Methods for determining wellbore integrity

Abstract

A method for determining the integrity of a well is provided. The method includes mixing a conductive material into a fluid, introducing the fluid into the well, and allowing the conductive material to coat a surface of a subterranean formation to form a conductive data conduit coating. The method also includes transmitting data through the conductive data conduit coating to determine the integrity of the well.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. application serial number 62 / 877,036, filed on July 22, 2019, the entire disclosure of which is hereby incorporated by reference. Technical Field

[0003] Embodiments of the present disclosure generally relate to methods of determining the integrity of a well. Background Art

[0004] Cement slurries are used in the oil and gas industry, such as for cementing in oil and gas wells. For example, cement sheaths can be placed in the annulus between the wellbore casing and the subsurface formation using primary, remedial, squeeze, and plug cementing techniques for well repair, well stabilization, and downhole abandonment (sealing old wells to eliminate safety hazards). These cement slurries must be able to perform consistently over a wide range of temperatures and conditions, as cement setting in oil and gas wells can be susceptible to cyclic stresses imposed by pressure and temperature fluctuations. However, under downhole conditions, cement can break down over time, which can degrade the integrity of the wellbore and can result in unwanted fluid communication between the wellbore and the subsurface formation. Summary of the invention

[0005] Monitoring wellbore integrity determines the elasticity, strength and performance characteristics of cured cement compositions over time. However, conventional tools for determining wellbore integrity, such as logging, may only be performed periodically and require complete shutdown of the well. In addition, by connecting these sensors to the surface using conventional electrical connections, such as continuous fiber optic cables, potential fluid communication paths are provided between underground formations. The use of such conventional electrical connections interrupts the continuity of the cement jacket and may cause cement cracks or breaks. Therefore, there has always been a need for a method for determining the integrity of a well that can be performed during production operations without shutting in the well. The present embodiment addresses these needs by providing a method for determining the integrity of a well using a conductive data conduit coating.

[0006] In one embodiment, a method of determining the integrity of a well is provided, comprising mixing a conductive material into a fluid, introducing the fluid into the well, and allowing the conductive material to coat a surface of a subsurface formation to form a conductive data conduit coating. The method also includes transmitting data through the conductive data conduit coating to determine the integrity of the well.

[0007] In another embodiment, a method of determining the integrity of a well is provided, comprising mixing an insulating material into a drilling fluid, mixing a conductive material into the spacer fluid, introducing the drilling fluid into the well, and allowing the insulating material to coat a surface of a subsurface formation to form an electrically insulating layer. The method also includes introducing the spacer fluid into the well, allowing the conductive material to coat the electrically insulating layer to form a conductive data conduit coating, and transmitting data through the conductive data conduit coating to determine the integrity of the well.

[0008] The present disclosure also discloses a wellbore integrity monitoring configuration having a conductive data conduit coating disposed between a wellbore casing and a subterranean formation, a plurality of wellbore sensors, and a surface interrogator in communication with the wellbore sensors via the conductive data conduit coating. The conductive data conduit coating provides a medium for data transmission from the wellbore sensors to the surface interrogator. The wellbore sensors are disposed in the subterranean formation, the conductive data conduit coating, or in an intermediate layer between the conductive data conduit coating and the wellbore casing. The wellbore sensors are operable to measure conditions indicative of wellbore integrity and generate sensory data representative of the wellbore conditions. The surface interrogator, the wellbore sensors, and the conductive data conduit coating are collectively configured to transmit the sensory data from the wellbore sensors to the surface interrogator via the conductive data conduit coating so as to monitor the integrity of the wellbore based on the sensory data received from the wellbore sensors.

[0009] According to an embodiment of the wellbore integrity monitoring configuration, the wellbore sensor is disposed in the conductive data conduit coating. In other embodiments, the wellbore sensor is disposed in the underground formation. The intermediate layer may have a cement layer disposed between the wellbore casing and the conductive data conduit coating. In some embodiments, the wellbore sensor is disposed in the cement layer. The intermediate layer may have an electrical insulation layer disposed between the wellbore casing and the conductive data conduit coating. The wellbore sensor may be disposed in the electrical insulation layer. In other embodiments, the wellbore sensor is disposed in at least two of the conductive data conduit coating, the underground formation, and the intermediate layer. The intermediate layer may have a cement layer and an electrical insulation layer disposed between the wellbore casing and the conductive data conduit coating. In some embodiments, the intermediate layer has a cement layer and an electrical insulation layer, and the wellbore sensor is disposed in at least two of the conductive data conduit coating, the underground formation, the cement layer, and the electrical insulation layer.

[0010] Additional features and advantages of the described embodiments will be set forth in the detailed description that follows, and in part will become apparent to those skilled in the art from that description or will be recognized by practicing the embodiments as described herein, including the following detailed description, claims, and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] The following detailed description of specific embodiments of the present disclosure may be best understood when read in conjunction with the following drawings, in which like structures are represented by like reference numerals, and in which:

[0012] Figure 1 is a schematic diagram of an oil and gas platform according to one or more embodiments described in the present disclosure;

[0013] Figure 2 is a side schematic diagram of a wellbore according to one or more embodiments described in the present disclosure;

[0014] Figure 3 is a side schematic diagram of a wellbore according to one or more embodiments described in the present disclosure;

[0015] Figure 4 is a side schematic diagram of a wellbore according to one or more embodiments described in the present disclosure; and

[0016] Figure 5 is a side schematic diagram of a wellbore according to one or more embodiments described in the present disclosure. DETAILED DESCRIPTION

[0017] As used throughout this disclosure, the term "cement slurry" refers to a composition comprising a cement precursor that is mixed with at least water to form cement. The cement slurry may include calcined alumina (Al2O3), silicon dioxide (SiO2), calcium oxide (CaO, also known as lime), iron oxide (FeO), magnesium oxide (MgO), clay, sand, gravel, and mixtures thereof.

[0018] As used throughout this disclosure, the term "chemisorption" refers to chemical adsorption, where the adsorbed species is held by chemical bonds.

[0019] As used throughout this disclosure, the term "conductive fiber" refers to any substrate having an aspect ratio greater than 1 that is capable of conducting an electrical current.

[0020] As used throughout this disclosure, the term "hydrostatic pressure" refers to the pressure per unit area exerted by a column of fluid.

[0021] As used throughout this disclosure, the term "physical adsorption" refers to physical adsorption in which the electronic structure of an atom or molecule is not affected.

[0022] As used throughout this disclosure, the term "retarder" refers to a chemical agent used to increase the thickening time of a cement slurry to enable proper placement of the cement slurry within a wellbore. The need for cement retardation increases with depth due to the longer time required to complete cementing operations and the effects of increased temperatures during the cement setting process.

[0023] As used throughout this disclosure, the term "spacer fluid" is any fluid that can be used to separate one fluid from another so that the two different fluids do not interact with each other, change the composition of each other, or contaminate each other.

[0024] As used throughout this disclosure, the term "subsurface formation" refers to a body of rock that is sufficiently distinct and continuous from the surrounding rock mass that the rock mass can be divided into distinct entities. Thus, the subsurface formation is sufficiently homogeneous to form a single identifiable unit containing similar rheological properties throughout the subsurface formation, including but not limited to porosity and permeability. The subsurface formation is the basic unit of lithostratigraphy.

[0025] As used throughout this disclosure, the term "wellbore" refers to a borehole or wellbore, including an open hole or an uncased portion of a well. The borehole may refer to the inner diameter of the wellbore wall (ie, the rock face that defines the drilled hole).

[0026] Embodiments of the present disclosure are directed to cement slurries with improved elasticity and self-healing capabilities. In certain specific embodiments, embodiments of the present disclosure are also directed to methods of producing and using cement slurries for use in the oil and gas industry.

[0027] refer to Figure 1 and Figure 2 , an oil and gas platform 210 may be located above a wellbore 10 formed in an underground formation 140. The wellbore 10 may be used to connect natural resources, such as petrochemical products, to the surface platform 210. A wellbore casing 160 may be inserted into the wellbore 10. The wellbore casing 160 may be a pipe or other tubular structure having a diameter that is smaller than the diameter of the wellbore 10. Typically, the wellbore casing may be lowered into the wellbore 10 so that the bottom of the wellbore casing 160 reaches an area near the bottom of the wellbore 10.

[0028] Figure 2 and 5 exist Figure 1 Inset A is shown showing a detailed alternative embodiment of the wellbore 10. In a non-limiting example, Figure 2-5The wellbore casing 160 shown in the figure can be consolidated by inserting cement slurry into the annular area between the outer edge of the wellbore casing 160 and the edge of the wellbore 10 formed in the underground formation 140. The cement slurry will form a cement layer 110. The cement slurry can be inserted into the annular area by pumping the cement slurry into the interior of the wellbore casing 160, the bottom of the wellbore casing 160, around the bottom of the wellbore casing 160, into the annular area, or a combination of some or all of these. The cement slurry can displace the drilling fluid and push it to the top of the well. In some embodiments, by displacing and removing the drilling fluid before the cement slurry is pumped into the well, the spacer fluid can be used as a buffer between the cement slurry and the drilling fluid to prevent contact between the drilling fluid and the cement slurry. After inserting an appropriate amount of cement slurry into the interior area of ​​the wellbore casing, in some embodiments, the cement slurry can be pushed out of the interior area of ​​the wellbore casing 160 and into the annular area using a displacement fluid. This displacement can move the entire spacer fluid and drilling fluid out of the wellbore top from the annular area.

[0029] The cement slurry may then be cured or otherwise hardened to form a cement layer 110. The cement layer 110 so formed is disposed between the wellbore casing 160 and the underground formation 140. The cement layer 110 isolates the wellbore casing 160 from the underground formation 140. The conductive data conduit coating 130 is disposed between the cement layer 110 and the underground formation 140. The process of coating the underground formation 140 with the conductive data conduit coating 130 is discussed in detail later. In some embodiments, an electrically insulating layer 120 is disposed between the cement layer 110 and the conductive data conduit coating 130. Figure 2-5 In contrast, the electrically insulating layer in other embodiments of the present disclosure (not shown) is disposed between the underground formation and the conductive data conduit coating. In these embodiments, the cement layer is disposed on the conductive layer. Thus, the cement layer in these embodiments is sandwiched between the wellbore casing and the conductive data conduit coating. In some embodiments, an intermediate layer is disposed between the conductive data conduit coating and the wellbore casing 160. The intermediate layer may include the cement layer 110, the electrically insulating layer 120, or both.

[0030] A plurality of wellbore sensors 150 are disposed in the underground formation 140, the conductive data conduit coating 130, the electrical insulation layer 120, the cement layer 110, or a combination thereof. In other words, the wellbore sensors 150 may be disposed in one or more of these coatings or layers. The wellbore sensors 150 measure conditions indicative of the integrity of the wellbore 10 and generate sensor data representing the condition of the wellbore 10. Further details on the types and operation of the wellbore sensors 150 are provided subsequently. In the present disclosure, the wellbore sensors 150 are interchangeably referred to as wellbore sensors 150. The conductive data conduit coating 130 provides a medium for data transmission from the wellbore sensors 150 to the surface interrogator. The surface interrogator and its components will be discussed in detail subsequently. The surface interrogator communicates with the wellbore sensors 150 through the conductive data conduit coating 130. The surface interrogator, wellbore sensor 150 and conductive data conduit coating 130 are collectively configured for transmitting sensed data from wellbore sensor 150 to the surface interrogator via conductive data conduit coating 130 to monitor the integrity of wellbore 10 based on the sensed data received from wellbore sensor 150 .

[0031] To ensure well stability and safety, it is important that the cement layer 110 maintains integrity and isolates the wellbore 10 from the surrounding subterranean formation 140. If the cement layer 110 cracks or deteriorates under cyclic stress, wellbore integrity and isolation may be lost, resulting in undesirable fluid communication between the wellbore 10 and the surrounding subterranean formation. Without being limited by theory, such fluid communication may result in loss of drilling fluid from the wellbore 10 into the surrounding subterranean formation 140 or reduce wellbore pressure, possibly leading to a well control event. Therefore, wellbore integrity and isolation are critical to the effective production and use of the wellbore 10.

[0032] The present disclosure provides a method for determining the integrity of a well, comprising mixing a conductive material into a fluid, introducing the fluid into a wellbore 10, and allowing the conductive material to coat the surface of an underground formation 140, thereby forming a conductive data conduit coating. The method also includes transmitting data through the conductive data conduit coating to determine the integrity of the wellbore 10.

[0033] The fluid may include conductive fibers. These conductive fibers may include any substrate having an aspect ratio greater than 1 capable of conducting an electric current. Specifically, the conductive fibers may include carbon nanotubes. The conductive fibers include conductive elements. These conductive elements may include at least one of carbon, nickel, copper, gold, silver, graphene, carbon nanofibers, carbon nanosheets, or titanium. Graphene may be provided in any desired form or combination of forms, such as nanosheets, microsheets, nanofibers, nanotubes, chemically modified graphene, doped graphene, functionalized graphene, warped nanographene, or a combination of these. These conductive fibers may form a conductive mesh within the conductive data conduit coating.

[0034] The carbon nanotubes can be randomly dispersed throughout the fluid. The carbon nanotubes can be dispersed by a variety of methods, including but not limited to ultrasonic treatment, exchange of superacids with surfactants, or sacrificial templates. Dispersing the carbon nanotubes by ultrasonic treatment can include stirring the carbon nanotubes in an aqueous phase with a dispersant. The dispersant can be any of the dispersants described above. Dispersing the carbon nanotubes by a sacrificial template can include adding particles including carbon nanotubes disposed on a sacrificial template to a cement slurry, and allowing the sacrificial template to decompose, thereby dispersing the carbon nanotubes throughout the cement slurry.

[0035] The carbon nanotubes include at least one of single-walled nanotubes, double-walled nanotubes, multi-walled nanotubes, narrow-walled nanotubes, or nanotube bundles. The diameter of the carbon nanotubes may be 1 to 200 nanometers (nm), 20 to 100 nm, 10 to 80 nm, 4 to 20 nm, 2 to 12 nm, 2 to 10 nm, 2 to 9 nm, 2 to 8 nm, 2 to 7 nm, 2 to 6 nm, 2 to 5 nm, 2 to 4 nm, 2 to 3 nm, 3 to 12 nm, 3 to 10 nm, 3 to 9 nm, 3 to 8 nm, 3 to 7 nm, 3 to 6 nm, 3 to 5 nm, 3 to 4 nm, 4 to 12 nm, 4 to 10 nm, 4 to 9 ...2 nm, 4 to 10 nm, 4 to 10 nm, 4 to 10 nm, 4 to 10 nm, 4 to 12 nm, 4 to 10 nm, 4 to 10 nm, 4 to 10 nm, 4 to 12 nm, 4 to 10 nm, 4 to 10nm, 8nm, 8nm, 9nm, 10nm, 12nm, 8 ...

[0036] The carbon nanotubes may have a length of 20 to 500 micrometers (μm), 20 to 200 μm, 20 to 150 μm, 20 to 100 μm, 50 to 500 μm, 50 to 200 μm, 50 to 150 μm, 50 to 100 μm, 100 to 500 μm, 100 to 200 μm, 100 to 150 μm, 150 to 500 μm, 150 to 200 μm, or 200 to 500 μm.

[0037] The aspect ratio is the length of the substrate divided by the width or diameter. The carbon nanotubes may have an aspect ratio of 100 to 50,000, 500 to 30,000, 1,000 to 20,000, 1,000 to 100,000, 1,000 to 50,000, 1,000 to 40,000, 1,000 to 30,000, 1,000 to 25,000, 1,000 to 20,000, 1,000 to 15,000, 1,000 to 12,000, 1,000 to 10,000, 1,000 to 8,000, 8,000 to 100,000, 8,000 to 50,000. 000, 8000 to 40000, 8000 to 30000, 8000 to 25000, 8000 to 20000, 8000 to 15000, 8000 to 12000, 8000 to 10000, 10000 to 100000, 10000 to 50000, 10000 to 40000, 10000 to 30000, 10000 to 25000, 10000 to 20000, 10000 to 15000, 10000 to 12 10000, 12000 to 100000, 12000 to 50000, 12000 to 40000, 12000 to 30000, 12000 to 25000, 12000 to 20000, 12000 to 15000, 15000 to 100000, 15000 to 50000, 15000 to 40000, 15000 to 30000, 15000 to 25000, 15000 to 20000, 20000 to 10000 0, 20,000 to 50,000, 20,000 to 40,000, 20,000 to 30,000, 20,000 to 25,000, 25,000 to 100,000, 25,000 to 50,000, 25,000 to 40,000, 25,000 to 30,000, 30,000 to 100,000, 30,000 to 50,000, 30,000 to 40,000, 40,000 to 50,000, 40,000 to 100,000, or 50,000 to 100,000.

[0038] The specific surface area of ​​carbon nanotubes can be 100 to 12,000 square meters per gram (m 2 / g), 100 to 10000m 2 / g, 100 to 800m 2 / g, 100 to 700m 2 / g, 400 to 12000m 2 / g, 400 to 10000m 2 / g, 400 to 800m 2 / g, 100 to 1500m 2 / g, 120 to 1000m 2 / g, 150 to 850m 2 / g or 400 to 700m 2 / g, where the specific surface area is calculated by Brunauer-Emmett-Teller (BET) theory.

[0039] The multi-walled carbon nanotubes may include 10 weight percent (wt.%) or less, 5 wt.% or less, 3 wt.% or less, 2 wt.% or less, 1.5 wt.% or less, 1 wt.% or less, or 0.5 wt.% or less of a metal oxide; and 0.001 to 0.12 g / cm 3 , 0.01 to 0.08 g / cm 3 , 0.02 to 0.06 g / cm 3 , 0.01 to 1 cubic centimeter / gram (g / cm 3 ), 0.01 to 0.5 g / cm 3 , 0.01 to 0.2 g / cm 3 , 0.01 to 0.1 g / cm 3 , 0.01 to 0.05 g / cm 3 , 0.01 to 0.02 g / cm 3 , 0.02 to 1 g / cm 3 , 0.02 to 0.5 g / cm 3 , 0.02 to 0.2 g / cm 3 , 0.02 to 0.1 g / cm 3 , 0.02 to 0.05 g / cm 3 , 0.05 to 1 g / cm 3 , 0.05 to 0.5 g / cm 3 , 0.05 to 0.2 g / cm 3 , 0.05 to 0.1 g / cm 3 , 0.06 to 0.08 g / cm 3 , 0.1 to 1 g / cm 3 , 0.1 to 0.5 g / cm 3 , 0.1 to 0.2 g / cm 3 , 0.2 to 1 g / cm 3 , 0.2 to 0.5 g / cm 3 , or 0.5 to 1 g / cm 3 The volume density of .

[0040] As previously mentioned, carbon nanotubes are capable of conducting electrical energy. The conductivity of the carbon nanotubes may be 0.01 to 20 ohm-meters (Ω·m), 0.01 to 10 Ω·m, 0.01 to 5 Ω·m, 0.01 to 2 Ω·m, 0.01 to 1 Ω·m, 1 to 20 Ω·m, 1 to 10 Ω·m, 1 to 5 Ω·m, 1 to 2 Ω·m, 2 to 20 Ω·m, 2 to 10 Ω·m, 2 to 5 Ω·m, 5 to 20 Ω·m, 5 to 10 Ω·m, or 10 to 20 Ω·m.

[0041] The fluid may include at least one of a drilling fluid, a spacer fluid, or a cement slurry. In some embodiments, the fluid includes an aqueous solution. The cement slurry includes a cement precursor material and water. The cement precursor material may be any suitable material that can cure into cement when mixed with water. The cement precursor material may be a hydraulic or non-hard hydraulic cement precursor. A hydraulic cement precursor material refers to a mixture of limestone, clay, and gypsum that burns together at extreme temperatures, which can harden immediately or within a few minutes when in contact with water. A non-hydraulic cement precursor material refers to a mixture of lime, gypsum, plaster, and oxychloride. Non-hydraulic cement precursors may require a longer time to harden, or may require dry conditions for proper reinforcement. A hydraulic or non-hydraulic cement precursor material may be selected based on the desired application of the cement slurry disclosed herein. In some embodiments, the cement precursor material may be a Portland cement precursor, such as Class G Portland cement. Portland cement precursor is a hydraulic cement precursor (a cement precursor material that not only hardens by reacting with water but also forms a water-resistant product) produced by grinding clinker, and contains one or more forms of hydraulic calcium silicate and calcium sulfate as an additive during grinding.

[0042] The cement precursor material may include one or more of the following: calcium hydroxide, silicates, oxides, belite (Ca2SiO5), tricalcium silicate (Ca3SiO4), tricalcium aluminate (Ca3Al2O6), tetracalcium aluminoferrite (Ca4Al2Fe2O 10), calcium aluminoaluminate ore (4CaO·Al2O3·Fe2O3), gypsum (CaSO4·2H2O), sodium oxide, potassium oxide, limestone, lime (calcium oxide), hexavalent chromium, trivalent chromium, calcium aluminate, silica sand, silica powder, hematite, manganese tetroxide, other similar compounds and combinations thereof. The cement precursor material may include portland cement, siliceous fly ash, calcium fly ash, slag cement, silica fume, quartz, any known cement precursor material or any combination thereof. Silica powder is finely ground crystalline silicon dioxide with a molecular formula of SiO2 and a particle size range of 1 to 500 microns, 10 to 500 microns, 10 to 100 microns, 10 to 80 microns, 10 to 50 microns, 10 to 20 microns, 20 to 100 microns, 20 to 80 microns, 20 to 50 microns, 50 to 100 microns, 50 to 80 microns or 80 to 100 microns.

[0043] Water can be added to the cement precursor material to produce a slurry. The water can be distilled water, deionized water or non-distilled water. In some embodiments, the water can contain additives or contaminants. For example, the water can contain fresh water or seawater, natural brine or synthetic brine or salt water. In some embodiments, salt or other organic compounds can be incorporated into the water to control certain properties of the water, and thereby control certain properties of the cement slurry, such as density. Without being bound by any particular theory, increasing the saturation of water by increasing the level of salt concentration or other organic compounds in the water can increase the density of the water, and thus increase the density of the cement slurry. Suitable salts can include but are not limited to alkali metal chlorides, hydroxides or carboxylates. In some embodiments, suitable salts can include sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, fluorides and combinations thereof.

[0044] In some embodiments, the cement paste may contain 10 wt.% to 70 wt.% water, based on the weight of the cement precursor (BWOC). In some embodiments, the BWOC, the cement paste may contain 10 wt.% to 40 wt.%, 10 wt.% to 30 wt.%, 10 wt.% to 20 wt.%, 20 wt.% to 40 wt.%, 25 wt.% to 35 wt.%, or 20 wt.% to 30 wt.% water. The BWOC, the cement paste may contain 30 wt.% water.

[0045] The density of the cement slurry may be 10 to 20 pounds per gallon (ppg), 10 to 17 ppg, 10 to 16 ppg, 10 to 15 ppg, 12 to 20 ppg, 12 to 17 ppg, 12 to 16 ppg, 12 to 15 ppg, 14 to 20 ppg, 14 to 17 ppg, 14 to 16 ppg, 14 to 15 ppg, 15 to 20 ppg, 15 to 17 ppg, 15 to 16 ppg, or 15 ppg.

[0046] In some embodiments, the cement slurry may contain one or more additives. The one or more additives may be any additive known to be suitable for use in cement slurries. As non-limiting examples, suitable additives may include accelerators, retarders, extenders, suspending agents, weighting agents, fluid loss control agents, circulating fluid leakage control agents, surfactants, defoamers, and combinations thereof.

[0047] In some embodiments, the cement slurry may contain 0.1% to 10% (BWOC) of one or more additives, based on the total weight of the cement slurry. For example, the cement slurry may contain 0.1% to 8% (BWOC) of one or more additives, 0.1% to 5% (BWOC) of one or more additives, or 0.1% to 3% (BWOC) of one or more additives. The cement slurry may contain 1% to 10% (BWOC) of one or more additives, 1% to 8% (BWOC), 1% to 5% (BWOC), or 1% to 3% (BWOC) of one or more additives. In some embodiments, the cement slurry may contain 3% to 5% (BWOC), 3% to 8% (BWOC), 3% to 10% (BWOC), or 5% to 10% (BWOC) of one or more additives.

[0048] As previously mentioned, the fluid may include drilling fluid. The drilling fluid may include an aqueous phase. The aqueous phase may include at least one of the following: fresh water, salt water, brine, city water, formation water, produced water, well water, filtered water, distilled water, seawater, or a combination of these. The brine may include at least one of natural brine and synthetic brine, such as saturated brine or formate brine. The aqueous phase may use water containing organic compounds or salts. Without being bound by any particular theory, salt or other organic compounds may be incorporated into the aqueous phase to control the density of the drilling fluid. Increasing the saturation of the aqueous phase by increasing the salt concentration or the level of other organic compounds in the aqueous phase may increase the density of the drilling fluid. Suitable salts include, but are not limited to, alkali chlorides, hydroxides, or carboxylates. In some embodiments, suitable salts may include sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, fluorides, and combinations of these. In some specific embodiments, brine may be used in the aqueous phase. Without being bound by any particular theory, brine may be used to create an osmotic equilibrium between the drilling fluid and the subterranean formation 140 .

[0049] In some embodiments, the drilling fluid may contain 10 weight percent (wt.%) to 70 wt.% of an aqueous phase, based on the total weight of the drilling fluid. In some embodiments, the drilling fluid may contain 28 pounds per barrel (lb / bbl) to 630 lb / bbl, such as 30 to 600 lb / bbl, 50 to 500 lb / bbl, 100 to 500 lb / bbl, 200 to 500 lbs / bbl, or 300 to 600 lb / bbl of an aqueous phase.

[0050] The drilling fluid can be non-aqueous. In certain embodiments, the drilling fluid can include an oil phase, which can include natural or synthetic liquid oils. Specifically, the drilling fluid can include diesel, mineral oil, hydrogenated or unhydrogenated olefins such as polyalphaolefins, straight and branched olefins, polydiorganosiloxanes, siloxanes, organosiloxanes, fatty acid esters, straight, branched or cycloalkyl ethers of fatty acids, esters, ethers, acetals, dialkyl carbonates, hydrocarbons or any combination of these. In certain embodiments, the drilling fluid can include oil derived from petroleum, such as mineral oil, diesel, linear olefins, paraffin, other petroleum-based oils and combinations of these oils, or oil derived from plants, such as safflower oil.

[0051] By the gross weight of drilling fluid, drilling fluid can contain 10wt.% to 90wt.% oil phase. By the gross weight of drilling fluid, drilling fluid can contain 28lb / bbl to 810lb / bbl oil phase, such as 30 to 800lb / bbl, 50 to 800lb / bbl, 75 to 800lb / bbl or 100 to 800lb / bbl. In certain embodiments, drilling fluid can contain 200 to 800lb / bbl or 300 to 600lb / bbl or 500 to 810lb / bbl oil phase.

[0052] The drilling fluid may include a polar aprotic solvent. In some embodiments, the polar aprotic solvent may replace the aqueous phase of the drilling fluid. The polar aprotic solvent lacks acidic hydrogens and is therefore not a hydrogen bond donor, which means that it cannot provide hydrogen. The polar aprotic solvent can dissolve salts and can accept hydrogen bonds. The polar aprotic solvent may have a dielectric constant or relative permittivity greater than 10, 15, 20, 25, 30, 35, or 40. The polar aprotic solvent may also have a relative permittivity greater than 1 Debye (1 Debye = 1×10 -18 The polar aprotic solvent may include at least one of n-alkylpyrrolidone, dimethylformamide, dimethyl sulfonate, acetonitrile, dimethylformamide, hexamethylphosphoramide or dimethyl sulfoxide.

[0053] The drilling fluid may include at least one surfactant. The surfactant may keep the carbon nanotubes dispersed in the drilling fluid. The surfactant may be anionic, cationic or neutral. Non-limiting examples of anionic surfactants include sulfonated polymers, sulfonated alkanes, polycarboxylate ethers, or combinations thereof. Non-limiting examples of cationic surfactants include trimethyl alkyl ammonium salts, alkyl benzyl ammonium salts, or combinations thereof. Non-limiting examples of neutral surfactants include proteins, polyethylene glycol derivatives, oligosaccharides, cholesterol derivatives, or combinations thereof. The surfactant may include at least one of sulfonated polymers, sulfonated alkanes, polycarboxylated ethers, trimethyl alkyl ammonium salts, alkyl benzyl ammonium salts, proteins, polyethylene glycol derivatives, oligosaccharides, or cholesterol derivatives. Based on the total weight of the drilling fluid, the drilling fluid may contain 0.01 wt.% to 20 wt.% of a surfactant. Based on the total weight of the drilling fluid, the drilling fluid may contain 0.02 lb / bbl to 180 lb / bbl of a surfactant, such as 0.02 to 150 lb / bbl or 0.05 to 150 lb / bbl. In some embodiments, the drilling fluid may contain 0.1 to 150 lb / bbl, or 0.1 to 100 lb / bbl, or 1 to 100 lb / bbl of a surfactant.

[0054] In some embodiments, the drilling fluid may contain at least one additive other than a surfactant. The one or more additives may be any additive known to be suitable for use in drilling fluids. As non-limiting examples, suitable additives may include fluid loss control agents, circulating fluid loss control agents, filtration control additives, defoamers, emulsifiers, weighting agents, fluid loss additives, alkali reserves, special additives, and combinations thereof.

[0055] In certain embodiments, one or more additives may include other tackifiers (also referred to as rheology modifiers), which may be added to the drilling fluid so that the drilling fluid has a non-Newtonian rheology, so that cuttings are lifted and transported to the wellbore surface. The example of tackifier may include but is not limited to bentonite, polyacrylamide, polyanionic cellulose or a combination of these tackifiers. In certain embodiments, the drilling fluid may include xanthan gum, a polysaccharide commonly referred to as XC polymers. XC polymers may be added to the drilling fluid based on water, to produce a flat velocity profile of the drilling fluid based on water in the annular flow, which may help improve the efficiency of the drilling fluid in lifting and transporting cuttings to the ground.

[0056] In some embodiments, the drilling fluid may contain 0.01 wt.% to 20 wt.% of one or more additives, based on the total weight of the drilling fluid. The drilling fluid may contain 0.02 lb / bbl to 180 lb / bbl of one or more additives, such as 0.02 to 150 lb / bbl or 0.05 to 150 lb / bbl, based on the total weight of the drilling fluid. In some embodiments, the drilling fluid may contain 0.1 to 150 lb / bbl or 0.1 to 100 lb / bbl or 1 to 100 lb / bbl of one or more additives.

[0057] In another embodiment, the method includes mixing an insulating material into a drilling fluid, mixing a conductive material into the spacer fluid, introducing the drilling fluid into the well, and allowing the insulating material to coat the surface of the subsurface formation to form an electrically insulating layer. The method also includes introducing the spacer fluid into the well, allowing the conductive material to coat the electrically insulating layer to form a conductive data conduit coating, and transmitting data through the conductive data conduit coating to determine the integrity of the well.

[0058] The insulating material may include silica. In some embodiments, the insulating material includes colloidal silica. The insulating material may be amine functionalized. This means that the insulating material may include amine functionalized silica or amine functionalized colloidal silica or both.

[0059] The method may further include cementing the wellbore after allowing the conductive material to coat the electrically insulating layer. The electrically insulating layer may have a relative static dielectric constant of 2 to 25.

[0060] The layering of the conductive data conduit coating or the electrically insulating layer onto the surface of the subterranean formation may be accomplished by physical adsorption or chemical adsorption onto the surface of the subterranean formation. In some embodiments, the conductive data conduit coating may be adsorbed onto the electrically insulating layer to form a conductive second layer. In some embodiments, a drilling fluid including dispersed conductive fibers is used to drill the wellbore. The hydrostatic pressure of such drilling fluid may be sufficiently great to allow a filter cake to form on the surface of the subterranean formation surrounding the wellbore. In such embodiments, the layering of the conductive data conduit coating or the electrically insulating layer onto the surface of the subterranean formation may be accomplished by physical adsorption or chemical adsorption onto the filter cake.

[0061] In some applications, the method includes conducting current from a power source through a conductive data conduit coating to sensors embedded throughout the wellbore, and then conducting current from the sensors through the conductive data conduit coating to a computing device. Such a conductive data conduit coating allows information transmission or telemetry throughout the wellbore.

[0062] Reference now Figures 2 to 5 , which shows Figure 1 Detailed alternative embodiment of the wellbore 10 at inset A, a plurality of wellbore sensors 150 for monitoring wellbore integrity in real time, intermittently, or both, may be disposed in any of the coatings discussed above. Figure 1 An embodiment of a wellbore integrity monitoring arrangement 100 is shown. The wellbore integrity monitoring arrangement 100 has a conductive data conduit coating 130 disposed between a wellbore casing 160 and a subterranean formation 140, a plurality of wellbore sensors 150, and a surface interrogator that communicates with the wellbore sensors 150 via the conductive data conduit coating 130. The conductive data conduit coating 130 provides a medium for data transmission from the wellbore sensors 150 to the surface interrogator. The wellbore sensors 150 are disposed in the subterranean formation 140, the conductive data conduit coating 130, or in an intermediate layer between the conductive data conduit coating 130 and the wellbore casing 160. The wellbore sensors 150 are operable to measure conditions indicative of the integrity of the wellbore 10 and generate sensory data representative of the conditions of the wellbore 10. The surface interrogator, wellbore sensor 150 and conductive data conduit coating 130 are collectively configured for transmitting sensed data from wellbore sensor 150 to the surface interrogator via conductive data conduit coating 130 to monitor the integrity of wellbore 10 based on the sensed data received from wellbore sensor 150 .

[0063] Wellbore sensors 150 may be embedded at various locations throughout the wellbore. Figure 2 , these wellbore sensors 150 can be disposed throughout the conductive data conduit coating 130. In another embodiment, as Figure 3 As shown, wellbore sensors 150 may be disposed throughout the electrically insulating layer 120 . Figure 4It is shown that wellbore sensors 150 may be disposed throughout the subsurface formation 140. Figure 5 , the wellbore sensor 150 may be disposed throughout the cement layer 110. Again, referring to Figures 2 to 5 In the illustrated embodiment, these wellbore sensors 150 may help propagate data along the wellbore 10 toward the surface.

[0064] In some embodiments, wellbore sensors 150 may be disposed in more than one coating. These wellbore sensors 150 measure and transmit information related to downhole parameters and conditions. Wellbore sensors 150 may include pressure sensors, temperature sensors, piezoelectric acoustic sensors, flow meters for determining flow rate, accelerometers, resistivity sensors for determining water content, velocity sensors, weight sensors, or any other type of sensor that measures downhole fluid properties or physical parameters. Wellbore sensors 150 may be used to create an electromagnetic profile of the wellbore by measuring changes in the electromagnetic properties of the wellbore, such as impedance, resistance, inductance, or capacitance.

[0065] The wellbore sensor 150 may be battery powered, either directly inductively powered or inductively powered via a rechargeable battery. Some wellbore sensors 150 may only send signals related to the collected data, while other wellbore sensors may be operable to send and receive signals. Some wellbore sensors 150 are capable of communicating with surface equipment and other sensors. The wellbore sensor 150 may have a receiver / transmitter for transmitting data and receiving instructions between the wellbore sensor 150 and the surface or between the wellbore sensor 150 and another downhole system. The wellbore sensor 150 may have an associated microprocessor to allow processing and interpretation of data and to process received instructions. Likewise, the wellbore sensor 150 may be coupled to a storage device that provides for storing information for later batch processing or batch transmission.

[0066] In some embodiments, transmitting data through the conductive data conduit coating also includes transmitting the data to the surface of the well. The data can then be interpreted to determine the integrity of the wellbore. This may include the location of any fractures that may cause unwanted fluid communication between the wellbore and the underground formation, or the location of weak points that have developed within the wellbore over time.

[0067] Reference again Figure 1In some embodiments, the conductive data conduit coating 130 can be connected to a surface interrogator including a receiver / transmitter (X / R) 220, a power source (P) 230, a data storage (D) 240, and a microprocessor (MP) 250. The wellbore sensor 150 can communicate with the surface interrogator via the conductive data conduit coating 130. Suitable frequencies, frequency band ranges with a signal-to-noise ratio greater than 2 can be used to reflect local conditions to maximize transmission distance and signal strength. Some wellbore sensors 150 can be operated inductively for one-way / two-way communication or powered wirelessly. The wellbore sensor 150 can communicate with or be powered by the surface interrogator via the conductive data conduit coating 130 using other suitable methods and techniques. In one embodiment, the wellbore sensor 150 and the surface interrogator can communicate using a wireless downhole electromagnetic data transmission system (not shown). The method can also utilize microprocessor-based controlled frequency synthesis to achieve two-way communication between the surface interrogator and the wellbore sensor 150. The conductive data conduit coating 130 can become a conductor on which the sensor data collected by the wellbore sensor 150 is encoded in a digital format. Frequency shift keying of electromagnetic energy waves may be used to apply the sensor data to the conductive data conduit coating 130. The sensor data may be analyzed by the surface interrogator in a variety of ways, the details of which are beyond the scope of this disclosure but include, for example, data processing, filtering, demodulation, storage, and display at the surface.

[0068] In one embodiment, the conductive data conduit coating 130 serves as a communication channel using, for example, orthogonal frequency division multiplexing (OFDM) coupled with wideband frequency division multiple access (W-CDMA). The system can be adapted to varying channel conditions and can accommodate multiple downhole sensors 150 .

[0069] In some embodiments, prior to forming an intermediate layer, which may include a cement layer 110, an electrically insulating layer 120, or both, a wellbore casing 160 will be positioned in the wellbore 10 with a gap between the wellbore casing 160 and the subterranean formation 140, or other layers are formed on the subterranean formation 140. A wellbore casing centralizer may be disposed in the gap to properly position the wellbore casing 160 in the wellbore 10 and provide a continuous 360 degree annular space around the wellbore casing 160. The annular space allows the cement forming the cement layer 110 to completely seal the wellbore casing 160 within the wellbore 10. Although the concepts of the present disclosure are not limited to a particular type of wellbore casing centralizer, and contemplate the use of conventional or yet to be developed centralizers, it should be noted that there are generally two different types of centralizers - a bow spring design and a rigid blade design. Regardless of the type of wellbore casing centralizer used, the present disclosure contemplates securing the wellbore sensor 150 to the wellbore casing centralizer or integrating the wellbore sensor 150 into the structure of the wellbore casing centralizer.

[0070] It should be noted that one or more of the following claims utilize the term "where" or "in which" as a transitional phrase. For purposes of defining the present technology, it should be noted that this term is introduced in the claims as an open transitional phrase used to introduce a statement of a series of features of the structure, and should be interpreted in the same manner as the more commonly used open-ended introductory term "comprising". For purposes of defining the present technology, the transitional phrase "consisting of..." may be introduced in the claims as a closed introductory term that limits the scope of the claim to the stated components or steps and any naturally occurring impurities. For purposes of defining the present technology, the transitional phrase "consisting essentially of..." may be introduced in the claims to limit the scope of one or more claim items to the stated elements, components, materials, or method steps and any non-stated elements, components, materials, or method steps that do not materially affect the characteristics of the claimed subject matter. The transitional phrases "consisting of" and "consisting essentially of" may be interpreted as subsets of open transitional phrases such as "comprising" and "including"), such that any statement using an open phrase to introduce a list of elements, components, materials, or steps should be interpreted as also using the closed terms "consisting of" and "consisting essentially of" to disclose the list of elements, components, materials, or steps. For example, a statement that a composition "comprising" components A, B, and C should be interpreted as also disclosing a composition "consisting of components A, B, and C" as well as a composition "consisting essentially of components A, B, and C." Any quantitative value expressed in this application may be considered to include open embodiments consistent with the transitional phrases "comprising" or "including" as well as closed or partially closed embodiments consistent with the transitional phrases "consisting of" and "consisting essentially of."

[0071] As used in the specification and the appended claims, the singular forms "a", "an", and "the" include plural references unless the context clearly indicates otherwise. The verb "comprise" and its conjugated forms should be interpreted as referring to elements, components, or steps in a non-exclusive manner. The referenced elements, components, or steps may exist, be utilized, or be combined with other elements, components, or steps that are not explicitly referenced. It should be understood that any two quantitative values ​​assigned to a certain characteristic may constitute a range for the characteristic, and all combinations of ranges formed by all the quantitative values ​​for a given characteristic are considered in the present disclosure.

[0072] The subject matter of the present disclosure has been described in detail and by reference to specific embodiments. It should be understood that any detailed description of a component or feature of an embodiment does not necessarily imply that the component or feature is essential to that particular embodiment or any other embodiment. In addition, it will be apparent to those skilled in the art that various modifications and variations may be made to the described embodiments without departing from the spirit and scope of the claimed subject matter.

[0073] The presently described subject matter may include one or more aspects, which should not be considered as limiting the teachings of the present disclosure. A first aspect may include a method of determining the integrity of a well, comprising: mixing a conductive material into a fluid; introducing the fluid into the well; allowing the conductive material to coat a surface of a subsurface formation, thereby forming a conductive data conduit coating; and transmitting data through the conductive data conduit coating to determine the integrity of the well.

[0074] A second aspect may include a method for determining the integrity of a well, comprising: mixing an insulating material into a drilling fluid, wherein the insulating material comprises silica, colloidal silica, amine-functionalized silica, amine-functionalized colloidal silica, or a combination thereof; mixing a conductive material into an isolation fluid, wherein the conductive material comprises carbon nanotubes selected from single-walled nanotubes, double-walled nanotubes, multi-walled carbon nanotubes, narrow-walled nanotubes, or a combination thereof; introducing the drilling fluid into the well; allowing the insulating material to coat the surface of the underground formation to form an electrical insulating layer; introducing the isolation fluid into the well; allowing the conductive material to coat the electrical insulating layer to form a conductive data conduit coating; introducing cement slurry into the well; cementing the well; and transmitting data to the surface of the well through the conductive data conduit coating to determine the integrity of the well.

[0075] A third aspect may include a wellbore integrity monitoring configuration, which includes a conductive data conduit coating disposed between a wellbore casing and an underground formation, a plurality of wellbore sensors, and a surface interrogator that communicates with the wellbore sensors via the conductive data conduit coating, wherein: the conductive data conduit coating provides a medium for data transmission from the wellbore sensors to the surface interrogator; the wellbore sensors are disposed in the underground formation, the conductive data conduit coating, or in an intermediate layer between the conductive data conduit coating and the wellbore casing; the wellbore sensors are operable to measure conditions indicative of wellbore integrity and generate sensory data representative of the wellbore conditions; and the surface interrogator, the wellbore sensors, and the conductive data conduit coating are collectively configured to transmit the sensory data from the wellbore sensors to the surface interrogator via the conductive data conduit coating so as to monitor the integrity of the wellbore based on the sensory data received from the wellbore sensors.

[0076] Another aspect may include any of the preceding aspects, wherein transmitting data through the conductive data conduit coating further comprises transmitting the data to a surface of the well.

[0077] Another aspect may include any of the preceding aspects, wherein the fluid comprises an aqueous solution.

[0078] Another aspect may include any of the preceding aspects, wherein the fluid comprises at least one of a drilling fluid, a spacer fluid, or a cement slurry.

[0079] Another aspect may include any of the preceding aspects, wherein the conductive material comprises at least one of carbon fibers, carbon nanofibers, carbon nanotubes, carbon nanosheets, or graphene.

[0080] Another aspect may include any of the preceding aspects, wherein the conductive material comprises carbon nanotubes selected from single-wall nanotubes, double-wall nanotubes, multi-wall carbon nanotubes, narrow-wall nanotubes, or combinations thereof.

[0081] Another aspect may include any of the foregoing aspects, further comprising cementing the well after allowing the conductive material to coat the surface of the subterranean formation.

[0082] Another aspect may include any of the foregoing aspects, and also includes: mixing insulating material into drilling fluid; introducing drilling fluid into the well; allowing the insulating material to coat the surface of the underground formation to form an electrical insulation layer; introducing fluid into the well, wherein the fluid includes an isolation fluid; allowing a conductive material to coat the electrical insulation layer to form a conductive data conduit coating; transmitting data through the conductive data conduit coating to determine the integrity of the well.

[0083] Another aspect may include any of the preceding aspects, further comprising cementing the well after allowing the conductive material to coat the electrically insulating layer.

[0084] Another aspect may include any of the preceding aspects, wherein the insulating material comprises silica, colloidal silica, amine functionalized silica, amine functionalized colloidal silica, or a combination thereof.

[0085] Another aspect may include any of the preceding aspects, wherein the electrically insulating layer may have a relative static dielectric constant of 2 to 25.

[0086] Another aspect may include any of the preceding aspects, wherein the drilling fluid comprises at least one of a natural oil, a synthetic oil, a diesel oil, a mineral oil, a hydrogenated olefin, and an unhydrogenated olefin.

[0087] Another aspect may include any of the foregoing aspects, wherein the drilling fluid comprises at least one of an accelerator, a retarder, an extender, a weighting agent, a fluid loss control agent, a circulating fluid leakage control agent, a surfactant, and a defoaming agent.

[0088] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in the conductive data conduit coating.

[0089] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in a subterranean formation.

[0090] Another aspect may include any of the preceding aspects, wherein: the intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in the cement layer.

[0091] Another aspect may include any of the preceding aspects, wherein: the intermediate layer comprises an electrically insulating layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in the electrically insulating layer.

[0092] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in at least two of the conductive data conduit coating, the subsurface formation, and the intermediate layer.

[0093] Another aspect may include any of the foregoing aspects, wherein: the intermediate layer includes a cement layer and an electrical insulation layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in at least two of the conductive data conduit coating, the underground formation, the cement layer, and the electrical insulation layer.

[0094] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in the conductive data conduit coating.

[0095] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in a subterranean formation.

[0096] Another aspect may include any of the preceding aspects, wherein: the intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in the cement layer.

[0097] Another aspect may include any of the preceding aspects, wherein: the intermediate layer comprises an electrically insulating layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in the electrically insulating layer.

[0098] Another aspect may include any of the preceding aspects, wherein the wellbore sensor is disposed in at least two of the conductive data conduit coating, the subsurface formation, and the intermediate layer.

[0099] Another aspect may include any of the foregoing aspects, wherein: the intermediate layer includes a cement layer and an electrical insulation layer disposed between the wellbore casing and the conductive data conduit coating; and the wellbore sensor is disposed in at least two of the conductive data conduit coating, the underground formation, the cement layer, and the electrical insulation layer.

[0100] Another aspect may include any of the preceding aspects, wherein the wellbore sensor comprises a pressure sensor, a temperature sensor, a piezoelectric acoustic sensor, a flow meter for determining flow rate, an accelerometer, a resistivity sensor for determining water cut, a velocity sensor, a weight sensor, or a combination thereof.

[0101] Another aspect may include any of the preceding aspects, wherein the conductive data conduit coating comprises carbon fibers, carbon nanofibers, carbon nanotubes, carbon nanosheets, graphene, or a combination thereof.

[0102] Another aspect may include any of the preceding aspects, wherein the conductive data conduit coating includes conductive fibers.

[0103] Another aspect may include any of the preceding aspects, wherein the conductive data conduit coating has a conductivity in a range from about 0.01 ohm-meter (Ωm) to about 20 Ωm.

[0104] Another aspect may include any of the preceding aspects, wherein the conductive data conduit coating has a conductivity in a range from about 0.01 Ωm to about 1 Ωm.

[0105] Another aspect may include any of the preceding aspects, wherein: the intermediate layer disposed between the conductive data conduit coating and the wellbore casing comprises a wellbore casing centralizer; and the wellbore sensor is secured to or integrated with the wellbore casing centralizer.

[0106] The subject matter of the present disclosure has been described in detail and with reference to specific embodiments in any of these embodiments, it should be noted that the various details disclosed herein should not be considered to imply that these details relate to elements of the essential components of the various embodiments described herein, even if specific elements are shown in each of the figures attached to this specification. Further, it is apparent that modifications and changes can be made without departing from the scope of the present disclosure, including but not limited to the embodiments defined in the appended claims. More specifically, although some aspects of the present disclosure are identified as particularly advantageous, it is contemplated that the present disclosure is not necessarily limited to these aspects.

Claims

1. A method of determining the integrity of a well, comprising: Mixing insulating materials into drilling fluid; introducing the drilling fluid into the well; allowing the insulating material to coat the surface of the underground formation to form an electrically insulating layer; mixing a conductive material into a fluid, the fluid comprising a spacer fluid, a cement slurry, or both; introducing the fluid into the well; allowing the conductive material to coat a surface of a subterranean formation, thereby forming a conductive data conduit coating; and Data is transmitted through the conductive data conduit coating to determine the integrity of the well, the data being collected by a plurality of wellbore sensors disposed in the well. 2 . The method of claim 1 , wherein transmitting data through the conductive data conduit coating further comprises transmitting data to a surface of the well.

3. The method according to claim 1, wherein: The conductive material comprises at least one of carbon fiber, carbon nanofiber, carbon nanotube, carbon nanosheet or graphene; and The carbon nanotubes are selected from single-walled nanotubes, double-walled nanotubes, multi-walled carbon nanotubes, narrow-walled nanotubes or a combination thereof.

4. The method of claim 1, further comprising cementing the well after allowing the conductive material to coat the surface of the subterranean formation. The method of claim 1 , wherein the fluid mixed with the conductive material comprises a spacer fluid.

6. The method of claim 5, further comprising cementing the well after allowing the conductive material to coat the electrically insulating layer.

7. The method of claim 1, wherein the insulating material comprises silicon dioxide, colloidal silicon dioxide, amine-functionalized silicon dioxide, amine-functionalized colloidal silicon dioxide, or a combination thereof. The method according to claim 1 , wherein the electrically insulating layer has a relative static dielectric constant of 2 to 25.

9. The method of claim 1, wherein the drilling fluid comprises at least one of natural oil, synthetic oil, diesel, mineral oil, hydrogenated olefins, and unhydrogenated olefins.

10. A method of determining the integrity of a well, comprising: mixing an insulating material into the drilling fluid, wherein the insulating material comprises silica, colloidal silica, amine-functionalized silica, amine-functionalized colloidal silica, or a combination thereof; mixing a conductive material into the spacer fluid, wherein the conductive material comprises carbon nanotubes selected from single-walled nanotubes, double-walled nanotubes, multi-walled carbon nanotubes, narrow-walled nanotubes, or combinations thereof; introducing the drilling fluid into the well; allowing the insulating material to coat the surface of the underground formation to form an electrically insulating layer; introducing the spacer fluid into the well; allowing the electrically conductive material to coat the electrically insulating layer to form an electrically conductive data conduit coating; introducing a cement slurry into the well; cementing the well; and Data collected by a plurality of wellbore sensors disposed in the well is transmitted through the conductive data conduit coating to the surface of the well to determine the integrity of the well.

11. A wellbore integrity monitoring system comprising: An electrical insulating layer disposed between a subsurface formation and a wellbore casing; an electrically conductive data conduit coating disposed between the wellbore casing and the electrically insulating layer; multiple wellbore sensors; as well as a surface interrogator in communication with said wellbore sensor through said conductive data conduit coating, wherein: The conductive data conduit coating provides a medium for data transmission from the wellbore sensor to the surface interrogator; The wellbore sensor is disposed in the underground formation, the conductive data conduit coating, or an intermediate layer between the conductive data conduit coating and the wellbore casing; The wellbore sensor is operable to measure a condition indicative of the wellbore integrity and to generate sensor data representative of the wellbore condition; and The surface interrogator, the wellbore sensor, and the conductive data conduit coating are collectively configured for transmitting sensed data from the wellbore sensor to the surface interrogator via the conductive data conduit coating to monitor the integrity of the wellbore based on the sensed data received from the wellbore sensor.

12. The wellbore integrity monitoring system of claim 11, wherein the wellbore sensor is disposed in the conductive data conduit coating.

13. The wellbore integrity monitoring system of claim 11, wherein the wellbore sensor is disposed in the subterranean formation.

14. The wellbore integrity monitoring system of claim 11, wherein: The intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and The wellbore sensor is disposed in the cement layer.

15. The wellbore integrity monitoring system of claim 11, wherein the wellbore sensor is disposed in the electrical insulation layer.

16. The wellbore integrity monitoring system of claim 11, wherein: The intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and The wellbore sensor is disposed in at least two of the conductive data conduit coating, the subterranean formation, the cement layer, and the electrically insulating layer.

17. The wellbore integrity monitoring system of claim 11, wherein the wellbore sensor comprises a pressure sensor, a temperature sensor, a piezoelectric acoustic sensor, a flow meter for determining flow rate, an accelerometer, a resistivity sensor for determining water cut, a velocity sensor, a weight sensor, or a combination thereof.

18. The wellbore integrity monitoring system of claim 11, wherein the conductive data conduit coating comprises carbon fibers, carbon nanofibers, carbon nanotubes, carbon nanosheets, graphene, or a combination thereof.

19. The wellbore integrity monitoring system of claim 11, wherein the conductive data conduit coating comprises conductive fibers, the conductive data conduit coating having an electrical conductivity ranging from 0.01 ohm-meter (Ωm) to 20 Ωm.

20. The wellbore integrity monitoring system of claim 11, wherein: The intermediate layer disposed between the conductive data conduit coating and the wellbore casing comprises a wellbore casing centralizer; and The wellbore casing is fixed on the wellbore casing centralizer or integrated with the wellbore casing centralizer.

21. A wellbore integrity monitoring system comprising: An electrical insulating layer disposed between a subsurface formation and a wellbore casing; an electrically conductive data conduit coating disposed between the wellbore casing and the electrically insulating layer; multiple wellbore sensors; as well as a surface interrogator in communication with said wellbore sensor through said conductive data conduit coating, wherein: wherein the wellbore sensor comprises a pressure sensor, a temperature sensor, a piezoelectric acoustic sensor, a flow meter for determining flow velocity, an accelerometer, a resistivity sensor for determining water content, a velocity sensor, a weight sensor, or a combination thereof; The conductive data conduit coating provides a medium for data transmission from the wellbore sensor to the surface interrogator; The conductive data conduit coating comprises carbon fibers, carbon nanofibers, carbon nanotubes, carbon nanosheets, graphene, or a combination thereof; The conductive data conduit coating has an electrical conductivity ranging from 0.01 ohm-meter (Ωm) to 20 Ωm; The wellbore sensor is disposed in the underground formation, the conductive data conduit coating, or an intermediate layer between the conductive data conduit coating and the wellbore casing; The wellbore sensor is operable to measure a condition indicative of the wellbore integrity and to generate sensor data representative of the wellbore condition; and The surface interrogator, the wellbore sensor, and the conductive data conduit coating are collectively configured for transmitting sensed data from the wellbore sensor to the surface interrogator via the conductive data conduit coating to monitor the integrity of the wellbore based on the sensed data received from the wellbore sensor.

22. The wellbore integrity monitoring system of claim 21, wherein the wellbore sensor is disposed in the conductive data conduit coating.

23. The wellbore integrity monitoring system of claim 21, wherein the wellbore sensor is disposed in the subterranean formation.

24. The wellbore integrity monitoring system of claim 21, wherein: The intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and The wellbore sensor is disposed in the cement layer.

25. The wellbore integrity monitoring system of claim 21, wherein the wellbore sensor is disposed in the electrical insulation layer.

26. The wellbore integrity monitoring system of claim 21, wherein: The intermediate layer comprises a cement layer disposed between the wellbore casing and the conductive data conduit coating; and The wellbore sensor is disposed in at least two of the conductive data conduit coating, the subterranean formation, the cement layer, and the electrically insulating layer.

27. The wellbore integrity monitoring system of claim 21, wherein the conductive data conduit coating comprises conductive fibers.

28. The wellbore integrity monitoring system of claim 21, wherein: The intermediate layer disposed between the conductive data conduit coating and the wellbore casing comprises a wellbore casing centralizer; and The wellbore sensor is fixed on the wellbore casing centralizer or integrated with the wellbore casing centralizer.

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