Apparatus, system and method for collecting and distributing data

Abstract

The present disclosure relates to a data gathering platform (DGP) that comprises: a power system; a communication system; a sensory unit configured to detect conditions external to the sensory assembly; a controller circuit that is operatively coupled to the power system, the communication system and the sensory unit; and a housing that is configured to house the power system, the communication system, the sensory unit and the controller circuit, wherein the housing is further configured to be deployed within a well bore. Some embodiments of the present disclosure relate to a system that comprises one or more DGP within a well and, optionally, a data tool for regulating a mode of the DGP and for collecting data from the one or more DGP. Some embodiments of the present disclosure relate to a method of gathering and transmitting assessment data of one or more operational parameters within a well.

Description

APPARATUS, SYSTEM AND METHOD FOR COLLECTING AND DISTRIBUTING DATATECHNICAL FIELD

[0001] This disclosure generally relates to collecting and distributing data. In particular, this disclosure relates to apparatus, systems and methods of collecting and distributing data captured from a downhole environment.BACKGROUND

[0002] Once drilled, an oil and / or gas well, referred to herein as a well, may have multiple subsequent operational stages, including but not limited to: (i) a completion stage; (ii) a workover stage; (iii) a production stage; and (iv) a shutting-in stage. Generally, a well is divided into smaller portions, referred to as sections. Furthermore, more than one well can be drilled in a given location, with multiple wells having proximal surface wellheads in a location referred to as a well pad.

[0003] During the completion stage, any further materials that are required to reinforce the wellbore are added. Examples of such further required materials include, but are not limited to: lengths of metal conduits, referred to as casing or liner, and / or concrete. It is during the completion stage that the underground reservoir that holds the target oil and gas can be stimulated, typically via the well, in order to increase the flow of oil and gas fluids into the well. Non-exhaustive examples of stimulation operations include: cyclic steam stimulation, steam assisted gravity drainage, acid injection, flooding, deflagration stimulation and hydraulic fracturing. The purpose of the stimulation operations is to: increase the available flow paths between the wellbore and the reservoir, enhance the existing flow paths between the wellbore and the reservoir, decrease the viscosity of the target hydrocarbons, or both.

[0004] During the production stage the target oil and gas fluids are captured by the well and delivered to surface for delivery to further processing plants, such as a refinery.

[0005] During both of the completion and production stages, but particularly during a stimulation operation, fluid communication can be established between different parts of the reservoir surrounding the well. For example, there may be fluid communication established between different sections of the well, between different wells on a given well pad and between different well pads. This fluid communication can pose many operational issues, such as but not limited to: fluids delivered during a given completion operation may not end up in the intended portion of the reservoir and target oil and gas fluids may not be captured by the well or an undesirably high amount of the fluids delivered during a given completion operation may overstimulate a target zone of the well. These issues can result in delay, increased capital costs, decreased production and wasted energy inputs. Additionally, there may be a detrimental environmental impact of some portion of the fluids pumped down a well not ending up in the intended portion of the reservoir and of oil and gas fluids not being captured by the well.

[0006] It is known to deploy fiber optic cables and sensors down into the well to identify any unintended fluid communication within different portions of a reservoir or beyond. However, fiber optic cables are expensive to deploy, which can be a deterrent to many operators of oil and gas wells. This may present a barrier to operators reducing their environmental impact because there is no means by which unintended fluid communication can be detected, let alone addressed or remedied. Furthermore, fiber optic cables can be severed at any time during the stimulation stage, or even before the stimulation has started. As a further consideration, fiber optic cable and the associated sensors often lose the capability or have an impaired capability to record and / or transmit data below the target zone of the reservoir being stimulated because the fiber optic cable is can be damaged, cut or severed at or near the fluid exit point from the well pipe. This eliminates all intended benefits of the capital expenditure of deploying the fiber optic cable. Furthermore, the fiber optic cable and associated sensors are often coupled to the exterior of the casing or liner pipe. This can result in a micro-annulus forming between the outer surface of the pipe and the inner surface of the wellbore (whether open, lined or cased), which can perpetuate the problem of fluid communication being established between undesirable portions of thereservoir. Furthermore, known fiber optic coupled sensors are limited to sensing temperature or strain.

[0007] As such, it may be desirable to provide information about a downhole well environment, including information regarding a geologic formation adjacent a well, to operators of wells as to any unintended fluid communication that may be occurring proximal to a given well, wells or well pad. This information is desirable to have whether the well is a geothermal well, an oil and / or gas well, such as a conventional well, a stimulated oil and / or gas well, a steam assisted gravity drainage injection well or production well and various other types of wells.SUMMARY

[0008] The embodiments of the present disclosure relate to an apparatus, system and method for capturing and transmitting operational data from a downhole well environment to a second location.

[0009] Some embodiments of the present disclosure relate to an apparatus that can be deployed downhole and operatively couple with a downhole tubular. The apparatus, which may also be referred to as a data-collecting node (DCN) or data- gathering platform (DGP), may comprise of at least a pressure sensor, a temperature sensor, a power source, a controller circuit and a memory system. The apparatus further comprises a bus for operatively connecting the power source, the controller circuit and the memory system. In some embodiments of the present disclosure, the apparatus may be operatively coupled with the downhole tubular and the apparatus is configured to detect, measure, store (which may collectively be referred to as gather) assessment data of one or more operational-conditions that are external to the downhole tubular, internal to the downhole tubular or both and to transmit such assessment data.

[0010] Some embodiments of the present disclosure relate to a system that is deployable into a downhole environment. The system comprises multiple apparatus that are each configured to gather and transmit assessment data of one or more operational conditions. The apparatus each comprise a pressure sensor, a temperature sensor, a power source, a controller circuit and a memory system. The apparatusfurther comprises a bus for operatively connecting the power source, the controller circuit and the memory system. Each apparatus is also configured to be activated into a first state to detect, measure and store the assessment of one or more operational conditions. The apparatus is also configured to be activated into a second state whereby the stored assessment is transmitted to one or more other apparatus of the system. The system further comprises a collection apparatus at a second location within the wellbore for receiving the transmitted assessment and for transmitting that received information to a third location, where such third location may be proximal to or at the surface of the well into which the system is deployed. In some embodiments of the present disclosure, the system may further comprise a data tool that is deployable into the well, where the data tool is configured to: change an activation status of one, some or all apparatus within a well and to collect stored assessment from same.

[0011] Some embodiments of the present disclosure relate to a method for detecting, measuring, storing (gathering) and transmitting assessment data of one or more operational conditions within a wellbore. The method comprising a step of detecting the one or more operational conditions within a wellbore, wherein the step of detecting may occur internal or external to a wellbore conduit. The method further comprising a step of measuring the one or more operational conditions and storing the measured data downhole. The method further comprising a step of transmitting the stored data from a first position to a second position and from the second position to a third position, wherein the first and second positions are within the wellbore and the third position is proximal or at the surface. Alternatively, the method may further comprise a step of transmitting the stored data from a first position within the wellbore to a second position that is proximal to or at the surface.

[0012] Without being bound by any particular theory, the embodiments of the present disclosure may detect, measure, store and transmit an assessment of an operational parameter from the downhole well environment to a second and / or third location on or near the surface above. In some embodiments of the present disclosure, pressure build up in areas of the annulus that can be correlated to stimulation events can be captured and transmitted. This pressure build up could mean lost production which results in lost revenue and wasted energy input increasing the environmental impact perbarrel of production on that well. By employing the embodiments of the present disclosure, operators may be able to make operational decisions without expensive evaluation methods that may also increase the detrimental environmental impact.

[0013] Some embodiments of the present disclosure may be used in large sections of geothermal wells - even in sections where there is no metal conduit present.

[0014] Some embodiments of the present disclosure may wirelessly capture and transmit data regarding cap-rock integrity, aquifer integrity, and water table isolation for intermediate and surface casings. This data may be used to address a significant concern in some regions of the world where monitoring and protecting sub-surface water resources are desired outcomes. Some embodiments of the present disclosure may be able to capture and transmit desired data in real time.

[0100] Some embodiments of the present disclosure may maintain operability for the lifetime of the well either through wireless charging of onboard batteries, or with an onboard power generation system that can harvest kinetic energy from the flowing fluids within the well either via flow (turbine like) power generation or thermovoltaic power generation or combinations thereof.

[0101] Some embodiments of the present disclosure may replace fibre optic systems, reduce costs, reduce environmental impacts, provide risk mitigation after each zone is completed and prior to starting operations on a next zone.

[0102] Some embodiments of the present disclosure may provide real-time information to inform risk mitigation strategies for nearby wellbores (including previously stimulated wells). Some embodiments of the present disclosure may also provide real-time information regarding operational conditions within the annulus and a desired geologic formation over the life of the well.BRIEF DESCRIPTION OF THE DRAWINGS

[0015] These and other features of the present disclosure will become more apparent in the following detailed description in which reference is made to the appended drawings.

[0016] FIG. 1 is a side-elevation view of a data-collecting node, according to embodiments of the present disclosure, shown in use within a well.

[0017] FIG. 2 is a side-elevation view of the node of FIG. 1 and a second data- collecting, according to embodiments of the present disclosure, shown in use within a well.

[0018] FIG. 3 a side-elevation view of a well with multiple data collection nodes deployed therein and indicating the sensor payload of each node, according to embodiments of the present disclosure.

[0019] FIG. 4 a side-elevation view of a well with multiple data collection nodes deployed therein and indicating the sensor payload of each node, according to embodiments of the present disclosure.

[0020] FIG. 5 shows four example activation signature profiles (i) through (iv), according to embodiments of the present disclosure.

[0021] FIG. 5A, FIG. 5B, FIG. 5C and FIG. 5D each depict a different configuration of a well deployable tool for generating a respective signature of FIG. 5.

[0022] FIG. 6A, FIG. 6B and FIG. 6C each depict a scenario of a first assessment data captured at eight different well locations.

[0023] FIG. 7A, FIG. 7B and FIG. 7C each depict a scenario of a second assessment data captured at the same eight different well locations as in FIG. 6A-6C.

[0024] FIG. 8 depicts two configurations (layouts) of a well deployable data tool.

[0025] FIG. 9, FIG. 9A, FIG. 10 and FIG. 11 each show the configurations (layouts) of FIG. 8 having progressed through a respective data transmission operation.

[0026] FIG. 12 depicts a system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.

[0027] FIG. 13 depict as system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.

[0028] FIG. 14 depicts a system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.

[0029] FIG. 15 depicts a system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.

[0030] FIG. 16 depicts a system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.

[0031] FIG. 17 depicts a system, according to embodiments of the present disclosure, that are each configured to collect and transmit assessment data of one or more operational parameters within or proximal to a well.DETAILED DESCRIPTION

[0032] The embodiments of the present disclosure relate to an apparatus, a system and a method for detecting, measuring, storing and transmitting an assessment of an operational condition associated with or proximal to an oil and / or gas well or a geothermal well. The assessment comprises data, which may also be referred to as assessment data, operational data or the like, that is detected, measured and stored at a first location and transmitted to a second location. In some embodiments of the presentdisclosure, the first location is below ground and the second location is also below ground and the assessment data is further transmitted to a third location proximal or at the surface. In some embodiments of the present disclosure the second location is between the first location and the third location. In some embodiments of the present disclosure, the second location is at the surface.

[0033] As used herein, the term “about” refers to an approximately + / -10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

[0034] As used herein, the term “surface casing” refers to the first and largest casing installed in a well, the primary purpose of the surface casing string is to protect the water table (aquafer) from contamination that originates from lower sections of the well.

[0035] As used herein, the term “intermediate casing” refers to a secondary casing installed in some wells to isolate zones above the target formation. The size is smaller than the surface casing, but larger than the primary casing string or “liner”.

[0036] As used herein, the term “liner” refers to a primary casing that is installed after a well has finished drilling, Some embodiments of the present disclosure relate to liner centralizers that are positionable on the outside of the liner, liner collars that are integral in the liner and sensor systems that are positionable inside the liner, where such centralizers, collars and sensor systems capture and transmit desired information.

[0037] As used herein, the term “tie-back”, which may also be referred to as a “frac string”, refers to the primary casing installed above liner hangers, it is typically the same size as the liner. This string is often removed after the stimulation (frac) is complete. As used herein, the term “tie-back” may also be referred to in reference to a production casing or a mono-bore well installed above liner hangers.

[0038] As used herein, the term “production tubing” refers to a tubing string that may be installed after a well has been completed (stimulated), it doesn’t need to beconsidered for initial goals, but may have an effect on some long-term monitoring methods.

[0039] As used herein, the term “collar” refers to a connector between two joints of metal conduit, which may also be referred to as “pipe”.

[0040] As used herein, the term “coiled tubing” refers to a long roll of tubing (that is sufficiently long so as to reach any desired depth within a well) for performing a desired well operation at the desired depth of the well) without any connections that can be used to push tools through the liner. Variation called “E-coil” have an electronic conductor for electronic communication to downhole tools.

[0041] As used herein, the term “wireline” refers to a long roll of wire conductor with a group of tools on the downhole end that can be electronically controlled from surface or send data from the downhole environment to the surface.

[0042] As used herein, the term “casing shoe” refers to the deepest point on each casing string.

[0043] As used herein, the term “packer” refers to any tool that uses a rubber element to create a pressure barrier in an annulus between two pipes, or between a pipe inside a well.

[0044] As used herein, the term “liner hanger packer” refers to an integral part of the “liner hanger” well design. The liner hanger packer is a tool that is designed to “hang” the weight of the liner from the intermediate casing and isolate the formation from the inside of the intermediate casing.

[0045] As used herein, the term “stage collar”, which may also be referred to as a “stage tool” refers to a component used in well cementing operations in monobore wells to pump cement out of a pipe at multiple locations individually to control hydrostatic pressures.

[0046] As used herein, the term “frac sleeve” refers to an actuated valve installed in the lateral section of the liner, where the frac sleeve can be actuated with aball, dart, or coiled tubing deployed tool in order to control fluid communication between the well bore and the relevant geologic formation.

[0047] Toe initiation sleeve (Toe sleeve) - a frac sleeve installed at the toe of each well that is typically hydraulically activated to all pumping operations to begin.

[0048] As used herein, the term “bottom hole assembly” and “BHA” refer to a group of tools assembled on the end of tubing, coil, or wireline.

[0049] As used herein, the term “casing collar locator” and “CCL” refer to a tool in a wireline BHA used for detecting pipe collar locations.

[0050] As used herein, the term “slips” refers to a mechanism that the holds pipe in place by “biting” into the metal. Typically using tungsten carbide buttons or a carburized metal. Slips can describe surface equipment or portions of downhole tools such as liner hangers.

[0051] As used herein, the term “wellhead” refers to the pressure control equipment that is installed on top of the well at surface, it provides selectable access to each annulus and the liner and it has the “master valve” to shut-in a well.

[0052] As used herein, the term “tubing hanger” and “dognut” refer to a tubing hanger that is used on most tiebacks to “hang” the tie-back at surface and seal the annulus between the tie-back and the intermediate casing. The wellhead is then installed after the tubing hanger has been landed.

[0053] As used herein, the term “slip and cut” refers to a method where the liner is held in place with slips at surface, the top of last liner joint is cut off, and the wellhead is welded on top.

[0054] As used herein, the term “kick off point” and “KOP” refer to the point in the well where the well starts transitioning from vertical to horizontal.

[0055] As used herein, the term “heel” refers to the point in the well where the transition from vertical to horizontal is complete.

[0056] As used herein, the term “inclination” refers to the angle at any given point in a well, 0 degress is vertical, 90 degrees is horizontal.

[0057] As used herein, the term “vertical section” refers to the vertical portion of the well from surface to the KOP.

[0058] As used herein, the term “build section” refers to a curved section of the well from the KOP to the heel.

[0059] As used herein, the term “lateral section” refers to a horizontal portion of the well in the target formation.

[0060] As used herein, the term “toe”, “toe depth” and “TD” refer to the deepest point in the well.

[0061] As used herein, the term “measured depth” and “MD” refer to the total length from surface to a given location in a well

[0062] As used herein, the term “True Vertical Depth” and “TVD” refer tot he vertical depth from surface to a given location or section in a well, this information may be used to calculate various operational conditions, including but not limited to hydrostatic pressure.

[0063] As used herein, the term “outer diameter” and “OD” refer to the outer diameter of a pipe. Note, most OD’s listed are nominal and in some cases may have large tolerances that result in non-negligible changes to specified dimensions.

[0064] As used herein, the term “inner diameter” and “ID” refer to the inner diameter of a pipe. Note, most ID’s listed are nominal and in some cases may have large tolerances that result in non-negligible changes to specified dimensions.

[0065] As used herein, the term “bottom hole temperature” and “BHT” refer to the temperature of the formation that embodiments of the present disclosure will operate at, starting with expected operating temps of 80-125°C (or less) with some embodiments operating at temps up to 175°C or higher.

[0066] As used herein, the term “bottom hole pressure” and “BHP” refer to the absolute pressure at the formation, typical BHP is 21-35MPa (3000-5000psi) with a maximum absolute operating pressure of 138MPa (20,000psi) in early configurations, but other BHPs are also contemplated.

[0067] As used herein, the terms “logging while drilling”, “LWD”, “measuring while drilling”, and “MWD” refer to existing methods for capturing operational information while performing a drilling operation.

[0068] As used herein, the term “buckling” refers to structural damage caused when a downward (compression) force is applied to pipe, buckling typically happens in and around the build section in horizontal wells

[0069] As used herein, the term “helical buckling” refer to buckling that may happen where the buckling forces are at the maximum, this is a form of 3-dimensional buckling where the pipe “coils” against the walls of the hole

[0070] As used herein, the term “sinusoidal buckling” refers to buckling that may happen on either end of a section that is helically buckled, this is a form 2- dimensional buckling where the pipe “zig zags” against the walls of the hole

[0071] As used herein, the term “operator” refers the individuals who are performing one or more operations on a well.

[0072] Embodiments of the present disclosure will now be described by reference to the figures, which show representations of the apparatus, systems and methods according to the present disclosure.

[0073] FIG. 1 shows a non-limiting example of a data gathering platform 100 (DGP), which may also referred to as a data-collecting node (DCN), platform or node. The DGP 100 can be installed / deployed in a wellbore 16 that is drilled through a geological formation 10 of interest. The formation 10 may be of interest due to the presence of retrieval oil, gas, geothermal heat or any combination thereof. The DGP 100 may be operatively coupled to a wellbore tubular 14, such as casing, liner, pipe or tubing, on either an external surface of the tubular 14 or within an internal bore 17 ofthe tubular 14 (see FIG. 2). The DGP 100 is configured to detect, measure, store and transmit an assessment of one or more operational parameters in or near to the wellbore 16, via one or more sensors and / or gauges. The DPG 100 may comprise a housing 1000, a pressure sensor 102, a temperature sensor 104, a resistivity sensor transmitter 106, a resistivity sensor receiver 108 and further other sensors with a transmitter 105 and a receiver 107. The DGP 100 may further comprise a power source, a controller circuit and a memory all of which are operatively connected by a bus system (not shown). In the non-limiting depiction of the DGP 100 shown in FIG. 1, DPG 100 may be operatively coupled to a surface receiver output (SRO) that in turn is operatively coupled to a user inter-face, such as a computer, tablet, smart phone or the like, the DPG 100 may be operatively coupled to the SRO by wireless data transmission and / or one or more wired transmission cables, such as fiber optic cable, wireline cable, coaxial cable and the like. Furthermore, DPG 100 may receive power via the one or more wire transmission cables. In the non-limiting depiction of the DGP 100 shown in FIG. 1, the DGP 100 may be coupled to the external surface of the tubular 14 via the housing 1000, which may also be referred to as an accessory. In some embodiments of the present disclosure, the housing 1000 may be configured to act as a centralizer for centralizing the tubular 14 within the wellbore 16. For example, the centralizer 1000 is a device that may be installed on the external surface of a wellbore tubular 14 to push the tubular closer to the center of the wellbore 16 by creating standoff against the outer surface of the wellbore 16. Some configurations of centralizers also have fins that are configured to create fluid turbulence when fluid flows past the fins. The housing 1000 may be secured to the external surface of the tubular 14 or it may be allowed to slide freely between casing collars (connectors). In other embodiments of the present disclosure, the DGP 100 may be housed within the housing 1000, which is installed integral to the tubular 14. The housing 1000 may be a collar, pipe joint, or any form of downhole tool that may or may not have additional functions besides the data gathering functions provided by the DGP 100.

[0074] In some embodiments of the present disclosure, the DGP 100 may comprise pressure sensors that are positioned within the housing 1000 where such internal pressure sensors are in fluid communication with the environment outside ofthe housing 1000 via one or more pressure communication tubes that extend between outside and inside the housing 1000. Such pressure tubes may be filled with wax or other apparatus that melts at elevated temperatures. The pressure tubes may have plugs to prevent foreign debris from collecting therein and interfering with operation of the internal pressure sensor. The pressure tubes may be protected by one or more plugs made up of a material that dissolves when exposed to a specific chemical, pressure or temperature.

[0075] In other embodiments of the present disclosure, the housing 1000 may be configured to house the DGP 100 where the housing 1000 may directly engage the surface of the wellbore 16 for deploying into wellbores that are without a downhole tubular 14.

[0076] In some embodiments of the present disclosure, the DGP 100 will include a digital controller circuit that can be pre -programed or re -programed after deployment. The digital controller circuit may operate in various modes that may include a “low power mode”, “high sample mode”, and “low sample mode”. In the low power mode, the DGP 100 may draw power from a secondary power source and may be cut-off from the primary power source to preserve power integrity. The secondary power source may be the real-time clock battery in the digital controller. In the low power mode, the DGP 100 may monitor a sensor or group of sensors for a change beyond pre-programmed static parameters to switch modes, which may also be referred to as activating the DGP 100. The DGP 100 may also use pulse modulation methods to monitor sensors or receive an electromagnetic (EM) signal to switch between different operational modes. The DPG 100 may also be configured to use a magnetic switch activator that relies on different configurations of magnets to change a mode that the DPG 100 is operating. The DPG 100 may also be configured to change the mode in which it operates based upon an acoustic signal, whereby an acoustic sensory may detect a specific frequency, amplitude, sequence or pattern of an acoustic signal to shift a DGP 100 from one activation state to another. The DPG 100 may also be configured to change the mode in which it operates based upon active electromagnetic communication and / or changes in the operational parameters being detected, specific sequences in parameter changes, or different signals may be used to select differentmodes or change sensor parameters. Additionally, the controller circuit may also be configured to initiate a mechanical or electronic function that may or may not be related to data gathering functions of the DGP 100. For example, the DGP 100 may also be able to regulate the activation, setting, or opening of a downhole tool such as a liner hanger, isolation packer, or sliding sleeve via various methods including, but not limited to electronically driven mechanical movement, valve opening / closing, and chemical reaction initiation to produce high pressure gas. The controller circuit may also be configured to open a high-pressure gas bottle or to activate a chemical reaction to “purge” sensors and ensure proper operation of the sensors that are included with the DGP 100. In the high sample mode, the DGP will sample data from each sensor at programed intervals, these samples occur approximately every 1 second to 15 minutes depending on data gathering requirements and power budget management. Some sensors may require much higher sample rates and record data approximately every 1 millisecond. In the low sample mode, the DGP will sample data from each sensor at programmed intervals that may be greater in length than the high sample mode. These samples occur approximately every 12 hours to preserve power budget.

[0077] The assessment of the one or more operational parameters may be embodied in data that is detected and measured by the DGP 100. The DGP 100 may store the measured data that can be handled using various methods including internal memory, instant data transmission, timed data transmission, data transmission when specific parameters met, or data transmission through transmission request. If instant data transmission is used, the DGP 100 may or may not include internal memory storage capabilities. Timed data transmission may allow for improved data compression and reduced power requirements. Data transmission when specific parameters are met (including via on board data analysis) allows for quick decision making if parameters exceed decision limits. Data transmission through transmission request allows data to be transferred on demand from one DGP 100 to another DGP 100 or to a second location. All configurations of the DGP 100 include the ability to transmit data, some configurations also include the ability to receive data. The DGP may also be configured to receive and store data from other DGPs. Various data transmission methods are detailed further below.

[0078] The power source of the DGP 100 may using batteries, thermovoltaics, flow-induced power generation (such as a turbine), vibration or a combination thereof. In some embodiments of the present disclosure, the DGP 100 includes one or more rechargeable batteries that may be charged using any onboard power generation method or via induction charging methods.

[0079] A variety of sensors may be integrated into the DGP 100 to monitor both environments that are external and / or internal to the wellbore tubular 14. There may be one of more of each sensor installed on any given DGP. FIG. 1 shows a common sensor configuration of a DGP 100 that is operatively coupled onto the external surface of the tubular 14 for external data gathering. (Note: other embodiments of the DGP 100 may also be capable of internal data gathering, internal data gathering as shown in FIG. 2) The DGP 100 may comprise an external pressure sensor 102 that is configured to monitor the external fluid pressure around the DGP, multiple sensors 102 may be installed to monitor different points as shown. Alternatively, the sensors 102 may be connected to additional points around the DGP via pressure lines. The DGP 100 may comprise an external temperature sensor 104 that is configured to monitor the external temperature around the DGP, multiple sensors 104 may be installed to monitor different points as shown. The DGP 100 may comprise a resistivity sensor transmitter 106 that is configured to emit an electromagnetic signal that is received the resistivity sensor receiver 108, this signal can be used to analyze fluid and material properties in proximity to the DGP 100. This measurement can be done in two ways - the first is with the Resistivity Tx / Rx both placed inside of the same DGP 100 - the second is using the communications Tx / Rx between DGPs and emitting a specific signal that is used to analyze resistivity. The DGP 100 may comprise an accelerometer 110, which is a sensor that monitors movement along the X, Y, and Z axis as well as rotation about the X, Y, and Z axis. The accelerometer 110 may be used to determine orientation parameters including inclination, rotation, and azimuth. The DGP 100 may comprise a magnetic switch sensor 112 that monitors for changes in magnetic fields, both in polarity and field strength.

[0080] In addition to the configurations depicted herein, a variety of additional sensors may be integrated - these sensors are all known and used within various datagathering tools within the oil & gas industry as well as other industries, including but not limited to: an acoustic microphone - this sensor records the acoustic environment around the DGP; a strain gauge - this sensor is attached directly to the pipe and linked to the DGP, it allows continuous monitoring of the mechanical strain in the casing; a 3D positioning system - using multiple high power EM emitters at surface operating at less than 1000Hz it is possible to determine the exact location of each DGP; an external flow meter - this determines if there is flow past the outside of the DGP and may also determine the rate of volume flow and rate of mass flow; a geophone array - this uses “geophone” sensors to monitor micro-seismic activity near / around the DGP; a neutron density logger - used to determine the density and other properties of the surrounding materials using a neutron emitter source; an ultrasonic scanner - this uses a sensor or array of sensors to scan the hole around the DGP; a mechanical caliper - this uses the deflection of mechanical arms to determine the dimensions of the hole; a spectroscopic sensor - various sensors calibrated to look for specific molecules and amounts around the DGP may be installed; a viscosity sensor - determines the viscosity of the fluid around the DG; a salinity sensor - determines the salinity of the fluid around the DGP; a gamma log - this uses a gamma source to analyze the materials around the DGP; a cement bond log - this uses a sonic emitter / sensor to analyze the cement and other materials around the DGP; a H2S sensor; and, a CO2 sensor.

[0081] From time to time, one or more of the DGP 100 sensors may need to be purged or cleaned to function correctly. Various features can be integrated into the DGP 100 for this purpose. For example, the DGP 100 may comprise: a purge bottle - a bottle of a high-pressure gas (>20,000psi) that is opened or punctured releasing the high-pressure gas and pushing material off of sensors that may interfere with operation; a propellant bottle - a bottle containing a chemical mixture, when a chemical reaction is initiated, a high-pressure gas is produced to push material off of sensors; a solvent bottle - a bottle that releases a chemical solvent to clear solid material off of sensors; a low melting temp protector - a material with a melting temperature such that it is solid at ambient temperatures in air, but melts at the higher temperatures deep underground such that it would initially protect sensors from debris and then melt off once the DGP has reached the ambient temperature where it is installed.

[0082] The DGP 100 may also be configured to perform one-way communication or two-way communication by any combination of:(a) Method A: Capacitive coupling communication;(b) Method B: EM Communication through EM leaks (outside to inside, inside to outside);(c) Method C: EM Communication, inside to inside through fluid;(d) Method D: Magnetic Induction Communication, inside to inside through fluid;(e) Method E: PLC (Power Line Communication) - with optional up hole amplifiers and / or repeaters;(1) Method F : EM Communication (outside to outside through cement / rock or inside to inside through fluid) - with optional EM repeaters;(g) Method H: a DGP 100 or multiple DGP 100 are placed throughout the well that gather data transmitted wirelessly from other accessories via Method E or F and then data is retrieved from the data node(s) using an accessory that is deployed via wireline, slickline, tubing, coiled tubing, e-coil, pumped down, or self propelled; and,(h) Method 1: fibre optic is used to retrieve data from the DGP 100.

[0083] The DGP 100 and the housing 1000 that houses same may be made of various materials that are suitable for the downhole environment, such as metal, plastic or (glass / CF / and the like) filled plastic. The housing 1000 may be machined, cast, injection molded or hydroformed in order to take a suitable shape for housing the DPG 100 and to perform any ancillary functions, such as centralizing and the like. In some embodiments of the present disclosure, the various electronic components of the DGP 100 may have independent pressure housings. In some embodiments of the present disclosure, the DGP 100 may have erosion protection, such as: silicon carbide coating; tungsten carbide coating, other metal coatings; material treatments (nitride, boronizedcoating, etc), tungsten carbide wear buttons, silicon carbide wear buttons or any combination thereof.

[0084] FIG. 2 depicts an embodiment of the present disclosure where the DGP 100 is housed within an housing 1000 that is can be deployed in an integral fashion to the tubular 14, slid over the casing string, and a further DGP 120 can be installed inside the tubular 14. The further DGP 120 can have all or some of the same features and functionalities of the DGP 100 described herein above with the primary difference being that the further DGP 120 is configured to detect, measure, store and transmit an assessment of one or more operational parameters within the bore 17 of the tubular 14. For example, the further DGP 120 may comprise an internal pressure sensor 130, an internal temperature sensor 134 and, optionally, one or more further sensors 136 that are configured to detect, measure, store and transmit one or more operational parameters inside the tubular 14. The further DPG 120 may further comprise sensor transmitter (Tx) and sensor receiver (Rx) assembly 128. In some embodiments of the present disclosure, the two DGPs 100, 120 can be run in tandem and electronically and / or mechanically connected, for example by a conduit 122, so that power, digital control, and communications can be shared between the DGPs. In some embodiments of the present disclosure, the conduit 122 may further comprise a strain gauge 132 to monitor the physical coupling of the DPG 100 and the further DPG 120.

[0085] In FIG. 2, the DGP 100 described herein above, 1 is electronically and mechanically coupled to the further DPG 120 via a modified connector 124. In this embodiment of the present disclosure, the further DGP 120 comprises internal sensors and internal communications and the further DPG 120 relies on the DGP 100 for power, digital control, and external communication to other DGPs (if required). An integral DGP may include all the sensors and components outlined in FIG. 1, in addition it also provides the ability to have a variety of sensors inside the casing string. Without being bound by any particular theory, at least one benefit of the embodiment depicted in FIG. 2 is that it minimizes the exposure of the two DGPs to internal pressure forces and tension forces and reduces the risk a pressure or structural failure will occur at either DGP. It also can improve the economics of building and deploying the DGP.

[0086] Internal sensors that may be included in further DGP 120 may include but are not limited to: an internal pressure sensor - this sensor allows the pressure of the fluid inside the casing to be monitored. Internal temperature sensor - this sensor allows the temperature of the fluid inside the casing to be monitored. Internal flow meter - this determines if there is flow past the inside of the DGP / casing and may also determine the rate of volume flow and rate of mass flow. Densiometer - this sensor determines the density of the fluid inside the casing. Spectroscopic sensors - various sensors calibrated to look for specific molecules and amounts inside the DGP may be installed. Viscosity sensor - determines the viscosity of the fluid inside the DGP. Salinity sensor - determines the salinity of the fluid inside the DGP.

[0087] FIG. 3 depicts multiple DGP 1001through DGP1008deployed along a non-vertical portion of a wellbore 16 that has been drilled through a desired geological formation 10. In some embodiments of the present disclosure, the DPG 100 are installed at an interval range of 10-120m, as shown by X1through X8. However, in some specific applications the DGPs may be closer or further away from each other. In FIG. 3, the DGPs are only shown as deployed through the lateral section of the wellbore 16, but they can also be deployed in the build and vertical sections if desired. The assessment data in relation to one or more operational parameters may be detected, measured, stored and transmitted for a variety of applications in both oil & gas operations and geothermal operations at different stages of the well' s operation.

[0088] A first application is formation and isolation analysis during and immediately following initial installation. The data gathered by the DGP can be used to analyze the formation and wellbore features and isolation integrity as well as provide baseline readings to compare against future data gathering. The formation and wellbore features can include areas such as natural fractures as well as washouts and hole ovality. Isolation integrity can include cement evaluation and pressure integrity evaluation between the various DGPs in both cemented and open-hole applications.

[0089] A second application is real-time analysis of the entire wellbore during stimulation operations. This allows for on-the-fly decision making to improve operations and reduce energy & material inputs in real time. The primary goal is toidentify any time of pressure isolation failure in real-time and / or to track pressure events to determine whether or not fluid flow is entering the desired location. The secondary goal is to identify casing deformation in real-time to prevent issues that can impede operations and potentially lead to the loss of a well. This analysis can focus on a single well, a group of wells on a single pad, or groups of wells across multiple pads. The real-time analysis may also include analysis of seismic events (or other acoustic events) via a geophone to track shearing events within downhole components deployed within eh well.

[0090] A third application is long term analysis of the entire wellbore during production operations. The primary goal is identifying formation draw down and changes in formation characteristics. The secondary goal is identifying potential production issues and improving the ability to determine mitigation methods and viability to improve production.

[0091] The fourth application is monitoring of upper formations, aquifers, and water table integrity. The goal is to accurately confirm there was no accidental communication or damage to other formations, aquifers or the water table as a result of stimulation operations.

[0092] FIG. 4 is similar to FIG. 3, with the primary difference that at each place there are tandem DGPs as depicted in FIG. 2, 1001-8A represent the external DGPs and 1001-8B represent the internal DGPs. This deployment configuration allows for data gathering inside of the casing as well outside and improves the overall data picture as compared to the deployment configuration depicted in FIG. 3.

[0093] FIG. 5 and FIG. 5A-5D provides a series of schematics that outline a process that can be used to send a coded to signal to a DGP or used to send a coded signal (including activation signal) to any downhole tool that may or may not incorporate data gathering capabilities. FIG. 5 shows four possible magnetic activator signatures (i) - (iv) that may be detected by the magnetic sensor of a given DGP according to the embodiments of the present disclosure. Such that when the magnetic sensor of a given DPG detects one of the signatures, the controller circuit will initiateone or more predetermined actions. For example, FIG. 5 A shows a dart 200 A that is configured to be delivered downhole to a given DPG and to produce Signature 1, where the dart 200 has three magnets 202, 204 and 206 with a first magnet 202 separated from a second magnet 204 by a first length (LI) and the second magnet 204 separated from a third magnet by a second length (L2).

[0094] FIG. 5B depicts a second dart 200B that is configured to be delivered downhole to a given DPG and to produce Signature 2, where the dart 200B has three magnets 202, 204 and 206 with a first magnet 202 separated from a second magnet 204 by a first length (LI) and the second magnet 204 separated from a third magnet by a second length (L3).

[0095] FIG. 5C depicts a third dart 200C that is configured to be delivered downhole to a given DPG and to produce Signature 3, where the dart 200C has three magnets 202, 204 and 206 with a first magnet 202 separated from a second magnet 204 by a first length (LI) and the second magnet 204 separated from a third magnet by a second length (L3).

[0096] FIG. 5D depicts a dart 200D that is configured to be delivered downhole to a given DPG and to produce Signature 4, where the dart 200 has four magnets 202, 204, 206 and 208 with a first magnet 202 separated from a second magnet 204 by a first length (LI) and the second magnet 204 separated from a third magnet by a second length (L4) and the third magnet 206 is separated from the fourth magnet by a third distance (L5). Note, the field strength, flux and orientation of each of the magnets upon the darts 200A-200D may be the same or different and LI and L3 in FIG. 5B and FIG. 5C may or may not be equal.

[0097] The premise of this system is each DGP or downhole tool will have a digital controller connected to one or more magnetic switches for monitoring. As a potential addition or alternative, a current measurement device can be attached to the pipe to monitor for the current induced by the magnets traveling through pipe. A downhole deployable dart or other type of downhole deployable system with one or more magnets travels past the magnetic switch and can send a code based on acombination of four potential parameters: 1. The number of magnets 2. The combination of lengths between each magnet 3. The polarity orientation of each magnet 4. The velocity of the system. A list of codes is pre-programmed into each digital controller prior to the installation of a DGP or downhole tool.

[0098] As the magnetic activator dart 200A in FIG. 5A travels past the magnetic switch of a given DGP, the DGP will record the graph shown as Signature 1 (Scenario 1). The length “LI” is a known length pre-programmed into the digital controller of the DGP. When the signature is analyzed the velocity of the dart can be determined. Based on the velocity of the dart, the length “L2” to the next magnet can be determined. The length “L2” and the orientation of each of the three magnets matches a pre-programmed code in the digital controller. Based on this code the digital controller can change a programmed parameter or activate a pre-programmed action. Additionally, the velocity of the dart may be used to create additional actions and / or prevent corrupted codes from triggering incorrect actions.

[0099] When the dart 200B is delivered downhole to a DGP (Scenario 2), all the parameters may be similar to when the DGP detects the Signature 1 with the exception of the length “L3”, when this code is analyzed by the digital controller it will trigger a different action than caused by Signature 1.

[0100] When the dart 200C is delivered to a DGP (Scenario 3), all the parameters are may be similar to when the DGP detects the Signature 2 with the exception of the orientation of the second magnet 204 is reversed in dart 200C as compared to dart 200B. When this code is analyzed by the digital controller it will trigger a different action by the DGP as compared to when the DGP detects Signature 1 or 2.

[0101] When the dart 200D is delivered to a DGP there is an additional magnet 2008 as compared to Scenarios 1, 2, and 3. This allows for the creation of more codes compared to the darts deployed in the first three Scenarios.

[0102] These scenarios show darts where the magnets are in a fixed position. However, additional configurations not shown could allow for the lengths betweenmagnets and the orientations of the magnets to be adjusted by a digital controller inside the dart or other device that allows for a single device to send different codes to different DGPs or other downhole tools. Additionally, it would allow for multiple codes to be sent to a single DGP or downhole tool if it passes multiple times.

[0103] FIG. 6A & 7A (Scenario 5)

[0104] Scenario 5 starts with eight DGPs distributed through a well as shown in FIG. 3. Each of FIG. 6A-6C and FIG. 7A-7C have 8 panels with each panel representing a DGP at a given data gathering location within a well and with FIG. 6A- 6C representing pressure measurements and FIG. 7A-7C representing temperature measurements. After the initial installation, static baseline sensor readings are typically expected and FIG. 6A and FIG. 7A represent the static readings expected for pressure (FIG. 6A) and temperature (FIG. 7A). If there is successful isolation at a DGP then the sensor readings are typically expected to match the baseline sensor readings.

[0105] FIG. 6B & 7B (Scenario 6)

[0106] In a continuation from Scenario 5, there is bad isolation in the well during a stimulation or other procedure that inflows high pressure fluid injection. It can be observed from the data that there is a deviation in pressure and temperature and at DGP2 and DGP3 (see second and third panels of FIG. 6B and FIG. 7B).

[0107] FIG. 6C & 7C (Scenario 6 continued)

[0108] Zooming in on the data shows that the change in pressure and temperature is more approximately double at DGP2 as compared DGP3. Differences in data can allow for different operational decisions throughout the continued operations on this well.

[0109] FIG. 8 depicts a non-limiting embodiment of a configuration (layout) for capacitive coupling communication configuration that can transfer data from outside of the tubular 14 to inside 16 of the tubular 14 or vice versa.

[0110] As mentioned hereinabove, there are multiple configurations (layouts) of transferring data from a given DGP to a telemetry tool 300 that can be deployed into a wellbore 16. The telemetry tool 300 comprises a surface connecting line 302 and a body 304. The line 302 may be configured to act as a tether and means to retrieve the tool 300 and / or it may also have conductive properties so as to deliver data uphole to the surface while the body 302 remains downhole. Capacitive coupling communication is a known method of data transfer and is the first such method of data transfer. This method can be used for a slide on DGP 100 as shown in FIG. 1 or an integrated DGP as shown in FIG. 2. This method involves the capacitive coupling of a transmitter and receiver to send data. As shown in FIG. 8, both the DGP 100 and the telemetry tool 300 may have transmitters and receivers allowing two-way data transfer. With this method it is possible to transmit data through the faraday cage of solid metal casing. SIGNAL 1 (upper panel of FIG. 8) - shows data being transferred from the DGP 100 to the telemetry tool body 304. SIGNAL 2 (lower panel of FIG. 8) - shows data or commands being transferred from the telemetry tool body 304 to the DGP 100. The data sent to the telemetry tool can either be sent via wire communication to surface in real-time, via line 302, or stored on the telemetry tool body 304 until it is retrieved at surface.

[0111] FIG. 9 depicts a non-limiting embodiment of a configuration (layout) for electromagnetic communication or magnetic communication that can transfer data from outside of the tubular 14 to inside 16 of the tubular 14 or vice versa.

[0112] Electromagnetic communication and magnetic communication are both known methods of data transfer. This method can be used for a “slide on” DGP 100 as shown in FIG. 1 or an “integrated” DGP as shown in FIG. 2. In this method the communication is sent from the DGP and “electromagnetic leaks” inside the casing through any mechanical gap. Mechanical gaps at threads are most common as shown in this Figure, but mechanical gaps created by perforations in the casing or opening ports in a downhole tool will also create “electromagnetic leaks”. The data can be sent from the DGP to the telemetry tool or from the telemetry tool to the DGP through these leaks.

[0113] FIG. 9A - (Approx, between 1kHz and IMhz) Electromagnetic Communication or Magnetic Communication (outside of casing to inside of casing or inside of casing to outside of casing) from Pressure Barrier DGP to External DGP

[0114] FIG. 9A depicts a continuation of the configuration (layout) of FIG. 9, in which the communication travels through “electromagnetic leaks” at perforations SI 8 or open ports in the pipe that allow an easier escape of the signal as the “electromagnetic leaks” are larger than those at the pipe threads. In FIG. 9A, the data is sent and received to / from a pressure barrier inside the pipe that contains a DGP.

[0115] FIG. 10 - Electromagnetic Communication (inside of casing to inside of casing)

[0116] FIG. 10 depicts another configuration (layout) for sending data from a DGP outside of the casing to a telemetry tool inside of the tubular. FIG. 10 shows that data can be sent from a transmission point inside the tubular to a telemetry tool inside the casing. This method requires an integrated DGP such as the configuration shown in FIG. 2. The advantage of the configuration (layout) depicted in FIG. 10 is higher transmission frequencies can be communicated than through “electromagnetic leaks”. However, as the frequency is increased, the viable transmission distance between the transmitter and receiver decreases. In FIG. 10, the data is sent from the “slide on” DGP through to the “integrated” DGP to the telemetry tool, or from the telemetry tool through the “integrated” DGP to the “slide on” DGP.

[0117] FIG. 11 - Magnetic Induction Communication (inside of casing to inside of casing)

[0118] Magnetic induction communication is a known method of data transfer. This is a form of short range communication (<3m) that can transmit through an associate medium that may make standard electromagnetic communication unreliable. This method requires an integrated DGP such as the configuration shown in FIG. 2.

[0119] FIG. 12 - Basic EM Repeater Layout

[0120] FIG. 8, 9, 10, and 11 outline configuration (layout) for transmitting data between DGPs and a telemetry tool. FIG. 12 outlines a configuration (layout) for transferring data between deployed DGPs. In this FIG. 12, data from DGP1 is transmitted to DGP2, the combined data from DGP2 and DGP1 is sent to DGP3, then the combined data from DGP1, DGP2, and DGP3 is sent further up the well. The data transfer between DGPs continues until it reaches a DGP designated to store the data or transferred all the way to a surface readout system at the well head (as shown in the lower panel of FIG. 12). Electromagnetic data transfer between DGPs is typically done at frequencies in the range of 1kHz to 1MHz depending on the operating environment and application; however, lower and higher frequencies are also contemplated.

[0121] FIG. 13 - Full Wellbore with EM Repeater Layout

[0122] FIG. 12 shows a configuration (layout) of transmitting data between DGPs. FIG. 13 depicts a configuration for transmitting data between DGPs and sending that data all the way to surface. FIG. 13 also shows how multiple EM frequencies can be used to increase data transmission capabilities. FIG. 13 also introduces the concept or “Repeaters”, in this configuration a Repeater is a DGP that may not have any sensor or data gathering capabilities but can transmit or store data. As shown, DGP1 transmits data to DGP5, DGP2 transmits data to DGP6, etc. until the data reaches a Repeater Rl. This also creates “frequency chains” to ensure that if one DGP is has a technical failure, then data gathering capabilities are not lost of the entire wellbore. In this configuration the repeaters are capable of transmitting on multiple frequencies through the network of repeaters until the data reaches the surface readout at the wellhead where it can be downloaded to a computer and analyzed.

[0123] FIG. 14 - Full Wellbore with EM Repeater Layout (Surface Command)

[0124] In FIG. 13, a configuration (layout) for transmitting data to surface via DGP to DGP transmission is shown. FIG. 14 depicts a similar configuration (layout) as in FIG. 13; however, a command is sent from surface through the DGPs. This command could change DGP modes, sample rate parameters, sensor parameters, ordirectly trigger an action by the DGP or a downhole tool that is in the data transmission proximity of a DGP.

[0125] FIG. 15 - Full wellbore with EM Repeater Layout and Data Node

[0126] In FIG. 13 and FIG. 14, a configuration (layout) is shown for transmitting data from one or more DGPs all the way to surface via DGP to DGP transmission. However, some operating environments or configurations may present technical challenges with this operation, such as upper formations that interfere with data transmission. In these environments a configuration (layout) may be used where one or more DGPs are used as a “Data Node” where data from all other DGPs are transmitted and stored in a single location. Data nodes are typically configured as shown in FIG. 2 and can then use methods outlined in Figures 8, 9, 10, or 11 to transmit data to surface.

[0127] FIG. 16 - Full wellbore with EM Repeater Layout and Data Node (Data Node Command)

[0128] Using the same configuration (layout) shown in FIG. 15, a command can be sent from a Data Node to other DGPs for the same purposes outlined in FIG. 14. This can be sent on a timed basis or via a telemetry tool.

[0129] Without being bound by any particular theory, the embodiments of the systems described hereinabove may further comprise one or more integrated transceivers, for example one or more a controller area network (CAN) nodes that are operatively coupled to each other to share / transmit data between each CAN node. For example, individual CAN nodes may be positioned along the wellbore for transmitting collected data and / or instructions and together multiple CAN nodes may form a CAN that extends through some, most or substantially all of the wellbore. Each CAN node may comprise a CAN controller and a CAN transceiver. The CAN controller may be operatively coupled to one or more sensors to receive the sensor’s detected data and the CAN controller may then share that received data with the CAN transceiver. The CAN transceiver can then transmit the sensor data to another CAN node that is at a different position within the wellbore so that ultimately the sensor data is received at surface andso that surface borne instructions or data can be relayed through the coupled CAN nodes back downhole. In some embodiments of the present disclosure, the series of operatively coupled CAN nodes may be separate from but in addition to Tx / Rx architectures described above. In some embodiments of the present disclosure, the CAN nodes may replace one or more of the Tx / Rx architectures.

[0130] FIG. 17 - Data transmission from Data Node to Telemetry Tool to Surface

[0131] Continuing with configuration (layout) shown in FIG. 15 and 16, a telemetry tool can be deployed to a data node using known deployment methods such as wireline or coiled tubing. Once the telemetry tool has reached the Data Node it can download all stored data or it can send a command through the DGP network. In the configuration (layout) of FIG. 17, the data is transmitted from the Data Node to the telemetry tool and then to a surface location where it can be transferred to a computer for analysis. In this configuration of FIG. 17, a data command can be sent from a computer through the surface connection to the telemetry tool then to the Data Node for transmission through the DGP network.

[0132] The various DGP apparatus described above can be deployed in one or more of the configurations (layouts) also described above in order to perform various types of methods (processes) for detecting, measuring, storing and transmitting assessment data of one or more operating parameters within a well.

[0133] For example, one or more DGPs may be installed into a well, initially they will be in a sleep (battery saver) mode, while the target zones within the well may be isolated (with cement or open hole packers or other well zone isolation methods).

[0134] When the operator starts stimulation operations on the well with the deployed DGPs, the DGPs are activated to switch from sleep mode to active mode (regular interval readings ~l-5min).

[0135] When the DGPs switch to active mode, it will optionally open a purge bottle that will purge all internal tubing and sensors (gauge and sensor lines).

[0136] Manners to switch into active mode:• Magnetic switch activated by dropping a magnetic ball / dart during first stage operations• Magnetic switch activated by magnet on bottom hole assembly (BHA) containing data tool (wireline, coiled tubing and the like)• Passive or low energy noise sensor / accelerometer that detects active operations• by inter-well communication from a different well, not just first stage operations• EM or radioactive signal

[0137] Once the DGP has switched to active mode, it will first take an initial reading, by detecting the desired operational parameter and measuring the desired operational parameter, based upon the given sensor type deployed on each DGP. Then each DGP will take regular interval readings of low power gauges (pressure, temperature, accelerometer) and long interval readings of high power gauges (resistivity / fluid analysis) after pre-determined conditions are met (ex. Pressure flat-line for 15min after pressure changes) or at set time intervals (every 15min-lhr).

[0138] Initial readings can be used to: identify geological and wellbore features (such as natural fractures) and areas of poor cement isolation (based upon resistivity readings).

[0139] High power readings can also be requested via a deployed data tool.

[0140] Each DGP will store all data readings until a data tool is deployed downhole to collect the stored readings (via E-Line, E-Coil or a pump down / self propelled data tool).

[0141] Each DGP may be switched into a “transmit mode” when the magnetic switch of each DPG is activated. Magnetic signal activators may be placed with aknown separation for different combinations to each DGP to determine the speed of the data tool and exact distance to the receiver on the data tool (required for communication methods A & D).

[0142] While in the transmit mode, each DGP will transmit the maximum amount of data possible within the calculated communication window (based on communication method).

[0143] During this time, the data tool can send a signal to one, some or all of the DGPs and request a full data download of all stored assessment data.

[0144] A signal can also be sent to one, some or all of the DGPs to change the recording mode, for example to switch to “production mode”, with only recording 1 -2 readings being taken and stored per day.

[0145] Communication methods:

[0146] Method A: Capacitive Coupling Communication

[0147] A capacitive transmitter (Tx) in the DGP on the outside of the tubular capacitively couples with a capacitive receiver (Rx) inside the tubular (on the data tool) to transmit data. This communication method requires Tx / Rx pairing, methods of knowing exact distance for pairing are outlined above.

[0148] Method B: Magnetic Communication through EM leaks (outside to inside)

[0149] A magnetic transmitter (Tx) in the DGP - for example when the housing of the DGP is a centralizer - transmits an EM signal to an magnetic receiver (Rx) inside the pipe (on the data tool) to transmit data. This communication method takes advantage of EM leaks created by threaded pipe connections, perforations, and port openings to send a magnetic signal from outside the pipe to inside the pipe. EM concentrators may be placed at / near connections to improve communication.

[0150] Method C: EM Communication with Rx / Tx both inside the pipe (inside to inside)

[0151] An EM Tx in the DGP - for example when the housing of the DGP is a collar - transmits an EM signal from a Tx placed inside the pipe to a Rx that is also inside the pipe (on the data tool) to transmit data. This communication is significantly simpler as it only requires transmitting the signal through fluid instead of via RF leaks.

[0152] The expected suitable frequency is approx. 400-500 kHz with an optional use of multi-frequency Tx / Rx to increase data transmission rates. Higher frequencies may be possible with adjustments to applicable E-line communication frequencies that may also be present in the wellbore.

[0153] Method D: Magnetic Induction communication with Rx / Tx both inside the pipe (inside to inside)

[0154] A magnetic induction Tx in the DGP - for example when the housing of the DGP is a collar - transmits a magnetic signal from a Tx placed inside the tubular to the a Rx that is also inside the tubular (on the data tool) to send data. This communication may be simpler than other communication methods as it only requires transmitting the signal through fluid instead of via RF leaks. This communication method requires Tx / Rx pairing and methods of knowing exact distance for pairing are outlined above.

[0155] The assessment data will be stored in the data tool, if run on E-Line or E-Coil, the assessment data will be sent to surface as well. The assessment data may be sent up the E-Line / E-Coil via modem, “panel” at surface receives data and sends to laptop. Software on laptop interprets and / or generates a visual representation of the assessment data and its interpretation thereof. For example, applicable software may overlay assessment data from one or more previous stages on a 3D plot of all applicable wellbores. The assessment data may allow operator to determine if any inter-stage or inter-well communication occurred when pumping last stage. The assessment data may also allow operator to determine extent of fluid communication. For example, a larger temperature change may mean there is more fluid communication than originally intended. The operator may also be able to determine from the assessment data if thereis sand present, which if there is sand present may result potential issues on the next well stage.

[0156] Formula created with operator input will determine cost / benefit analysis of attempting to treat a stage where there has been communication as opposed to abandoning the well or stage.

[0157] After stimulation is complete, the data tool can be run on coiled tubing, E-Coil or the like, to collect full data download from each DGP. Some embodiments of the present disclosure allow for data to be download from DGPs that are closer to the toe of a well where the stages are completed via “plug and perf ’ stimulation. Retrieving this data will allow greater understanding of what happened during the stimulation and allow for further optimization on future wells.

[0158] Once data download is complete, the data tool will send a signal to one, some or all DGPs to switch to “Production Mode” (long term) where Accessory takes 1 -2 readings per a day.

[0159] The data tool may switch to production mode after sensors have flat lined or after pre-determined time.

[0160] Magnet / other signal activator can be used to switch one, some or all DGPs back to the active mode.

[0161] Different combinations of magnets can indicate different modes with a 1 -way transmitter.

[0162] Additional runs of the data tool can be used to retrieve production assessment data to provide further information on how a well is performing over time, with battery life being a potential term limiting factor.

Claims

CLAIMSI claim1. A data gathering platform (DGP) comprising:(a) a power system;(b) a communication system;(c) a sensory unit configured to detect one or more conditions external to the sensory assembly;(d) a controller circuit that is operatively coupled to the power system, the communication system and the sensory unit; and(e) a housing that is configured to house the power system, the communication system, the sensory unit and the controller circuit, wherein the housing is further configured to be deployed within a well bore.

2. The DGP of claim 1, wherein the power system is configured to store and / or generate sufficient electrical power in order to operate the communication system, the sensory unit, the controller circuit and any combination thereof.

3. The DGP of claim 1 or 2, wherein the power system comprises a battery, a rechargeable battery, a turbine generator, a thermos-voltaic generator and any combination thereof.

4. The DGP of claim 1, 2 or 3, wherein the communication system is configured to distribute data from a first location where the housing is deployed in a well bore to a second location.

5. The DGP of claim 4, wherein the second location is within the well bore, at a surface of the well bore or combinations thereof.

6. The DGP of any one of claims 1 - 5, wherein the communication system is configured to communicate information by a capacitive coupling communication protocol, an electromagnetic communication protocol, a magnetic induction communication protocol and any combination thereof.

7. The DGP of any one of claim 1 - 6, wherein the communication system further comprises a node that is positionable within the well bore external to the housing and wherein the node is configured to communicate information with: a portion of the communication system housed within the housing, a further node, a data capture tool and any combination thereof.

8. The DGP of claim 7, wherein the data-capture tool comprises a receiver that is configured to wirelessly receive information from the node, wherein the receiver is deployable into the well bore by a line-deployment system (wireline, slickline, coiled tubing), by being pumped down into the well bore, by being self-propelled within the well bore and any combination thereof.

9. The DGP of any one of claims 1-8, wherein the sensory unit comprises a pressure sensor, a pressure gauge, a temperature sensor, a temperature gauge, an acoustic sensor, an accelerometer, a strain gauge, an orientation sensor, an electromagnetic positioning system, a mass flow sensor, a flow meter / sensor, a densitometer, a seismic sensor, a neutron-density log related sensor, a cobalt pip tag, a resistivity sensor, an ultrasonic sensor, a sonar sensor, a caliper, an electromagnetic sensor, a magnetic sensor, a spectroscopy-based sensor, a viscosity sensor, a salt sensor, a gamma-log related-sensor, a cement-bond log related sensor, a gas monitoring sensor and combinations thereof.

10. The DGP of any one of claims 1 - 9, wherein the housing defines an internal pressure tube configured to communicate pressure from a first location within the housing to a second location inside or outside the housing.

11. The DGP of any one of claims 1 - 10, further comprising a purge bottle.

12. The DGP of any one of claims 1 - 10, further comprising a switch that is operatively coupled to the controller circuit, wherein the switch can be activated by a patterned magnetic stimulus, a patterned acoustic stimulus and any combination thereof, wherein when the switch is activated the controller circuit will activate or shutdown.

13. A data-capture tool for communicating information with a data gathering platform (DGP), the data-capture tool comprising:(a) a power system;(b) a communication system that comprises a receiver and a transmitter, wherein the receiver is configured to receive information from the DGP and the transmitter is configured to transmit information to a further receiver; and(c) housing that is configured to house the power system and the communication system, wherein the body is deployable into a well bore by a line-deployment system (wireline, slickline, coiled tubing), by being pumped down into the well bore, by being self-propelled within the well bore and any combination thereof.

14. A system for gathering and transmitting assessment data of one or more operational parameters in or proximal a well, the system comprising:(a) one or more DGPs of claim 1 ; and(b) the data-capture tool of claim 13.

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