SYSTEM AND METHOD FOR LOCALIZED SEISMIC IMAGING AROUND WELLBORES

A method is described for localized seismic imaging around a wellbore. The method uses at least one non-conventional seismic source such as an electrical submersible pump to generate seismic signals which are reflected by the surrounding wellbore and rock formation and recorded by a fiber optic cable or downhole geophones. The seismic data is then processed and imaged to generate an image of the volume around the wellbore. The method may be executed by a computer system.

Not applicable.

TECHNICAL FIELD

The disclosed embodiments relate generally to techniques for seismic imaging around wellbores existing in subsurface reservoirs and, in particular, to a method of localized seismic imaging around a wellbore using a non-conventional seismic source.

BACKGROUND

Seismic exploration involves surveying subterranean geological media for hydrocarbon deposits. A survey typically involves deploying seismic sources and seismic sensors at predetermined locations on the surface or in the subsurface. The sources generate seismic waves, which propagate into the geological medium creating pressure changes and vibrations. Variations in physical properties of the geological medium give rise to changes in certain properties of the seismic waves, such as their direction of propagation and other properties.

Portions of the seismic waves reach the seismic sensors. Some seismic sensors are sensitive to pressure changes (e.g., hydrophones), others to particle motion (e.g., geophones, fiber optic cables), and industrial surveys may deploy one type of sensor or both. In response to the detected seismic waves, the sensors generate corresponding electrical or optical signals, known as traces, and record them in storage media as seismic data. Seismic data will include a plurality of “shots” (individual instances of the seismic source activating), each of which are associated with a plurality of traces recorded at the plurality of sensors.

Seismic data is often contaminated by “noise”. Noise may include any undesired seismic signals that reach the seismic sensors. For example, in marine seismic, this may include cavitation noises from host or passing ships. Although there have been examples of using ship noise as a seismic source (e.g., Davies, K., Hampson, G., Jakubowicz, H., Odegaard, J., 1992, Screw Seismic Sources. SEG Technical Program Expanded Abstracts 1992. January 1992, pages 710-711, which is incorporated by reference), it is not considered a standard source. In another example, when a well is being drilled, the drill-bit vibrations may be considered noise or may be used as a downhole seismic source (e.g., Rector J. M., 1990, Utilization of drill-bit vibrations as a downhole seismic source. A PhD dissertation submitted to the department of geophysics Stanford University available at https://pangea.stanford.edu/research/srb/docs/theses/SRB_44_SEP90_Rector.pdf, which is incorporated by reference). This drill-bit source may only be used during the drilling of the wellbore.

Seismic data is processed and imaged to create seismic images that can be interpreted to identify subsurface geologic features including hydrocarbon deposits. The ability to define the location of rock and fluid property changes in the subsurface is crucial to our ability to make the most appropriate choices for purchasing materials, operating safely, and successfully completing projects. Project cost is dependent upon accurate prediction of the position of physical boundaries within the Earth. Decisions include, but are not limited to, budgetary planning, obtaining mineral and lease rights, signing well commitments, permitting rig locations, designing well paths and drilling strategy, preventing subsurface integrity issues by planning proper casing and cementation strategies, and selecting and purchasing appropriate completion and production equipment.

There exists a need for improved localized seismic imaging around wellbores.

SUMMARY

In accordance with some embodiments, a method of detecting seismic waves is disclosed. The method includes detecting a first plurality of seismic waves generated while a first electric submersible pump (ESP), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within a first well. The first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof. The method includes recording seismic data for the first plurality of seismic waves detected by the at least one seismic sensor in an electronic storage.

In accordance with some embodiments, a system of detecting seismic waves is disclosed. The system includes a first electric submersible pump (ESP), a first logging tool, or any combination thereof within a first well. The system includes at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof to detect a first plurality of seismic waves generated while the first electric submersible pump (ESP), the first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well. The system includes an electronic storage to record seismic data for the first plurality of seismic waves detected by the at least one seismic sensor.

In accordance with some embodiments, a method of generating a digital seismic image is disclosed. The method includes obtaining first seismic data for a first plurality of seismic waves generated while a first electric submersible pump (ESP), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well. The first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof. The method includes generating a first digital seismic image of a subsurface using the first seismic data.

In accordance with some embodiments, a computer system of generating a digital seismic image is disclosed. The system includes one or more processors, memory, and one or more programs. The one or more programs are stored in the memory and configured to be executed by the one or more processors. The one or more programs include an operating system and instructions that when executed by the one or more processors cause the computer system to: obtain first seismic data for a first plurality of seismic waves generated while a first electric submersible pump (ESP), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well; and generate a first digital seismic image of a subsurface using the first seismic data. The first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof.

In accordance with some embodiments, a method of localized seismic imaging around a wellbore using non-conventional sources such as one or more electrical submersible pumps and a plurality of downhole seismic sensors such as a fiber optic cable is disclosed.

DETAILED DESCRIPTION OF EMBODIMENTS

Described below are methods and systems of detecting seismic waves. One embodiment of a method of detecting seismic waves includes detecting a first plurality of seismic waves generated while a first electric submersible pump (ESP), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within a first well; and recording seismic data for the first plurality of seismic waves detected by the at least one seismic sensor in an electronic storage (e.g., memory, USB, disk). The first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof. The detected seismic waves may be utilized to generate one or more digital seismic images, for example, for imaging of subsurface volumes adjacent to a wellbore, for localized seismic imaging around a wellbore (e.g., within one meter around the wellbore to several kilometers around the wellbore), etc.

Described below are methods, systems, and computer readable storage media that provide a manner of seismic imaging. One embodiment of a method of generating a digital seismic image includes obtaining first seismic data for a first plurality of seismic waves generated while a first electric submersible pump (ESP), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well; and generating a first digital seismic image of a subsurface using the first seismic data. The first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof. These embodiments are designed to be of particular use for seismic imaging of subsurface volumes adjacent to a wellbore. For example, the principles of the present invention includes embodiments of a method and system for localized seismic imaging around a wellbore.

Non-Conventional Seismic Source: Electrical Submersible Pumps (ESP's) are commonly deployed down hole in the oil and gas industry to manage fluid and gas flow. ESP's emit acoustic energy typically classed as “noise”. For example, the noise may be from electrical hum, bearing rumble, cavitation, fluid and gas flow, or any combination thereof (e.g., (i) Davies, K., Hampson, G., Jakubowicz, H., Odegaard, J., 1992, Screw Seismic Sources. SEG Technical Program Expanded Abstracts 1992. January 1992, pages 710-711, (ii) CA2087908, and (iii) EP0553053, each of which is incorporated by reference). This invention disclosure concerns use of noise from non-conventional seismic sources such as ESPs as the seismic source energy (signal) in conjunction with downhole seismic receivers (also referred to as seismic sensors) for imaging in and around the wellbore. Although ESPs are described as the seismic source in an embodiment, this is not meant to be limiting; any non-conventional seismic source that generates seismic energy i.e., acoustic or elastic waves, e.g., fluid cavitating, bubble pulses, mechanical devices, resulting tube waves, earthquakes, passive seismicity, migration of particles (e.g., sand ingress), or any combination thereof is within the scope of this method. Indeed, another example of a non-conventional seismic source is a logging tool, such as in wireline logging.

Electrical hum, bearing rumble, cavitation, fluid and gas flow, or any combination thereof may all generate more than a single fundamental frequency. Turning to cavitation, ESP suction side, pressure side, and/or tip vortex cavitation are naturally broad band and can include frequencies that otherwise require manipulation to generate (e.g., (i) Davies, K., Hampson, G., Jakubowicz, H., Odegaard, J., 1992, Screw Seismic Sources. SEG Technical Program Expanded Abstracts 1992. January 1992, pages 710-711, which is incorporated by reference). Electrical hum and bearing rumble are also not necessarily mono-frequencies emitters, as in addition to fundamental frequency, this system naturally generates harmonics. Furthermore, non-linear superposition from multiple natural frequency emitters enables more frequencies than the parts resulting in further broadening of the spectrum, for example, from multiple ESPs running together. Fluid and gas flow is broad band, but potentially low power noise. The noise from fluid and gas flow may be utilized as a non-conventional source by measuring over long periods to overcome low power.

As will be described further herein, a plurality of seismic waves is generated while one or more non-conventional seismic sources (e.g., one or more ESPs, one or more logging tools, or any combination thereof) is running at its operating frequency or operating frequencies within a well. The operating frequencies may be higher than 0 Hertz to about 900 Hertz for the non-conventional source(s). Some embodiments consistent with the present disclosure intend to make use of ESP(s) already in place in a well and/or deployed for independent primary use (i.e., fluid production control). There is no requirement to interfere with the primary use or equipment, whether during ESP installation or during ESP operation. Similarly, some embodiments consistent with the present disclosure intend to make use of logging tool(s) already in place in a well and/or deployed for independent primary use (i.e., logging). There is no requirement to interfere with the primary use or equipment, whether during logging tool installation or during logging tool operation. Examples of logging tools include, but are not limited to, logging while drilling (LWD) tools, measure while drilling (MWD) tools, nuclear magnetic resonance (NMR) logging tools, wireline tools, etc.

Seismic Sensor: A “seismic sensor” or “seismic receiver” refers to practically anything that detects seismic waves. In some embodiments, at least one seismic sensor comprises fiber optic distributed sensing, such as, but not limited to, a fiber optic cable configured for distributed acoustic sensing (DAS). In some embodiments, at least one seismic sensor comprises one or more fiber optic cables configured for DAS (also referred to as DAS fiber optic cable). In some embodiments, at least one seismic sensor comprises one or more geophones, one or more accelerometers, one or more point sensors, or any combination thereof. A single well may include a single seismic sensor or a plurality of seismic sensors, for example, a single well may include a single fiber optic cable configured for DAS or a plurality of fiber optic cables configured for DAS (e.g., a helical wound fiber optic cable configured for DAS and another fiber optic cable that is not helically wound configured for DAS).

Of note, there is no requirement to connect the “seismic sensor” (e.g., fiber optic cable configured for DAS) to the “non-conventional source” (e.g., ESP, logging tool). For example, a fiber optic cable configured for DAS that is already deployed in the same well as an ESP may be utilized, and the fiber optic cable is not connected to the ESP. Moreover, a seismic sensor may even be deployed in an adjacent well or adjacent wells to the well with the ESP in this example. In some embodiments, the seismic sensor, such as the fiber optic cable configured for DAS, has no electrical connectivity requirements and it is purely optical.

Of note, it should be understood that the fiber optic cable discussed herein is configured for DAS, even if the terminology “configured for DAS” is not utilized each time. For example, the fiber optic cable configured for DAS detects a plurality of seismic waves that is generated while an ESP, a logging tool, or any combination thereof is running at its operating frequency or operating frequencies within a well. The fiber optic cable may detect during ESP ramp up or ESP ramp down. In some embodiments, the fiber optic cable may also be configured to perform distributed temperature sensing (DTS). In some embodiments, the fiber optic cable may also be configured to perform distributed pressure sensing (DPS). In some embodiments, the fiber optic cable may also be configured to perform distributed strain sensing (DSS). Indeed, the fiber optic cable may perform DPS, DTS, DSS, or any combination thereof, as well DAS, depending on the embodiment.

A previously installed fiber optic cable may already be configured for DAS (and optionally DPS and/or optionally DTS and/or optionally DSS), and this previously installed fiber optic cable may be utilized herein. Alternatively, a new fiber optic cable configured for DAS (and optionally DPS and/or optionally DTS and/or optionally DSS) may be installed. The techniques and equipment to be used to install the fiber optic cable may depend on whether the fiber optic cable is to be installed in a permanent, pumpable, or temporary manner, as well as the location where the fiber optic cable is to be installed. For example, the equipment may include clamps, straps, reels, within cement, etc., but for simplicity, the items related to installing the fiber optic cable will just be referred herein as “fiber optic installation apparatus.”

The fiber optic cable may include one or more scatterers. The fiber optic cable may include one or more diffractors. The fiber optic cable may include one or more reflectors. The fiber optic cable includes one or more optical fibers used for DAS. In one embodiment, an unmodified, substantially continuous length of standard optical fiber may be used, requiring little or no modification or preparation for use as a DAS optical fiber. The fiber optic cable configured for DAS may optionally include one or more optical fibers for DPS and/or may optionally include one or more optical fibers for DTS, and/or may optionally include one or more optical fibers for DSS. Thus, the fiber optic cable includes at least one optical fiber that may be, but is not limited to: one or more optical fibers used for DAS, one or more optical fibers for DPS, one or more optical fibers used for DTS, one or more optical fibers used for DSS, or any combination thereof. The optical fibers may include multimode optical fibers, single mode optical fibers, etc.

Each DAS optical fiber of the fiber optic cable may be optically interrogated by one or more input pulses to provide substantially continuous sensing of strain or vibrational activity along its length. An interrogator (e.g., at the surface) may be connected to the DAS optical fiber for the interrogation. The DAS optical fiber may be either single-mode or multimode. Optical pulses are launched into the DAS optical fiber and the radiation backscattered from within the DAS optical fiber is detected and analyzed. Backscattering (e.g., Rayleigh backscattering) analysis is used to quantify vibration, seismic waves, sound, strain, etc. By analyzing the radiation backscattered within the DAS optical fiber, the DAS optical fiber can effectively be divided into a plurality of sensing portions or points which may be (but do not have to be) contiguous. Mechanical vibrations of the DAS optical fiber, for instance from the non-conventional seismic sources, cause a variation in the amount of backscatter (e.g., Rayleigh backscatter) from that portion. This variation can be detected and analyzed and used to give a measure of the acoustic spectrum intensity of disturbance of the DAS optical fiber at that portion. In some embodiments, the term “acoustic” may be taken to mean any type of mechanical vibration or pressure wave, including seismic waves and sounds from sub-Hertz to 20 KHz. Besides the intensity (amplitude) and distance, other factors that can be measured include frequency, phase, duration, and signal evolution of the transients.

In short, the fiber optic cable may be coupled to an interrogator. The interrogator may be on the surface (e.g., land surface, on a sea surface vessel), or the interrogator may even be a “marinized interrogator” such as on the seafloor. The interrogator contains opto-electronic components. The interrogator provides light (e.g., laser light) into the fiber optic cable and receives the backscatter energy from the fiber optic cable. For example, one or more non-conventional seismic sources causes strain, and the strain causes the backscatter energy from the fiber optic cable. The interrogator converts the backscatter energy into arrival times and generates DAS data that includes the arrival times. The DAS data may be sent from the interrogator to at least one computer system for processing. The DAS data may be stored in electronic storage in the interrogator, in at the least one computer system, etc. In some embodiments, the DAS data (before processing, during processing, or after processing) may be combined with other data (e.g., ground truth data, core data, etc.). Thus, the seismic signal detected by the fiber optic cable is recorded in electronic storage at the interrogator as a seismic dataset and then the recorded seismic data may be sent from the interrogator to a computer system for processing at the computer system.

Fiber Optic Cable/Core: Turning to a more detailed discussion about the structure of the fiber optic cable, the fiber optic cable includes at least one optical fiber that may be surrounded by at least one protective layer to shield the at least one optical fiber against the environment. One embodiment of the fiber optic cable comprises a capillary tubing (also referred to as capillary tube) to house the at least one optical fiber. The capillary tubing may be filled with a fluid, e.g., a hydrogen scavenging gel, an inert heat transfer fluid, or an inert gas. In one embodiment, the filling fluid is a gel designed to scavenge hydrogen and protect the at least one optical fiber from hydrogen darkening. The gel also helps to support the weight of the at least one optical fiber within the capillary tubing. In another embodiment, the capillary tubing is filled with an inert gas such as nitrogen to avoid exposure of the at least one optical fiber to water or hydrogen, thereby minimizing any hydrogen-induced darkening of the at least one optical fiber during oilfield operations. In one embodiment, a single capillary tubing is used, which contains a plurality of optical fibers. In another embodiment, multiple capillary tubings may be used, with each capillary tubing containing one or more optical fibers.

A variety of installation options may be utilized: permanent, pumpable, or temporary. With the pumpable option, two capillary tubings are used to enable pumping fluid to be pumped down the capillary tubing and returned to the surface. A turnaround sub with a U-tube geometry is used at the deepest wellbore placement to join the two capillary tubings and enable pumping. The viscous drag force of the pumped fluid on the at least one optical fiber enables recovery and replacement. The pumping of the at least one optical fiber may occur in a factory, controlled surface environment, or at the wellsite with the at least one optical fiber in the wellbore. The pumpable option may be used if one or two optical fibers are used. The pumpable option allows the at least one optical fiber to be recovered and replaced should it experience hydrogen darkening.

With the permanent option, at least one optical fiber is installed inside a capillary tubing in a factory or controlled environment. If a permanently installed optical fiber becomes damaged due to hydrogen darkening or thermal degradation, the recourse is a complete replacement. The permanent and pumpable options may strap or clamp the capillary tubing to the outside of casing, liners, and tubing, or installed inside a coiled tubing instrument tube.

With the temporary option, at least one optical fiber is run into a wellbore off a reeling system into the tubing or into a coiled tubing instrument tube. The coiled tubing instrument tube could be free hanging in the tubing-casing annulus or strapped to the tubing, casing, or liner. The temporary deployable optical fiber may use a small diameter FIMT (fiber in metal tube) with an outside diameter of 0.09 to 0.15 inches, which is reinforced with fiber glass, polyproylene, polyethylene, carbon fiber, or any combinations of the foregoing which encases and protects the FIMT. This temporary option is designed to be run in and out of many wellbores and installed for a few hours to a few weeks to acquire data.

Some installation options may depend on whether a wellbore is existing or new. In one embodiment, for an existing wellbore, installation may be inside the liner or casing on the tubing or coiled tubing to take advantage of the preexisting structure. However, for a newly drilled wellbore, installation may be either inside or outside the liner or casing with trade-offs between cost, risk, etc.

In short, those of ordinary skill in the art will appreciate that various installation options are available. In one embodiment, the capillary tubing may be attached to the outer surface of the tubing with a plurality of clamps, or any known method for coupling conduits. Further, in some embodiments, it should be appreciated that the capillary tubing need not be coupled to the tubing, but it may be coupled to any other conduits in the wellbore or the casing/liner itself, or it may be integral with the casing/liner, e.g., the capillary tubing may be positioned in the annulus, clamped/strapped/fastened to any of the tubing, inside the tubing, the liner, the casing, the instrument coiled tubing, or any combination thereof. Thus, the installation scheme that is chosen may depend upon whether the wellbore is new or preexisting, components of the wellbore, etc.

Wellbore: Turning toFIGS. 1A-1C,FIG. 1Ais a diagram of an electrical submersible pump as a downhole seismic source, in accordance with some embodiments. A portion of a wellbore105having an ESP107is illustrated. The wellbore105may contain the tubing145and will contain the casing (e.g., a surface casing120and/or a production casing125referred to as casing120,125) with cement106between the casing120,125and surrounding rock101(also referred to as subsurface). Inside the tubing145is the ESP107. Coupled to the tubing145is a fiber optic cable178(or fiber core185). The fiber optic cable178(or fiber core185) may be outside the casing (cemented between casing120,125and rock101), lose inside the casing120,125, clamped to the outside of the tubing145, loose inside the tubing145, or even built into the casing or tubing material. The fiber optic cable178(or fiber core185) is connected to the distributed acoustic sensing (DAS) interrogator108.

At step A, the ESP107generates an acoustic or elastic wavefield109while the ESP107is running at its operating frequency or operating frequencies. At step B, the acoustic or elastic wavefield109refracts or reflects at interfaces in the cement106and/or rock101. At step C, the returning acoustic or elastic wavefield111is detected on the fiber optic cable178(or fiber core185). At step D, the seismic signal detected by the fiber optic cable178(or fiber core185) is recorded at the DAS interrogator108as a seismic dataset. The seismic signal detected by the fiber optic cable178(or fiber core185) may be recorded in an electronic storage at the DAS interrogator108as the seismic dataset and then the recorded seismic data may be sent from the DAS interrogator108to a computer system500(FIG. 5) for processing at the computer system500. Although this figure shows the seismic signal being recorded by the fiber optic system, the seismic signal may also be recorded by downhole electrical sensors such as accelerometers or geophones. One or more fiber optic cables, one or more accelerometers, one or more geophones, one or more point sensors, and/or other seismic sensors may be deployed and utilized in the wellbore105in some embodiments.

FIG. 1Bis a cross-sectional view of one embodiment of the wellbore inFIG. 1A, withFIG. 1Aillustrating a vertical trajectory andFIG. 1Billustrating a horizontal trajectory. The wellbore105is a horizontal wellbore inFIG. 1Band it includes a vertical section110, the build section112, and a horizontal section115. The area between the vertical section110and the horizontal section115is referred to as the heel and the area towards the end of the horizontal section115is referred to as the toe. For example, unconventional reservoirs may be produced using horizontal wellbores, such as the wellbore105.

The wellbore105may be drilled with at least one drilling apparatus113through a surface140(e.g., terrestrial surface, seafloor, etc.) and into the rock101(e.g., subsurface). The drilling apparatus113may include a drill bit, a drill string, etc. The wellbore105may be cemented as illustrated by cement106. The wellbore105may include a surface casing120along a portion of the wellbore105, a production casing125along a portion of the wellbore105, and a liner130(e.g., a slotted liner) attached by at least one liner hanger132. The wellbore105may also include a tubing145within the surface casing120, the production casing125, and the liner130. The tubing145may be of standard sizes known in the industry (e.g., outermost diameter of 2⅜ inches to 4.5 inches) for standard and commonly known casing sizes (e.g., outermost diameter of 4½ inches to 12 inches), each of which have lengths in the tens to hundreds of feet. The tubing145includes a plurality of tubulars tubing joints, pup joints, packers (e.g., may include centralizers), etc. The end of the tubing145(e.g., at the toe) includes a bull plug150. At least one packer170may be located in an annulus169between the tubing145and the liner130.

In operation, the wellbore105may be utilized for hydrocarbon production, including waterflooding, etc. For example, water may enter the tubing145, and the water is injected into the adjacent rock101through flow control devices, perforations, etc. The hydrocarbons from the rock101flow into the wellbore105and up towards the surface140for refining, transporting, etc.

Those of ordinary skill in the art will appreciate that various modifications may be made to the wellbore105. For example, the wellbore105may simply be a vertical wellbore, instead of a horizontal wellbore, in a different embodiment. Examples of vertical wellbores are provided inFIG. 1Aas well as U.S. Patent Application Publication No. 2014/0288909 (Attorney Dkt. No. T-9407) and U.S. Patent Application Publication No. 2017/0058186 (Attorney Dkt. No. T-10197), each of which is incorporated by reference in its entirety. Furthermore, a plurality of wellbores, instead of the single wellbore105illustrated inFIG. 1B, may be drilled through the surface140and into the rock101.

Fiber Optic Cable—Capillary Tubing: One embodiment of the fiber optic cable178comprises a capillary tubing180.FIG. 1Cillustrates an expanded view, in cross-section, of the capillary tubing180. The capillary tubing180is one embodiment of the fiber optic cable178, however, those of ordinary skill in the art will appreciate that there are other designs and the appended claims are not limited to any disclosed embodiments. The capillary tubing180may have a length of tens of feet to hundreds of feet. For example, the capillary tubing180may be practically the entire length of the wellbore105, or optionally, a portion of the entire length of the wellbore105. The outer diameter of the capillary tubing180may be about ⅛ inches to about ⅜ inches. The outer diameter of the capillary tubing180may be about ¼ inches. The dimensions of the capillary tubing180may vary as long as the wavefield is detected to record seismic data.

Starting from the inside, the capillary tubing180includes the core185comprised of a first protective layer that is typically of an Inconel® or Incoloy® alloy 25, a stainless steel, or any combination thereof with at least one optical fiber186with at least one sensing portion inside the core185. One or more of the optical fibers186is a DAS optical fiber, but other sensing capabilities, such as DPS and/or DTS, may be available in some embodiments. The optical fibers186may have high temperature coatings and coating combinations, including polyimide, high temperature acrylates, silicone-PFA, hermetic carbon, or any combination thereof to prevent hydrogen darkening. The core185may be filled with fluid, and the fluid surrounds each optical fiber186. The fluid may be a gel or inert gas as discussed hereinabove. The inner diameter of the core185may be about 0.05 inches to about 0.10 inches. The combination of the first protective layer and the optical fiber(s) is commonly referred to as a FIMT or fiber in metal tube. The length of the core185depends on the length of the capillary tubing180.

Adjacent to the core185may be an optional second protective layer187, which may be of a metallic material such as aluminum. The diameter of the second protective layer187is optional, but may be about 0.10 inches to about 0.20 inches. The length of the second protective layer187depends on the length of the capillary tubing180.

Adjacent to the optional second protective layer187may be a third protective layer188, which may be of a metallic material (e.g., Inconel® or Incoloy® alloy 25, a stainless steel, or any combination thereof). The diameter of the third protective layer188may be about 0.20 inches to about 0.40 inches. The length of the third protective layer188depends on the length of the capillary tubing180.

Adjacent to the third protective layer188may be an encapsulation protective layer189, which is an extruded encapsulation polymer (e.g., polyethylene, polypropolyene, Teflon™ brand, Hypalon™ brand, or any combination thereof). The diameter of the encapsulation protective layer189may be about 0.25 inches to about 0.75 inches. The length of the encapsulation protective layer189depends on the length of the capillary tubing180.

Fiber Optic Cable—Capillary Tubing Clamped to Liner:FIGS. 2A-1 and 2A-2illustrate an embodiment with a hydraulic wet connect at liner top131with the capillary tubing180being clamped to the tubing145above the liner top131. There may be one or more of the capillary tubing180. In the embodiment ofFIGS. 2A-1 and 2A-2, the capillary tubing180may be installed outside of the liner130in the horizontal section115of the wellbore105, and clamped on the tubing145in the vertical section110. The capillary tubing180includes the core185and at least one optical fiber186is inside the core185. One or more of the optical fibers186is a DAS optical fiber. The optical fiber186ofFIG. 1C(e.g., the DAS fiber, etc.) may be permanently installed in the capillary tubing180or can be pumped and retrieved through pumping to/from the capillary tubing180. The hydraulic wet connect is used to connect the optical fiber186in the horizontal section115and the vertical clamped section110. The tubing145can be run in and out of the wellbore without damaging the optical fiber186in the horizontal section115. This setup may include at least one packer170.

Fiber Optic Cable—Capillary Tubing Clamped to Casing:FIGS. 2B-1 and 2B-2illustrate an embodiment in which the capillary tubing180may be clamped to the casing, such as the production casing125. There may be one or more of the capillary tubing180. The installation scheme ofFIGS. 2B-1 and 2B-2is similar to the liner deployed surveillance scheme ofFIGS. 2A-1 and 2A-2. As illustrated, the complete system is installed outside of the casing125. The capillary tubing180is clamped to the casing125as the casing125is installed into the wellbore105. The capillary tubing180includes the core185and at least one optical fiber186is inside the core185. One or more of the optical fibers186is a DAS optical fiber. The optical fiber186may be retrieved and replaced when designed with the pumpable option. In another embodiment, a single capillary tubing180may be run with single or multiple permanent optical fibers186. The perforations may be shot 180 degrees away from the capillary tubing180. The capillary tubing180may be run with ½ inch steel cables on either side of the ¼ inch capillary tubing180to facilitate electro-magnetic orienting of perforating guns. This setup may include at least one packer170.

Fiber Optic Cable—Capillary Tubing Clamped to Tubing:FIGS. 2C-1 and 2C-2illustrate an embodiment in which the capillary tubing180may be clamped to the tubing145. There may be one or more of the capillary tubing180. In one embodiment of this scheme, the capillary tubing180is only clamped on the tubing145and no other component. In another embodiment, the capillary tubing180may be installed inside the tubing145. The capillary tubing180includes the core185and at least one optical fiber186is inside the core185. One or more of the optical fibers186is a DAS optical fiber. The installation scheme in this setup is flexible, which facilitates the changes in the optical fiber186design and specifications. Additionally, the optical fiber186and capillary tubing180are retrievable. This setup may include at least one packer170, and the capillary tubing180may penetrate through each packer170.

Fiber Optic Cable—Capillary Tubing inside Instrument Coiled Tubing:FIGS. 2D-1 and 2D-2illustrate an embodiment in which the capillary tubing180may be positioned within an instrument coiled tubing190. There may be one or more of the capillary tubing180. In one embodiment, the scheme ofFIGS. 2D-1 and 2D-2is used as a temporary surveillance method (e.g., for a few days) so there is less chance of fiber degradation and capillary tubing corrosion. In another embodiment, the scheme works best with a larger size of liner130or casing125to avoid damage to the optical fiber186and sticking in the wellbore105. The capillary tubing180includes the core185and at least one optical fiber186is inside the core185. One or more of the optical fibers186is a DAS optical fiber. The scheme ofFIGS. 2D-1 and 2D-2is flexible, allowing retrieval of optical fiber186/capillary tubing180. This setup may not include any packers170.

FIGS. 1A, 1B, 1C, 2A-1, 2A-2, 2B-1, 2B-2, 2C-1, 2C-2, 2D-1, and 2D-2are not necessarily drawn to scale and those of ordinary skill will appreciate that various modifications may be made. Those of ordinary skill in the art will appreciate that the embodiments of the fiber optic cable provided herein are non-limiting, and for example, a fiber optic cable may include at least one core (e.g., single core, multicore), at least one optical fiber (e.g., a DAS optical fiber), other components, etc. As another example, dimensions, materials, components, connectors, etc. may vary and may be based, for example, on compatibility with the conditions on and under the surface 140. Fiber optics are also discussed in U.S. Pat. No. 10,344,585 (Attorney Dkt. No. T-10077), U.S. Pat. No. 10,233,744 (Attorney Dkt. No. T-10089), and U.S. Pat. No. 10,233,745 (Attorney Dkt. No. T-10242), each of which is incorporated by reference. A discussion of fiber optics in a marine environment is provided in U.S. Patent App. Pub. No. 2018/0100939 (Attorney Dkt. No. T-10466) and U.S. Pat. No. 11,079,508 (Attorney Dkt. No. T-10608), which is incorporated by reference in its entirety. An additional discussion of fiber optics is provided in U.S. Patent App. Pub. No. 2018/0031734 (Attorney Dkt. No. T-10258), U.S. Patent App. Pub. No. 2019/0339408 (Attorney Dkt. No. T-10792), and U.S. Pat. No. 10,901,103 (T-10476), each of which is incorporated by reference in its entirety.

Turning toFIG. 3, this figure is a diagram of multiple electrical submersible pumps as downhole seismic sources, in accordance with some embodiments.FIG. 3is similar toFIG. 1Awith the addition of a second ESP. The differences are illustrated with an apostrophe.FIG. 3illustrates a portion of a wellbore105′ having an ESP107′. The wellbore105′ may contain the tubing145′ and will contain the casing (e.g., a surface casing120′ and/or a production casing125′ referred to as casing120′,125′) with cement106′ between the casing120′,125′ and surrounding rock101(also referred to as subsurface). Inside the tubing145′ is the ESP107′. Coupled to the tubing145′ is a fiber optic cable178′ (or fiber core185′). The fiber optic cable178′ (or fiber core185′) may be outside the casing (cemented between casing120′,125′ and rock101), lose inside the casing120′,125′, clamped to the outside of the tubing145′, loose inside the tubing145′, or even built into the casing or tubing material. The fiber optic cable178′ (or fiber core185′) is connected to the distributed acoustic sensing (DAS) interrogator108′.

At step A′, the ESP107′ generates an acoustic or elastic wavefield109′ while the ESP107′ is running at its operating frequency or operating frequencies. At step B′, the acoustic or elastic wavefield109′ refracts or reflects at interfaces in the cement106′ and/or rock101. At step C′, the returning acoustic or elastic wavefield (not shown) is detected on the fiber optic cable178′ (or fiber core185′). At step E, the acoustic or elastic wavefield109from ESP107is detected on the fiber optic cable178′ (or fiber core185′). At step D′, the seismic signal detected by the fiber optic cable178′ (or fiber core185′) is recorded at the DAS interrogator108′ as a seismic dataset. The seismic signal detected by the fiber optic cable178′ (or fiber core185′) may be recorded in an electronic storage at the DAS interrogator108′ as the seismic dataset and then the recorded seismic data may be sent from the DAS interrogator108′ to the computer system500(FIG. 5) for processing at the computer system500.

At step A, the ESP107generates an acoustic or elastic wavefield109while the ESP107is running at its operating frequency or operating frequencies. At step B, the acoustic or elastic wavefield109refracts or reflects at interfaces in the cement106and/or rock101. At step C′, the returning acoustic or elastic wavefield (not shown) is detected on the fiber optic cable178(or fiber core185). Furthermore, at step E′, the acoustic or elastic wavefield109′ from ESP107′ is detected on the fiber optic cable178(or fiber core185). At step D, the seismic signal detected by the fiber optic cable178(or fiber core185) is recorded at the DAS interrogator108as a seismic dataset. The seismic signal detected by the fiber optic cable178(or fiber core185) may be recorded in an electronic storage at the DAS interrogator108as the seismic dataset and then the recorded seismic data may be sent from the DAS interrogator108to the computer system500(FIG. 5) for processing at the computer system500.

Although this figure shows the seismic signal being recorded by the fiber optic system, the seismic signal may also be recorded by downhole electrical sensors such as accelerometers or geophones. Those of ordinary skill in the art will appreciate that various modification/variations are within the principles of the present invention. Indeed, one or more seismic sensors such as one or more fiber optic cables, one or more accelerometers, one or more geophones, one or more point sensors, and/or other seismic sensors may be utilized in the wellbore105in some embodiments. One or more seismic sensors such as one or more fiber optic cables, one or more accelerometers, one or more geophones, one or more point sensors, and/or other seismic sensors may be utilized in the wellbore105′ in some embodiments. One or more seismic sensors such as one or more fiber optic cables, one or more accelerometers, one or more geophones, one or more point sensors, and/or other seismic sensors may be utilized in each wellbore105and wellbore105′ in some embodiments. One or more non-conventional seismic sources such as one or more ESPs, one or more logging tool, and/or other non-conventional seismic sources may be utilized in the wellbore105in some embodiments. One or more non-conventional seismic sources such as one or more ESPs, one or more logging tool, and/or other non-conventional seismic sources may be utilized in the wellbore105′ in some embodiments. One or more non-conventional seismic sources such as one or more ESPs, one or more logging tool, and/or other non-conventional seismic sources may be utilized in each wellbore105and wellbore105′ in some embodiments. Furthermore, mixing of non-conventional seismic sources in a single well is contemplated. As an example, this disclosure contemplates running at least one tool down the inside of a tubing while one or more ESPs are at least in place, if not running. Similarly, mixing of seismic sensors in a single well is also contemplated.

FIG. 4is a flowchart that illustrates one embodiment of a method of detecting seismic waves, illustrated as method400. At step405, the method400includes detecting a first plurality of seismic waves (e.g.,109inFIG. 3) generated while a first electric submersible pump (ESP) (e.g.,107inFIG. 3), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within a first well (e.g.,105inFIG. 3). The first plurality of seismic waves (e.g.,109inFIG. 3) is detected using at least one seismic sensor comprising a seismic sensor within the first well (e.g.,178inFIG. 3), a seismic sensor within a second well (e.g.,178′ inFIG. 3), a seismic sensor on a surface, or any combination thereof.

At step410, the method400includes recording seismic data for the first plurality of seismic waves (e.g.,109inFIG. 3) detected by the at least one seismic sensor in an electronic storage (e.g., DAS interrogator108and/or electronic storage thereof inFIG. 3). The electronic storage may be practically any electronic storage for storing data, such as, but not limited to, the memory506described in the context ofFIG. 5. The electronic storage may be a memory, USB, disk, etc.

At step415, the method400includes detecting a second plurality of seismic waves (e.g.,109′ inFIG. 3) generated while a second electric submersible pump (ESP) (e.g.,107′ inFIG. 3), a second logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the second well (e.g.,105′ inFIG. 3). The second plurality of seismic waves (e.g.,109′ inFIG. 3) is detected using the at least one seismic sensor comprising the seismic sensor within the first well (e.g.,178inFIG. 3), the seismic sensor within the second well (e.g.,178′ inFIG. 3), the seismic sensor on the surface, or any combination thereof.

At step420, the method400includes recording seismic data for the second plurality of seismic waves (e.g.,109′ inFIG. 3) detected by the at least one seismic sensor in the electronic storage (e.g., DAS interrogator108′ and/or electronic storage thereof inFIG. 3). The electronic storage may be practically any electronic storage for storing data, such as, but not limited to, the memory506described in the context ofFIG. 5. The electronic storage may be a memory, USB, disk, etc.

At step425, the method400includes detecting a second plurality of seismic waves generated while a second electric submersible pump (ESP), a second logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well. For example,FIG. 3may include a plurality of the ESP107in the wellbore105and each ESP107generates a wavefield such as the wavefield109. The second plurality of seismic waves is detected using the at least one seismic sensor comprising the seismic sensor within the first well (e.g.,178inFIG. 3), the seismic sensor within the second well (e.g.,178′ inFIG. 3), the seismic sensor on the surface, or any combination thereof.

At step430, the method400includes recording seismic data for the second plurality of seismic waves detected by the at least one seismic sensor in the electronic storage (e.g., DAS interrogator108and/or electronic storage thereof inFIG. 3). The electronic storage may be practically any electronic storage for storing data, such as, but not limited to, the memory506described in the context ofFIG. 5. The electronic storage may be a memory, USB, disk, etc.

Some embodiments may even include a plurality of seismic sensors such as a plurality of the fiber optic cable178in the wellbore105inFIG. 3. Some embodiments may even include a plurality of seismic sensors such as a plurality of the fiber optic cable178′ in the wellbore105′ inFIG. 3.

Various modification may be made to the method400. Some embodiments may include405,410,415,420,425, and430depending on the implementation. Some embodiments may include405,410,415, and420depending on the implementation. Some embodiments may include405,410,425, and430depending on the implementation. Some embodiments may include405and410depending on the implementation.

Processing/Imaging: This localized seismic imaging around the wellbore has potential use in wellbore cement quality determination, wellbore integrity evaluation, and potentially static imaging or time lapse imaging (monitoring) of rocks and reservoir.

The seismic dataset recorded by the system ofFIG. 1AandFIG. 3using the ESP107and/or ESP107′ as a seismic source may be processed and imaged by: 1) Near field source signature estimation local to ESP via accelerometer, geophone or fiber optic DAS channel. Data received on single or multiple down hole accelerometers, geophones or fiber optic DAS channels, wave field deconvolved using estimated source signature and wave field imaged. 2) Near field source signature estimation cross-correlated with data received on single or multiple down hole accelerometers, geophones or fiber optic DAS channels, and wave field imaged. 3) Use of interferometry from one or more ESP's and multiple accelerometers, geophones or fiber optic channels for wavefield imaging.

FIG. 5is a block diagram illustrating a seismic imaging system500, in accordance with some embodiments. While certain specific features are illustrated, those skilled in the art will appreciate from the present disclosure that various other features have not been illustrated for the sake of brevity and so as not to obscure more pertinent aspects of the embodiments disclosed herein.

To that end, the seismic imaging system500includes one or more processing units (CPUs)502, one or more network interfaces508and/or other communications interfaces503, memory506, and one or more communication buses504for interconnecting these and various other components. The seismic imaging system500also includes a user interface505(e.g., a display505-1and an input device505-2). The communication buses504may include circuitry (sometimes called a chipset) that interconnects and controls communications between system components. Memory506includes high-speed random access memory, such as DRAM, SRAM, DDR RAM or other random access solid state memory devices; and may include non-volatile memory, such as one or more magnetic disk storage devices, optical disk storage devices, flash memory devices, or other non-volatile solid state storage devices. Memory506may optionally include one or more storage devices remotely located from the CPUs502. Memory506, including the non-volatile and volatile memory devices within memory506, comprises a non-transitory computer readable storage medium and may store seismic data recorded by the system depicted inFIG. 1AandFIG. 3.

In some embodiments, memory506or the non-transitory computer readable storage medium of memory506stores the following programs, modules and data structures, or a subset thereof including an operating system516, a network communication module518, and a seismic imaging module520.

The operating system516includes procedures for handling various basic system services and for performing hardware dependent tasks.

The network communication module518facilitates communication with other devices via the communication network interfaces508(wired or wireless) and one or more communication networks, such as the Internet, other wide area networks, local area networks, metropolitan area networks, and so on.

In some embodiments, the seismic imaging module520performs seismic data processing and seismic imaging of seismic data recorded using an ESP, logging tool, or any combination thereof as a seismic source. Seismic imaging module520may include data sub-module525, which handles the seismic dataset recorded by the system ofFIG. 1AandFIG. 3. This data is supplied by data sub-module525to other sub-modules.

Processing sub-module522contains a set of instructions522-1and accepts metadata and parameters522-2that will enable it to perform any seismic data processing required to prepare the data for imaging. The imaging sub-module523contains a set of instructions523-1and accepts metadata and parameters523-2that will enable it to perform seismic imaging, such as migration. Although specific operations have been identified for the sub-modules discussed herein, this is not meant to be limiting. Each sub-module may be configured to execute operations identified as being a part of other sub-modules, and may contain other instructions, metadata, and parameters that allow it to execute other operations of use in processing data and generating images. For example, any of the sub-modules may optionally be able to generate a display that would be sent to and shown on the user interface display505-1. In addition, any of the data or processed data products may be transmitted via the communication interface(s)503or the network interface508and may be stored in memory506.

Method600is, optionally, governed by instructions that are stored in computer memory or a non-transitory computer readable storage medium (e.g., memory506inFIG. 5) and are executed by one or more processors (e.g., processors502) of one or more computer systems. The computer readable storage medium may include a magnetic or optical disk storage device, solid state storage devices such as flash memory, or other non-volatile memory device or devices. The computer readable instructions stored on the computer readable storage medium may include one or more of: source code, assembly language code, object code, or another instruction format that is interpreted by one or more processors. In various embodiments, some operations in each method may be combined and/or the order of some operations may be changed from the order shown in the figures. For ease of explanation, method600is described as being performed by a computer system, although in some embodiments, various operations of method600are distributed across separate computer systems.

FIG. 6is a flowchart that illustrates one embodiment of a method of generating a digital seismic image, illustrated as the method600. At step605, the method600includes obtaining first seismic data for a first plurality of seismic waves (e.g.,109inFIG. 3) generated while a first electric submersible pump (ESP) (e.g.,107inFIG. 3), a first logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well (e.g.,105inFIG. 3). The first plurality of seismic waves (e.g.,109inFIG. 3) is detected using at least one seismic sensor comprising a seismic sensor within the first well (e.g.,178inFIG. 3), a seismic sensor within a second well (e.g.,178′ inFIG. 3), a seismic sensor on a surface, or any combination thereof.

At step610, the method600includes generating a first digital seismic image of a subsurface using the first seismic data. In some embodiments, generating the first digital seismic image comprises using near field source signature estimation, near field source signature estimation cross-correlation, deconvolution, interferometry, or any combination thereof.

At step615, the method600includes obtaining second seismic data for a second plurality of seismic waves (e.g.,109′ inFIG. 3) generated while a second electric submersible pump (ESP) (e.g.,107′ inFIG. 3), a second logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the second well (e.g.,105′ inFIG. 3). The second plurality of seismic waves (e.g.,109′ inFIG. 3) is detected using at least one seismic sensor comprising the seismic sensor within the first well (e.g.,178inFIG. 3), the seismic sensor within the second well (e.g.,178′ inFIG. 3), the seismic sensor on the surface, or any combination thereof.

At step620, the method600includes generating a second digital seismic image of a subsurface using the second seismic data. In some embodiments, generating the first digital seismic image comprises using near field source signature estimation, near field source signature estimation cross-correlation, deconvolution, interferometry, or any combination thereof.

At step625, the method600includes obtaining second seismic data for a second plurality of seismic waves generated while a second electric submersible pump (ESP), a second logging tool, or any combination thereof is running at its operating frequency or operating frequencies within the first well. For example,FIG. 3may include a plurality of the ESP107in the wellbore105and each ESP107generates a wavefield such as the wavefield109. The second plurality of seismic waves is detected using at least one seismic sensor comprising the seismic sensor within the first well (e.g.,178inFIG. 3), the seismic sensor within the second well (e.g.,178′ inFIG. 3), the seismic sensor on the surface, or any combination thereof.

At step630, the method600includes generating a second digital seismic image of a subsurface using the second seismic data. In some embodiments, generating the first digital seismic image comprises using near field source signature estimation, near field source signature estimation cross-correlation, deconvolution, interferometry, or any combination thereof.

Various modification may be made to the method600. Some embodiments may include605,610,615,620,625, and630depending on the implementation. Some embodiments may include605,610,615, and620depending on the implementation. Some embodiments may include605,610,625, and630depending on the implementation. Some embodiments may include605and610depending on the implementation.

While particular embodiments are described above, it will be understood it is not intended to limit the invention to these particular embodiments. On the contrary, the invention includes alternatives, modifications and equivalents that are within the spirit and scope of the appended claims. Numerous specific details are set forth in order to provide a thorough understanding of the subject matter presented herein. But it will be apparent to one of ordinary skill in the art that the subject matter may be practiced without these specific details. For instance, another embodiment may include detecting a first plurality of seismic waves generated by a non-conventional seismic source within a first well, wherein the first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof; and recording seismic data for the first plurality of seismic waves detected by the at least one seismic sensor in an electronic storage. For instance, another embodiment may include obtaining first seismic data for a first plurality of seismic waves generated by a non-conventional seismic source within the first well, wherein the first plurality of seismic waves is detected using at least one seismic sensor comprising a seismic sensor within the first well, a seismic sensor within a second well, a seismic sensor on a surface, or any combination thereof; and generating a first digital seismic image of a subsurface using the first seismic data. In other instances, well-known methods, procedures, components, and circuits have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.

The terms “first” and “second” herein are not limiting. Some embodiments may include a first ESP only (i.e., singe ESP). Some embodiments may include both a first ESP and a second ESP (i.e., two ESPs). Some embodiments may include a first ESP and one or more second ESPs, such as more than two ESPs. Some embodiments may include a first logging tool only (i.e., singe logging tool). Some embodiments may include both a first logging tool and a second logging tool (i.e., two logging tools). Some embodiments may include a first logging tool and one or more second logging tools, such as more than two logging tools. Thus, the term “second” may be one or more even if not explicitly stated.

The use of the term “about” applies to all numeric values, whether or not explicitly indicated. This term generally refers to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term can be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% can be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. All citations referred herein are expressly incorporated by reference.