US20150300159A1

US20150300159A1 - Apparatus and Method for Evaluating Cement Integrity in a Wellbore Using Acoustic Telemetry

Info

Publication number: US20150300159A1
Application number: US14/435,987
Authority: US
Inventors: David A. Stiles; Stuart R. Keller; Timothy I. Morrow; Max Deffenbaugh; Mark M. Disko
Original assignee: Individual
Current assignee: Individual
Priority date: 2012-12-19
Filing date: 2013-12-18
Publication date: 2015-10-22
Also published as: US20150285065A1; WO2014100269A1; US9816373B2; WO2014100266A1

Abstract

An electro-acoustic system for downhole telemetry employs a series of communications nodes spaced along a string of casing within a wellbore. In one embodiment the nodes are placed within the cement sheath surrounding the joints of casing and allow wireless communication between transceivers residing within the communications nodes and a receiver at the surface. The transceivers provide node-to-node communication up a wellbore at high data transmission rates for data indicative of cement sheath integrity. A method of evaluating a cement sheath in a wellbore uses a plurality of data transmission nodes situated along the casing string which send signals to a receiver at the surface. The signals are then analyzed.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 61/739,681, filed Dec. 19, 2012, the disclosure of which is hereby incorporated by reference.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD OF THE INVENTION

The present invention relates to the field of well drilling and completions. More specifically, the invention relates to the transmission of data along a tubular body within a wellbore. The present invention further relates to the evaluation of cement integrity behind a casing string using acoustic signals.

GENERAL DISCUSSION OF TECHNOLOGY

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation penetrated by the wellbore.
A cementing operation is typically conducted in order to displace drilling fluid and fill part or all of the hollow-cylindrical annular area between the casing and the borehole wall with cement. The combination of cement and casing strengthens the wellbore and facilitates the zonal fluid isolation of certain sections of a hydrocarbon-producing formation (or “pay zones”) behind the casing.
A first string of casing is placed from the surface and down to a first drilled depth. This casing is known as a surface casing. In the case of offshore operations, this casing may be referred to as a conductor pipe. Typically, one of the main functions of the initial string(s) of casing is to isolate and protect the shallower, useable water bearing aquifers from contamination by any other wellbore fluids. Accordingly, these casing strings are almost always cemented entirely back to surface.
One or more intermediate strings of casing is also run into the wellbore. These casing strings will have progressively smaller outer diameters into the wellbore. In most current wellbore completion jobs, especially those involving so called unconventional formations where high-pressure hydraulic operations are conducted downhole, these casing strings may be entirely cemented. In some instances, an intermediate casing string may be a liner, that is, a string of casing that is not tied back to the surface.
The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. In some instances, the final string of casing is also a liner. The final string of casing, referred to as a production casing, is also typically cemented into place.
Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner. Each tubing string extends from the surface to a designated depth proximate a production interval, or “pay zone.” Each tubing string may be attached to a packer. The packer serves to seal off the annular space between the production tubing string(s) and the surrounding casing.
It is important that the cement sheath surrounding the casing strings have a high degree of circumferential and axial integrity around the casing annulus against fluid channeling or flowing through the cement along the wellbore. The cement must also bond with the casing surface and borehole wall to affect a hydraulic seal against fluid migration along the wellbore. This means that the cement is fully placed into the annular region to prevent fluid communication between fluids at the level of subsurface completion and aquifers residing just below the surface. Such fluids may include fracturing fluids, aqueous acid, and formation fluids.
Heretofore, the integrity of a cement sheath has been determined through the use of a so-called cement bond long. A cement bond log (or CBL), uses an acoustic signal that is transmitted by a logging tool at the end of a wireline. The logging tool includes a transmitter, and then a receiver that “listens” for sound waves generated by the transmitter through the surrounding case strings. The logging tool includes a signal processor that takes a continuous measurement of the amplitude of sound pulses from the transmitter to the receiver.
The theory behind the CBL is that the amplitude of a sonic signal as it travels through a well cemented pipe is only a fraction of the amplitude through uncemented pipe. Acoustic signals in free steel casing generally provide a large amplitude because the acoustic energy remains in the steel. However, for casing that is surrounded by and well bonded with cement, the amplitude is small because the acoustic energy is dispersed not only in the steel but also into the coupled cement and formation. Bond logs may also measure acoustic impedance of the cement or other material in the annulus behind the casing by resonant frequency decay.
Cement bond logs are typically conducted using an acoustic logging tool that is pulled through the wellbore using a wireline. This is done after a casing string has been cemented in placed within the wellbore. However, it is desirable to be able to evaluate the integrity of the cement sheath behind the casing string immediately after the cementing operation has been conducted and without need for a wireline or separate logging tool. Further, it is desirable to determine the progress of cement placement during the cementing operation using a series of communications nodes placed along the casing string as part of the well completion. Still further, a need exists for an acoustic telemetry system that enables the operator to receive signals at high data transmission rates, with such signals being indicative of cement sheath integrity, both at the time of cementing and later in the life of the well.

SUMMARY OF THE INVENTION

An electro-acoustic system for downhole telemetry is provided herein. The system employs a series of communications nodes spaced along a wellbore. Each node transmits a signal that represents a packet of information. The packet of information includes both a node identifier and an acoustic wave. The signals are relayed up the wellbore from node-to-node in order to provide a wireless signal to a receiver at the surface.
The system first includes a string of casing. The casing string is disposed in the wellbore. In actuality, the wellbore may have more than one casing string, including a string of surface casing, one or more intermediate casing strings, and a production casing. In any aspect, the wellbore is completed for the purpose of conducting hydrocarbon recovery operations. A cement sheath resides within an annular region formed between the casing string and a surrounding subsurface rock matrix. The cement sheath extends substantially along the exterior of the casing string.
The system further has a topside communications node. The topside communications node may be placed along the casing string proximate to surface. The surface may be an earth surface. Alternatively, in a subsea context, the surface may be an offshore platform or vessel at or below a water level. In another embodiment, the topside communications node is connected to the wellhead.
The system further includes a plurality of subsurface communications nodes. The subsurface communications nodes are attached to an outer wall of the casing string in spaced-apart relation. In one aspect, the communications nodes are spaced at between about 20 and 40 foot (6.1 to 12.2 meter) intervals. Preferably, each joint of pipe making up the casing string receives one node. The communications nodes are configured to transmit acoustic waves from node-to-node, up to the topside communications node.
Each of the subsurface communications nodes has a sealed housing. In addition, each node relies upon an independent power source. The power source may be, for example, batteries or a fuel cell. The power source resides within the housing.
In addition, each of the subsurface communications nodes has an electro-acoustic transducer. In one aspect, the communications nodes transmit data as mechanical waves at a rate exceeding about 50 bps. In one aspect, the electro-acoustic transducer is associated with a transceiver designed to receive acoustic waves at a first frequency, and then transmit or relay the acoustic waves at a second different frequency. Multiple frequency shift keying (MFSK) may be used as a modulation scheme enabling the transmission of information.
The system also includes a receiver. The receiver is positioned at the surface and is configured to receive signals from the topside communications node. The signals originate with the various subsurface communications nodes. In one aspect, the receiver is in electrical communication with the topside communications node by means of an electrical wire or through a wireless data transmission such as Wi-Fi or Blue Tooth. The receiver is configured to process the signals to identify any sections of casing that are not adequately cemented.
A method of detecting the integrity of a cement sheath along a wellbore is also provided herein. The method uses a plurality of data transmission nodes situated along a casing string to accomplish a wireless transmission of data along the wellbore. The data represents signals that indicate the presence of a cement sheath both adjacent to and between the respective communications nodes.
The method first includes running joints of pipe into the wellbore. The joints of pipe are connected together at threaded couplings. The joints of pipe are fabricated from a steel material and have a resonant frequency.
The method also provides for attaching a series of communications nodes to the joints of pipe according to a pre-designated spacing. In one aspect, each joint of pipe receives at least one communications node. Preferably, each of the communications nodes is attached to a joint of pipe by one or more clamps. In this instance, the step of attaching the communications nodes to the joints of pipe comprises clamping the communications nodes to an outer surface of the joints of pipe.
The series of communications nodes includes a topside communications node. This is the uppermost communications node along the wellbore. More specifically, the topside communications node is attached to the tubular body proximate the surface. Alternatively, the topside communications node is connected to the well head or to a tubular body immediately downstream from the wellhead. The topside communications node transmits signals from an uppermost subsurface communications node to the surface.
The communications nodes also include a series of subsurface communications nodes residing below the topside communications nodes. The subsurface communications nodes reside in spaced-apart relation along the casing string. The subsurface communications nodes are configured to transmit acoustic waves up to the topside communications node. Each subsurface communications node includes an electro-acoustic transducer and associated transceiver that receives an acoustic signal from a previous communications node, and then transmits or relays that acoustic signal to a next communications node, in node-to-node arrangement. In one aspect, the communications nodes transmit data as mechanical waves at a rate exceeding about 50 bps.
In one embodiment, one or more of the subsurface communications nodes includes a temperature sensor. The communications nodes are then designed to generate a signal that corresponds to temperature readings sensed by the respective temperature sensors. The electro-acoustic transceivers in the subsurface communications nodes then transmit acoustic signals up the wellbore representative of the temperature readings, node-to-node.
In another embodiment, selected subsurface communications nodes include a strain gauge. Alternatively or in addition, selected subsurface communications nodes include passive acoustic sensors, or microphones. Signals from the strain gauges or the microphones are sent to the surface via the subsurface communications nodes.
The method next includes providing a receiver. The receiver is placed at the surface. The receiver has a processor that processes signals received from the topside communications node, such as through the use of firmware and/or software. The receiver preferably receives electrical or optical signals via a so-called “Class I, Division I” conduit, meaning a conduit (as defined by NFPA 497 and API 500) for operation in an electrically classified area. Alternatively, data may be transferred from the topside communications node to the receiver via an electromagnetic (RF) wireless connection. The processor processes the signals to identify which signals correlate to which subsurface communications node.
The method also includes analyzing the signals to evaluate the integrity of the cement sheath in proximity to each of the communications nodes. Analyzing the signals will allow the operator to infer the quality of the cement sheath at and in between the nodes. If it is determined that cement has not been properly placed around the casing string adjacent one of the communications nodes, then appropriate decisions on subsequent drilling, completing, operating or abandonment the well can be undertaken.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a side, cross-sectional view of an illustrative wellbore. The wellbore is being formed using a derrick, a drill string and a bottom hole assembly. A series of communications nodes is placed along the drill string as part of a telemetry system.

FIG. 2 is a cross-sectional view of a wellbore having been completed. The illustrative wellbore has been completed as a cased hole completion. A series of communications nodes is placed along the casing string as part of a telemetry system.

FIG. 3 is a perspective view of an illustrative tubular pipe joint as may be positioned in a wellbore. A communications node of the present invention, in one embodiment, is shown exploded away from the pipe joint.

FIG. 4A is a perspective view of a communications node as may be used in the wireless data transmission system of the present invention, in an alternate embodiment.

FIG. 4B is a cross-sectional view of the communications node of FIG. 4A. The view is taken along the longitudinal axis of the node. Here, a sensor is provided within the communications node.

FIG. 4C is another cross-sectional view of the communications node of FIG. 4A. The view is again taken along the longitudinal axis of the node. Here, a sensor resides along the wellbore external to the communications node.

FIGS. 5A and 5B are perspective views of a shoe as may be used on opposing ends of the communications node of FIG. 4A, in one embodiment. In FIG. 5A, the leading edge, or front, of the shoe is seen. In FIG. 5B, the back of the shoe is seen.

FIG. 6 is a perspective view of a communications node system as may be used in the methods of the present invention, in one embodiment. The communications node system utilizes a pair of clamps for connecting a subsurface communications node onto a tubular body.

FIG. 7 is a flowchart demonstrating steps of a method for detecting the integrity of a cement sheath along a wellbore in accordance with the present inventions, in one embodiment.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Examples of hydrocarbons include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.
As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions (about 20° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, gas condensates, coal bed methane, shale oil, pyrolysis oil, and other hydrocarbons that are in a gaseous or liquid state.
As used herein, the term “subsurface” refers to the region below the earth's surface.
As used herein, the term “sensor” includes any electrical sensing device or gauge. The sensor may be capable of monitoring or detecting pressure, temperature, fluid flow, vibration, or resistivity or other formation data.
As used herein, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.
The terms “zone” or “zone of interest” refer to a portion of a formation containing hydrocarbons. The term “hydrocarbon-bearing formation” may alternatively be used. Zones of interest may also include formations containing brines or useable water which are to be isolated.
As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”
The terms “tubular member” or “tubular body” refer to any pipe, such as a joint or string of casing, a joint or string of a liner pipe, a joint or string of drill pipe, a production tubing joint or string, an injection tubing joint or string, or any other tubular tool associated with use in a wellbore.

DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.
FIG. 1 is a side, cross-sectional view of an illustrative well site 100. The well site 100 includes a derrick 120 at an earth surface 101. The well site 100 also includes a wellbore 150 extending from the earth surface 101 and down into an earth subsurface 155. The wellbore 150 is being formed using the derrick 120, a drill string 160 below the derrick 120, and a bottom hole assembly 170 at a lower end of the drill string 160.
Referring first to the derrick 120, the derrick 120 includes a frame structure 121 that extends up from the earth surface 101. The derrick 120 supports drilling equipment including a traveling block 122, a crown block 123 and a swivel 124. A so-called kelly 125 is attached to the swivel 124. The kelly 125 has a longitudinally extending bore (not shown) in fluid communication with a kelly hose 126. The kelly hose 126, also known as a mud hose, is a flexible, steel-reinforced, high-pressure hose that delivers drilling fluid through the bore of the kelly 125 and down into the drill string 160.
The kelly 125 includes a drive section 127. The drive section 127 is non-circular in cross-section and conforms to an opening 128 longitudinally extending through a kelly drive bushing 129. The kelly drive bushing 129 is part of a rotary table. The rotary table is a mechanically driven device that provides clockwise (as viewed from above) rotational force to the kelly 125 and connected drill string 160 to facilitate the process of drilling a borehole 105. Both linear and rotational movement may thus be imparted from the kelly 125 to the drill string 160.
A platform 102 is provided for the derrick 120. The platform 102 extends above the earth surface 101. The platform 102 generally supports rig hands along with various components of drilling equipment such as a pumps, motors, gauges, a dope bucket, tongs, pipe lifting equipment and control equipment. The platform 102 also supports the rotary table.
It is understood that the platform 102 shown in FIG. 1 is somewhat schematic. It is also understood that the platform 102 is merely illustrative and that many designs for drilling rigs and platforms, both for onshore and for offshore operations, exist. These include, for example, top drive drilling systems. The claims provided herein are not limited by the configuration and features of the drilling rig unless expressly stated in the claims.
Placed below the platform 102 and the kelly drive section 127 but above the earth surface 101 is a blow-out preventer, or BOP 130. The BOP 130 is a large, specialized valve or set of valves used to control pressures during the drilling of oil and gas wells. Specifically, blowout preventers control the fluctuating pressures emanating from subterranean formations during a drilling process. The BOP 130 may include upper 132 and lower 134 rams used to isolate flow on the back side of the drill string 160. Blowout preventers 130 also prevent the pipe joints making up the drill string 160 and the drilling fluid from being blown out of the wellbore 150 in the event of a sudden pressure kick.
As shown in FIG. 1, the wellbore 150 is being formed down into the subsurface formation 155. In addition, the wellbore 150 is being shown as a deviated wellbore. Of course, this is merely illustrative as the wellbore 150 may be a vertical well or even a horizontal well, as shown later in FIG. 2.
In drilling the wellbore 150, a first string of casing 110 is placed down from the surface 101. This is known as surface casing 110 or, in some instances (particularly offshore), conductor pipe. The surface casing 110 is secured within the formation 155 by a cement sheath 112. The cement sheath 112 resides within an annular region 115 between the surface casing 110 and the surrounding formation 155.
During the process of drilling and completing the wellbore 150, additional strings of casing (not shown) will be provided. These may include intermediate casing strings and a final production casing string. For an intermediate case string or the final production casing, a liner may be employed, that is, a string of casing that is not tied back to the surface 101.
As noted, the wellbore 150 is formed by using a bottom hole assembly 170. The bottom-hole assembly 170 allows the operator to control or “steer” the direction or orientation of the wellbore 150 as it is formed. In this instance, the bottom hole assembly 170 is known as a rotary steerable drilling system, or RSS.
The bottom hole assembly 170 will include a drill bit 172. The drill bit 172 may be turned by rotating the drill string 160 from the platform 102. Alternatively, the drill bit 172 may be turned by using so-called mud motors 174. The mud motors 174 are mechanically coupled to and turn the nearby drill bit 172. The mud motors 174 are used with stabilizers or bent subs 176 to impart an angular deviation to the drill bit 172. This, in turn, deviates the well from its previous path in the desired azimuth and inclination.
There are several advantages to directional drilling. These primarily include the ability to complete a wellbore along a substantially horizontal axis of a subsurface formation, thereby exposing a greater formation face. These also include the ability to penetrate into subsurface formations that are not located directly below the wellhead. This is particularly beneficial where an oil reservoir is located under an urban area or under a large body of water. Another benefit of directional drilling is the ability to group multiple wellheads on a single platform, such as for offshore drilling. Finally, directional drilling enables multiple laterals and/or sidetracks to be drilled from a single wellbore in order to maximize reservoir exposure and recovery of hydrocarbons.
As the wellbore 150 is being formed, the operator may wish to evaluate the integrity of the cement sheath 112 placed around the surface casing 110 (or other casing string). To do this, the industry has relied upon so-called cement bond logs. As discussed above, a cement bond log (or CBL), uses an acoustic signal that is transmitted by a logging tool at the end of a wireline. The logging tool includes a transmitter, and one or more receivers that “listen” for sound waves generated by the transmitter through the surrounding casing string. The logging tool includes a signal processor that takes a continuous measurement of the amplitude of sound pulses from the transmitter to the receiver. Alternately, the attenuation of the sonic signal may be measured.
In some instances, a bond log will measure acoustic impedance of the material in the annulus directly behind the casing. This may be done through resonant frequency decay. Such logs include, for example, the USIT log of Schlumberger (of Sugar Land, Tex.) and the CAST-V log of Halliburton (of Houston, Tex.).
It is desirable to implement a downhole telemetry system that enables the operator to evaluate cement sheath integrity without need of running a CBL line. This enables the operator to check cement sheath integrity as soon as the cement has set in the annular region 115 or as soon as the wellbore 150 is completed. To do this, the well site 100 includes a plurality of communications nodes 180, 182. The communications nodes 180, 182 are placed along the outer surface of the surface casing 110 according to a pre-designated spacing. The communications nodes then send acoustic signals up the wellbore 150 in node-to-node arrangement.
Acoustic telemetry systems are known in the industry. U.S. Pat. No. 5,924,499 entitled “Acoustic Data Link and Formation Property Sensor for Downhole MWD System” teaches the use of acoustic signals for “short hopping” a component along a drill string. Signals are transmitted from the drill bit or from a near-bit sub and across the mud motors. This may be done by sending separate acoustic signals simultaneously—one that is sent through the drill string, a second that is sent through the drilling mud, and optionally, a third that is sent through the formation. These signals are then processed to extract readable signals.
U.S. Pat. No. 6,912,177, entitled “Transmission of Data in Boreholes,” addresses the use of an acoustic transmitter that is as part of a downhole tool. Here, the transmitter is provided adjacent a downhole obstruction such as a shut-in valve along a drill stem so that an electrical signal may be sent across the drill stem. U.S. Pat. No. 6,899,178, entitled “Method and System for Wireless Communications for Downhole Applications,” describes the use of a “wireless tool transceiver” that utilizes acoustic signaling. Here, an acoustic transceiver is in a dedicated tubular body that is integral with a gauge and/or sensor. This is described as part of a well completion.
U.S. Pat. No. 4,314,365, entitled “Acoustic Transmitter and Method to Produce Essentially Longitudinal, Acoustic Waves, teaches a “portable, electrohydraulic, acoustic transmitter” that attaches to an outer surface of a drill string. The transmitter is used to send acoustic signals down a drill string to a downhole receiver. When actuated, the downhole receiver activates a subsurface “instrument package” which performs a desired “downhole function.”
None of these patents disclose an acoustic telemetry system that enables an operator to receive signals at the surface that are indicative of cement sheath integrity behind a casing string. In contrast, the well site 100 of FIG. 1 presents a telemetry system that utilizes a series of novel communications nodes 180, 182 placed along the casing 110. These nodes 180, 182 allow for the high speed transmission of wireless signals based on the in situ generation of acoustic waves. The waves represent wave forms that may be processed and analyzed at the surface.
The nodes first include a topside communications node 182. The topside communications node 182 is placed closest to the surface 101. The topside communications node 182 is configured to receive acoustic signals and convert them to electrical or optical signals. The topside communications node 182 may be above grade or below grade.
In addition, the nodes include a plurality of subsurface communications nodes 180. The subsurface communications nodes 180 are configured to receive and then relay acoustic signals along the length of the wellbore 150 up to the topside communications node 182.
In FIG. 1, the nodes 180, 182 are shown schematically. However, FIG. 3 offers an enlarged perspective view of an illustrative pipe joint 300, along with a communications node 350. The illustrative communications node 350 is shown exploded away from the pipe joint 300.
In FIG. 3, the pipe joint 300 is intended to represent a joint of casing. However, the pipe joint 300 may be any other tubular body such as a joint of tubing, drill pipe, pipeline, or other jointed tubular conduit assembly. The illustrated pipe joint 300 has an elongated wall 310 defining an internal bore 315. The bore 315 transmits drilling fluids such as an oil based mud, or OBM, during a drilling operation. The bore 315 also receives a string of tubing (such as production tubing or injection tubing, not shown), once a wellbore is completed.
The illustrated pipe joint 300 has a box end 322 having internal threads. In addition, the pipe joint 300 has a pin end 324 having external threads, such as via an integrated box end or with an internally threaded collar connector. The threads may be of any design. Tubing joints and casing joints have a slightly different general end appearance than the illustrated drill pipe joint, but these are also tubular bodies that may be equipped similar to the illustrated drill pipe joint 300.
As noted, an illustrative communications node 350 is shown exploded away from the pipe joint 300. The communications node 350 is designed to attach to the wall 410 of the pipe joint 300 at a selected location. In one aspect, each pipe joint 300 will have a communications node 350 between the box end 322 and the pin end 324. In one arrangement, the communications node 350 is placed immediately adjacent the box end 322 or, alternatively, immediately adjacent the pin end 324 of every joint of pipe. In another arrangement, the communications node 350 is placed at a selected location along every second or every third pipe joint 300 in a drill string. In still another arrangement, at least some pipe joints 300 receive two communications nodes 350.
The communications node 350 shown in FIG. 3 is designed to be pre-welded onto the wall 310 of the pipe joint 300. Alternatively, the communications node 350 may be glued using an adhesive such as epoxy. However, it is preferred that the communications node 350 be configured to be selectively attachable to/detachable from a pipe joint 300 by mechanical means at a well site. This may be done, for example, through the use of clamps. Such a clamping system is shown at 600 in FIG. 6, described more fully below. In any instance, the communications node 350 is an independent wireless communications device that is designed to be attached to an external surface of a well pipe.
There are benefits to the use of an externally-placed communications node that uses acoustic waves. For example, such a node will not decrease the effective inner diameter which would interfere with passing subsequent assemblies or tubulars through the internal bore 315 of the pipe joint 300. Further, installation and mechanical attachment can be readily assessed and adjusted.
In FIG. 3, the communications node 350 includes an elongated body 351. The body 351 supports one or more batteries, shown schematically at 352. The body 351 also supports an electro-acoustic transducer, shown schematically at 354. The electro-acoustic transducer 354 is associated with a transceiver that receives acoustic signals at a first frequency, converts the received signals into a digital signal, converts the digital signal back into an acoustic signal, and transmits the acoustic signal at a second different frequency to a next communications node.
The communications node 350 is intended to represent the communications nodes 180 of FIG. 1, in one embodiment. The electro-acoustic transducer 354 in each node 180 allows signals to be sent from node-to-node, up the wellbore 150, as acoustic waves. The acoustic waves may be at a frequency of, for example, between about 100 kHz and 125 kHz. A last subsurface communications node 180 transmits the signals to the topside node 182. Beneficially, the subsurface communications nodes 180 do not require a wire or cable to transmit data to the surface. Preferably, communication is routed around nodes which are not functioning properly.
The well site 100 of FIG. 1 also shows a receiver 190. The receiver 190 comprises a processor 192 that receives signals sent from the topside communications node 182. The signals may be received through a wire (not shown) such as a co-axial cable, a fiber optic cable, a USB cable, or other electrical or optical communications wire. Alternatively, the receiver 190 may receive the final signals from the topside node 182 wirelessly through a modem, a transceiver or other wireless communications link such as Bluetooth or Wi-Fi. The receiver 190 preferably receives electrical signals via a so-called Class I, Division I conduit, that is, a housing for wiring that is considered acceptably safe in an explosive environment. In some applications, radio, infrared or microwave signals may be utilized.
The processor 192 may include discrete logic, any of various integrated circuit logic types, or a microprocessor. In any event, the processor 192 may be incorporated into a computer having a screen. The computer may have a separate keyboard 194, as is typical for a desk-top computer, or an integral keyboard as is typical for a laptop or a personal digital assistant. In one aspect, the processor 192 is part of a multi-purpose “smart phone” having specific “apps” and wireless connectivity.
FIG. 1 demonstrates the use of a wireless data telemetry system during a drilling operation. However, the wireless downhole telemetry system may also be employed after a well is completed. This enables the operator to confirm the viability of a cement sheath after, for example, formation fracturing operations have taken place.
FIG. 2 is a cross-sectional view of an illustrative well site 200. The well site 200 includes a wellbore 250 that penetrates into a subsurface formation 255. The wellbore 250 has been completed as a cased-hole completion for producing hydrocarbon fluids. The well site 200 also includes a well head 260. The well head 260 is positioned at an earth surface 201 to control and direct the flow of formation fluids from the subsurface formation 255 to the surface 201.
Referring first to the well head 260, the well head 260 may be any arrangement of pipes or valves that receive reservoir fluids at the top of the well. In the arrangement of FIG. 2, the well head 260 represents a so-called Christmas tree. A Christmas tree is typically used when the subsurface formation 255 has enough in situ pressure to drive production fluids from the formation 255, up the wellbore 250, and to the surface 201. The illustrative well head 260 includes a top valve 262 and a bottom valve 264.
It is understood that rather than using a Christmas tree, the well head 260 may alternatively include a motor (or prime mover) at the surface 201 that drives a pump. The pump, in turn, reciprocates a set of sucker rods and a connected positive displacement pump (not shown) downhole. The pump may be, for example, a rocking beam unit or a hydraulic piston pumping unit. Alternatively still, the well head 260 may be configured to support a string of production tubing having a downhole electric submersible pump, a gas lift valve, or other means of artificial lift (not shown). The present inventions are not limited by the configuration of operating equipment at the surface unless expressly noted in the claims.
Referring next to the wellbore 250, the wellbore 250 has been completed with a series of pipe strings referred to as casing. First, a string of surface casing 210 has been cemented into the formation. Cement is shown in an annular bore 215 of the wellbore 250 around the casing 210. The cement is in the form of an annular sheath 212. The surface casing 110 has an upper end in sealed connection with the lower valve 264.
Next, at least one intermediate string of casing 220 is cemented into the wellbore 250. The intermediate string of casing 220 is in sealed fluid communication with the upper master valve 262. A cement sheath 212 is again shown in a bore 215 of the wellbore 250. The combination of the casing 210/220 and the cement sheath 212 in the bore 215 strengthens the wellbore 250 and facilitates the isolation of formations behind the casing 210/220.
It is understood that a wellbore 250 may, and typically will, include more than one string of intermediate casing. In some instances, an intermediate string of casing may be a liner.
Finally, a production string 230 is provided. The production string 230 is hung from the intermediate casing string 230 using a liner hanger 231. The production string 230 is a liner that is not tied back to the surface 101. In the arrangement of FIG. 2, a cement sheath 232 is provided around the liner 230.
The production liner 230 has a lower end 234 that extends to an end 254 of the wellbore 250. For this reason, the wellbore 250 is said to be completed as a cased-hole well. Those of ordinary skill in the art will understand that for production purposes, the liner 230 may be perforated after cementing to create fluid communication between a bore 235 of the liner 230 and the surrounding rock matrix making up the subsurface formation 255. In one aspect, the production string 230 is not a liner but is a casing string that extends back to the surface.
As an alternative, end 254 of the wellbore 250 may include joints of sand screen (not shown). The use of sand screens with gravel packs allows for greater fluid communication between the bore 235 of the liner 230 and the surrounding rock matrix while still providing support for the wellbore 250. In this instance, the wellbore 250 would include a slotted base pipe as part of the sand screen joints. Of course, the sand screen joints would not be cemented into place and would not include subsurface communications nodes.
The wellbore 250 optionally also includes a string of production tubing 240. The production tubing 240 extends from the well head 260 down to the subsurface formation 255. In the arrangement of FIG. 2, the production tubing 240 terminates proximate an upper end of the subsurface formation 255. A production packer 241 is provided at a lower end of the production tubing 240 to seal off an annular region 245 between the tubing 240 and the surrounding production liner 230. However, the production tubing 240 may extend closer to the end 234 of the liner 230.
In some completions a production tubing 240 is not employed. This may occur, for example, when a monobore is in place.
It is also noted that the bottom end 234 of the production string 230 is completed substantially horizontally within the subsurface formation 255. This is a common orientation for wells that are completed in so-called “tight” or “unconventional” formations. Horizontal completions not only dramatically increase exposure of the wellbore to the producing rock face, but also enables the operator to create fractures that are substantially transverse to the direction of the wellbore. Those of ordinary skill in the art may understand that a rock matrix will generally “part” in a direction that is perpendicular to the direction of least principal stress. For deeper wells, that direction is typically substantially vertical. However, the present inventions have equal utility in vertically completed wells or in multi-lateral deviated wells.
As with the well site 100 of FIG. 1, the well site 200 of FIG. 2 includes a telemetry system that utilizes a series of novel communications nodes. This again is for the purpose of evaluating the integrity of the cement sheath 212, 232. The communications nodes are placed along the outer diameter of the casing strings 210, 220, 230. These nodes allow for the high speed transmission of wireless signals based on the in situ generation of acoustic waves.
The nodes first include a topside communications node 282. The topside communications node 282 is placed closest to the surface 201. The topside node 282 is configured to receive acoustic signals.
In addition, the nodes include a plurality of subsurface communications nodes 280. Each of the subsurface communications nodes 280 is configured to receive and then relay acoustic signals along essentially the length of the wellbore 250. Preferably, the subsurface communications nodes 280 utilize two-way electro-acoustic transducers to receive and relay mechanical waves.
The subsurface communications nodes 280 transmit signals as acoustic waves. The acoustic waves are preferably at a frequency of between about 50 kHz and 500 kHz. The signals are delivered up to the topside communications node 282 so that signals indicative of cement integrity are sent from node-to-node. A last subsurface communications node 280 transmits the signals acoustically to the topside communications node 282. Communication may be between adjacent nodes or may skip nodes depending on node spacing or communication range. Preferably, communication is routed around nodes which are not functioning properly.
The well site 200 of FIG. 2 shows a receiver 270. The receiver 270 comprises a processor 272 that receives signals sent from the topside communications node 284. The processor 272 may include discrete logic, any of various integrated circuit logic types, or a microprocessor. The receiver 270 may include a screen and a keyboard 274 (either as a keypad or as part of a touch screen). The receiver 270 may also be an embedded controller with neither a screen nor a keyboard which communicates with a remote computer such as via wireless, cellular modem, or telephone lines.
The signals may be received by the processor 272 through a wire (not shown) such as a co-axial cable, a fiber optic cable, a USB cable, or other electrical or optical communications wire. Alternatively, the receiver 270 may receive the final signals from the topside node 282 wirelessly through a modem or transceiver. The receiver 270 preferably receives electrical signals via a so-called Class I, Div. 1 conduit, that is, a wiring system or circuitry that is considered acceptably safe in an explosive environment.
FIGS. 1 and 2 present illustrative wellbores 150, 250 that may receive a downhole telemetry system using acoustic transducers. In each of FIGS. 1 and 2, the top of the drawing page is intended to be toward the surface and the bottom of the drawing page toward the well bottom. While wells commonly are completed in substantially vertical orientation, it is understood that wells may also be inclined and even horizontally completed. When the descriptive terms “up” and “down” or “upper” and “lower” or similar terms are used in reference to a drawing, they are intended to indicate location on the drawing page, and not necessarily orientation in the ground, as the present inventions have utility no matter how the wellbore is orientated.
In each of FIGS. 1 and 2, the communications nodes 180, 280 are specially designed to withstand the same corrosion and environmental conditions (high temperature, high pressure) of a wellbore 150 or 250 As the casing, drill string, or production tubing. To do so, it is preferred that the communications nodes 180, 280 include steel housings for holding the electronics. In one aspect, the steel material is a corrosion resistant alloy.
FIG. 4A is a perspective view of a communications node 400 as may be used in the wireless data transmission systems of FIG. 1 or FIG. 2 (or other wellbore), in one embodiment. The communications node 400 is designed to provide data communication using a transceiver within a novel downhole housing assembly. FIG. 4B is a cross-sectional view of the communications node 400 of FIG. 4A. The view is taken along the longitudinal axis of the node 400. The communications node 400 will be discussed with reference to FIGS. 4A and 4B, together.
The communications node 400 first includes a fluid-sealed housing 410. The housing 410 is designed to be attached to an outer wall of a joint of wellbore pipe, such as the pipe joint 300 of FIG. 3. Where the wellbore pipe is a carbon steel pipe joint such as drill pipe, casing or liner, the housing 410 is preferably fabricated from carbon steel. This metallurgical match avoids galvanic corrosion at the coupling.
The housing 410 includes an outer wall 412. The wall 412 is dimensioned to protect internal electronics for the communications node 400 from wellbore fluids and pressure. In one aspect, the wall 412 is about 0.2 inches (0.51 cm) in thickness. The housing 410 optionally also has a protective outer layer 425. The protective outer layer 425 resides external to the wall 412 and provides an additional thin layer of protection for the electronics.
A bore 405 is formed within the wall 412. The bore 405 houses the electronics, shown in FIG. 4B as a battery 430, a power supply wire 435, a transceiver 440, and a circuit board 445. The circuit board 445 will preferably include a micro-processor or electronics module that processes acoustic signals. An electro-acoustic transducer 442 is provided to convert acoustical energy to electrical energy (or vice-versa) and is coupled with outer wall 412 on the side attached to the tubular body. The transducer 442 is in electrical communication with a sensor 432.
It is noted that in FIG. 4B, the sensor 432 resides within the housing 410 of the communications node 400. However, as noted, the sensor 432 may reside external to the communications node 400, such as above or below the node 400 along the wellbore. In FIG. 4C, a dashed line is provided showing an extended connection between the sensor 432 and the electro-acoustic transducer 442.
The transceiver 440 will receive an acoustic telemetry signal. In one preferred embodiment, the acoustic telemetry data transfer is accomplished using multiple frequency shift keying (MFSK). Any extraneous noise in the signal is moderated by using well-known conventional analog and/or digital signal processing methods. This noise removal and signal enhancement may involve conveying the acoustic signal through a signal conditioning circuit using, for example, a bandpass filter.
The transceiver will also produce acoustic telemetry signals. In one preferred embodiment, an electrical signal is delivered to an electromechanical transducer, such as through a driver circuit. In a preferred embodiment, the transducer is the same electro-acoustic transducer that originally received the MFSK data. The signal generated by the electro-acoustic transducer then passes through the housing 410 to the tubular body (such as production tubing 240), and propagates along the tubular body to other communication nodes. The re-transmitted signal represents the same sensor data originally transmitted by sensor communications node 284. In one aspect, the acoustic signal is generated and received by a magnetostrictive transducer comprising a coil wrapped around a core as the transceiver. In another aspect, the acoustic signal is generated and received by a piezoelectric ceramic transducer. In either case, the electrically encoded data are transformed into a sonic wave that is carried through the wall of the tubular body in the wellbore.
Each transceiver 440 is associated with a specific joint of pipe. That joint of pipe, in turn, has a known location or depth along the wellbore. The acoustic wave as originally transmitted from the transceiver 440 will represent a packet of information. The packet will include an identification code that tells a receiver (such as receiver 270 in FIG. 2) where the signal originated, that is, which communications node 400 it came from. In addition, the packet will include an amplitude value originally recorded by the communications node 400 for its associated joint of pipe.
When the signal reaches the receiver at the surface, the signal is processed. This involves identifying which communications node the signal originated from, and then determining the location of that communications node along the wellbore. This further involves comparing the original amplitude value with a baseline value. The baseline value represents an anticipated value for a joint of casing having a fluid residing within its bore and a continuous cement sheath along its outer surface.
If the measured amplitude value is at or below the baseline amplitude value, then the operator can assume that a cement sheath has been placed around the joint of pipe at issue. On the other hand, if the measured amplitude value is above the baseline amplitude value, then the operator should assume that a poor cement sheath has been placed around the joint of pipe at issue. In that instance, remedial steps may be taken. Where the wellbore is presently undergoing a cementing operation, such steps may include further injecting cement through a cement shoe and up the annular region in the hopes of filling the annular region. More likely, where the wellbore has been completed, such steps may include placing perforations in the casing at the subject joint of pipe, and then conducting a so-called “cement squeeze” in order to isolate the joint of pipe and fill the annular region at the depth of that joint of pipe. Alternatively, the operator may elect to forego perforating casing at that depth or along a certain zone of interest.
The communications node 400 optionally also includes one or more sensors 432. The sensors 432 may be, for example, pressure sensors, temperature sensors, or microphones. The sensor 432 sends signals to the transceiver 440 through a short electrical wire 435 or through the printed circuit board 435. Signals from the sensor 432 are converted into acoustic signals using an electro-acoustic transducer, that are then sent by the transceiver 440 as part of the packet of information.
Preferably, the sensor 432 is a temperature sensor. The packet of information will then include signals representative of temperature readings taken by the temperature sensor. When the signal reaches the receiver at the surface, the signal is compared with a baseline value. The baseline value represents an anticipated temperature for a joint of casing having a fresh column of cement residing there around. Those of ordinary skill in the art of well completions will understand that cement mix undergoes an exothermic reaction which causes an increase in temperature.
If the measured temperature value is at or above the baseline temperature value, then the operator can assume that a cement sheath has been placed around the joint of pipe at issue. On the other hand, if the measured temperature value is below the baseline temperature value, then the operator should assume that a poor cement sheath has been placed around the joint of pipe at issue. Appropriate remedial steps may then be considered.
Additional methods of processing temperature data may be used. For example, the receiver may collect temperature data from a designated number of communications nodes that are in proximity to the subject communications node. Temperature readings will then be averaged to determine a moving average temperature value for a section of casing. The measured temperature reading will then be compared to the moving average temperature value to determine cement integrity at the level of a particular joint of pipe.
Ideally, the operator will review a combination of amplitude data and temperature data along the wellbore to confirm cement sheath integrity. Strain data and passive acoustic data may also be used to evaluate the integrity of the cement sheath.
The communications node 400 also optionally includes a shoe 500. More specifically, the node 400 includes a pair of shoes 500 disposed at opposing ends of the wall 412. Each of the shoes 500 provides a beveled face that helps prevent the node 400 from hanging up on an external tubular body or the surrounding earth formation, as the case may be, during run-in or pull-out. The shoes 500 may have a protective outer layer 422 and an optional cushioning material 424 under the outer layer 422.
FIGS. 5A and 5B are perspective views of an illustrative shoe 500 as may be used on an end of the communications node 400 of FIG. 4A, in one embodiment. In FIG. 5A, the leading edge or front of the shoe 500 is seen, while in FIG. 4B the back of the shoe 500 is seen.
The shoe 500 first includes a body 510. The body 510 includes a flat under-surface 512 that butts up against opposing ends of the wall 412 of the communications node 400.
Extending from the under-surface 512 is a stem 520. The illustrative stem 520 is circular in profile. The stem 520 is dimensioned to be received within opposing recesses 414 of the wall 412 of the node 400.
Extending in an opposing direction from the body 510 is a beveled surface 530. As noted, the beveled surface 530 is designed to prevent the communications node 400 from hanging up on an object during run-in into a wellbore.
Behind the beveled surface 530 is a flat (or slightly arcuate) surface 535. The surface 535 is configured to extend along the drill string 160 (or other tubular body) when the communications node 400 is attached along the tubular body. In one aspect, the shoe 500 includes an optional shoulder 515. The shoulder 515 creates a clearance between the flat surface 535 and the tubular body opposite the stem 520.
In one arrangement, the communications nodes 400 with the shoes 500 are welded onto an outer surface of the tubular body, such as wall 310 of the pipe joint 300. More specifically, the body 410 of the respective communications nodes 400 are welded onto the wall of a joint of casing. In some cases, it may not be feasible or desirable to pre-weld the communications nodes 400 onto pipe joints before delivery to a well site. Further still, welding may degrade the tubular integrity or damage electronics in the housing 410. Therefore, it is desirable to utilize a clamping system that allows a drilling or service company to mechanically connect/disconnect the communications nodes 400 along a tubular body as the tubular body is being run into a wellbore.
FIG. 6 is a perspective view of a communications node system 600 as may be used for methods of the present invention, in one embodiment. The communications node system 600 utilizes a pair of clamps 610 for mechanically connecting a communications node 400 onto a tubular body 630 such as a joint of casing or liner.
The system 600 first includes at least one clamp 610. In the arrangement of FIG. 6, a pair of clamps 610 is used. Each clamp 610 abuts the shoulder 515 of a respective shoe 500. Further, each clamp 610 receives the base 535 of a shoe 500. In this arrangement, the base 535 of each shoe 500 is welded onto an outer surface of the clamp 610. In this way, the clamps 610 and the communications node 400 become an integral tool.
The illustrative clamps 610 of FIG. 6 include two arcuate sections 612, 614. The two sections 612, 614 pivot relative to one another by means of a hinge. Hinges are shown in phantom at 615. In this way, the clamps 610 may be selectively opened and closed.
Each clamp 610 also includes a fastening mechanism 620. The fastening mechanisms 620 may be any means used for mechanically securing a ring onto a tubular body, such as a hook or a threaded connector. In the arrangement of FIG. 6, the fastening mechanism is a threaded bolt 625. The bolt 625 is received through a pair of rings 622, 624. The first ring 622 resides at an end of the first section 612 of the clamp 610, while the second ring 624 resides at an end of the second section 614 of the clamp 610. The threaded bolt 625 may be tightened by using, for example, one or more washers (not shown) and threaded nuts 627.
In operation, a clamp 610 is placed onto the tubular body 630 by pivoting the first 612 and second 614 arcuate sections of the clamp 610 into an open position. The first 612 and second 614 sections are then closed around the tubular body 630, and the bolt 625 is run through the first 622 and second 624 receiving rings. The bolt 625 is then turned relative to the nut 627 in order to tighten the clamp 610 and connected communications node 400 onto the outer surface of the tubular body 630. Where two clamps 610 are used, this process is repeated.
The tubular body 630 may be, for example, a casing string such as the illustrative casing string 160 of FIG. 1. Alternatively, the tubular body 630 may be a string of production tubing such as the tubing 240 of FIG. 2. In any instance, the wall 412 of the communications node 400 is fabricated from a steel material having a resonant frequency compatible with the resonant frequency of the tubular body 630. Stated another way, the mechanical resonance of the wall 412 is at a frequency contained within the frequency band used for telemetry.
In one aspect, the communications node 400 is about 12 to 16 inches (0.30 to 0.41 meters) in length as it resides along the tubular body 630. Specifically, the housing 410 of the communications node may be 8 to 10 inches (0.20 to 0.25 meters) in length, and each opposing shoe 500 may be 2 to 5 inches (0.05 to 0.13 meters) in length. Further, the communications node 400 may be about 1 inch in width and inch in height. The base 410 of the communications node 400 may have a concave profile that generally matches the radius of the tubular body 630.
A method for transmitting date in a wellbore is also provided herein. The method preferably employs the communications node 400 and the communications node system 600 of FIG. 6.
FIG. 7 provides a flow chart for a method 700 of detecting the integrity of a cement sheath along a wellbore. The method 700 uses a plurality of data transmission nodes situated along a casing string to accomplish a wireless transmission of data along the wellbore. The data represents signals that indicate the presence of a cement sheath adjacent or in proximity to the respective communications nodes.
The method 700 first includes running a tubular body into the wellbore. This is shown at Box 710. The tubular body is formed by connecting a series of pipe joints end-to-end, with the pipe joints being connected by threaded couplings. The joints of pipe are fabricated from a steel material suitable for conducting an acoustic signal.
The method 700 also provides for attaching a series of communications node to the joints of pipe. This is provided at Box 720. The communications nodes are attached according to a pre-designated spacing. In one aspect, each joint of pipe receives a communications node. Preferably, each of the subsurface communications nodes is attached to a joint of pipe by one or more clamps. In this instance, the step 720 of attaching the communications nodes to the joints of pipe comprises clamping the communications nodes to an outer surface of the joints of pipe. Alternatively, an adhesive material or welding may be used for the attaching step 720.
The method 700 further includes placing a cement sheath around the tubular body. This is indicated at Box 730. The cement sheath is placed within an annular region formed between the casing joints and the surrounding subsurface rock matrix or previous strings of casing. The cement sheath is placed in the annular region using any known method of cementing casing into a wellbore. Typically, cement is injected down the casing string behind a bottom wiper plug and ahead of a top wiper plug, through a cement shoe, and back up the annular region. In the method 700, the cement sheath will ideally surround the externally placed communications nodes in the annular region along areas where a cement sheath is desired.
The communications nodes include a series of subsurface communications nodes. The nodes reside along the casing string. The communications nodes also include a topside communications node. This is the uppermost communications node along the wellbore. The topside communications node may be attached to the tubular body proximate the surface. More preferably, the topside communications node is connected to the well head. The topside communications node transmits signals from an uppermost subsurface communications node to a receiver at the surface.
The subsurface communications nodes are configured to transmit acoustic waves up to the topside communications node. Each subsurface communications node includes a transceiver that receives an acoustic signal from a previous communications node, and then transmits or relays that acoustic signal to a next communications node, in node-to-node arrangement.
The method 700 also includes providing a receiver. This is shown at Box 740. The receiver is placed at the surface. The receiver has a processor that processes signals received from the topside communications node, such as through the use of firmware and/or software. The receiver preferably receives electrical or optical signals via a so-called “Class I, Division I” conduit or through a radio signal. The processor processes signals to identify which signals correlate to which subsurface communications node. This may involve the use of a multiplexer or a pulse-receive switch.
The method next includes transmitting signals from each of the communications nodes up the wellbore and to the receiver. This is provided at Box 750. The signals are acoustic signals that have a resonance amplitude. These signals are sent up the wellbore, node-to-node. In one aspect, piezo wafers or other piezoelectric elements are used to receive and transmit acoustic signals. In another aspect, multiple stacks of piezoelectric crystals or other magnetostrictive devices are used. Signals are created by applying electrical signals of an appropriate frequency across one or more piezoelectric crystals, causing them to vibrate at a rate corresponding to the frequency of the desired acoustic signal.
In one aspect, the data transmitted between the nodes is represented by acoustic waves according to a multiple frequency shift keying (MFSK) modulation method. Although MFSK is well-suited for this application, its use as an example is not intended to be limiting. It is known that various alternative forms of digital data modulation are available, for example, frequency shift keying (FSK), multi-frequency signaling (MF), phase shift keying (PSK), pulse position modulation (PPM), and on-off keying (OOK). In one embodiment, every 4 bits of data are represented by selecting one out of sixteen possible tones for broadcast.
Acoustic telemetry along tubulars is characterized by multi-path or reverberation which persists for a period of milliseconds. As a result, a transmitted tone of a few milliseconds duration determines the dominant received frequency for a time period of additional milliseconds. Preferably, the communication nodes determine the transmitted frequency by receiving or “listening to” the acoustic waves for a time period corresponding to the reverberation time, which is typically much longer than the transmission time. The tone duration should be long enough that the frequency spectrum of the tone burst has negligible energy at the frequencies of neighboring tones, and the listening time must be long enough for the multipath to become substantially reduced in amplitude. In one embodiment, the tone duration is 2 ms, then the transmitter remains silent for 48 milliseconds before sending the next tone. The receiver, however, listens for 2+48=50 ms to determine each transmitted frequency, utilizing the long reverberation time to make the frequency determination more certain. Beneficially, the energy required to transmit data is reduced by transmitting for a short period of time and exploiting the multi-path to extend the listening time during which the transmitted frequency may be detected.
In one embodiment, an MFSK modulation is employed where each tone is selected from an alphabet of 16 tones, so that it represents 4 bits of information. With a listening time of 50 ms, for example, the data rate is 80 bits per second.
The tones are selected to be within a frequency band where the signal is detectable above ambient and electronic noise at least two nodes away from the transmitter node so that if one node fails, it can be bypassed by transmitting data directly between its nearest neighbors above and below. In one example the tones are evenly spaced in period within a frequency band from about 100 kHz to 125 kHz. In another example, the tones are evenly spaced in frequency within a frequency band from about 100 kHz to 125 kHz.
Preferably, the nodes employ a “frequency hopping” method where the last transmitted tone is not immediately re-used. This prevents extended reverberation from being mistaken for a second transmitted tone at the same frequency. For example, 17 tones are utilized for representing data in an MFSK modulation scheme; however, the last-used tone is excluded so that only 16 tones are actually available for selection at any time.
The communications nodes will transmit data as mechanical waves at a rate exceeding about 50 bps.
In one embodiment, each of the subsurface communications nodes also includes a temperature sensor. When the cement job is complete and the cement is setting, an exothermic reaction will take place. Changes in temperature will be indicative of the presence of cement between communications nodes. Later during production, changes in temperature may be indicative of the presence of formation fluids flowing behind the casing string. This may be indicative of flaws in the cement sheath. In any instance, the communications nodes are then designed to generate a signal that corresponds to temperature readings sensed by the respective temperature sensors along their corresponding joints of pipe.
Other sensors may also be employed in selected subsurface communications nodes. In one embodiment, strain gauges are used as sensors. Strain gauge data can be used to determine changes in stress on the casing as cement transitions from a fluid capable of transmitting hydrostatic pressure to a solid that is set. Strain gauge data can also be used to later identify volumetric changes within the set cement due to chemical reactions as cement hydration continues. Further, strain gauge data may be used to detect a pressure increase in the wellbore due to reservoir fluid influx through a flaw in the cement sheath. Data from the strain gauges may be included as part of the packet of information sent to the receiver at the surface for analysis.
In another embodiment, microphones are placed within selected subsurface communications nodes. Passive acoustic data gathered by microphones can be used to detect wellbore fluids, especially gas, that are flowing through a flaw or a mud channel in the cement sheath. As gas moves through a small gap it will produce ambient noises across a broad range of frequencies that can be detected by passive acoustic sensors in the nodes. Data from microphones may be included as part of the packet of information sent to the receiver at the surface for analysis.
As can be seen, various data can be gathered by sensors including temperature measurements, casing strain, noise caused by gas flow, and acoustic wave measurements themselves. All of this data may be considered together in evaluating a cement sheath along a wellbore.
The method 700 also includes analyzing the signals from the communications nodes. This is seen at Box 760. The signals are analyzed to evaluate the integrity of the cement sheath adjacent or in proximity to each of the subsurface communications nodes. Preferably, the signals are analyzed after the cement has set into a solid material having a compressive strength. Analyzing the signals may mean comparing the amplitude to a baseline or to other amplitude readings.
The receiver (or a processor associated with the receiver) will compare amplitude values of the various acoustic signals, or waveforms, against a baseline amplitude value to confirm that the amplitude is not too high. The baseline amplitude value may be a specific value input into the program representative of an expected amplitude value for a joint of casing having fluids within its bore and a cement sheath around its outer surface. Alternatively, the baseline amplitude value may be a moving average amplitude value determined by the program by averaging amplitude readings from a pre-designated number of communications nodes in proximity to the subject communications node. In one aspect, matrix equations are used to calculate a moving average, which serves as the baseline amplitude value. In any instance, an excessively high amplitude value suggests that cement has not been adequately placed around the pipe proximate to the communications node.
Where the signals correspond to temperature readings, the signals are compared to a baseline temperature value representing an expected temperature for fresh cement. Alternatively, the baseline temperature value may be a moving average temperature value determined by the program by averaging temperature readings from a pre-designated number of communications nodes in proximity to the subject communications node. In any instance, if the temperature reading from a specific communications node is too low, this will suggest that cement has not been adequately squeezed around the pipe joint at the level of that communications node.
Alternatively, analyzing the signals may mean measuring attenuation of a sonic signal. Propagation of acoustic waves between pairs of electro-acoustic transducers on neighboring subsurface communications nodes produces localized information (between two nodes) about the presence of cement and bonding. The level of acoustic wave attenuation increases from empty casing, to water-filled casing, to mud-filled casing, to casing with cement slurry (before setting), to a solidified/set cement. A plurality of pair-wise acoustic attenuation measurements provides a real-time log of the presence of cement. Optionally, this acoustic attenuation data is correlated with conventional cement bond-log data to analyze cement integrity.
A next step in the method 700 may be the identification of a subsurface communications node that is sending signals indicative of poor cement integrity within the cement sheath. This is provided at Box 770. If it is determined that cement has not been properly placed around the casing string adjacent one of the communications nodes, various operational decisions may be made. This is indicated at Box 780. In some embodiments (not illustrated), Boxes 770 and 780 may be replace with a single box stating “Make appropriate decision on subsequent drilling, completing, operating, or abandonment of the well.”
In the method 700, each of the communications nodes has an independent power source. The independent power source may be, for example, batteries or a fuel cell. Having a power source that resided within the housing of the communications nodes avoids the need for passing electrical connections through the housing, which could compromise fluid isolation. In addition, each of the intermediate communications nodes has a transducer and associated transceiver.
Preferably, the electro-acoustic transducer receives acoustic signals at a first frequency, and then sends acoustic signals at a second frequency that is different from the first frequency. Each transducer then “listens” for signals at the second frequency. Preferably, each transducer “listens” for the acoustic waves sent at the first frequency until after reverberation of the acoustic waves at the first frequency has substantially attenuated. Thus, a time is selected for both transmitting and for receiving. In one aspect, the listening time may be about twice the time at which the waves at the first frequency are transmitted or pulsed. To accomplish this, the transducer will operate with and under the control of a micro-processor located on a printed circuit board, along with memory. Beneficially, the energy required to transmit signals is reduced by transmitting for a shorter period of time.
It is noted that the method 700 and the claims herein do not require that communications nodes be placed along the entire wellbore, but only along a selected section or sections. Further, the method 700 and the claims herein do not require that the cement sheath be placed along the entire annular region unless the claims expressly so state.
A separate method for determining the integrity of a cement sheath is provided herein. The cement sheath resides within an annular region along a wellbore. Preferably, the annular region is between a string of casing and a surrounding subsurface rock matrix.
The method first includes receiving signals from a wellbore. Each signal defines a packet of information having (i) an identifier for a subsurface communications node originally transmitting the signal, and (ii) an acoustic amplitude value for the subsurface communications node originally transmitting the signal.
The method also includes correlating communications nodes to their respective locations in the wellbore. In addition, the method comprises analyzing the amplitude values to determine whether any of such amplitude values are indicative of a poor cement sheath along the wellbore.
In this method, the subsurface communications nodes may be constructed in accordance with communications node 350 of FIG. 3, communications node 400 of FIG. 4, or other arrangement for acoustic transmission of data. Preferably, each of the subsurface communications nodes is attached to an outer wall of the casing string according to a pre-designated spacing, and resides within the annular region. The subsurface communications nodes are configured to communicate by acoustic signals transmitted through the casing string.
In one aspect, analyzing the amplitude values comprises identifying amplitude values generated by each of the subsurface communications nodes, and comparing those amplitude values to a baseline amplitude value. The baseline amplitude value may be, for example, (i) a previously stored amplitude value indicative of an amplitude value of a joint of casing having a continuous annular cement sheath, or (ii) a moving average of amplitude readings taken from a pre-designated number of communications nodes in proximity to a subject communications node.
In one aspect, each of the subsurface communications nodes further comprises a temperature sensor. The communications nodes are then designed to generate a signal that corresponds to temperature readings taken by the temperature sensors. The electro-acoustic transceivers in the subsurface communications nodes transmit acoustic signals up the wellbore representative of the temperature readings, node-to-node. In this instance, the packet of information generated by each subsurface communications node further has (iii) an acoustic waveform indicative of a temperature reading. In addition, the method further comprises analyzing the temperature readings to determine the presence of cement adjacent to the sensor.
In one aspect, analyzing the temperature readings comprises identifying temperature values generated by each of the subsurface communications nodes, and comparing those temperature values to a baseline temperature value. The baseline temperature value may be (i) a previously stored temperature value indicative of a temperature value of a joint of casing having a freshly-cemented annular region, or (ii) a moving average of temperature readings taken from a pre-designated number of communications nodes in proximity to a subject communications node in the wellbore.
As noted above, other sensors may be placed in selected subsurface communications nodes. These may include strain gauges and microphones.
As can be seen, a novel downhole telemetry system is provided, as well as a novel method for the wireless transmission of information using a plurality of data transmission nodes for detecting cement sheath integrity. In some States, new hydraulic fracturing regulations are being implemented which may require the use of cement bond logs. However, the system disclosed herein may potentially be used by an operator in lieu a cement bond log.
While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.

Claims

What is claimed is:

1. An electro-acoustic telemetry system for evaluating a cement sheath in a wellbore, comprising:

a casing string disposed in a wellbore, with a cement sheath residing within an annular region formed between the casing string and a surrounding subsurface rock matrix along the casing string;

a topside communications node placed proximate a surface of the wellbore;

a plurality of subsurface communications nodes spaced along the wellbore and attached to an outer wall of the casing string, the subsurface communications nodes configured to transmit acoustic waves from node-to-node up the wellbore and to the topside communications node, and with at least some of the subsurface communications nodes being in contact with the cement sheath; and

a receiver at the surface configured to receive signals from the topside communications node;

wherein each of the subsurface communications nodes comprises:

a sealed housing;

an electro-acoustic transducer and associated transceiver also residing within the housing, with the transceiver being designed to relay signals from node-to-node up the wellbore, with each signal representing a packet of information that comprises an identifier for the subsurface communications node that originally transmitted the signal, and an acoustic waveform having an amplitude; and

an independent power source residing within the housing providing power to the transceiver.

2. The electro-acoustic telemetry system of claim 1, wherein the subsurface communications nodes are spaced apart such that each joint of pipe supports at least one subsurface communications node.

3. The electro-acoustic telemetry system of claim 1, wherein the subsurface communications nodes are spaced at about 20 to 40 foot (6.1 to 12.2 meter) intervals.

4. The electro-acoustic telemetry system of claim 1, wherein the subsurface communications nodes transmit data in acoustic form at a rate exceeding about 50 bps.

5. The electro-acoustic telemetry system of claim 1, wherein each of the electro-acoustic transceivers is designed to receive acoustic waves at a first frequency, and then transmit the acoustic waves at a second different frequency up the wellbore to a next subsurface communications node.

6. The electro-acoustic system of claim 1, further comprising:

one or more sensors placed along the wellbore, the sensors being any of strain gauges, temperature sensors, microphones, or combinations thereof; and

wherein the subsurface communications nodes are configured to receive and relay acoustic signals indicative of readings taken by the sensors up to the surface.

7. The electro-acoustic system of claim 6, wherein:

the one or more sensors reside within the housings of selected subsurface communications nodes; and

the electro-acoustic transducers within the selected subsurface communications nodes convert signals from the sensors into acoustic signals for the associated transceivers.

8. The electro-acoustic system of claim 6, wherein a frequency band for the acoustic wave transmission by the transceivers is about 25 KHz wide.

9. The electro-acoustic system of claim 6, wherein a frequency band for the acoustic wave transmission by the transceivers operates from about 100 kHz to 125 kHz.

10. The electro-acoustic telemetry system of claim 6, wherein the acoustic waves provide data that is modulated by (i) a multiple frequency shift keying method, (ii) a frequency shift keying method, (iii) a multi-frequency signaling method, (iv) a phase shift keying method, (v) a pulse position modulation method, or (vi) an on-off keying method.

11. The electro-acoustic telemetry system of claim 6, wherein each subsurface communications node listens for the acoustic waves generated at the first frequency for a longer time than the time for which the acoustic waves were generated at the second frequency by a previous subsurface communications node.

12. The electro-acoustic telemetry system of claim 1, wherein:

a well head is placed above the wellbore; and

the topside communications node is placed (i) on an outer surface of the well head, (ii) on an outer surface of a tubular body that is downstream of the wellhead, or (iii) on the outer surface of an uppermost joint of the casing string.

13. The electro-acoustic telemetry system of claim 12, wherein the signal from the topside communications node to the receiver is transmitted via a Class I, Division I conduit or a wireless transmission.

14. The electro-acoustic telemetry system of claim 1, wherein the subsurface communications nodes are attached to the outer wall of the casing string by (i) an adhesive material, (ii) welding, or (iii) one or more mechanical fasteners.

15. The electro-acoustic telemetry system of claim 1, wherein:

each of the subsurface communications nodes is attached to the casing string by one or more clamps; and

each of the one or more clamps comprises:

a first arcuate section;

a second arcuate section;

a hinge for pivotally connecting the first and second arcuate sections; and

a fastening mechanism for securing the first and second arcuate sections around an outer surface of the casing string.

16. The electro-acoustic telemetry system of claim 1, wherein:

the receiver comprises a processor; and

the processor is programmed to identify amplitude values generated by each subsurface communications node and compare those amplitude values to a baseline amplitude value.

17. The electro-acoustic telemetry system of claim 16, wherein the baseline amplitude value is (i) a previously stored amplitude value indicative of an amplitude value of a joint of casing having a continuous annular cement sheath, or (ii) a moving average of amplitude readings taken from a pre-designated number of communications nodes in proximity to a subject communications node.

18. The electro-acoustic telemetry system of claim 16, wherein:

selected communications nodes further comprise a temperature sensor, with those selected communications nodes being designed to generate a signal that corresponds to temperature readings taken by the respective temperature sensors; and

the transceivers transmit acoustic signals up the wellbore representative of the temperature readings, node-to-node, as part of the packets of information.

19. The electro-acoustic telemetry system of claim 18, wherein the processor is further programmed to identify temperature values generated by the selected subsurface communications node and compare those temperature values to a baseline temperature value.

20. The electro-acoustic telemetry system of claim 19, wherein the baseline temperature value is (i) a previously stored temperature value indicative of a temperature value of a joint of casing having a freshly-cemented annular region, or (ii) is a moving average of temperature readings taken from a pre-designated number of communications nodes in proximity to a subject communications node.

21. The electro-acoustic telemetry system of claim 16, wherein:

selected communications nodes further comprise a strain gauge, with those selected communications nodes being designed to generate a signal that corresponds to strain readings taken by the respective strain gauges; and

the electro-acoustic transceivers transmit acoustic signals up the wellbore representative of the strain readings, node-to-node, as part of the packets of information.

22. The electro-acoustic telemetry system of claim 16, wherein:

selected communications nodes further comprise a passive acoustic sensor, with those selected communications nodes being designed to generate a signal that corresponds to ambient noise readings taken by the respective temperature sensors; and

the electro-acoustic transceivers transmit acoustic signals up the wellbore representative of the noise readings, node-to-node, as part of the packets of information.

23. A method of detecting the integrity of a cement sheath along a wellbore, comprising:

running joints of casing into the wellbore, the joints of casing being connected by threaded couplings to form a casing string;

attaching a series of communications nodes to the joints of casing according to a pre-designated spacing, wherein adjacent communications nodes are configured to communicate by acoustic signals transmitted through the joints of casing, and wherein each of the communications nodes comprises:

a sealed housing;

an electro-acoustic transducer and associated transceiver residing within the housing configured to relay signals, with each signal representing a packet of information that comprises an identifier for the subsurface communications node originally transmitting the signal, and an acoustic waveform; and

an independent power source also residing within the housing for providing power to the transceiver;

placing a cement sheath within an annular region formed between the casing string and a surrounding subsurface matrix substantially along the wellbore;

sending signals from the communications nodes to a receiver at a surface via the series of communications nodes; and

analyzing the signals to evaluate the integrity of the cement sheath proximate each of the communications nodes.

24. The method of claim 23, wherein the surface is an earth surface, or a drilling or production platform over a water surface.

25. The method of claim 20, wherein the housing for each of the intermediate communications nodes is fabricated from a steel material, with the steel material of the housing having a resonance frequency within a width of the resonance frequency of the acoustic waveforms transmitted through the joints of casing.

26. The method of claim 23, wherein:

the series of communications nodes comprises a topside communications node residing proximate the surface, and a series of subsurface communications nodes along the wellbore below the topside communications nodes; and

the topside communications node transmits the signals from an uppermost subsurface communications node to the receiver.

27. The method of claim 26, wherein:

a well head is placed above the wellbore; and

the topside communications node is clamped (i) on an outer surface of the well head, or (ii) on the outer surface of an uppermost joint of the casing string.

28. The method of claim 27, wherein the topside communications node is in electrical communication with the receiver by means of a Class I, Division I conduit or a wireless transmission.

29. The method of claim 26, wherein each of the subsurface communications nodes is attached to an outer wall of a joint of casing by (i) an adhesive material, (ii) welding, or (iii) one or more mechanical fasteners.

30. The method of claim 26, wherein:

each of the subsurface communications nodes is attached to a joint of casing by one or more clamps; and

the step of attaching the communications nodes to the joints of casing comprises clamping the communications nodes to an outer surface of the joints of casing.

31. The method of claim 30, wherein:

the housing of each of the subsurface communications nodes comprises a first end and a second opposite end; and

each of the one or more clamps comprises a first clamp secured at the first end of the housing, and a second clamp secured at the second end of the housing.

32. The method of claim 23, wherein the subsurface communications nodes are spaced apart such that each joint of casing supports at least one subsurface communications node.

33. The method of claim 23, wherein the subsurface communications nodes are spaced at about 20 to 40 foot (6.1 to 12.2 meter) intervals.

34. The method of claim 23, wherein the subsurface communications nodes transmit data representing the waveforms at a rate exceeding about 50 bps.

35. The method of claim 23, wherein analyzing the signals to evaluate the integrity of the cement sheath comprises:

identifying amplitude values generated by each of the subsurface communications nodes; and

comparing those amplitude values to a baseline amplitude value.

36. The method of claim 35, wherein the baseline amplitude value is (i) a previously stored amplitude value indicative of an amplitude value of a joint of casing having a continuous annular cement sheath, or (ii) a moving average of amplitude readings taken from a pre-designated number of communications nodes in proximity to a subject communications node.

37. The method of claim 36, wherein:

each of the subsurface communications nodes further comprises a temperature sensor, and is designed to generate a signal that corresponds to temperature readings taken by the temperature sensor; and

the electro-acoustic transceivers in the subsurface communications nodes also transmit acoustic signals up the wellbore representative of the temperature readings, node-to-node.

38. The method of claim 35, wherein analyzing the signals to determine the integrity of the cement sheath further comprises:

identifying temperature values generated by each of the subsurface communications nodes; and

comparing those temperature values to a baseline temperature value.

39. The method of claim 38, wherein the baseline temperature value is (i) a previously stored temperature value indicative of a temperature value of a joint of casing having a freshly-cemented annular region, or (ii) a moving average of temperature readings taken from a pre-designated number of communications nodes in proximity to a subject communications node in the wellbore.

40. The method of claim 23, wherein:

41. The method of claim 23, wherein:

42. The method of claim 23, wherein a frequency band for the acoustic wave transmission by the transceivers is about 25 KHz wide.

43. The method of claim 23, wherein a frequency band for the acoustic wave transmission by the transceivers operates from about 100 kHz to 125 kHz.

44. The method of claim 23, wherein the acoustic waves provide data that is modulated by (i) a multiple frequency shift keying method, (ii) a frequency shift keying method, (iii) a multi-frequency signaling method, (iv) a phase shift keying method, (v) a pulse position modulation method, or (vi) an on-off keying method.

45. The method of claim 23, further comprising:

identifying a subsurface communications node sending signals indicative of poor cement integrity within the surrounding cement sheath.

46. The method of claim 23, further comprising:

perforating the joint of casing supporting that subsurface communications node; and

squeezing cement through the perforated joint of casing and into the annular region around the casing string.

47. The method of claim 23, wherein analyzing the signals to evaluate the integrity of the cement sheath further comprises comparing the attenuation of acoustic signals between pairs of subsurface communications nodes.

48. The method of claim 47, wherein analyzing the signals to evaluate the integrity of the cement sheath further comprises comparing the attenuation of acoustic signals with cement bond-log data.

49. A method of detecting the integrity of a cement sheath in an annular region along a wellbore, comprising:

receiving signals from a wellbore, each signal defining a packet of information having (i) an identifier for a subsurface communications node originally transmitting the signal, and (ii) an acoustic amplitude value for the subsurface communications node originally transmitting the signal;

correlating subsurface communications nodes to their respective locations in the wellbore; and

analyzing the amplitude values to determine whether any of such amplitude values are indicative of a poor cement sheath along the wellbore.

50. The method of claim 49, wherein:

the annular region resides between a casing string and a surrounding subsurface rock matrix; and

each of the subsurface communications nodes is attached to an outer wall of the casing string according to a pre-designated spacing, and resides within the annular region.

51. The method of claim 50, wherein:

the subsurface communications nodes are configured to communicate by acoustic signals transmitted through the casing string, and

each of the communications nodes comprises:

a sealed housing;

an electro-acoustic transducer and associated transceiver residing within the housing; and

an independent power source also residing within the housing for providing power to the transceiver.

52. The method of claim 51, wherein analyzing the amplitude values comprises:

comparing those amplitude values to a baseline amplitude value.

53. The method of claim 52, wherein the baseline amplitude value is (i) a previously stored amplitude value indicative of an amplitude value of a joint of casing having a continuous annular cement sheath, or (ii) a moving average of amplitude readings taken from a pre-designated number of communications nodes in proximity to a subject communications node.

54. The method of claim 52, wherein:

selected subsurface communications nodes further comprises a temperature sensor, and are designed to generate a signal that corresponds to temperature readings taken by the temperature sensor;

the electro-acoustic transceivers in the subsurface communications nodes transmit acoustic signals up the wellbore representative of the temperature readings, node-to-node;

the packet of information generated by each subsurface communications node further has (iii) an acoustic waveform indicative of a temperature reading; and

the method further comprises analyzing the temperature readings to determine whether any of such temperature readings are indicative of a poor cement sheath along the wellbore.

55. The method of claim 54, wherein analyzing the temperature readings comprises:

comparing those temperature values to a baseline temperature value.

56. The method of claim 55, wherein the baseline temperature value is (i) a previously stored temperature value indicative of a temperature value of a joint of casing having a freshly-cemented annular region, or (ii) a moving average of temperature readings taken from a pre-designated number of communications nodes in proximity to a subject communications node in the wellbore.

57. The method of claim 52, wherein:

at least some of the subsurface communications nodes further comprises a passive acoustic sensor, and generate a signal that corresponds to ambient noise readings taken by the passive acoustic sensors;

the electro-acoustic transceivers in the subsurface communications nodes transmit acoustic signals up the wellbore representative of the ambient noise readings, node-to-node;

the packet of information generated by the subsurface communications nodes further has (iii) an acoustic waveform indicative of the ambient noise readings; and

the method further comprises analyzing the ambient noise readings to determine whether any of such ambient noise readings are indicative of a poor cement sheath along the wellbore.

58. The method of claim 52, wherein:

at least some of the subsurface communications nodes further comprises a strain gauge, and generate a signal that corresponds to strain readings taken by the strain gauges;

the electro-acoustic transceivers in the subsurface communications nodes transmit acoustic signals up the wellbore representative of the strain readings, node-to-node;

the packet of information generated by the subsurface communications nodes further has (iii) an acoustic waveform indicative of the strain readings; and

the method further comprises analyzing the strain readings to determine whether any of such strain readings are indicative of a poor cement sheath along the wellbore.