法国专利FR3061508A1 ROTARY SPECTRAL DENSITY TOOL FOR EXAMINATION BEHIND PIPES

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专利摘要:
One method includes introducing a string of tools into a wellbore having a material disposed in an annular region surrounding the tubing. Obtaining acoustic refracted waveform measurements of the material from a cement adhesion logging tool, obtaining ultrasonic measurements of the material from a circumferential acoustic scanning tool, obtaining radiation measurements gamma scattered from the material from a circumferential spectral density logging (RSDX) logging tool by emitting gamma radiation from a radioactive source in a rotational portion of the RSDX and detecting scattered gamma radiation using of near and far spectral density detectors, and obtaining thermal neutron radiation measurements scattered from a double-spaced neutron logging tool. A computer obtains measurements and generates a deliverable that includes one or more transverse traces that identify a composition equivalent of the material in a complete circumference of the wellbore.
公开号:FR3061508A1
申请号:FR1761277
申请日:2017-11-28
公开日:2018-07-06
发明作者:Philip Edmund Fox；Fnu Suparman；Gary James Frisch；Michael Jason ENGLAR
申请人:Halliburton Energy Services Inc；
IPC主号:

专利说明:

Agent (s):
Holder (s):
INC ..
HALLIBURTON ENERGY SERVICES,
GEVERS & ORES Public limited company.
® ROTARY SPECTRAL DENSITY TOOL FOR EXAMINATION BEHIND PIPES.
FR 3 061 508 - A1 (57) a method comprises the introduction of a string of tools into a wellbore having a material arranged in an annular region surrounding the casing. Obtaining acoustic refracted waveform measurements of the material from a cement adhesion logging tool, obtaining ultrasonic measurements of the material from a circumferential acoustic scanning tool, obtaining radiation measurements gamma scattered from matter from a logging circumferential spectral density (RSDX) logging tool by emitting gamma radiation from a radioactive source into a rotating part of the RSDX and detecting scattered gamma radiation using near and far spectral density detectors, and obtaining scattered thermal neutron radiation measurements from a double gauge neutron logging tool. A computer obtains measurements and generates a deliverable that includes one or more transverse plots that identify an equivalent material composition in a complete circumference of the wellbore.

i
ROTARY SPECTRAL DENSITY TOOL FOR EXAMINATION BEHIND PIPES
BACKGROUND In the oil and gas sector, after having drilled a well, it is common to pipe the wellbore with one or more columns of pipes called in the "casing" sector, and to fix the casing in the wellbore with cement pumped into the annular space of the wellbore defined between the casing and the wall of the wellbore. In some cases, two or more columns of casing are positioned concentrically in the wellbore and cement is pumped between the casing and the annular space of the wellbore to secure the casing in the wellbore.
A good characterization of the adhesiveness of the cement between the casing and the wellbore, as well as the location and distribution of other categories of background material and their characterization, are essential and particularly critical in the case of capping and abandonment operations. For example, the precise characterization of the materials or substances arranged in the annular space, and the determination of their azimuth and depth distributions through the wellbore can help an operator to determine a preferred location for cutting the casing so that upper parts of the casing can be removed from the wellbore. In particular, determining the azimuth and depth location of particular materials present in the annulus can help determine where the tubing is relatively "free" or offers little resistance to extraction (withdrawal) from the well after have been cut. It is also desirable to estimate the forces required to extract the cut casing when parts of the casing are completely or partially covered by solids and / or gelled materials which increase the friction between the casing and the materials in it. annular space. In addition, it is desirable to estimate the presence of lighter gases and / or fluids which may present a risk or a danger for the operations carried out during intervention interventions on the well and abandonment.
Past methods have included the use of data acquired from cement adhesion logging tools, such as omnidirectional or segmented / segmented logging tools, ultrasonic measurement tools and logging tools. spectral density mounted on buffer. Similar to sectored / segmented cement adhesion logging tools, buffer-mounted spectral density logging tools acquire data only from a sector of the wellbore and do not acquire data from of the entire circumference of the wellbore. In addition, in deviated wells, buffer-mounted spectral density logging tools can only acquire data from the bottom side of the wellbore, as the weighed measurement buffer can become oriented toward down due to gravity. It is therefore difficult to accurately determine the presence of certain substances, such as hardened drilling fluid solids (“mud”), in the annular space of the wellbore and between the casings, and thus differentiate these substances from the cement. present in the annular space of the wellbore and between the casings.
[0004] Sure a period years from the completion initial of well until moment abandonment of wells fluids of drilling left in place in space well annular of drilling deteriorate and rush the
suspended weights, which often accumulate between concentric or overlapping layers of casing. These solids can act as a binder which makes it more difficult to extract the cut tubing above a depth of cut.
[0005] Based on the inherited acoustic and spectral density measurements, the identification of these solids is often partially inaccurate. This is due to the fact that the acoustic sensor readings for such solids do not provide a significant contrast with the adjacent materials present in the annular space of the wellbore at an appropriate level sufficient for identification purposes. This often results in the incorrect determination of the character of the materials in the annular space and, therefore, an error in calculating the optimal or achievable cutting forces required to extract the casing.
BRIEF DESCRIPTION OF THE DRAWINGS The following figures are included to illustrate certain aspects of the present invention, and should not be considered as exclusive embodiments. The object described may be subject to considerable modifications, transformations, combinations and the like in terms of form and function, without departing from the scope of the present invention.
Figure 1 is a schematic diagram of an example of a wellbore logging system which can use the principles of the present invention.
FIG. 2 represents an enlarged view of an exemplary embodiment of the tool chain of FIG. 1.
FIGS. 3A and 3B are schematic side views of an example of embodiments of the circumferential spectral density logging tool and of the double spacing neutron tool, respectively, of FIG. 2.
FIG. 4A is an example of a two-dimensional (2-D) transverse plot representing a density ratio RATDE (window count rate of calibrated density from far to near) and a lithology report RATLI (window count rate of calibrated lithology from far to near) for the responses obtained by a pad-mounted spectral density logging tool.
Figure 4B is a three-dimensional transverse plot (3-D) corresponding to the 2-D transverse plot of Figure 4Ά.
DETAILED DESCRIPTION The described embodiments are intended for downhole tools and methods of using these for improved operations of intervention on wells for the oil and gas sector and, more particularly, to circumferential spectral density logging tools making it possible to characterize the materials arranged in an annular region surrounding a casing located in a wellbore, and thus allowing an improved examination of the integrity of the connection between the tubing and a bonding material filling the annular region to secure the tubing in the wellbore.
spectral [0013] The circumferential logging tools allow a more reliable characterization description of the materials in the density or an annular region by providing complete circumferential coverage around the wellbore using a radioactive source and measurement detectors positioned in a rotary mechanism, unlike legacy unidirectional buffer spectral density logging tools currently used throughout the sector.
The circumferential spectral density logging tools advantageously perform measurements in all directions around the circumference of the wellbore to complete the responses of the associated sensors and develop a circumferential mapping of the entire wellbore.
The measurements obtained from the circumferential spectral density logging tools also allow a phase description distinguishing between solid, liquid, hardened mud (i.e. barite) and gaseous components, if applicable. . The methods described here can prove to be advantageous by allowing a more precise characterization of the annular region and a prediction of the estimated depth of cut from a historically optimized model based on previous diaqraphy measurements and a voltage profiling. modeled applied drilling rig. As will be understood, this can allow a well operator to better plan the operations of the drilling rig and to manage forecast expenditures and activities.
Density measurements from the circumferential spectral density tools are added to the inherited acoustic, ultrasonic and neutronic measurements and to the interpretation of the data to characterize the materials arranged in the annular region.
Based on the material (s) present in the annular region, one can determine the depth to which the casing of the wellbore can be cut for extraction.
In addition, when the latter is used in an open hole environment, the measurement · obtained using the circumferential spectral diaqraphy tools makes it possible to better evaluate the variation of the properties of the rock formation and the elementary distributions in Training. These open hole measurements can be used to quantify the apparent density of the formation in gram / cc units and lithology in barn / electron units. In addition to rotating the detectors, the spacing (i.e. the annular distance) between the radioactive source and the inner wall of the wellbore, the axial separation between the detectors far and near the tool circumferential spectral density logging, and the spacing between the far and near detectors and the inner wall of the wellbore can be adjusted to vary the study depth and acquire additional data about the wellbore. As a result, the identification of training features, such as fractures, defects, druses, tilted beds, and the like, is possible.
As used herein, the term "annular region" or variations thereof refers to an annular space defined between the casing and the wellbore or one or more annular spaces defined between one or more overlapping casings (for example concentric).
Figure 1 is a schematic diagram of an exemplary wellbore logging system 100 which can use the principles of the present invention, according to one or more embodiments. As illustrated, the wellbore logging system 100 may include a surface platform 102 positioned on the earth's surface and a wellbore 104 which extends from the surface platform 102 into one or more underground formations 106. In other embodiments, such as in offshore operations, a volume of water can separate the surface platform 102 and the wellbore 104. The wellbore 104 may include one or more columns of casing 108 (one shown ) and fixed in place with a binder, such as cement. In some embodiments, portions of wellbore 104 may have a single casing 108 fixed therein, but other parts of wellbore 104 may have two or more casing columns 108 or more which overlap each other (e.g. example concentric casings) at least a short distance and are fixed in the borehole 104 via cement filling the annular spaces between the overlapping casing columns 108. The casings 108 may be carbon steel, stainless steel or another material capable of withstanding a variety of forces, such as collapse, bursting, and tensile failure.
A derrick 110 is supported by the surface platform 102 and a wellhead installation 112 is positioned at the top of the wellbore 104. A chain of tools 114 (also called a "probe") can be suspended in the well bore 104 on a means of transport 116 such as, but not limited to, a metal cable, a smooth cable, a power line, a spiral tube, a drill rod, a production conduit, a downhole tractor , or any combination thereof.
The chain of tools 114 may include multiple sensors or analyze the connection integrity between the casing
108 and casing cement 108 to the wellbore
104. In particular, the logging tools may be configured to detect the presence and circumferential distribution of gases, liquids, hardened mud solids, cement, or any combination of the foregoing materials at any depth in the wellbore
104 at the interface between the casing 108 and the cement.
The logging tools 118 may include, but are not limited to, a cement bond logging tool, a circumferential acoustic scanning tool, a circumferential spectral density logging tool, and a double gauge neutron logging tool. Those skilled in the art will readily understand that logging tools be developed to include other known sensors, or those developed in the future with an appropriate application, without departing from the scope of the invention.
The chain of tools 114 may also include a communication module 120 comprising an uplink communication device, a downlink communication device, a data transmitter and a data receiver. The transport means 116 may comprise electrical conductors for supplying the logging tools 118 and communicatingly coupling the logging tools 118 to a logging installation 122 located at a surface location. Alternatively, in other embodiments, the logging tools 118 may be powered via a downhole power source, such as a battery, fuel cells, a downhole power generation mechanism or analogues, included in the string of tools 114. In still other embodiments, an electric cable can be introduced into the well bore 104 to transmit electricity to the logging tools 118. In the illustrated embodiment, the logging facility 122 is shown as a truck, but could alternatively be another type of computing facility commonly used in the art. The logging facility 122 may include a surface communication module 124 and a surface computer 126. The surface communication module 124 may include an uplink communication device, a downlink communication device, a radio transmitter data and a data receiver. The surface computer 126 may include any suitable type of processing logic and may include a log display and one or more recording devices. The surface computer 126 includes processing logic (for example, one or more processors) and has access to software (for example, stored on any suitable computer-readable medium housed in or coupled to the computer 126 ) and / or input interfaces which allow the computer 126 to perform, assisted or not, one or more of the methods and techniques described here. In operation, the logging installation 122 can collect measurements from the logging tools 118 via the communication modules 120, 124, and the surface computer 126 can control, process, store and / or view the measurements collected by the logging tools 118. The computer 126 may include processing logic (for example, one or more processors) configured to execute one or more sequences of instructions or programming code stored on a non-transient computer readable medium. The processor can be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application-specific integrated circuit, a user-programmable pre-broadcast network, a programmable logic network, a controller, a state machine, gate-controlled logic, separate hardware components, an artificial neural network, or any similar suitable entity that can perform calculations or other manipulation of data. Common forms of non-transient computer readable media may include, for example, floppy disks, floppy disks, hard disks, magnetic tapes, other similar magnetic media, CD-ROMs, DVDs, other similar optical media , punched cards, paper tapes and similar physical media with patterned holes, random access memory (RAM), read-only memory (ROM) RAM and semiconductor memory devices (e.g. EPROM, EEPROM, flash memory devices).
In some embodiments, the processing loqique and the storage media can be arranged at the bottom of the hole in the string of tools 114 and can be used either instead of the computer on the surface 126, or in addition of it. In such embodiments, the storage media housed in the tool string 114 can store data (such as that obtained from the logging operations described here), which can be downloaded and processed using the computer on the surface 126 or other appropriate processing logic once the string of tools 114 has been raised to the surface. In certain embodiments, the processing logic housed in the chain of tools 114 can process at least some of the data stored in the storage media inside the chain of tools 114 before the chain of tools 114 be raised to the surface.
[0022] Figure 2 shows an enlarged view of a example of fashion of production of tool chain 114 of the figure 1. As illustrated, the string of tools 114 East
ίο transported on the means of transport 116 in the borehole 104, which penetrates into the surrounding underground formation 106 and comprises the casing 108. An annular region, for example an annular space 202, is defined between the casing 108 and the wall of the wellbore 104 and may be filled with cement 204 and / or other materials which secure or bind the casing 108 in the wellbore 104. Although not explicitly illustrated, multiple columns of casing 108 may be attached to inside the wellbore 104, for example two or more casing columns 108 which overlap each other or are otherwise concentrically positioned.
Along most parts of the wellbore 104, the casing 108 may be suitably linked to the formation 106 by means of cement 204 or other materials which fill the interface between the casing 108 and the formation 106. However, in certain places, the connection between the casing 108 and the cement 204 (or other materials) may be poor or may weaken over time and it is desirable to analyze the material 206 disposed in the annular space 202 to determine whether the connection between the casing 108 and the cement 204 remains intact or not. According to the embodiments described, the logging tools 118 (FIG. 1) included in the chain of tools 114 can be used to determine an equivalent of composition for the material 206 arranged in the annular space 202 and thus to determine axial locations. along the borehole 104 where the casing 108 may or may not be properly bonded to the cement 204 or other materials. Although the embodiments are described with respect to determining the composition equivalent for the material 206 disposed in the annular space 202, the embodiments are not limited to this. The embodiments described also apply to the determination of the composition equivalent for a material arranged in the annular space between overlapping casing columns, without departing from the scope of application.
The invention.
As used here, the term "composition equivalent" refers to a category to which the material
206 may be affected and may include gases, liquids, hardened mud solids (i.e. barite) or cement.
figure 2
206 can
Consequently, even if it is shown separately from the cement 204, in some cases, the material will comprise a part of the cement 204, thus indicating that the connection between the tubing 108 and the cement 204 remains intact.
If however the equivalent of composition of the matter
206 is one of gas, liquids or hardened mud solids, it can be established that the connection between the casing 108 and the cement 204 failed at this location. Likewise, materials other than cement 204 may have accumulated in intervals previously not isolated by cement 204 or in unbound parts of the annular space
202.
This can create linked intervals beyond the originally cemented parts of the well.
the well of [0025] While the string of drilling tools 104, one or more drilling centralizers 104.
The centralizers 208 can, for example, leaf spring centralizers or
114 cross
208 may include, by arc spring, but could also be any other type of device for centering downhole tools.
As mentioned above, the string of tools 114 may include a plurality of logging tools 118 (Figure 1, which may include, but is not limited to, a cement adhesion logging tool 210, a tool acoustic scanning tool 212, and at least two nuclear tools shown as a circumferential spectral density logging tool 214 and a double gauge neutron tool 216.
During operation in the wellbore 104, each of the logging tools 210, 212, 214, 216 can be configured to obtain measurements which make it possible to determine the equivalent of composition for the material 206, whether it be cement 204 or any of the gases, liquids, hardened mud solids, or any combination thereof.
As mentioned above, the logging tools 118 (for example, tools 210, 212, 214, 216) can be developed to include one or more other logging tools comprising sensors (and the corresponding sources) in order to determine the composition equivalent for material 206. These sensors may include, but are not limited to, ultrasonic transducers comprising a single sensor or a network of multiple sensors, spectral gamma ray sensors such as sensors for detecting radioactive tracers, pulsed neutron sensors to perform a circumferential measurement such as inelastic C / O measurements of gadolinium used for the examination of the gravel mass, an epithermal neutron sensor, a rotary gamma density sensor, a tool for advanced acoustic logging with multiple excitation capabilities (monopolar, dipolar, quadrupole, multipolar), or capture gamma ray sensors elementary or the like, without departing from the scope of the invention.
The cement adhesiveness logging tool
210 may include an omnidirectional and sectorized / segmented logging tool configured to provide measurements of acoustic refracted waveform. In some embodiments, the cement adhesion logging tool 210 can function as a transmit-receive transducer. In particular, the cement adhesion logging tool 210 may include a source transmitter 218 and two or more detectors 220a and 220b, which can be arranged in a transmit-receive configuration. In sum, the source transmitter 218 can act as a transmit transducer, and the detectors 220a, b can act as near and far receive transducers spaced at appropriate near and far axial distances from the source transmitter, respectively. 218. In such a configuration, the source transmitter 218 emits sound or ultrasonic waves 222 while the near and far detectors 220a, b receive acoustic refracted waveforms 223 after reflection from the fluid in the wellbore 104 , casing 108, cement 204 (or other annular contents), and formation 106 and record the received waveforms 223 as time domain waveforms. Since the distance between the near and far detectors 220a, b is known, the differences between the refracted waves 223 received at each detector 220a, b provide information about the attenuation that can be correlated with the material 206 in
The annular space 202, and allow a circumferential study depth around the wellbore [0029]
The pairing of the reception transmitting transducer can have different frequencies, spacings and / or angular orientations depending on the environmental effects and / or the design of the tools. For example, if the source transmitter 218 and the detectors 220a and 220b operate in the sound range, spacing between 3 and 15 feet (0.9 and 4.5 meters) may be appropriate. However, if the source transmitter 218 and the detectors 220a and 220b operate in the ultrasonic range, the spacing can be reduced.
In addition to or as an alternative to the transmit-receive configuration of the source transmitter 218 and of the detectors 220a and 220b, the cement adhesion logging tool 210 may also include an ultrasonic pulsed echo transducer. (not expressly shown). The ultrasonic pulsed echo transducer can, for example, operate at a frequency between 80 kHz and 800 kHz. The optimal transducer frequency is a function of size, weight, muddy environment of tubing 108 and other conditions. The ultrasonic pulsed echo transducer transmits waves, receives the same waves after they have been reflected by the casing 108, the materials in the annular space 202 and the formation 106, and records the waves as waveforms. in the domain of time.
The sound wave, ultrasonic pulsed echo and emission-reception waveforms have been used historically to evaluate the annular space 202 concerning the presence of cement 204 (a cement sheath) or the absence thereof. this. The sound waveforms 222 use the amplitude of the first arrival, the attenuation of the refracted waveforms
223 using several near and far detectors 220a, b and a recorded waveform to determine the quantity of cement 204.
Pulsed echo and transmit-receive ultrasonic waveforms are processed using a variety of methods to determine the impedance of materials in annular space 202, and examination of the impedance data can be used to help determine the distribution and equivalent of composition of the material 206 on the circumferential outer surface of the casing 108 in the annular space 202. It will however be understood that the evaluation of the material 206 may not be limited to the methods described above, but may also include other proprietary techniques based on the design and methodology of the tools.
The sound, ultrasonic pulsed echo and standard transmit-receive waveforms can be treated by referring to the peaks and troughs of the waveforms to help characterize the material 206 in the annular space.
Such processing and analysis can be performed using techniques such as
Peak Analysis for
Cernent Evaluation (PACE) and PACE for segmented radial connection tools
The waveforms have a completely different signature when the annular space 202 is filled with a fluid (i.e., a free pipe or tubing
108) or a solid (i.e., cement 204) and variations associated with other materials, such as drilling mud and hardened mud solids. The free pipe signature, for example, usually exhibits higher amplitudes, a low attenuation rate, and a constant waveform response.
When the annular space 202 is filled with a solid material, however, like cement 204, the waveform is reduced, the attenuation of the same waveform is increased and the waveforms are not constants.
PACE and PACERS assess the peaks and valleys of these waveforms using a standard methodology for various acoustic measurement systems with different types of waveforms.
[0033]
Specifically, this new technique uses the peaks and troughs of the waveform for analysis and a derived process is then used to determine the peaks and troughs.
The locations where the derivative changes sign correspond to the peak or trough of this waveform, and the value of the waveform will be called a peak. This provides an automatic process for selecting the positive and negative peaks of the entire waveform. The next step is to take the absolute value of each peak. At this point, it is possible to start to see some general trends in the data for each waveform, and various groupings or sections appear. It is also possible to stack these waveforms to highlight these groupings.
Using the above sequence of steps, various patterns begin to appear from both free and linked sections of wellbore 104. There are at least four distinct areas (regions) or breaks in the shape response wave and can be sorted or studied according to these breaks. Each zone or break can be adjusted or moved depending on the waveform response, casing size, casing weight, cement properties and other environmental conditions of the well.
It is obvious that the first region corresponds to the arrivals of the casing 108, while the fifth region constitutes arrivals derived from the formation 106. The other regions include the area between the casing 108 and the formation 106 (that is, i.e. the annular space 202). The second and fourth regions, for example, appear to be influenced by casing 108 and formation, respectively.
106, and may be analyzed in the future.
The third region may also be influenced by the surrounding regions, but it is unclear by what effect. This grouping of regions may be a function of environmental conditions and tools, but has been recognized by both the standard cement tack log and the radially bonded cement tack log, which operate at different frequencies.
Once the regions are selected, the area under each waveform for each region is determined. The area of the first region is calculated without using the first positive peak. This is due to the fact that the first positive peak is always smaller than the subsequent peaks, and therefore removing this naturally low peak allows for easier comparison with other areas. These areas are then normalized with respect to a 100% free pipe and a color code is created to allow easier viewing. This is somewhat analogous to using the amplitude of the waveforms to determine the bond, but multiple peaks are used instead of using a single cycle.
The circumferential acoustic scanning tool 212 can obtain ultrasonic measurements of the material 206 using a rotary transducer to emit high frequency acoustic pulses which are reflected by the fluid in the wellbore 104, the casing 108, the cement 204 (or other annular contents) and training
106. The transducer detects the reflected pulses, and an associated logging system measures and records the amplitude of the reflected pulse and the bidirectional travel time. This data can be processed to produce detailed visual images of the casing 108, cement 204 (or other annular contents) and beyond. Suitable tools that can be used as a circumferential acoustic scanning tool 212 include, but are not limited to, the range of circumferential acoustic scanning tools (CAST) currently available from Halliburton company based in Houston, Texas
Energy Services, one (eg CAST-I ™,
CAST-V ™, CAST-M ™, CAST-XR ™, FASTCAST ™, etc.
The circumferential spectral density logging tool 214 may include a type of nuclear logging tool.
In some embodiments, as illustrated,
The circumferential spectral density logging tool 214 may include a rotating portion 221 which may include a radioactive source and measurement detectors.
In one example, the rotary part 221 can be a scanning head on which the radioactive source and the measurement detectors are mounted.
The rotating part 221 is centered in the wellbore 104 and therefore in the casing
108, using centralizers
208, and can be pivoted to make measurements in the well bore 104.
However, in other examples, the rotating part
221 can be a stationary housing and the radioactive source and the measurement detectors can be mounted on a rotary assembly included in the rotary part 221.
221 can define a
In such examples, the rotating part or several "windows" to allow the gamma radiation emitted by the radioactive source to exit from the rotating part 221 and the diffused gamma radiation to be detected by the measurement detectors.
The circumferential spectral density logging tool 214 can be configured to adjust the annular distance between the radioactive source and the internal wall of the well bore 104. In addition, the circumferential spectral density logging tool 214 can also be configured to adjust the annular distance between the measuring detectors and the internal wall of the well bore 104, and the axial separation between the measuring detectors. By adjusting the annular distances and the axial separation of the radioactive source and the measuring detectors, the examination depth can be modified to obtain measurements. Although not expressly illustrated, the circumferential spectral density logging tool 214 may include the necessary instruments and electronics (for example, motors, gears, control circuits, etc.) to control the operation of the part rotary 221 and to adjust the annular distances and the axial separation between the radioactive source and the measuring detectors. As will be understood, these radial and axial variations of the positions of the radioactive source and of the measurement detectors adapt to the variation of the state of the wellbore, including, but not limited to, the contents of the well. drilling (sludge, brine, production fluids, etc.), casing sizes, casing material, casing thickness, annular contents between overlapping casing and between casing and wellbore, and the spacing between the multiple concentric casings and the formation.
As a result, the circumferential spectral density logging tool
214 provides multiple study depths that can be rotated to provide complete circumferential coverage of wellbore 104.
3A shows a schematic side view of an exemplary embodiment of the rotary part 221 of the circumferential spectral density logging tool 214 as arranged in the well bore 104. In one example, an objective measurement materials in the annular space 202 can be produced by controlling the annular distance between a radioactive source 304 and the internal wall of the casing 108, by controlling a rotation of the rotary part 221 and by varying the axial separation between the density detectors spectral 306a, b (explained below) contained in the rotating part 221.
The rotary part 221 can contain the radioactive source 304, a near spectral density detector 306a and a far spectral density detector 306b spaced axially from each other inside the rotary part 221 so that the near spectral density detector 306a is placed axially between the radioactive source 304 and the far spectral density detector 306b. Although Figure 3A illustrates the circumferential spectral density logging tool 214 comprising a radioactive source 304 and two detectors 306a, b, more than one radioactive source and more than two detectors can be used, without departing from the scope d application of the invention. Radioactive source 304, which may include cesium-137 (Cs-137), emits gamma 308 rays to the casing
108 (multiple casings
108 can be cement 204 (or other annular contents) and formation
106 to determine the counting rates of near and far detectors in different parts of the measured spectrum and can thus derive the apparent density and the photoelectric absorption of the materials in its path.
Gamma 310 near and far spectral density detectors
306a, b are configured to detect the radiation backscattered from the casing 108, the materials in the annular space 202 (for example, the material 206 in Figure 2), and the formation 106. The near and far spectral density detectors 306a, b can be coupled to a drive mechanism (for example, an electromechanical drive system 302) to axially vary the positions of the near and far spectral density detectors 306a, b relative to each other and / or relative to the radioactive source 304. In addition, the annular distance between the internal wall of the borehole 104 and the near and far spectral density detectors 306a, b can also be modified using the mechanism of drive 302 or another separate drive mechanism (not shown explicitly). Thus, with regard to the axis of the wellbore of FIG. 3A, the near and far spectral density detectors 306a, b can be movable in the axial and radial directions.
The detection of gamma radiation 310 can be done by measuring a photon count rate as a function of energy. As gamma rays 308 travel from radioactive source 304, they are attenuated by structures and materials in their path and reach near and far spectral density detectors 306a, b as gamma radiation 310. The attenuation is a function of the electron densities as well as the photoelectric absorption properties of these structures and materials. Real-time analysis of the energy spectrum of the detected gamma radiation 310 can reveal an apparent density and a photoelectric absorption of the casing 108, of the materials in the annular space 202 (for example, the material 206 of FIG. 2) , and training 106.
The near and far spectral density detectors 306a, b detect the full spectrum of can also be calibrated gamma 310 having energies in can be calibrated for gamma radiation 310, but to detect radiation a predetermined fixed window similar to that of logging tools density. Due to the acquisition of the full spectrum of gamma 310 radiation, advanced spectral processing techniques can be performed to provide a result in a detailed composition assessment of the formation volumes outside of tubagg 108 or, in the case of a casing overlap, wellbore volumes outside the innermost casing. In one embodiment, the circumferential spectral density logging tool 214 can include a plurality of radioactive sources 304 and gamma radiation 310 can be measured with a single spectral density detector 306 or a network of multiple spectral density detectors 306 .
As illustrated, the radioactive source 304 can be located in a cavity 311 defined in the rotary part 221 and a position of the radioactive source 304 in the cavity 311 can be variable. For example, the radioactive source 304 can be moved back and forth (indicated by arrow A) in the cavity 311 using a drive mechanism (not shown). By varying the position of the radioactive source 304, the annular distance between the radioactive source 304 and the inner wall of the wellbore 104 can be changed. In some embodiments, the cavity 311 can function as a collimator to direct the emitted gamma rays 308 in a preferred path. The near and far spectral density detectors 306a, b can each be coupled to the respective collimators 312a and 312b to shrink the detected gamma radiation 310. The collimators 312a, b can be coupled to the respective near and far spectral density detectors 306a, b so that the collimators 312a, b also move when the position of the respective near and far spectral density detectors 306a, b is changed. Each of the collimators 312a, b is an optional component of the circumferential spectral density logging tool 214.
3B shows a schematic side view of an embodiment of the double gauge neutron tool 216 of Figure 2 as disposed in the wellbore 104. The double gauge neutron tool
216 can also achieve an objective measurement of the materials in the annular space 202 by controlling the spacing (that is to say the annular distance) between the face of the double-spacing neutron tool 216 and the internal wall of the casing 108. Like the circumferential spectral density logging tool 214, the double gauge neutron tool
216 may also include a type of nuclear logging tool. As illustrated, the double gauge neutron tool 216 may include a housing 314 which contains a radioactive source 316, a near neutron detector 318a, and a far neutron detector 318b spaced axially from each other within of the housing 314 so that the near neutron detector 318a is interposed axially between the radioactive source 316 and the far neutron detector 318b. In one example, an array of multiple neutron detectors can be used in place of the near neutron detector 318a and the far neutron detector 318b. The radioactive source 316, such as americium-beryllium (AmBe), bombards the casing 108 (several casings can be
present), the cement 204 and all other matters contained in the space annular 202, and the training 106 with of fast neutrons 320. The neutrons fast 320 can is refer to neutrons at bursting from AmBe source with a
energy of 4.6 MeV. Collisions with elements in the path of fast neutrons 320, including hydrogen, reduce the energy of fast neutrons 320 to the thermal level, resulting in thermal neutron radiation 322. The intensity of thermal neutron radiation 322 can be measured by the near and far neutron detectors 318a, b The measurement obtained by the double spacing neutron tool 216 consists of the calibrated ratio of counting rates between the far and near neutron detectors 318a, b (or, the multiple detector network, when used). The counting rate is linked to the hydrogen content in the materials penetrated by the fast neutrons 320, such as the materials 206 (FIG. 2) present in the annular space 202. When hydrogen is associated with a void volume filled with liquid in annular space 202, this ratio can be used to determine porosity, and when combined with other porosity measurements, the porosity of neutrons can be used to detect the presence of formation gases and identify the lithology.
In some embodiments, the radioactive source 316 and the near and far neutron detectors 318a, b (or the array of multiple detectors, when used) may each be coupled to collimators 324 (shown as collimators 324a, 324b and 324c). The first collimator 324a coupled to the radioactive source 316 directs the fast emitted neutrons 320 in a preferred path, and the second and third collimators 324b, c coupled respectively to the near and far neutron detectors 318a, b, shrink the thermal neutron radiation
322 detected.
Each of the collimators 324a-c is an optional component of the double-spacing neutron tool. The methods and analyzes presented here can use response ratios between the numbers of gamma rays obtained from a distant detector and the number gamma rays obtained from the near detector in a desired energy window obtained using the circumferential spectral density logging tool 214 and the double-gauge neutron tool
216. Based on the response reports, transverse plots and continuous presentations of depth-based logs can be generated, and can then be analyzed to determine
The composition equivalent for material 206 (Figure 2).
As described above, the composition equivalents can be classified compositions or substances analogous to material 206 and can include, but are not limited to, gases, liquids, hardened mud solids, or cement 204 If the analysis described here specifies that the material 206 takes the form, for example, of hardened mud solids, this may indicate that the material 206 comprises a drilling fluid weighed down with barite or, alternatively, a drilling fluid weighed down with another weighting agent such as hematite, calcium carbonate, ilmenite, sand, etc. Consequently, the composition equivalent does not positively identify an exact composition of matter 206, but rather identifies matter 206 on the basis of a general type or category of composition, for example as barite or a cement, or based on the phase composition, as being a solid, a liquid or a gas.
Examples of the material 206 which can be classified as an equivalent of a qazous composition can include, but are not limited to, air, natural gas, and the like. Examples of material 206 which can be classified as a liquid composition equivalent may include, but are not limited to, water, brines, emulsion, petroleum, alkane, olefin, aromatic organic compound, a cyclic alkane, a paraffin, a diesel fluid, a mineral oil, a desulfurized hydrogen kerosene, oil-based mud, water-based mud, and the like.
As will be understood, the identification of the equivalent composition of the material 206 can help a well operator to determine a preferred location where the casing 108 could be cut to minimize friction during an operation cutting and shrinking involving tubing 108. Over cement 204, there are generally layers of cement, hardened mud solids, liquids and gases. Consequently, the depth of cut is preferably as close to the top of the cement 204 as possible so that the maximum length of the casing 108 can be recovered while minimizing the frictional forces caused by connections between the casing 108, the cement 204 and other materials disposed behind the casing 108 in the annular space 202. The analyzes and methods described herein to identify the composition equivalent of the material 206 may allow a better estimate of the depth of cut to improve the effectiveness and efficiency of cutting and removal operations.
In certain embodiments, the raw counting rates for the near and far spectral density detectors 306a, b and the near and far neutron detectors 318a, b can be used to identify the composition equivalent of the material 206. However, in other embodiments, the near and far spectral density detectors 306a, b and the near and far neutron detectors 318a, b can be calibrated against a common standard to obtain calibrated count rates. . Since each logging tool is slightly different and each radioactive source has a different strength, uncalibrated tools will result in different readings from each logging tool. In addition, the effectiveness of the detectors may vary from one logging instrument to another.
For example, there are differences in radioactive sources 304, 316 (Figures 3A-3B) used in the circumferential spectral density logging tool 214 (for example
Cs-137) and the double gauge neutron tool 216 (for example, AmBe) as used on different log acquisitions and in individual well locations where these services are performed. However, the calibration of the counting rates of the near and far spectral density detectors 306a, b and of the near and far neutron detectors 318a, b provides a uniform basis for comparison between studies and provides a more uniform light on the environmental conditions of the borehole 104 (FIGS. 2 and 3A-3B) and a characterization of the material 206, including its phase. Calibration of count rates makes all detection rates uniform, although different radioactive sources 304, 316 can be used.
Embodiments of the present invention may use near and far spectral density detector count rates 306a, b calibrated as well as near and b neutral neutron detector count rates and ratios thereof in various forms.
This improvement allows for standardization and equal comparison of all logging tools of a particular design to be compared on a similar basis, and provides consistent results between different generations of logging tools and radioactive source strengths and efficiencies. variable detectors.
Such embodiments differ from prior density measurement methods, which were commonly based on industry standard bulk density (RHOB) based on the raw count rates for near and far spectral density detectors 306a,
Such embodiments also differ from prior neutron measurement methods, which were commonly based on industry standard neutron porosity (NPHI) based on the raw count rates for near and far neutron detectors 318a,
b.
Consequently, the use of calibrated counts can prove to be advantageous in that it generalizes the responses, which do not depend on the tool model or the improvement of similar tools.
The figure
4A is an example of a two-dimensional (2-D) cross-section
400 representing a RATDE density report in comparison with a RATLI lithology report for the responses obtained by a pad-mounted spectral density logging tool. The RATDE density report is a report of the calibrated counts for a density detector
spectral close (NDE) and a distant (FDE) of 1 ¹ tool of Climb on buffer grouped in
detector spectral density logging cluster spectral density by photoelectric response characteristics. The RATLI lithology report is a calibration count report for the near spectral density detector (NLI) and a far spectral density detector (FLI) grouped in clusters by lithological response characteristics. The abscissa of the transverse plot 400 provides the lithology ratio RATLI = FLI / NLI on a scale between 0.0 and 2.0, and the ordinate provides the density ratio RATDE = FDE / NDE also on a scale between 0.0 and 2.0.
The transverse line 400 provides a plurality of density and lithology responses grouped 402 from the near and far spectral density detectors with a desired ratio scaling of far to near counts. The 402 responses can result from buffer-mounted spectral density logging tools measuring the ratio between the atomic weight (Z) and the atomic number (A) obtained from the material present in the wellbore.
A comparison base 404 has been superimposed across the responses 402 and indicates the average Z / A ratio of the responses 402.
The responses 402 have an upper data envelope 406 delimited by a line and a barite response limit 408.
The upper data envelope line 406 is located based on a predetermined standard deviation. Barite response limit 408 is located based on the same predetermined standard deviation value as the upper data envelope line 406. Responses obtained from a majority of typical wellbore fluids may be between the upper data envelope line 406 and the barite response limit 408. Any response that may be below or to the right of the barite response limit
408 can be determined to be obtained from a material comprising barite.
Also illustrated is a solid-liquid phase limit 410 and a liquid-gas phase limit 412. The density and lithology responses 402 located below the solid-liquid phase limit 410 indicate that the responses 402 are obtained from a solid material (for example, cement) 206 in the annular space 202. The density and lithology responses 402 located between the solid-liquid phase limit 410 and the liquid-gas phase limit 412 indicate that 402 responses are obtained from a liquid (for example, heavier liquids such as mud and · water). The density and lithology responses 402 located above (or to the right of) the liquid-gas phase boundary 412 indicate that the responses 402 are obtained from a gaseous material 206 in the annular space 202. As we seen in Figure 4A, there is no indication of the presence of barite or gas in the transverse line 400 because there is no response located to the right of the liquid-gas phase limit 412 (indicating the presence of gas) and below the barite response limit 408 (indicating the presence of barite).
The responses obtained by the near spectral density detector generally come from the region of the wellbore 104 (FIGS. 2 and 3A) dominated by liquids. Consequently, the evaluation methods can use the responses obtained by the near spectral density detector as an indicator of the response of the drilling fluid in the interpretation efforts. Furthermore, the responses obtained by the far spectral density detector can extend more deeply through the casing 108 and the space occupied by the annular space 202, as well as certain effects emanating from the formation 106.
As mentioned above, the measurements made from the spectral density logging tool mounted on existing buffer are acquired only from a sector of the wellbore and the spectral density logging tool mounted on buffer cannot acquire data from the entire circumference of the wellbore. Conversely, the circumferential spectral density logging tool 214 (FIG. 2), according to one or more embodiments described here, can acquire data from the entire circumference of the wellbore. The measurements obtained by the circumferential spectral density logging tool 214 can be identical or analogous to the measurements as acquired by the existing buffer mounted spectral density logging tool. However, since the circumferential spectral density logging tool 214 measures the entire circumference of wellbore 104, measurements taken at a location in wellbore 104 indicate the material composition equivalent 206 ( Figure 2) across the entire circumference of the wellbore 104 at this location and not just in one sector of the wellbore.
In certain embodiments, the response ratios obtained from the double-spacing neutron tool 216 can also be used to help determine and otherwise refine the equivalent composition of the material 206.
In particular, a ratio (RATN) between count rates (FDSN) of calibrated far neutron detectors
318b and the count rates (NDSN) of calibrated near neutron detectors 318a (figure
3B) can be used to determine a relative hydrogen index for the wellbore environment
104.
[0060]
The RATN neutron ratio obtained during the execution of a logging operation in the direction of the bottom of the hole (the chain of tools 114 being directed towards the base of the well) can be represented graphically on the plot 400 according to a scale with a color code / color chart 414. The color or shade of the answers 402 can indicate the hydrogen content of the detected material. Compositions with a higher hydrogen content, for example mud, will have a lower RATN on the scale of the color / shade index 414, while a lower hydrogen content will correspond to a higher RATN on the color / shade index scale 414. Cement and gas, for example, have a low hydrogen index, while drilling mud and brine generally have large amounts of hydrogen. Consequently, there may be a visible correlation between the hydrogen index and the equivalent composition of matter 206 (Figure 2), such as its phase, and the color or shade of the 402 responses may constitute the indicator. visual on plot 400. Consequently, the use of calibrated counts for generalized responses for different tool models may prove advantageous in that it provides more consistent responses.
FIG. 4B is a three-dimensional transverse line (3-D) 450 corresponding to the transverse line 2-D 400 in FIG. 4A. For the sake of clarity of illustration, lines 404, 406, 408 and 412 are not illustrated in Figure 4B. In Figure 4A, since the transverse plot 400 represents the density and lithology responses 402 in 2-D, some of the responses 402 which are not visible (for example, due to an overlap) in the transverse plot 400 may be visible in the 3-D 450 cross-section. For example, the 3-D 450 cross-section may visibly represent the darker color responses 402 (top of the scale 414) indicating a relatively RATN neutron ratio which is characteristic of the presence of solids. The 3-D 450 cross-section represents more clearly the variation of the data from a solid to a pure liquid.
Log analysts using the interpretation and modeling methods described herein may be able to generate and evaluate the results before the string of tools 114 (Figures 1 and 2) is returned to the surface. The methods described herein make it possible to distinguish between cement, barite (and the weighting materials of similar heavy mineral drilling fluid), hardened solids, gases and drilling mud from which there is sometimes a separation of solids. precipitated, that the previous processes based on an acoustic and ultrasonic measurement alone could not identify precisely. The full circumferential measurement obtained using the circumferential spectral density logging tool 214 (Figure 2) is analogous to the measurements provided by the double gauge neutron tool 216 (Figure 2) and the circumferential acoustic scanning tool 212 (Figure 2). Consequently, the measurements obtained by the circumferential spectral density logging tool 214, the double gauge neutron tool 216 and the circumferential acoustic scanning tool 212 are obtained from the entire circumference of the wellbore. 104, and it is therefore relatively easier to interpret these measures. In addition, by varying the axial separation between the near and far spectral density detectors 306a, b, the annular distance between the radioactive source 304 and the internal wall of the casing 108 and the annular distance between the near and far spectral density detectors 306a, b, and the inner wall of casing 108 optimizes density measurements for various logging environments.
In some embodiments, a response product from the examination technique behind pipes (BPET) or "deliverable" can be generated and otherwise derived from the various responses of the logging tools interpreted here. The BPET deliverable, for example, can be calculated and generated using the surface computer 126 (Figure 1) of the logging facility 122 (Figure 1), or with any other computing device or facility with access to the responses of the logging tools. BPET results can be displayed (for example, as two-dimensional or three-dimensional images) on a graphical user interface or any other format capable of displaying or providing the results to be taken into account. In some embodiments, the BPET deliverable may include and graphically display the evaluation results obtained from all or part of the cement adhesion logging tool 210, the circumferential acoustic scanning tool 212, the circumferential spectral density logging tool 214, the double-gauge neutron tool 216 and any other tool (or sensor) included in the tool string 114 (FIG. 2).
In some embodiments, when one or more other types of logging tools (see above) are included in the tool string 114, the BPET deliverable can include and graphically display the evaluation results obtained from all or part of these other logging tools in combination with the examination results obtained from all or part of the cement adhesion logging tool 210, the circumferential acoustic scanning tool 212, the circumferential spectral density logging tool 214 and the double-gauge neutron tool 216. In at least one embodiment, the BPET deliverable may also include a composite logging derived from the measurements obtained from the logging tool of cement adhesiveness 210, the circumferential acoustic scanning tool 212, the circumferential spectral density logging tool 214, the double gauge neutron tool 216, and all other tool (or sensor) included in the tool string 114. Composite logging can collectively indicate the measurements obtained from the logging tools included in the tool string 114, as opposed to a single log which indicates the measurements to from a single logging tool. The BPET deliverable may also include interpretative highlights that identify intervals of interest, historical results and possible current recommendations, such as preferred locations for cutting casing 108 for cutting and processing. withdrawal. In certain embodiments, the BPET deliverable may also include a legend for interpretation and examination providing recommendations and solutions for operating the drilling rig.
The examples described here include:
A. A method which comprises introducing a string of tools into a wellbore comprising at least partially a casing and having a material arranged in an annular region surrounding the casing, in which the strand tools includes a plurality of logging tools including a cement adhesion logging tool, a circumferential acoustic scanning tool, a circumferential spectral density logging tool and a double gauge neutron logging tool; obtaining acoustic refracted waveform measurements of the material using the cement adhesion logging tool; obtaining ultrasonic measurements of the material using the circumferential acoustic scanning tool; obtaining gamma radiation measurements scattered from the material using the circumferential spectral density logging tool, the gamma radiation measurements being obtained by emitting gamma radiation from a first positioned radioactive source in a rotating part of the circumferential spectral density logging tool while rotating the rotating part and detecting the gamma radiation scattered by the material using a near spectral density detector and a density detector far spectral positioned in the rotating part; obtaining measurements of thermal neutron radiation scattered from the material using the double-gauge neutron logging tool having a second radioactive source, a nearby neutron detector and a distant neutron detector; collecting the measurements obtained from the plurality of logging tools with a computer; and generating with the computer a deliverable that includes an equivalent or more cross-sectional composition plots that identify material within a complete circumference of the wellbore.
[0067]
B. A wellbore logging system which includes a string of tools that can extend into a wellbore having at least partially casing and having material disposed in an annular region surrounding the casing, in which the chaplet of tools includes a plurality of logging tools including a cement adhesion diaqraphy tool that obtains acoustic refracted waveform measurements of the material; a circumferential acoustic scanning tool which obtains ultrasonic measurements of the material; a circumferential spectral density logging tool having a rotating part comprising a first radioactive source, a near spectral density detector, and a far spectral density detector positioned therein, in which the circumferential spectral density logging tool obtains gamma radiation measurements by emitting gamma radiation from the first radioactive source while rotating the rotating part and detecting the gamma radiation which is diffused by the material to detectors of near and far spectral density; and a double gauge neutron logging tool having a second radioactive source, a near neutron detector and a far neutron detector, wherein the near and far neutron detectors obtain measurements of thermal neutron radiation scattered from the material; a computer communicatively coupled to the plurality of logging tools and comprising a non-transient computer readable medium capable of being read by a processor and storing instructions which, when executed by the processor, cause the computer obtains the measurements from the plurality of logging tools;
and a computer-generated deliverable comprising one or more transverse plots that identify an equivalent composition of matter in a full circumference of the wellbore.
Each of Examples A and B can count one or more of the following additional elements, according to any combination: Element 1: further comprising the optimization of an axial separation between the near and far spectral density detectors.
Element 2: further comprising optimizing an annular distance between the first radioactive source and an internal wall of the casing. Element 3: further comprising optimizing an annular distance between an inner wall of the casing and one of the near spectral density detector and the far spectral density detector, or both. Element 4: wherein the annular region is an annular space defined between the casing and the wellbore. Element 5: wherein the casing comprises two or more casing columns which overlap each other or are positioned concentrically, and the annular region is an annular space defined between two of the two or more casing columns. Element 6: in which the one or more transverse plots represent: responses based on a count rate density ratio based on a density response as opposed to a count rate lithology report based on a lithology response as well as other parts of measured density spectra and their ratios and a coded hydrogen index scale of responses based on a ratio between the counting rates of the far neutron detector and the near neutron detector.
Element 7 determination of a location to cut the casing according to the equivalent of the composition of the material identified from one or more transverse lines; and performing a cutting and removing operation to remove the casing from the wellbore. Element: further comprising: calibrating count rates of near and far spectral density detectors and near and far neutron detectors against a common standard to obtain calibrated count rates; and using the calibrated count rates to plot responses on the one or more transverse plots. Element 9: wherein the deliverable further includes a composite log derived from the measurements obtained from the cement adhesion log tool, the circumferential acoustic scanning tool, the circumferential spectral density log tool and the double gauge neutron logging tool. Element 10: further comprising the processing of acoustic refracted waveform measurements with reference to the peaks and troughs of the waveforms obtained using the cement adhesiveness logging tool. Element 11: further comprising determining a phase of the material on the basis of the density and lithology ratios as well as the other measured parts of density spectra and their associated ratios.
Element 12: in which the circumferential spectral density logging tool varies near and far.
an axial separation between the spectral density detectors Element: in which the circumferential spectral density logging tool varies an annular distance between the first radioactive source and an internal wall of the casing. Element 14: wherein the circumferential spectral density logging tool varies an annular distance between an inner wall of the casing and one or both of the near spectral density detector and the far spectral density detector. Element 15: in which the one or more transverse plots represent: responses based on a count rate density ratio for near and far spectral density detectors based on a density response as opposed to a rate lithology ratio counting for near and far spectral density detectors based on a lithology response as well as other parts of measured density spectra; and a hydrogen coded response index scale based on a ratio between the counting rates of the far neutron detector and the near neutron detector. Element: wherein the computer is a surface computer disposed at a surface location and the tool string is communicatively coupled to the surface computer via a cable that carries the tool string in the wellbore. Element 17: wherein the composition equivalent of the material includes one of a gas, a liquid, a hardened mud solid and cement. Element 18: wherein the count rates of near and far spectral density detectors and near and far neutron detectors are calibrated against a common standard to obtain calibrated count rates.
Element: in which the deliverable further comprises a composite log derived from the measurements obtained from the cement adhesion log tool,
The circumferential acoustic scanning tool, the circumferential spectral density logging tool and the double spacing neutron tool.
Consequently, the systems and methods described are well suited to achieve the objectives and obtain the advantages mentioned as well as those which are inherent therein. The particular embodiments described above are given for illustration purposes only, insofar as the teachings of the present invention can be modified and practiced in different but equivalent ways, obvious to those skilled in the art who builds on the lessons of the present invention. In addition, no limitation relates to the construction or design details presented herein, other than those described in the claims below. It is therefore obvious that the particular illustrative embodiments described above can be changed, combined or modified and all these variations are considered to be within the scope of the present invention. The systems and methods described herein by way of illustration can be appropriately practiced in the absence of any element which is not specifically described here and / or any optional element described here. While the compositions and methods are described by the terms "comprising", "containing" or "including" various components or steps, the compositions and methods may also consist essentially of "or" consisting of "the various components and steps. All of the numbers and ranges described above may vary to some extent.
Whenever a numerical range with a lower limit and an upper limit is described, any number and any range included in this range is described in a specific way.
In particular, any range of values (in the form, "from about a to about b", or, equivalently, "from about a to b", or, equivalently, "from about ab") described here should be understood as spelling out all the numbers and ranges within the wider range of values.
Likewise, the terms in the claims have their ordinary meaning, to be defined otherwise explicitly and clearly by the patent owner. In addition, the indefinite articles "one" or the claims are defined here as designating one or more of the elements they introduce. In the event of a conflict concerning the uses of a word or term in this description and one or more patents or other documents which may be incorporated here by reference, the definitions in accordance with this description must be adopted.
As used here, the expression "au de" preceding a series of elements, with the terms "and" or "or" to separate one of the elements, modifies the list as a whole, rather than each part of the list
The term "at least one of" has a meaning which includes at least one of any of the elements, and / or at least one of any combination of the elements and / or at least one of each of the elements. For example, the expressions “at least one of A, B and C” or “at least one of A, B or C” each denote only A, B, or only C; any combination of A, B and C; minus one of each of A, B and C.
only and / or at

权利要求:
Claims (15)
[1" id="c-fr-0001]
1. Process, comprising:
introducing a string of tools into a wellbore having at least partially tubing and having a material disposed in an annular region surrounding the tubing, wherein the string of tools includes a plurality of logging tools comprising a cement adhesion logging tool, a circumferential acoustic scanning tool, a circumferential spectral density logging tool and a double gauge neutron logging tool;
obtaining acoustic refracted waveform measurements of the material using the cement adhesion logging tool;
obtaining ultrasonic measurements of the material using the circumferential acoustic scanning tool;
obtaining gamma radiation measurements scattered from the material using the circumferential spectral density logging tool, the gamma radiation measurements being obtained by emitting gamma radiation from a first positioned radioactive source in a rotating part of the circumferential spectral density logging tool while rotating the rotating part and detecting the gamma radiation scattered by the material using a near spectral density detector and a density detector far spectral positioned in the rotating part;
obtaining measurements of thermal neutron radiation scattered from the material using the double-gauge neutron logging tool having a second radioactive source, a nearby neutron detector and a distant neutron detector;
collecting the measurements obtained from the plurality of logging tools with a computer; and generating with the computer a deliverable which comprises one or more transverse plots which identify an equivalent composition of the material in a complete circumference of the wellbore.
[2" id="c-fr-0002]
2. Method according to claim 1, further comprising one or more elements among the optimization of an axial separation between the near and far spectral density detectors, the optimization of an annular distance between the first radioactive source and a wall internal casing, and optimizing an annular distance between an internal wall of the casing and one of the near spectral density detector and the far spectral density detector, or both.
[3" id="c-fr-0003]
3. Method according to claim 1, in which the one or more transverse lines represent:
responses based on a count rate density ratio based on a density response as opposed to a count rate lithology report based on a lithology response as well as other portions of measured density spectra and their ratios; and a hydrogen coded response index scale based on a ratio between the counting rates of the far neutron detector and the near neutron detector.
[4" id="c-fr-0004]
4. Method according to claim 1, further comprising:
determining a location to cut the casing based on the composition equivalent of the material identified from one or more transverse paths; and performing a cutting and removing operation to remove the casing from the wellbore.
[5" id="c-fr-0005]
5. Method according to claim 1, further comprising:
calibrating the count rates of near and far spectral density detectors and near and far neutron detectors against a common standard to obtain calibrated count rates; and using the calibrated count rates to plot responses on the one or more transverse plots.
[6" id="c-fr-0006]
6. The method of claim 1, wherein the deliverable further comprises a composite log derived from the measurements obtained from the cement adhesion log tool, the circumferential acoustic scanning tool, the logging tool circumferential spectral density and the double gauge neutron tool.
[7" id="c-fr-0007]
7. The method of claim 1, further comprising processing the acoustic refracted waveform measurements with reference to the peaks and troughs of the waveforms obtained with the cement adhesiveness logging tool.
[8" id="c-fr-0008]
8. The method of claim 1, further comprising determining a phase of the material based on the density and lithology ratios as well as the other measured portions of density spectra and their associated ratios.
[9" id="c-fr-0009]
9. Wellbore logging system, comprising:
a string of tools that can extend into a wellbore having at least partially tubing and having material disposed in an annular region surrounding the tubing, wherein the string of tools includes a plurality of logging tools comprising :
a cement adhesion logging tool that obtains acoustic refracted waveform measurements of the material;
a circumferential acoustic scanning tool which obtains ultrasonic measurements of the material;
a circumferential spectral density logging tool having a rotating part comprising a first radioactive source, a near spectral density detector, and a far spectral density detector positioned therein, in which the circumferential spectral density logging tool obtains gamma radiation measurements by emitting gamma radiation from the first radioactive source while rotating the rotating portion and detecting the gamma radiation which is diffused by the material using near and far spectral density detectors; and a double gauge neutron logging tool having a second radioactive source, a near neutron detector and a far neutron detector, wherein the near and far neutron detectors obtain measurements of thermal neutron radiation scattered from the material;
a computer communicatively coupled to the plurality of logging tools and comprising a non-transient computer readable medium capable of being read by a processor and storing instructions which, when executed by the processor, cause the computer obtains the measurements from the plurality of logging tools; and a computer-generated deliverable comprising one or more transverse plots that identify an equivalent composition of matter in a full circumference of the wellbore.
[10" id="c-fr-0010]
10. A wellbore logging system according to claim 9, in which the circumferential spectral density logging tool varies one or more elements among an axial separation between the near and far spectral density detectors, an annular distance between the first radioactive source and an inner wall of the tubing, and an annular distance between an inner wall of the tubing and one of the near spectral density detector and the far spectral density detector, or both.
[11" id="c-fr-0011]
11. A wellbore logging system according to claim 9, in which the one or more transverse traces represent:
responses based on a count rate density ratio for near and far spectral density detectors based on a density response as opposed to a count rate lithology report for near and far spectral density detectors based on a density response lithology response as well as other parts of measured density spectra; and a hydrogen coded response index scale based on a ratio between the counting rates of the far neutron detector and the near neutron detector.
[12" id="c-fr-0012]
The wellbore logging system according to claim 9, wherein the computer is a surface computer disposed at a surface location and the string of tools is communicatively coupled to the surface computer by the through a cable that carries the string of tools into the wellbore.
[13" id="c-fr-0013]
13. A wellbore logging system according to claim 9, wherein the material composition equivalent comprises one of a gas, a liquid, a hardened mud solid and cement.
[14" id="c-fr-0014]
The wellbore logging system of claim 9, wherein the count rates of the near and far spectral density detectors and the neutron and far detectors are calibrated against a common standard to obtain calibrated count rates .
[15" id="c-fr-0015]
15. A borehole logging system according to claim 9, in which the deliverable further comprises a composite logging derived from the measurements obtained from the cement adhesion logging tool, the circumferential acoustic scanning tool, the circumferential spectral density logging tool and the double-gauge neutron tool.
1/6

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WO2017040149A1|2017-03-09|Determination of near wellbore properties using natural gamma rays

同族专利:

公开号 | 公开日

GB2570826A|2019-08-07|

US10731455B2|2020-08-04|

GB201906505D0|2019-06-19|

WO2018125114A1|2018-07-05|

US20190383130A1|2019-12-19|

GB2570826B|2021-09-08|

BR112019009732A2|2019-08-13|

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法律状态:
2018-09-28| PLFP| Fee payment|Year of fee payment: 2 |

2019-11-29| PLFP| Fee payment|Year of fee payment: 3 |

2021-04-02| RX| Complete rejection|Effective date: 20210226 |

优先权:

申请号 | 申请日 | 专利标题

PCT/US2016/069099|WO2018125114A1|2016-12-29|2016-12-29|Rotating spectral density tool for behind pipe evaluation|

IBWOUS2016069099|2016-12-29|

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