FIBER DEPLOYED VIA A TOP PLUG

Abstract

Methods and systems for evaluating the effectiveness of a cementing process including a wellbore having a liner disposed therein to create a flow path and an annulus within the wellbore. A cementing tool positionable at the surface of the wellbore for pumping a cement composition through the liner. A plurality of sensors dispersed throughout the cement composition and capable of transmitting a location signal receivable via a fiber optic cable. A control facility communicatively coupled with the fiber optic cable having one or more processors which execute instructions including receiving location data from the plurality of sensors via the fiber optic cable, and evaluating the location of each of the sensors to determine the effectiveness of the cementing process.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application 62/969,000, which was filed in the U.S. Patent and Trademark Office on Jan. 31, 2020, which is incorporated herein by reference in its entirety for all purposes.

TECHNICAL FIELD

The present disclosure generally relates to a system and method for deploying a fiber via a top plug dart that engages a top plug to provide communication therethrough. In particular, the present disclosure relates to systems and methods for detecting the location of one or more sensors dispersed throughout cement used in a wellbore via the fiber.

BACKGROUND

In the oil and gas industry, it can be required to measure the characteristics of substances located at remote subterranean locations and convey the results to the earth's surface for processing and analysis. For instance, during completion of the wellbore the annular space between the wellbore wall and a casing or liner can be filled with cement.

The process is referred to as “cementing” the wellbore. The cement slurry can be pumped into place and allowed to solidify for typically around 12 to 24 hours. The cement must reach a specific strength before drilling or perforating can occur. Determining the consistency with which the cement has entered the annulus provides valuable insight to the cementing process.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other advantages and features of the disclosure can be obtained, a more particular description of the principles briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 illustrates a system for preparation and delivery of a cement composition to a wellbore in accordance with aspects of the present disclosure;

FIG. 2A illustrates surface equipment that may be used in placement of a cement composition in a wellbore in accordance with aspects of the present disclosure;

FIG. 2B illustrates placement of a cement composition into a wellbore annulus in accordance with aspects of the present disclosure;

FIG. 3A-3D illustrate a series of images showing different states in which a fiber is deployed through a modified top plug dart which engages a top plug in accordance with aspects of the present disclosure;

FIG. 4 is a flow chart illustrating a method for evaluating the effectiveness of a cementing process within a wellbore in accordance with aspects of the present disclosure; and

FIG. 5 illustrates an exemplary processing system for configuring and/or controlling the distributed network of sensors of FIGS. 3A-3D.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein can be practiced without these specific details. In other instances, methods, procedures, and components have not been described in detail so as not to obscure the related relevant feature being described. Also, the description is not to be considered as limiting the scope of the embodiments described herein. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features of the present disclosure.

In order to be able to evaluate a cement sheath immediately after placement, a means to communicate information to the surface is required and a means to evaluate cement coverage of the liner or casing is required to indicate to the user that the cement sheath has been successfully placed. For the purpose of oil well cementing, the process of cementing a casing versus a liner are different. For the purpose of displacing a cement job into an annulus, a primary cement job through a casing can require plugs, a top and bottom plug or at the very minimum a top plug. For a liner, means by which you deploy a plug is to place the plug set into the top of the liner and then deploy darts for the top and bottom plug which will then launch the primary plugs from the liner top in order to place a cement job. After a liner job is complete, the liner running tool and work string are removed from the well. Once the cement is set, conventional logging techniques can be used to evaluate the cementing job. However, waiting for the cement to set can take an extended period of time, and such techniques do not provide all the desired information regarding the cementing job. For example, typical logging techniques can only be used to determine the location of the cement but cannot gain additional information such as the heat of hydration. As such, there is currently no means for placing a fiber within a liner top dart and have the dart engage a liner top plug to deploy a fiber into the well.

The present disclosure relates to methods and systems for deploying a fiber through a top plug dart that engages a top plug located at the top of a liner, allowing the location of one or more sensors dispersed throughout wellbore liner cement to be determined. There are many applications where a network of sensors is dispersed within a wellbore. However, it is difficult to interrogate and receive information from the sensors dispersed within the cement. In particular, the present disclosure relates to a top plug dart that is modified to allow a fiber to penetrate through a plug container for detecting sensors. A top plug dart which engages a top plug that can be used to place a fiber within a wellbore for the purpose of gathering information and data about the wellbore. The methods and systems described herein provide means for interrogating a network of sensors dispersed in cement to ascertain the location of each of the sensors and transmit data such as temperature, pressure conditions, and location. In at least one instance, the methods and systems described herein can be used to determine where the cement pumped into a wellbore solidifies. For example, the fiber can be used to determine a lead and tail location of the cement.

Systems and methods for interrogating and receiving information from sensors dispersed throughout a cementing composition using a modified top plug are disclosed herein. Specifically, the modified top plug dart which engages a top plug can be used to interrogate the wellbore via a fiber to identify the depth of sensors that are pumped into an annulus of a wellbore. The data can be used to determine the depth, pressure, and temperature at the location of the sensors within the cement.

The well systems described herein can include a network of dispersed sensors which can be placed within an annulus of a wellbore via a cementing process. FIG. 1 illustrates a system that may be used in the preparation of a cement composition in accordance with the present disclosure. FIG. 1 illustrates a system 2 for the preparation of a cement composition and delivery to a wellbore in accordance with one or more embodiments. As shown, the cement composition may be mixed in mixing equipment 4, such as a jet mixer, re-circulating mixer, or a batch mixer, for example. In at least one instance, a plurality of sensors can be added to the mixing equipment 4 to achieve a cement composition having a plurality of sensors dispersed therein. The plurality of sensors can be used to detect a characteristic of a fluid and output an electrical signal or an acoustic signal proportional to the characteristic. As used herein, the term “characteristic” or “characteristic of interest” refers to a chemical, mechanical, or physical property of the cement. The characteristic of the cement may include a quantitative or qualitative value of one or more physical properties associated therewith. The cement composition can then be pumped via pumping equipment 6 to the wellbore. In an alternative instance, the plurality of sensors can be added to the cement composition at the pumping equipment, immediately prior to the cement composition being pumped into the wellbore. In some embodiments, the mixing equipment 4 and the pumping equipment 6 may be disposed on one or more cement trucks as will be apparent to those of ordinary skill in the art. In some embodiments, a jet mixer or recirculating mixer may be used, for example, to continuously mix the composition, including water, as it is being pumped into the wellbore.

An example technique and system for placing a cement composition having a plurality of sensors dispersed therein into a wellbore drilled through a subterranean earth formation will now be described with reference to FIGS. 2A and 2B. FIG. 2A illustrates surface equipment 10 that may be used in placement of a cement composition in accordance with certain embodiments of the present disclosure. As illustrated, the surface equipment 10 may include a cementing unit 12, which may include one or more cement trucks. The cementing unit 12 may include mixing equipment 4 and pumping equipment 6 (e.g., FIG. 1) as will be apparent to those of ordinary skill in the art. The cementing unit 12 may pump a cement composition 14 having a plurality of sensors dispersed therein through a feed pipe 16 and to a cementing head 18 which conveys the cement composition 14 downhole.

Modifications, additions, or omissions may be made to FIG. 2A without departing from the spirit and scope of the present disclosure. For example, FIG. 2A depicts components of the operational well system 10 in a particular configuration. However, any suitable configuration of components may be used. Furthermore, fewer components or additional components beyond those illustrated may be included in the operational well system 10 without departing from the spirit and scope of the present disclosure.

It should also be noted that while FIG. 2A generally depicts a land-based operation, those skilled in the art would readily recognize that the principles described herein are equally applicable to operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. For example, sea-based operations including deep-water applications typically use a casing in lieu of a liner. The methods and systems described herein can be modified to be used in casing operations as described above. For example, in deep-water applications a casing can be hung from sub-sea wellhead. Such deep-water casing deployment can require a running tool and plug sets that are launched via darts.

Turning now to FIG. 2B, the cementing composition 14 may be placed into a subterranean earth formation 20 in accordance with example embodiments. As illustrated, a wellbore 22 may be drilled into the subterranean earth formation 20. As illustrated, the wellbore 22 comprises walls 24. In the illustrated embodiments, a surface casing 26 has been inserted into the wellbore 22. The surface casing 26 may be cemented to the walls 24 of the wellbore 22 by cement sheath 28. In the illustrated embodiment, one or more additional wellbore tubulars (e.g., intermediate casing, production casing, liners, etc.) shown here as casing 30 may also be disposed in the wellbore 22. As illustrated, there is a wellbore annulus 32 formed between the casing 30 and the walls 24 of the wellbore 22 and/or the surface casing 26. One or more centralizers 34 may be attached to the casing 30, for example, to centralize the casing 30 in the wellbore 22 prior to and during the cementing operation.

With continued reference to FIG. 2B, the cement composition 14 having sensors dispersed therein may be pumped down the interior of the casing 30. In at least one example, the cement composition 14 can include one or more binders. The binders used may directly or indirectly affect one or more components or pieces of equipment associated with the preparations, delivery, recapture, recycling, reuse, and/or disposal of the binder compositions. For example, the binder compositions may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, composition separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used generate, store, monitor, regulate, and/or recondition the exemplary binder compositions. The binder compositions may also directly or indirectly affect any transport or delivery equipment used to convey the binder compositions to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to compositionally move the binder compositions from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the binder compositions into motion, any valves or related joints used to regulate the pressure or flow rate of the binder compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like. The binder compositions may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the cement compositions/additives such as, but not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, cement pumps, surface-mounted motors and/or pumps, centralizers, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devise, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), surveillance lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like. The binder compositions used in a cementing process implementing the methods and systems disclosed herein must be sufficient to carry the sensors throughout the liner and into the annulus of the wellbore.

Referring back to FIG. 2A, the cement composition 14 may be allowed to flow down the interior of the casing 30 into the wellbore annulus 32. The cement composition 14 may be allowed to set in the wellbore annulus 32, for example, to form a cement sheath that supports and positions the casing 30 in the wellbore 22. While not illustrated, other techniques may also be utilized for introduction of the cement composition 14.

As it is introduced, the cement composition 14 may displace other fluids 36, such as drilling fluids and/or spacer fluids, that may be present in the interior of the casing 30 and/or the wellbore annulus 32. At least a portion of the displaced fluids 36 may exit the wellbore annulus 32 via a flow line 38 and be deposited, for example, in one or more retention pits 40 (e.g., a mud pit), as shown in FIG. 2A. Referring again to FIG. 2B, a bottom plug 44 may be introduced into the wellbore 22 ahead of the cement composition 14, for example, to separate the cement composition 14 from the fluids 36 that may be inside the casing 30 prior to cementing. After the bottom plug 44 reaches the landing collar 46, a diaphragm or other suitable device ruptures to allow the cement composition 14 through the bottom plug 44. In FIG. 2B, the bottom plug 44 is shown on the landing collar 46. In the illustrated embodiment, a top plug dart 48 may be introduced into the wellbore 22 behind the cement composition 14. The top plug dart 48 may separate the cement composition 14 from a displacement fluid 50 the top plug dart will engage the top plug once the top plug dart reaches the liner top. The top plug dart and the top plug will then move through the liner until, the cement in the liner will push the cement composition 14 through the bottom plug 44, the top plug dart and the top plug will bump up to the bottom plug and the job will be over.

Modifications, additions, or omissions may be made to FIG. 2B without departing from the spirit and scope of the present disclosure. It should also be noted that while FIG. 2B generally depicts a vertical well section, those skilled in the art would readily recognize that the principles described herein are equally applicable to operations in inclined well sections, directional well sections, horizontal well sections, and the like without departing from the scope of the present disclosure.

In some instances, it may be required to measure chemical and/or physical properties of substances located in a wellbore and convey the results of the measurement over long distances to the earth's surface. For example, the ability to sense where a cement is placed immediately after the cement job is done can provide several benefits including, but not limited to, effectiveness of the cement job, consistency of cementing, strength of the material, and the like. In many cases two separate cement designs can be placed within the casing including a lead cement and a tail cement. In such instances, it can be valuable to know whether the tail cement, which usually has enhanced properties of preventing gas migration or high strengths, was placed where it was intended. As such, some sensors may be tagged to a tail cement to assure a user that the blend has been placed as designed. Additionally, knowing where the cement is located may prevent the need for a cement integrity log, such as a cement bong log or ultrasonic log, which can delay wellbore operations. In at least one instance, the systems and methods described herein can be used to determine if the cement was properly placed within the wellbore, preventing the need for remediation, saving time and money.

Embodiments described herein relate to a distributed network of sensors for measuring physical and/or chemical properties of cement located within a wellbore annulus. For instance, embodiments may be directed to systems and methods for converting the electrical signals obtained from the network of sensors to acoustic signals, converting the acoustic signals to optical signals, and subsequently transmitting the optical signals to the surface via fiber optics. FIGS. 3A through 3D illustrate various stages 100, 200, 300, 400 of the systems and methods described herein which allow for the evaluation of cement placement within a wellbore using a network of distributed sensors. In at least one instance, each of the plurality of sensors can include a battery sufficient to output an electric or acoustic signal for a predetermined period of time. Referring to FIG. 3A, a first stage 100 of the deployment of the present well systems is illustrated. In the first stage 100, a wellbore 122 can have a casing 130 and a liner 140 disposed therein forming a flow path therethrough and defining a wellbore annulus 124. As used herein, the term “flow path” refers to a route through which a fluid is capable of being transported between two points. Exemplary flow paths can include, but are not limited to, a casing, a liner, a work string, a coiled tubing, and the like. As used herein, a “liner” refers to a casing string that does not extend to the top of the wellbore (as illustrated in FIG. 3A). As shown, the liner 140 is coupled with (for example, anchored to or suspended from) the bottom of the previous casing 130. A liner top plug 112 can be located at the top of the liner 140 where the liner 140 meets the casing 130. A work string 120 can be disposed within the wellbore 122, the work string 120 can include a liner top plug dart 110 located at the upstream end of the work string 120. As used herein, the term “dart” refers to a device dropped or pumped through a tubing to activate downhole equipment and tools. For example, one or more pins 116 can be located at the upstream end of the work string 120 and below the top plug dart 110. Each of the pins can be removed sequentially to release the dart 110 into the wellbore. The work string 120 can further include one or more valves 118 that can be used to attach cementing lines to the work string 120 for the circulation of fluids and displacement of the dart 110. The dart 110 can be deployed into the wellbore 122 via a fiber 150 as illustrated in FIG. 3B. In at least one instance, the dart 110 can be releasably couplable with the top plug 112.

Referring to FIG. 3B illustrates a second stage 200 of the well systems described herein. As illustrated, a cement composition 114 having a plurality of sensors 160 dispersed therein can be pumped through the work string 120 and into the flow path created by the liner 140. The plurality of sensors 160 can be any type of sensors including, but not limited to, radio-frequency identification (RFID) to acoustic sensors to piezoelectric sensors. In at least one instance, electrical sensors may be used. As indicated above, each of the plurality of sensors can include a battery having a predetermined life. Electrical sensors may be pressure sensors based on quarts type sensors or strain gauge-based sensors or other commonly used sensing technologies. In at least one instance, the electrical signals can be converted to acoustic signals which allows deployment of sensors over long downhole distances without the need for deploying long electrical conductors to the surface or deploying power consuming processing units to convert and convey a high SNR electrical signal to the surface. The plurality of sensors 160 described herein can be used to transmit data to the fiber 150 described above. As such, the fiber optic cable may include fiber and electrical conductors.

In at least one instance, the fiber 150 can be a fiber optic cable capable of transmitting data received downhole to a control or processing facility (not shown) at the surface. A fiber optic cable which can be used in accordance with the systems and methods described herein may house one or several optical fibers, which may be single mode fibers, multi-mode fibers, or a combination of single mode and mutli-mode optical fibers. The fiber optic sensing systems connected to the optical fibers may include, but are not limited to, Distributed Temperature Sensing (DTS) systems, Distributed Acoustic Sensing (ADS) systems, Distributed Strain Sensing (DSS) systems, quasi-distributed sensing systems where multiple single point sensors are distributed along an optical fiber/cable, or single point sensing systems where the sensors are located at the end of the cable.

The fiber optic sensing systems may operate using various sensing principles including, but not limited to, amplitude based sensing systems like e.g. DTS systems based on Raman scattering, phase sensing based systems like e.g. DAS systems based on interferometric sensing using e.g. homodyne or heterodyne techniques where the system may sense phase or intensity changes due to constructive or destructive interference, strain sensing systems like DSS using dynamic strain measurements based on interferometric sensors or static strain sensing measurements using e.g. Brillouin scattering, quasi-distributed sensors based on e.g. Fiber Bragg Gratings (FBGs) where a wavelength shift is detected or multiple FBGs are used to form Fabry-Perot type interferometric sensors for phase or intensity based sensing, or single point fiber optic sensors based on Fabry-Perot or FBG or intensity based sensors.

Specifically, temperature measurements from e.g., a DTS system, may be used to determine locations for fluid flow throughout the wellbore as fluids from the surface are likely to be cooler than formation temperatures.

DAS data can be used to determine fluid allocation in real-time as acoustic noise is generated when fluid flows through the casing and into the annulus. Phase and intensity based interferometric sensing systems are sensitive to temperature and mechanical as well as acoustically induced vibrations. DAS data can be converted from time series date to frequency domain data using Fast Fourier Transforms (FFT) and other transforms like wavelet transforms may also be used to generate different representations of the data. Various frequency ranges can be used for different purposes and where e.g. low frequency signal changes may be attributed to formation strain changes or fluid movement other frequency ranges may be indicative of fluid or gas movement. Various filtering techniques may be applied to generate indicators of events that maybe of interest.

DSS data can be generated using various approaches and static strain data can be used to determine absolute strain changes over time. Static strain data is often measured using Brillouin based systems or quasi-distributed strain data from FBG based systems. Fiber Bragg Grating abased systems may also be used for a number of different measurements. FBG's are partial reflectors that can be used as temperature and strain sensors, or can be used to make various interferometric sensors with very high sensitivity. FBG's can be used to make point sensors or quasi-distributed sensors where the FBG based sensors can be used to independently or with other types of fiber optic based sensors. FBG's can be manufactured into an optical fiber at a specific wavelength, and other systems like DAS, DSS, or DTS systems may operate at different wavelengths in the same fiber and measure different parameters simultaneously as the FBG based systems using Wavelength Division Multiplexing (WDM). In at least one example, if the sensors remain active after the fiber stops transmitting, strain data can be obtained by subsequently running a logging tool in the wellbore to interrogate the sensors.

Referring back to FIG. 3B, as the cement composition 114 and plurality of sensors 160 are pumped into the wellbore 122 the top plug dart 110 is deployed with a fiber 150 coupled therewith to follow the cement composition as it is placed into the wellbore 122. In at least one example, the dart 110 can be pushed through the flow path of the liner by pumping a liquid behind the dart 110. In at least one instance, each of the plurality of sensors can be tagged with an identifier such that it is easily determined when each of the plurality of sensors 160 entered the wellbore 122 during the pumping process.

A third stage 300 of the well system described herein is illustrated in FIG. 3C. As shown, the fiber 150 in the top plug dart 110 couples with the top plug 112 once the dart 110 reaches the top of the liner 140. Once the top plug dart 110 and top plug 112 are engaged, they can move down the wellbore 122 within the flow path of the liner 140 behind the cement composition 114 and plurality of sensors 160 being placed in the annulus 124 of the wellbore 122.

At the final stage 400, illustrated in FIG. 3D, the top plug 112 achieves the final depth at the bottom of the liner 140. As shown, the plurality of sensors 160 are distributed throughout the length of the annulus 124 creating a network of distributed sensors. The fiber 150 can be an active sensor that can interrogate the surrounding environment once it is placed within the flow path of the liner 140, as shown by the arrows leading from the plurality of sensors 160 to the fiber 150. For example, the fiber 150 can receive information from each of the plurality of sensors 160 in the cement that have been secured in the annulus 124 of the wellbore 122. The plurality of sensors 160 can provide information regarding characteristics of the cement. Such information can be used to evaluate the cementing process including, but not limited to, indicating the final location of the sensors within the annulus 124. In at least one instance, the information received from the plurality of sensors 160 can be used to determine whether the cement pumped into the annulus 124 was successfully placed and determine if well construction operations can move forward or if remediation steps are required. In another instance, the plurality of sensors 160 can be used to determine the depth, thickness, pressure, and temperature of the cement surrounding each sensor. In at least one instance, the final location data for each of the plurality of sensors 160 can be related back to the initial tag indicator, providing details on how the cement moved once it was pumped into the flow path of the wellbore 122. The plurality of sensors 160 dispersed within the cement can remain permanently installed in the wellbore annulus and interrogated as required for additional information.

The liner running tool must be removed from the wellbore once the cementing process is completed. The systems described herein provide a method for quickly evaluating the cementing process prior to the removal of the liner or casing running tool. Specifically, after the fiber has evaluated the effectiveness of the process, the work string is pulled from the wellbore. In the process of removing the work string, the fiber coupled with the top plug dart is broken, cutting off communication with the distributed network of sensors. However, as indicated above, each of the plurality of sensors may include a battery allowing the sensor to function for a predetermined period of time. The batteries for each of the sensors can be activated as they are pumped into the wellbore. In at least one instance, any tool capable of reading an acoustic signal can be disposed within the wellbore to interrogate the sensors, allowing continued monitoring of well conditions. In at least one example, a logging suit, measurement while drilling (MWD), or logging while drilling (LWD) tool can be used.

Additionally, while FIGS. 3A-3D illustrate a liner environment, it should be generally understood that the presently disclosed systems and methods are equally applicable to a wellbore environment including a casing. For example, a fiber can be deployed in a similar manner via a top plug within a casing to evaluate the cement job. In a casing environment, the fiber can remain disposed within the wellbore for a longer period of time than in a liner environment. In such cases, the fiber can continue to interrogate the distributed network of sensors to evaluate various conditions within the wellbore.

For example, a method 500 for evaluating the effectiveness of a cementing process within a wellbore is provided in FIG. 4. The method 500 can begin at block 510 where a plurality of sensors are added to a cement composition. As described above, the sensors can be added to the cement composition in mixing equipment to distribute the sensors throughout the composition. In the alternative, the sensors can be added as the cement composition moves from the mixing equipment to the pumping equipment to allow a more precise determination of when the sensor entered the wellbore. Each of the plurality of sensors can be individually tagged with an indicator so the path each sensor takes through the wellbore is easily determined.

As block 520, the cement composition and plurality of sensors are pumped into the flow path of a wellbore to begin a cementing process. In at least one example, the wellbore can include a liner as described with respect to FIGS. 3A-3D. At block 530, a fiber can be deployed into the wellbore. The fiber can be coupled with a dart, which can follow the path of the cement composition through the wellbore. As the cement composition is pumped into the wellbore, the cement composition and plurality of sensors move through the flow path and into an annulus of the wellbore.

At block 540, the fiber can be used to receive data from the plurality of sensors. In at least one instance, the data can include location, temperature, and pressure data. At block 550, the data received by the plurality of sensors can be transmitted via the fiber to a control or processing facility at the surface of the well.

The control or processing facility may include a computing device capable of carrying out the methods and techniques of the present disclosure, including collecting and analyzing data gathered by the fiber. In some instances, the computing device can be equipped to process the received information in substantially real-time. In other instances, the computing device can be equipped to store the received information for processing at some subsequent time. The computing device can be a computing system including one or more processors coupling a memory capable of storing instructions thereof, as described in detail with respect to FIG. 5. The computing device can be capable of receiving information transmitted by the fiber as described above and can output results onto a display.

Finally, at block 560, the effectiveness of the cementing is determined based at least in part on the data obtained from each of the plurality of sensors. In at least one instance, determining the effectiveness of the cementing process can include evaluating the location that each of the plurality of sensors is secured within the annulus. The location data for each of the sensors can be correlated back to the initial tag indicator given to each of the sensors prior to being deployed within the wellbore. Such information can provide a detailed picture of where the cement composition pumped into the wellbore solidified. In at least one instance, if the effectiveness of the cementing process is determined to be low, remediation actions can be immediately taken to increase the stability of the wellbore cementing. For example, as the fiber descends into the wellbore it can interrogate the plurality of sensors as they enter the annulus of the wellbore. As such, the progress of the cementing process can be continuously evaluated throughout the pumping process as the fiber descends. In at least one instance, if the cementing process is determined to be insufficient, steps can be taken to mobilize materials and tools to remedy the problem. This can be as soon as the readings from the fiber are received and the problem is recognized. For example if there are losses on the job, it would be known immediately that the top of cement was not obtained and steps can be taken immediately to remedy the situation including, but not limited to, ordering tools and materials to remediate the height of the cement. This can in turn negate waiting for the cement to set and subsequent evaluation of the cement success via wireline, saving valuable time. In the alternative, if the effectiveness is determined to be high, wellbore operations can proceed to the next stages of completion.

FIG. 5 shows an illustrative processing system 600 for configuring and/or controlling the plurality of sensors and fiber for performing the various tasks as described herein. The system 600 may include a processor 610, a memory 620, a storage device 630, and an input/output device 640. Each of the components 610, 620, 630, and 640 may be interconnected, for example, using a system buss 650. The processor 610 may be processing instructions for execution within the system 600. In some instances, the processor 610 is a single-threaded processor, a multi-threaded processor, or another type or processor. The processor 610 may be capable of processing instructions stored in the memory 620 or on the storage device 630. The memory 620 and the storage device 630 can store information within the computer system 600.

The input/output device 640 may provide input/output operations for the system 600. In some instances, the input/output device 640 can include one or more network interface devices. In some instances, the input/output device can include driver devices configured to receive input data and send output data to other input/output devices, such as keyboards, printers, and display devices 660. In some instances, mobile computing devices, mobile communication devices, and other devices can be used.

Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of statements are provided as follows.

Statement 1: A method for evaluating a cementing process, the system comprising inserting a wellbore tubular with a top plug and a bottom plug into a wellbore creating a flow path and an annulus between the wellbore tubular and the walls of the wellbore; deploying a work string within the wellbore tubular coupled therewith; performing a cementing process including pumping a cement composition through the work string and wellbore tubular and into the annulus, the cement composition having a plurality of sensors dispersed therein; deploying a dart coupled with a fiber optic cable into the work string, the dart further couplable with the top plug; interrogating the plurality of sensors via the fiber optic cable to obtain at least a location for each of the plurality of sensors; and evaluating the location of each of the plurality of sensors to determine an effectiveness of the cementing process.

Statement 2: A method in accordance with Statement 1, further comprising mixing the plurality of sensors into the cement composition prior to pumping the cement composition into the work string.

Statement 3: A method in accordance with Statement 1, further comprising adding the plurality of sensors into the cement composition while the cement composition is being pumped into the work string.

Statement 4: A method in accordance with Statements 1-3, further comprising tagging each of the plurality of sensors with an identifier as each of the plurality of sensors enters the work string.

Statement 5: A method in accordance with Statements 1-3, further comprising tagging each of the plurality of sensors with an identifier prior to entering the work string.

Statement 6: A method in accordance with Statements 1-5, further comprising receiving, at a control facility, the identifier for each of the plurality of sensors; transmitting the location for each of the plurality of sensors to the control facility via the fiber optic cable; and determining, at the control facility, the effectiveness of the cementing process.

Statement 7: A method in accordance with Statements 1-6, wherein the effectiveness of the cementing process is determined in part by comparing the identifier of each of the plurality of sensors with the location for each of the plurality of sensors.

Statement 8: A method in accordance with Statements 1-7, further comprising interrogating the plurality of sensors as the fiber optic cable descends through the wellbore to obtain data; and ordering equipment to further evaluate the integrity of the cement based on the data obtained from the plurality of sensors.

Statement 9: A system for evaluating a cementing process, the system comprising a wellbore having at least a liner disposed therein, the liner creating a flow path and an annulus within the wellbore; a cementing tool positionable at the surface of the wellbore for pumping a cement composition through the liner; a plurality of sensors dispersed throughout the cement composition; a fiber optic cable for communicating with the plurality of sensors and disposed within the flow path of the wellbore; and a control facility communicatively coupled with the fiber optic cable, the control facility including one or more processors coupled with at least one non-transitory computer-readable storage medium storing instructions which, when executed by the one or more processors, cause the processors to pump the cement composition and plurality of sensors through the flow path of the wellbore and into the annulus; receive after the cementing process is completed, data from the plurality of sensors via the fiber optic cable, the data including at least a location of each of the plurality of sensors; and evaluate the location of each of the plurality of sensors to determine an effectiveness of the cementing process.

Statement 10: A system in accordance with Statement 9, wherein the instructions further cause the processor to tag each of the plurality of sensors with an indicator upon entering the flow path of the wellbore.

Statement 11: A system in accordance with Statement 9, wherein the instructions further cause the processor to tag each of the plurality of sensors with an indicator prior to entering the flow path of the wellbore.

Statement 12: A system in accordance with Statements 9-11, wherein the effectiveness of the cementing process is based at least in part on a comparison of the identifier of each of the plurality of sensors and the location of each of the plurality of sensors.

Statement 13: A system in accordance with Statements 9-11, wherein the location of each of the plurality of sensors is determined by interrogating the plurality of sensors via the fiber optic cable.

Statement 14: A system in accordance with Statements 9-12, wherein the cementing tool further comprises a mixing vessel where the plurality of sensors are mixed into the cement composition prior to pumping the cement composition into the flow path.

Statement 15: A system in accordance with Statements 9-14, wherein the cementing tool further comprises pumping equipment where the plurality of sensors are added to the cement composition as the cement composition is pumped into the flow path.

Statement 16: A system in accordance with Statements 9-15, further comprising a top plug disposed within the wellbore.

Statement 17: A system in accordance with Statements 9-15, further comprising a top plug and a bottom plug disposed within the wellbore.

Statement 18: A system in accordance with Statements 9-17, further comprising a dart coupled with the fiber optic cable, the dart configured to engage with the top plug, wherein the top plug and the dart guide the fiber optic cable through the casing.

Statement 19: A system in accordance with Statements 9-17, further comprising interrogating the plurality of sensors as the fiber optic cable descends through the wellb ore to obtain data; and ordering equipment to further evaluate the integrity of the cement based on the data obtained from the plurality of sensors.

Statement 20: A well system comprising a wellbore tubular extendable within a wellbore and defining a flow path and an annulus; a cementing tool positionable at the surface of the wellbore for pumping a cement composition into the wellbore tubular; a plurality of sensors dispersed within a cement composition, the plurality of sensors to detect a characteristic of the cement composition and output an electrical signal proportional to the characteristic; and a fiber optic cable to detect the electrical signal from each of the plurality of sensors and transmit the signal to a control facility.

Statement 21: A well system in accordance with Statement 20, wherein the fiber optic cable is coupled with a dart and a top plug which guide the fiber optic cable through the flow path of the wellbore.

Statement 22: A well system in accordance with Statement 20 and Statement 21, wherein the cementing tool pumps the cement composition and plurality of sensors through the flow path and into the annulus of the wellbore during a cementing process.

Statement 23: A well system in accordance with Statements 20-22, wherein the characteristic is a location of each of the plurality of sensors within the annulus of the wellbore.

Statement 24: A well system in accordance with Statements 20-23, wherein the control facility comprises a computing device to determine an effectiveness of the cementing process based in part on the location of each of the plurality of sensors.

Statement 25: A well system in accordance with Statements 20-24, further comprising a control facility communicatively coupled with the fiber optic cable, the control facility including one or more processors coupled with at least one non-transitory computer-readable storage medium storing instructions which, when executed by the one or more processors, cause the processors to pumping the cement composition and plurality of sensors through the flow path of the wellbore and into the annulus; receiving after the cementing process is completed, data from the plurality of sensors via the fiber optic cable, the data including at least a location of each of the plurality of sensors; and evaluating the location of each of the plurality of sensors to determine an effectiveness of the cementing process.

Statement 26: A well system in accordance with Statements 20-25, wherein the instructions further cause the processor to tag each of the plurality of sensors with an indicator upon entering the flow path of the wellbore.

Statement 27: A well system in accordance with Statements 20-26, wherein the instructions further cause the processor to tag each of the plurality of sensors with an indicator prior to entering the flow path of the wellbore.

Statement 28: A well system in accordance with Statements 20-27, wherein the effectiveness of the cementing process is based at least in part on a comparison of the identifier of each of the plurality of sensors and the location of each of the plurality of sensors.

Statement 29: A well system in accordance with Statements 20-28, wherein the location of each of the plurality of sensors is determined by interrogating the plurality of sensors via the fiber optic cable.

The embodiments shown and described above are only examples. Even though numerous characteristics and advantages of the present technology have been set forth in the foregoing description, together with details of the structure and function of the present disclosure, the disclosure is illustrative only, and changes may be made in the detail, especially in matters of shape, size and arrangement of the parts within the principles of the present disclosure to the full extent indicated by the broad general meaning of the terms used in the attached claims. It will therefore be appreciated that the embodiments described above may be modified within the scope of the appended claims.

Claims

1. A method for evaluating a wellbore cementing process, the system comprising:

inserting a wellbore tubular with a top plug and a bottom plug into the wellbore creating a flow path and an annulus between the wellbore tubular and the walls of the wellbore;

deploying a work string within the wellbore tubular coupled therewith;

performing a cementing process including pumping a cement composition through the work string and wellbore tubular and into the annulus, the cement composition having a plurality of sensors dispersed therein;

deploying a dart coupled with a fiber optic cable into the work string, the dart further couplable with the top plug;

interrogating the plurality of sensors via the fiber optic cable to obtain at least a location for each of the plurality of sensors; and

evaluating the location of each of the plurality of sensors to determine an effectiveness of the cementing process.

2. The method of claim 1, further comprising mixing the plurality of sensors into the cement composition prior to pumping the cement composition into the work string.

3. The method of claim 1, further comprising adding the plurality of sensors into the cement composition while the cement composition is being pumped into the work string.

4. The method of claim 1, further comprising tagging each of the plurality of sensors with an identifier as each of the plurality of sensors enters the work string.

5. The method of claim 4, further comprising:

receiving, at a control facility, the identifier for each of the plurality of sensors;

transmitting the location for each of the plurality of sensors to the control facility via the fiber optic cable; and

determining, at the control facility, the effectiveness of the cementing process.

6. The method of claim 4, wherein the effectiveness of the cementing process is determined in part by comparing the identifier of each of the plurality of sensors with the location for each of the plurality of sensors.

7. The method of claim 1, further comprising:

interrogating the plurality of sensors as the fiber optic cable descends through the wellbore to obtain data; and

ordering equipment to further evaluate the integrity of the cement based on the data obtained from the plurality of sensors.

8. A system for evaluating a wellbore cementing process, the system comprising:

a liner disposed within the wellbore, the liner creating a flow path and an annulus within the wellbore;

a cementing tool positionable at the surface of the wellbore for pumping a cement composition through the liner;

a plurality of sensors dispersed throughout the cement composition;

a fiber optic cable for communicating with the plurality of sensors and disposed within the flow path of the wellbore; and

a control facility communicatively coupled with the fiber optic cable, the control facility including one or more processors coupled with at least one non-transitory computer-readable storage medium storing instructions which, when executed by the one or more processors, cause the processors to:

pump the cement composition and plurality of sensors through the flow path of the wellbore and into the annulus; receive after the cementing process is completed, data from the plurality of sensors via the fiber optic cable, the data including at least a location of each of the plurality of sensors; and evaluate the location of each of the plurality of sensors to determine an effectiveness of the cementing process.

9. The system of claim 8, wherein the instructions further cause the processor to tag each of the plurality of sensors with an indicator upon entering the flow path of the wellbore.

10. The system of claim 9, wherein the effectiveness of the cementing process is based at least in part on a comparison of the identifier of each of the plurality of sensors and the location of each of the plurality of sensors.

11. The system of claim 8, wherein the location of each of the plurality of sensors is determined by interrogating the plurality of sensors via the fiber optic cable.

12. The system of claim 8, wherein the cementing tool further comprises a mixing vessel where the plurality of sensors are mixed into the cement composition prior to pumping the cement composition into the flow path.

13. The system of claim 8, wherein the cementing tool further comprises pumping equipment where the plurality of sensors are added to the cement composition as the cement composition is pumped into the flow path.

14. The system of claim 8, further comprising a top plug disposed within the wellbore.

15. The system of claim 14, further comprising a dart coupled with the fiber optic cable, the dart configured to engage with the top plug, wherein the top plug and the dart guide the fiber optic cable through the casing.

16. A well system for evaluating a wellbore cementing process comprising:

a wellbore tubular extendable within the wellbore and defining a flow path and an annulus;

a cementing tool positionable at the surface of the wellbore for pumping a cement composition into the wellbore tubular; a plurality of sensors dispersed within a cement composition, the plurality of sensors to detect a characteristic of the cement composition and output an electrical signal proportional to the characteristic; and a fiber optic cable to detect the electrical signal from each of the plurality of sensors and transmit the signal to a control facility.

17. The well system of claim 16, wherein the fiber optic cable is coupled with a dart and a top plug which guide the fiber optic cable through the flow path of the wellbore.

18. The well system of claim 16, wherein the cementing tool pumps the cement composition and plurality of sensors through the flow path and into the annulus of the wellbore during a cementing process.

19. The well system of claim 18, wherein the characteristic is a location of each of the plurality of sensors within the annulus of the wellbore.

20. The well system of claim 19, wherein the control facility comprises a computing device to determine an effectiveness of the cementing process based in part on the location of each of the plurality of sensors.