2. Cement evaluation log
A representation of the integrity of the cement job, especially whether the cement is adhering solidly to the
outside of the casing.
The log is typically obtained from one of a variety of sonic-type tools.
The newer versions, called cement evaluation logs, along with their processing software, can give detailed,
360° representations of the integrity of the cement job, whereas older versions may display a single line
representing the integrated integrity around the casing.
3. What is Cement Bond Log (CBL)?
• The Cement Bond Logging tools have become the standard method of
evaluating cement jobs.
• They indicate how good the cement bond is.
• A cement bond log (CBL) documents an evaluation of the integrity of
cement job performed on an oil well.
• It is basically a sonic tool which is run on wireline.
• Similar to a ringing bell, when no cement is bonded to the casing,
pipe is free to vibrate (loud sound).
• When the casing is bonded to hard cement, casing vibrations are
attenuated proportionally to bonded surface.
5. When there is good bonding between the casing and the cement, the acoustic signal is attenuated, proportionally
to the surface of the casing attached to the cement
Water or mud
No
Cement
Good
Bonding
6. CBL Measurement Principle
• The basic tool configuration of CBL-VDL log is composed by One Transmitter and Two Receivers: the first Receiver is
located 3 ft. from the Transmitter and is used for CBL Measurement.
• The second Receiver is located 5 ft. from the Transmitter and is used for Variable Density Log (VDL).
• NB: CBL-VDL logging tools MUST be centralized.
7. CBL-VDL Log Applications
• Operator needs to evaluate cement job by checking the integrity of cement and verifying zone isolation.
• Also, CBL-VDL log is used to determine cement quality and answer the following questions:
• Is there any channeling?
• Is it necessary to Repair?
• And, will it be possible to repair (by performing a cement/chemical squeeze)?
8. CBL Operations Requirements
• As per API 10TR-1 “Cement Sheath Evaluation”, the following recommended practices are required to produce a
valid CBL:
• A fluid-filled borehole. Gas or air bubbles will induce inaccurate readings.
• Centralized CBL tool during the run.
• A bit and scraper run is recommended to remove cement and/or scale from the casing wall.
• Wellbore schematic.
• Plot of the cement strength vs. time to determine the time after which logging can produce a valid log.
• Predicted cement tops for the lead and tail cements.
• Casing and centralizer report to determine where casing eccentering may occur.
• Openhole logs with a caliper and lithology.
• An understanding of fluid type or gas in the formation pore space.
9. Radial-CBL
Radial-CBL tools were developed to overcome some limitations of conventional CBL tools and to permit more accurate
evaluation of cement distribution by providing the precise location of partial bond and channeling. These tools use one or
more azimuthally sensitive transducers to evaluate cement quality around the circumference of the casing. Data from
these tools are presented as individual log curves or as azimuthal images (“maps”) of cement quality generated by
interpolating between the individual azimuthal measurements. In addition, each tool design also provides a conventional
5-ft VDL waveform measurement to provide information about the cement to formation bond.
10.
11. Variable –Density log VDL
• A presentation of the acoustic waveform at
a receiver of a sonic or ultrasonic measurement, in
which the amplitude is presented in color or the
shades of a gray scale.
• The variable-density log is commonly used as an
adjunct to the cement-bond log, and offers better
insights into its interpretation; in most
cases microannulus
• and fast-formation-arrival effects can be identified
using this additional display.
• In openhole, it may be displayed alongside the sonic
log transit-time as a qualitative presentation of the
acoustic wave train, and is sometimes used
for fracture detection by examination of the chevron
patterns given by Stoneley wave reflections (and other
wave reflections) at fractures crossing the borehole.
12. Sonic Foundations - VDL
• The variable density record is the complete
presentation of the wave recorded in the 5-ft receiver
• It is plotted with light and dark stripes.
• The contrast depends on whether the amplitude is
positive or negative
• Allows easy differentiation between the casing signals
and formation and fluids in the well
• Unless the casing is completely eccentric, the signal
received from the presence of the formation will be:
o A qualitative indicator of the presence of a solid
material behind the casing
o It will not indicate the amount of this solid
material
13. • The 5ft VDL curve provides a greater depth of research than the 3ft CBL
15. Example of a Good CBL
Quality control
• Check the curve of the TT
Check the curve of the CBL
• Relatively shows a low amplitude
Verify the VDL
• There are no casing arrivals.
• The formation signals are clearly observed.
16. VDL Log (Variable Density) Tools & Interpretation
The Variable Density – VDL Log in essence is a further refinement of the conventional CBL (Cement Bond
Log) by including a full waveform display, presented on the log as ‘a variable intensity’ in shades
between black and white, representing maximum and minimum in amplitudes.
It is used mainly in the interpretation of the cement-to-formation bond (Cementing In Drilling). You
might be interested in cement evaluation & cement evaluation tool.
17. Figure 1 – CBL.VDL tool schematic
• The essential parts of the CBT are an acoustic transmitter
and one or two receivers spaced at 0.9 (CBL) and 1.5 m
(VDL Log) below (or at 1.2 m for a single receiver
configuration).
• Figure 1.
• In fact, the tool is the same as used for open bore-hole
compensated sonic logging (BHC).
18. Mechanism & VDL Log Tool Working Principle
• In the VDL transmitter short bursts of acoustic energy, at a frequency of 10 to 30 kHz, are generated and emitted in a
spherical wave.
• The duration of each emission is typically 50 μs and is repeated once every 1 to 5 seconds.
• In between the emissions the receiver{s) pick up the refracted and direct waves, in the form of a wave train of varying
amplitudes, measuring their arrival times.
• Part of the refracted energy travels through the casing and shows up on the VDL as the first arriving signal as the wave
travels faster along casing than through the (liquid) hole contents (transit times for casing and water are 187.5 and 683
μs respectively).
• Some of the acoustic energy traverses the casing and is partly refracted, partly conducted by cement and formation and
arrives at the receiver{s) in accordance with their transit times.
• The strength of the signal from cement and formation first of all depends on the part of the energy of each pulse that is
passing the interfaces casing-cement and cement-formation.
• A good shear coupling facilitates a high energy transfer across these interfaces.
• Therefore the strength of the received signal is a measure of this coupling and by extension the cement bond, taking
into account the attenuation effects imposed by the media.
• The total signal picked up by the VDL log tool receiver{s) will be rather complex, composed as it is of compressional
waves from the four media (liquid, casing, cement and formation rock) and shear waves from the solid media.
• By using ‘gates’ in the electronic circuitry processing the receiver signal, unwanted parts of the wave train are filtered
out, thereby enhancing the parts of interest.
• Figure 3 (below) is an example of a wave signature. Table 1 compares gating systems.
19. Example of a Bad CBL
1.Control the quality
Check the curve of the TT
2.Check the curve of the CBL
High amplitude
3. Verify the VDL
There are signs of the casing
There are no formation
signs-There are parallel
lines
Bad Isolation
23. • For the CBL to produce meaningful results it is essential too that the tool is centralized in the (cased) hole and logging is
carried out at a constant speed.
• The speed, together with the pulse frequency at the transducer, determines the ‘resolution’ of the tool, i.e. the height that is
covered by a single pulse emission and receiving cycle.
• The interpretation of the VDL log today is as much a matter of debate, indeed of controversy, as it was at the time of its
inception.
• Even under the best of circumstances bond logging interpretation requires a thorough understanding of the fundamentals of
sonic logging.
• As there are a great many variables the signal interpretation can be very complex and experience in cement evaluation,
therefore, is very valuable.
• In many cases the results can be undiscriminating, leaving some questions unresolved. However, it still can provide a
qualitative assessment of the degree of cement fill in the annulus that has been achieved and the shear bonding of cement to
casing and formation alike.
• As the formation plays an important role in the evaluation of the cement bond, open-hole log and evaluation data, such as
Caliper, porosity and lithology need to be taken into account in the interpretation of the CBL / VDL tool response.
24. Quality Control
• The interpretation process should begin with quality control of the log for which it is essential that the log
also has a transit time curve, allowing comparison of measured with expected transit times.
• This comparison may show transit times shorter or longer than expected:
• Shorter transit times may indicate poor centralization of the sonde or are caused by fast formations.
• If the shorter time is indicative of poor tool centering quantitative CBL evaluation becomes impossible
when the shortening exceeds a certain limit.
• A maximum of 4 μs is widely used.
• Longer transit times (‘stretch’) as pictured in Figure 4 usually indicate a good bond when a corresponding
low amplitude is observed and the differential is less than 15 μs.
• When the amplitude is high a thin cement sheath and high acoustic impedance contrast might be
implicated.
• If longer than 15 μs a good cement-to-pipe bond is present, particularly when this is a ‘cycle skip’, i.e. the
first cycle of the original wave is that much attenuated that the amplitude is below the detection level of
the receiver, as set by the ‘gate’.
• Figure 5 shows an example of cycle skipping.
27. Good Cement Bond Indication In VDL Log
• If cement is well bonded to the pipe and formation a high proportion of energy will pass to the formation to propagate
and be attenuated before it shows up at the receiver.
• The better the shear bonding the higher the ‘loss’ of energy to cement and formation.
• The loss to the borehole (liquid + pipe) is low and constant, therefore the variation in energy received is from the annular
material.
The Annulus is Filled With Fluid
• If the annulus is filled with fluid little or no acoustic energy is lost and the signal received will be composed only of the
casing and fluid waves.
• A micro annulus between pipe and cement will have a similar effect as fluid fill in that the absence of an acoustic
coupling means little energy is transmitted and eventually returned to the receiver.
VDL Log Extra Complications
• In the interpretation of a cement bond log extra complications come from e.g.:
• Unconsolidated formations.
• These have a strong attenuation effect on sonic energy.
• Therefore the amplitude of the receiver signal will be low and the VDL log will indicate a poor cement-to-formation
(Figure 6).
• When transit times of formation are shorter (‘fast formations’) than for casing the formation signal will arrive earlier than
the one from the casing. This is important for tool settings, so as not to miss this early arrival.
• Poor centralization may result in intimate contact between casing and formation, which may show up, erroneously, on
the VDL as a strong formation signal (Figures 7 and 8).
• Plastic, homogeneous salt formations may cause the VDL log to indicate free pipe as this type of formation causes a high
degree of attenuation and no contrast in the wave train.
30. Figure 8 – Effect of eccentricity on the acoustic signal at the VDL receiver
31. VDL Log Bond Index
• The Bond Index has been introduced to give a quantitative interpretation of the cement bond.
• It is defined as the ratio of cemented cross-sectional area at the zone of interest and full cement fill.
• The index is based on the linear relationship between attenuation and cemented area, as shown in Figure 9.
33. Log Nomograph – Attenuation and compressive strength
• In the early days after CBL / VDL log evolution, a nomograph was introduced known as the ‘CBL interpretation chart’.
It relates the attenuation to casing size and weight but above all to the compressive strength of the cement (check
also oil well cement properties).
• This has been proven wrong and nowadays the nomograph uses the acoustic impedance of the cement rather than its
strength.
• This change also allows the nomograph interpretation of non-conventional cements, such as foamed
cement formulations, as long as the acoustic impedance is known.
34. Interference and parameters affecting CBL & VDL Log
• Apart from tool and technique-related parameters that have a bearing on the final logging result, there are a number of
‘external’ factors that influence CBL / VDL results.
• Temperature and pressure affect sound transmission and attenuation in well-bore fluid and casing/rock material.
• It also has some effect on the response of transducers and receivers.
• Also, increases and decreases in hydrostatic pressure inside the casing may indirectly reduce the cement bond quality by
creating a micro-annulus.
• Running the log at sufficient pressure, therefore, is a prerequisite for successful logging.
Casing size and thickness
• the larger the casing the longer the path acoustic energy has to travel before reaching the casing, resulting in attenuation
increasing with size.
• Greater thickness in contrast leads to less attenuation and a stronger signal at the receiver.
35. Fast formations
• Fast formations* lead to shorter transit times than expected. When sufficient acoustic energy propagates through the
formation it would imply a good acoustic coupling between pipe and formation.
• However, as wave amplitudes vary a great deal in formations the first arriving cycle, which normally is used to measure
transit time, maybe too weak to be picked up. In this case, the second wave is used, leading to apparently longer transit
times rather than shorter, indicative of fast formations.
Well-bore fluids.
• The acoustic properties of well-bore fluids have an impact on the transit time and CBL amplitude, particularly for large
casing sizes where the ‘fluid path’ is relatively long.
*Fast formation
A formation where the velocity of the compressional wave traveling through the borehole fluid is less than the velocity
of the shear wave through the surrounding formation.
In such conditions a shear head wave is generated, so that standard techniques based on monopole transducers can be
used to measure formation shear velocity.
In hard formations, several normal modes are excited in addition to the Stoneley and leaky modes.
38. Good Bond To Pipe & Formation
Good Bond To Pipe & Formation - Good bond
to pipe is characterized by a low 3’ amplitude,
transit times of something other than pipe
arrivals (which are consistent), lack of pipe
arrival in the VDL and low 2’ radial amplitudes
(if RBL). Good bond to formation can be
assumed if the VDL exhibits strong formation
arrival suggesting good acoustic coupling
between cement and the surrounding
formation. Travel time will also track lithology.
39. Free Pipe
Free Pipe - No bond to pipe (free pipe) is
characterized by a high, consistent 3’ amplitude,
consistent 3’ travel time, high radial amplitudes,
strong pipe arrivals (train tracks) and chevron
patterns in VDL. No formation arrivals are
present in the VDL as no cement is present to
carry acoustic signal to formation and back to
the receivers.
40. Good Bond to Pipe & Poor Bond to Formation
Good Bond To Pipe & Poor Bond to Formation - Good bond
to pipe is characterized by a low 3’ amplitude, transit times
of something other than pipe arrivals (which are
consistent), lack of pipe arrival in the VDL and low
2’ radial amplitudes (if RBL). Poor bond to formation may
be assumed if
the VDL does not exhibit strong formation arrivals (may not
be present at all). Must be aware if VDL is from 3’ or 5’ as
mud may be confutes with formation.
41. Channel
Channel - a channel is a potential conduit for
formation fluids from one zone to
communicate with another, contaminate
groundwater or allow for fluid/gas
communication to surface in the form of
surface casing vent flow or gas migration.
Radial bond logging allows for the
identification of channels not readily identified
on basic cement bond logs.
42. Fast Formation
Fast Formation - to get formation
arrivals there must be good bond from
cement to pipe and cement to
formation. Thus, if there is fast formation
arrival there is good bond on both sides
of cement. The problem arises when the
formation arrival appears like pipe
arrival. Look for clean GR (hard rock -
carbonates)earlier arrival times in VDL
and travel time, , wavy appearance
in VDL and lack of chevrons in VDL. 3’
amplitude may be high or low.
43. Light Weight Cement
Light Weight Cement - VDL exhibits a “straight
line” collar effect with no chevron patterns.
First arrival in VDL and 3’ Travel Time is pipe as
cement does not fully attenuate signal. 3’
amplitude may baseline up to 10 mV (new
100% bond). Formation arrival may be weak if
present.
44. Microannulus
Microannulus - Micro-seperation of
pipe from cement that reduces the
cements ability to support the pipe in
shear and thus allows for some pipe
ring. To test for a microannulus, the
pipe is logged under pressure to see a
reduction in 3’ amplitude, loss of pipe
arrival in VDL and improved radials.
The presence of a microannulus
indicates cement present.
45. Ten feet of apparently
good cement on the USIT
and VDL cement map was
not sufficient to prevent
communication between
the perforations.
46. As per cement design, Tail cement density is 14.2 ppg; Lead
cement density is 9.5ppg and lifted to surface.
A, B, C: Indications of relatively large dry micro-annulus (at A)
progressively reducing in gap size from A to B to C. D: Slight
wet micro-annulus in tail cement.
Track 1 – GR; Tracks
2-AI Map;
3-Flex. Attn.;
4-Std. SLG map;
5 – CBL; Track
6 – VDL; Track
7 – Depth in ft.; T
rack 8 - Well schematics: 7" - 9 5/8" casing; Track
9 –TIGHT SLG map; Track
10- AIAV: averaged AI from ultrasonic,
ZSONIC = AI from sonic amplitude.
47. As per cement design, Tail cement density is 14.2 ppg;
Lead cement density is 9.5ppg and lifted to surface.
Cement topped up with a top job. The interval below
1200 ft is neat cement that exhibits a cement de-
bonded with a dry micro-annulus. At the D the neat tail
cement is well bonded; B, C: Indications of dry micro-
annulus progressively increasing in gap size from C to B.
Interval above 1200ft is cemented with light-weight lead
cement. At E the light weight cement is interpreted to
be bonded. The brown shaded intervals indicate varying
AI of light- weight lead cement. Examining the cement
maps from AIBK and Flex. Attn., we see circumferential
presence of solids in most of the "brown shaded"
intervals and the AI variations are attributed mainly to
changes in cement AI. However, in some intervals, some
of the AI variation may be attributed to thin channels
caused by eccentralization of pipe. At A, it is completely
de-bonded dry. Pipe eccentering and lack of
circumferential displacement of lead is indicated on the
cement map (F) and helps identify presence of a wide
channel and rule out a wet micro-annulus. Track 1 – GR,
CBL; Track 2-VDL; Track 3 – Pulse-echo AI map; Track 4-
Flex. Attn. map; 5- Std. SLG map; Track 6 – Depth in ft.;
Track 7 - Well schematics: 7" - 9 5/8" casing; Track 8 –
TIGHT SLG map; Track 9-AIAV: averaged AI from
48. Density distribution of points on TIGHT [2] model for
sections cemented with light-weight and neat cement. Path
D-C-B corresponds to the tail section with the neat cement
at various stages of dry de-bonding. At the D the neat tail
cement is well bonded; B, C: Indications of dry micro-
annulus progressively increasing in gap size from C to B.
Path E-F-A corresponds to the light-weight lead cement. At
E the light weight cement is well-bonded. At A, it is
completely de-bonded dry. Pipe eccentering and lack of
circumferential displacement of lead is indicated on the
cement map (F).
49. AN INTEGRATED APPROACH
TO CEMENT EVALUATION
Courtesy Schlumberger
Gunnar DeBruijn
Anouar Elhancha
Polina Khalilova
Pavel Shaposhnikov
Gioconda Tovar
Paul Sheperd
50. Invizion-Well integrity services
Increase zonal isolation assurance in your well
• Cementing is a critical part of achieving long-lasting zonal isolation, which
affects productivity, helps avoid annular pressure buildup or sustained casing
pressure, and is necessary to maintain well control.
• Invizion well integrity services ensure effective zonal isolation to increase the
success of stimulation treatments and aid production optimization while
limiting the operational footprint.
Invizion RT real-time well integrity service
• Invizion RT real-time well integrity service significantly improves cementing
operations by enabling operators to monitor, control, and evaluate cement
placement in real time.
• The service combines the job design with real-time acquisition data from both
the rig and the cementing equipment to accurately represent the operation as
it is being conducted.
Invizion Evaluation well integrity evaluation service
• Invizion Evaluation well integrity evaluation service enables operators to
ensure zonal isolation, verify regulatory compliance, plan completions, and
address technical challenges for future wells.
• The Invizion Evaluation service's team of highly trained and specialized
engineers works with experts in multiple disciplines and uses state-of-the-art
software-based interpretation tools to increase the success of cementing
operations.
52. • For land wells, Invizion Evaluation service's multidisciplinary approach provides precise, fit-for-purpose
solutions that mitigate losses and prevent aquifer contamination, even when using lightweight cement or
operating in extremely cold environments.
• In offshore wells, Invizion Evaluation service couples openhole data and cement placement analysis with
cement evaluation logs to provide a more complete picture of the well for greater zonal isolation assurance.
• Primary cementing operations rank among the more important events that occur during a well’s lifetime.
• The cement sheath plays a critical role in establishing and maintaining zonal isolation in the well, supporting
the casing and preventing external casing corrosion.
• Well cementing involves a myriad of geologic, chemical and mechanical parameters.
• The operation may be divided into several principal activities—drilling the wellbore, casing the wellbore,
placing the cement slurry in the casing to wellbore annulus, allowing the cement to set and then evaluating the
quality of the resulting cement sheath.
• Secondary considerations may include remedial treatments to correct cementing problems and the long-term
effects of production on cement sheath integrity.
• Primary cementing requires the wellbore to be in a condition that is conducive to successful cement slurry
placement.
• For example, the borehole should be free of washed-out, out-of-gauge zones.
• Caused either by soft or unconsolidated formations or as a result of drilling practices, washouts create
irregular and enlarged boreholes that are difficult to clean up and tend to hold gelled or dehydrated drilling
fluid that can contaminate the cement slurry.
• Because they also create voids in the borehole wall that must be filled with cement, washouts must be factored
into cement volume calculations.
53. • To determine the location and volume of washouts, engineers usually perform openhole caliper measurements
prior to running casing.
• In the absence of a caliper measurement, the cement volume must be estimated.
• When designing the cement job, engineers may also be guided by other formation considerations, including
pore pressures, fracture gradients and the locations of potential lost circulation zones.
• As the casing is run in the hole, centralizers installed on the outside of the pipe establish a standoff between
the casing and the wellbore that provides open flow paths in an annulus.
• The general guideline for centralization is to maintain a casing standoff sufficient for effective mud removal
and cement sheath coverage.
• When the casing is poorly centralized, annular constrictions can trap drilling fluid between the casing and the
wellbore, preventing complete cement coverage.
• This problem is exacerbated as a well’s deviation angle increases.
• For many years, the industry has employed strategies to promote optimal cement placement results.
• These strategies, collectively known in the industry as good cementing practices, dictate that drilling fluid be
conditioned prior to a cement job.
• Conditioning is a process of homogenization, cuttings removal, gelled mud dispersal and adjustment of
rheological properties to facilitate cementing.
• Many cement placement simulators provide recommendations that address drilling fluid conditioning.
• In the absence of cement placement simulators, cementing personnel commonly circulate at least one annular
volume of drilling fluid before pumping the cement slurry.
• This precaution is carried out after casing is run to remove entrained gas and cuttings, break the fluid’s gel
strength and lower the fluid’s yield stress and plastic viscosity.
• However, such broad measures may be questionable in light of the highly diverse and increasingly complex
wells being drilled today.
• Chemical washes and spacer fluids are pumped ahead of the cement slurry to facilitate removal of drilling
fluid and prevent commingling of the drilling fluid and the cement slurry.
54. • The types and volumes of washes and spacers are selected on the basis of the drilling fluid properties and
hole geometry as well as the physical and chemical environment downhole.
• When feasible, casing movement—in the form of reciprocation, rotation or both—is performed while
circulating drilling fluid and while pumping preflushes and cement slurries.
• Casing movement helps reduce drilling fluid viscosity and dislodge gelled drilling fluid from annular
constrictions, thereby providing an improved environment for cement placement.
• The cement slurry is designed to perform within the parameters of the anticipated wellbore environment.
• Accurate temperature and pressure data are essential inputs to the design process.
• Cement parameters that must be optimized include rheological properties, thickening time, strength
development, permeability, free fluid and long-term durability.
• During job execution, care must be taken to prepare the preflushes and cement slurries according to the
design and to pump these fluids at the planned rates to ensure successful cement placement.
• The wellhead pressure must also be examined throughout the operation to verify that the fluids are being
placed properly and that the well is under control.
• Modern cement mixing and pumping equipment is fitted with sensors that allow engineers to closely monitor
and record these parameters.
• After the cement sheath has set and hardened, logging helps engineers ascertain the quality of zonal
isolation.
• Log interpretation can be improved if logging personnel are informed of previous drilling and cementing
activities as well as the physical properties of the cement.
55. • Information about hole geometry, potential lost circulation zones, mud type, spacer fluid and cement
properties, pressure testing and unusual events that occurred during drilling and cementing may help logging
engineers properly calibrate tools and ensure that sufficient logging data are obtained for cement sheath
evaluation.
• Building on established cementing practices, a system for rendering all relevant information into a compatible
format allows a more efficient and thorough analysis of the principal parameters influencing primary
cementing and zonal isolation.
• Schlumberger engineers have developed a technique by which logging personnel and operators may easily view
and analyze previous well events, thereby improving log interpretation.
• This article presents case histories from Alaska, Colorado and Texas, USA, and from the Gulf of Mexico.
• These cases illustrate how performing a comprehensive examination of the entire well construction process can
help engineers verify primary cementing success or diagnose why cementing objectives have not been met.
• In the latter case, the lessons learned can provide guidance for remediation and improving results in future
wells with similar parameter integrated Cement Evaluation .
• In the context of well cementing, the concept of following a cementing operation from the design stage through
the execution stage and to the evaluation stage has existed for some time.
• Accordingly, Schlumberger has organized dedicated teams of drilling, geomechanical, logging and cementing
engineers that perform multidisciplinary analyses of virtually all parameters relevant to the lifetime of a well.
• A community of these engineers is located at Schlumberger PetroTechnical Engineering Centers (PTECs)
around the world.
• Their principal objective is to provide operators with information to safely and efficiently construct wells and
maximize well productivity.
56. • The engineers gather the data and arrange the information in a workflow that allows offset well histories to be
used during well planning.
• Within the PTECs, multidisciplinary teams of well integrity engineers (WIEs) collaboratively analyze many
well parameters and arrange the information in a workflow that allows straightforward visualization of the
history and current status of a well.
• At key junctures, the WIE teams are also able to remotely monitor and analyze the current status of a well.
Because the datasets frequently come from various sources in a variety of formats, they must be normalized to
allow a coherent examination.
• Engineers accomplish this task by entering the data into the Techlog wellbore software platform.
• The platform consists of a comprehensive set of modules that accommodates the myriad types of data acquired
during a well’s lifetime.
• An interactive graphical user interface allows engineers to evaluate details throughout the entire well
construction process.
• The WIEs use the software platform to collaboratively examine formation geology and petrophysics, well
geometry, drilling events, drilling and cementing fluids, cement placement events and cement sheath
evaluation logs (Figure 1).
• The information is arranged into a chronological account of well events that is used in the newly developed
Invizion Evaluation well integrity service.
• Ancillary data such as laboratory test results and modeling predictions may be displayed in separate windows
on the presentation.
• he system’s capability to visualize and evaluate all of the available well data allows the WIEs to perform
improved interpretations and determine why zonal isolation has or has not been achieved.
57. Figure 1. Well properties and measurements for the Invizion Evaluation service.
Well integrity engineers analyze many types of data to generate an Invizion Evaluation presentation that
shows drilling measurements, cement placement data and cement sheath evaluation logs.
58. • Using the Invizion Evaluation service, holistic assessments have been performed on more than 100 casing strings
worldwide.
• Cementing Depleted Sands in Alaska An operator in Alaska is producing from a reservoir characterized by depleted
sands, potential lost circulation zones and a narrow fracture pressure window.
• The wells have deviation angles up to 60° and the producing interval lies between 9,800 and 10,060 ft [2,990 and
3,070 m].
• The bottomhole static temperature (BHST) is approximately 150°F [66°C]; the temperature at the anticipated top of
cement (TOC)—about 4,000 ft [1,200 m]—is 75°F [24°C].
• A retarder was added to the cement slurry to prevent premature setting at the TD; however, the retarder also
presented risk of slurry over retardation at the TOC depth.
• Because of the narrow fracture pressure window, a low fluid density contrast was necessary to avoid well failure.
• The densities of the drilling fluid, spacer fluid and cement slurry were 10.4, 11, and 11.5 lbm/galUS [1,250, 1,320 and
1,380 kg/m 3 ], respectively.
• State regulations require that, before continuing operations, engineers must confirm the location of the top of cement
and verify the presence of competent cement around the circumference of the casing.
• Because of the small density contrast between the wellbore fluids, the operator typically had to wait several days
after the cement job for the set cement to develop an acoustic signature that would be discernable by most wireline
logging tools.
• The delay was expensive in terms of rig time.
• To determine whether cementing and logging could proceed more efficiently while reducing the waiting-on-cement
(WOC) time, the operator elected to use the Invizion Evaluation service.
• The engineers were provided with data gathered during drilling and cementing along with the compositions and
rheological properties of the wellbore fluids.
• The well deviation created a narrow side of the annulus, where cement contamination by mud would be more likely.
• Knowing the rheological properties of the drilling fluid, spacer fluid and cement slurry, the engineers performed
cement placement simulations to obtain guidance for preventing such cement slurry contamination and for
estimating whether the cement would cover the entire interval of interest (Figure 2).
59. Figure 2. Alaska well presentation. Tracks 1 through 5 display well information and measurements
obtained before cement placement. Tracks 6 through 9 present cementing execution information.
Track 9 predicted that some mud contamination (red) could be expected in the lead cement slurry to
a depth of 9,200 ft. However, no contamination was predicted across the tail slurry below 9,150 ft
(Track 9, dark gray). Tracks 10 through 14 show cement evaluation results. Acoustic and ultrasonic
logs that were run 27 hrs after cement placement confirmed adequate cement coverage and zonal
isolation across both the lead and tail portions of the cement sheath below 4,000 ft (Track 14,
predominantly brown).
60. • The results of the simulation indicated a risk of incomplete mud removal and also provided an estimate of the
volume of cement contaminated by mud.
• In the laboratory, Schlumberger engineers prepared cement slurries whose compositions corresponded to the
mud contamination estimate and cured the samples in an ultrasonic cement analyzer (UCA) at the well’s
BHST.
• The tests indicated that, despite the contamination, the cement slurry would set within 10 hours; however, the
acoustic impedance differential was only 0.3 Mrayl—too small to be detected by conventional logging tools.
• Three days of curing would be necessary for the cement to develop a sufficiently high acoustic impedance
contrast to permit evaluation by conventional logging methods—confirming the operator’s previous experience.
• The WIEs recommended the use of the Isolation Scanner cement evaluation service because of its ability to
acquire more sensitive acoustic impedance measurements.
• The tool combines the classic pulse-echo techniques of ultrasonic bond logging tools with a flexural imaging
technique that provides more effective imaging of the annular fill, including reflection echoes at the cement-
formation interface—the third interface echo (TIE).
• The TIE also allows engineers to determine whether material behind the casing is solid, liquid or gas.
• Correlating data from the UCA to the capabilities of the Isolation Scanner technology, the WIEs determined
that logging could commence as early as 27 hours after cement placement.
• The cement execution data and laboratory data, combined with the log information, illustrated the presence of
good cement across all sections of the cement sheath.
• The operator has continued to employ this evaluation technique, lowering the WOC time and reducing
completion costs.
61. • Solving Sustained Casing Pressure in Colorado The Niobrara play in the Denver-Julesburg basin is located in
a highly populated region along the Front Range in Colorado, USA.
• This field pro- duces approximately 250,000 bbl/d [39,700 m 3 /d] of oil from the Niobrara formation.
• One of the principal operators has more than 8,400 active wells in the region.
• Effective zonal isolation is of particular importance because some wells are located immediately adjacent to
residential areas.
• Sustained casing pressure caused by gas migration through inadequate tail cement is a cause for concern and
has been confirmed by cement bond log (CBL) and USI ultrasonic imager logs in certain cases.
• To mitigate gas migration, the operator elected to try the Invizion Evaluation service.
• The operator provided the WIEs with pertinent well data, which were loaded into the Techlog platform to
produce a comprehensive presentation (Figure 3)
• The analysis indicated that previous wells had poor casing centralization, resulting in poor mud removal that
allowed channels to form in the cement sheath and serve as conduits for annular gas migration to the
surface.
• Based on these findings, the operator increased the centralizer density by 50%, which led to better cement
slurry displacement and mud removal.
• Sustained casing pressure was no longer observed.
• The investigation also included using the CemSTRESS cement sheath stress analysis soft- ware to estimate
the radial and tangential stresses imposed on casing strings, cement sheaths and formations during the life
of a well.
• The input parameters included Young’s modulus, Poisson’s ratio and cement compressive strength.
62. Figure 3. Colorado well presentation. The first presentation (left ) indicates numerous areas of poor casing
standoff (Track 1, red). The cement displacement simulation predicted areas of poor mud displacement (Track 2,
red). The acoustic impedance map also showed regions of poor cement coverage (Track 3, blue) up to the
surface—which explained the presence of sustained casing pressure at the surface after cementing. The second
presentation (center ) shows the results obtained by improving the casing centralization. The simulator
indicated good mud removal and cement displacement up to a depth of about 2,000 ft (Track 2, green). Although
cement did not reach the surface, no gas or pressure was observed. The third presentation (right ) shows the
results of improved rheological properties of the cement slurry in addition to improved centralization. The
cement reached the surface and the acoustic impedance map shows competent bonding with no contiguous
channels (Track 3). Sustained casing pressure was not observed using this design
63. • The software evaluates cement sheath performance in compression, tension or both; it can also identify both
inner and outer microannuli and predict their size and development over time.
• In wells that experienced gas leakage, CemSTRESS analysis showed that the Young’s modulus of the formation
surrounding the tail section of the cement sheath was too low to sup- port the mechanical properties of the
cement compositions that had been pumped.
• As a result, the cement sheath simulation indicated failure under traction, a possible explanation for the poor
casing-cement bonding across that interval.
• Engineers altered the cement slurry composition to improve cement sheath flexibility.
• In addition, the cement slurry contained an additive to cause slight cement sheath expansion after setting,
thereby improving the bond.
• The operator has successfully applied the revised cementing strategy in wells in the region.
• Mitigating Gas Migration in South Texas An operator producing from the Eagle Ford Shale in South Texas,
encountered difficulties while cementing surface casing.
• The 10 3 / 4-in. surface casing was set inside 80 ft [24 m] of 16-in. conductor pipe.
• The casing string extended vertically from the surface through the conductor pipe and inside a 13 1 /2-in. open
hole to 4,525 ft [1,379 m].
• The operator faced three principal cementing risks: lost circulation, hole washouts and gas migration from
shallow flow zones between 250 and 600 ft [76 and 183 m] measured depth.
• An offset well on the same pad developed gas migration outside the casing and required remedial cement
squeezes and a casing patch to fix the problem.
• The casing patch reduced the inner diameter of the casing to an extent that interfered with further well
development plans.
64. • The operator sought advice from Schlumberger to propose measures to improve cementing results in future
wells. Updated cementing practices were employed to prevent gas migration along the surface casing string.
• Both the lead and tail cement slurry incorporated a gas migration control additive.
• The tail slurry was also designed to set quickly to further minimize the likelihood of gas migration.
• The centralizer program was designed to provide maximum standoff across the shallow gas zones—engineers
installed one centralizer per casing joint to 1,000 ft [305 m].
• Then, at lower depths, where the well was still vertical, every fourth casing joint was fitted with a centralizer.
• To further minimize the risk of gas migration, the operator elected to install an external casing packer (ECP)
within the casing-conductor pipe annulus.
• The cementing operation successfully stopped gas migration; however, after the cement slurry reached the
surface, lost circulation difficulties were encountered, and the TOC fell back into the well before the top plug
reached the bottom of the casing string.
• The WIEs performed the Invizion Evaluation service to investigate these problems as well as verify annular
zonal isolation.
• The overall presentation indicated that the TOC was at 240 ft [73 m].
• Washouts and liquid channels in the cement slurry were also observed.
• To more thoroughly examine the data, the WIEs divided the well into five analysis zones (Figure 4).
• In Zone 1, extending from TD to 4,060 ft [1,237 m], good cement bonding was present despite about 10% mud
contamination.
• In Zone 2, between 4,060 and 2,006 ft [611 m], evidence of mud invasion and lost circulation was apparent;
nevertheless, the interpretation indicated good bonding within the interval (Figure 5).
65. Figure 4. Overview of an Invizion Evaluation service for an Eagle Ford well. Engineers divided
the Invizion Evaluation presentation into five zones (left ). Key observations included that,
although cement slurry had reached the surface during displacement, losses occurred thereafter,
and the top-of-solids depth was 240 ft (Track 13). Liquid channels existed between 240 and 550 ft.
Washouts occurred between 500 and 1,200 ft (Track
66. Figure 5. Invizion Evaluation service interpretation of Zone 4 of an Eagle Ford well. Zone 4 extends from 560 to
1,250 ft. The interpretation results indicate well-bonded casing (Track 3, brown) and some apparent liquid
patches (blue), which are also predicted by the cement placement simulation (Track 8). The gamma ray curve
(Track 1) shows an average value of less than 70 gAPI. The resistivity data (Track 3) do not indicate mud
invasion except at approximately 650 to 750 ft. Caliper values (Track 4) averaged 16.5 in. [42 cm], indicating
washout sections. Casing standoff (Track 6) averaged about 60%. The interpretation results indicate bonded
solids around the casing and some liquid patches (Track 13)
67. • A discrepancy between the predicted and measured location of the interface between the tail slurry and lead
slurry provided evidence that the lead and tail slurries were mixed during displacement.
• In Zone 3, between 2,006 and 1,250 ft [611 and 381 m], mud pockets were observed.
• Log interpretation indicated bonded solids around the casing and the development of liquid channels.
• Similar results were seen in Zone 4 between 1,250 and 560 ft [381 and 171 m] surface, and liquid channels were
observed in the cement sheath (Figure 6).
• The presence of the inflated ECP was evident at 75 ft [23 m].
• The tortuosity of the channels and their position on the wide side of the annulus suggested fluid flow into the
annulus after cement slurry placement.
• The overall analysis indicated that, despite the operational problems, the cementing operation achieved
adequate zonal isolation.
• A possible explanation for the losses and lowered TOC is that during displacement, the pumping pressure may
have initiated ECP inflation, thereby reducing the effective annular size inside the conductor pipe.
• The resulting pumping pressure increase at shallow depths may have caused formation breakdown.
• Furthermore, the formation of channels was a possible result of inadequate casing centralization below 1,000 ft
[305 m].
• Therefore, the recommendation for future offset wells is to eliminate the ECP from the well design and to install
a centralizer on each casing joint.
• Well Planning in the Deepwater Gulf of Mexico An operator developing a deepwater prospect in the Mississippi
Canyon in the Gulf of Mexico encountered difficulties while completing an exploration well drilled in about
4,059 ft [1,237 m] of water.
• Previously, the operator drilled to a depth exceeding 20,000 ft [6,100 m] and cemented a 14-in. casing string
inside a 16-in. liner.
• The length of the overlap between the casing string and the liner was 8,940 ft [2,725 m], and the annular
clearance within the liner lap was 0.425 in. [1.08 cm].
68. Figure 6. Invizion Evaluation service interpretation of an Eagle Ford well, Zone 5. Zone 5 extends from the surface to 560 ft.
The interpretation results indicate the top of solids were at 240 ft (Tracks 11 through 13) and the presence of a post
cementing liquid channel (Track 13, blue). The gamma ray values vary from 33 to 70 gAPI between 250 and 275 ft (Track 1).
Some mud invasion occurred at approximately 500 ft, where the washout area was located. The average neutron porosity is
45%, and the density porosity is 30%. Most of the zone contained washout areas based on the caliper log (Track 4). One
centralizer was installed per joint, resulting in a 65% average standoff. Dynamic cementing pressures remained below the
formation fracture pressure. The cement evaluation log shows the cement top at 240 ft. In the processed solids, liquids and
gas (SLG) map (Track 13), liquid channels occur from the top of solids to 560 ft in the wide side of the annulus. The tortuosity
of the liquid channels suggests that the channels were formed after the cement was placed. An external casing packer is also
evident at 75 ft. An offset well required remedial cement squeezes between 500 and 800 ft. No gas was observed in this region
of the we
69. • The casing string was designed to isolate a zone composed entirely of salt.
• Fluid losses during drilling and cementing indicated the presence of lost circulation zones.
• After the cementing operation, a logging run was performed to locate the TOC (Figure 7).
• Relying mainly on CBL attenuation data and a computed bond index (BI), the logging engineers estimated
the TOC was located at 18,640 ft [5,680 m]—3,960 ft [1,210 m] lower than expected—which meant that the
upper portion of the salt zone was uncemented.
• The operator, who plans to drill a similar offset well in the future, approached Schlumberger to provide an
Invizion Evaluation service on the exploratory well and help formulate strategies to prevent difficulties
that might impede successful zonal isolation in the offset well.
• The operator provided archival data from the earlier well.
• This information—including openhole logging-while- drilling (LWD) data; compositions and physical
properties of the drilling fluid, spacer fluid and cement slurries; and analyses of well fluids that returned to
the surface—was integrated into the Invizion Evaluation presentation.
• Engineers also discovered that, during the previous logging run, significantly more data were actually
acquired but never examined.
• The additional data included flexural attenuation (FA), TIE and a solids, liquids and gas (SLG) map.
• The openhole data revealed the presence of three intervals along the salt zone that were contaminated by
other minerals (Figure 8).
• Engineers had previously assumed that the salt zone was continuous.
• The contaminated intervals were identified as possible sites where lost circulation took place, and their
presence helped explain why the TOC was below the intended depth.
• Equipped with the mud, spacer and cement slurry property data as well as pressure charts acquired
during the cementing operation, the WIEs performed fluid placement simulations.
•
70. Figure 7. Deepwater Gulf of Mexico exploration well log. Engineers relied mainly on the bond index
(BI) data (Track 2) to estimate the TOC. The BI falls significantly at 18,640 ft (red line), and
engineers chose that depth as the TOC. This finding is not as evident in the acoustic impedance
map (Track 1) or the variable density log (Track 3).
71. Figure 8. Openhole LWD measurements from a Gulf of Mexico exploration well. Spikes on the
gamma ray log (Track 1) indicate three zones in which the salt contains inclusions of other minerals.
The contamination is further confirmed by the resistivity (Track 3) and lithology (Track 4) data. The
resistivity increases across the contaminated zones, and the lithology presentation shows inclusions
of foreign material (blue and tan) within the salt (magenta). The three zones were identified as
potential lost circulation sites. Drilling dynamics (Track 2) and well geometry data (Track 5) are also
present
72. • The first simulations confirmed that the pressure charts were consistent with the occurrence of lost circulation
when the float valves were converted on the casing prior to cement job execution.
• In addition, engineers noted that the fluid displacement pressure exceeded the fracture pressure in the
interval.
• The elevated pressure likely resulted from the constricted annular clearance between the liner and the casing
string. The second set of simulations examined the capability of the spacer fluid and cement slurry to displace
the drilling fluid (Figure 9).
• Engineers noted that centralizers had been installed only at the bottom of the casing string.
• Above the centralizers, the casing standoff was poor, and the simulations indicated poor mud removal and a
sizeable channel above about 18,700 ft [5,700 m]—a depth consistent with what had been concluded to be the
top of cement in the earlier interpretation.
• Integration of the additional logging data with the previous findings was revelatory (Figure 10).
• The acoustic impedance map, coupled with the FA and SLG maps, showed the TOC to be much higher than
previously thought—at about 16,000 ft [4,880 m].
• Unfortunately, this depth was still below that required to cover the entire salt interval.
• Furthermore, WIEs confirmed that the cement sheath quality was good in the centralized portions of the
annulus around the casing shoe, and the cement slurry that rose to 16,000 ft had a clear placement channel
consistent with computer simulations performed after the job execution.
• The new information resulting from the Invizion Evaluation service allowed the operator to adjust the
completion plan for the future.
• The operator’s engineers formulated a plan to improve centralization of tubulars in regions above the casing
shoe.
73. Figure 9. Cement placement simulations for an
exploratory well in the Gulf of Mexico. Centralizers were
installed only in the lower part of the casing string. Above
about 19,300 ft [5,880 m], the casing standoff was poor
(Track 1). The displacement simulations (Track 2)
predicted that full cement coverage (gray) rose to a depth
of about 18,700 ft [5,700 m]. Above, the annulus
contained drilling fluid (brown). The mud contamination
risk simulation concurred. Mud contamination (Track 3,
red) began as the casing standoff decreased. Full cement
coverage (Track 3, green) was predicted in the centralized
region.
74. Figure 10. Complete log information retrieved from an exploratory well in the Gulf of Mexico.
Examination of the acoustic impedance map (Track 4), the flexural attenuation map (Track 5) and
the solids, liquids and gas map (Track 7) reveals a sharp interface between a contaminated cement
sheath below about 16,000 ft and spacer fluid at shallower depths.
75. • To reduce friction pressure during pumping and minimize lost circulation, the operator decided to eliminate the
14-in. casing string and extend the 16-in. liner through the salt zone.
• Care will also be taken to ensure that fluid placement pressures remain below formation fracture pressures,
further reducing the probability of lost circulation while allowing the cement slurry to reach the intended depth.
• Expanding the Scope of Holistic Cement Sheath Evaluations Engineers and wellsite personnel have only one
chance to achieve a successful primary cement job for each casing string.
• Remedial cementing to solve problems associated with a faulty cement sheath has a less than stellar success
rate and may even reduce a well’s productivity.
• Improved understanding of primary cementing operations can be gained by examining well histories while
performing comprehensive interpretations of log data.
• Indeed, the added insight provided by the Invizion Evaluation service can further enhance the value of
integrating all available information and allowing operators to make better informed decisions concerning
drilling and cementing practices.
• To date, the Invizion Evaluation service has been aimed at examining current cementing practices and the
objective is to improve them and troubleshoot less than optimal outcomes.
• The longer-term value of the service will be enhanced as engineers and operators become more proactive during
the well cementing process, making real-time cementing decisions that make use of all borehole measurements
and data obtained during drilling.
• For example, the information may be entered into the Techlog platform as it is acquired, facilitating close
collaboration among personnel involved in the drilling and cementing process.
• Ultimately, engineers may apply the Invizion Evaluation service at the planning stage, allowing geologists and
geophysicists to collaborate with the drilling and cementing engineers to further ensure primary cementing
success.
76. Cement Bond Logging Tools-SLB
• Cement bond tools measure the bond between the casing and the cement placed in the annulus between the casing
and the wellbore.
• The measurement is made by using acoustic sonic and ultrasonic tools. In th case of sonic tools, the measurement is
usually displayed on a cement bond log (CBL) in millivolt units, decibel attenuation, or both.
• Reduction of the reading in millivolts or increase of the decibel attenuation is an indication of better- quality bonding
of the cement behind the casing to the casing wall.
• Factors that affect the quality of the cement bonding are
o cement job design and execution as well as effective mud removal
o compressive strength of the cement in place I temperature and pressure changes applied to the casing after
cementing
o epoxy resin applied to the outer wall of the casing.
• SLIM ARRAY SONIC TOOL
• The Slim Array Sonic Tool (SSLT) is a digital sonic tool that provides conventional openhole sonic measurements,
standard CBL amplitude and Variable Density* log (VDL), and attenuation measurements, which are less affected by
borehole environmental conditions.
• The SSLT can also make a short-spacing (1-ft [0.30-m]) CBL measurements for cement evaluation in fast formations.
• The two transmitters and six receivers of the SSLT sonde have transmitter–receiver spacings of 1, 3, 3.5, 4, 4.5, and 5 ft
[0.30, 0.91, 1.07, 1.22, 1.37, and 1.52 m to compute the following:
o standard 3-ft CBL and 5-ft VDL measurements I borehole-compensated (BHC) attenuation from the 3.5- and 4.5-ft
spacing receivers
o near-pseudo attenuation from the 3-ft spacing receivers
o short-spacing attenuation from the 1-ft spacing receiver for cement bond measurement in fast for- mations that
may affect the standard 3-ft spacing.
78. SLIMXTREME SONIC LOGGING TOOL
• The SlimXtreme* Sonic Logging Tool (QSLT) provides the same measurements as the SSLT of the cement bond
amplitude, attenuation, and Variable Density display for evaluation of the cement bond quality of a cemented casing
in high-pressure and high-temperature environments.
CEMENT BOND LOG FROM DIGITAL SONIC LOGGING TOOL
• The Digital Sonic Logging Tool (DSLT) uses the Sonic Logging Sonde (SLS) to measure the cement bond amplitude and
provide a Variable Density display for evaluation of the cement bond quality of a cemented casing string.
• Variable Density or x-y waveform display of the sonic signal is presented in conjunction with the bond index and
amplitude signal.
• The DSLT is also used in the open borehole environment for conventional sonic measurements of BHC (3- to 5-ft)
transit time and long-spacing depth-derived BHC (DDBHC) (9- to 11-ft [2.74 to 3.35-m]) transit time.
CEMENT BOND LOG FROM HOSTILE ENVIRONMENT SONIC LOGGING TOOL
• The Hostile Environment Sonic Logging Tool (HSLT) provide the same measurements of the cement bond amplitude
and Variable Density display for evaluation of the cement bond quality of a cemented casing string as the SSLT in high-
pressure and high-temperature environments.
79. SLIM CEMENT MAPPING TOOL
• The Slim Cement Mapping Tool (SCMT) is a through-tubing cement evaluation tool combinable with the PS Platform* production
logging service for a variety of well diagnostics.
• The two sizes are 111⁄16 in [4.29 cm] for the standard (302 degF [150 degC]) temperature rating and 21⁄16 in [5.24 cm] with a 392
degF [200 degC] temperature rating.
• The SCMT is suitable for running workover operations and in new wells.
• SCMT operations provide a clear advantage in workover wells because there
• is no need to pull tubing above the zone of interest for cement evaluation.
• The SCMT is capable of running through most tubings to evaluate the casing below.
• In new wells the SCMT is an excellent tool for evaluating casing that is 75⁄8 in [19.36 cm] or less.
• The SCMT features a single transmitter, two receivers spaced at 3 and 5 ft from the transmitter, and eight segmented receivers 2 ft [0.61
m] from the transmitter.
• The output of the near (3-ft) receiver is used for CBL and transit-time measurement.
• The output of the far (5-ft) receiver is used for the VDL measurement. The eight segmented receivers generate a radial image of the
cement bond variation.
• MEMORY SLIM CEMENT BOND LOGGING TOOL
• The Memory Slim Cement Bond Logging Tool provides through-tubing 3-ft CBL and 5-ft VDL measurements with the same accuracy
and quality as surface-readout logs.
• Because of its slim size, the 111⁄16-in tool can be run into the zone of interest without having to remove the tubing from the well.
• The tool simultaneously records gamma ray, casing collar location, pressure, temperature, and waveforms in a single pass, with the
waveforms fully digitized downhole.
• More than 40 h of combined tool running time is possible, including 16 h of continuous waveform recording time. Depth-recording
systems are available for both hazardous and nonhazardous environments.
• The Memory Slim CBL Tool can be run with other Memory PS Platform* production logging tools for complete well and reservoir
evaluation in one descent.
• The tools and sensors can be conveyed in the borehole by drillpipe, coiled tubing, slickline, or unintelligent tractor. PS Platform
software is used to perform onsite data processing or any necessary postprocessing and prepare the log presentation.
80.
81. USI ULTRASONIC IMAGER TOOL
• The USI* UltraSonic Imager tool (USIT) uses a single transducer mounted on an Ultrasonic Rotating Sub (USRS)
on the bottom of the tool.
• The transmitter emits ultrasonic pulses between 200 and 700 kHz and measures the received ultrasonic
waveforms reflected from the internal and external casing interfaces.
• The rate of decay of the waveforms received indicates the quality of the cement bond at the cement/casing
interface, and the resonant frequency of the casing provides the casing wall thickness required for pipe
inspection.
• Because the transducer is mounted on the rotating sub, the entire circumference of the casing is scanned.
• This 360° data coverage enables the evaluation of the quality of the cement bond as well as the determination of
the internal and external casing condition.
• The very high angular and vertical resolutions can detect channels as narrow as 1.2 in [3.05 cm].
• Cement bond, thick- ness, internal and external radii, and self-explanatory maps
• are generated in real time at the wellsite.
• APPLICATIONS
• Cement evaluation
• Casing inspection
– Corrosion detection and monitoring
– Detection of internal and external damage or deformation
– Casing thickness analysis for collapse and burst pressure calculations
