Any implementation of these algorithms for computer applications should be approached with caution. Many programming languages differ in their treat- ment of trigonometric functions for angles exceeding 90”. Another area requiring care is in the matter of precision. When depth data are processed, a repetitive ac- cumulation of depth increments is made. As many as IO4 or more additions must be made in a normal well. Thus the precision of each increment must be at least one part in IO6 or better. Depending on the computer used (16 bit, 32 bit, etc.) the programming of these algorithms should demand appropriate precision.

By way of summary, all three plots perform valuable functions, but all three may be misleading if not used with the proper caution, in particular with respect to absolute depths.

1, The TVD is incorrect in both formation thicknesses and in absolute depths if formations have appreciable dip.

2. The TST is always correct in formation thicknesses. It should be run in the common subsurface point mode. If changes of dips are present, it should reset the subsurface point at each change of dip and make independent plots through each dip zone. This resetting may be made automatically if the program allows it, and manually otherwise.

3, The TVT may produce apparent thicknesses greater than measured thicknesses. Such thicknesses may be fit- titious when beds are truncated in their vertical extension by unconformities or faults. It should be run in independent sections for each change of dip, in the common subsurface point mode, as for the TST.

Fig. 53.19-A typical borehole.

Caliper Logs Introduction 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 ear- ly 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, which contact the wall of the borehole. The instrument is lowered to the total depth (TD), 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, which contact the wall of the borehole. These springs are con- nected 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 elec- tromotive 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. Either of the preceding instruments may be adjusted so that they will record borehole area rather than hole diameter. If the caliper log is used to determine hole volume, area should be recorded 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 is the microcaliper, which 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 Borehole Configuration A schematic of a typical borehole is shown in Fig. 53.19. As illustrated in this figure, some formations cave considerably, causing enlarged holes. Other formations do not cave, and because of the presence of mudcake, the hole size actually may be reduced to less than bit size. Although not illustrated in Fig. 53.19. some fotma- tions may swell, causing reduction in hole size.

The primary cause of formation caving is the action of the drilling fluid. Action of the bit and the drillpipe also have an effect. Most drilling muds are composed primarily of water. The chemical action of this water on shales (hydration of the shales) causes many shales to disintegrate and slough into the hole. The amount and rate of this sloughing depend on the nature of the mud and shale. Other shales (heaving shales) swell rather than disintegrate.

If a freshwater mud is used to drill a salt section, it will dissolve salt until the mud becomes salt-saturated. The drilling fluid does not react with formations such as


limestone, dolomite, and sandstone. However, if those formations are permeable, a mudcake will be formed, as illustrated in Fig. 53.19. This mudcake forms rapidly. The character (density and thickness) of the mudcake varies with the mud used to drill the well. Of course, thickness of the mudcake is limited by erosion of the drilling fluid while circulating.

In some areas the shallow portion of the hole is drilled with water. If loosely cemented sands are encountered, they may cave under this condition.

The action of the bit is probably not too 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. Usually this enlargement is not great enough to affect hole volume appreciably, but it may cause the drillpipe to become differentially pressure stuck, necessitating a fishing job. Formation wear by the drillpipe will cause 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 usually are recorded on vertical scales from 1 in.= 100 ft to 5 in.= 100 ft. The horizontal scale is selected to show a detail picture of hole diameter and is usually on 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. When plotted on the same horizontal and vertical scales, it is evident that the normal borehole is quite regular. This should be remembered when using the caliper log.

The primary uses of the caliper log are: (1) to compute hole volume to determine the amount of cement needed to fill up to a certain depth, (2) to determine hole diameter accurately for use in interpreting other logs, and (3) 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 also available in conjunction with hole deviation and hole azimuth measurements, in which case the log is referred to as a borehole geometry log.

Fig. 53.20 is an example of a borehole geometry 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 are also available in Track 3 but with a reduced sensitivity. 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 the future casing volume) is presented along the edge of Track 2.

i

Fig. 53.20- Borehole geometry log.

Casing Inspection Logs Introduction Inspection of the mechanical state of the completion string is an important aspect of production logging. Many production (or injection) problems can be traced back to mechanical damage to, or corrosion of, the completion string. A number of casing inspection methods are available including: (1) multifingered caliper logs, (2) electrical potential logs, (3) electromagnetic inspection devices, and (4) borehole televiewers or borehole TV. Of these the majority measure the extent to which corrosion has taken place. Only the electrical potential log may indicate where corrosion is currently occurring. With the exception of the caliper logs, all the devices require that the tubing be pulled before running the survey, since most are designed to inspect casing rather than tubing, and all are large-diameter tools.

Caliper Logs for Tubing and Casing Inspection Various arrangements of caliper mechanisms ate available to gauge the internal shape of a casing or tubing string. Fig. 53.21 illustrates three such tools. Table 53.3 lists the various sizes available, their respective number of feelers, and the appropriate casing size.

Tubing Profile Calipers. Tubing profile calipers will determine the extent of wear and corrosion, and will detect holes in the tubing string-all in a single run into the well. The large number of feelers on each size of caliper ensures detection of even very small irregularities in the tubing wall.

In pumping wells, the tubing caliper log may be run by one person and there is no need for a pulling unit crew to be present. A “pull sheet” showing the maximum percentage of wall loss of every joint of tubing in the well may be prepared. Before the well is pulled, a program of rearranging the tubing string can be provided. Moving partially worn joints nearer the surface and discarding thin-wall joints substantially prolongs the effective life of tubing strings and reduces pulling costs in pumping wells. In flowing or gas lift wells, the tubing profile caliper provides an economical method to check

53-I 8 PETROLEUM ENGINEERING HANDBOOK

Tubing Profile

Caliper Casing Pmfrle

Caliper

Fig. 53.21-Casing and tubing profile caliper tools

TABLE 53.3-TUBING AND CASING PROFILE CALIPERS

Sizes of Tubing Profile Calipers

Tool Diameter Number of OD

(in.) Feelers (in.)

1% 20 2 1’/2 20 wl6 1% 26 2% 2% 6 32 27/s 2’%6 44 3% 3’h 44 4

Sizes of Casing Profile Calipers 3% 40 4% t0 6 5% 64 6% to 7510 7v? 64 8% lo 9 7% 64 9% 8’/4 64 10% 9% 64 11%

1 IS/l6 64 133/e 13% 64 16 17% 64 20

periodically for corrosion damage, to monitor the effec- tiveness of a corrosion inhibitor program, or to detect and remove damaged tubing joints when working over a well.

Split Detector. This is an accessory tool that may be run in combination with the tubing profile caliper. This tool, functioning much like a magnetic collar locator, is designed to detect and log vertical splits or hairline cracks in the tubing that might be difficult to locate with the profile caliper. In practice, the split detector is used to log down the tubing, and the profile caliper to log up the tubing. This gives a complete inspection for wall thickness and splits in one run of the cable in the well.

Casing Profile Calipers. Casing profile calipers are available to log 4%in.- through 20-in.-OD casing. The tool is especially valuable where drilling operations have been carried on for an extended period of time through a string of casing. The determination of casing wear is of great importance when deciding if a liner can be hung safely, or if a full production string is required. In pro- ducing wells, the casing profile caliper will locate holes or areas of corrosion that may require remedial work. The tool is also valuable when abandoning wells because it permits grading of casing to be salvaged before it is pulled.

Casing Minimum-ID Calipers. The minimum-ID caliper can pass through and accurately measure restric- tions as small as 3% in. in casing with a nominal ID up to 13% in. This log is of particular value in determining areas of collapsed or deformed casing, identifying casing-weight change intervals, or detecting parted casing.

Examples of these logs are given in Fig. 53.22.

53-19 OTHER WELL LOGS

TUBING PROFILE CALIPER

r

CASING PROFILE CALIPER CASING MINIMUM I.D. CALIPER

Fig. 53.22-Tubing and casing profile logs.

Electrical Potential Logs An electrical potential log determines the galvanic current flow entering or leaving the casing. This will indicate not only where corrosion is taking place and the amount of iron being lost, but also where cathodic protection will be effective. The magnitude and direction of the current within and external to the casing is derived mathematically from electrical potential measurements made at fixed intervals throughout the casing string. To achieve reliable results from this kind of survey, the borehole fluid must be an electrical insulator (i.e., the hole must be either empty or filled with oil or gas). Mud or other aqueous solutions will provide a “short” that in- validates the measurements. The log itself is a recording vs. depth of the small galvanic voltages detected. Fig. 53.23 illustrates such a log with three different runs recorded, each with a differing level of cathodic protection applied to the casing.

Figs. 53.24 and 53.25 show an interpretation of casing potential profile logs nm both with and without cathodic

protection. Note that in Fig. 53.25 the metal loss has been reduced to practically zero by the application of an appropriate cathodic protection.

Electromagnetic Devices The most commonly used casing corrosion inspection tools are of the electromagnetic type. They come in two versions, those that attempt to measure the remaining metal thickness in a casing string I5 and those that try to detect defects in the inner or outer wall of the casing. I6 Although frequently run together, these tools will be discussed separately.

Electromagnetic Thickness Tools. The electromagnetic thickness tools are available under a variety of trade names such as ETT (Schlumberger), Magnelog (Dresser), and Electronic Casing Caliper Log (Mc- Cullough). They operate in a manner similar to openhole induction tools. Each consists of a transmitter coil and a receiver coil. An AC is sent through the transmitter coil.


Fig. 53.23-Casing potential profile.

Fig. 53.24-Casing potential profile analysis-without cathodic protection.

This sets up an alternating magnetic field, which in- teracts both with the casing and the receiver coil (see Fig. 53.26). The coils are spaced about three casing diameters apart to ensure that the flux lines sensed by the receiver coil are those that have passed through the casing.

The signal induced in the receiver coil will be out of phase with the transmitted signal. In general the phase difference is controlled by the thickness of the casing wall. Thus the raw log measurement is one of phase lag in degrees and the log is scaled in degrees. Fig. 53.27 illustrates an ETT log in severely corroded casing. Note that an increasing thickness corresponds to an increase in the phase shift angle and vice-versa. Some presentations of this log show a resealing in terms of actual pipe thickness. This requires that the operator make some calibration readings in the type of casing present in the well. It is quite common to see quite large differences in thickness between adjacent stands resulting from a number of variables, such as the drift diameter of the pipe, the weight per foot, the magnetic relative permeability of the steel used, etc.

The ETT-type tool is good at finding vertical splits in pipe, since the magnetic flux lines pass perpendicular to the casing wall. A horizontal circumferential anomaly is less well defined.

Eddy Current and Flux leakage Tools (Pipe Analysis Log). Another closely related measurement uses a slight- ly different technique and forms the basis of the Pipe Analysis Log (PAL). I6 Two electromagnetic measurements are of interest in the context of the pipe analysis tool-magnetic flux leakage and eddy current distortion. ”

Fig. 53.25-Casing potential proflle-with cathodic protection.


I;2ux leakage. If the poles of a magnet are positioned near a sheet of steel, magnetic flux will flow through the sheet (Fig. 53.28). So long as the metal has no flaws the flux lines will be parallel to the surface. However, at the location of a cavity either on the surface of the sheet or inside it, the uniform flux pattern will be distorted. The flux lines will move away from the surface of the steel at the location of the anomaly, an effect known as flux leakage. The amount of flux distortion will depend on the size of the defect. If a coil is moved at a constant speed along the direction of magnetic flux parallel to the metal sheet, a voltage will be induced in the coil as it passes through the area of flux leakage. The larger the anomaly, the greater the flux leakage and, therefore, the greater the voltage. The magnetic flux is distorted on both faces of the sheet, regardless of the location of the
Fig. 53.26-Electromagnetic thickness tool
PHASE SHIFT

3M

Fig. 53.27-Electromagnetic thickness log.


Magnetic flux 1

Sensor coil

J

FL

Flux f leakage

1 I

/iagnet /’ lole piece

Casing H .l

Fig. 53.28-Magnetic flux leakage principle.

defect, and therefore the coil needs to be moved along only one surface to survey the sheet completely. Since the coil must be moved through a changing magnetic flux to produce a voltage, no signal is generated when it is moved parallel to the surface of an undamaged sheet of steel _

Eddy Currents. When relatively high frequency AC is applied to a coil close to a sheet of steel, the resulting magnetic field induces eddy currents in the steel (Fig. 53.29). These eddy currents, in turn, produce a magnetic field that tends to cancel the original field, and the total magnetic field is the vector sum of the two fields. A measure voltage would be induced in a sensor (receiver) coil situated in the magnetic field. The generation of eddy currents is, at relatively high frequencies, a near- surface effect. Therefore, if the surface of the steel adjacent to the coil is damaged then the magnitude of the eddy currents will be reduced, and, consequently, the total magnetic field will be increased. This will result in a variation in the sensor coil voltage. A flaw in the sheet of metal on the surface away from the coils will not be detected and, depending on its distance from the surface, a cavity within the sheet will not influence the eddy currents either.

Tool Principle. The measuring sonde consists of an iron core with the pole pieces of an electromagnet at each end, and 12 sensor pads in two arrays between the pole pieces (Fig. 53.30). The two arrays are offset radially to ensure complete coverage of the inner surface of the casing. Each of the pads contains a transmitting coil (for the eddy current measurement) and two sensor coils wound in opposite directions (for both the flux leakage and eddy current measurements). The two sensor coils are wound in opposite directions so that for both measurements

Transmlttcr coil

Fig. 53.29-Eddy current principle


there is zero voltage as long as no anomaly exists, but a signal will be produced when the quality of the casing is different below the two coils. The same sensor coils can be used for both measurements since two distinct frequencies are involved. A frequency of 2 kHz is used for the eddy current measurement, giving a depth of investigation of about 1 mm. The sensor pads are mounted on springs so that they are held in contact with the casing, facilitated through centralization of the sonde. Various sizes of magnet pole pieces are available and are selected according to the casing ID to optimize the signal strength for the flux leakage measurement.

Six measurements of flux leakage and eddy current distortion are made on each array, and the maximum signal from each array is sent uphole to the surface in- strumentation. Four signals, the eddy current and flux leakage data from the two arrays, are recorded.

The flux leakage data correspond to anomalies located anywhere in the casing, while eddy current distortion occurs only at the inside wall of the casing. The standard presentation of the measurements is as shown in Fig. 53.31, with the data from the two arrays displayed in Tracks 2 and 3. Enhanced data arc displayed in Track 1, making any anomalies more obvious.

Interpretation. The measurements are generally suitable only for qualitative interpretation. This is because any voltages induced in the sensor coils depend not only on the size of any flaws in the casing, but also on the magnetic permeability of the casing, the logging speed, and the abruptness of a defect. The measurement, therefore, is used primarily to locate the presence of small defects in the casing, such as pits and holes. Defects such as gradual decreasing of the wall thickness cannot be detected. To get a complete picture of the state of the casing the electromagnetic thickness tool also should be used to measure the casing wall thickness, since the PAT device will give zero signal in the two ex- tremes of no casing and perfect casing (except at the collars).

Two sets of data are recorded, one set influenced by defects occurring anywhere in the casing, and the other by faults on the inner surface. By examining the log, therefore, it can be inferred whether the casing is damaged on the inner or outer wall, assuming that there is no defect within the casing. Although the magnetic flux bulges away from both sides of the casing at the location of a defect, the effect is greater on the side of the flaw, hence for the flux leakage measurement, smaller defects can be detected on the inner surface than on the outer surface. Because of the overlapping configuration of the two-pad arrays all of the inner surface of the casing is surveyed, but there is a casing-diameter-dependent defect size below which the flaw will be seen by only one array, and above which it will be seen by both arrays.

The eddy current measurements are not able to detect flaws smaller than about 0.39-in. diameter, while the flux leakage limit is somewhat lower (0.25 in.). This means that if an anomaly of less than %-in. diameter is present it cannot be determined whether it is on the inner or outer surface. If a deflection is noted on the eddy current measurement but not on the flux measurement it is

6 ARM CENTRALIZER

MAGNET

UPPER PAD ARRAY

6 C

LOWER PAD ARRAY

MAGNET

ARM ENTRALIZER

Fig. 53.30-The pipe analysis tool


T ENHANCED CURVES LOWER ARRAY UPPER ARRAY

r Total wall Total wall Inner wall lnner wall

/

1 I I rrl j i

I;IFI I I I

I I i / /

/

i I4 z

Z-=- .- _ .-- _- - -- .

-

I ! --- -= ----

COI Se\ Sur

‘erc face

Fig. 53.31-The pipe analysis log In severely corroded casing.

OTHER WELL LOGS

LOWER ARRAY I UPPER ARRAY

Total wall inner wall Inner wall Total wall

\-. ,i

lz-. I ., -

_- -

Fig. 53.32-Pipe analysis log over a perforated section of casing.


assumed that the defect on the inner wall is less than 1 mm deep, and also usually can be ignored. In addition, events can be seen on the flux leakage readings that are not caused by casing damage but are a result of the presence of localized magnetization in the casing. This is one reason why a reference PAT survey should be run in new casing, so that a time-lapse technique can be applied to determine the casing damage.

The example of Fig. 53.32 includes sections of perforated casing (798 to 805 m, 807 to 819 m and 821 to 830 m), and there is a clear indication of damaged and undamaged casing. The flux leakage measurement (total wall) is responding strongly through the perforated intervals, the eddy current curve less so. This is probably a result of the diameter of the perforations being fairly close to the detection limit of the eddy current measurement. In the upper section the tool response is much lower, indicating a certain amount of corrosion on both surfaces of the casing, but probably nothing major. The large deflections occurring on all the curves are caused by the casing collars.

Casing Collar-Locator Log The collar locator is used to locate casing collars, usually in conjunction with another cased-hole service such as a nuclear log or a perforating gun. Perhaps its most common use is in precisely locating perforating points. To do this the collar locator is run with a nuclear log (either the gamma-ray or neutron log) after the casing is set. This survey accurately positions casing collar in reference to the nuclear log. By correlating the nuclear log with logs run in an open hole, casing collars can be positioned accurately with reference to the openhole logs. The collar locator is then run with the perforating gun. The collars adjacent to the desired perforating interval are located and the desired interval perforated using the casing collars as reference points. Use of the collar locator makes it possible to locate perforations within a few inches of the desired interval.

Various types of collar locators are now in use. Some of the collar locators are sensitive enough to locate old perforations in casing. The collar locator also can be used to locate the casing shoe in openhole completions.

I.

2.

3.

4

5

6

7.

8.

9.

IO.

II.

12.

13.

14.

15.

16.

17.

References Kamp, A.W.: “Downhole Telemetry From the User’s Point of View,” J. Pet. Tech. (Oct. 1983) 1792-96. Grosso, D.S., Raynal, J.C., and Radar. D.: “Report on MWD Experimental Downhole Sensors,” J. Per. Tech. (May 1983) 899-904, “Measurements While Drilling (M.W.D.) Technical Specifica- tions,” Schlumberger Well Services. Houston. Hodgson, H. and Gemado, S.G.: “Computerized Well Planning for Directional Wells,” paper SPE 12071 presented at the 1983 SPE Annual Technical Conference and Exhibition, San Francisco, Oct. 3-6. Scott, A.C. and Wright, J.W.: “A New Generation Directional Survey System Using Continuous Fyrocompassmg Techmques,” paper SPE 11169 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 29-Oct. 2. Walstrom, J.E., Harvey, R.P.. and Eddy, H.D.: “A Comparison of Various Directional Survey Methods and an Approach to Model Error Analysis.” J. Per. Tech. (Aug. 1972) 935-43. “Dipmeter- Interpretation-Volume-l-Fundamentals,” Schlum- I berger Ltd., New York City (1981) 8. 10. 53. Bateman, R.M. and Konen, C.E.: “The Log Analyst and the Pro- grammable Pocket Calculator-Part Ill-Dipmeter Computa- I I lion.” The Log Anal~w (Jan.-Feb. 1978) 19. No. I, 3-l 1. Bateman, R.M. and Hepp, V R.: “Application of True Vertical Depth, True Stratigraphic Thickness and True Vertical Thickness Log Displays,” paper presented at the 1981 SPWLA Annual Log- ging Symposium. Pennbaker. P.E.: “Vertical Net Sandstone Determination for lsopach Mapping of Hydrocarbon Re.servoin.” Bull., AAPG (Aug. 1972) 53, No. 8, 1520-29. Hepp, V.R.: “Vertical Net Sandstone Determination for lsopach Mapping of Hydrocatin Reservoirs-Dixussmn.” Bull., AAPG (1973) 57, 1784-87. Holt. O.R., Schoonovers, L.G., and Wlchmann. P.A.: “True Vertical Depth, True Vertical Thickness, and True Stratigraphic Thickness Logs,” Truns., SPWLA Logging Symposium (1977) paper Y. Peveraro, R.: “Vertical Depth CorrectIon Methods for Deviation Survey and Well Log Interpretation,” Truns., SPWLA European Symposium, London (1979) paper P. Bateman. R.M. and Konen, C.E.: “The Log Analyst and the Pro- grammable Pocket Calculator-Part VI-Finding True Straw graphic Thickness and True Vertical Thickness of Dipping Beds Cut by DirectIonal Wells.” 771~ Log Aria/w (March-April 1979). Cuthbert, J.F. and Johnson, W.M. Jr., “New Casing lnspectmn Log,” paper SPE 5090 presented at the 1974 SPE Annual Meeting, Houston, Oct. 6-9. Illiyan.-I.S., Cotton, W.J. Jr.. and Brown, G.A.: “Test Resultsof a Corrosion Logging Technique Using Electromagnetic Thickness and Pipe Analysis Logging -Tools,“-J. Per. Tkh. (April 1983) 801-08. “Well Evaluation Development-Continental Europe.” Schlum- berger Ltd., New York City (1982).

53 - Other Well Logs

Documents