Production logs are often used to inspect the well completion. Locating tubing, casing, or packer leaks, detecting channels behind pipe, and evaluating the condition of the cement are all common applications. In this section, we will review methods for locating channels or leaks followed by a discussion of cement evaluation.
Channels through the cemented region behind the casing can be located with temperature, radioactive tracer, and noise logs while leaks in casing or tubing are routinely detected with noise and radioactive tracer logs. Sometimes, a comparison of two or more production logs is the best means of locating leaks or channels.
A temperature log can sometimes indirectly detect channeling in an injection well by locating a cool anomaly away from the intended injection intervals. If there is no means for fluid to exit the wellbore at the location of the anomaly (such as through a casing leak), the fluid cooling the formation apparently traveled to the cool region through a channel.
Example 6 Channel Detection with a Temperature Log
Figure 19 [Hill, 1990] is an 18 hour shut-in temperature log from a well with a suspected channel. Looking first at the perforated interval, no cool anomaly has developed in this region, so it appears that little of the injected fluid is entering the formation opposite the perforations. The cool anomaly from 4790 ft to 4844 ft suggests that fluid is entering the formation over this interval after channeling up from the perforations beginning at 4848 ft. The cool anomaly at 4924 ft-4950 ft is likely due to injection into the openhole section of the well at this depth. On this particular log, the flowing temperature log indicates where fluid leaves the wellbore as the regions where temperature is increasing more rapidly with depth, such as from 4855 to 4865 ft.
However, in most injection wells, the flowing temperature log will show little definition across the overall injection interval.
Fig. 19 Temperature log showing channeling behind casing
Radioactive tracer logs can also be used to find leaks and channels. Since the gamma-rays generated by the radioactive tracer can penetrate 1-2 ft, it is possible to observe fluid movement outside of the casing with tracer loss logs. If the fluid movement can be clearly identified as being outside the casing, the tracer loss log can give a positive indication of channeling.
Channeling is identified on a tracer loss log by the development of a secondary peak of tracer concentration (gamma-ray intensity). Figure 20 illustrates this technique [Schlumberger, 1973]. After tracer enters the perforations at Sand #3, a secondary peak develops which moves back up the well (f, j, n, v). This movement indicates fluid channeling up the casing-formation annulus to Sand #4. Also, tracer is detected moving below the lowest perforated interval at Sand #2 (1, p). Presumably, this movement is due to channeling down to Sand #1. Finally, the secondary tracer peak remaining stationary at the packer is attributed to tracer caught in the hardware and in turbulent eddies and is not an indication of channeling.
Fig. 20 Hypothetical behavior of a tracer loss log in a well with channeling behind pipe
The noise log is one of the most positive means of detecting leaks or channels. A noise log is simply a record of a passive measure of the audible sound detected by a sensitive hydrophone at a number of locations in the wellbore. Since sound is generated by fluid turbulence, high noise amplitudes indicate locations where the flow path is such that additional turbulence is developed. Fluid moving through restricted channels, leaks, flow from perforations, and flow past the logging sonde are among the phenomena that can produce characteristic sounds in the wellbore and thus may be detected with a noise log. Analysis of the frequency characteristics of the measured noise can distinguish between the various possible sources of high sound amplitudes.
The noise log has been used primarily as a qualitative indicator of channeling behind pipe [McKinley et al., 1973]. Flow in a channel is indicated on a noise log by the presence of high amplitude noise at places where restrictions in the channel cause
throttling of the fluid, as shown in Fig. 21 [Atlas Wireline Services, 1982]. Similarly, flow through a leak results in a pressure drop that generates detectable noise.
Fig. 21 Noise
Fig. 21 Noise log
Example 7 Detection of a Leak with a Noise Log
Figure 22 [Hill, 1990] shows a noise log run in a well with a suspected packer leak allowing flow into the annulus. The log shown in Fig. 22 was run with 1200 psi surface pressure on the annulus; with this backpressure, no leak is evident as no noise anomalies occur at the packer location. Pressure was then bled off the annulus and the noise log repeated (Fig. 23 [Hill, 1990]). With low pressure in the annulus, a leak at the packer was clearly indicated by the noise amplitude peaks at the packer location.
Fig. 23 packer leak indicated on noise log with annulus pressure bled off
Sometimes, a combination of logs is needed to clearly distinguish between leaks and channeling behind pipe. Consider, for example, the log responses that would be obtained in an injection well with a channel downward from the lowest perforations and another injection well with a casing leak below the lowest perforations [Hill, 1990]. The temperature log responses that would be expected in these situations are shown in Figs. 24 and 25.
Fig. 25 Temperature logs for injection well with a casing leak below the bottom zone
The temperature logs are identical, as the temperature responds primarily to where the fluid enters the formation. Spinner and radioactive tracer logs for these wells are shown in Figs. 26 and 27. Now differences are seen between the logs. When channeling is occurring, the spinner and velocity shot logs detect no flow below the perforations (Fig. 26), while a casing leak results in flow in the wellbore past the bottom of the
perforations, as detected by the spinner or velocity shot log. In the case of channeling, the spinner or velocity shot log alone cannot find the anomalous well behavior. However, when they are compared with a temperature or tracer loss log, channeling is conclusively identified.
Fig. 27 Radioactive tracer logs for injection well with a casing leak below the bottom zone
4.2 Cement Evaluation
Acoustic logging techniques, primarily the cement bond log, have been used for many years to try to directly measure the quality of the cement between the casing and the formation. More recently, ultrasonic pulse-echo techniques have been developed in an attempt to eliminate some of the deficiencies of the cement bond log for cement evaluation.
A primary function of the cement is to prevent fluid movement between the various zones in a reservoir and between the reservoir and other zones up or down the hole. Thus, cement quality logging is aimed at determining whether the cement is of sufficient strength and is sufficiently distributed to prevent fluid communication between zones. Ideally, a cement quality log should indicate whether the cement is bonded to the pipe, if the cement is bonded to the formation, and if the channels are present in the cement. A cement quality log does not directly measure the capability of the cement to prevent fluid communication – this is inferred from the
degree of acoustic coupling of the cement to the pipe and the formation as measured by the logs. For this reason, cement quality logs are not an absolute measure of the hydraulic integrity of the cement; however, when run and interpreted properly, they have been shown to be generally reliable predictors of cement placement.
The two primary logs for evaluating cement quality, the cement bond log and the ultrasonic cement evaluation log, are both acoustic logs that differ primarily in the path taken by the sound waves between the transmitter and the detector. With the cement bond log, sound travels axially down the casing and through the cement and formation to detectors (usually two) located below the sound source on the logging tool (Fig. 28 [Hill, 1990]). An ultrasonic cement tool, on the other hand, has an array of transducers, or rotating transducers, that serve as both transmitters and receivers of sound energy, so that the sound path is radial to and from the transducers – Schlumberger’s Cement Evaluation Tool is pictured in Fig. 29 [Froelich et al., 1982]. Alternatively, the ultrasonic logging devises have transducers mounted on a rotating section of the tool . so that continuous acoustic scans of the cement conditions around the borehole circumference can be made. Thus, the two types of logs are fundamentally different measurements and must be treated separately.
Fig. 29 Ultrasonic pulse-echo log tool
A cement bond log usually records three separate measurements of the acoustic energy received: the transit time, a measure of the time from sound transmission to the first arrival of sound energy at the near detector; the amplitude, the amplitude of the first wave arriving at the near detector; and the full wave train, a presentation of all the
acoustic energy received by the far detector for a short time period. The full wave train is often displayed as a variable density log, constructed by rectifying the wave train and assigning varying shades of gray to the waves, based on their amplitude. These logs yield information about the acoustic coupling between the cement and the pipe and between the cement and the formation. Following are a few examples of cement bond log interpretation for different bonding conditions.
Free pipe – In uncemented casing, the amplitude log shows high amplitude and the transit time corresponds to the casing arrival time (the time required for sound waves to pass through the wellbore fluid and the casing). The variable density log shows
strongly contrasting parallel vertical lines with no indication of formation signals. Casing collars show up distinctively on a cement bond log in free pipe. Collar reflections result in chevrons (capital W’s on their sides) on the variable density log, a decrease in
amplitude, and an increase in transit time. A cement bond log in free pipe is shown in Fig. 30 [Hill, 1990]. It is important to log in an area of free pipe if possible when running a cement bond log. Any deviation from the expected response in free pipe indicates a malfunctioning or improperly centralized tool. This calibrates the tool in a known environment under logging conditions.
Fig. 30 Cement bond log in free pipe
Good bond to formation and casing –With good bonding, the amplitude is low. The full wave train display shows weak or no casing signals and strong formation arrivals unless the formation attenuation is high such as would be observed for an unconsolidated
gas sand, weak shales, or other low velocity formations. Comparison of the cement bond log with an open hole sonic log can help identify regions of high attenuation in the
formation. An example of good bonding to the pipe and the formation is presented in Fig. 31 [Hill, 1990].
Fig. 31 Cement bond log with good bonding to the pipe and the formation
Good casing bond but poor formation bond – This is characterized by weak casing arrivals as indicated by low amplitude and low contrast on the variable density log at casing arrival times and weak formation signals on a full wave train display.
formation acoustic attenuation and tool eccentricity. Good bonding to the pipe but not to the formation can easily occur opposite permeable zones where a mud cake is built up that is not displaced by cement. Figure 32 from Bigelow [1985] presents such a case where both casing and formation amplitudes are low. Interpretation of the bonding from the amplitude curve alone would give an erroneous picture of cement integrity – the lack of acoustic coupling to the formation indicates poor cementing even though the pipe amplitude is quite low. However, this behavior alone is not sufficient to prove a lack of hydraulic seal, as mud occupying the space between the cement and the formation may be immobile.
Fig. 32 Cement bond showing good bond to the pipe but poor bonding to the formation
Ultrasonic pulse-echo techniques have been developed in an attempt to overcome some of the deficiencies of traditional cement bond logs. The primary advantage of the ultrasonic devices is that they provide a circumferential picture of cement quality by utilizing multiple
transducers arrayed around the tool, or by rotating the transducer(s) to give continuous
measurement of cement conditions around the well circumference. The ultrasonic measurements are less sensitive, however, to acoustic coupling to the formation.
Ultrasonic pulse-echo tool originally consisted of an array of eight ultrasonic transducers spaced around the body of the tool such as shown for the Schlumberger Cement Evaluation Tool in Fig. 29. A ninth transducer is aligned axially and aimed at an acoustic mirror so that an in-situ measure of travel time in the wellbore fluid can be made. Pulse-echo tools operate within the resonance frequency of steel pipe, so that the casing will resonate if it is not well bonded by cement. These tools measure the bonding to the casing by measuring the rate of decay of casing vibration. The output from the eight transducer is presented as a map of the bonding conditions around the casing.
Newer ultrasonic tools have replaced the eight fixed transducers with rotatable
transducers that continually sweep around the borehole (Fig. 33, Morris et al.,2007). The angled transducers measure flextural attenuation of the acoustic energy.
Fig. 33 Rotating ultrasonic transducers on cement imaging tool
One of the primary advantages of the ultrasonic pulse-echo log is that it can identify unsupported sections of the pipe circumference since it measures bonding conditions at eight positions circumferentially around the pipe. Figures 34 from Catala et al. [1984] shows a typical response to a channel, with a few of the tracks showing poor bonding, while good bonding is indicated around the rest of the pipe. The channel appears to be spiraling around the pipe; however, the relative bearing recording indicates that the tool was slowly rotating as the log was run – the channel is consistently on one side of the pipe.
Fig. 34 Ultrasonic pulse-echo log