US20160053608A1 - Identification of Casing Collars While Drilling and Post Drilling Using LWD and Wireline Measurements - Google Patents
Identification of Casing Collars While Drilling and Post Drilling Using LWD and Wireline Measurements Download PDFInfo
- Publication number
- US20160053608A1 US20160053608A1 US14/929,621 US201514929621A US2016053608A1 US 20160053608 A1 US20160053608 A1 US 20160053608A1 US 201514929621 A US201514929621 A US 201514929621A US 2016053608 A1 US2016053608 A1 US 2016053608A1
- Authority
- US
- United States
- Prior art keywords
- casing
- measurements
- well casing
- downhole
- well
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000005259 measurement Methods 0.000 title claims abstract description 92
- 238000005553 drilling Methods 0.000 title claims description 23
- 238000000034 method Methods 0.000 claims abstract description 24
- 239000004568 cement Substances 0.000 claims description 24
- 230000006854 communication Effects 0.000 claims description 21
- 238000004891 communication Methods 0.000 claims description 21
- 230000009471 action Effects 0.000 claims description 5
- 230000005251 gamma ray Effects 0.000 abstract description 6
- 230000015572 biosynthetic process Effects 0.000 description 16
- 238000005755 formation reaction Methods 0.000 description 16
- 230000008859 change Effects 0.000 description 9
- 238000001739 density measurement Methods 0.000 description 9
- 230000005672 electromagnetic field Effects 0.000 description 7
- 230000035699 permeability Effects 0.000 description 6
- 230000004907 flux Effects 0.000 description 5
- 230000033001 locomotion Effects 0.000 description 5
- 239000000463 material Substances 0.000 description 5
- 238000001514 detection method Methods 0.000 description 4
- 238000004804 winding Methods 0.000 description 4
- 230000008878 coupling Effects 0.000 description 3
- 238000010168 coupling process Methods 0.000 description 3
- 238000005859 coupling reaction Methods 0.000 description 3
- 230000006870 function Effects 0.000 description 3
- 229910000831 Steel Inorganic materials 0.000 description 2
- 230000007175 bidirectional communication Effects 0.000 description 2
- 230000002457 bidirectional effect Effects 0.000 description 2
- 230000005540 biological transmission Effects 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 239000002184 metal Substances 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 238000012545 processing Methods 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 238000005070 sampling Methods 0.000 description 2
- 230000035939 shock Effects 0.000 description 2
- 239000010959 steel Substances 0.000 description 2
- 238000005481 NMR spectroscopy Methods 0.000 description 1
- 238000010521 absorption reaction Methods 0.000 description 1
- 230000001133 acceleration Effects 0.000 description 1
- 230000001174 ascending effect Effects 0.000 description 1
- 230000000712 assembly Effects 0.000 description 1
- 238000000429 assembly Methods 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 239000000835 fiber Substances 0.000 description 1
- -1 for example Substances 0.000 description 1
- 238000003384 imaging method Methods 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 238000010348 incorporation Methods 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 230000003287 optical effect Effects 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 230000001902 propagating effect Effects 0.000 description 1
- 230000005855 radiation Effects 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/02—Couplings; joints
- E21B17/08—Casing joints
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
Definitions
- the invention relates to systems and methods for identifying and/or detecting one or more features of a wellbore by utilizing one or more downhole measurements.
- the systems and methods may identify and/or detect one or more features of a well casing by utilizing one or more measurements detectable by a downhole component.
- the one or more measurements may be based on one or more properties associated with the well casing and/or the one or more features of the well casing.
- the one or more measurements may be utilized for indentifying and/or detecting a presence and/or a location of one or more features of the well casing.
- the one or more measurements may exclude electromagnetic measurements and/or may include, for example, sonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like.
- a downhole detector is utilized for detecting one or more features of a well casing in a well by utilizing one or more electromagnetic-fields generated by the downhole detector.
- Certain downhole oilfield applications such as, for example, perforating applications, require the ability to be able to position a downhole tool at a particular known position in the well.
- a wireline tool assembly including one or more instruments is lowered downhole into the well via a wireline such that the wireline tool assembly is positioned at a particular position or depth in the well.
- a depth counter may be used at the Earth's surface to track a length of dispensed cable to approximate the depth of the wireline tool assembly in the well.
- the depth counter may not precisely indicate the depth of the wireline tool assembly in the well because stretching and/or flexing in the downhole wireline may occur due to the weight of the wireline tool assembly.
- other depth determination techniques are necessary to accurately determine the depth of the wireline tool assembly in the well.
- depth determination techniques include use of a depth control log which is utilized to generate a casing collar locator log for identifying and/or detecting locations of features of the well casing, such as, for example, one or more casing collar joints of the well casing.
- the casing collar locator log is, typically, generated by ascending and descending a downhole detector in a well to determine locations and depths of one or casing collar joints of the well casing.
- Casing collar joints are locations in the well casing whereby casing segments are coupled together.
- Each casing collar joint includes a casing collar coupling two adjacent casing segments together.
- the wireline tool assembly may include a casing collar locator.
- the casing collar locator of the wireline tool assembly is moved downhole and/or uphole via the wireline to collect measurements and/or information associated with well casing.
- the casing collar locator may detect and/or identify locations and/or depths of the casing collar joints of the well casing.
- the measurements and/or information detected by the casing collar locator may be used to generate the depth control log.
- a coarse depth that is provided by the depth counter at the Earth's surface is used to locate the corresponding casing collar joint on the depth control log.
- the depth of the wireline tool assembly may be determined because the depth control log precisely illustrates the depth of the detected casing collar joint. From this determination, an error compensation factor may be derived. Then, for example, when a perforating gun is positioned downhole, the error compensation factor is used to compensate the reading of the depth counter to precisely position the gun within the well.
- the casing collar locator is a passive device that utilizes principles of electromagnetic inductance to detect the casing collar joints of the well casing.
- the casing collar locator typically, includes an electrical coil winding through which an electromagnetic flux field is created by one or more permanent magnets passes.
- an electromagnetic flux field is created by one or more permanent magnets passes.
- the change in permeability which is caused by such things as, for example, the presence of the air gap between adjacent well casing segments and the casing collar, causes a change in the electromagnetic flux field to generate or induce a signal across the coil winding.
- This generated or induced signal may be communicated uphole and/or observed at a surface of the well.
- the casing collar locator must be in continual uphole or downhole motion to produce the signal indicating detection of the casing collar joint.
- the quality of the signal may be highly dependent on a degree to which the magnetic permeability changes, or is disturbed. For example, the higher the rate of change in the permeability experienced by the electromagnetic flux field, the higher the induced signal.
- the degree to which the electromagnetic field is disturbed depends on factors such as, for example, distance or gap (hereinafter “stand-off”) between the casing collar locator and the well casing, electromagnetic properties, such as, for example, permeability of the surrounding well casing, and a degree of change in geometry or bulk-mass of the casing, such as, for example, an abrupt and/or drastic change causing a sufficient and/or rapid disturbance in the flux field.
- the resulting signal may be too small to be detected at the surface of the well.
- the signal-to-noise ratio of the signal produced downhole typically places a limit on the degree to which the signal can be boosted, or amplified. As a result, it may be very difficult to detect casing collar joints made from a material having a low magnetic permeability. Likewise, joints having no casing collars are difficult to detect, particularly, if the joints are “flush” and/or without air gaps.
- the conventional casing collar locator may be made up of many different components, such as, for example, two or more permanent magnets, one or more coils, and one or more coil cores, or bobbins.
- the combination of the components of the casing collar locator imparts a large mass to the conventional casing collar locator.
- the resulting large mass of the casing collar locator may cause a significant force to be exerted on the casing collar locator during perforating operations due to high acceleration and/or shock that may affect the resulting large mass.
- the force exerted on the casing collar locator may damage the casing collar locator if measures are not undertaken to properly pack and/or protect the casing collar locator in the well.
- the casing collar locator may extend from six inches to eighteen inches, not including the pressure housing and connections.
- a tool string which may house the casing collar locator may, thus, be long and cumbersome.
- a length of the tool string is very important, particularly, when the tool string is conveyed on a wireline and/or when working with high well pressure. Having a tool string with a long length can present major operational and safety problems with pressure control equipment, such as, for example, a lubricator and/or a riser pipe. Therefore, it is important to conserve every inch in length of a tool string, particularly, in perforating applications.
- Another depth determination technique includes measuring each casing segment at the Earth's surface before the casing segments are coupled together to form the well casing and lowered downhole into the well. By measuring each casing segment at the Earth's surface, a total number of casing segments necessary to insure that formations of interest have casing segments placed or positioned thereon may be determined. A length of each casing segment, typically, lies within a variance of tens of inches of each other. Since each casing segment has a unique length, a unique pattern of casing segment lengths are distributed downhole throughout the well and recorded at the Earth's surface.
- the casing collar of each casing segment refers to a top end and/or a bottom end of each casing segments which have threads thereon for coupling the casing segments together.
- the casing collars of the casing segments have a greater thickness at threads located at the top and bottom ends of each casing segment than the thickness of casing segments between the top and bottom ends of each casing segment.
- the greater thickness at the ends of each casing segment allows locations of the top end, the bottom end, and the length of each casing segment to be identified and/or detected by, for example, a downhole electromagnetic-field based detector lowered downhole into the well.
- a depth and/or location of the detector, casing segments and/or casing collars within the well may be determined.
- the downhole electromagnetic-field based detector may be utilized for measuring and/or determining formation properties, relative positions of the casing collar joints, formation layers, and/or total depth.
- the downhole electromagnetic-field based detector must be lowered into the well using the wireline. And as discussed above, the precise depth of the detector may not be identifiable because the wireline may stretch and/or flex due to the weight of the downhole detector. Thus, other depth determination techniques are necessary in order to accurately determine or identify locations and depths associated downhole detectors, downhole wireline tool assemblies and/or features of the well casing.
- FIG. 1 illustrates a schematic diagram of a drilling system in an embodiment of the present invention and which can be used in practicing embodiments of the method of the present specification.
- FIG. 2 illustrates a schematic diagram of a well casing and a downhole component in an embodiment of the present invention and which can be used in practicing embodiments of the method of the present specification.
- FIG. 3 illustrates a graph for identifying one or more features of a well casing in an embodiment of the present specification.
- FIG. 4 illustrates a graph for identifying one or more features of a well casing via gamma-gamma density measurements in an embodiment of the present specification.
- FIG. 5 illustrates a graph for identifying one or more features of a well casing via photoelectric type nuclear measurements in an embodiment of the present specification.
- FIG. 6 illustrates a graph for identifying one or more features of a well casing via photoelectric type nuclear measurements obtained by a downhole tool in an embodiment of the present specification.
- FIG. 7 illustrates a graph for identifying one or more features of a well casing via density measurements obtained by a downhole tool in an embodiment of the present specification.
- FIG. 8 illustrates a graph includes sonic Slowness Time Coherence (hereinafter “STC”) projections and Variable Density Log (hereinafter “VDL”) waveforms for identifying one or more features of a well casing in an embodiment of the present specification.
- STC Slowness Time Coherence
- VDL Variable Density Log
- FIG. 9 illustrates a graph including real time mud pulse transmissions of sonic STC projections and slowness for identifying one or more features of a well casing in an embodiment of the present specification.
- FIG. 10A illustrates a graph including sonic receiver waveforms for identifying one or more features of a well casing in an embodiment of the present specification.
- FIG. 10B illustrates a graph including sonic receiver waveforms for identifying one or more features of a well casing in an embodiment of the present specification.
- the invention relates to systems and methods for identifying and/or detecting a feature of well casing by utilizing a downhole measurement associated with a well casing or formations or cement located adjacent to the well casing.
- the systems and methods may identify and/or detect features of the well casing by utilizing measurements of the one or more properties associated with the well casing detectable by a downhole component.
- the well casing may be made of steel and may be positioned within a portion of the well during or after drilling of the well.
- the one or more features of the well casing identifiable and/or detectable may include, for example, casing collars, casing collar joints and/or cement adjacent to the well casing.
- the one or more measurements utilized to identify and/or detect the one or more features of the well casing may be detectable by the downhole component which may include a logging-while-drilling (hereinafter “LWD”) tool and/or a wireline configurable tool.
- LWD logging-while-drilling
- the one or more measurements for indentifying and/or detecting the features of the well casing may include, for example, sonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like.
- the one or more measurements for identifying and/or detecting the features of the well casing may not include or may exclude electromagnetic measurements.
- FIG. 1 schematically depicts a drilling system 10 , which may be on-shore or off-shore, in which the present systems and methods for identifying and/or detecting one or more features of a well casing may be implemented.
- the drilling system 10 may be an on-shore drilling system 10 with a drill string 12 comprising a string of drill pipe 13 .
- a surface pumping system (not shown in the drawings) may deliver mud flow 16 to the central passageway of the drill pipe 13 , and the mud flow 16 may propagate downhole through the drill pipe 13 .
- the mud flow 16 may exit the drill pipe 13 at nozzles (not shown in the drawings) and may return uphole to the surface pumping system via an annulus 18 of the well.
- the circulating mud flow 16 may actuate a downhole mud motor 20 that may, in turn, rotate a drill bit 22 of the drill pipe 13 .
- Embodiments of the present invention may be utilized with vertical, horizontal and/or directional drilling.
- the drilling system 10 of FIG. 1 may depict a particular stage of the well during its drilling, post drilling and/or completion.
- upper segments 24 of the wellbore 14 may be formed through the operation of the drill pipe 13 and may be lined with and supported by a well casing 26 that has been installed in the upper segments 24 .
- the well casing 26 may be made of material, such as, for example, steel and/or the like. It should be understood that the well casing 26 may be made from any material as known to one of ordinary skill in the art.
- the wellbore 14 may extend below the upper segments 24 into a lower, uncased segment 28 .
- drilling operations may be interlaced with installation operations of the well casing 26 .
- the drill pipe 13 may alternatively be used as part of the well completion. In this manner, called “casing drilling,” the drill pipe 13 may be constructed to line and support the wellbore 14 so that at the conclusion of the drilling operation, the drill pipe 13 may be left in the well to perform the traditional function of a well casing 26 .
- the drilling operation and/or the downhole formations through which the wellbore 14 extends may be monitored at the surface of the well via measurements that are acquired downhole.
- the drill pipe 13 may have a wired drill pipe infrastructure 30 (hereinafter “WDP 30 ”) for purposes of establishing one or more communication link(s) between the surface of the well and a downhole components 36 may acquire measurements and/or may be part of a bottom hole assembly 32 (hereinafter “BHA 32 ”) of the drill pipe 13 .
- WDP 30 may provide a cable within each drill pipe 13 that is communicatively coupled at each pipe joint.
- Communication through the WDP 30 may be bidirectional, in that the communication may be from the surface of the well to the BHA 32 and/or from the BHA 32 to the surface of the well.
- WDP 30 many variations and uses of the WDP 30 are contemplated and are within the scope of the present invention. Examples include U.S. Pat. Nos. 6,641,434 (Boyle et al.), U.S. Pat. No. 6,866,306 (Boyle et al.) and U.S. Pat. No. 7,413,021 (Madhara et al.) each assigned to the assignee of the present application and hereby incorporation by reference in their entire.
- the WDP 30 may include one or more communication line segments 34 embedded in a housing of the drill pipe 13 .
- the one or more communication line segments 34 may be, for example, fiber optic line segments, a coaxial cable, electrical cable segments, or another device for transferring data. It should be understood that the communication line segments 34 may be any communication line segments as known to one of ordinary skill in the art. The present invention should not be deemed as limited to a specific number of downhole components incorporated within the WDP 30 of the drilling system 10 .
- the WDP 30 may contain multiple communication lines that extend between the surface of the well and the BHA 32 , with each communication line being formed from serially connected communication line segments 34 , the downhole component 36 and/or communication connectors within the WDP joints 44 .
- the drill pipe 13 may include the one or more downhole components 36 which may be a downhole tool comprising a telemetry module.
- Communication signals may be received by the telemetry module at the BHA 32 from a surface controller 48 via the bidirectional communication provided by the telemetry module.
- the communication signals received from the surface controller 48 may control processes such as directional drilling and/or functions or operations of the one or more downhole components 36 associated with the drill pipe 13 .
- the communication signals from the surface controller 48 may be transmitted downhole to the one or more downhole components.
- the bidirectional communication may improve measurement and control, during drilling (and pausing and tripping) processes, to achieve improved operation and decision making.
- the telemetry module of the one or more downhole components 36 may communicate with the surface controller 48 via mud pulse telemetry, acoustic telemetry, electromagnetic telemetry and/or real time bidirectional drill string telemetry. It should be understood that the type of telemetry utilized by the telemetry module of the one or more downhole components 36 may be any type of telemetry capable of communicating with the surface controller 48 as known to one of ordinary skill in the art.
- the one or more downhole components 36 of the drill pipe 13 may communicate with the surface controller 48 via communication signals that may be communicated over the WDP 30 and/or telemetry module of the one or more downhole components 36 .
- the one or more downhole components 36 may receive one or more signals, such as, for example, control and/or data signals from the WDP 30 via the communication line segments 34 .
- the one or more downhole components 36 may transmit one or more signals uphole to the surface controller 48 via the WDP 30 or the telemetry module.
- the drill pipe 13 may include various other features, such as, for example, a drill collar, an under-reamer and/or the like, as the depiction of the drill pipe 13 in FIG.
- the BHA 32 may include any number of downhole components 36 and/or other features as known to one of ordinary skill in the art.
- the one or more downhole components 36 may be housed in a drill collar, as is known in the art, and may contain one or more known types of telemetry, survey or measurement tools, such as, for example, one or more LWD tools, one or more measuring-while-drilling tools (hereinafter “MWD tools”), one or more near-bit tools, one or more on-bit tools, and/or one or more wireline configurable tools.
- LWD tools one or more measuring-while-drilling tools
- near-bit tools one or more near-bit tools
- on-bit tools one or more on-bit tools
- wireline configurable tools such as, for example, one or more wireline configurable tools.
- the LWD tools of the one or more downhole components 36 may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment.
- the LWD tools may indentify, detect and/or measure one or more properties associated with the formation 15 , the drill string 12 , the well casing 26 and/or the features of the well casing 26 .
- the one or more LWD tools may include one or more of the following types of logging and/or measuring devices: a resistivity measuring device; a directional resistivity measuring device; a sonic measuring device; a nuclear measuring device; a nuclear magnetic resonance measuring device; a pressure measuring device; a seismic measuring device; an imaging device; a formation sampling device; a gamma ray measuring device; a density and photoelectric measuring device; a neutron porosity device; a bit resistivity measuring device, a ring resistivity measuring device, a button resistivity measuring device and/or a borehole caliper device.
- the LWD tool may include, for example, a compensated density neutron tool, an azimuthal density neutron tool, a resistivity-at-the-bit tool, hookload sensor and/or a heave motion sensor.
- the one or more downhole components 36 may be any type of LWD tool as known to one or ordinary skill in the skill.
- the MWD tools of the one or more downhole components 36 may include one or more devices for measuring characteristics associated with the drill bit 22 and/or the drill string 12 .
- the one or more MWD tools may include one or more of the following types of measuring devices: a weight-on-bit measuring device; a torque measuring device; a vibration measuring device; a shock measuring device; a stick slip measuring device; a direction measuring device; an inclination measuring device; a gamma ray measuring device; a directional survey device; a tool face device; a borehole pressure measuring device; and/or a temperature device.
- the one or more MWD tools may detect, collect and/or log data and/or information about the conditions at the drill bit 22 , around the formation 15 , at a front of the drill string 12 and/or at a distance around the drill strings 12 .
- the one or more MWD tools may provide telemetry for operating rotary steering tools.
- the one or more downhole components 36 may be any type of MWD tool as known to one of ordinary skill in the art.
- the wireline configurable tools of the one or more downhole components 36 may be a tool commonly conveyed by wireline cable as known to one having ordinary skill in the art.
- the wireline configurable tools may form a wireline tool string which may include multiple separate tools which may perform multiple operations at the same time or at different times.
- the wireline configurable tool may be a logging tool for sampling, detecting and/or measuring properties associated with the formation 15 , the drill string 12 , the well casing 26 and/or features of the well casing 26 .
- the wireline configurable tools may be one or more open hole electric line tool which may identify and/or detect one or more measurements, such as, for example, gamma radiation measurements, nuclear measurements, density measurements, neutron measurements, resistivity measurements, sonic measurements, ultrasonic measurements, magnetic resonance measurements, seismic measurements and/or porosity measurements.
- wireline configurable tools may be one or more cased hole electric line tools, such as, for example, a sonic tool, an ultrasonic tool, an azimuthal density neutron tool, a cement bond tool, a casing collar locator, a gamma perforating tool, a well completion tool and/or a setting tool.
- the one or more downhole components 36 may be any type of wireline configurable tool as known to one of ordinary skill in the art.
- the one or more downhole components 36 may comprise, include or incorporate a BHA power source, such as, for example, the downhole mud motor 20 or any other power generating source as known to one of ordinary skill in the art.
- the BHA power source may produce and generate electrical power or electrical energy to be distributed throughout the BHA 32 and/or to power the one or more downhole components 36 .
- the downhole component 36 such as, for example, a LWD tool or a wireline configurable tool may be used to locate one or more features of the well casing 26 surrounding and/or adjacent to the downhole component 36 .
- the well casing 26 and/or the one or more features of the well casing 26 may include, for example, a valve, a casing collar joint or other tubular structure which may have one or more properties measurable and/or detectable by the downhole component 36 .
- the well casing 26 may have a passageway for receiving the downhole component 36 .
- the one or more properties associated with and/or related to the well casing 26 and/or the one or more features of the well casing 26 may include, for example, physical properties, mechanical properties, electrical properties, thermal properties, chemical properties, magnetic properties, optical properties, acoustical properties, radiological properties and/or atomic properties. It should be understood that the one or more properties associated with the well casing 26 and/or the one or more features of the well casing 26 may be any type of properties measurable and/or detectable by the downhole component 36 and known to one of ordinary skill in the art.
- the downhole component 36 may pass through a central passageway 100 of the well casing 26 along an axis 102 within the well casing 26 for purposes of identifying and/or detecting the one or more features of the well casing 26 , such as a casing collar joint 104 by measuring and/or detecting the one or more properties of the well casing 26 and/or the casing collar joint 104 .
- the downhole component 36 may or may not need to move along the axis 102 to measure and/or detect the properties of the well casing 26 and/or the casing collar joint 104 .
- the downhole component 36 may measure and/or detect the one or more properties associated with the casing collar joint 104 and may transmit a signal to indicate and/or identify that the feature and/or the casing collar joint 104 of the well casing may be near and/or adjacent to the downhole component 36 .
- the downhole component 36 may be used to detect and/or identify one or more features of the well casing 26 .
- the properties associated with the well casing 26 , the features of the well casing 26 and/or the casing collar joint 104 may be detectable and/or identifiable by measurements detectable and/or measurable by the downhole component 36 .
- the measurements for detecting and/or identifying the one or more properties of the well casing 26 detectable and/or measureable by the downhole component 36 may include, for example, sonic measurements, ultrasonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like.
- the measurements for detecting and/or identifying the one or more properties of the well casing 26 may not include or may exclude electromagnetic measurements.
- the measurements of the one or more properties of the well casing 26 that may be detectable and/or measurable by the downhole component 36 may be affected differently by the properties associated with the features and/or the casing collar joint 104 of the well casing 26 .
- the downhole component 36 may identify and/or determine when the one or more of the features of the well casing 26 , such as, for example, the casing collar joint 104 may be present and in proximity and/or adjacent to the downhole component 36 .
- the casing collar joint 104 that is depicted in FIG. 2 may be formed from a union or coupling of well casing segments 106 a and 106 b which may be attached, connected and/or coupled together by a casing collar 108 .
- a lower tapered end 110 of the upper casing segment 106 a may extend into an upper portion of the casing collar 108
- an upper tapered end 112 of the lower casing segment 106 b may extend into a lower portion of the casing collar 108 .
- the lower tapered end 110 and the upper tapered end 112 may not meet and/or abut each other inside the casing collar 108 , but rather, an air gap 114 may exist between the ends 110 , 112 .
- the combination of the air gap 114 and the casing collar 108 may create and/or result in substantially different measurements of properties detectable and/or measurable by the downhole component 36 , when the downhole component 36 may be near or adjacent to the casing collar joint 104 , than measurements of properties detectable and/or measurable when the downhole component 36 may be near a portion of the well casing 26 without the casing collar joint 104 .
- the measurements of the properties detected and/or measured by the downhole component 36 may provide an identification and/or a location of the features of the well casing 26 , such as, for example, the casing collar joint 104 . Because the measurements may be different when the downhole component 36 may be near or adjacent to the casing collar joint 104 than when the downhole component 36 may not be near the casing collar joint 104 and near, for example, a straight section of the well casing 26 . As a result, a presence and/or a location of the casing collar joint 104 may be identified and/or detected by comparing the different measurements, detected and/or measured by the downhole component 36 .
- the downhole component 36 may be compared to a conventional casing collar locator that relies on a change in the sensed magnetic field to induce a signal on a winding for purposes of indicating detection of a casing collar joint.
- the conventional casing collar locator does not generate a signal if the locator is not moving.
- the downhole component 36 may measure and/or detect the measurements of the properties associated with the well casing 26 , the features of the well casing 26 and/or the casing collar joint 104 , regardless of whether the downhole component 36 may be stationary or moving with respect to the well casing 26 .
- the differences in the measurements obtained and/or measured by the downhole component 36 may be used to determine if one or more of the features of the well casing 26 , such as, for example, the casing collar joints 104 may be identified and/or detected.
- identification of the one or more casing collar joints 104 may be utilized to determine a measured depth based on and/or corresponding to the location of the one or more casing collar joints 104 .
- the determined measured depth may be used to a downhole location for performing and/or executing a downhole action.
- the downhole action may include, for example, positioning a whipstock, side tracking a well and/or positioning a perforation tool. After the measured depth may be determined based on the locations of one or more casing collar joints 104 , the downhole action may be performed and/or executed at the downhole location based on the measured depth.
- the changes, differences or disturbances between the measured and/or detected properties may be caused by, for example, changes in the geometry of the well casing 26 ; gaps in the well casing 26 , such as, for example, the air gap 114 ; anomalies in the well casing 26 , such as, for example, heavy pitting, cracks, or holes such as perforations; sudden changes in distance or stand-off between the downhole component 36 and the well casing 26 ; other changes in one or more properties associated with the well casing 26 ; and/or changes in the bulk-mass of the well casing 26 .
- the downhole component 36 which may be a LWD tool which may be included in the drill string 12 or a wireline configurable tool may include a tubular housing (not shown in the drawings) having a longitudinal axis.
- the longitudinal axis may be generally aligned with the axis 102 of the well casing 26 when the downhole component 36 may be located inside the well casing 26 .
- the housing of the downhole component 36 may protect and provide sealed containment for sensors (not shown in the drawings) and/or circuitry (not shown in the drawings) of the downhole component 36 .
- the housing of the downhole component 36 may be connected to a wireline cable (not shown in the drawings) that may extend to the Earth's surface to position the downhole component 36 , to communicate signals, in real time, from the downhole component 36 to the Earth's surface and the surface controller 48 and/or to provide electrical power to the downhole component 36 .
- the downhole component 36 may output and/or transmit one or more signals to the surface controller 48 that may be processed by the surface controller 48 for identifying the presence and/or location of the one or more features of the well casing 26 , such as, for example, the casing collar joint 104 .
- the downhole component 36 may identify and/or determine the presence and/or the location of the casing collar joint 104 and/or other features of the well casing 26 based on the signals received from the downhole component 36 .
- the downhole component 36 may communicate the one or more signals, in real time, identifying the one or more features and/or the casing collar joint 104 to the Earth's surface via one or more communication line segments 34 of the WDP 30 or the telemetry module of the one or more downhole components 36 .
- the downhole component 36 may establish communication with the wireline cable that extends to the Earth's surface.
- the downhole component 36 may communicate to the surface a direct indication of the properties associated with the one or more features or the casing collar joint 104 of the well casing 26 or, alternatively, may communicate an indication of the actual feature(s) and/or the casing collar joint 104 detected.
- the downhole component 36 may be a LWD sonic tool which may utilize sonic waves to measure and/or detect one or more properties associated with the casing collar joint 104 , such as sonic absorption.
- the downhole component 36 may transmit sound waves towards the casing collar joint 104 and/or the well casing 26 and may have a receiver (not shown in the drawings) which may receive the sonic waves reflected from the casing collar joint 104 and/or the well casing 26 .
- graph 200 illustrates amplitudes for sound waves or waveforms received by the downhole component 36 and processed by the downhole component 36 and/or the surface controller 48 .
- the amplitudes of the detected sound waves or waveforms may change when the casing collar joint 104 is near or adjacent to the downhole component 36 .
- the amplitude of the detected sound waves or waveforms may momentarily increase to one or more spikes 202 when the downhole component 36 is in the presence of and/or is adjacent to the casing collar joint 104 as shown in track 204 of FIG. 3 .
- the downhole component 36 and/or the surface controller 48 may identify the presence and/or the location of one or more casing collar joint 104 based on the measurements and/or spikes 202 detected and obtained by the downhole component 36 when the downhole component 36 may be near or adjacent to the casing collar joint 104 .
- the downhole component 36 may be adapted to measure and/or detect, for example, gamma-gamma and photoelectric type nuclear density measurements to identify and/or detect the presence and/or the location of one or more casing collar joints 104 as shown in graphs 300 and 400 of FIGS. 4 and 5 , respectively.
- the measured and detected gamma-gamma and photoelectric type nuclear density measurements may momentarily increase to larger values or upward spikes 202 at regular intervals which identify the presence and/or the location of the one or more casing collar joints 104 .
- the upward spikes may represent or correspond to detection of a higher density in FIG. 4 and a higher photoelectric value in FIG. 5 .
- the downhole component 36 and/or the surface controller 48 may utilize one or more processing algorithms to analyze the measurements detected by the downhole component 36 and to identify the one or more casing collar joints 104 .
- the identification of the one or more casing collar joints may be enhanced by insuring that the source and detectors of the downhole component 36 for the gamma-gamma and photoelectric type nuclear density measurements may be pressed up against the well casing 26 by, for example, a backup arm (not shown in the drawings).
- Other variations in the measurements may be unrelated to the casing collar joints 104 but may also be identified from the gamma-gamma and photoelectric type nuclear density measurements.
- the other variations or may be associated with the formation 15 or changes in a position of the well casing 26 with respect to the formation 15 .
- FIG. 6 illustrates a graph 500 for photoelectric type nuclear measurements detected by the downhole component 36 and processed by the downhole component 36 and/or the surface controller 48 .
- Graph 500 in FIG. 6 may represent or correspond to scintillation detector count rates that may be utilized primarily in computation of bulk density and/or secondary in determination of gamma gamma density.
- the plotted count rates in each column of FIG. 6 may represent specific energy ranges obtained from a short spaced detector. These energy ranges may be associated with photoelectric measurements.
- Each column of FIG. 6 may represent a different pass over the same interval with varying speeds and/or varying directions.
- FIG. 7 illustrates a graph 600 for gamma-gamma density measurements detected by the downhole component 36 and processed by the downhole component 36 and/or the surface controller 48 .
- the downhole component 36 may be a LWD azimuthal density neutron (hereinafter “ADN” tool).
- ADN LWD azimuthal density neutron
- Graph 600 may represent or correspond to detector count rates that may be utilized in computation of photoelectric values and/or determination of gamma gamma density.
- the measured and detected density photoelectric measurements may momentarily increase to larger values or spikes 202 at regular intervals.
- the spikes 202 may identify the presence and/or the location of the one or more casing collar joints 104 .
- the spikes 202 may be a result of variations of metal density at the casing collar joints 104 when compared to the metal density at the well casing 26 without the casing collar joints 104 .
- the measurements detected and/or measured by the downhole component 36 may allow for real time identification of the one or more casing collar joints 104 of the well casing 26 .
- the downhole component 36 may move uphole and/or downhole at a velocity to detect and/or measure the properties along a portion of or an entire length of the well casing 26 .
- the velocity of movement by the downhole component 36 may be, for example, about thirty (30) meters per hour, about forty (40) meters per hour or about fifty (50) meters per hour and/or the like.
- data density measurements of at least 6 data points may be obtained and/or measured for every meter that may be logged by the downhole component 36 .
- the present disclosure should not be deem limited to a specific velocity of movement for the downhole component 36 .
- FIGS. 8 and 9 illustrate graphs 700 and 800 , respectively, for measurements relating to one or more properties, such as acoustical properties associated with the features and/or the one or more casing collar joints 104 which may be detected and/or measured by the downhole component 36 .
- the data and/or measurements may be stored in a memory (not shown in the drawings) of the downhole component 36 or, alternatively, may be transmitted, in real time, uphole to surface controller 48 .
- the measurements may be processed by the downhole component 36 and/or the surface controller 48 to identify the presence and/or the location of the one or more casing collar joints 104 in real time or at a different time.
- FIG. 8 Graph 700 of FIG. 8 identifies the one or more casing collar joints 104 based on sonic STC projections and normal waveform VDL.
- FIG. 8 may include more than one track, such as, for example four tracks.
- a first track 702 may represent a depth;
- a second track 704 may represent a coherence amplitude;
- a third track 706 may represent a STC plane; and
- a fourth track 708 may represent a normal waveform VDL.
- the one or more casing collar joints 104 may be identified and/or detected by a lack of coherence in the STC plane.
- the normal waveform VDL may show a scattering of the waveform as the downhole component 36 may be positioned near and/or adjacent to the one or more casing collar joints 104 .
- the one or more casing collar joints 104 may be located near or about the middle of the scattering of the waveform in the normal waveform VDL.
- FIG. 9 illustrates real time mud pulse transmission measurements of sonic STC projections and slowness used for identification of the one or more casing collar joints 104 .
- the measurements may be processed by the downhole component 36 and/or the surface controller 48 .
- FIG. 9 shows real time measurements illustrate a loss of coherence in the STC plane (as shown in the track located on the right side of graph 800 ) which may result in a momentarily increase to larger values or horizontal spikes in the computation of the compressional slowness to identify the one or more casing collar joints 104 .
- the horizontal spikes in FIG. 9 may represent one or more casing collar joints 104 as identified by horizontal arrows 802 at various depths.
- the whipstock may be placed between the one or more casing collar joints 104 such that a window (not shown in the drawings) may be milled into the side of the well casing 26 between the one or more casing collar joints 104 .
- a window not shown in the drawings
- the inclusion of the whipstock may not be successful because material(s) of the one or more casing collar joints 104 may be harder and thicker than material(s) of the well casing 26 without the casing collar joints 104 .
- the possibility of parting the well casing 26 to form the window for inclusion of the whipstock may be greatly reduced or may be incapable of being achieved.
- Graphs 900 and 910 of FIG. 10A and Graph 920 of FIG. 10B illustrate sonic receiver measurements for identifying and/or determining a location of an upper top end 902 of cement 116 (as shown FIG. 2 ) and a degree of cement bond quality.
- the cement 116 may be injected through the wellbore 14 and may rise up the annulus 18 between the well casing 26 and the formation 15 .
- the cement bond quality refers to a quality of a bond between the well casing 26 and the cement 116 placed in the annulus 18 between the well casing 26 and the wellbore 14 and/or a bond between the cement 116 and the formation 15 .
- Graph 900 of FIG. 10A shows a wireline cement bond log over a distance of three hundred (300) feet into the wellbore 14
- Graph 910 of FIG. 10A shows a Sonicvision log over a distance of three hundred (300) feet into the wellbore 14
- Graph 920 of FIG. 10B shows a sonic log obtainable by a LWD tool which measures velocity of a propagating sound wave through a formation penetrated by a wellbore over a distance of twenty-five hundred (2500) feet into the wellbore 14 .
- the waveform VDL for the sonic log in FIG. 10B may be, for example, 40-240 ⁇ s/ft.
- An upper top end 902 of the cement 116 may be marked by an appearance of well casing 26 at early times in the measurements, such as, for example, the waveform VDL detected and/or measured by the downhole component 36 .
- the wireline cement bond log in Graph 900 of FIG. 10A illustrates that a straight waveform VDL 904 may be separated from a dynamic delta T (hereinafter “DT”) waveform 906 at the upper top end 902 of the cement 116 in the wellbore 14 .
- the Sonicvision log in FIG. 10A and the Sonicvision JTQC log in FIG. 10B illustrate that no cement 912 and high amplitudes 914 are present at and/or associated with locations above the upper top end 902 of the cement 116 in the wellbore 14 and that the cement 116 and low amplitudes 916 are present at and/or associated with locations below the upper top end 902 of the cement 116 in the wellbore 14 .
- the amplitude may be inversely proportional to the degree of bonding between the cement 116 and the well casing 26 or the cement 116 and the formation 15 .
Abstract
Systems and methods identify and/or detect one or more features of a well casing by utilizing one or more downhole measurements obtainable by a downhole component. The one or more features of the well casing are identifiable and/or detectable from the one or more measurements associated with one or more properties of the one or more features of the well casing. The one or more measurements for indentifying and/or detecting a presence and/or a location of the one or more features of the well casing include sonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or combinations thereof
Description
- This application is a divisional of co-pending U.S. patent application Ser. No. 13/12,127, filed Aug. 19, 2011, which is a 371 National Stage Entry of International Application No. PCT/US2009/059369, filed Oct. 2, 2009, which claims benefit of U.S. Provisional Patent Application Ser. No. 61/102,400, filed Oct. 3, 2008. Each of the aforementioned related patent applications is herein incorporated by reference.
- The invention relates to systems and methods for identifying and/or detecting one or more features of a wellbore by utilizing one or more downhole measurements. For example, the systems and methods may identify and/or detect one or more features of a well casing by utilizing one or more measurements detectable by a downhole component. The one or more measurements may be based on one or more properties associated with the well casing and/or the one or more features of the well casing. The one or more measurements may be utilized for indentifying and/or detecting a presence and/or a location of one or more features of the well casing. The one or more measurements may exclude electromagnetic measurements and/or may include, for example, sonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like.
- Traditionally, a downhole detector is utilized for detecting one or more features of a well casing in a well by utilizing one or more electromagnetic-fields generated by the downhole detector.
- Certain downhole oilfield applications, such as, for example, perforating applications, require the ability to be able to position a downhole tool at a particular known position in the well. For example, a wireline tool assembly including one or more instruments is lowered downhole into the well via a wireline such that the wireline tool assembly is positioned at a particular position or depth in the well. A depth counter may be used at the Earth's surface to track a length of dispensed cable to approximate the depth of the wireline tool assembly in the well. However, the depth counter may not precisely indicate the depth of the wireline tool assembly in the well because stretching and/or flexing in the downhole wireline may occur due to the weight of the wireline tool assembly. As a result, other depth determination techniques are necessary to accurately determine the depth of the wireline tool assembly in the well.
- Other depth determination techniques include use of a depth control log which is utilized to generate a casing collar locator log for identifying and/or detecting locations of features of the well casing, such as, for example, one or more casing collar joints of the well casing. The casing collar locator log is, typically, generated by ascending and descending a downhole detector in a well to determine locations and depths of one or casing collar joints of the well casing. Casing collar joints are locations in the well casing whereby casing segments are coupled together. Each casing collar joint includes a casing collar coupling two adjacent casing segments together.
- The wireline tool assembly may include a casing collar locator. The casing collar locator of the wireline tool assembly is moved downhole and/or uphole via the wireline to collect measurements and/or information associated with well casing. As a result, the casing collar locator may detect and/or identify locations and/or depths of the casing collar joints of the well casing. The measurements and/or information detected by the casing collar locator may be used to generate the depth control log. When the casing collar locator indicates detection of a casing collar joint, a coarse depth that is provided by the depth counter at the Earth's surface is used to locate the corresponding casing collar joint on the depth control log. As a result, the depth of the wireline tool assembly may be determined because the depth control log precisely illustrates the depth of the detected casing collar joint. From this determination, an error compensation factor may be derived. Then, for example, when a perforating gun is positioned downhole, the error compensation factor is used to compensate the reading of the depth counter to precisely position the gun within the well.
- Conventionally, the casing collar locator is a passive device that utilizes principles of electromagnetic inductance to detect the casing collar joints of the well casing. The casing collar locator, typically, includes an electrical coil winding through which an electromagnetic flux field is created by one or more permanent magnets passes. When a change occurs in the effective magnetic permeability of the surroundings, such as in the presence of a casing collar joint, a voltage is induced in the coil winding due to the corresponding change or disturbance in the electromagnetic flux field. Therefore, as the casing collar locator passes the casing collar joints, the change in permeability, which is caused by such things as, for example, the presence of the air gap between adjacent well casing segments and the casing collar, causes a change in the electromagnetic flux field to generate or induce a signal across the coil winding. This generated or induced signal may be communicated uphole and/or observed at a surface of the well. Thus, with this technique of detecting casing collar joints, the casing collar locator must be in continual uphole or downhole motion to produce the signal indicating detection of the casing collar joint.
- The quality of the signal may be highly dependent on a degree to which the magnetic permeability changes, or is disturbed. For example, the higher the rate of change in the permeability experienced by the electromagnetic flux field, the higher the induced signal. The degree to which the electromagnetic field is disturbed depends on factors such as, for example, distance or gap (hereinafter “stand-off”) between the casing collar locator and the well casing, electromagnetic properties, such as, for example, permeability of the surrounding well casing, and a degree of change in geometry or bulk-mass of the casing, such as, for example, an abrupt and/or drastic change causing a sufficient and/or rapid disturbance in the flux field.
- If the electromagnetic field is not sufficiently and/or rapidly disturbed, the resulting signal may be too small to be detected at the surface of the well. The signal-to-noise ratio of the signal produced downhole typically places a limit on the degree to which the signal can be boosted, or amplified. As a result, it may be very difficult to detect casing collar joints made from a material having a low magnetic permeability. Likewise, joints having no casing collars are difficult to detect, particularly, if the joints are “flush” and/or without air gaps.
- Another difficulty associated with the conventional casing collar locator is associated with a mass and/or a size of the conventional casing collar locator. For example, the conventional casing collar locator may be made up of many different components, such as, for example, two or more permanent magnets, one or more coils, and one or more coil cores, or bobbins. As a result, the combination of the components of the casing collar locator imparts a large mass to the conventional casing collar locator. The resulting large mass of the casing collar locator may cause a significant force to be exerted on the casing collar locator during perforating operations due to high acceleration and/or shock that may affect the resulting large mass. The force exerted on the casing collar locator may damage the casing collar locator if measures are not undertaken to properly pack and/or protect the casing collar locator in the well.
- The combination of the components of the casing collar locator often results in the casing collar locator being bulky in size. For example, the casing collar locator may extend from six inches to eighteen inches, not including the pressure housing and connections. As a result, a tool string which may house the casing collar locator may, thus, be long and cumbersome. A length of the tool string is very important, particularly, when the tool string is conveyed on a wireline and/or when working with high well pressure. Having a tool string with a long length can present major operational and safety problems with pressure control equipment, such as, for example, a lubricator and/or a riser pipe. Therefore, it is important to conserve every inch in length of a tool string, particularly, in perforating applications.
- Another depth determination technique includes measuring each casing segment at the Earth's surface before the casing segments are coupled together to form the well casing and lowered downhole into the well. By measuring each casing segment at the Earth's surface, a total number of casing segments necessary to insure that formations of interest have casing segments placed or positioned thereon may be determined. A length of each casing segment, typically, lies within a variance of tens of inches of each other. Since each casing segment has a unique length, a unique pattern of casing segment lengths are distributed downhole throughout the well and recorded at the Earth's surface.
- The casing collar of each casing segment refers to a top end and/or a bottom end of each casing segments which have threads thereon for coupling the casing segments together. Thus, the casing collars of the casing segments have a greater thickness at threads located at the top and bottom ends of each casing segment than the thickness of casing segments between the top and bottom ends of each casing segment. The greater thickness at the ends of each casing segment allows locations of the top end, the bottom end, and the length of each casing segment to be identified and/or detected by, for example, a downhole electromagnetic-field based detector lowered downhole into the well. By identifying the unique pattern of casing segment lengths with the downhole electromagnetic-field based detector, a depth and/or location of the detector, casing segments and/or casing collars within the well may be determined. For example, the downhole electromagnetic-field based detector may be utilized for measuring and/or determining formation properties, relative positions of the casing collar joints, formation layers, and/or total depth.
- However, the downhole electromagnetic-field based detector must be lowered into the well using the wireline. And as discussed above, the precise depth of the detector may not be identifiable because the wireline may stretch and/or flex due to the weight of the downhole detector. Thus, other depth determination techniques are necessary in order to accurately determine or identify locations and depths associated downhole detectors, downhole wireline tool assemblies and/or features of the well casing.
-
FIG. 1 illustrates a schematic diagram of a drilling system in an embodiment of the present invention and which can be used in practicing embodiments of the method of the present specification. -
FIG. 2 illustrates a schematic diagram of a well casing and a downhole component in an embodiment of the present invention and which can be used in practicing embodiments of the method of the present specification. -
FIG. 3 illustrates a graph for identifying one or more features of a well casing in an embodiment of the present specification. -
FIG. 4 illustrates a graph for identifying one or more features of a well casing via gamma-gamma density measurements in an embodiment of the present specification. -
FIG. 5 illustrates a graph for identifying one or more features of a well casing via photoelectric type nuclear measurements in an embodiment of the present specification. -
FIG. 6 illustrates a graph for identifying one or more features of a well casing via photoelectric type nuclear measurements obtained by a downhole tool in an embodiment of the present specification. -
FIG. 7 illustrates a graph for identifying one or more features of a well casing via density measurements obtained by a downhole tool in an embodiment of the present specification. -
FIG. 8 illustrates a graph includes sonic Slowness Time Coherence (hereinafter “STC”) projections and Variable Density Log (hereinafter “VDL”) waveforms for identifying one or more features of a well casing in an embodiment of the present specification. -
FIG. 9 illustrates a graph including real time mud pulse transmissions of sonic STC projections and slowness for identifying one or more features of a well casing in an embodiment of the present specification. -
FIG. 10A illustrates a graph including sonic receiver waveforms for identifying one or more features of a well casing in an embodiment of the present specification. -
FIG. 10B illustrates a graph including sonic receiver waveforms for identifying one or more features of a well casing in an embodiment of the present specification. - The invention relates to systems and methods for identifying and/or detecting a feature of well casing by utilizing a downhole measurement associated with a well casing or formations or cement located adjacent to the well casing. The systems and methods may identify and/or detect features of the well casing by utilizing measurements of the one or more properties associated with the well casing detectable by a downhole component. The well casing may be made of steel and may be positioned within a portion of the well during or after drilling of the well. The one or more features of the well casing identifiable and/or detectable may include, for example, casing collars, casing collar joints and/or cement adjacent to the well casing. The one or more measurements utilized to identify and/or detect the one or more features of the well casing may be detectable by the downhole component which may include a logging-while-drilling (hereinafter “LWD”) tool and/or a wireline configurable tool. The one or more measurements for indentifying and/or detecting the features of the well casing may include, for example, sonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like. Moreover, the one or more measurements for identifying and/or detecting the features of the well casing may not include or may exclude electromagnetic measurements.
- Referring now to the drawings wherein like numerals refer to like parts,
FIG. 1 schematically depicts adrilling system 10, which may be on-shore or off-shore, in which the present systems and methods for identifying and/or detecting one or more features of a well casing may be implemented. Thedrilling system 10 may be an on-shore drilling system 10 with adrill string 12 comprising a string ofdrill pipe 13. During the drilling of awellbore 14 insubsurface formations 15, a surface pumping system (not shown in the drawings) may delivermud flow 16 to the central passageway of thedrill pipe 13, and themud flow 16 may propagate downhole through thedrill pipe 13. Near the bottom end of thedrill pipe 13, themud flow 16 may exit thedrill pipe 13 at nozzles (not shown in the drawings) and may return uphole to the surface pumping system via anannulus 18 of the well. As an example, the circulatingmud flow 16 may actuate adownhole mud motor 20 that may, in turn, rotate adrill bit 22 of thedrill pipe 13. Embodiments of the present invention may be utilized with vertical, horizontal and/or directional drilling. - The
drilling system 10 ofFIG. 1 may depict a particular stage of the well during its drilling, post drilling and/or completion. In this stage,upper segments 24 of thewellbore 14 may be formed through the operation of thedrill pipe 13 and may be lined with and supported by awell casing 26 that has been installed in theupper segments 24. Thewell casing 26 may be made of material, such as, for example, steel and/or the like. It should be understood that the well casing 26 may be made from any material as known to one of ordinary skill in the art. - For example, the
wellbore 14 may extend below theupper segments 24 into a lower,uncased segment 28. Thus, drilling operations may be interlaced with installation operations of thewell casing 26. However, thedrill pipe 13 may alternatively be used as part of the well completion. In this manner, called “casing drilling,” thedrill pipe 13 may be constructed to line and support thewellbore 14 so that at the conclusion of the drilling operation, thedrill pipe 13 may be left in the well to perform the traditional function of awell casing 26. - The drilling operation and/or the downhole formations through which the
wellbore 14 extends may be monitored at the surface of the well via measurements that are acquired downhole. For this purpose, thedrill pipe 13 may have a wired drill pipe infrastructure 30 (hereinafter “WDP 30”) for purposes of establishing one or more communication link(s) between the surface of the well and adownhole components 36 may acquire measurements and/or may be part of a bottom hole assembly 32 (hereinafter “BHA 32”) of thedrill pipe 13. As non-limiting examples, theWDP 30 may provide a cable within eachdrill pipe 13 that is communicatively coupled at each pipe joint. Communication through theWDP 30 may be bidirectional, in that the communication may be from the surface of the well to theBHA 32 and/or from theBHA 32 to the surface of the well. Moreover, many variations and uses of theWDP 30 are contemplated and are within the scope of the present invention. Examples include U.S. Pat. Nos. 6,641,434 (Boyle et al.), U.S. Pat. No. 6,866,306 (Boyle et al.) and U.S. Pat. No. 7,413,021 (Madhara et al.) each assigned to the assignee of the present application and hereby incorporation by reference in their entire. - The
WDP 30 may include one or morecommunication line segments 34 embedded in a housing of thedrill pipe 13. The one or morecommunication line segments 34 may be, for example, fiber optic line segments, a coaxial cable, electrical cable segments, or another device for transferring data. It should be understood that thecommunication line segments 34 may be any communication line segments as known to one of ordinary skill in the art. The present invention should not be deemed as limited to a specific number of downhole components incorporated within theWDP 30 of thedrilling system 10. - The
WDP 30 may contain multiple communication lines that extend between the surface of the well and theBHA 32, with each communication line being formed from serially connectedcommunication line segments 34, thedownhole component 36 and/or communication connectors within the WDP joints 44. - In embodiments, the
drill pipe 13 may include the one or moredownhole components 36 which may be a downhole tool comprising a telemetry module. Communication signals may be received by the telemetry module at theBHA 32 from asurface controller 48 via the bidirectional communication provided by the telemetry module. The communication signals received from thesurface controller 48 may control processes such as directional drilling and/or functions or operations of the one or moredownhole components 36 associated with thedrill pipe 13. The communication signals from thesurface controller 48 may be transmitted downhole to the one or more downhole components. As a result, the bidirectional communication may improve measurement and control, during drilling (and pausing and tripping) processes, to achieve improved operation and decision making. - The telemetry module of the one or more
downhole components 36 may communicate with thesurface controller 48 via mud pulse telemetry, acoustic telemetry, electromagnetic telemetry and/or real time bidirectional drill string telemetry. It should be understood that the type of telemetry utilized by the telemetry module of the one or moredownhole components 36 may be any type of telemetry capable of communicating with thesurface controller 48 as known to one of ordinary skill in the art. - As a result, the one or more
downhole components 36 of thedrill pipe 13 may communicate with thesurface controller 48 via communication signals that may be communicated over theWDP 30 and/or telemetry module of the one or moredownhole components 36. In embodiments, the one or moredownhole components 36 may receive one or more signals, such as, for example, control and/or data signals from theWDP 30 via thecommunication line segments 34. Further, the one or moredownhole components 36 may transmit one or more signals uphole to thesurface controller 48 via theWDP 30 or the telemetry module. Moreover, thedrill pipe 13 may include various other features, such as, for example, a drill collar, an under-reamer and/or the like, as the depiction of thedrill pipe 13 inFIG. 1 is simplified for purposes of illustrating certain aspects of thedrill pipe 13 related to thewell casing 26, theWDP 30 and/or the one or moredownhole components 36. It should be understood that theBHA 32 may include any number ofdownhole components 36 and/or other features as known to one of ordinary skill in the art. - For example, the one or more
downhole components 36, in embodiments, may be housed in a drill collar, as is known in the art, and may contain one or more known types of telemetry, survey or measurement tools, such as, for example, one or more LWD tools, one or more measuring-while-drilling tools (hereinafter “MWD tools”), one or more near-bit tools, one or more on-bit tools, and/or one or more wireline configurable tools. - In embodiments, the LWD tools of the one or more
downhole components 36 may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment. The LWD tools may indentify, detect and/or measure one or more properties associated with theformation 15, thedrill string 12, thewell casing 26 and/or the features of thewell casing 26. Additionally, the one or more LWD tools may include one or more of the following types of logging and/or measuring devices: a resistivity measuring device; a directional resistivity measuring device; a sonic measuring device; a nuclear measuring device; a nuclear magnetic resonance measuring device; a pressure measuring device; a seismic measuring device; an imaging device; a formation sampling device; a gamma ray measuring device; a density and photoelectric measuring device; a neutron porosity device; a bit resistivity measuring device, a ring resistivity measuring device, a button resistivity measuring device and/or a borehole caliper device. In an embodiment, the LWD tool may include, for example, a compensated density neutron tool, an azimuthal density neutron tool, a resistivity-at-the-bit tool, hookload sensor and/or a heave motion sensor. It should be understood that the one or moredownhole components 36 may be any type of LWD tool as known to one or ordinary skill in the skill. - In embodiments, the MWD tools of the one or more
downhole components 36 may include one or more devices for measuring characteristics associated with thedrill bit 22 and/or thedrill string 12. The one or more MWD tools may include one or more of the following types of measuring devices: a weight-on-bit measuring device; a torque measuring device; a vibration measuring device; a shock measuring device; a stick slip measuring device; a direction measuring device; an inclination measuring device; a gamma ray measuring device; a directional survey device; a tool face device; a borehole pressure measuring device; and/or a temperature device. The one or more MWD tools may detect, collect and/or log data and/or information about the conditions at thedrill bit 22, around theformation 15, at a front of thedrill string 12 and/or at a distance around the drill strings 12. The one or more MWD tools may provide telemetry for operating rotary steering tools. It should be understood that the one or moredownhole components 36 may be any type of MWD tool as known to one of ordinary skill in the art. - The wireline configurable tools of the one or more
downhole components 36 may be a tool commonly conveyed by wireline cable as known to one having ordinary skill in the art. The wireline configurable tools may form a wireline tool string which may include multiple separate tools which may perform multiple operations at the same time or at different times. For example, the wireline configurable tool may be a logging tool for sampling, detecting and/or measuring properties associated with theformation 15, thedrill string 12, thewell casing 26 and/or features of thewell casing 26. The wireline configurable tools may be one or more open hole electric line tool which may identify and/or detect one or more measurements, such as, for example, gamma radiation measurements, nuclear measurements, density measurements, neutron measurements, resistivity measurements, sonic measurements, ultrasonic measurements, magnetic resonance measurements, seismic measurements and/or porosity measurements. In embodiments, wireline configurable tools may be one or more cased hole electric line tools, such as, for example, a sonic tool, an ultrasonic tool, an azimuthal density neutron tool, a cement bond tool, a casing collar locator, a gamma perforating tool, a well completion tool and/or a setting tool. It should be understood that the one or moredownhole components 36 may be any type of wireline configurable tool as known to one of ordinary skill in the art. - The one or more
downhole components 36 may comprise, include or incorporate a BHA power source, such as, for example, thedownhole mud motor 20 or any other power generating source as known to one of ordinary skill in the art. The BHA power source may produce and generate electrical power or electrical energy to be distributed throughout theBHA 32 and/or to power the one or moredownhole components 36. - As illustrated in
FIG. 2 , thedownhole component 36, such as, for example, a LWD tool or a wireline configurable tool may be used to locate one or more features of thewell casing 26 surrounding and/or adjacent to thedownhole component 36. Thewell casing 26 and/or the one or more features of thewell casing 26 may include, for example, a valve, a casing collar joint or other tubular structure which may have one or more properties measurable and/or detectable by thedownhole component 36. Additionally, the well casing 26 may have a passageway for receiving thedownhole component 36. The one or more properties associated with and/or related to thewell casing 26 and/or the one or more features of thewell casing 26 may include, for example, physical properties, mechanical properties, electrical properties, thermal properties, chemical properties, magnetic properties, optical properties, acoustical properties, radiological properties and/or atomic properties. It should be understood that the one or more properties associated with thewell casing 26 and/or the one or more features of thewell casing 26 may be any type of properties measurable and/or detectable by thedownhole component 36 and known to one of ordinary skill in the art. - In embodiments, the
downhole component 36 may pass through acentral passageway 100 of thewell casing 26 along anaxis 102 within thewell casing 26 for purposes of identifying and/or detecting the one or more features of thewell casing 26, such as a casing collar joint 104 by measuring and/or detecting the one or more properties of thewell casing 26 and/or the casing collar joint 104. Unlike conventional casing collar detectors, thedownhole component 36 may or may not need to move along theaxis 102 to measure and/or detect the properties of thewell casing 26 and/or the casing collar joint 104. Thedownhole component 36 may measure and/or detect the one or more properties associated with the casing collar joint 104 and may transmit a signal to indicate and/or identify that the feature and/or the casing collar joint 104 of the well casing may be near and/or adjacent to thedownhole component 36. Thus, while stationary or moving with respect to the features and/or the casing collar joint 104 of thewell casing 26, thedownhole component 36 may be used to detect and/or identify one or more features of thewell casing 26. - In some embodiments of the invention, the properties associated with the
well casing 26, the features of thewell casing 26 and/or the casing collar joint 104 may be detectable and/or identifiable by measurements detectable and/or measurable by thedownhole component 36. The measurements for detecting and/or identifying the one or more properties of thewell casing 26 detectable and/or measureable by thedownhole component 36 may include, for example, sonic measurements, ultrasonic measurements, nuclear measurements, gamma ray measurements, photoelectric measurements, resistivity measurements and/or the like. The measurements for detecting and/or identifying the one or more properties of thewell casing 26 may not include or may exclude electromagnetic measurements. - The measurements of the one or more properties of the
well casing 26 that may be detectable and/or measurable by thedownhole component 36 may be affected differently by the properties associated with the features and/or the casing collar joint 104 of thewell casing 26. By detecting and/or measuring the properties associated with thewell casing 26, thedownhole component 36 may identify and/or determine when the one or more of the features of thewell casing 26, such as, for example, the casing collar joint 104 may be present and in proximity and/or adjacent to thedownhole component 36. - For example, the casing collar joint 104 that is depicted in
FIG. 2 may be formed from a union or coupling of well casing segments 106 a and 106 b which may be attached, connected and/or coupled together by acasing collar 108. A lowertapered end 110 of the upper casing segment 106 a may extend into an upper portion of thecasing collar 108, and an uppertapered end 112 of the lower casing segment 106 b may extend into a lower portion of thecasing collar 108. The lowertapered end 110 and the upper tapered end 112 (hereinafter “theends casing collar 108, but rather, anair gap 114 may exist between theends air gap 114 and thecasing collar 108 may create and/or result in substantially different measurements of properties detectable and/or measurable by thedownhole component 36, when thedownhole component 36 may be near or adjacent to the casing collar joint 104, than measurements of properties detectable and/or measurable when thedownhole component 36 may be near a portion of thewell casing 26 without the casing collar joint 104. - The measurements of the properties detected and/or measured by the
downhole component 36 may provide an identification and/or a location of the features of thewell casing 26, such as, for example, the casing collar joint 104. Because the measurements may be different when thedownhole component 36 may be near or adjacent to the casing collar joint 104 than when thedownhole component 36 may not be near the casing collar joint 104 and near, for example, a straight section of thewell casing 26. As a result, a presence and/or a location of the casing collar joint 104 may be identified and/or detected by comparing the different measurements, detected and/or measured by thedownhole component 36. - The
downhole component 36 may be compared to a conventional casing collar locator that relies on a change in the sensed magnetic field to induce a signal on a winding for purposes of indicating detection of a casing collar joint. However, the conventional casing collar locator does not generate a signal if the locator is not moving. In contrast, thedownhole component 36 may measure and/or detect the measurements of the properties associated with thewell casing 26, the features of thewell casing 26 and/or the casing collar joint 104, regardless of whether thedownhole component 36 may be stationary or moving with respect to thewell casing 26. The differences in the measurements obtained and/or measured by thedownhole component 36 may be used to determine if one or more of the features of thewell casing 26, such as, for example, the casing collar joints 104 may be identified and/or detected. - In embodiments, identification of the one or more casing collar joints 104 may be utilized to determine a measured depth based on and/or corresponding to the location of the one or more casing collar joints 104. The determined measured depth may be used to a downhole location for performing and/or executing a downhole action. The downhole action may include, for example, positioning a whipstock, side tracking a well and/or positioning a perforation tool. After the measured depth may be determined based on the locations of one or more casing collar joints 104, the downhole action may be performed and/or executed at the downhole location based on the measured depth.
- In general, the changes, differences or disturbances between the measured and/or detected properties may be caused by, for example, changes in the geometry of the
well casing 26; gaps in thewell casing 26, such as, for example, theair gap 114; anomalies in thewell casing 26, such as, for example, heavy pitting, cracks, or holes such as perforations; sudden changes in distance or stand-off between thedownhole component 36 and thewell casing 26; other changes in one or more properties associated with thewell casing 26; and/or changes in the bulk-mass of thewell casing 26. - Among the other features of the
downhole component 36, in some embodiments, thedownhole component 36 which may be a LWD tool which may be included in thedrill string 12 or a wireline configurable tool may include a tubular housing (not shown in the drawings) having a longitudinal axis. The longitudinal axis may be generally aligned with theaxis 102 of thewell casing 26 when thedownhole component 36 may be located inside thewell casing 26. The housing of thedownhole component 36 may protect and provide sealed containment for sensors (not shown in the drawings) and/or circuitry (not shown in the drawings) of thedownhole component 36. - The housing of the
downhole component 36 may be connected to a wireline cable (not shown in the drawings) that may extend to the Earth's surface to position thedownhole component 36, to communicate signals, in real time, from thedownhole component 36 to the Earth's surface and thesurface controller 48 and/or to provide electrical power to thedownhole component 36. Thedownhole component 36 may output and/or transmit one or more signals to thesurface controller 48 that may be processed by thesurface controller 48 for identifying the presence and/or location of the one or more features of thewell casing 26, such as, for example, the casing collar joint 104. As a result, thedownhole component 36 may identify and/or determine the presence and/or the location of the casing collar joint 104 and/or other features of thewell casing 26 based on the signals received from thedownhole component 36. - When the one or more features and/or the casing collar joint 104 of the
well casing 26 has been detected, thedownhole component 36 may communicate the one or more signals, in real time, identifying the one or more features and/or the casing collar joint 104 to the Earth's surface via one or morecommunication line segments 34 of theWDP 30 or the telemetry module of the one or moredownhole components 36. For example, thedownhole component 36 may establish communication with the wireline cable that extends to the Earth's surface. Thedownhole component 36 may communicate to the surface a direct indication of the properties associated with the one or more features or the casing collar joint 104 of thewell casing 26 or, alternatively, may communicate an indication of the actual feature(s) and/or the casing collar joint 104 detected. - For example, the
downhole component 36 may be a LWD sonic tool which may utilize sonic waves to measure and/or detect one or more properties associated with the casing collar joint 104, such as sonic absorption. Thedownhole component 36 may transmit sound waves towards the casing collar joint 104 and/or thewell casing 26 and may have a receiver (not shown in the drawings) which may receive the sonic waves reflected from the casing collar joint 104 and/or thewell casing 26. - As shown in
FIG. 3 ,graph 200 illustrates amplitudes for sound waves or waveforms received by thedownhole component 36 and processed by thedownhole component 36 and/or thesurface controller 48. The amplitudes of the detected sound waves or waveforms may change when the casing collar joint 104 is near or adjacent to thedownhole component 36. For example, the amplitude of the detected sound waves or waveforms may momentarily increase to one ormore spikes 202 when thedownhole component 36 is in the presence of and/or is adjacent to the casing collar joint 104 as shown intrack 204 ofFIG. 3 . As a result, thedownhole component 36 and/or thesurface controller 48 may identify the presence and/or the location of one or more casing collar joint 104 based on the measurements and/orspikes 202 detected and obtained by thedownhole component 36 when thedownhole component 36 may be near or adjacent to the casing collar joint 104. - In embodiments, the
downhole component 36 may be adapted to measure and/or detect, for example, gamma-gamma and photoelectric type nuclear density measurements to identify and/or detect the presence and/or the location of one or more casing collar joints 104 as shown ingraphs FIGS. 4 and 5 , respectively. The measured and detected gamma-gamma and photoelectric type nuclear density measurements may momentarily increase to larger values orupward spikes 202 at regular intervals which identify the presence and/or the location of the one or more casing collar joints 104. The upward spikes may represent or correspond to detection of a higher density inFIG. 4 and a higher photoelectric value inFIG. 5 . - The
downhole component 36 and/or thesurface controller 48 may utilize one or more processing algorithms to analyze the measurements detected by thedownhole component 36 and to identify the one or more casing collar joints 104. The identification of the one or more casing collar joints may be enhanced by insuring that the source and detectors of thedownhole component 36 for the gamma-gamma and photoelectric type nuclear density measurements may be pressed up against the well casing 26 by, for example, a backup arm (not shown in the drawings). Other variations in the measurements may be unrelated to the casing collar joints 104 but may also be identified from the gamma-gamma and photoelectric type nuclear density measurements. The other variations or may be associated with theformation 15 or changes in a position of thewell casing 26 with respect to theformation 15. -
FIG. 6 illustrates agraph 500 for photoelectric type nuclear measurements detected by thedownhole component 36 and processed by thedownhole component 36 and/or thesurface controller 48.Graph 500 inFIG. 6 may represent or correspond to scintillation detector count rates that may be utilized primarily in computation of bulk density and/or secondary in determination of gamma gamma density. The plotted count rates in each column ofFIG. 6 may represent specific energy ranges obtained from a short spaced detector. These energy ranges may be associated with photoelectric measurements. Each column ofFIG. 6 may represent a different pass over the same interval with varying speeds and/or varying directions. - Additionally,
FIG. 7 illustrates agraph 600 for gamma-gamma density measurements detected by thedownhole component 36 and processed by thedownhole component 36 and/or thesurface controller 48. In embodiments, thedownhole component 36 may be a LWD azimuthal density neutron (hereinafter “ADN” tool).Graph 600 may represent or correspond to detector count rates that may be utilized in computation of photoelectric values and/or determination of gamma gamma density. The measured and detected density photoelectric measurements (seeFIGS. 6 and 7 , respectively) may momentarily increase to larger values or spikes 202 at regular intervals. Thespikes 202 may identify the presence and/or the location of the one or more casing collar joints 104. Moreover, thespikes 202 may be a result of variations of metal density at the casing collar joints 104 when compared to the metal density at thewell casing 26 without the casing collar joints 104. - The measurements detected and/or measured by the
downhole component 36 may allow for real time identification of the one or more casing collar joints 104 of thewell casing 26. Thedownhole component 36 may move uphole and/or downhole at a velocity to detect and/or measure the properties along a portion of or an entire length of thewell casing 26. The velocity of movement by thedownhole component 36 may be, for example, about thirty (30) meters per hour, about forty (40) meters per hour or about fifty (50) meters per hour and/or the like. By utilizing the velocity of movement for thedownhole component 36, data density measurements of at least 6 data points may be obtained and/or measured for every meter that may be logged by thedownhole component 36. The present disclosure should not be deem limited to a specific velocity of movement for thedownhole component 36. -
FIGS. 8 and 9 illustrategraphs downhole component 36. The data and/or measurements may be stored in a memory (not shown in the drawings) of thedownhole component 36 or, alternatively, may be transmitted, in real time, uphole to surfacecontroller 48. The measurements may be processed by thedownhole component 36 and/or thesurface controller 48 to identify the presence and/or the location of the one or more casing collar joints 104 in real time or at a different time. -
Graph 700 ofFIG. 8 identifies the one or more casing collar joints 104 based on sonic STC projections and normal waveform VDL.FIG. 8 may include more than one track, such as, for example four tracks. InFIG. 8 afirst track 702 may represent a depth; asecond track 704 may represent a coherence amplitude; athird track 706 may represent a STC plane; and afourth track 708 may represent a normal waveform VDL. The one or more casing collar joints 104 may be identified and/or detected by a lack of coherence in the STC plane. Moreover, the normal waveform VDL may show a scattering of the waveform as thedownhole component 36 may be positioned near and/or adjacent to the one or more casing collar joints 104. Thus, the one or more casing collar joints 104 may be located near or about the middle of the scattering of the waveform in the normal waveform VDL. -
Graph 800 ofFIG. 9 illustrates real time mud pulse transmission measurements of sonic STC projections and slowness used for identification of the one or more casing collar joints 104. The measurements may be processed by thedownhole component 36 and/or thesurface controller 48. Specifically,FIG. 9 shows real time measurements illustrate a loss of coherence in the STC plane (as shown in the track located on the right side of graph 800) which may result in a momentarily increase to larger values or horizontal spikes in the computation of the compressional slowness to identify the one or more casing collar joints 104. The horizontal spikes inFIG. 9 may represent one or more casing collar joints 104 as identified byhorizontal arrows 802 at various depths. - In embodiments, after the position or location of the one or more casing collar joints 104 may be identified, the whipstock may be placed between the one or more casing collar joints 104 such that a window (not shown in the drawings) may be milled into the side of the
well casing 26 between the one or more casing collar joints 104. However, if the one or more casing collar joints 104 is mistakenly drilled for placement of the whipstock, the inclusion of the whipstock may not be successful because material(s) of the one or more casing collar joints 104 may be harder and thicker than material(s) of thewell casing 26 without the casing collar joints 104. As a result, the possibility of parting thewell casing 26 to form the window for inclusion of the whipstock may be greatly reduced or may be incapable of being achieved. -
Graphs FIG. 10A andGraph 920 ofFIG. 10B illustrate sonic receiver measurements for identifying and/or determining a location of an uppertop end 902 of cement 116 (as shownFIG. 2 ) and a degree of cement bond quality. During the drilling of thewellbore 14, thecement 116 may be injected through thewellbore 14 and may rise up theannulus 18 between thewell casing 26 and theformation 15. The cement bond quality refers to a quality of a bond between thewell casing 26 and thecement 116 placed in theannulus 18 between thewell casing 26 and thewellbore 14 and/or a bond between thecement 116 and theformation 15. -
Graph 900 ofFIG. 10A shows a wireline cement bond log over a distance of three hundred (300) feet into thewellbore 14,Graph 910 ofFIG. 10A shows a Sonicvision log over a distance of three hundred (300) feet into thewellbore 14.Graph 920 ofFIG. 10B shows a sonic log obtainable by a LWD tool which measures velocity of a propagating sound wave through a formation penetrated by a wellbore over a distance of twenty-five hundred (2500) feet into thewellbore 14. In embodiments, the waveform VDL for the sonic log inFIG. 10B may be, for example, 40-240 μs/ft. An uppertop end 902 of thecement 116 may be marked by an appearance of well casing 26 at early times in the measurements, such as, for example, the waveform VDL detected and/or measured by thedownhole component 36. - The wireline cement bond log in
Graph 900 ofFIG. 10A illustrates that astraight waveform VDL 904 may be separated from a dynamic delta T (hereinafter “DT”)waveform 906 at the uppertop end 902 of thecement 116 in thewellbore 14. Additionally, the Sonicvision log inFIG. 10A and the Sonicvision JTQC log inFIG. 10B illustrate that nocement 912 andhigh amplitudes 914 are present at and/or associated with locations above the uppertop end 902 of thecement 116 in thewellbore 14 and that thecement 116 andlow amplitudes 916 are present at and/or associated with locations below the uppertop end 902 of thecement 116 in thewellbore 14. Moreover, when thecement 116 may be present in thewellbore 14, the amplitude may be inversely proportional to the degree of bonding between thecement 116 and the well casing 26 or thecement 116 and theformation 15. - It will be appreciated that various of the above-disclosed and other features and functions, or alternatives thereof, may be desirably combined into many other different systems or applications. Also, various presently unforeseen or unanticipated alternatives, modifications, variations or improvements therein may be subsequently made by those skilled in the art, and are also intended to be encompassed by the following claims.
Claims (8)
1. A method for identifying a feature of a well casing located within a wellbore, the method comprising:
positioning a downhole component within the wellbore;
obtaining one or more measurements associated with the feature of the well casing via the downhole component, wherein the one or more measurements is selected from the group consisting of sonic measurements, nuclear measurements, photoelectric measurements, resistivity measurements and combinations thereof;
identifying a location of the feature of the well casing based on the one or more measurements;
determining a measured depth based on the location of the feature; and
performing a downhole action based on the measure depth.
2. The method according to claim 1 , wherein the downhole action is selected from the group consisting of positioning a perforation tool, side tracking a well and positioning a whipstock.
3. The method according to claim 1 , wherein the feature of the well casing is selected from a group consisting of a casing collar joint, a top end of cement located adjacent to the well casing, a degree of cement bonding adjacent to the well casing and an air gap associated with the casing collar joint.
4. The method according to claim 1 , further comprising:
positioning the downhole component on drill pipe.
5. The method according to claim 1 , further comprising:
transmitting the one or more measurements from the downhole component uphole via a communication link, wherein the communication link is a wired drill pipe or a telemetry module.
6. The method according to claim 5 , further comprising:
electrically connecting the downhole component to an uphole controller via the communication link, wherein the controller identifies the feature of the well casing based on the one or more measurements associated with the feature of the well casing.
7. The method according to claim 1 , further comprising:
identifying the location of the feature of the well casing based on sonic measurements obtained by the downhole component, wherein the feature of the well casing is selected from a group consisting of a casing collar joint, a top end of cement located adjacent to the well casing and a degree of cement bond located adjacent to the well casing.
8. The method according to claim 1 , wherein the downhole component is a logging-while-drilling tool or a wireline configurable tool.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US14/929,621 US20160053608A1 (en) | 2008-10-03 | 2015-11-02 | Identification of Casing Collars While Drilling and Post Drilling Using LWD and Wireline Measurements |
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US10240008P | 2008-10-03 | 2008-10-03 | |
PCT/US2009/059369 WO2010040045A2 (en) | 2008-10-03 | 2009-10-02 | Identification of casing collars while drilling and post drilling and using lwd and wireline |
US201113122127A | 2011-08-19 | 2011-08-19 | |
US14/929,621 US20160053608A1 (en) | 2008-10-03 | 2015-11-02 | Identification of Casing Collars While Drilling and Post Drilling Using LWD and Wireline Measurements |
Related Parent Applications (2)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2009/059369 Division WO2010040045A2 (en) | 2008-10-03 | 2009-10-02 | Identification of casing collars while drilling and post drilling and using lwd and wireline |
US13/122,127 Division US9175559B2 (en) | 2008-10-03 | 2009-10-02 | Identification of casing collars while drilling and post drilling using LWD and wireline measurements |
Publications (1)
Publication Number | Publication Date |
---|---|
US20160053608A1 true US20160053608A1 (en) | 2016-02-25 |
Family
ID=42074232
Family Applications (2)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/122,127 Active 2031-06-13 US9175559B2 (en) | 2008-10-03 | 2009-10-02 | Identification of casing collars while drilling and post drilling using LWD and wireline measurements |
US14/929,621 Abandoned US20160053608A1 (en) | 2008-10-03 | 2015-11-02 | Identification of Casing Collars While Drilling and Post Drilling Using LWD and Wireline Measurements |
Family Applications Before (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/122,127 Active 2031-06-13 US9175559B2 (en) | 2008-10-03 | 2009-10-02 | Identification of casing collars while drilling and post drilling using LWD and wireline measurements |
Country Status (2)
Country | Link |
---|---|
US (2) | US9175559B2 (en) |
WO (1) | WO2010040045A2 (en) |
Cited By (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20150285069A1 (en) * | 2014-04-04 | 2015-10-08 | Micro-G Lacoste, Inc. | High Resolution Continuous Depth Positioning in a Well Bore Using Persistent Casing Properties |
US20170242152A1 (en) * | 2015-10-02 | 2017-08-24 | Halliburton Energy Services, Inc. | Logging-while-drilling tool with interleaved instruments |
US11242740B2 (en) | 2017-11-17 | 2022-02-08 | Keystone Wireline, Inc. | Method of evaluating cement on the outside of a well casing |
Families Citing this family (22)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
RU2475784C2 (en) | 2007-12-19 | 2013-02-20 | Эксонмобил Апстрим Рисерч Компани | Simulation of gamma-ray logging probe characteristics |
US10145237B2 (en) * | 2009-04-02 | 2018-12-04 | Statoil Pertoleum As | Apparatus and method for evaluating a wellbore, in particular a casing thereof |
US8365825B1 (en) * | 2009-11-06 | 2013-02-05 | Halliburton Energy Services, Inc. | Suppressing voltage transients in perforation operations |
NO333359B1 (en) * | 2012-03-20 | 2013-05-13 | Sensor Developments As | Method and system for correcting a well completion |
US9383473B2 (en) | 2012-06-26 | 2016-07-05 | Exxonmobil Upstream Research Company | Method for cement evaluation with neutron logs |
US20140216734A1 (en) * | 2013-02-05 | 2014-08-07 | Schlumberger Technology Corporation | Casing collar location using elecromagnetic wave phase shift measurement |
US9488006B2 (en) | 2014-02-14 | 2016-11-08 | Baker Hughes Incorporated | Downhole depth measurement using tilted ribs |
WO2016025230A1 (en) | 2014-08-11 | 2016-02-18 | Halliburton Energy Services, Inc. | Well ranging apparatus, systems, and methods |
WO2017048263A1 (en) * | 2015-09-17 | 2017-03-23 | Halliburton Energy Services, Inc. | Determining permeablility based on collar responses |
WO2017062032A1 (en) * | 2015-10-09 | 2017-04-13 | Halliburton Energy Services, Inc. | Hazard avoidance during well re-entry |
US11442196B2 (en) | 2015-12-18 | 2022-09-13 | Halliburton Energy Services, Inc. | Systems and methods to calibrate individual component measurement |
FR3049355B1 (en) | 2016-03-25 | 2020-06-12 | Services Petroliers Schlmumberger | METHOD AND DEVICE FOR ESTIMATING ACOUSTIC SLOWNESS IN A SUBTERRANEAN FORMATION |
US20170285219A1 (en) * | 2016-03-31 | 2017-10-05 | Schlumberger Technology Corporation | Method of determining the condition and position of components in a completion system |
BR112019001569A2 (en) * | 2016-08-12 | 2019-05-07 | Halliburton Energy Services, Inc. | method and system for locating a necklace. |
US10465509B2 (en) | 2016-10-12 | 2019-11-05 | Baker Hughes, A Ge Company, Llc | Collocated multitone acoustic beam and electromagnetic flux leakage evaluation downhole |
WO2018190831A1 (en) * | 2017-04-12 | 2018-10-18 | Halliburton Energy Services, Inc. | Method for finding position of collars |
WO2019032262A1 (en) * | 2017-08-08 | 2019-02-14 | Halliburton Energy Services, Inc. | Workflow and visualization for localization of concentric pipe collars |
WO2019046101A1 (en) * | 2017-08-30 | 2019-03-07 | Halliburton Energy Services, Inc. | Artifact identification and removal method for electromagnetic pipe inspection |
CA3100702A1 (en) * | 2018-05-18 | 2019-11-21 | Globaltech Corporation Pty Ltd | Devices, systems and methods for downhole event detection and depth determination |
BR112020018833B1 (en) | 2018-06-28 | 2023-12-26 | Halliburton Energy Services, Inc | System and method for detecting a discontinuity in a well casing |
WO2023177767A1 (en) * | 2022-03-16 | 2023-09-21 | Schlumberger Technology Corporation | Casing collar locator detection and depth control |
CN114837655A (en) * | 2022-05-24 | 2022-08-02 | 吉林瑞荣德能源科技有限公司 | Method and device for positioning oil and gas logging optical fiber |
Citations (45)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2201311A (en) * | 1936-12-24 | 1940-05-21 | Halliburton Oil Well Cementing | Apparatus for indicating the position of devices in pipes |
US2350832A (en) * | 1941-02-21 | 1944-06-06 | Schlumberger Well Surv Corp | Electrical depth marker |
US2476137A (en) * | 1942-05-16 | 1949-07-12 | Schlumberger Well Surv Corp | Method of positioning apparatus in boreholes |
US2549109A (en) * | 1949-03-19 | 1951-04-17 | Lane Wells Co | Radioactive locating means |
US2580544A (en) * | 1948-12-30 | 1952-01-01 | Texas Co | Locating casing collars in a well |
US2602833A (en) * | 1948-07-15 | 1952-07-08 | Well Surveys Inc | Casing collar locator |
US2768684A (en) * | 1952-02-20 | 1956-10-30 | Perforating Guns Atlas Corp | Well perforating and logging methods and apparatus |
US2782365A (en) * | 1950-04-27 | 1957-02-19 | Perforating Guns Atlas Corp | Electrical logging apparatus |
US2892977A (en) * | 1954-12-30 | 1959-06-30 | Well Surveys Inc | Differential conductivity pipe testing |
US2897438A (en) * | 1954-04-19 | 1959-07-28 | Well Surveys Inc | Casing joint detector |
US2985822A (en) * | 1957-09-16 | 1961-05-23 | Well Surveys Inc | Modulation system for casing collar locators |
US3212601A (en) * | 1962-03-01 | 1965-10-19 | Pgac Dev Company | Single conductor acoustic well logging system |
US3221548A (en) * | 1961-06-02 | 1965-12-07 | Dresser Ind | Combination logging system and method |
US3295628A (en) * | 1962-03-23 | 1967-01-03 | Pgac Dev Company | Acoustic well logging method and apparatus |
US3431488A (en) * | 1965-04-19 | 1969-03-04 | Dresser Ind | Stabilized high temperature casing collar logging system utilizing the on-off ratio of a square wave as a signal transmitting means |
US3504758A (en) * | 1969-02-19 | 1970-04-07 | Schlumberger Technology Corp | Acoustic well-logging apparatus |
US3512407A (en) * | 1961-08-08 | 1970-05-19 | Schlumberger Technology Corp | Acoustic and radioactivity logging method and apparatus |
US3783444A (en) * | 1969-08-01 | 1974-01-01 | Schlumberger Technology Corp | Method and apparatus for use in investigating earth formations |
US4180727A (en) * | 1977-10-20 | 1979-12-25 | Mobil Oil Corporation | Gamma-gamma density logging method |
US4297575A (en) * | 1979-08-13 | 1981-10-27 | Halliburton Company | Simultaneous gamma ray measurement of formation bulk density and casing thickness |
US4431963A (en) * | 1981-09-28 | 1984-02-14 | Dresser Industries, Inc. | Apparatus for determining a natural current flow in well casing |
EP0134626A1 (en) * | 1983-06-13 | 1985-03-20 | Halliburton Company | Determination of casing thickness using a gain stabilized gamma ray spectroscopy technique |
US5187440A (en) * | 1986-11-04 | 1993-02-16 | Para Magnetic Logging, Inc. | Measuring resistivity changes from within a first cased well to monitor fluids injected into oil bearing geological formations from a second cased well while passing electrical current between the two cased wells |
US5250806A (en) * | 1991-03-18 | 1993-10-05 | Schlumberger Technology Corporation | Stand-off compensated formation measurements apparatus and method |
US5491668A (en) * | 1994-05-13 | 1996-02-13 | Western Atlas International, Inc. | Method for determining the thickness of a casing in a wellbore by signal processing pulse-echo data from an acoustic pulse-echo imaging tool |
US5717169A (en) * | 1994-10-13 | 1998-02-10 | Schlumberger Technology Corporation | Method and apparatus for inspecting well bore casing |
US20020093431A1 (en) * | 1998-08-28 | 2002-07-18 | Zierolf Joseph A. | Method and apparatus for determining position in a pipe |
US20040210393A1 (en) * | 2003-01-24 | 2004-10-21 | Ellis Darwin V. | Measuring formation density through casing |
US20040239521A1 (en) * | 2001-12-21 | 2004-12-02 | Zierolf Joseph A. | Method and apparatus for determining position in a pipe |
US20050284661A1 (en) * | 1996-03-25 | 2005-12-29 | Goldman William A | Method and system for predicting performance of a drilling system for a given formation |
US20060106541A1 (en) * | 2004-10-21 | 2006-05-18 | Baker Hughes Incorporated | Enhancing the quality and resolution of an image generated from single or multiple sources |
US20060201711A1 (en) * | 1994-10-14 | 2006-09-14 | Vail William B Iii | Methods and apparatus for cementing drill strings in place for one pass drilling and completion of oil and gas wells |
US7147068B2 (en) * | 1994-10-14 | 2006-12-12 | Weatherford / Lamb, Inc. | Methods and apparatus for cementing drill strings in place for one pass drilling and completion of oil and gas wells |
US20070192074A1 (en) * | 2005-08-08 | 2007-08-16 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US20070242265A1 (en) * | 2005-09-12 | 2007-10-18 | Schlumberger Technology Corporation | Borehole Imaging |
US20090090556A1 (en) * | 2005-08-08 | 2009-04-09 | Shilin Chen | Methods and Systems to Predict Rotary Drill Bit Walk and to Design Rotary Drill Bits and Other Downhole Tools |
US20090229888A1 (en) * | 2005-08-08 | 2009-09-17 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US7647182B2 (en) * | 2004-07-15 | 2010-01-12 | Baker Hughes Incorporated | Apparent dip angle calculation and image compression based on region of interest |
US7710823B2 (en) * | 2007-04-04 | 2010-05-04 | Baker Hughes Incorporated | Resistivity measurement through metal casing using magnetic field and magnetoacoustic phenomena |
US20100134112A1 (en) * | 2008-12-02 | 2010-06-03 | Hong Zhang | Detecting electrical current in a magnetic structure |
US20100133015A1 (en) * | 2007-03-27 | 2010-06-03 | Shilin Chen | Rotary Drill Bit with Improved Steerability and Reduced Wear |
US20100163312A1 (en) * | 2007-05-30 | 2010-07-01 | Shilin Chen | Rotary Drill Bits with Gage Pads Having Improved Steerability and Reduced Wear |
US20100252725A1 (en) * | 2009-04-02 | 2010-10-07 | Recon Petrotechnologies., Ltd. | Logging tool and method for determination of formation density |
US20100300758A1 (en) * | 2005-08-08 | 2010-12-02 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US9322949B2 (en) * | 2010-04-19 | 2016-04-26 | Schlumberger Technology Corporation | System and method for generating density in a cased-hole wellbore |
Family Cites Families (53)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2156519A (en) * | 1937-09-07 | 1939-05-02 | Cranford P Walker | Means for measuring the location of obstructions in wells |
US2459499A (en) * | 1943-12-17 | 1949-01-18 | Schlumberger Well Surv Corp | Casing joint locator |
US3106960A (en) * | 1960-01-08 | 1963-10-15 | Howard J Doak | Method of and means for positioning apparatus in well casings |
US3177941A (en) * | 1963-07-22 | 1965-04-13 | Dow Chemical Co | Locator for collars in well casings |
US3306102A (en) * | 1963-12-04 | 1967-02-28 | Schlumberger Technology Corp | Formation evaluation method and apparatus |
US3434046A (en) * | 1965-12-20 | 1969-03-18 | Halliburton Co | Electronic borehole casing collar locator |
US4382290A (en) * | 1977-07-11 | 1983-05-03 | Schlumberger Technology Corporation | Apparatus for acoustically investigating a borehole |
US4551823A (en) * | 1981-11-19 | 1985-11-05 | Dresser Industries, Inc. | Method and apparatus for acoustic cement bond logging |
US4459479A (en) * | 1982-07-06 | 1984-07-10 | Halliburton Company | Determination of casing thickness using a natural gamma ray spectroscopy technique |
FR2569859B1 (en) * | 1984-09-05 | 1986-08-29 | Schlumberger Prospection | LOGGING METHOD AND DEVICE FOR THE ACOUSTIC INSPECTION OF A BORING WITH A TUBING |
US4733380A (en) * | 1984-12-26 | 1988-03-22 | Schlumberger Technology Corporation | Apparatus and method for acoustically investigating a casing set in a borehole |
US4709357A (en) * | 1985-08-14 | 1987-11-24 | Gearhart Industries, Inc. | Method and apparatus for acoustically investigating a borehole casing cement bond |
US4791619A (en) * | 1986-09-22 | 1988-12-13 | Schlumberger Technology Corporation | Method of detecting and characterizing features in a borehole |
US4805156A (en) * | 1986-09-22 | 1989-02-14 | Western Atlas International, Inc. | System for acoustically determining the quality of the cement bond in a cased borehole |
US4809236A (en) * | 1986-10-15 | 1989-02-28 | Schlumberger Technology Corporation | Method and apparatus for determining the magnitude of components of measurements made from inside a borehole |
US6031381A (en) * | 1986-11-04 | 2000-02-29 | Paramagnetic Logging, Inc. | Electrical voltages and resistances measured to inspect metallic cased wells and pipelines |
US5717334A (en) * | 1986-11-04 | 1998-02-10 | Paramagnetic Logging, Inc. | Methods and apparatus to produce stick-slip motion of logging tool attached to a wireline drawn upward by a continuously rotating wireline drum |
US6577144B2 (en) * | 1986-11-04 | 2003-06-10 | Western Atlas International, Inc. | Electrical voltages and resistances measured to inspect metallic cased wells and pipelines |
US4912683A (en) * | 1988-12-29 | 1990-03-27 | Atlantic Richfield Company | Method for acoustically measuring wall thickness of tubular goods |
US5081611A (en) * | 1991-03-06 | 1992-01-14 | Schlumberger Technology Corporation | Methods for determining formation and borehole parameters via two-dimensional tomographic reconstruction of formation slowness |
US5485745A (en) * | 1991-05-20 | 1996-01-23 | Halliburton Company | Modular downhole inspection system for coiled tubing |
US5275038A (en) * | 1991-05-20 | 1994-01-04 | Otis Engineering Corporation | Downhole reeled tubing inspection system with fiberoptic cable |
US5279366A (en) * | 1992-09-01 | 1994-01-18 | Scholes Patrick L | Method for wireline operation depth control in cased wells |
US5361838A (en) * | 1993-11-01 | 1994-11-08 | Halliburton Company | Slick line casing and tubing joint locator apparatus and associated methods |
US5543617A (en) * | 1994-06-27 | 1996-08-06 | Schlumberger Technology Corporation | Method of measuring flow velocities using tracer techniques |
US5635712A (en) * | 1995-05-04 | 1997-06-03 | Halliburton Company | Method for monitoring the hydraulic fracturing of a subterranean formation |
US5740864A (en) * | 1996-01-29 | 1998-04-21 | Baker Hughes Incorporated | One-trip packer setting and whipstock-orienting method and apparatus |
US5720345A (en) | 1996-02-05 | 1998-02-24 | Applied Technologies Associates, Inc. | Casing joint detector |
US5996711A (en) * | 1997-04-14 | 1999-12-07 | Schlumberger Technology Corporation | Method and apparatus for locating indexing systems in a cased well and conducting multilateral branch operations |
US5987385A (en) * | 1997-08-29 | 1999-11-16 | Dresser Industries, Inc. | Method and apparatus for creating an image of an earth borehole or a well casing |
GB9907620D0 (en) * | 1999-04-01 | 1999-05-26 | Schlumberger Ltd | Processing sonic waveform measurements |
US6815946B2 (en) | 1999-04-05 | 2004-11-09 | Halliburton Energy Services, Inc. | Magnetically activated well tool |
US6520264B1 (en) * | 2000-11-15 | 2003-02-18 | Baker Hughes Incorporated | Arrangement and method for deploying downhole tools |
US6866306B2 (en) | 2001-03-23 | 2005-03-15 | Schlumberger Technology Corporation | Low-loss inductive couplers for use in wired pipe strings |
US6896056B2 (en) * | 2001-06-01 | 2005-05-24 | Baker Hughes Incorporated | System and methods for detecting casing collars |
US7082822B2 (en) * | 2002-04-05 | 2006-08-01 | Vetco Gray Inc. | Internal riser inspection device and methods of using same |
WO2004020789A2 (en) * | 2002-08-30 | 2004-03-11 | Sensor Highway Limited | Method and apparatus for logging a well using a fiber optic line and sensors |
US6641432B1 (en) | 2002-10-16 | 2003-11-04 | Globe Union Industrial Corp. | Waterproof cell cabinet |
US6904365B2 (en) * | 2003-03-06 | 2005-06-07 | Schlumberger Technology Corporation | Methods and systems for determining formation properties and in-situ stresses |
US7301852B2 (en) * | 2003-08-13 | 2007-11-27 | Baker Hughes Incorporated | Methods of generating directional low frequency acoustic signals and reflected signal detection enhancements for seismic while drilling applications |
US7150317B2 (en) * | 2004-03-17 | 2006-12-19 | Baker Hughes Incorporated | Use of electromagnetic acoustic transducers in downhole cement evaluation |
US7077200B1 (en) * | 2004-04-23 | 2006-07-18 | Schlumberger Technology Corp. | Downhole light system and methods of use |
US7363967B2 (en) * | 2004-05-03 | 2008-04-29 | Halliburton Energy Services, Inc. | Downhole tool with navigation system |
US7202671B2 (en) * | 2004-08-05 | 2007-04-10 | Kjt Enterprises, Inc. | Method and apparatus for measuring formation conductivities from within cased wellbores by combined measurement of casing current leakage and electromagnetic response |
GB2420357B (en) * | 2004-11-17 | 2008-05-21 | Schlumberger Holdings | Perforating logging tool |
US7302841B2 (en) * | 2005-01-11 | 2007-12-04 | Estes James D | Free point tool with low mass sensor |
US7413021B2 (en) | 2005-03-31 | 2008-08-19 | Schlumberger Technology Corporation | Method and conduit for transmitting signals |
RU2302019C1 (en) * | 2006-04-18 | 2007-06-27 | Общество С Ограниченной Ответственностью "Интерлог" | Method for electrical logging of cased wells |
US7805248B2 (en) * | 2007-04-19 | 2010-09-28 | Baker Hughes Incorporated | System and method for water breakthrough detection and intervention in a production well |
US7698937B2 (en) * | 2007-10-18 | 2010-04-20 | Neidhardt Deitmar J | Method and apparatus for detecting defects in oilfield tubulars |
US8456166B2 (en) * | 2008-12-02 | 2013-06-04 | Schlumberger Technology Corporation | Single-well through casing induction logging tool |
CA2745112A1 (en) * | 2008-12-02 | 2010-06-10 | Schlumberger Canada Limited | Electromagnetic survey using metallic well casings as electrodes |
US20140216734A1 (en) * | 2013-02-05 | 2014-08-07 | Schlumberger Technology Corporation | Casing collar location using elecromagnetic wave phase shift measurement |
-
2009
- 2009-10-02 US US13/122,127 patent/US9175559B2/en active Active
- 2009-10-02 WO PCT/US2009/059369 patent/WO2010040045A2/en active Application Filing
-
2015
- 2015-11-02 US US14/929,621 patent/US20160053608A1/en not_active Abandoned
Patent Citations (49)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2201311A (en) * | 1936-12-24 | 1940-05-21 | Halliburton Oil Well Cementing | Apparatus for indicating the position of devices in pipes |
US2350832A (en) * | 1941-02-21 | 1944-06-06 | Schlumberger Well Surv Corp | Electrical depth marker |
US2476137A (en) * | 1942-05-16 | 1949-07-12 | Schlumberger Well Surv Corp | Method of positioning apparatus in boreholes |
US2602833A (en) * | 1948-07-15 | 1952-07-08 | Well Surveys Inc | Casing collar locator |
US2580544A (en) * | 1948-12-30 | 1952-01-01 | Texas Co | Locating casing collars in a well |
US2549109A (en) * | 1949-03-19 | 1951-04-17 | Lane Wells Co | Radioactive locating means |
US2782365A (en) * | 1950-04-27 | 1957-02-19 | Perforating Guns Atlas Corp | Electrical logging apparatus |
US2768684A (en) * | 1952-02-20 | 1956-10-30 | Perforating Guns Atlas Corp | Well perforating and logging methods and apparatus |
US2897438A (en) * | 1954-04-19 | 1959-07-28 | Well Surveys Inc | Casing joint detector |
US2892977A (en) * | 1954-12-30 | 1959-06-30 | Well Surveys Inc | Differential conductivity pipe testing |
US2985822A (en) * | 1957-09-16 | 1961-05-23 | Well Surveys Inc | Modulation system for casing collar locators |
US3221548A (en) * | 1961-06-02 | 1965-12-07 | Dresser Ind | Combination logging system and method |
US3512407A (en) * | 1961-08-08 | 1970-05-19 | Schlumberger Technology Corp | Acoustic and radioactivity logging method and apparatus |
US3212601A (en) * | 1962-03-01 | 1965-10-19 | Pgac Dev Company | Single conductor acoustic well logging system |
US3295628A (en) * | 1962-03-23 | 1967-01-03 | Pgac Dev Company | Acoustic well logging method and apparatus |
US3431488A (en) * | 1965-04-19 | 1969-03-04 | Dresser Ind | Stabilized high temperature casing collar logging system utilizing the on-off ratio of a square wave as a signal transmitting means |
US3504758A (en) * | 1969-02-19 | 1970-04-07 | Schlumberger Technology Corp | Acoustic well-logging apparatus |
US3783444A (en) * | 1969-08-01 | 1974-01-01 | Schlumberger Technology Corp | Method and apparatus for use in investigating earth formations |
US4180727A (en) * | 1977-10-20 | 1979-12-25 | Mobil Oil Corporation | Gamma-gamma density logging method |
US4297575A (en) * | 1979-08-13 | 1981-10-27 | Halliburton Company | Simultaneous gamma ray measurement of formation bulk density and casing thickness |
US4431963A (en) * | 1981-09-28 | 1984-02-14 | Dresser Industries, Inc. | Apparatus for determining a natural current flow in well casing |
EP0134626A1 (en) * | 1983-06-13 | 1985-03-20 | Halliburton Company | Determination of casing thickness using a gain stabilized gamma ray spectroscopy technique |
US5187440A (en) * | 1986-11-04 | 1993-02-16 | Para Magnetic Logging, Inc. | Measuring resistivity changes from within a first cased well to monitor fluids injected into oil bearing geological formations from a second cased well while passing electrical current between the two cased wells |
US5250806A (en) * | 1991-03-18 | 1993-10-05 | Schlumberger Technology Corporation | Stand-off compensated formation measurements apparatus and method |
US5491668A (en) * | 1994-05-13 | 1996-02-13 | Western Atlas International, Inc. | Method for determining the thickness of a casing in a wellbore by signal processing pulse-echo data from an acoustic pulse-echo imaging tool |
US6188643B1 (en) * | 1994-10-13 | 2001-02-13 | Schlumberger Technology Corporation | Method and apparatus for inspecting well bore casing |
US5717169A (en) * | 1994-10-13 | 1998-02-10 | Schlumberger Technology Corporation | Method and apparatus for inspecting well bore casing |
US20060201711A1 (en) * | 1994-10-14 | 2006-09-14 | Vail William B Iii | Methods and apparatus for cementing drill strings in place for one pass drilling and completion of oil and gas wells |
US7147068B2 (en) * | 1994-10-14 | 2006-12-12 | Weatherford / Lamb, Inc. | Methods and apparatus for cementing drill strings in place for one pass drilling and completion of oil and gas wells |
US20050284661A1 (en) * | 1996-03-25 | 2005-12-29 | Goldman William A | Method and system for predicting performance of a drilling system for a given formation |
US20020093431A1 (en) * | 1998-08-28 | 2002-07-18 | Zierolf Joseph A. | Method and apparatus for determining position in a pipe |
US20040239521A1 (en) * | 2001-12-21 | 2004-12-02 | Zierolf Joseph A. | Method and apparatus for determining position in a pipe |
US7292942B2 (en) * | 2003-01-24 | 2007-11-06 | Schlumberger Technology Corporation | Measuring formation density through casing |
US20040210393A1 (en) * | 2003-01-24 | 2004-10-21 | Ellis Darwin V. | Measuring formation density through casing |
US7647182B2 (en) * | 2004-07-15 | 2010-01-12 | Baker Hughes Incorporated | Apparent dip angle calculation and image compression based on region of interest |
US7295928B2 (en) * | 2004-10-21 | 2007-11-13 | Baker Hughes Incorporated | Enhancing the quality and resolution of an image generated from single or multiple sources |
US20060106541A1 (en) * | 2004-10-21 | 2006-05-18 | Baker Hughes Incorporated | Enhancing the quality and resolution of an image generated from single or multiple sources |
US20070192074A1 (en) * | 2005-08-08 | 2007-08-16 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US20090090556A1 (en) * | 2005-08-08 | 2009-04-09 | Shilin Chen | Methods and Systems to Predict Rotary Drill Bit Walk and to Design Rotary Drill Bits and Other Downhole Tools |
US20090229888A1 (en) * | 2005-08-08 | 2009-09-17 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US20100300758A1 (en) * | 2005-08-08 | 2010-12-02 | Shilin Chen | Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk |
US7646480B2 (en) * | 2005-09-12 | 2010-01-12 | Schlumberger Technology Corporation | Borehole imaging |
US20070242265A1 (en) * | 2005-09-12 | 2007-10-18 | Schlumberger Technology Corporation | Borehole Imaging |
US20100133015A1 (en) * | 2007-03-27 | 2010-06-03 | Shilin Chen | Rotary Drill Bit with Improved Steerability and Reduced Wear |
US7710823B2 (en) * | 2007-04-04 | 2010-05-04 | Baker Hughes Incorporated | Resistivity measurement through metal casing using magnetic field and magnetoacoustic phenomena |
US20100163312A1 (en) * | 2007-05-30 | 2010-07-01 | Shilin Chen | Rotary Drill Bits with Gage Pads Having Improved Steerability and Reduced Wear |
US20100134112A1 (en) * | 2008-12-02 | 2010-06-03 | Hong Zhang | Detecting electrical current in a magnetic structure |
US20100252725A1 (en) * | 2009-04-02 | 2010-10-07 | Recon Petrotechnologies., Ltd. | Logging tool and method for determination of formation density |
US9322949B2 (en) * | 2010-04-19 | 2016-04-26 | Schlumberger Technology Corporation | System and method for generating density in a cased-hole wellbore |
Non-Patent Citations (6)
Title |
---|
Aulia et al., "Resistivity Behind Casing," Oildfield Review, Spring 2001, pages 2-25 * |
Cosentino et al., "Reevaluation of Hydrocarbon Reserves in Old Fields Through Cased-Hole Interpretation: A New Approach," 1992, SPE 22345, pages 167-175 * |
GoWell, "Through Casing Formation Resistivity Tool (TCFR)," November 2015, 2 pages * |
Jacobson et al., "Computer Simulation of Cased-Hole Density Logging," December 1990, SPE Formation Evaluation, pages 465-468 * |
Moake et al., "Design of a Cased-Hole-Density Logging Tool Using Laboratory Measurements," 1998, SPE 49226, pages 565-580 * |
Quint, "Monitoring Contact Movement during Deprssurization of the Brent Field," 1999, SPE 56951, pages 1-8 * |
Cited By (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20150285069A1 (en) * | 2014-04-04 | 2015-10-08 | Micro-G Lacoste, Inc. | High Resolution Continuous Depth Positioning in a Well Bore Using Persistent Casing Properties |
US9540927B2 (en) * | 2014-04-04 | 2017-01-10 | Micro-G Lacoste, Inc. | High resolution continuous depth positioning in a well bore using persistent casing properties |
US20170242152A1 (en) * | 2015-10-02 | 2017-08-24 | Halliburton Energy Services, Inc. | Logging-while-drilling tool with interleaved instruments |
US10782445B2 (en) * | 2015-10-02 | 2020-09-22 | Halliburton Energy Services, Inc. | Logging-while-drilling tool with interleaved instruments |
US11242740B2 (en) | 2017-11-17 | 2022-02-08 | Keystone Wireline, Inc. | Method of evaluating cement on the outside of a well casing |
Also Published As
Publication number | Publication date |
---|---|
US9175559B2 (en) | 2015-11-03 |
WO2010040045A3 (en) | 2010-07-22 |
US20110290011A1 (en) | 2011-12-01 |
WO2010040045A2 (en) | 2010-04-08 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US9175559B2 (en) | Identification of casing collars while drilling and post drilling using LWD and wireline measurements | |
CA2954657C (en) | Well ranging apparatus, systems, and methods | |
US7782709B2 (en) | Multi-physics inversion processing to predict pore pressure ahead of the drill bit | |
US8528636B2 (en) | Instantaneous measurement of drillstring orientation | |
AU770185B2 (en) | Multi-depth focused resistivity imaging tool for logging while drilling applications | |
CA2648698C (en) | Method and apparatus for determining formation resistivity ahead of the bit and azimuthal at the bit | |
US5899958A (en) | Logging while drilling borehole imaging and dipmeter device | |
US8015868B2 (en) | Formation evaluation using estimated borehole tool position | |
US20130301389A1 (en) | System And Method For Communicating Data Between Wellbore Instruments And Surface Devices | |
US20140216734A1 (en) | Casing collar location using elecromagnetic wave phase shift measurement | |
US11719090B2 (en) | Enhanced cement bond and micro-annulus detection and analysis | |
EP3724447B1 (en) | Systems and methods for downhole determination of drilling characteristics | |
CN103492659B (en) | The method and system of side well is drilled with in shale formation | |
US20110134719A1 (en) | Methods, apparatus and articles of manufacture to determine anisotropy indicators for subterranean formations | |
CN101460868A (en) | Method and apparatus for determining formation resistivity ahead of the bit and azimuthal at the bit | |
US10921486B2 (en) | Integrated logging tool | |
US11680479B2 (en) | Multiple surface excitation method for determining a location of drilling operations to existing wells | |
WO2012068205A2 (en) | Method and apparatus for determining the size of a borehole |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |