WO2015199986A1 - Procédés et systèmes de détection d'étiquettes rfid dans un environnement de trou de forage - Google Patents

Procédés et systèmes de détection d'étiquettes rfid dans un environnement de trou de forage Download PDF

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Publication number
WO2015199986A1
WO2015199986A1 PCT/US2015/035090 US2015035090W WO2015199986A1 WO 2015199986 A1 WO2015199986 A1 WO 2015199986A1 US 2015035090 W US2015035090 W US 2015035090W WO 2015199986 A1 WO2015199986 A1 WO 2015199986A1
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WIPO (PCT)
Prior art keywords
result
wellbore
frequencies
data
sensors
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Application number
PCT/US2015/035090
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English (en)
Inventor
Mark W. Roberson
Scott Goodwin
Charles Bartee
Craig W. Roddy
Krishna M. Ravi
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US14/316,408 external-priority patent/US10358914B2/en
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to GB1617705.7A priority Critical patent/GB2542035B/en
Publication of WO2015199986A1 publication Critical patent/WO2015199986A1/fr
Priority to NO20161797A priority patent/NO20161797A1/en

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/005—Monitoring or checking of cementation quality or level
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency

Definitions

  • This disclosure relates to the field of drilling, completing, servicing, and treating a su bterranean well, such as a hydrocarbon recovery well.
  • the present disclosure relates to systems and methods for detecting and/or monitoring the position and/or condition of wellbore compositions, for example wellbore sealants such as cement, using RFID tags (in some cases including micro-electrical mechanical system (MEMS)-based data sensors).
  • RFID tags in some cases including micro-electrical mechanical system (MEMS)-based data sensors.
  • MEMS micro-electrical mechanical system
  • the present disclosure describes methods of scanning for RFID tags using a detector assembly that includes an RFID detection circuit.
  • Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a well bore into the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe (e.g., casing) is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus.
  • a hard mass i.e., sheath
  • Subsequent secondary cementing operations may also be performed.
  • One example of a secondary cementing operation is squeeze cementing whereby a cement slurry is employed to plug and seal off undesirable flow passages in the cement sheath and/or the casing.
  • Non-cementitious sealants are also utilized in preparing a wellbore. For example, polymer, resin, or latex- based sealants may be desirable for placement behind casing.
  • sealant slurries are chosen based on calculated stresses and characteristics of the formation to be serviced. Suitable sealants are selected based on the conditions that are expected to be encountered during the sealant service life. Once a sealant is chosen, it is desirable to monitor and/or evaluate the health of the sealant so that timely maintenance can be performed and the service life maximized.
  • the integrity of sealant can be adversely affected by conditions in the well. For example, cracks in cement may allow water influx while acid conditions may degrade cement. The initial strength and the service life of cement can be significantly affected by its moisture content from the time that it is placed.
  • it is desirable to measure one or more sealant parameters e.g., moisture content, temperature, pH and ion concentration
  • one or more sealant parameters e.g., moisture content, temperature, pH and ion concentration
  • Active, embeddable sensors can involve drawbacks that make them undesirable for use in a wellbore environment.
  • low- powered (e.g., nanowatt) electronic moisture sensors are available, but have inherent limitations when embedded within cement.
  • the highly alkali environment can damage their electronics, and they are sensitive to electromagnetic noise.
  • power must be provided from an internal battery to activate the sensor and transmit data, which increases sensor size and decreases useful life of the sensor. Accordingly, an ongoing need exists for improved methods of monitoring wellbore sealant condition from placement through the service lifetime of the sealant.
  • FIG. 1 is a flow chart illustrating a method in accordance with some embodiments.
  • FIG. 2 is a schematic of a typical onshore oil or gas drilling rig and wellbore in accordance with some embodiments.
  • FIG. 3 is a flow chart illustrating a method for determining when a reverse cementing operation is complete and for subsequent optional activation of a downhole tool in accordance with some embodiments.
  • FIG. 4 is a flow chart illustrating a method for selecting between a group of sealant compositions in accordance with some embodiments.
  • FIG. 5 is a schematic view of an embodiment of a wellbore parameter sensing system.
  • FIG. 6 is a schematic view of another embodiment of a wellbore parameter sensing system.
  • FIG. 7 is a schematic view of still another embodiment of a wellbore parameter sensing system.
  • FIG. 8 is a flow chart illustrating a method for servicing a wellbore in accordance with some embodiments.
  • FIG. 9 is a flow chart illustrating another method for servicing a wellbore in accordance with some embodiments.
  • FIG. 10 is a schematic cross-sectional view of a casing in accordance with some embodiments.
  • FIG. 11 is a schematic view of a further embodiment of a wellbore parameter sensing system.
  • FIG. 12 is a schematic view of yet another embodiment of a wellbore parameter sensing system.
  • FIG. 13 is a flow chart illustrating a method for servicing a wellbore.
  • FIGs. 14 depicts a functional representations of a communication assemblies suitable for use for obtaining measurements in the well annulus surround the casing.
  • FIGs. 15A-C depict example embodiments of communication assemblies, with each of FIGs. 15A-C depicting a side representation of a respective example configuration.
  • FIG. 16 depicts an example system for detecting RFID tags in a borehole annulus.
  • FIG. 17 is a depiction of several example embodiments illustrating signal/noise ratios as related to RFID detection.
  • FIG. 18A is a conceptualized diagram of one embodiment of a "sawtooth" scanning pattern usable to detect RFID tags.
  • FIG. 18B a related conceptual diagram of an embodiment of a power response curve corresponding to Fig. 18A.
  • FIG. 19 is a conceptualized group of charts of power response by a sensor assembly as a function of time at different frequencies.
  • FIG. 20 is a chart showing two power response curves from
  • FIGs. 21A-B are each a block diagram of a respective example embodiment of an RFID detection system, depicted in FIG. 21A having an RFID detection circuit and an RFID tag circuit; and depicted in Fig. 21B having a transmitter circuit, a detector circuit and a an RFID tag circuit.
  • FIG. 22 is a block diagram of another example em bodiment of an
  • FIG. 23 is a flow chart of an example embodiment of a method relating to detection of RFI D tags.
  • FIG. 24 is a flow chart of another example embodiment of a method relating to detection of RFID tags.
  • FIG. 25 is a block diagram of an example embodiment of a sensor assembly including an RFID detection circuit.
  • Disclosed herein are methods for detecting and/or monitoring the position and/or condition of a wellbore, a formation, a wellbore service tool, and/or wellbore compositions, for example wellbore sealants such as cement, using M EMS-based data sensors. Still more particularly, the present disclosure describes methods of monitoring the integrity and performance of wellbore compositions over the life of the well using MEMS-based data sensors. Performance may be indicated by changes, for example, in various parameters, including, but not limited to, moisture content, temperature, pH, and various ion concentrations (e.g., sodium, chloride, and potassium ions) of the cement.
  • various ion concentrations e.g., sodium, chloride, and potassium ions
  • the methods comprise the use of em beddable data sensors capable of detecting parameters in a wellbore composition, for example a sealant such as cement.
  • the methods provide for evaluation of sealant during mixing, placement, and/or curing of the sealant within the wellbore.
  • the method is used for sealant evaluation from placement and curing throughout its useful service life, and where applicable to a period of deterioration and repair.
  • the methods of this disclosure may be used to prolong the service life of the sealant, lower costs, and enhance creation of improved methods of
  • sealant within a wellbore
  • methods are disclosed for determining the location of sealant within a wellbore, such as for determining the location of a cement slurry during primary cementing of a wellbore as discussed further herein. Additional embodiments and methods for employing MEMS-based data sensors in a wellbore are described herein.
  • the methods disclosed herein comprise the use of various wellbore compositions, including sealants and other wellbore servicing fluids.
  • wellbore composition includes any composition that may be prepared or otherwise provided at the surface and placed down the wellbore, typically by pumping.
  • a “sealant” refers to a fluid used to secure components within a wellbore or to plug or seal a void space within the wellbore.
  • Sealants and in particular cement slurries and non-cementitious compositions, are used as wellbore compositions in several embodiments described herein, and it is to be understood that the methods described herein are applicable for use with other wellbore compositions.
  • cement slurries and non-cementitious compositions are used as wellbore compositions in several embodiments described herein, and it is to be understood that the methods described herein are applicable for use with other wellbore compositions.
  • servicing fluid refers to a fluid used to drill, complete, work over, fracture, repair, treat, or in any way prepare or service a wellbore for the recovery of materials residing in a subterranean formation penetrated by the wellbore.
  • servicing fluids include, but are not limited to, cement slurries, non-cementitious sealants, drilling fluids or muds, spacer fluids, fracturing fluids or completion fluids, all of which are well known in the art.
  • While fluid is generally understood to encompass material in a pumpable state, reference to a wellbore servicing fluid that is settable or cura ble (e.g., a sealant such as cement) includes, unless otherwise noted, the fluid in a pumpable and/or set state, as would be understood in the context of a given wellbore servicing operation.
  • well bore servicing fluid and well bore composition may be used interchangeably unless otherwise noted.
  • the servicing fluid is for use in a wellbore that penetrates a subterranean formation. It is to be understood that "subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
  • the wellbore may be a su bstantially vertical wellbore and/or may contain one or more lateral wellbores, for example as produced via directional drilling.
  • components are referred to as being "integrated” if they are formed on a common support structure placed in packaging of relatively small size, or otherwise assembled in close proximity to one another.
  • FIG. 1 includes methods of placing M EMS sensors in a wellbore and gathering data.
  • data sensors are selected based on the parameter(s) or other conditions to be determined or sensed within the wellbore.
  • a quantity of data sensors is mixed with a wellbore composition, for example a sealant slurry.
  • data sensors are added to a sealant by any methods known to those of skill in the art.
  • the sensors may be mixed with a dry material, mixed with one more liquid components (e.g., water or a non-aqueous fluid), or combinations thereof.
  • the mixing may occur onsite, for example by addition of the sensors into a bulk mixer such as a cement slurry mixer.
  • the sensors may be added directly to the mixer, may be added to one or more component streams and su bsequently fed to the mixer, may be added downstream of the mixer, or combinations thereof.
  • data sensors are added after a blending unit and slurry pump, for example, through a lateral by-pass.
  • the sensors may be metered in and mixed at the well site, or may be pre-mixed into the composition (or one or more components thereof) and subsequently transported to the well site.
  • the sensors may be dry mixed with dry cement and transported to the well site where a cement slurry is formed comprising the sensors.
  • the sensors may be pre-mixed with one or more liquid components (e.g., mix water) and transported to the well site where a cement slurry is formed comprising the sensors.
  • liquid components e.g., mix water
  • the properties of the wellbore composition or components thereof may be such that the sensors distributed or dispersed therein do not substantially settle during transport or placement.
  • the wellbore composition e.g., sealant slurry
  • the wellbore composition is then pumped downhole at block 104, whereby the sensors are positioned within the wellbore.
  • the sensors may extend along all or a portion of the length of the wellbore adjacent the casing.
  • the sealant slurry may be placed downhole as part of a primary cementing, secondary cementing, or other sealant operation as described in more detail herein.
  • a data interrogation tool also referred to as a data interrogator tool, data
  • interrogator interrogator, interrogator, interrogation/communication tool or unit, or the like
  • interrogator interrogator, interrogator, interrogation/communication tool or unit, or the like
  • one or more data interrogators may be placed downhole (e.g., in a wellbore) prior to, concurrent with, and/or subsequent to placement in the wellbore of a wellbore composition comprising M EMS sensors.
  • the data interrogation tool interrogates the data sensors (e.g., by sending out an RF signal) while the data interrogation tool traverses all or a portion of the wellbore containing the sensors.
  • the data sensors are activated to record and/or transmit data at block 110 via the signal from the data interrogation tool.
  • the data interrogation tool communicates the data to one or more computer components (e.g., memory and/or microprocessor) that may be located within the tool, at the surface, or both.
  • the data may be used locally or remotely from the tool to calculate the location of each data sensor and correlate the measured parameter(s) to such locations to evaluate sealant performance.
  • the data interrogation tool comprises MEMS sensor interrogation functionality, communication functionality (e.g., transceiver functionality), or both.
  • Data gathering may be carried out at the time of initial placement in the well of the wellbore composition comprising M EMS sensors, for example du ring drilling (e.g., drilling fluid comprising MEMS sensors) or during cementing (e.g., cement slurry comprising M EMS sensors) as described in more detail below. Additionally or alternatively, data gathering may be carried out at one or more times subsequent to the initial placement in the well of the wellbore composition comprising M EMS sensors. For example, data gathering may be carried out at the time of initial placement in the well of the well bore composition comprising M EMS sensors or shortly thereafter, to provide a baseline data set.
  • du ring drilling e.g., drilling fluid comprising MEMS sensors
  • cement slurry cement slurry comprising M EMS sensors
  • data gathering may be performed additional times, for example at regular maintenance intervals such as every 1 year, 5 years, or 10 years.
  • the data recovered during su bsequent monitoring intervals can be compared to the baseline data as well as any other data obtained from previous monitoring intervals, and such comparisons may indicate the overall condition of the wellbore.
  • changes in one or more sensed parameters may indicate one or more problems in the wellbore.
  • consistency or uniformity in sensed parameters may indicate no substantive problems in the wellbore.
  • the data may comprise any combination of parameters sensed by the M EMS sensors as present in the wellbore, including but not limited to temperature, pressure, ion concentration, stress, strain, gas concentration, etc.
  • data regarding performance of a sealant composition includes cement slurry properties such as density, rate of strength
  • data e.g., sealant parameters
  • a resultant graph is provided showing an operating or trend line for the sensed parameters.
  • Atypical changes in the graph as indicated for example by a sharp change in slope or a step change on the graph may provide an indication of one or more present problems or the potential for a future problem. Accordingly, remedial and/or preventive treatments or services may be applied to the well bore to address present or potential problems.
  • the MEMS sensors are contained within a sealant composition placed substantially within the annular space between a casing and the wellbore wall. That is, substantially all of the M EMS sensors are located within or in close proximity to the annular space.
  • the wellbore servicing fluid comprising the MEMS sensors does not substantially penetrate, migrate, or travel into the formation from the wellbore.
  • substantially all of the M EMS sensors are located within, adjacent to, or in close proximity to the wellbore, for example less than or equal to about 1 foot, 3 feet, 5 feet, or 10 feet from the wellbore.
  • Such adjacent or close proximity positioning of the M EMS sensors with respect to the wellbore is in contrast to placing MEMS sensors in a fluid that is pumped into the formation in large volumes and substantially penetrates, migrates, or travels into or through the formation, for example as occurs with a fracturing fluid or a flooding fluid.
  • the MEMS sensors are placed proximate or adjacent to the wellbore (in contrast to the formation at large), and provide information relevant to the wellbore itself and compositions (e.g., sealants) used therein (again in contrast to the formation or a producing zone at large).
  • the MEMS sensors are distributed from the wellbore into the surrounding formation (e.g., additionally or alternatively non-proximate or non- adjacent to the wellbore), for example as a component of a fracturing fluid or a flooding fluid described in more detail herein.
  • the sealant is any wellbore sealant known in the art.
  • sealants include cementitious and non-cementitious sealants both of which are well known in the art.
  • non- cementitious sealants comprise resin based systems, latex based systems, or combinations thereof.
  • the sealant comprises a cement slurry with styrene-butadiene latex (e.g., as disclosed in U.S. Pat. No. 5,588,488 incorporated by reference herein in its entirety). Sealants may be utilized in setting expandable casing, which is further described below.
  • the sealant is a cement utilized for primary or secondary wellbore cementing operations, as discussed further below.
  • the sealant is cementitious and comprises a hydraulic cement that sets and hardens by reaction with water.
  • hydraulic cements include but are not limited to Portland cements (e.g., classes A, B, C, G, and H Portland cements), pozzolana cements, gypsum cements, phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, magnesia cements, fly ash cement, zeolite cement systems, cement kiln dust cement systems, slag cements, micro-fine cement, metakaolin, and combinations thereof.
  • sealants are disclosed in U.S. Pat. Nos.
  • the sealant comprises a sorel cement composition, which typically comprises magnesium oxide and a chloride or phosphate salt which together form for example magnesium oxychloride.
  • magnesium oxychloride sealants are disclosed in U.S. Pat. Nos. 6,664,215 and 7,044,222, each of which is incorporated herein by reference in its entirety.
  • the wellbore composition may include a sufficient amount of water to form a pumpable slurry.
  • the water may be fresh water or salt water (e.g., an unsaturated aqueous salt solution or a saturated aqueous salt solution such as brine or seawater).
  • the cement slurry may be a lightweight cement slurry containing foam (e.g., foamed cement) and/or hollow beads/microspheres.
  • the M EMS sensors are incorporated into or attached to all or a portion of the hollow microspheres. Thus, the M EMS sensors may be dispersed within the cement along with the microspheres. Examples of sealants containing microspheres are disclosed in U.S. Pat. Nos.
  • the MEMS sensors are incorporated into a foamed cement such as those described in more detail in U.S. Pat. Nos. 6,063,738; 6,367,550; 6,547,871; and 7,174,962, each of which is incorporated by reference herein in its entirety.
  • additives may be included in the cement composition for improving or changing the properties thereof.
  • additives include but are not limited to accelerators, set retarders, defoamers, fluid loss agents, weighting materials, dispersants, density-reducing agents, formation conditioning agents, lost circulation materials, thixotropic agents, suspension aids, or combinations thereof.
  • Other mechanical property modifying additives for example, fibers, polymers, resins, latexes, and the like can be added to further modify the mechanical properties. These additives may be included singularly or in combination. Methods for introducing these additives and their effective amounts are known to one of ordinary skill in the art.
  • the MEMS sensors are contained within a wellbore composition that forms a filtercake on the face of the formation when placed downhole.
  • various types of drilling fluids also known as muds or drill-in fluids have been used in well drilling, such as water-based fluids, oil-based fluids (e.g., mineral oil, hydrocarbons, synthetic oils, esters, etc.), gaseous fluids, or a combination thereof.
  • Drilling fluids typically contain suspended solids. Drilling fluids may form a thin, slick filter cake on the formation face that provides for successful drilling of the wellbore and helps prevent loss of fluid to the subterranean formation.
  • At least a portion of the M EMS remain associated with the filtercake (e.g., disposed therein) and may provide information as to a condition (e.g., thickness) and/or location of the filtercake. Additionally or in the alternative at least a portion of the M EMS remain associated with drilling fluid and may provide information as to a condition and/or location of the drilling fluid.
  • the MEMS sensors are contained within a wellbore composition that when placed downhole under suitable conditions induces fractures within the su bterranean formation.
  • Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a fracturing fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create, enhance, and/or extend at least one fracture therein. Stimulating or treating the wellbore in such ways increases hydrocarbon production from the well.
  • the MEMS sensors may be contained within a wellbore composition that when placed downhole enters and/or resides within one or more fractures within the subterranean formation.
  • the M EMS sensors provide information as to the location and/or condition of the fluid and/or fracture during and/or after treatment. In an embodiment, at least a portion of the M EMS remain associated with a fracturing fluid and may provide information as to the condition and/or location of the fluid.
  • Fracturing fluids often contain proppants that are deposited within the formation upon placement of the fracturing fluid therein, and in an embodiment a fracturing fluid contains one or more proppants and one or more MEMS.
  • At least a portion of the MEMS remain associated with the proppants deposited within the formation (e.g., a proppant bed) and may provide information as to the condition (e.g., thickness, density, settling, stratification, integrity, etc.) and/or location of the proppants. Additionally or in the alternative at least a portion of the M EMS remain associated with a fracture (e.g., adhere to and/or retained by a surface of a fracture) and may provide information as to the condition (e.g., length, volume, etc.) and/or location of the fracture. For example, the MEMS sensors may provide information useful for ascertaining the fracture complexity.
  • the MEMS sensors are contained in a wellbore composition (e.g., gravel pack fluid) which is employed in a gravel packing treatment, and the M EMS may provide information as to the condition and/or location of the wellbore composition during and/or after the gravel packing treatment.
  • Gravel packing treatments are used, inter alia, to reduce the migration of unconsolidated formation particulates into the wellbore.
  • particulates referred to as gravel
  • carrier fluid a servicing fluid known as carrier fluid. That is, the particulates are suspended in a carrier fluid, which may be viscosified, and the carrier fluid is pumped into a wellbore in which the gravel pack is to be placed.
  • the resultant gravel pack acts as a filter to separate formation solids from produced fluids while permitting the produced fluids to flow into and through the wellbore.
  • the gravel is carried to the formation in the form of a slurry by mixing the gravel with a viscosified carrier fluid.
  • Such gravel packs may be used to stabilize a formation while causing minimal impairment to well productivity.
  • the gravel inter alia, acts to prevent the particulates from occluding the screen or migrating with the produced fluids, and the screen, inter alia, acts to prevent the gravel from entering the wellbore.
  • the wellbore servicing composition (e.g., gravel pack fluid) comprises a carrier fluid, gravel and one or more M EMS.
  • the MEMS remain associated with the gravel deposited within the wellbore and/or formation (e.g., a gravel pack/bed) and may provide information as to the condition (e.g., thickness, density, settling, stratification, integrity, etc.) and/or location of the gravel pack/bed.
  • the MEMS may provide information as to a location, flow path/profile, volume, density, temperature, pressure, or a combination thereof of a sealant composition, a drilling fluid, a fracturing fluid, a gravel pack fluid, or other wellbore servicing fluid in real time such that the effectiveness of such service may be monitored and/or adjusted during performance of the service to improve the result of same.
  • the M EMS may aid in the initial performance of the well bore service additionally or alternatively to providing a means for monitoring a wellbore condition or performance of the service over a period of time (e.g., over a servicing interval and/or over the life of the well).
  • the one or more M EMS sensors may be used in monitoring a gas or a liquid produced from the subterranean formation.
  • MEMS present in the wellbore and/or formation may be used to provide information as to the condition (e.g., temperature, pressure, flow rate, composition, etc.) and/or location of a gas or liquid produced from the subterranean formation.
  • the MEMS provide information regarding the composition of a produced gas or liquid.
  • the M EMS may be used to monitor an amount of water produced in a hydrocarbon producing well (e.g., amount of water present in hydrocarbon gas or liquid), an amount of undesirable components or contaminants in a produced gas or liquid (e.g., sulfur, carbon dioxide, hydrogen sulfide, etc. present in hydrocarbon gas or liquid), or a combination thereof.
  • the data sensors added to the wellbore composition are passive sensors that do not require continuous power from a battery or an external source in order to transmit real-time data.
  • the data sensors are micro-electromechanical systems (MEMS) comprising one or more (and typically a plurality of) M EMS devices, referred to herein as MEMS sensors.
  • MEMS devices are well known, e.g., a semiconductor device with mechanical features on the micrometer scale.
  • M EMS embody the integration of mechanical elements, sensors, actuators, and electronics on a common substrate.
  • the substrate comprises silicon.
  • M EMS elements include mechanical elements which are movable by an input energy (electrical energy or other type of energy).
  • a sensor may be designed to emit a detectable signal based on a number of physical phenomena, including thermal, biological, optical, chemical, and magnetic effects or stimulation.
  • MEMS devices are minute in size, have low power requirements, are relatively inexpensive and are rugged, and thus are well suited for use in wellbore servicing operations.
  • the M EMS sensors added to a wellbore servicing fluid may be active sensors, for example powered by an internal battery that is rechargeable or otherwise powered and/or recharged by other downhole power sources such as heat capture/transfer and/or fluid flow, as described in more detail herein.
  • the data sensors comprise an active material connected to (e.g., mounted within or mounted on the surface of) an enclosure, the active material being liable to respond to a wellbore parameter, and the active material being operably connected to (e.g., in physical contact with, surrounding, or coating) a capacitive M EMS element.
  • the MEMS sensors sense one or more parameters within the wellbore.
  • the parameter is temperature.
  • the parameter is pH.
  • the parameter is moisture content.
  • the parameter may be ion concentration (e.g., chloride, sodium, and/or potassium ions).
  • the M EMS sensors may also sense well cement characteristic data such as stress, strain, or combinations thereof.
  • the MEMS sensors of the present disclosure may comprise active materials that respond to two or more measu rands. In such a way, two or more parameters may be monitored.
  • a MEMS sensor incorporated within one or more of the wellbore compositions disclosed herein may provide information that allows a condition (e.g., thickness, density, volume, settling, stratification, etc.) and/or location of the composition within the subterranean formation to be detected.
  • a condition e.g., thickness, density, volume, settling, stratification, etc.
  • Suitable active materials such as dielectric materials, that respond in a predictable and stable manner to changes in parameters over a long period may be identified according to methods well known in the art, for example see, e.g., Ong, Zeng and Grimes. "A Wireless, Passive Carbon
  • the MEMS sensors are coupled with radio frequency identification devices (RFIDs) and can th us detect and transmit parameters and/or well cement characteristic data for monitoring the cement during its service life.
  • RFIDs combine a microchip with an antenna (the RFID chip and the antenna are collectively referred to as the "transponder” or the "tag”).
  • the antenna provides the RFID chip with power when exposed to a narrow band, high frequency electromagnetic field from a transceiver.
  • Such a device can return a unique identification "ID” number by modulating and re-radiating the radio frequency (RF) wave.
  • RF radio frequency
  • Passive RF tags are gaining widespread use due to their low cost, indefinite life, simplicity, efficiency, ability to identify parts at a distance without contact (tether-free information transmission ability). These robust and tiny tags are attractive from an environmental standpoint, as they require no battery.
  • the MEMS sensor and RFID tag are preferably integrated into a single component (e.g., chip or su bstrate), or may alternatively be separate components operably coupled to each other.
  • an integrated, passive MEMS/RFI D sensor contains a data sensing component, an optional memory, and an RFID antenna, whereby excitation energy is received and powers up the sensor, thereby sensing a present condition and/or accessing one or more stored sensed conditions from memory and transmitting same via the RFI D antenna.
  • MEMS sensors having different RFID tags i.e., antennas that respond to RF waves of different frequencies and power the RFID chip in response to exposure to RF waves of different frequencies may be added to different wellbore compositions.
  • commonly used operating bands for RFID systems center on one of the three government assigned frequencies: 125 kHz, 13.56 MHz or 2.45 GHz.
  • a fourth frequency, 27.125 M Hz has also been assigned.
  • the 2.45 GHz carrier frequency is used, the range of an RFID chip can be many meters. While this is useful for remote sensing, there may be multiple transponders within the RF field.
  • anti- collision schemes are used, as are known in the art.
  • the data sensors are integrated with local tracking hardware to transmit their position as they flow within a wellbore composition such as a sealant slurry.
  • the data sensors may form a network using wireless links to neighboring data sensors and have location and positioning capability through, for example, local positioning algorithms as are known in the art.
  • the sensors may organize themselves into a network by listening to one another, therefore allowing communication of signals from the farthest sensors towards the sensors closest to the interrogator to allow uninterrupted transmission and capture of data.
  • the interrogator tool may not need to traverse the entire section of the wellbore containing M EMS sensors in order to read data gathered by such sensors. For example, the interrogator tool may only need to be lowered about half-way along the vertical length of the wellbore containing M EMS sensors.
  • the interrogator tool may be lowered vertically within the well bore to a location adjacent to a horizontal arm of a well, whereby M EMS sensors located in the horizontal arm may be read without the need for the interrogator tool to traverse the horizontal arm.
  • the interrogator tool may be used at or near the surface and read the data gathered by the sensors distributed along all or a portion of the wellbore. For example, sensors located a distance away from the interrogator (e.g., at an opposite end of a length of casing or tubing) may communicate via a network formed by the sensors as described previously.
  • the MEMS sensors are ultra-small, e.g., 3 mm 2 , such that they are pumpable in a sealant slurry.
  • the M EMS device is approximately 0.01 mm 2 to 1 mm 2 , alternatively 1 mm 2 to 3 mm 2 , alternatively 3 mm 2 to 5 mm 2 , or alternatively 5 mm 2 to 10 mm 2 .
  • the data sensors are capable of providing data throughout the cement service life. In embodiments, the data sensors are capable of providing data for up to 100 years.
  • the wellbore composition comprises an amount of MEMS effective to measure one or more desired parameters. In various embodiments, the wellbore composition comprises an effective amount of M EMS such that sensed readings may be obtained at intervals of about 1 foot, alternatively about 6 inches, or alternatively about 1 inch, along the portion of the wellbore containing the M EMS. In an
  • the M EMS sensors may be present in the wellbore composition in an amount of from about 0.001 to about 10 weight percent. Alternatively, the M EMS may be present in the wellbore composition in an amount of from about 0.01 to about 5 weight percent.
  • the sensors may have dimensions (e.g., diameters or other dimensions) that range from nanoscale, e.g., about 1 to 1000 nm (e.g., NEMS), to a micrometer range, e.g., about 1 to 1000 ⁇ (e.g., MEMS), or alternatively any size from about 1 nm to about 1 mm.
  • the M EMS sensors may be present in the wellbore composition in an amount of from about 5 volume percent to about 30 volume percent.
  • the size and/or amount of sensors present in a wellbore composition may be selected such that the resultant wellbore servicing composition is readily pumpable without damaging the sensors and/or without having the sensors undesirably settle out (e.g., screen out) in the pumping equipment (e.g., pumps, conduits, tanks, etc.) and/or upon placement in the wellbore.
  • the concentration/loading of the sensors with in the wellbore servicing fluid may be selected to provide a sufficient average distance between sensors to allow for networking of the sensors (e.g., daisy-chaining) in embodiments using such networks, as described in more detail herein.
  • such distance may be a percentage of the average communication distance for a given sensor type.
  • a given sensor having a 2 inch communication range in a given wellbore composition should be loaded into the wellbore composition in an amount that the average distance between sensors in less than 2 inches (e.g., less than 1.9, 1.8, 1.7, 1.6, 1.5, 1.4, 1.3, 1.2, 1.1, 1.0, etc. inches).
  • the size of sensors and the amount may be selected so that they are stable, do not float or sink, in the well treating fluid.
  • the size of the sensor could range from nano size to microns.
  • the sensors may be nanoelectromechanical systems (NEMS), M EMS, or combinations thereof.
  • any suitable micro and/or nano sized sensors or combinations thereof may be employed.
  • the embodiments disclosed herein should not otherwise be limited by the specific type of micro and/or nano sensor employed unless otherwise indicated or prescribed by the functional requirements thereof, and specifically NEMS may be used in addition to or in lieu of MEMS sensors in the various embodiments disclosed herein.
  • the MEMS sensors comprise passive (remain unpowered when not being interrogated) sensors energized by energy radiated from a data interrogation tool.
  • the data interrogation tool may comprise an energy transceiver sending energy (e.g., radio waves) to and receiving signals from the MEMS sensors and a processor processing the received signals.
  • the data interrogation tool may further comprise a memory component, a communications component, or both.
  • the memory component may store raw and/or processed data received from the M EMS sensors, and the
  • communications component may transmit raw data to the processor and/or transmit processed data to another receiver, for example located at the surface.
  • the tool components e.g., transceiver, processor, memory component, and communications component
  • the tool components are coupled together and in signal communication with each other.
  • one or more of the data interrogator components may be integrated into a tool or unit that is temporarily or permanently placed downhole (e.g., a downhole module), for example prior to, concurrent with, and/or subsequent to placement of the M EMS sensors in the wellbore.
  • a removable downhole module comprises a transceiver and a memory component, and the downhole module is placed into the wellbore, reads data from the M EMS sensors, stores the data in the memory component, is removed from the wellbore, and the raw data is accessed.
  • the removable downhole module may have a processor to process and store data in the memory component, which is subsequently accessed at the surface when the tool is removed from the wellbore.
  • the removable downhole module may have a communications component to transmit raw data to a processor and/or transmit processed data to another receiver, for example located at the surface.
  • the communications component may communicate via wired or wireless communications.
  • the downhole component may communicate with a component or other node on the surface via a network of M EMS sensors, or cable or other communications/telemetry device such as a radio frequency, electromagnetic telemetry device or an acoustic telemetry device.
  • the removable downhole component may be intermittently positioned downhole via any suitable conveyance, for example wire-line, coiled tubing, straight tubing, gravity, pumping, etc., to monitor conditions at various times during the life of the well.
  • the data interrogation tool comprises a permanent or semi-permanent downhole component that remains downhole for extended periods of time.
  • a semi-permanent downhole module may be retrieved and data downloaded once every few months or years.
  • a permanent downhole module may remain in the well throughout the service life of well.
  • a permanent or semipermanent downhole module comprises a transceiver and a memory component, and the downhole module is placed into the wellbore, reads data from the MEMS sensors, optionally stores the data in the memory component, and transmits the read and optionally stored data to the surface.
  • the permanent or semi-permanent downhole module may have a processor to process and sensed data into processed data, which may be stored in memory and/or transmit to the surface.
  • the permanent or semi-permanent downhole module may have a communications component to transmit raw data to a processor and/or transmit processed data to another receiver, for example located at the surface.
  • the communications component may communicate via wired or wireless communications.
  • the downhole component may communicate with a component or other node on the surface via a network of M EMS sensors, or a cable or other communications/telemetry device such as a radio frequency, electromagnetic telemetry device or an acoustic telemetry device.
  • the data interrogation tool comprises an RF energy source incorporated into its internal circuitry and the data sensors are passively energized using an RF antenna, which picks up energy from the RF energy source.
  • the data interrogation tool is integrated with an RF transceiver.
  • the MEMS sensors e.g., M EMS/RFID sensors
  • the MEMS sensors are empowered and interrogated by the RF transceiver from a distance, for example a distance of greater than 10 m, or alternatively from the surface or from an adjacent offset well.
  • the data interrogation tool traverses within a casing in the well and reads M EMS sensors located in a wellbore servicing fluid or composition, for example a sealant (e.g., cement) sheath surrounding the casing, located in the annular space between the casing and the wellbore wall.
  • the interrogator senses the M EMS sensors when in close proximity with the sensors, typically via traversing a removable downhole component along a length of the wellbore comprising the M EMS sensors.
  • close proximity comprises a radial distance from a point within the casing to a planar point within an annular space between the casing and the wellbore. In embodiments, close proximity comprises a distance of 0.1 m to 1 m.
  • close proximity comprises a distance of 1 m to 5 m.
  • close proximity comprises a distance of from 5 m to 10 m.
  • the transceiver interrogates the sensor with RF energy at 125 kHz and close proximity comprises 0.1 m to 5 m.
  • the transceiver interrogates the sensor with RF energy at 13.5 M Hz and close proximity comprises 0.05 m to 0.5 m.
  • the transceiver interrogates the sensor with RF energy at 915 MHz and close proximity comprises 0.03 m to 0.1 m.
  • the transceiver interrogates the sensor with RF energy at 2.4 GHz and close proximity comprises 0.01 m to 0.05 m.
  • the MEMS sensors incorporated into wellbore cement and used to collect data during and/or after cementing the wellbore.
  • the data interrogation tool may be positioned downhole prior to and/or during cementing, for example integrated into a component such as casing, casing attachment, plug, cement shoe, or expanding device.
  • the data interrogation tool is positioned downhole upon completion of cementing, for example conveyed downhole via wireline.
  • the cementing methods disclosed herein may optionally comprise the step of foaming the cement composition using a gas such as nitrogen or air.
  • the foamed cement compositions may comprise a foaming surfactant and optionally a foaming stabilizer.
  • the MEMS sensors may be incorporated into a sealant composition and placed downhole, for example during primary cementing (e.g., conventional or reverse circulation cementing), secondary cementing (e.g., squeeze cementing), or other sealing operation (e.g., behind an expandable casing).
  • primary cementing e.g., conventional or reverse circulation cementing
  • secondary cementing e.g., squeeze cementing
  • other sealing operation e.g., behind an expandable casing
  • cement In primary cementing, cement is positioned in a wellbore to isolate an adjacent portion of the subterranean formation and provide support to an adjacent conduit (e.g., casing).
  • the cement forms a barrier that prevents fluids (e.g., water or hydrocarbons) in the subterranean formation from migrating into adjacent zones or other subterranean formations.
  • fluids e.g., water or hydrocarbons
  • the wellbore in which the cement is positioned belongs to a horizontal or multilateral wellbore configuration. It is to be understood that a multilateral wellbore configuration includes at least two principal wellbores connected by one or more ancillary wellbores.
  • FIG. 2 which shows a typical onshore oil or gas drilling rig and wellbore, will be used to clarify the methods of the present disclosure, with the understanding that the present disclosure is likewise applicable to offshore rigs and wellbores.
  • Rig 12 is centered over a subterranean oil or gas formation 14 located below the earth's surface 16.
  • Rig 12 includes a work deck 32 that supports a derrick 34.
  • Derrick 34 supports a hoisting apparatus 36 for raising and lowering pipe strings such as casing 20.
  • Pump 30 is capable of pumping a variety of wellbore compositions (e.g., drilling fluid or cement) into the well and includes a pressure measurement device that provides a pressure reading at the pump discharge.
  • Wellbore 18 has been drilled through the various earth strata, including formation 14.
  • casing 20 is often placed in the wellbore 18 to facilitate the production of oil and gas from the formation 14.
  • Casing 20 is a string of pipes that extends down wellbore 18, through which oil and gas will eventually be extracted.
  • a cement or casing shoe 22 is typically attached to the end of the casing string when the casing string is run into the wellbore.
  • Casing shoe 22 guides casing 20 toward the center of the hole and minimizes problems associated with hitting rock ledges or washouts in wellbore 18 as the casing string is lowered into the well.
  • Casing shoe, 22, may be a guide shoe or a float shoe, and typically comprises a tapered, often bullet- nosed piece of equipment found on the bottom of casing string 20.
  • Casing shoe, 22, may be a float shoe fitted with an open bottom and a valve that serves to prevent reverse flow, or U-tu bing, of cement slurry from annulus 26 into casing 20 as casing 20 is run into wellbore 18.
  • the region between casing 20 and the wall of wellbore 18 is known as the casing annulus 26.
  • casing 20 is usually "cemented" in wellbore 18, which is referred to as "primary cementing.”
  • a data interrogator tool 40 is shown in the well bore 18.
  • the method of this disclosure is used for monitoring primary cement during and/or subsequent to a conventional primary cementing operation.
  • MEMS sensors are mixed into a cement slurry, block 102 of FIG. 1, and the cement slurry is then pumped down the inside of casing 20, block 104 of FIG. 1.
  • the slurry reaches the bottom of casing 20, it flows out of casing 20 and into casing annulus 26 between casing 20 and the wall of wellbore 18.
  • cement slurry flows up annulus 26, it displaces any fluid in the wellbore.
  • devices called "wipers" may be pumped by a wellbore servicing fluid (e.g., drilling mud) through casing 20 behind the cement.
  • a wellbore servicing fluid e.g., drilling mud
  • the wellbore servicing fluids such as the cement slurry and/or wiper conveyance fluid (e.g., drilling mud) may contain M EMS sensors which aid in detection and/or positioning of the wellbore servicing fluid and/or a mechanical component such as a wiper plug, casing shoe, etc.
  • the wiper contacts the inside surface of casing 20 and pushes any remaining cement out of casing 20.
  • cement slurry reaches the earth's surface 16
  • annulus 26 is filled with slurry
  • pumping is terminated and the cement is allowed to set.
  • the M EMS sensors of the present disclosure may also be used to determine one or more parameters during placement and/or curing of the cement slurry.
  • the M EMS sensors of the present disclosure may also be used to determine completion of the primary cementing operation, as further discussed herein below.
  • a data interrogation tool may be positioned in wellbore 18, as at block 106 of FIG. 1.
  • the wiper may be equipped with a data interrogation tool and may read data from the MEMS while being pumped downhole and transmit same to the surface.
  • an interrogator tool may be run into the wellbore following completion of cementing a segment of casing, for example as part of the drill string during resumed drilling operations.
  • the interrogator tool may be run downhole via a wireline or other conveyance. The data interrogation tool may then be signaled to interrogate the sensors (block 108 of FIG.
  • the data interrogation tool communicates the data to a processor 112 whereby data sensor (and likewise cement slurry) position and cement integrity may be determined via analyzing sensed parameters for changes, trends, expected values, etc. For example, such data may reveal conditions that may be adverse to cement curing.
  • the sensors may provide a temperature profile over the length of the cement sheath, with a uniform temperature profile likewise indicating a uniform cure (e.g., produced via heat of hydration of the cement during curing) or a change in temperature might indicate the influx of formation fluid (e.g., presence of water and/or hydrocarbons) that may degrade the cement during the transition from slurry to set cement.
  • such data may indicate a zone of reduced, minimal, or missing sensors, which would indicate a loss of cement
  • Reverse circulation cementing is a term of art used to describe a method where a cement slurry is pumped down casing annulus 26 instead of into casing 20. The cement slurry displaces any fluid as it is pumped down annulus 26. Fluid in the annulus is forced down annulus 26, into casing 20 (along with any fluid in the casing), and then back up to earth's surface 16.
  • casing shoe 22 comprises a valve that is adjusted to allow flow into casing 20 and then sealed after the cementing operation is complete.
  • sealant slurries comprising M EMS data sensors are pumped down the annulus in reverse circulation applications, a data interrogator is located within the wellbore (e.g., integrated into the casing shoe) and sealant performance is monitored as described with respect to the conventional primary sealing method disclosed hereinabove. Additionally, the data sensors of the present disclosure may also be used to determine completion of a reverse circulation operation, as further discussed below.
  • Secondary cementing within a wellbore may be carried out subsequent to primary cementing operations.
  • a common example of secondary cementing is squeeze cementing wherein a sealant such as a cement composition is forced under pressure into one or more permeable zones within the wellbore to seal such zones.
  • permeable zones include fissures, cracks, fractures, streaks, flow channels, voids, high permeability streaks, annular voids, or combinations thereof.
  • the permeable zones may be present in the cement column residing in the annulus, a wall of the conduit in the wellbore, a microannulus between the cement column and the
  • the sealant e.g., secondary cement composition
  • Various procedures that may be followed to use a sealant composition in a wellbore are described in U.S. Pat. No. 5,346,012, which is incorporated by reference herein in its entirety.
  • a sealant composition comprising M EMS sensors is used to repair holes, channels, voids, and microannuli in casing, cement sheath, gravel packs, and the like as described in U.S. Pat. Nos. 5,121,795; 5,123,487; and 5,127,473, each of which is incorporated by reference herein in its entirety.
  • the method of the present disclosure may be employed in a secondary cementing operation.
  • data sensors are mixed with a sealant composition (e.g., a secondary cement slurry) at block 102 of FIG.
  • the sensors are interrogated to monitor the performance of the secondary cement in an analogous manner to the incorporation and monitoring of the data sensors in primary cementing methods disclosed hereinabove.
  • the MEMS sensors may be used to verify that the secondary sealant is functioning properly and/or to monitor its long-term integrity.
  • the methods of the present disclosure are utilized for monitoring cementitious sealants (e.g., hydraulic cement), non- cementitious (e.g., polymer, latex or resin systems), or combinations thereof, which may be used in primary, secondary, or other sealing applications.
  • cementitious sealants e.g., hydraulic cement
  • non- cementitious e.g., polymer, latex or resin systems
  • combinations thereof which may be used in primary, secondary, or other sealing applications.
  • expandable tubulars such as pipe, pipe string, casing, liner, or the like are often sealed in a subterranean formation.
  • the expandable tubular e.g., casing
  • a sealing composition is placed into the wellbore
  • the expandable tubular is expanded, and the sealing composition is allowed to set in the wellbore.
  • a mandrel may be run through the casing to expand the casing diametrically, with expansions up to 25% possible.
  • the expandable tu bular may be placed in the wellbore before or after placing the sealing composition in the wellbore.
  • the expandable tubular may be expanded before, during, or after the set of the sealing composition.
  • resilient compositions will remain competent due to their elasticity and compressibility. Additional tu bulars may be used to extend the wellbore into the subterranean formation below the first tubular as is known to those of skill in the art.
  • sealant compositions and methods of using the compositions with expandable tubulars are disclosed in U.S. Pat. Nos. 6,722,433 and 7,040,404 and U.S. Pat. Pub. No. 2004/0167248, each of which is incorporated by reference herein in its entirety.
  • the sealants may comprise compressible hydraulic cement compositions and/or non-cementitious compositions.
  • Compressible hydraulic cement compositions have been developed which remain competent (continue to support and seal the pipe) when compressed, and such compositions may comprise M EMS sensors.
  • the sealant composition is placed in the annulus between the wellbore and the pipe or pipe string, the sealant is allowed to harden into an impermeable mass, and thereafter, the expandable pipe or pipe string is expanded whereby the hardened sealant composition is compressed.
  • the sealant is placed in the annulus between the wellbore and the pipe or pipe string, the sealant is allowed to harden into an impermeable mass, and thereafter, the expandable pipe or pipe string is expanded whereby the hardened sealant composition is compressed.
  • compressible foamed sealant composition comprises a hydraulic cement, a ru bber latex, a rubber latex stabilizer, a gas and a mixture of foaming and foam stabilizing surfactants.
  • Suitable hydraulic cements include, but are not limited to, Portland cement and calcium aluminate cement.
  • non-cementitious resilient sealants with comparable strength to cement, but greater elasticity and compressibility, are required for cementing expandable casing.
  • these sealants comprise polymeric sealing compositions, and such compositions may comprise M EMS sensors.
  • the sealants composition comprises a polymer and a metal containing compound.
  • the polymer comprises copolymers, terpolymers, and interpolymers.
  • the metal-containing compounds may comprise zinc, tin, iron, selenium magnesium, chromium, or cadmium.
  • the compounds may be in the form of an oxide, carboxylic acid salt, a complex with dithiocarbamate ligand, or a complex with mercaptobenzothiazole ligand.
  • the sealant comprises a mixture of latex, dithio carbamate, zinc oxide, and sulfur.
  • the methods of the present disclosure comprise adding data sensors to a sealant to be used behind expandable casing to monitor the integrity of the sealant upon expansion of the casing and during the service life of the sealant.
  • the sensors may comprise M EMS sensors capable of measuring, for example, moisture and/or temperature change. If the sealant develops cracks, water influx may thus be detected via moisture and/or temperature indication.
  • the MEMS sensors are added to one or more wellbore servicing compositions used or placed downhole in drilling or completing a monodiameter well bore as disclosed in U.S. Pat. No. 7,066,284 and U.S. Pat. Pub. No. 2005/0241855, each of which is incorporated by reference herein in its entirety.
  • the MEMS sensors are included in a chemical casing composition used in a monodiameter wellbore.
  • the MEMS sensors are included in compositions (e.g., sealants) used to place expandable casing or tubulars in a monodiameter wellbore. Examples of chemical casings are disclosed in U.S. Pat. Nos.
  • the MEMS sensors are used to gather data, e.g., sealant data, and monitor the long-term integrity of the wellbore composition, e.g., sealant composition, placed in a wellbore, for example a wellbore for the recovery of natural resources such as water or hydrocarbons or an injection well for disposal or storage.
  • data e.g., sealant data
  • the wellbore composition e.g., sealant composition
  • data/information gathered and/or derived from M EMS sensors in a downhole wellbore composition e.g., sealant composition
  • a downhole wellbore composition e.g., sealant composition
  • Such models and simulators may be used to select a wellbore composition, e.g., sealant composition, comprising MEMS for use in a wellbore.
  • the M EMS sensors may provide data that can be used to refine, recalibrate, or correct the models and simulators.
  • the M EMS sensors can be used to monitor and record the downhole conditions that the composition, e.g., sealant, is subjected to, and composition, e.g., sealant, performance may be correlated to such long term data to provide an indication of problems or the potential for problems in the same or different wellbores.
  • data gathered from MEMS sensors is used to select a wellbore composition, e.g., sealant composition, or otherwise evaluate or monitor such sealants, as disclosed in U.S. Pat. Nos. 6,697,738; 6,922,637; and 7,133,778, each of which is incorporated by reference herein in its entirety.
  • compositions and methodologies of this disclosure are employed in an operating environment that generally comprises a wellbore that penetrates a subterranean formation for the purpose of recovering hydrocarbons, storing hydrocarbons, injection of carbon dioxide, storage of carbon dioxide, disposal of carbon dioxide, and the like, and the M EMS located downhole (e.g., within the wellbore and/or surrounding formation) may provide information as to a condition and/or location of the composition and/or the subterranean formation.
  • the MEMS may provide information as to a location, flow path/profile, volume, density, temperature, pressure, or a combination thereof of a hydrocarbon (e.g., natural gas stored in a salt dome) or carbon dioxide placed in a subterranean formation such that effectiveness of the placement may be monitored and evaluated, for example detecting leaks, determining remaining storage capacity in the formation, etc.
  • a hydrocarbon e.g., natural gas stored in a salt dome
  • carbon dioxide placed in a subterranean formation such that effectiveness of the placement may be monitored and evaluated, for example detecting leaks, determining remaining storage capacity in the formation, etc.
  • the compositions of this disclosure are employed in an enhanced oil recovery operation wherein a wellbore that penetrates a subterranean formation may be su bjected to the injection of gases (e.g., carbon dioxide) so as to improve hydrocarbon recovery from said wellbore, and the MEMS may provide information as to a condition and/or location of the composition and/or the subterranean formation.
  • gases e.g., carbon dioxide
  • the M EMS may provide information as to a location, flow path/profile, volume, density, temperature, pressure, or a combination thereof of carbon dioxide used in a carbon dioxide flooding enhanced oil recovery operation in real time such that the effectiveness of such operation may be monitored and/or adjusted in real time during performance of the operation to improve the result of same.
  • actual measured conditions experienced during the life of the well in addition to or in lieu of the estimated conditions, may be used. Such actual measured conditions may be obtained for example via sealant compositions comprising MEMS sensors as described herein.
  • Effectiveness considerations include concerns that the sealant composition be stable under downhole conditions of pressure and temperature, resist downhole chemicals, and possess the mechanical properties to withstand stresses from various downhole operations to provide zonal isolation for the life of the well.
  • step 212 well input data for a particular well is determined.
  • Well input data includes routinely measurable or calculable parameters inherent in a well, including vertical depth of the well, overburden gradient, pore pressure, maximum and minimum horizontal stresses, hole size, casing outer diameter, casing inner diameter, density of drilling fluid, desired density of sealant slurry for pumping, density of completion fluid, and top of sealant.
  • the well can be computer modeled. In modeling, the stress state in the well at the end of drilling, and before the sealant slurry is pumped into the annular space, affects the stress state for the interface boundary between the rock and the sealant composition.
  • well input data includes data that is obtained via sealant compositions comprising MEMS sensors as described herein.
  • the well events applicable to the well are determined.
  • cement hydration (setting) is a well event.
  • Other well events include pressure testing, well completions, hydraulic fracturing, hydrocarbon production, fluid injection, perforation, subsequent drilling, formation movement as a result of producing hydrocarbons at high rates from unconsolidated formation, and tectonic movement after the sealant composition has been pumped in place.
  • Well events include those events that are certain to happen during the life of the well, such as cement hydration, and those events that are readily predicted to occur during the life of the well, given a particular well's location, rock type, and other factors well known in the art.
  • well events and data associated therewith may be obtained via sealant compositions comprising M EMS sensors as described herein.
  • Each well event is associated with a certain type of stress, for example, cement hydration is associated with shrinkage, pressure testing is associated with pressure, well completions, hydraulic fracturing, and hydrocarbon production are associated with pressure and temperature, fluid injection is associated with temperature, formation movement is associated with load, and perforation and subsequent drilling are associated with dynamic load.
  • each type of stress can be characterized by an equation for the stress state (collectively "well event stress states"), as described in more detail in U.S. Pat. No. 7,133,778 which is incorporated herein by reference in its entirety.
  • step 216 the well input data, the well event stress states, and the sealant data are used to determine the effect of well events on the integrity of the sealant sheath during the life of the well for each of the sealant compositions.
  • the sealant compositions that would be effective for sealing the subterranean zone and their capacity from its elastic limit are determined.
  • the estimated effects over the life of the well are compared to and/or corrected in comparison to corresponding actual data gathered over the life of the well via sealant compositions comprising MEMS sensors as described herein.
  • Step 216 concludes by determining which sealant compositions would be effective in maintaining the integrity of the resulting cement sheath for the life of the well.
  • step 2128 parameters for risk of sealant failure for the effective sealant compositions are determined. For example, even though a sealant composition is deemed effective, one sealant composition may be more effective than another. In one embodiment, the risk parameters are calculated as percentages of sealant competency during the determination of
  • the risk parameters are compared to and/or corrected in comparison to actual data gathered over the life of the well via sealant compositions comprising MEMS sensors as described herein.
  • Step 218 provides data that allows a user to perform a cost benefit analysis. Due to the high cost of remedial operations, it is important that an effective sealant composition is selected for the conditions anticipated to be experienced during the life of the well. It is understood that each of the sealant compositions has a readily calculable monetary cost. Under certain conditions, several sealant compositions may be equally efficacious, yet one may have the added virtue of being less expensive. Thus, it should be used to minimize costs. More commonly, one sealant composition will be more efficacious, but also more expensive. Accordingly, in step 220, an effective sealant composition with acceptable risk parameters is selected given the desired cost.
  • steps 200-220 can be compared to actual data that is obtained via sealant compositions comprising M EMS sensors as described herein, and such data may be used to modify and/or correct the inputs and/or outputs to the various steps 200-220 to improve the accuracy of same.
  • wipers are often utilized during conventional primary cementing to force cement slurry out of the casing.
  • the wiper plug also serves another purpose: typically, the end of a cementing operation is signaled when the wiper plug contacts a restriction (e.g., casing shoe) inside the casing 20 at the bottom of the string. When the plug contacts the restriction, a sudden pressure increase at pump 30 is registered. In this way, it can be determined when the cement has been displaced from the casing 20 and fluid flow returning to the surface via casing annulus 26 stops.
  • a restriction e.g., casing shoe
  • FIG. 3 is a flowchart of a method for determining completion of a cementing operation and optionally further actuating a downhole tool upon completion (or to initiate completion) of the cementing operation. This description will reference the flowchart of FIG. 3, as well as the wellbore depiction of FIG. 2.
  • a data interrogation tool as described hereinabove is positioned at the far end of casing 20.
  • the data interrogation tool is incorporated with or adjacent to a casing shoe positioned at the bottom end of the casing and in communication with operators at the surface.
  • M EMS sensors are added to a fluid (e.g., cement slurry, spacer fluid, displacement fluid, etc.) to be pumped into annulus 26.
  • cement slurry is pumped into annulus 26.
  • M EMS sensors may be placed in substantially all of the cement slurry pumped into the wellbore.
  • M EMS sensors may be placed in a leading plug or otherwise placed in an initial portion of the cement to indicate a leading edge of the cement slurry.
  • MEMS sensors are placed in leading and trailing plugs to signal the beginning and end of the cement slurry.
  • the fluid of block 130 is the cement slurry
  • MEMS-based data sensors are incorporated within the set cement, and parameters of the cement (e.g., temperature, pressure, ion concentration, stress, strain, etc.) can be monitored during placement and for the duration of the service life of the cement according to methods disclosed hereinabove.
  • the data sensors may be added to an interface fluid (e.g., spacer fluid or other fluid plug) introduced into the annulus prior to and/or after introduction of cement slurry into the annulus.
  • the method just described for determination of the completion of a primary wellbore cementing operation may further comprise the activation of a downhole tool.
  • a valve or other tool may be operably associated with a data interrogator tool at the far end of the casing.
  • This valve may be contained within float shoe 22, for example, as disclosed hereinabove.
  • float shoe 22 may contain an integral data interrogator tool, or may otherwise be coupled to a data interrogator tool.
  • the data interrogator tool may be positioned between casing 20 and float shoe 22.
  • pumping continues as the data interrogator tool detects the presence or absence of data sensors in close proximity to the interrogator tool (dependent upon the specific method cementing method being employed, e.g., reverse circulation, and the positioning of the sensors within the cement flow).
  • the data interrogator tool Upon detection of a determinative presence or absence of sensors in close proximity indicating the termination of the cement slurry, the data interrogator tool sends a signal to actuate the tool (e.g., valve) at block 140.
  • the valve closes, sealing the casing and preventing cement from entering the portion of casing string above the valve in a reverse cementing operation.
  • the closing of the valve at 142 causes an increase in back pressure that is detected at the hydraulic pump 30.
  • pumping is discontinued, and cement is allowed to set in the annulus at block 148.
  • parameters of the cement can additionally be monitored during placement and for the duration of the service life of the cement according to methods disclosed hereinabove.
  • systems for sensing, communicating and evaluating wellbore parameters may include the wellbore 18; the casing 20 or other workstring, toolstring, production string, tubular, coiled tubing, wireline, or any other physical structure or conveyance extending downhole from the surface; MEMS sensors 52 that may be placed into the wellbore 18 and/or surrounding formation 14, for example, via a wellbore servicing fluid; and a device or plurality of devices for interrogating the M EMS sensors 52 to gather/collect data generated by the MEMS sensors 52, for transmitting the data from the MEMS sensors 52 to the earth's surface 16, for receiving communications and/or data to the earth's surface, for processing the data, or any combination thereof, referred to collectively herein a data
  • the wellbore servicing fluid comprising the M EMS sensors 52 may comprise a drilling fluid, a spacer fluid, a sealant, a fracturing fluid, a gravel pack fluid, a completion fluid, or any other fluid placed downhole.
  • the M EMS sensors 52 may be configured to measure physical parameters such as temperature, stress and strain, as well as chemical parameters such as C0 2 concentration, H 2 S concentration, CH 4 concentration, moisture content, pH, Na + concentration, K + concentration, and CI "
  • Various embodiments described herein are directed to interrogation/communication units that are dispersed or distributed at intervals along a length of the casing 20 and form a communication network for transmitting and/or receiving communications to/from a location downhole and the surface, with the further understanding that the
  • interrogation/communication units may be otherwise physically supported by a workstring, toolstring, production string, tu bular, coiled tubing, wireline, or any other physical structure or conveyance extending downhole from the surface.
  • the wellbore parameter sensing system 600 may comprise the wellbore 18, inside which the casing 20 is situated.
  • the wellbore parameter sensing system 600 may further comprise a plurality of regional communication units 610, which may be situated on the casing 20 and spaced at regular or irregular intervals along the casing, e.g., about every 5 m to 15 m along the length of the casing 20, alternatively about every 8 m to 12 m along the length of the casing 20, alternatively about every 10 m along the length of the casing 20.
  • a plurality of regional communication units 610 which may be situated on the casing 20 and spaced at regular or irregular intervals along the casing, e.g., about every 5 m to 15 m along the length of the casing 20, alternatively about every 8 m to 12 m along the length of the casing 20, alternatively about every 10 m along the length of the casing 20.
  • the regional communication units 610 may be situated on or in casing collars that couple casing joints together. In addition, the regional communication units 610 may be situated in an interior of the casing 20, on an exterior of the casing 20, or both.
  • the wellbore parameter sensing system 600 may further comprise a tool (e.g., a data interrogator 620 or other data collection and/or power-providing device), which may be lowered down into the wellbore 18 on a wireline 622, as well as a processor 630 or other data storage or communication device, which is connected to the data interrogator 620.
  • a tool e.g., a data interrogator 620 or other data collection and/or power-providing device
  • each regional communication unit 610 may be configured to interrogate and/or receive data from, MEMS sensors 52 situated in the annulus 26, in the vicinity of the regional communication unit 610, whereby the vicinity of the regional communication unit 610 is defined as in the above discussion of the wellbore parameter sensing system 300 illustrated in FIG. 5.
  • the MEMS sensors 52 may be configured to transmit M EMS sensor data to neigh boring M EMS sensors 52, as denoted by double arrows 632, as well as to transmit MEMS sensor data to the regional communication units 610 in their respective vicinities, as denoted by single arrows 634.
  • the M EMS sensors 52 may be passive sensors that are powered by bursts of electromagnetic radiation from the regional communication units 610.
  • the M EMS sensors 52 may be active sensors that are powered by batteries situated in or on the MEMS sensors 52 or by other downhole power sources.
  • the regional communication units 610 in the present embodiment of the wellbore parameter sensing system 600 are neither wired to one another, nor wired to the processor 630 or other surface equipment. Accordingly, in an embodiment, the regional communication units 610 may be powered by batteries, which enable the regional communication units 610 to interrogate the MEMS sensors 52 in their respective vicinities and/or receive M EMS sensor data from the M EMS sensors 52 in their respective vicinities.
  • the batteries of the regional communication units 610 may be inductively rechargeable by the data interrogator 620 or may be rechargeable by other downhole power sources.
  • the data interrogator 620 may be lowered into the wellbore 18 for the purpose of interrogating regional communication units 610 and receiving the M EMS sensor data stored in the regional communication units 610. Furthermore, the data interrogator 620 may be configured to transmit the MEMS sensor data to the processor 630, which processes the MEMS sensor data. In an embodiment, a fluid containing M EMS in contained within the wellbore casing (for example, as shown in FIGS. 5, 6, 7, and 10), and the data interrogator 620 is conveyed through such fluid and into communicative proximity with the regional communication units 610.
  • the data interrogator 620 may communicate with, power up, and/or gather data directly from the various MEMS sensors distributed within the annulus 26 and/or the casing 20, and such direct interaction with the M EMS sensors may be in addition to or in lieu of communication with one or more of the regional communication units 610. For example, if a given regional communication unit 610 experiences an operational failure, the data interrogator 620 may directly communicate with the M EMS within the given region experiencing the failure, and thereby serve as a backup (or secondary/verification) data collection option. [0096] Referring to FIG. 6, a schematic view of an embodiment of a wellbore parameter sensing system 700 is illustrated.
  • the wellbore parameter sensing system 700 comprises the wellbore 18 and the casing 20 that is situated inside the wellbore 18.
  • the wellbore parameter sensing system 700 comprises a plurality of regional communication units 710, which may be situated on the casing 20 and spaced at regular or irregular intervals along the casing, e.g., about every 5 m to 15 m along the length of the casing 20, alternatively about every 8 m to 12 m along the length of the casing 20, alternatively about every 10 m along the length of the casing 20.
  • the regional communication units 710 may be situated on or in casing collars that couple casing joints together.
  • the regional communication units 710 may be situated in an interior of the casing 20, on an exterior of the casing 20, or both, or may be otherwise located and supported as described in various embodiments herein.
  • the wellbore parameter sensing system 700 further comprises one or more primary (or master) communication units 720.
  • the regional communication units 710a and the primary communication unit 720a may be coupled to one another by a data line 730, which allows sensor data obtained by the regional communication units 710a from MEMS sensors 52 situated in the annulus 26 to be transmitted from the regional data line 730.
  • the MEMS sensors 52 may sense at least one wellbore parameter and transmit data regarding the at least one wellbore parameter to the regional communication units 710b, either via neighboring M EMS sensors 52 as denoted by double arrow 734, or directly to the regional communication units 710 as denoted by single arrows 736.
  • the regional communication units 710b may communicate wirelessly with the primary or master communication unit 720b, which may in turn communicate wirelessly with equipment located at the surface (or via telemetry such as casing signal telemetry) and/or other regional communication units 720a and/or other primary or master communication units 720a.
  • the primary or master communication units are configured to communicate
  • 720 gather information from the MEMS sensors and transmit (e.g., wirelessly, via wire, via telemetry such as casing signal telemetry, etc.) such information to equipment (e.g., processor 750) located at the surface.
  • equipment e.g., processor 750 located at the surface.
  • the wellbore parameter sensing system 700 further comprises, additionally or alternatively, a data interrogator 740, which may be lowered into the well bore 18 via a wire line 742, as well as a processor 750, which is connected to the data interrogator 740.
  • the data interrogator 740 is suspended adjacent to the primary communication unit 720, interrogates the primary communication unit 720, receives MEMS sensor data collected by all of the regional communication units 710 and transmits the M EMS sensor data to the processor 750 for processing.
  • the data interrogator 740 may provide other functions, for example as described with reference to data interrogator 620 of FIG. 5.
  • the data interrogator 740 may communicate directly or indirectly with any one or more of the M EMS sensors (e.g., sensors 52), local or regional data interrogation/communication units (e.g., units 310, 510, 610, 710), primary or master communication units (e.g., units 720), or any combination thereof.
  • M EMS sensors e.g., sensors 52
  • local or regional data interrogation/communication units e.g., units 310, 510, 610, 710
  • primary or master communication units e.g., units 720
  • FIG. 7 a schematic view of an embodiment of a wellbore parameter sensing system 800 is illustrated.
  • the wellbore parameter sensing system 800 comprises the wellbore 18 and the casing 20 that is situated inside the wellbore 18.
  • the wellbore parameter sensing system 800 comprises the wellbore 18 and the casing 20 that is situated inside the wellbore 18.
  • the wellbore parameter sensing system 800 comprises a plurality of local, regional, and/or primary/master communication units 810, which may be situated on the casing 20 and spaced at regular or irregular intervals along the casing 20, e.g., about every 5 m to 15 m along the length of the casing 20, alternatively about every 8 m to 12 m along the length of the casing 20, alternatively about every 10 m along the length of the casing 20.
  • the communication units 810 may be situated on or in casing collars that couple casing joints together.
  • the communication units 810 may be situated in an interior of the casing 20, on an exterior of the casing 20, or both, or may be otherwise located and supported as described in various embodiments herein.
  • M EMS sensors 52 which are present in a wellbore servicing fluid that has been placed in the well bore 18, may sense at least one wellbore parameter and transmit data regarding the at least one wellbore parameter to the local, regional, and/or primary/master
  • communication units 810 either via neighboring M EMS sensors 52 as denoted by double arrows 812, 814, or directly to the communication units 810 as denoted by single arrows 816, 818.
  • the wellbore parameter sensing system 800 may further comprise a data interrogator 820, which is connected to a processor 830 and is configured to interrogate each of the communication units 810 for MEMS sensor data via a ground penetrating signal 822 and to transmit the M EMS sensor data to the processor 830 for processing.
  • a data interrogator 820 which is connected to a processor 830 and is configured to interrogate each of the communication units 810 for MEMS sensor data via a ground penetrating signal 822 and to transmit the M EMS sensor data to the processor 830 for processing.
  • one or more of the communication units 810 may be coupled together by a data line (e.g., wired communications).
  • the M EMS sensor data collected from the M EMS sensors 52 by the regional communication units 810 may be transmitted via the data line to, for example, the regional communication unit 810 situated furthest uphole.
  • only one regional communication unit 810 is interrogated by the surface located data interrogator 820.
  • an energy and/or parameter (intensity, strength, wavelength, amplitude, frequency, etc.) of the ground penetrating signal 822 may be able to be reduced.
  • a data interrogator such as unit 620 or 740
  • the surface unit 810 may be used in addition to or in lieu of the surface unit 810, for example to serve as a back-up in the event of operation difficulties associated with surface unit 820 and/or to provide or serve as a relay between surface unit 820 and one or more units downhole such as a regional unit 810 located at an upper end of a string of interrogator units.
  • FIGS. 5- 7 For sake of clarity, it should be understood that like components as described in any of FIGS. 5-7 may be combined and/or substituted to yield additional embodiments and the functionality of such components in such additional embodiments will be apparent based upon the description of FIGS. 5- 7 and the various components therein. For example, in various embodiments disclosed herein (including but not limited to the embodiments of FIGS.
  • the local, regional, and/or primary/master communication/data interrogation units may communicate with one another and/or equipment located at the surface via signals passed using a common structural support as the transmission medium (e.g., casing, tubular, production tubing, drill string, etc.), for example by encoding a signal using telemetry technology such as an electrical/mechanical transducer.
  • a common structural support e.g., casing, tubular, production tubing, drill string, etc.
  • the local, regional, and/or primary/master communication/data interrogation units may communicate with one another and/or equipment located at the surface via signals passed using a network formed by the MEMS sensors (e.g., a daisy-chain network) distributed along the wellbore, for example in the annular space 26 (e.g., in a cement) and/or in a wellbore servicing fluid inside casing 20.
  • a network formed by the MEMS sensors e.g., a daisy-chain network
  • the MEMS sensors e.g., a daisy-chain network distributed along the wellbore, for example in the annular space 26 (e.g., in a cement) and/or in a wellbore servicing fluid inside casing 20.
  • the local, regional, and/or primary/master communication/data interrogation units may communicate with one another and/or equipment located at the surface via signals passed using a ground penetrating signal produced at the surface, for example being powered up by such a ground-penetrating signal and transmitting a return signal back to the surface via a reflected signal and/or a daisy-chain network of M EMS sensors and/or wired communications and/or telemetry transmitted along a mechanical conveyance/medium.
  • one or more of), the local, regional, and/or primary/master communication/data interrogation units may serve as a relay or broker of signals/messages containing information/data across a network formed by the units and/or M EMS sensors.
  • a method 900 of servicing a wellbore is described.
  • a plurality of M EMS sensors is placed in a wellbore servicing fluid.
  • the wellbore servicing fluid is placed in a wellbore.
  • data is obtained from the MEMS sensors, using a plurality of data interrogation units spaced along a length of the well bore.
  • the data obtained from the M EMS sensors is processed.
  • a further method 1000 of servicing a wellbore is described.
  • a plurality of M EMS sensors is placed in a wellbore servicing fluid.
  • the wellbore servicing fluid is placed in a wellbore.
  • a network consisting of the M EMS sensors is formed.
  • data obtained by the MEMS sensors is transferred from an interior of the wellbore to an exterior of the wellbore via the network consisting of the M EMS sensors.
  • a conduit e.g., casing 20 or other tubular such as a production tu bing, drill string, workstring, or other mechanical conveyance, etc.
  • a conduit in the well bore 18 may be used as a data transmission medium, or at least as a housing for a data transmission medium, for transmitting M EMS sensor data from the MEMS sensors 52 and/or
  • interrogation/communication units situated in the wellbore 18 to an exterior of the wellbore e.g., earth's surface 16.
  • other physical supports may be used as a data transmission medium such as a workstring, toolstring, production string, tubular, coiled tubing, wireline, jointed pipe, or any other physical structure or conveyance extending downhole from the surface.
  • the casing 1120 may comprise a groove, cavity, or hollow 1122, which runs longitudinally along an outer surface 1124 of the casing, along at least a portion of a length of the 1120 casing.
  • the groove 1122 may be open or may be enclosed, for example with an exterior cover applied over the groove and attached to the casing (e.g., welded) or may be enclosed as an integral portion of the casing body/structure (e.g., a bore running the length of each casing segment).
  • at least one cable 1130 may be embedded or housed in the groove 1122 and run longitudinally along a length of the groove 1122.
  • the cable 1130 may be insulated (e.g., electrically insulated) from the casing 1120 by insulation 1132.
  • the cable 1130 may be a wire, fiber optic, or other physical medium capable of transmitting signals.
  • a plurality of cables 1130 may be situated in groove 1122, for example, one or more insulated electrical lines configured to power pieces of equipment situated in the wellbore 18 and/or one or more data lines configured to carry data signals between downhole devices and an exterior of the wellbore 18.
  • the cable 1130 may be any suitable electrical, signal, and/or data communication line, and is not limited to metallic conductors such as copper wires but also includes fiber optical cables and the like.
  • FIG. 11 illustrates an embodiment of a wellbore parameter sensing system 1100, comprising the wellbore 18 inside which a wellbore servicing fluid loaded with MEMS sensors 52 is situated; the casing 1120 having a groove 1122; a plurality of data interrogation/communication units 1140 situated on the casing 1120 and spaced along a length of the casing 1120; a processing unit 1150 situated at an exterior of the wellbore 18; and a power supply 1160 situated at the exterior of the wellbore 18.
  • the data interrogation/communication units are identical to each other.
  • the data interrogation/communication units 1140 may be situated on or in casing collars that couple casing joints together.
  • the data interrogation/communication units 1140 may be situated in an interior of the casing 1120, on an exterior of the casing 1120, or both.
  • the data interrogation/communication units 1140a may be connected to the cable(s) and/or data line(s) 1130 via through- holes 1134 in the insulation 1132 and/or the casing (e.g., outer surface 1124).
  • the data interrogation/communication units 1140a may be connected to the power supply 1160 via cables 1130, as well as to the processor 1150 via data line(s) 1133.
  • the data interrogation/communication units 1140a commonly connected to one or more cables 1130 and/or data lines 1133 may function (e.g., collect and communication MEMS sensor data) in accordance with any of the embodiments disclosed herein having wired connections/communications, including but not limited to FIG. 6.
  • the wellbore parameter sensing system 1100 may further comprise one or more data
  • interrogation/communication units 1140b in wireless communication and may function (e.g., collect and communication MEMS sensor data) in accordance with any of the embodiments disclosed herein having wireless
  • connections/communications including but not limited to FIGS. 5-7.
  • the MEMS sensors 52 present in a wellbore servicing fluid situated in an interior of the casing 1120 and/or in the annulus 26 measure at least one wellbore parameter.
  • interrogation/communication units 1140 in a vicinity of the M EMS sensors 52 interrogate the sensors 52 at regular intervals and receive data from the sensors 52 regarding the at least one well bore parameter.
  • the data interrogation/communication units 1140 then transmit the sensor data to the processor 1150, which processes the sensor data.
  • the MEMS sensors 52 may be passive tags, i.e., may be powered, for example, by bursts of electromagnetic radiation from sensors of the regional data interrogation/communication units 1140.
  • the MEMS sensors 52 may be active tags, i.e., powered by a battery or batteries situated in or on the tags 52 or other downhole power source.
  • batteries of the M EMS sensors 52 may be inductively rechargeable by the regional data interrogation/communication units 1140.
  • the casing 1120 may be used as a conductor for powering the data interrogation/communication units 1140, or as a data line for transmitting MEMS sensor data from the data
  • FIG. 12 illustrates an embodiment of a wellbore parameter sensing system 1200, comprising the wellbore 18 inside which a wellbore servicing fluid loaded with MEMS sensors 52 is situated; the casing 20; a plurality of data interrogation/communication units 1210 situated on the casing 20 and spaced along a length of the casing 20; and a processing unit 1220 situated at an exterior of the wellbore 18.
  • the data interrogation/communication units are identical to each other.
  • the data interrogation/communication units 1210 may be situated on or in casing collars that couple casing joints together.
  • the data interrogation/communication units 1210 may be situated in an interior of the casing 20, on an exterior of the casing 20, or both.
  • the data interrogation/communication units 1210 may each comprise an acoustic transmitter, which is configured to convert M EMS sensor data received by the data interrogation/communication units 1210 from the MEMS sensors 52 into acoustic signals that take the form of acoustic vibrations in the casing 20, which may be referred to as acoustic telemetry embodiments.
  • the acoustic transmitters may operate, for example, on a piezoelectric or magnetostrictive principle and may produce axial compression waves, torsional waves, radial compression waves or transverse waves that propagate along the casing 20 in an uphole direction denoted by arrows 1212.
  • acoustic transmitters as part of an acoustic telemetry system is given in U.S. Patent Application Publication No. 2010/0039898 and U.S. Pat. Nos. 3,930,220; 4,156,229; 4,298,970; and
  • data interrogation/communication units 1210 may be powered as described herein in various embodiments, for example by internal batteries that may be inductively rechargeable by a recharging unit run into the wellbore 18 on a wireline or by other downhole power sources.
  • the wellbore parameter sensing system 1200 further comprises at least one acoustic receiver 1230, which is situated at or near an uphole end of the casing 20, receives acoustic signals generated and transmitted by the acoustic transmitters, converts the acoustic signals into electrical signals and transmits the electrical signals to the processing unit 1220.
  • Arrows 1232 denote the reception of acoustic signals by acoustic receiver 1230.
  • the acoustic receiver 1230 may be powered by an electrical line running from the processing unit 1220 to the acoustic receiver 1230.
  • the wellbore parameter sensing system 1200 further comprises a repeater 1240 situated on the casing 20.
  • the repeater 1240 may be configured to receive acoustic signals from the data
  • the repeater 1240 may be configured to retransmit, to the acoustic receiver 1230, acoustic signals regarding the data received by these downhole data
  • interrogation/communication units 1210 from M EMS sensors 52.
  • Arrows 1244 denote the retransmission of acoustic signals by repeater 1240.
  • the wellbore parameter sensing system 1200 may comprise multiple repeaters 1230 spaced along the casing 20.
  • the data interrogation/communication units 1210 and/or the repeaters 1230 may contain suitable equipment to encode a data signal into the casing 20 (e.g, electrical/mechanical transducing circuitry and equipment).
  • the M EMS sensors 52 situated in the interior of the casing 20 and/or in the annulus 26 may measure at least one wellbore parameter and then transmit data regarding the at least one wellbore parameter to the data interrogation/communication units 1210 in their respective vicinities in accordance with the various embodiments disclosed herein, including but not limited to FIGS. 5-9.
  • the acoustic transmitters in the data interrogation/communication units 1210 may convert the M EMS sensor data into acoustic signals that propagate up the casing 20.
  • the repeater or repeaters 1240 may receive acoustic signals from the data interrogation/communication units 1210 downhole from the respective repeater 1240 and retransmit acoustic signals further up the casing 20.
  • the acoustic receiver 1230 may receive the acoustic signals propagated up the casing 20, convert the acoustic signals into electrical signals and transmit the electrical signals to the processing unit 1220.
  • the processing unit 1220 then processes the electrical signals.
  • the acoustic telemetry embodiments and associated equipment may be combined with a network formed by the MEMS sensors and/or data interrogation/communication units (e.g., a point to point or "daisy-chain" network comprising M EMS sensors) to provide back-up or redundant wireless communication network functionality for conveying M EMS data from downhole to the surface.
  • a network formed by the MEMS sensors and/or data interrogation/communication units e.g., a point to point or "daisy-chain" network comprising M EMS sensors
  • a network formed by the MEMS sensors and/or data interrogation/communication units e.g., a point to point or "daisy-chain" network comprising M EMS sensors
  • wireless communications and networks could be further combines with various wired embodiments disclosed herein for further operational advantages.
  • a method 1300 of servicing a wellbore is described.
  • a plurality of MEMS sensors is placed in a wellbore servicing fluid.
  • the wellbore servicing fluid is placed in a wellbore.
  • data is obtained from the M EMS sensors, using a plurality of data interrogation units spaced along a length of the well bore.
  • the data is telemetrically transmitted from an interior of the wellbore to an exterior of the wellbore, using a casing situated in the wellbore (e.g., via acoustic telemetry).
  • the data obtained from the M EMS sensors is processed.
  • FIG. 14 is a functional representation of an example communication assembly 1400 shown from an end view, as may be used to measure the sealant (or other well servicing fluids) present within different azimuthal regions of the annulus. Communication assembly 1400 is discussed below with reference to some elements depicted in FIG. 5-7.
  • the example communication assembly 1400 includes a plurality of fins 1402 that extend longitudinally along the assembly and in spaced relation to one another around the periphery of the assembly.
  • fins 1402 will be hollow and will house control circuitry or other electronics, for example, voltage-controlled oscillators, memory, analog RF circuitry, sensors, power systems, processors, and other circuitry to enable communication with an external location, etc.
  • the fins 1402 will further include interrogation circuitry suitable for generating signals to both interrogate RFID tags (which may include additional MEMS sensor components, as described earlier herein) and to receive signals from those interrogated RFID tags. Such signals will be communicated to one or more antennas 1404 operatively coupled to each instance of such interrogation circuitry). An instance of interrogation circuitry with at least one antenna will form a "sensor assembly" for sensing the presence of RFID tags, and any additional information obtained when the RFID tags are interrogated (such as sensor data).
  • tags may be interrogated though a sensor assembly using a single antenna to both send interrogation signals to RFID tags and receive response signals from such tags.
  • a sensor assembly may be configured to use two antennas, one for transmitting the interrogation signals and the other for receiving the response signals.
  • Each sensor assembly (as defined below), includes at least one antenna and the identified interrogation circuitry; however, each sensor assembly will not necessarily include a discrete instance of the interrogation circuitry.
  • the interrogation circuitry can be configured to send/receive signals through multiple antennas, or through multiple pairs of antennas (depending on the sensor assembly configuration).
  • each antenna in a single antenna send/receive assembly
  • each pair of antennas in a dual antenna send-receive assembly
  • the antennas will be operably coupled to a discrete or shared instance of interrogation circuitry to form the complete sensor assembly.
  • the location and orientation of the antenna(s) will control the area interrogated by the sensor assembly. Therefore, the location of each single antenna or pair of antenna operated by the interrogation circuitry to interrogate RFID tags will be identified as the "location" of the sensor assembly, notwithstanding that the associated interrogation circuitry may be placed at a different physical location.
  • each fin 1402 can be configured to communicate as desired with circuitry in another fin 1402. Such communications between can occur through use of any suitable mechanism as will be apparent to those skilled in the art, for example, through use of a serial peripheral interface (SPI), though embodiments are not limited thereto.
  • SPI serial peripheral interface
  • Communication assembly 1400 can be configured to be associated with the casing string by a variety of mechanisms.
  • communication assembly includes a body member 1408 supporting other components and facilitating association with the casing string.
  • communication assembly 1400 will include a sleeve body member configured to concentrically engage the outer diameter of a length of casing.
  • the sleeve body member can be placed over a length of casing before it is incorporated into the casing string 20, and then secured in place by an appropriate mechanism.
  • the sleeve body member may be secured against the upset at the box end of the casing section and then clamped in place.
  • communication assembly 1400 can include a body member configured as a specialized section of casing 20 (see FIG. 5), which either includes fins 1402 as depicted in FIG.
  • communication assembly 1400 can have a supporting body member configured as a hinged clamshell (or a two part assembly) that can be secured around a length of casing, without either having to be joined into the casing string or the casing having to be inserted through the body member, as with the above alternative examples.
  • the communication assembly may include either a toroidal coil with a core extending circumferentially to the assembly (and casing), or a solenoid coil with windings extending circumferentially around the assembly (and casing string) to transmit the communication signals.
  • Such assemblies may be more difficult to implement in either a clamshell or a multi-section form, relative to solid body member configurations such as the above examples.
  • example communication assembly Referring again to FIG. 14, example communication assembly
  • each pair of antennas is provided between each pair of adjacent ribs 1402 to sense RFID tags contained within fluid passing by communication assembly 1400 in the well annulus.
  • the sensor assemblies are presumed to be of a dual antenna configuration, and thus each pair of antennas between ribs, 1404 A-B, 1404 C-D, 1404 E-F and 1404 G-H, is intended to form a respective sensor assembly under the definition provided above.
  • each antenna may represent a separate sensor assembly. Because of the dual antenna sensor assembly configuration assumed in communication assembly 1400, each sensor assembly will interrogate RFID tags within a respective azimuthal quadrant of the annulus surrounding communication assembly 1400 in a well. Any number of ribs, or corresponding structures, may be provided as necessary to house the necessary circuitry, and as desired to provide interrogation within a determined azimuthal region surrounding
  • azimuthal detection is not limited to space between the ribs (or corresponding structures).
  • sensor assemblies may be located to sense "across" each rib to maximize azimuthal sensing of the annulus.
  • Each sensor assembly will often be configured to detect generally within a determined azimuthal region of the annulus. In some implementations, these azimuthal regions may all be distinguished from one another, while in others the azimuthal regions may partially overlap with one another. Additionally, each communication assembly may provide multiple longitudinally offset sensor assemblies, providing redundant sensing within a given azimuthal region. Of course, in many contemplated configurations, multiple communication assemblies longitudinally disposed along the casing string will measure corresponding azimuthal regions as other communication assemblies, albeit at different depths within the borehole.
  • communication assembly 1400 includes four sensor assemblies, as noted above.
  • additional ribs may be provided, and may be used to support additional antennas in desired orientations; and/or additional sensor assemblies might be longitudinally offset along communication assembly 1400 relative to those depicted in FIG. 14 (see FIG. 15C).
  • each communication assembly 1420, 1430, 1440 includes a plurality of antennas (coils) arranged to provide a plurality of sensor assemblies, though only one side of each communication assem bly is shown. Accordingly, it should be understood that the described structures would be replicated at a plurality of azimuthally offset locations around each communication assembly 1420, 1430, 1440.
  • Each antenna 1404 can be configured as a loop, dipole, etc., as desired.
  • the antennas 1404 are each depicted as a loop antenna, again in a dual antenna sensor assembly configuration. Each antenna may be oriented on the respective communication assembly 1420, 1430, 1440, as desired to orient the field of the antenna in a desired direction.
  • antennas may be secured proximate a metallic surface.
  • the antennas can be mounted on a dielectric material 1406 to prevent electrical shorts against such metallic surfaces of the communication assemblies.
  • this dielectric material can be of any type generally known to persons skilled in the art for electrically isolating and protecting electrical components within downhole tools.
  • a material such as Protech DRBTM or Protech CRBTM, available from the Halliburton Company of Houston, Texas can be used as a suitable dielectric material 1406.
  • the same dielectric material 1406, or another suitable material can be disposed over antennas 1404 to protect them from the harsh environment within a borehole, including risk of abrasion, chemically induced deterioration, etc.
  • one antenna 1404 of a pair will transmit RF signals to interrogate RFID tags from one antenna and the other antenna 1404 of the pair will be used to receive signals generated from the RFID tags in response to the interrogation signal.
  • a compatible RFID tag (not shown in FIG. 14) passing in the field between the pair of antennas 1404 will generate a change in the transmission pattern between antennas 1404 in response to the interrogation signal.
  • the antennas can be arranged such that they define a generally known region of investigation for the respective sensor assembly.
  • antennas 1412 and 1414 can be oriented to provide a region of investigation extending generally between the adjacent ribs 1402.
  • the sensor assembly with antennas 1412 and 1414 will investigate approximately a quadrant of the annulus surrounding communication assembly 1420, up to a maximum depth of investigation as determined by the specific implementation.
  • Monitoring the number of tags identified by that sensor assembly provides an indication of the volume of fluid in which those RFID tags are carried proximate the quadrant investigated by the sensor assembly.
  • the location of the antenna, in combination with an experimentally determined region of investigation can again provide a measure of fluid within azimuthal region of investigation of the sensor assembly.
  • the primary concern is as to the number of tags within an identifiable region rather than the placement of any individual tag.
  • Such a system can be implemented with relatively basic passive RFID tags that merely respond to an interrogation rather than transmitting a tag ID or other information.
  • interrogation circuitry within fin 1402 can, in some examples, interrogate the RFI D tags by scanning through a range of possible tag frequencies, in a manner of RFID tag interrogation known to those skilled in the art.
  • the interrogation circuitry will be configured to determine a location of the tag with respect to the antennas by more complex methodologies, such as through evaluating the amplitude of a signal reflected from the tag and/or triangulation through interrogation of a tag by multiple sensor assemblies.
  • the RFID tags each have a unique tag ID, enabling the tag to be individually distinguished.
  • interrogation circuitry within fin 1402 can be configured detect azimuthal direction of a tag based on a transmission pattern or amplitude of a reflected signal between a tag and one or more antennas 1404. Therefore, the nature or type of fluid in which tags are disposed can again be detected at different azimuthal directions relative to communication assembly 1400 and casing 20.
  • antennas are contemplated, and the described system is not limited to any particular configuration of antennas.
  • the number, arrangement and spacing of antennas can be adjusted based on, for example, power needs, performance requirements, or borehole conditions.
  • the communication assemblies may include a coil that extends in either a toroidal or solenoid form concentrically to the casing to facilitate wireless communication of obtained data.
  • An example coil 1408 is depicted in each of communication assem blies 1420, 1430, 1440.
  • the described acoustic transceiver 1656 includes an acoustic sensor 1652 configured to direct ultrasonic waves into the wellbore servicing fluid 1630 and to receive reflected waves. Acoustic transceiver 1656, also includes an acoustic transmitter 1660 and an acoustic receiver 1658, and as well as a microprocessor 1662 for providing the control functions to both transmit the acoustic signals and receive signals from the receivers. As depicted in FIG.
  • example communication assembly 1420 includes a plurality of such acoustic transceivers deployed circumferentially around the assembly.
  • the acoustic transceivers are placed between the ribs 1402.
  • the acoustic transceivers will have a thickness that would undesirably take up additional radial space relative to the body member 1408, as to make their placement between the ribs less than optimal.
  • acoustic transceivers 1656A-B may be incorporated into the ribs 1402.
  • any number of such acoustic transceivers may be included in each communication assembly 1420 in spaced relation around the circumference of body member 1408.
  • Communication assembly 1430 includes a sensor assembly including one anten na 1432 oriented along one fin 1402, with a paired antenna oriented at an angle such as by being placed generally in a plane tangential to body member 1408 of the
  • a second similarly arranged sensor assembly having a pair of antennas 1436, 1438 is included at a longitudinally offset location along body member 1408.
  • FIG. 15C depicts an alternative configuration of a communication assembly 1440 in which an antenna 1446 is placed in a generally central location between two ribs 1402 to serve as either a transmit or receive antenna relative to a pair of nearby antennas 1442, 1444.
  • Antennas 1442, 1444 may be mounted, for example, on the adjacent ribs 1402, and configured to perform the opposite transmit/receive function.
  • the central antenna 1446 is shared by two sensor assemblies each having antenna 1442 or 1444 as the other antenna. In some implementations, this configuration may serve to provide increased certainty of investigation across an azimuthal region of the surrounding annulus.
  • a plurality of communication assemblies will be disposed in longitudinally-spaced relation to each other along the casing 20, at least over a region of interest relative to either the sealing operation or to other downhole conditions.
  • a location, in particular a top location, of the sealant can be determined by finding a location on casing string 20 where below it, primarily only tags associated with the sealant are identified, while above the location, only tags associated with other fluids, for example spacer fluid or drilling mud, are identified. It will be understood there may be some mixing due to irregularities in the formation sidewalls that will trap some of the tags and possibly their associated fluids from the spacer and mud pumped through annulus 26. Therefore, some tags associated with one type of fluid may become mixed with a different type of flu id than that indicated by the tag type.
  • Each communication assembly will preferably include an azimuthal indicator, for example a compass, to determine the orientation of the communication assembly once it is disposed within the borehole.
  • an azimuthal indicator for example a compass
  • the orientation of each fin and/or sensor assembly will be known and therefore the quadrant or other azimuthally offset region being investigated will similarly be known.
  • the depth of each casing assembly can be known, for example through a record of the location of each communication assembly as it is associated with the casing string 20 as the string is placed in the wellbore, providing a measure of depth as to the surface.
  • TOC measurement can be done after the pumping of the sealant is completed or the measurement can be a dynamic measurement of the TOC while the sealant is moving up annulus 26.
  • the other measurements described herein facilitate measurements not only of the TOC, but also of the distribution of the cement or other sealant around the casing over the region of the casing string that includes associated communication assemblies. Regions where a minimal number of tags of the type entrained within the sealant are located indicate a region where, for some reason, sealant has been blocked from reaching the region, or has reached the region in a relatively limited volume. Identifying both the depth and orientation where this occurs facilitates remediation efforts.
  • Each communication assembly 1400 can report information associated with the sensed tags to a surface system, for example surface system 630, using communication methods described above regarding FIG. 5-7.
  • this may be as basic as a number of tags sensed within a given time interval, grouped or formatted in a manner to indicate the azimuthal orientation of the sensing. Sometimes, this will include a similar number of tags of each of a plurality of frequencies sensed within the time interval, and grouped or formatted to indicate the azimuthal orientation.
  • RFID tags may be used which include tag IDs, facilitating identification of which individual tags have been sensed.
  • the information associated with the sensed tags may include MEMS sensor data.
  • MEMS sensor tags may include sensors for detecting temperature or any of a variety of fluid properties, etc. These additional properties can be important to fully evaluating the quality of the sealing operation, particularly over time.
  • monitoring temperature in the annulus can identify regions where he sealant is curing either improperly or inconsistently relative to other areas in the annulus.
  • the ability to identify azimuthal regions where the temperature is inconsistent either with other regions or with expectations can be useful in identifying defects such as fluid incursions.
  • Such temperature sensing M EMS RFID tags may in some cases be active (having a contained power source) or may be passive and energized by the interrogation signal.
  • Sensed fluid properties may also be of significant use in evaluating the sealing operation. For example, a change in pH in a region of the annulus may also indicate a fluid incursion potentially adversely affecting the sealing operation. As with other measurements, the ability to identify an azimuthal orientation of the sensed parameter provides valuable information facilitating further analysis and/or remediation within the well. Again, in various embodiments these tags may be either active or passive. Temperature Monitoring Through the Communication Assemblies
  • M EMS sensor RFID tags may be used to monitor temperature within the annulus to evaluate curing of the sealant. In some situations, temperature variations might indicate fluid incursion and/or low barrier quality.
  • temperature sensors can be mounted on or associated with the communication assemblies, rather than the RFID tags. In some examples, these sensors may be mounted directly on the surface of the communication assembly. However, in some applications, it may be desirable to extend the sensors away from the communication assembly and casing, both to avoid temperature effects from those members, and to more directly monitor temperatures in the annulus.
  • one or more flexible fingers supporting temperature sensors can be anchored on the
  • the flexible fingers will typically be oriented to extend out into the annulus 26, and to extend in an uphole direction, so that as the casing string is lowered into the borehole, the fingers would be pointed back up toward the surface so they would not be caught on the formation during the run-in, but would instead drag the tips down the formation wall.
  • the sealant is pumped up the well from the bottom, again the fingers would be pointed downstream (i.e. uphole) with respect to the flowing sealant and would maintain their orientation in the annulus 26.
  • the temperature sensors and the wires leading back to the casing collar can be placed on the side of the fingers oriented toward the casing collar, thus protecting the sensors and wiring from the formation wall and the flowing sealant. With the sensors distributed along the fingers across the annulus 26, thermal measurement of the sealant may be improved. In such examples, the temperature information can be
  • a receiving unit such as a surface unit 630, along with the other sensed information from the communication assembly.
  • FIG. 16 the figure illustrates an embodiment of a portion of a wellbore parameter sensing system 1600.
  • the wellbore parameter sensing system 1600 comprises the wellbore 18, the casing 20 situated in the wellbore 18, a plurality of regional communication units 1610 attached to the casing 20 and spaced along a length of the casing 20, a processing unit 1620 situated at an exterior of the well bore and communicatively linked to the units 1610, and a wellbore servicing fluid 1630 situated in the wellbore 18.
  • the wellbore servicing fluid 1630 may comprise a plurality of MEMS sensors 1640, which are configured to measure at least one wellbore parameter.
  • the unit 16 represents a regional communication unit 1610 located on an exterior of the casing 20 in annular space 26 and surrounded by a cement composition comprising M EMS sensors.
  • the unit 1610 may further comprise a power source, for example a battery (e.g., lithium battery) or power generator.
  • a battery e.g., lithium battery
  • the unit 1610 may comprise an interrogation unit 1650, which is configured to interrogate the M EMS sensors 1640 and receive data regarding the at least one wellbore parameter from the M EMS sensors 1640.
  • the unit 1610 may also comprise at least one acoustic sensor 1652, which is configured to input ultrasonic waves 1654 into the wellbore servicing fluid 1630 and/or into the oil or gas formation 14 proximate to the wellbore 18 and receive ultrasonic waves reflected by the wellbore servicing fluid 1630 and/or the oil or gas formation 14.
  • the at least one acoustic sensor 1652 may transmit and receive ultrasonic waves using a pulse-echo method or pitch-catch method of ultrasonic sampling/testing.
  • a discussion of the pulse-echo and pitch-catch methods of ultrasonic sampling/testing may be found in the NASA preferred reliability practice no. PT-TE-1422, "Ultrasonic Testing of Aerospace Materials,"
  • ultrasonic waves and/or acoustic sensors may be provided via the unit 1610 in accordance with one or more embodiments disclosed in U.S. Pat. Nos. 5,995,447; 6,041,861; or 6,712,138, each of which is incorporated herein in its entirety.
  • the at least one acoustic sensor 1652 may be able to detect a presence and a position in the wel lbore 18 of a liquid phase and/or a solid phase of the well bore servicing fluid 1630.
  • the at least one acoustic sensor 1652 may be able to detect a presence of cracks and/or voids and/or inclusions in a solid phase of the wellbore servicing fluid 1630, e.g., in a partially cured cement slurry or a fully cured cement sheath.
  • the acoustic sensor 1652 may be able to determine a porosity of the oil or gas formation 14.
  • the acoustic sensor 1652 may be configured to detect a presence of the MEMS sensors 1640 in the wellbore servicing fluid 1630.
  • the acoustic sensor may scan for the physical presence of MEMS sensors proximate thereto, and may thereby be used to verify data derived from the MEMS sensors. For example, where acoustic sensor 1652 does not detect the presence of M EMS sensors, such lack of detection may provide a further indication that a wellbore servicing fluid has not yet arrived at that location (for example, has not entered the annulus). Likewise, where acoustic sensor 1652 does detect the presence of M EMS sensors, such presence may be further verified by interrogation on the MEMS sensors.
  • a failed attempt to interrogate the MEMS sensors where acoustic sensor 1652 indicates their presence may be used to trouble-shoot or otherwise indicate that a problem may exist with the MEMS sensor system (e.g., a fix data interrogation unit may be faulty thereby requiring repair and/or deployment of a mobile unit into the wellbore).
  • the acoustic sensor 1652 may perform any combination of the listed functions.
  • the acoustic sensor 1652 may be a piezoelectric-type sensor comprising at least one piezoelectric transducer for inputting ultrasonic waves into the wellbore servicing fluid 1630.
  • acoustic sensors comprising piezoelectric composite transducers may be found in U.S. Pat. No. 7,036,363, which is hereby incorporated by reference herein in its entirety.
  • the regional communication unit 1610 may further comprise an acoustic transceiver 1656.
  • the acoustic transceiver 1656 may comprise an acoustic receiver 1658, an acoustic transmitter 1660 and a microprocessor 1662.
  • the microprocessor 1662 may be configured to receive M EMS sensor data from the interrogation unit 1650 and/or acoustic sensor data from the at least one acoustic sensor 1652 and convert the sensor data into a form that may be transmitted by the acoustic transmitter 1660.
  • the acoustic transmitter 1660 may be configured to transmit the sensor data from the M EMS sensors 1640 and/or the acoustic sensor 1652 to an interrogation/communication unit situated uphole (e.g., the next unit directly uphole) from the unit 1610 shown in FIG. 16.
  • the acoustic transmitter 1660 may comprise a plurality of piezoelectric plate elements in one or more plate assemblies configured to input ultrasonic waves into the casing 20 and/or the wellbore servicing fluid 1630 in the form of acoustic signals (for example to provide acoustic telemetry
  • the acoustic receiver 1658 may be configured to receive sensor data in the form of acoustic signals from one or more acoustic transmitters disposed in one or more interrogation/communication units situated uphole and/or downhole from the unit 1610 shown in FIG. 16.
  • the acoustic receiver 1658 may be configured to transmit the sensor data to the microprocessor 1662.
  • a microprocessor or digital signal processor may be used to process sensor data, interrogate sensors and/or interrogation/communication units and communicate with devices situated at an exterior of a wellbore. For example, the microprocessor 1662 may then route/convey/retransmit the received data (and
  • interrogation/communication unit situated directly uphole and/or downhole from the unit 1610 shown in FIG. 16.
  • the received sensor data may be passed along to the next interrogation/communication unit without undergoing any transformation or further processing by microprocessor 1662.
  • sensor data acquired by interrogators 1650 and acoustic sensors 1652 situated in units 1610 disposed along at least a portion of the length of the casing 20 may be transmitted up or down the wellbore 18 to the processing unit 1620, which is configured to process the sensor data.
  • sensors, processing electronics, communication devices and power sources may be integrated inside a housing (e.g., a composite attachment or housing) that may, for example, be attached to an outer surface of a casing.
  • the housing may comprise a composite resin material.
  • the composite resin material may comprise an epoxy resin.
  • the composite resin material may comprise at least one ceramic material.
  • housing of unit 1610 e.g., composite housing
  • the housing of unit 1610 may be contained within a recess in the casing and by mounted flush with a wall of the casing. Any of the composite materials described herein may be used in embodiments to form a housing for unit 1610.
  • sensors may measure parameters of a wellbore servicing material in an annulus situated between a casing and an oil or gas formation.
  • the wellbore servicing material may comprise a fluid, a cement (or other sealant) slurry, a partially cured cement slurry, a cement sheath, or other materials.
  • Parameters of the wellbore and/or servicing material may be acquired and transmitted continuously or in discrete time, depending on demands.
  • parameters measured by the sensors include velocity of ultrasonic waves, Poisson's ratio, material phases, temperature, flow, compactness, pressure and other parameters described herein.
  • the unit 1610 may contain a plurality of sensor types used for measuring the parameters, and may include lead zirconate titanate (PZT) acoustic transceivers, electromagnetic transceivers, pressure sensors, temperature sensors and other sensors.
  • PZT lead zirconate titanate
  • unit 1610 may be used, for example, to monitor parameters during a curing process of cement situated in the annulus. In further embodiments, flow of production fluid through production tu bing and/or the casing may be monitored. In various embodiments, an
  • interrogation/communication unit e.g., unit 1610
  • interrogation/communication unit e.g., unit 1610
  • sensors e.g., electromagnetic and acoustic sensors as well as M EMS sensors
  • data to be processed in the interrogation/communication unit may include data from acoustic sensors, e.g., liquid/solid phase, annulus width, homogeneity/heterogeneity of a medium, velocity of acoustic waves through a medium and impedance, as well as data from MEMS sensors, which in embodiments include passive RFID tags and are interrogated electromagnetically.
  • each acoustic sensors e.g., liquid/solid phase, annulus width, homogeneity/heterogeneity of a medium, velocity of acoustic waves through a medium and impedance
  • MEMS sensors which in embodiments include passive RFID tags and are interrogated electromagnetically.
  • each acoustic sensors e.g., liquid/solid phase, annulus width, homo
  • interrogation/communication unit may process data pertaining to a vicinity or region of the wellbore associated to the unit.
  • the interrogation/communication unit may further comprise a memory device configured to store data acquired from sensors.
  • the sensor data may be tagged with time of acquisition, sensor type and/or identification information pertaining to the
  • raw and/or processed sensor data may be sent to an exterior of a wellbore for further processing or analysis, for example via any of the communication means, methods, or networks disclosed herein.
  • interrogation/communication units may be transmitted acoustically from unit to unit and to an exterior of the wellbore, using the casing as an acoustic transmission medium.
  • sensor data from each interrogation/communication unit may be transmitted to an exterior of the wellbore, using a very low frequency electromagnetic wave.
  • sensor data from each interrogation/communication unit may be transmitted via a daisy-chain to an exterior of the wellbore, using a very low frequency electromagnetic wave to pass the data along the chain.
  • a wire and/or fiber optic line coupled to each of the
  • interrogation/communication units may be used to transmit sensor data from each unit to an exterior of the wellbore, and also used to power the units.
  • a circumferential acoustic scanning tool comprising an acoustic transceiver may be lowered into a casing, along which the interrogation/communication units are spaced.
  • the acoustic transceiver in the circumferential acoustic scanning tool may be configured to interrogate corresponding acoustic transceivers in the interrogation/communication units, by transmitting an acoustic signal through the casing to the acoustic transceiver in the unit.
  • interrogation/communication unit may be able to store, for example, two weeks worth of sensor data before being interrogated by the circumferential acoustic scanning tool.
  • the acoustic transceiver in the circumferential acoustic scanning tool may further comprise a MEMS sensor interrogation unit, and thereby interrogate and collect data from MEMS sensors.
  • data interrogation/communication units or tools of the various embodiments disclosed herein may be powered by devices configured to generate electricity while the units are located in the wellbore, for example turbo generator units and/or quantum thermoelectric generator units.
  • the electricity generated by the devices may be used directly by components in the interrogation/communication units or may be stored in a battery or batteries for later use.
  • Figs. 17A-D depict several example embodiments illustrating signal/noise ratios as related to RFID detection.
  • detection of RFID tags may be difficult in some cases due to an electrically noisy environment or due to the distances between an RFID tag and an RFID detector. The greater the distance between the two, the more generally difficult it will be to detect the RFI D tag.
  • Structures and techniques described herein are suitable in a number of different specific configurations to detect RFID tags in environments such as a borehole of a subterranean well Note that to the example embodiments discussed below focus on the detecting/reading of RFID tags; but the described tags may, in some examples, have additional functionality.
  • the tags may include one or more MEMS sensors.
  • FIG. 17A-D depict example detection power curves relating to detecting of an RFID tag.
  • FIG. 17A depicts a conceptualized example of an ideal power response curve 1700 relating to detecting an RFID tag.
  • a power level is shown as would be measured by a sensor assembly. Note that as discussed above and herein, in some examples, such a sensor assembly may include an RFID detector circuit such as circuit 2200 (discussed below relative to Fig. 22).
  • power is used by a sensor assembly in order to emit an electromagnetic field usable to power (and detect) remote RFID tags. If an RFID tag is within sufficient distance of the emitted electromagnetic signal, for example, a current may be induced in the tag, causing an observable change in a power level at the sensor assembly (e.g., corresponding to power use by the RFID tag). Thus, if the sensor assembly detects a sufficient change in power, an RFID tag may be present.
  • tags may or may not be present at a particular time (such as a region of interest in a borehole during a cementing operation), detecting RFID tags in a reliable yet energy conscious manner may present challenges.
  • a power response is seen from an
  • RFID tag at a frequency at which the tag operates.
  • a tag operates at 5.040 MHz (for example)
  • no detectable power response may occur if the sensor assembly is transmitting at a frequency of 4 MHz, as one example.
  • a power response of the RFI D tag may be observed as the operating frequency of a tag is approached. Accordingly, in an example case, for a tag that operates at 5.040 MHz, some response might be observable at 5.039 MHz, while a greater (maximal) response might be observed at a scan frequency of 5.040 MHz.
  • a sensor assembly may scan at different frequencies to determine if one or more particular RFID tags exist within a detectable distance range.
  • Chart 1700 is shown as a conceptual ized ideal response curve for an RFID tag that operates at a frequency fi and that is within range of a suitable sensor assembly.
  • no power response from a tag is observed at a first scan frequency f 0 of the sensor assembly.
  • f 0 first scan frequency
  • a power response can be seen, with a maximum response being seen at tag operating frequency fi.
  • Continuing to increase the frequency of the sensor assembly past fi will then show a decreased power function, as seen in curve 1710.
  • a detection window for the RFID tag may therefore exist between f 0 and f 2 in this example.
  • the observed power response is flat (unchanged) in frequency ranges that are sufficiently far away from the operating frequency fi of the tag (e.g., beyond f 0 and f 2 ).
  • materials or other environmental factors will often affect the power response detected by a sensor assembly.
  • the depicted curve 1710 depicts a conceptualized scenario intended to be more reflective of real world conditions.
  • a sensor assembly is operated at various frequencies to detect a tag with an operating frequency fi and that is present from the sensor assembly at a distance Di.
  • the power response differential observed for the tag (as measured between f 0 and fi, or fi and f 2 ) may still be sufficiently large to easily detect the tag.
  • power response fluctuations are seen due to factors other than the presence of the tag (e.g., electromagnetic properties of materials in a borehole or surrounding geological formations).
  • the depicted curves 1720 and 1730 show similar possible example power response curves for an RFID tag at increasingly further distances D 2 and D 3 from the sensor assembly (i.e., Di ⁇ D 2 ⁇ D 3 ).
  • the differentials between observed power responses at f 0 and fi (as well as fi and f 2 ) become increasingly smaller.
  • the RFID tag may therefore become increasingly difficult to detect without an increased probability of generating false positives.
  • the tag operating at frequency fi may be practically undetectable.
  • Fig. 18A a conceptualized diagram is shown of one embodiment of a "sawtooth" scanning pattern usable to detect RFID tags.
  • a sensor assembly is configured to raise and lower an RFID scanning frequency 1805 over time in the manner shown.
  • the y- axis in this chart represents a scanning frequency of a sensor assembly, while the x-axis represents time.
  • a particular frequency fi is a target frequency at which one or more RFID tags are known to operate.
  • Times ti, t 2 , t 3 , and U are indicated to show times at which scanning frequency 1805 is the same as (intersects) frequency fi.
  • Fig. 18B a related conceptual diagram is shown of an embodiment of an idealized power response curve as might be seen in response to the frequency scanning pattern of Fig. 18A.
  • power response curve 1810 indicates a power response as detected by a sensor assembly.
  • power response curve 1810 is uniformly level except at times near to ti, t 2 , t 3 , and t 4 , which correspond to tag detection events.
  • ti time
  • t 2 time
  • t 3 time
  • t 4 time
  • a detected power level in the sensor assembly begins to change, indicating that the tag's operating frequency is being approached (and that a current is being induced in the tag).
  • Fig. 19 a conceptualized group of charts are shown of power response by a sensor assembly as a function of time at different frequencies.
  • power response curves 1905, 1910, and 1915 each respectively correspond to frequencies f3 ⁇ 4 fi. f2-
  • These power response curves also include various distortions representative of those that can be caused by environmental or other distortion-inducing factors.
  • tag detection may be more difficult.
  • fi is the operating frequency of an RFI D tag
  • f 0 is a nearby lower frequency
  • f 2 is a nearby higher frequency.
  • power response curves 1905 and 1915 may be used by way of comparison with power response curve 1910 in order to better detect an RFID tag, while also controlling the potential for false positive detection.
  • power response curve 1910 there are several rises and dips in the power response curve that could potentially indicate the presence of an RFID tag. For example, power response changes are observable near both ti and t 2 for power response curve 1910. To better determine whether the power response changes near ti and t 2 actually indicate the presence of a tag, however, power response curve 1910 may be compared to power response curve 1905. This comparison may help ascertain whether the observed power response changes in curve 1910 are simply the result of environmental conditions rather than the actual presence of a tag.
  • Fig. 20 a chart is shown with two superimposed power response curves from Fig. 19. Power response curve 1905
  • power response curve 1905 shows a relatively large differential 2005 between the two power responses, indicating the likely presence of an RFID tag.
  • power response curve 1910 changes significantly around time t 2 (e.g., between times ti. 5 and t 2 )
  • power response curve 1905 also shows a large change.
  • a comparison of curve 1910 to 1905 at time t 2 shows a relatively small differential 2010 between the two curves.
  • the fact that there is another similar large power response change in curve 1905 (for a different, lower frequency) indicates that the distortion in the power response for curve 1910 may not actually be due to the presence of a tag. Instead, this change may be due to an environmental factor that has similarly affected other frequencies.
  • the changes in power response curve 1910 might seemingly indicate that two tags are present, but a comparison with power response curve 1905 reveals that only one tag may be present. Similar comparisons between power response curves 1910 and 1915 may likewise be used to help determine whether a change in power response for curve 1910 is occurring primarily only at frequency fi (indicating probable tag presence), or at potentially numerous frequencies (indicating that an environmental factor, rather than an RFID tag, may be causing a power distortion).
  • a power response at a first frequency may be observed within a first period of time (e.g., 300 ms).
  • a detected result might then be stored in a sample/hold circuit for later use.
  • a power response for a second frequency might then be similarly observed for a same period of time (e.g., 300 ms), and then compared to the earlier stored results for the first scan at the first frequency.
  • detecting RFID tags does not require scanning more than one frequency at a given time (although this may be possible in some scenarios).
  • Fig 21A depicts a block diagram of one example embodiment of an RFID detection circuit 2100 and an RFID tag circuit 2130.
  • RFID detection circuit 2100 is configured to interrogate and detect the RFID tag circuit 2130 through use of a single antenna 2110.
  • RFI D detection circuit 2100 includes a signal generator 2105, inductor 2110, resistor 2115, and ground connection 2120, linked by electrical pathways.
  • RFID tag circuit 2130 (which may be a portion of an RFID tag) includes an inductor 2135 and a capacitor 2140.
  • signal generator 2105 includes an alternating current (AC) power source that drives current through inductor 2110.
  • AC alternating current
  • Current in RFID detection circuit 2100 flows through inductor 2110 and resistor 2115 toward ground connection 2120, and creates a magnetic field 2125.
  • Magnetic field 2125 will induce a current in inductor 2135 and power RFID circuit 2130, and the current in inductor 2135 generates a magnetic field that is reflected back to RFID detection circuit 2100.
  • the voltage of the reflected signal may be measured across resistor 2115 in order to determine a presence of an RFID tag circuit 2130.
  • a signal reflected by the RFID tag circuit 2130 (or borehole walls, fluids, etc.) and received at the RFID detection circuit 2100 can be monitored by taking voltage measurements across the resistor 2115 to determine a frequency response of the signal.
  • the frequency response can have a known value when no RFI D tag circuit 2130 is present, for example if the signal was reflected by another body downhole.
  • FIG. 21B the figure depicts an alternative example of an RFI D detection circuit 2145 configured to interrogate an RFI D tag circuit 2130 by transmitting signals through a transmitter 2150 having a first antenna 2110 with an associated magnetic field 2125 when transmitting, and receiving signals through a receiver 2160 having a second antenna 2168.
  • transmitter 2150 includes a signal generator 2105, inductor 2110, resistor 2115, and ground connection 2120, linked by electrical pathways.
  • Transmitter 2150 further includes a pair of matching element assemblies 2152 and 2154, located between the signal generator 2105 and inductor 2110, and between the inductor 2110 and resistor 2115, respectively.
  • Matching element assemblies 2152 and 2154 will each be formed of a combination of two or more circuit elements selected from the group of a capacitor, a resistor and an inductor, with the selected elements cooperatively arranged to balance impedance on opposite sides of antenna 2110.
  • both matching element assemblies 2152, 2154 will be of essentially identical configuration.
  • Receiver 2160 includes two matching element assemblies 2162 and 2164 on opposite sides of inductor 2168, which is arranged to receive signals through a magnetic field 2130.
  • one matching element assembly 2162 extends to ground 2158 while the other matching element assembly 2164 is coupled to a power detector 2166.
  • Matching element assemblies are formed of selected circuit elements as described above relative to matching element assemblies 2152 and 2154; and matching element assemblies will again often be of essentially identical configuration to one another.
  • RFID detection circuit 2200 includes a signal generator 2205; a first resonant circuit, in this example comprising a first inductor 2210 and a first capacitor 2215, coupled in series to a resistor 2220 extending to ground connection 2225.
  • RFID detection circuit also includes first and second impedance matching assemblies in the form of a first sub-circuit 2230, and a second su b-circuit 2240.
  • Each sub- circuit 2230, 2240 forms a second resonant circuit, in this example, with first sub-circuit 2230 comprising a second capacitor 2231 and a second inductor 2232 coupled in parallel to one another to ground; and with second sub-circuit 2240 including a third capacitor 2241 and a third inductor 2242 coupled in parallel to one another to ground.
  • RFID detection circuit 2200 may be used to interrogate RFID tag circuit 2130.
  • signal generator 2205 includes an AC power source that drives current through inductor 2210, creating a magnetic field to induce a current in RFID tag circuit 2130.
  • a voltage measured across resistor 2220 of certain characteristics will indicate the presence of an RFID tag.
  • Component values for RFI D detection circuit 2200 may be chosen to provide better levels of tag detection than those provided by RFID detection circuit 2100.
  • component values may be chosen with respect to a center frequency (e.g., a target frequency at which an RFID tag operates), as well as a center bandwidth (e.g., a frequency range around which RFI D detection may be centered).
  • a center frequency e.g., a target frequency at which an RFID tag operates
  • a center bandwidth e.g., a frequency range around which RFI D detection may be centered.
  • a characteristic impedance of the RFID detection circuit e.g., with respect to resistor 2220
  • further component values based on these techniques known to one skilled in the art (e.g., using algebraic rules).
  • Another technique involves selecting a characteristic inductance of the RFID detection circuit (e.g., with respect to inductor 2210), and then selecting further component values appropriately.
  • characteristics of other components in circuit 2200 may be chosen based on characteristics of inductor 2210 (e.g., coil dimensions, properties, etc.).
  • choosing to first select a characteristic inductance of the RFID detection circuit before choosing other component values may provide for a better detection response (e.g., allowing tags to be detected at a greater distance range) by causing a greater observable power response (e.g., voltage response across resistor 2220).
  • component values are chosen primarily with respect to the inductance value L of inductor 2210.
  • inductance and capacitance values for the matching circuits can be determined by first determining a desired circuit bandwidth (BW), and then defining the angular frequency ft' to be equal to 2 ⁇ few where few is the center frequency at the bandwidth BW.
  • BW circuit bandwidth
  • R'
  • R' can be therefore be calculated based on the known intrinsic inductance and desired resonant frequency and BW of circuit 2200.
  • values for other inductors and capacitors of circuit 2200 are selected using impedance matching methods. For example, given f BW and BW (which further gives a desired Q of f
  • impedance is calcu lated for each filter and BW this dictates values for capacitors 2231 and 2241 and inductors 2232 and 2242 when calculated according to methods known by those skilled in the art (e.g., using the American Radio Relay LeagueTM (ARRL) handbook.
  • ARRL American Radio Relay LeagueTM
  • RFID detection circuit 2200 may be suitably coupled to other circuits or include additional components in various embodiments in order to perform operations as described herein and below (e.g., with respect to method 2300).
  • RFID detection circuit 2200 may include or be coupled to one or more of any of a voltage monitoring circuit, a frequency stepping control circuit, an analog subtraction circuit, a digital comparator circuit, an analog scaling circuit, an analog scaling circuit, an analog
  • sample/hold circuit an analog-to-digital sampling circuit, a bandpass filter, or other circuitry.
  • FIG. 23 the figure depicts an example embodiment of a method 2300 relating to detection of RFID tags.
  • Various steps performed in method 2300 may be performed by a sensor assembly and/or portions thereof (such as RFID detector circuit 2200) in some embodiments.
  • Method 2300 may include additional operations in some instances, and some portions of method 2300 may be omitted and/or performed in a different order than the one shown as consistent with this disclosure.
  • step 2305 RFID tags are scanned for at a plurality of frequencies.
  • This step may be performed by a sensor assembly that scans in a portion of an annulus surrounding an exterior of a casing string of a borehole, for example (as discussed above, a current passing through inductor 2210 may cause an electromagnetic signal of a first frequency, second frequency, etc. to be emitted into a portion of the borehole).
  • a frequency stepping control circuit e.g., coupled to RFID detector circuit 2200
  • Frequency stepping may be performed in a variety of different manners, such as the sawtooth pattern shown in Fig. 18A. Different frequency scanning intervals may be used in various
  • a frequency stepping control circuit may include components synchronizing timing with signal generator 2105 in various embodiments.
  • step 2305 includes scanning at a target frequency at which an RFID tag operates and another frequency that is slower or faster than the target frequency.
  • step 2305 includes scanning at least three frequencies: one frequency that is slower than a target frequency, the target frequency, and at least one frequency that is faster than the target frequency (e.g., scanning on both sides of a target frequency).
  • a series (two or more) of successively faster frequencies may be scanned, going low to high over time.
  • a scan result of a relatively lower frequency scan (scanned at an earlier time) may be su btracted from (or otherwise compared to) a scan result of a relatively higher frequency scan (scanned at a later time).
  • the stepwise scans will be performed across a range of frequencies extending both above and below a target frequency.
  • such scans can be performed starting at a frequency lower than a target frequency and extending to a final frequency higher than the target frequency, or alternatively, can proceed in the opposite direction. Combinations of these techniques may be used in conjunction with sawtooth frequency scanning patterns as seen in Fig. 18A, for example.
  • step 2310 corresponding results are received for each of the plurality of frequencies scanned in step 2305.
  • the received corresponding result for each of the plurality of frequencies scanned includes an analog value indicative of a reflected power level in a portion of the annulus.
  • the reflected power level may be affected by the presence of a tag, environmental factors, or structural formations beyond the borehole.
  • the received corresponding result for a scan of a particular frequency is an analog voltage value (e.g., as measured across a sensing resistor such as a resistor (as shown, for example, at 2220 in Fig. 22).
  • received results for a scan may include an analog current measurement in RFI D detector circuit 2200, though in some situations, voltage may be easier to measure.
  • a scan result (e.g., measured voltage level) for a particular frequency may be determined by averaging different results received over time. For example, two or more measurements for a scan at a single frequency may be taken, and then averaged together before comparing the average to a result of a scan at a different frequency. Averaging may be performed by analog techniques in some embodiments, and may reduce the noise effect of transient environmental factors in some instances.
  • a plurality of the corresponding scanning results from step 2310 are compared to one another by a desired method. For example, a first voltage value resulting from a scan at a first frequency may differ from a second voltage value resulting from a scan at a second frequency, and such difference (however determined) indicates a difference in power response in a portion of an annulus of the borehole, which may indicate the presence of a RFID tag.
  • step 2315 includes using an analog subtraction circuit to subtract a voltage level measured for a scan of one frequency from a voltage level measured for a scan of another frequency.
  • a voltage differential may be determined.
  • the voltage differential may indicate a relative difference in power response at different frequencies from a scanned region of interest, for example.
  • Such a voltage differential may then be used to determine the presence or absence of a tag, as discussed below.
  • Such comparison, and/or other forms of comparison may be performed, if desired, in the digital domain.
  • step 2315 includes multiple comparisons of scan results. For example, a first voltage differential between a scan of relatively lower frequency and a scan of a target frequency may be determined. A second voltage differential between a scan of the target frequency and a relatively higher frequency may also be determined. Note that the phrase "comparing a plurality of results to one another," as used herein, does not require that every single of those results be compared to every single other one of those results.
  • Step 2315 may also include use of an analog sample/hold circuit to store results of previous measurements for purposes of comparison, in some embodiments. For example, a first result from a scan at a first frequency may be stored in the analog sample/hold circuit and later retrieved to compare that result with a second result from a scan at the same or a second frequency.
  • an analog sample/hold circuit stores a voltage measurement indicative of a reflected power level from a portion of a borehole. The sample/hold circuit can then provide the stored result to an analog subtraction circuit for purposes of comparison with another voltage measurement. Sampling/hold circuits may be used for other types of measurements as well. Use of a sample/hold circuit may therefore provide greater flexibility in various embodiments by allowing a single coil sensor to sequentially detect results for scans at different frequencies.
  • step 2320 a determination is made as to whether one or more RFID tags are present based on one or more comparisons between scan results made in step 2315.
  • step 2320 includes determining whether a difference (e.g., voltage differential), or some other comparison between a plurality of scan results from different scans exceeds a threshold or other reference value.
  • Threshold values may generally be used for detecting RFID tags in order to distinguish from random noise or other electromagnetic fluctuations. Use of threshold values may therefore reduce false positives (detection of a tag that is not actually present) in some scenarios.
  • a particular threshold value may be determined empirically by way of experimentation (e.g., performing tests in a laboratory environment or in a borehole environment), or may be determined in other manners (for example, by scan result averaging, as discussed above.
  • step 2320 By comparing a voltage differential to a threshold value, in one embodiment, step 2320 produces an indication as to whether one or more RFID tags are present. Referring briefly to Fig. 20, for example, a voltage differential corresponding to power response differential 2005 would exceed the threshold value, indicating a tag. A voltage differential corresponding to power response differential 2010, however, would fail to exceed the threshold value, indicating that no tag is present. Note that results from step 2320 (and other steps of method 2300 generally) may be stored by a sensor assembly. The sensor assembly may also transmit such results to other systems, such as a surface computer system used by a borehole operator.
  • determining whether one or more RFID tags are present includes determining if a threshold value is exceeded on both sides of a target frequency (slower and faster) at which an RFID tag operates. For example, a voltage differential between a scan at a relatively lower frequency and a scan at a target frequency may be sufficiently large to exceed a threshold value. The voltage differential between the scan at the target frequency and a scan at a relatively high frequency, however, might fail to exceed the threshold value. In this scenario, by checking that two or more differentials both exceed a threshold (e.g., checking differentials on either side of a target frequency), greater tag detection reliability may be achieved in some cases, and false positives may be avoided.
  • a threshold value is exceeded on both sides of a target frequency (slower and faster) at which an RFID tag operates. For example, a voltage differential between a scan at a relatively lower frequency and a scan at a target frequency may be sufficiently large to exceed a threshold value. The voltage differential between the scan at the target frequency and a scan at a relatively high frequency, however
  • step 2320 may also include converting an analog value to a digital value prior to comparison with a threshold value.
  • an output of an analog subtraction circuit e.g., a voltage differential
  • a sampling circuit may be converted by a sampling circuit to a digital value for ease of comparison. Once converted, the corresponding digital value may then be directly compared to a digital threshold value in order to determine if the threshold value has been exceeded.
  • Additional operations may also be performed prior to comparing a result (e.g., analog subtraction result) to a threshold value.
  • a result e.g., analog subtraction result
  • a bandpass filter may filter frequencies for a voltage signal measured by an analog monitoring circuit (e.g., frequencies that are lower than a first threshold and higher than a second threshold).
  • an analog monitoring circuit e.g., frequencies that are lower than a first threshold and higher than a second threshold.
  • a pumping system could introduce low frequency noise that would be desirable to filter out before a voltage measurement is taken (or after, in some embodiments).
  • 15 Hz is used as the high pass frequency of the bandpass filter
  • 300 Hz is used as the low pass frequency of the bandpass filter (to eliminate or reduce other
  • a bandpass filter is applied to each of the plurality of results. Bandpass filtering may improve detection performance in some instances.
  • the detected power levels as a function of a plurality of scan frequencies may be used as a spectrum to define a reference level to assist in identifying power levels indicative of the presence of an RFID tag.
  • one or more of the measured power levels may be compared to, or otherwise evaluated relative to, one or more other of the measured power levels or to a separately established reference value (or pattern) in order to determine a response indicative of a tag.
  • reference value might be, for example, a reference pattern (for example, possibly a sine function) established by previously acquired spectra.
  • Such comparison or other evaluation can be performed either in the analog or digital domain (for example, through either digital or analog multiplication of two or more power levels).
  • Analog scaling operations may also be performed prior to comparing an analog subtraction result (e.g., voltage differential) with a threshold value.
  • an analog scaling circuit may scale up (or scale down) an analog subtraction result, as may be desired prior to digitization for comparison with a threshold value.
  • analog amplification operations may also be performed by an analog amplification circuit as desired to provide an analog voltage value to an analog-to-digital sampling circuit.
  • signal receiving step 2310 may be performed through alternative processes, such as largely in the digital domain.
  • One example is through use of a lock-in amplifier system.
  • received signals would be digitized at a rate much faster than the sweep time.
  • a sweep for a single tag frequency might be performed at a rate of approximately 17 ksweeps per second, while a sweep for three tag frequencies might be performed at a rate of approximately 5 ksweeps per second.
  • the sweeps would be digitized at a much higher frequency, for example in the range of 30 ksps to 2 Msps, though even higher digitization rates (for example, on the order of 100 Msps), would be desirable.
  • the comparing step 2315 is then performed by comparing the digitized points forming the digitized signal to prior signals. For example, for each frequency point of the digitized signal, an adaptive background correction can be performed at that frequency relative to past sweeps to remove the unchanging, or at least relatively slowly changing, portion of the response curve. Such background correction may be performed using one or more techniques, such as, for example: linear averaging, exponential decay averaging, median filtering, and histogram analysis.
  • the resulting background corrected signal is then convolved against a matched filter, or multiple filters in systems scanning multiple frequencies (such as Gaussian or first derivative Gaussian filters), for each of the tag frequency bands examined.
  • the convolved response is then sent to the detection section, which would filter it to yield a desired signal configuration (e.g., for example, a linear signal, a squared signal or absolute value signals).
  • the determining step 2320 is then performed by comparing that resulting signal to one or more reference values, such as thresholds, and evaluating the comparison by a resolution mechanism.
  • the resolution mechanism may be of different configurations, but in many examples will resolve the detection decision based on the signal meeting or exceeding a threshold for "n" of "m” observations.
  • FIG. 24 the figure depicts an example embodiment of another method 2400 relating to detection of RFID tags.
  • Various steps performed in method 2400 may be performed by a sensor assembly and/or portions thereof (such as RFI D detector circuit 2200).
  • method 2400 may include additional operations, and some portions of method 2400 may be omitted and/or performed in a different order than the one shown, as consistent with this disclosure.
  • Method 2400 may include any features, operations, or structures as described above relative to method 2300, in some embodiments, and vice versa.
  • step 2405 RFID tags are scanned for at first, second, and third frequencies.
  • the first frequency is lower than a target frequency at which an RFID tag operates
  • the second frequency is the target frequency
  • the third frequency is higher than the target frequency.
  • first, second, and third results are received that correspond to the scanning operations performed in step 2405.
  • the received results may be analog voltage levels detected across resistor 2220, in one example.
  • step 2415 the first result is compared with the second result.
  • this comparison includes calculating a fourth (analog) result by subtracting the first result from the second result using an analog subtraction circuit.
  • the fourth result will thus be indicative of a voltage differential between a scan of a relatively lower frequency and a scan of a target frequency.
  • step 2420 the second result is compared with the third result.
  • this comparison includes calculating a fifth (analog) result by subtracting the second result from the third result using an analog subtraction circuit.
  • the fifth result will likewise be indicative of a voltage differential between a scan of the target frequency and a scan of a relatively higher frequency. Accordingly, the fourth and fifth results may represent voltage differentials on respectively opposite sides of a target frequency, in some instances.
  • determining if RFID tags are present includes determining whether two voltage differentials (e.g., the fourth and fifth results) both exceed a threshold value. Checking that voltage differentials on both sides of a target frequency exceed a threshold, for example, may reduce false positives for RFID detection.
  • sensor assembly 2500 may be part of a communication assembly (e.g., as discussed relative to Figs. 14 and 15), and may include any or all of the structures or features described above relative to various embodiments of sensor assemblies in this disclosure. Circuits and structures within sensor assembly 2500 may be suitably connected (e.g., via electrical pathways or control structures) as would occur to one of skill in the art. Other circuits or components not shown may be present in some embodiments, while in other em bodiments, one or more circuits or components may be omitted.
  • sensor assembly 2500 includes an
  • RFID detection circuit 2505 an analog monitoring circuit 2510, an analog subtraction circuit 2515, an analog sample/hold circuit 2520, and a digital comparator circuit 2525 that includes an analog-to-digital converter 2530 and a digital comparator unit 2535.
  • RFID detection circuit 2505 may be generally in accordance with any of the detection circuits described herein, such as in reference to any of Figures 21A-B and 22. RFID detection circuit 2505 will configured to operate while sensor assembly 2500 is coupled to an exterior of a casing string in a borehole, and to scan for RFID tags as discussed above. As noted above, such scanning will often be done at a plurality of frequencies.
  • Analog monitoring circuit 2510 is configured to measure a voltage across a resistor (e.g., resistor 2220) in RFID detection circuit 2505. Measurements taken by analog monitoring circuit 2510 may therefore include voltage measurements that indicate levels of power reflected at different frequencies from within the borehole annulus. Analog subtraction circuit 2515 is configured to subtract different voltage measurements taken by analog monitoring circuit 2510 and to provide corresponding analog results indicating voltage differentials (e.g., between scans at two frequencies).
  • Digital comparator circuit 2525 is configured to use analog-to- digital converter 2530 to convert an analog value to a digital value. Note that analog-to-digital converter 2530 may be part of a sampling circuit in various embodiments. Values may be provided for digitization to analog-to-digital converter 2530 by analog su btraction circuit 2515, in one embodiment.
  • Digital comparator unit 2535 is also configured to receive a digital value (e.g., from analog-to-digital converter 2530) and to compare the received value to another digital value, such as a threshold value. Thus, digital comparator unit 2535 may assist in determining whether one or more RFID tags are present (in the case that a voltage differential between two frequencies exceeds a threshold value, for example).
  • a digital computation unit 2540 is provided to perform additional computations in the digital domain.
  • digital computation unit 2540 may be constructed to evaluate received signals relative to entries in a lookup table, as could be used in phase sensitive detection. Other computations useful in either detecting the received signals, or evaluation of the received signals are also contemplated.
  • Analog sample/hold circuit 2520 is configured to store analog measurements (such as voltage levels), which may be used later. For example, voltage levels from one or more previous frequency scans may be stored in analog sample/hold circuit 2520 for purposes of later comparison with voltage levels from other frequency scans.
  • sensor assembly 2500, or one or more of the structures therein may be suitably combined with other embodiments described above relative to Figs. 17-24 for purposes of RFID detection.
  • RFID detection circuit 2500 also includes an analog mathematics unit 2550 to simplify operations to be performed in the digital domain.
  • analog mathematics unit 2550 can include an analog multiplier that could result in fewer, or less complex, operations needing to be performed by the digital comparator circuit 2525.
  • Techniques and structures discussed above may be suitable for detecting RFID tags within a borehole of an oil well or other hydrocarbon recovery well. Techniques and structures used herein may also allow for more accurate RFI D detection in a borehole environment, and may save power used in performing RFI D detection (e.g., by virtue of analog operations instead of digital operations) in various instances.

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Abstract

Des ensembles capteurs sont déployés dans un trou de forage d'un puits, tel qu'un puits de pétrole ou autre puits d'extraction d'hydrocarbures. Les ensembles capteurs peuvent être couplés à une colonne de tubage (par ex. l'extérieur du tubage) et peuvent détecter des étiquettes RFID ou d'autres propriétés de matériau (par ex. des fluides) dans un espace annulaire entourant (5) la colonne de tubage. Pendant la cimentation ou d'autres opérations, des étiquettes RFID peut être utilisées pour suivre des fluides. Des circuits de détection RFID peuvent être utilisés pour explorer par balayage à différentes fréquences et des résultats correspondants peuvent être comparés par divers moyens et procédés pour déterminer la présence d'étiquettes RFID.
PCT/US2015/035090 2014-06-26 2015-06-10 Procédés et systèmes de détection d'étiquettes rfid dans un environnement de trou de forage WO2015199986A1 (fr)

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