INSULATING OR MODIFIED CONDUCTIVITY CASING IN CASING STRING

Abstract

A casing string in a wellbore has conductive tubulars and modified conductivity (MC) or non-conductive tubulars joined to one another. A MC/non-conductive tubular may be disposed between two conductive tubulars. If there are at least two MC/non-conductive tubulars and at least three conductive tubulars, two of the MC/non-conductive tubulars may be alternately disposed between three of the conductive tubulars. The MC/non-conductive tubulars may be formed from materials such as stainless steel, fiber-reinforced thermal sets, and thermal plastics. One such thermal plastic is polyetheretherketone (PEEK) and it may be glass-reinforced. The conductive tubulars, if electrically isolated, may be used as electrodes to transmit or receive electromagnetic signals. The casing string may used for borehole to surface applications, surface to borehole applications, borehole to borehole applications, or single well applications. The casing string may also have downhole sensors, uphole sensors, and surface sensors. Those sensors may be transmitters or receivers.

Description

BACKGROUND

1. Technical Field

The present disclosure relates generally to the logging of subsurface formations surrounding a wellbore using a downhole logging tool, and particularly to determining electrical properties of the formation behind a cased wellbore.

2. Background Art

Logging tools have long been used in wellbores to make, for example, formation evaluation measurements to infer properties of the formations surrounding the borehole and the fluids in the formations. Common logging tools include electromagnetic tools, nuclear tools, and nuclear magnetic resonance (NMR) tools, though various other tool types are also used.

Early logging tools were run into a wellbore on a wireline cable, after the wellbore had been drilled. Modern versions of such wireline tools are still used extensively. However, the need for information while drilling the borehole gave rise to measurement-while-drilling (MWD) tools and logging-while-drilling (LWD) tools. MWD tools typically provide drilling parameter information such as weight on the bit, torque, temperature, pressure, direction, and inclination. LWD tools typically provide formation evaluation measurements such as resistivity, porosity, and NMR distributions. MWD and LWD tools often have components common to wireline tools (e.g., transmitting and receiving antennas), but MWD and LWD tools must be constructed to not only endure but to operate in the harsh environment of drilling.

Typically, particularly for electromagnetic measurements, a signal originates from a tool disposed in the interior of an uncased wellbore, passes through the formation outside the wellbore, and returns to a receiver within the wellbore. Because the signal travels through the formation, certain properties of the formation can be inferred from the measurement. Measurements are typically performed in an uncased portion of the wellbore because conventional conductive casing tends to limit the electromagnetic signal that can pass between the interior and exterior of a cased wellbore. This is not necessarily an issue when a well is being drilled since measurements can be made prior to setting the casing, but presents a challenge should one wish to re-enter an existing cased wellbore to make updated measurements.

SUMMARY

A casing string in a wellbore has conductive tubulars and modified conductivity (MC) or non-conductive tubulars joined to one another. A MC/non-conductive tubular may be disposed between two conductive tubulars. If there are at least two MC/non-conductive tubulars and at least three conductive tubulars, two of the MC/non-conductive tubulars may be alternately disposed between three of the conductive tubulars. The MC/non-conductive tubulars may be formed from materials such as stainless steel, fiber-reinforced thermal sets, and thermal plastics. One such thermal plastic is polyetheretherketone (PEEK) and it may be glass-reinforced. The conductive tubulars, if electrically isolated, may be used as electrodes to transmit or receive electromagnetic signals. The casing string may used for borehole to surface applications, surface to borehole applications, borehole to borehole applications, or single well applications. The casing string may also have downhole sensors, uphole sensors, and surface sensors. Those sensors may be transmitters or receivers.

Other aspects and advantages will become apparent from the following description and the attached claims.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 illustrates an exemplary well site system.

FIG. 2 shows a prior art electromagnetic logging tool.

FIG. 3 schematically shows an example of a thermal plastic casing tubular, in accordance with the present disclosure.

FIG. 4 schematically shows a casing string with a section of plastic or non-conducting casing, in accordance with the present disclosure.

FIG. 5 shows the casing string of FIG. 4 with a wireline tool string deployed in the cased wellbore, in accordance with the present disclosure.

FIG. 6 shows the casing string of FIG. 4 with a large induction coil that is excited by a surface coil or an electrode deployed in the cased wellbore, in accordance with the present disclosure.

FIG. 7 schematically shows a casing string having alternating metallic and MC or insulating sections, in accordance with the present disclosure.

FIG. 8 is a flowchart showing the steps of an exemplary embodiment, in accordance with the present disclosure.

DETAILED DESCRIPTION

Some embodiments will now be described with reference to the figures Like elements in the various figures will be referenced with like numbers for consistency. In the following description, numerous details are set forth to provide an understanding of various embodiments and/or features. However, it will be understood by those skilled in the art that some embodiments may be practiced without many of these details and that numerous variations or modifications from the described embodiments are possible. As used here, the terms “above” and “below”, “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe certain embodiments. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship as appropriate.

FIG. 1 illustrates a well site system in which various embodiments can be employed. The well site can be onshore or offshore. In this exemplary system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Some embodiments can also use directional drilling, as will be described hereinafter.

A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11, the assembly 10 including a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook. As is well known, a top drive system could alternatively be used.

In the example of this embodiment, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this well known manner, the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.

The bottom hole assembly 100 of the illustrated embodiment includes a logging-while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a roto-steerable system and motor, and drill bit 105.

The LWD module 120 is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at 120A. (References, throughout, to a module at the position of 120 can alternatively mean a module at the position of 120A as well.) The LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module includes a resistivity measuring device.

The MWD module 130 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick/slip measuring device, a direction measuring device, and an inclination measuring device.

An example of a tool which can be the LWD tool 120, or can be a part of an LWD tool suite 120A, is shown in FIG. 2. As seen in FIG. 2, upper and lower transmitting antennas, T₁ and T₂, have upper and lower receiving antennas, R₁ and R₂, therebetween. The antennas are formed in recesses in a modified drill collar and mounted in MC or insulating material. The phase shift of electromagnetic energy as between the receivers provides an indication of formation resistivity at a relatively shallow depth of investigation, and the attenuation of electromagnetic energy as between the receivers provides an indication of formation resistivity at a relatively deep depth of investigation. U.S. Pat. No. 4,899,112 can be referred to for further details. In operation, attenuation-representative signals and phase-representative signals are coupled to a processor, an output of which is coupleable to a telemetry circuit.

Recent electromagnetic (EM) logging tools use one or more tilted or transverse antennas, with or without axial antennas. Those antennas may be transmitters or receivers. A tilted antenna is one whose dipole moment is neither parallel nor perpendicular to the longitudinal axis of the tool. A transverse antenna is one whose dipole moment is perpendicular to the longitudinal axis of the tool, and an axial antenna is one whose dipole moment is parallel to the longitudinal axis of the tool. A triaxial antenna is one in which three antennas (i.e., antenna coils) are arranged to be mutually orthogonal. Typically, one antenna (coil) is axial and the other two are transverse. Two antennas are said to have equal angles if their dipole moment vectors intersect the tool's longitudinal axis at the same angle. For example, two tilted antennas have the same tilt angle if their dipole moment vectors, having their tails conceptually fixed to a point on the tool's longitudinal axis, lie on the surface of a right circular cone centered on the tool's longitudinal axis and having its vertex at that reference point. Transverse antennas obviously have equal angles of 90 degrees, and that is true regardless of their azimuthal orientations relative to the tool.

After drilling a wellbore, or sometimes as an intermediate step in drilling a wellbore, casing is typically lowered into at least a portion of the drilled wellbore. The casing outer diameter is slightly less than the diameter of the wellbore so that when the casing is lowered in place, an annular space is created between the casing and the wellbore wall. Cement is pumped through the interior of the casing string, exits the lower end of the casing, and travels upward into the annular void. When the cement sets, it bonds the casing to the formation. Various tools and methods are known in the art to “case” a well in this or a similar manner.

Logging tools include, but are not limited to, transient and continuous-wave electromagnetic tools, nuclear tools, sonic or acoustic tools, and nuclear magnetic resonance (NMR) tools. Most logging tools must be run prior to casing a wellbore because the casing is generally made of a conductive material such as steel, which interferes with the measurement. The measurement results may be badly skewed by the presence of the casing, or the casing may prevent a meaningful measurement from being made altogether. To circumvent this problem, a casing string may be used in which sections of the casing comprise a modified conductivity (MC) or non-conductive material, including, but not limited to, stainless steel, fiber-reinforced thermal sets, and thermal plastics. Essentially any open hole logging tool or method that would be adversely affected by the presence of conductive steel casing can be run using MC/non-conductive sections of casing.

For example, a thin coating made of stainless steel can produce a hybrid casing joint having much higher resistivity than normal casing. The coating can thereby serve as a barrier to axial current flowing in the wellbore. Doped material may also be used to produce casing having a desired conductivity. There are many ways to construct such hybrid casing and such controlled conductivity casing can provide unique benefits. For example, one may use galvanic methods with such casing. Using controlled conductivity casing having a specific electrical conductivity allows one to optimize the sensitivity, efficiency, and mechanical or other properties, individually or simultaneously. Modified conductivity casing having a thin skin of stainless steel, as mentioned above, would provide for corrosion and strength benefits without adversely affecting the desired signals.

In various embodiments, either a galvanic or induction-type measurement is made, whereby a transmitter or receiver is placed uphole or on the surface. Such configurations measure the formation between the downhole instrument and the surface or uphole instrument. The decision as to the placement of the transmitter and receiver often depends on environmental conditions. MC or insulating sections of casing may be strategically placed in the wellbore adjacent certain sections of the formation. Those MC or insulating sections may subsequently be used, for example, to monitor the electrical properties of the formation throughout the life of the field. The MC or insulating sections of casing allow electromagnetic energy to pass and thereby be used to measure the electrical properties of the formation. In addition, a controlled source electromagnetic (CSEM) source may be used. The CSEM source could be lowered into a wellbore or operated on or near the earth's surface or sea floor. One possible application would be to monitor fronts emanating from an injection well such as those spawned by water flooding, steam flooding, or chemical flooding. A downhole CSEM source or associated receiver would preferably be placed adjacent a MC or non-conductive section of casing.

FIG. 3 shows casing having a fiberglass/polyetheretherketone (PEEK) thermal plastic tubular with threaded metal ends. Various lengths of plastic (i.e., insulating, or with desired electrical conductivity features) casing may be used, as desired. The insulating or MC casing may be disposed between two metallic or conducting sections of casing, as shown in FIG. 4. FIG. 5 shows a wireline tool for which any number of measurements are now possible by exploiting the insulating or MC casing. For example, if the tool is an induction-type tool, local resistivity measurements can be obtained at various times to produce a time lapse image. If the tool is equipped with a large receiver or transmitter working in conjunction respectively with a large transmitter or receiver on the surface, one may invert for the formation resistivity. Note that an electrode transmitter or an electric dipole on the surface can also excite the downhole coil receiver. In FIG. 6, an antenna, such as one carried on a wireline tool, is shown either driving or measuring an electromagnetic field in the formation. That is, the dipole antenna may be energized to transmit a signal through the formation to a receiver, or driven by a transmitter source located, for example, on the surface. Because the antenna is located adjacent an MC or insulating section of casing, the electromagnetic signal readily passes through the casing to or from the antenna, allowing communication with another antenna after passing through the formation. The transmitter and receiver antennas can be electric dipoles or magnetic dipoles.

Alternatively, there can be multiple alternating conductive and MC or insulating sections of casing, electrically breaking the casing into sections, as shown in FIG. 7. Those sections can be operated as electric dipoles. Where casing segments are isolated, each casing segment can be used as a transmitter or receiver electrode for electrical resistance tomography (ERT). The isolated sections of conductive casing can be used as excited or measure electrodes. Embodiments of a casing string interlaced with MC or insulating or resistive joints and including active electrodes for galvanic resistivity measurements are useful in borehole to surface applications, surface to borehole applications, borehole to borehole applications, as well as single well applications. Similarly, a casing string interlaced with MC (i.e., resistive) or insulating sections of casing may be used for induction resistivity measurements in borehole to surface applications, surface to borehole applications, borehole to borehole applications, and single well applications. Those embodiments could also be used for telemetry, allowing communication between surface and downhole equipment or downhole-to-downhole equipment, in the same or a different wellbore.

Thus, the electromagnetically transparent sections can be used to transmit or receive electromagnetic energy, whereby the electrical properties of the formation can be deduced by methods know in the industry. Having multiple electrode elements distributed along the length of the casing increases resolution and reduces non-uniqueness when inverting the galvanic data sets. Examples of formation properties that may be investigated include electrical resistivity, dielectric constants, and magnetic properties. It is also possible to make nuclear magnetic resonance (NMR) measurements using the MC or insulating sections of casing. The sensors may be run in on a tool, or they may be permanent sensors. In addition, transient or time-based measurement signals may be used.

Formation measurements may be made by providing a logging tool (step 800) and a casing string having one or more conductive tubulars and one or more MC/non-conductive tubulars joined to the one or more conductive tubulars (step 802). Formation measurements are made using the logging tool and the casing string (step 804).

It should be appreciated that while the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A casing string disposed in a wellbore, comprising: one or more conductive tubulars; andone or more modified conductivity or non-conductive (MC/non-conductive) tubulars joined to the one or more conductive tubulars.

2. The casing string of claim 1, wherein one of the one or more MC/non-conductive tubulars is disposed between two conductive tubulars.

3. The casing string of claim 1, wherein the one or more MC/non-conductive tubulars comprise two MC/non-conductive tubulars; the one or more conductive tubulars comprise three conductive tubulars; and the two MC/non-conductive tubulars are alternately disposed between the three conductive tubulars.

4. The casing string of claim 1, wherein the one or more MC/non-conductive tubulars are formed from materials selected from the group consisting of stainless steel, fiber-reinforced thermal sets, and thermal plastics.

5. The casing string of claim 1, wherein the one or more MC/non-conductive tubulars are formed from polyetheretherketone (PEEK).

6. The casing string of claim 5, wherein the polyetheretherketone (PEEK) is glass-reinforced.

7. The casing string of claim 1, wherein one or more of the conductive tubulars is an electrode.

8. The casing string of claim 7, wherein one or more of the electrodes is used to transmit or receive an electromagnetic signal.

9. The casing string of claim 1, wherein the casing string is used for borehole to surface applications, surface to borehole applications, borehole to borehole applications, or single well applications.

10. The casing string of claim 1, further comprising a downhole sensor and an uphole sensor or a downhole sensor and a surface sensor.

11. The casing string of claim 10, wherein the downhole sensor is a transmitter and the uphole sensor is a receiver or the downhole sensor is a transmitter and the surface sensor is a receiver.

12. The casing string of claim 10, wherein the downhole sensor is a receiver and the uphole sensor or the surface sensor is a transmitter.

13. The casing string of claim 1, wherein the one or more MC/non-conducting tubulars have threaded metal ends.

14. A logging system, comprising: one or more conductive tubulars;one or more modified conductivity or non-conductive (MC/non-conductive) tubulars joined to the one or more conductive tubulars; anda logging tool disposed in the interior region of the tubulars.

15. The logging system of claim 14, wherein the logging tool is a transient or continuous-wave electromagnetic tool, a nuclear tool, an acoustic or sonic tool, or a nuclear magnetic resonance tool.

16. A method to make formation measurements, comprising: providing a logging tool;providing a casing string having one or more modified conductivity or non-conductive (MC/non-conductive) tubulars joined to the one or more conductive tubulars; andmaking formation measurements using the logging tool and the casing string.

17. The method of claim 16, wherein the logging tool is a wireline tool.

18. The method of claim 16, wherein the logging tool is a transient or continuous-wave electromagnetic tool, a nuclear tool, an acoustic or sonic tool, or a nuclear magnetic resonance tool.

19. The method of claim 16, wherein the formation measurements relate to one or more of electrical resistivity, a dielectric constant, radioactivity properties, acoustic properties, nuclear magnetic resonance properties, and magnetic properties.

20. The method of claim 16, further comprising using the formation measurements for borehole to surface applications, surface to borehole applications, borehole to borehole applications, or single well applications.

21. The method of claim 16, wherein the one or more MC/non-conducting tubulars have threaded metal ends.