Patent Application
20200248548
The present technology relates to oil and gas wells. In particular, the present technology relates to systems and methods for monitoring well conditions.
Oil wells are typically examined to determine petrophysical properties related to one or more of the well bore, the reservoir it penetrates, and the adjacent formation. Such an examination is typically carried out by a well logging tool, which is lowered to the bottom of the well, and employs electrical, mechanical, and/or radioactive tools to measure and record certain physical parameters including pressure, temperature, flow rate, and other parameters. These parameters are normally interpreted to diagnose well and reservoir conditions. Several other factors pertaining to well conditions such as well architecture, depth, and oil grade are making it more difficult to acquire important data, and to make the best utilization of hydrocarbon assets.
Lowering the logging tool and other equipment (collectively known as the bottom hole assembly) to the bottom of the well can be difficult, particularly in horizontal or deviated portions of wells, where tubing is used to push the bottom hole assembly horizontally through the well bore. One reason for this difficulty is friction between the bottom hole assembly and walls of the well bore. The result of this friction can be that the bottom hole assembly stops progressing toward the bottom of the well. When the bottom hole assembly becomes stuck, the tubing that pushes the bottom hole assembly can buckle.
One known way to overcome this problem is with a well tractor that applies an urging force to the bottom hole assembly. A well tractor is typically a wheeled device that may be included with the bottom hole assembly. When the bottom hole assembly is pushed into the horizontal or deviated portion of the well, and if the friction between the bottom hole assembly and the well begins to slow or stop the progress of the bottom hole assembly toward the bottom of the well, the wheels on the well tractor may turn to drive the bottom hole assembly further into the well. Use of such a well tractor, however, can be problematic. For example, in reservoirs where the rock has low strength, insufficient traction may exist for the tractor to propel the bottom hole assembly toward the bottom of the hole. In addition, well tractors are expensive tools, and there are few companies that produce them.
One example embodiment is a bottom hole assembly for monitoring well conditions. The bottom hole assembly includes a well logging tool including a plurality of sensors, a vibrator tool coupled to the well logging tool for inserting the well logging tool into a wellbore, and a spoolable composite tube coupled to the vibrator tool, the spoolable composite tube configured to carry power and data cables from the surface to the plurality of sensors in the well logging tool. The well logging tool may have a substantially cylindrical body comprising a matrix material. The plurality of sensors may be selected from the group consisting of acoustic sensors, optical sensors, mechanical sensors, electrical sensors, fluidic sensors, pressure sensors, temperature sensors, and chemical sensors. The well logging tool may further include one or more cameras installed on a distal end of the tool to provide a live visual means to check a well condition.
The spoolable composite tube may include a plurality of fibers embedded in the matrix material. The fibers may be woven, braided, knitted, stitched, circumferentially wound, or helically wound. The fibers may include at least one material selected from the group consisting of stainless steel, glass, carbon, ceramic, aramid, nylon, polyester, and polyethylene. The matrix material may be selected from the group consisting of polyether ether ketone, polyether ketone, polyetherketoneketone, polyamide, polyethylene, polyurethane, polypropylene, polyphenylene sulfide, epoxy, phenolic, bismaleimide, ester, polyester, vinyl-ester, ceramic, and carbon. The matrix material may have a tensile modulus of elasticity of at least 250,000 psi, has a maximum tensile elongation of greater than or equal to 5%, or has a glass transition temperature of at least 180 degrees F.
The vibrator tool may include a substantially cylindrical body, a motor within the substantially cylindrical body, a non-linear shaft attached to the motor so that as the motor turns the non-linear shaft, the non-linear shaft extends outwardly from the motor within the substantially cylindrical body, and a bearing attached to the shaft a distance from the motor so that the bearing rotates as the non-linear shaft turns, the bearing contacting portions of the inner surface of the cylindrical body as the non-linear shaft turns, thereby vibrating the substantially cylindrical body. The motor is able to turn the shaft at a rate of about 1000-2000 revolutions per minute. The substantially cylindrical body has longitudinal slots that are positioned to contact the bearing as the bearing rotates so that contact between the bearing and the slots amplifies the vibration of the vibrator tool.
Another example embodiment is a method for monitoring a well condition. The method includes inserting a bottom hole assembly into a wellbore, and receiving, in real-time, data pertaining to the monitored well condition on the surface. The bottom hole assembly in this embodiment may include a well logging tool including a plurality of sensors for monitoring a well condition, a vibrator tool for enabling insertion of the well logging tool into the wellbore, and a spoolable composite tube to carry power and data cables from the surface to the plurality of sensors in the well logging tool. The method further includes the steps of lowering the bottom hole assembly through a vertical part of the well, pushing the bottom hole assembly through a deviated part of the well using the tubing, and vibrating the bottom hole assembly and tubing with the vibrating tool to reduce friction between the bottom hole assembly and tubing, and the wellbore.
In some embodiments, the bottom hole assembly can include more than one vibrating tool. In addition, the method can include one or more of the steps of adjusting the distance of the bearing from the motor to increase or decrease vibration, and adjusting the weight of the bearing to increase or decrease vibration.
Another example embodiment is a system for monitoring a well condition. The system includes a well logging tool including a plurality of sensors, a vibrator tool coupled to the well logging tool to enable inserting the well logging tool into a wellbore, and a spoolable composite tube coupled to the vibrator tool, the spoolable composite tube configured to carry power and data cables from the surface to the plurality of sensors in the well logging tool. The well logging tool may have a substantially cylindrical body comprising a matrix material. The plurality of sensors may be selected from the group consisting of acoustic sensors, optical sensors, mechanical sensors, electrical sensors, fluidic sensors, pressure sensors, temperature sensors, and chemical sensors. The well logging tool may also include one or more cameras installed on a distal end of the tool to provide a live visual means to check a well condition. The spoolable composite tube may include a plurality of fibers embedded in the matrix material. The matrix material may have a tensile modulus of elasticity of at least 250,000 psi, has a maximum tensile elongation of greater than or equal to 5%, or has a glass transition temperature of at least 180 degrees F.
The present technology will be better understood on reading the following detailed description of non-limiting embodiments, and on examining the accompanying drawings, in which:
The foregoing aspects, features, and advantages of the present technology will be further appreciated when considered with reference to the following description of preferred embodiments and accompanying drawings, wherein like reference numerals represent like elements. In describing the preferred embodiments of the technology illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the embodiments are not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.
There is attached to the end of the tubing 12 a bottom hole assembly 28, which, in the embodiment shown in
As the tubing 12 is unwound from the coiled tubing reel 19, the bottom hole assembly 28 is lowered into the well 14. In the vertical portion 20 of the well 14, the weight of the bottom hole assembly 28 pulls the bottom hole assembly 28 and its attached tubing 12 into the well 14. In wells having no deviated portion, the weight of the bottom hole assembly 28 alone may be sufficient to bring the bottom hole assembly 28 to the bottom 18 of the well 14. However, in wells having a horizontal or deviated portion 22, the coiled tubing 12 typically pushes the bottom hole assembly 28 further into the well 14 to move the bottom hole assembly 28 through the horizontal or deviated portion 22 of the well 14. Typically, an injector 30 can be included to force the tubing 12 into the well once the bottom hole assembly 28 reaches the horizontal or deviated portion 22 of the well 14.
As the bottom hole assembly 28 and the end of the tube 12 progress through the horizontal or deviated portion 22 of the well 14, friction can develop between the bottom hole assembly 28 and the walls of the well 14. As friction between these components increases, the injector 30 must exert more and more force on the tubing 12 to continue pushing the bottom hole assembly 28 deeper into the well 14. If the frictional forces between the bottom hole assembly 28 and the walls of the well 14 become greater than the force exerted on the tubing by the injector 30, forward progress of the bottom hole assembly 28 into the well 14 can slow or stop. In this situation, the bottom hole assembly 28, including the logging tool 29, cannot reach the bottom of the well 18 to record the required measurements. In addition, such a situation can lead to the tubing 12 buckling as the bottom hole assembly 28 stops progressing at the same rate as the tubing 12.
As shown in
Referring now to
The vibrating sub tool 34 is a tool that can produce vibration. This vibration can be manifested in the shaking or agitation of the vibrating sub tool 34 relative to the well 14, and has the tendency to cause the vibrating sub tool 34 to rapidly move or oscillate relative to the well 14, thereby decreasing contact and, as a result, frictional forces, between the vibrating sub tool 34 and the well 14. In some embodiments, the vibration can be enough to separate the vibrating sub tool 34 from surfaces of the well. This vibration can in turn provide vibration or agitation to the bottom hole assembly 28 and tubing 12, thereby reducing frictional forces between the bottom hole assembly 28 and tubing 12, and the well 14 in the same way. When the frictional forces are less than the forces exerted on the bottom hole assembly 28 by the injector 30 and the tubing 12, the down hole assembly 28 can continue to move down hole. If desired, multiple vibration sub tools 34 can be deployed in the same well 14, thereby increasing the amount of vibration and further reducing friction between the bottom hole assembly 28 and tubing 12, and the well 14.
The well logging tool 56 can be equipped with two or more sensors 58 in a distal end section of the well logging tool 56, for example, in the last 10-20 ft of the tool 56. The plurality of sensors 58 may be selected from the group consisting of acoustic sensors, optical sensors, mechanical sensors, electrical sensors, fluidic sensors, pressure sensors, temperature sensors, and chemical sensors. Although only three sensors are illustrated, the system 100 may include one or more of each type of sensors listed here. For example, the optical sensor can be an interferometric sensor or an optical intensity sensor. The optical intensity sensor may include light scattering sensors, spectral transmission sensor, radiative loss sensors, reflectance sensors, and modal change sensors. The mechanical sensor may include piezoelectric sensors, vibration sensors, position sensors, velocity sensors, strain sensors, and acceleration sensors. The electrical may include current sensors, voltages sensors, resistivity sensors, electric field sensors, and magnetic field sensors. The fluidic sensor may include flow rate sensors, fluidic intensity sensors, and fluidic density sensors. The pressure sensor may include absolute pressure sensors and differential pressure sensors. The temperature sensor may include thermocouples, resistance thermometers, and optical pyrometers. The well logging tool 56 may further include one or more cameras 60 that may be installed on a distal end of the tool 56 to provide a live visual means to check a well condition.
Vibration of the vibrating sub tool 34 can be caused by a motor, which, in one possible embodiment, can be structured in a similar way to the arrangement shown in
Another embodiment of the vibrating sub tool 34 is shown in
The embodiment of
Use of a vibration sub tool 34 to reduce friction between the tubing 12, bottom hole assembly 28, and the well 14 can be advantageous compared to the well tractor 32, because the vibrating sub tool 34 has few parts and can be manufactured and installed more economically. In addition, the vibration sub tool 34 has the ability to move the bottom hole assembly 28 even when the reservoir rock is of low strength, a condition that could preclude the use of a well tractor 32.
In practice, the vibrating sub tool 34 of the present technology can be used according to the following method. Initially, the bottom hole assembly 28, including the vibrating sub tool 34, can be lowered into the well 14. As the bottom hole assembly 28 passes through the vertical section 20 of the well 14, the weight of the bottom hole assembly itself can pull the bottom hole assembly 28 downward toward the bottom 18 of the well 14. Upon reaching the horizontal or deviated section 22 of the well 14, the tubing 12 attached to the bottom hole assembly 28 can begin pushing the bottom hole assembly 28 horizontally through the well 14. If desired, such as when the frictional forces between the bottom hole assembly 28 and the well 14 exceed the force exerted on the bottom hole assembly 28 by the tubing 12, the vibrating sub tool 34 may be activated and begin to vibrate. This vibration can agitate the bottom hole assembly 28 and tubing 12, thereby reducing the amount of friction between the tubing 12, bottom hole assembly 28, and the well 14 so that the tubing 12 can continue to push the bottom hole assembly 28 toward the bottom 18 of the well 14.
The sensor 72 is a structure that senses either the absolute value or a change in value of a physical quantity. Exemplary sensors for identifying physical characteristics include acoustic sensors, optical sensors, mechanical sensors, electrical sensors, fluidic sensors, pressure sensors, temperature sensors, strain sensors, and chemical sensors.
Mechanical sensors suitable for deployment in the composite tubular member 12 include piezoelectric sensors, vibration sensors, position sensors, velocity sensors, strain gauges, and acceleration sensors. The sensor 72 can also be selected from those electrical sensors, such as current sensors, voltage sensors, resistivity sensors, electric field sensors, and magnetic field sensors. Fluidic sensors appropriate for selection as the sensor 72 include flow rate sensors, fluidic intensity sensors, and fluidic density sensors. Additionally, the sensor 72 can be selected to be a pressure sensor, such as an absolute pressure sensor or a differential pressure sensor. For example, the sensor 72 can be a semiconductor pressure sensor having a moveable diaphragm with piezoresistors mounted thereon.
The sensor 72 can be also selected to be a temperature sensor. Temperature sensors include thermocouples, resistance thermometers, and optical pyrometers. A thermocouple makes use of the fact that junctions between dissimilar metals or alloys in an electrical circuit give rise to a voltage if they are at different temperatures. The resistance thermometer consists of a coil of fine wire. Copper wires lead from the fine wire to a resistance measuring device. As the temperature varies the resistance in the coil of fine wire changes.
As further illustrated in
In one example embodiment, the spoolable composite tube 12 may include a plurality of fibers embedded in the matrix material. The fibers may be woven, braided, knitted, stitched, circumferentially wound, or helically wound. The fibers may include at least one material selected from the group consisting of stainless steel, glass, carbon, ceramic, aramid, nylon, polyester, and polyethylene. The matrix material may be selected from the group consisting of polyether ether ketone, polyether ketone, polyetherketoneketone, polyamide, polyethylene, polyurethane, polypropylene, polyphenylene sulfide, epoxy, phenolic, bismaleimide, ester, polyester, vinyl-ester, ceramic, and carbon. The matrix material may have a tensile modulus of elasticity of at least 250,000 psi, a maximum tensile elongation of greater than or equal to 5%, and have a glass transition temperature of at least 180 degrees F.
In other embodiments of pressure barrier layer 130, the pressure barrier layer comprises co-polymers formed to achieve enhanced pressure barrier layer characteristics, such as corrosion resistance, wear resistance and electrical resistance. For instance, a pressure barrier layer 130 can be formed of a polymer and an additive such that the pressure barrier layer has a high electrical resistance or such that the pressure barrier layer dissipates static charge buildup within the composite tube 12. In particular, carbon black can be added to a polymeric material to form a pressure carrier layer 130 having a resistivity on the order of 108 ohms/centimeter. Accordingly, the carbon black additive forms a pressure barrier layer 130 having an increased electrical conductivity that provides a static discharge capability. The static discharge capability advantageously prevents the ignition of flammable fluids being circulated within the composite coiled tube 12.
In a further aspect, the pressure barrier layer 130 has a mechanical elongation of at least 25%. A pressure barrier layer with a mechanical elongation of at least 25% can withstand the increased bending and stretching strains placed upon the pressure barrier layer as it is coiled onto a reel and inserted into and removed from various well bores. Accordingly, the mechanical elongation characteristics of the pressure barrier layer prolong the overall life of the composite coiled tube 10. In addition, the pressure barrier layer 130 preferably has a melt temperature of at least 250 degrees Fahrenheit so that the pressure barrier layer is not altered or changed during the manufacturing process for forming the composite coiled tubing. A pressure barrier layer having these characteristics typically has a radial thickness in the range of 0.02-0.25 inches.
The composite layer 140 can be formed of a number of plies, each ply having fibers disposed with a matrix, such as a polymer, resin, or thermoplastic. Preferably, the matrix has a tensile modulus of at least 250,000 psi and has a maximum tensile elongation of at least 5% and has a glass transition temperature of at least 180 Degrees Fahrenheit. The fibers typically comprise structural fibers and flexible yarn components. The structural fibers are formed of either carbon, nylon, polyester, aramid, thermoplastic, or glass. The flexible yarn components, or braiding fibers, are formed of either nylon, polyester, aramid, thermoplastic, or glass. The fibers included in layer 14 can be woven, braided, knitted, stitched, circumferentially wound, or helically wound. In particular, the fibers can be biaxially or triaxially braided. The composite layer 140 can be formed through pultrusion processes, braiding processes, or continuous filament winding processes. A tube formed of the pressure barrier layer 130 and the composite layer 140 form a composite tube has a tensile strain of at least 0.25 percent and being capable of maintaining an open bore configuration while being spooled on a reel.
The pressure barrier layer 130, illustrated in
In another embodiment, axially extending structural fiber 120 is oriented relative to the longitudinal axis 17 at a first angle 128. Typically, fiber 120 is helically oriented at the first angle 128 relative to the longitudinal axis 17. The first angle 128 can vary between 5 degrees to 20 degrees, relative to the axis. The first angle 128 can also vary between 30 degrees to 70 degrees relative to the axis 17. Although it is preferred to have fiber 120 oriented at an angle of 45 degrees relative to axis 17.
The braiding fiber 160 is oriented relative to structural fiber 120 at a second angle 124, and braiding fiber 118 is oriented relative to structural fiber 120 at a third angle 126. The angle of braiding fibers 160 and 118, relative to structural fiber 120, may be varied between +/−10 degrees and +/−60 degrees. In one aspect, fibers 160 and 118 are oriented at an angle of +/−20 degrees relative to fiber 20.
As shown in
As shown in
The helical orientation of the energy conductors 70A, 70B allows the compression strain experienced by the section of the energy conductor located on the interior bend of the tube to be offset by the expansion strain experienced by the section of the conductor located on the exterior bend of the tube. That is, the conductor 70A, 70B is able to substantially distribute the opposing strains resulting from the bending action of the composite tube across the length of the conductor 70A, 70B, thereby reducing the damage to the energy conductor.
Another example embodiment is a method for monitoring a well condition. The method includes inserting a bottom hole assembly into a wellbore, and receiving, in real-time, data pertaining to the monitored well condition on the surface. The method further includes the steps of lowering the bottom hole assembly through a vertical part of the well, pushing the bottom hole assembly through a deviated part of the well using the tubing, and vibrating the bottom hole assembly and tubing with the vibrating tool to reduce friction between the bottom hole assembly and tubing, and the wellbore.
In some embodiments, the bottom hole assembly can include more than one vibrating tool. In addition, the method can include one or more of the steps of adjusting the distance of the bearing from the motor to increase or decrease vibration, and adjusting the weight of the bearing to increase or decrease vibration.
The signal processor 86 receives data from the sensor 72 in the form of energy transmitted over the energy conductor 70. The signal processor then processes the received signal. The processing performed by the signal processing can include transforming the signal, filtering the signal, sampling the signal, or amplifying the signal. The operations performed by the signal processor 86 generally enhance the understanding of the signal transmitted over the energy conductor 70. For instance, the signal processor 86 can amplify and retransmit the signal over the energy conductor 70, i.e. the signal processor can act as a repeater circuit.
In another aspect, the signal processor can include a source 90 for transmitting an energy signal over the energy conductor 70, and a detector for receiving an energy signal from the energy conductor 92. The signal processor can also include an optional coupler 88 for interfacing or multiplexing the source 90 and the detector 92 with the energy conductor.
The energy signal transmitted by the source 90 is placed on the energy conductor 70 by the coupler 88. The energy signal reaches the sensor 72 and is modified by the interaction between the sensor 72 and the ambient conditions of the composite tubular member 12. The sensor transmits the modified energy signal over the energy conductor 70. The coupler 88 then interfaces the detector 90 with the energy conductor 70 so that the detector can identify the patterns in the modified energy signal. The detector determines the ambient conditions sensed by the detector 72 by comparing the properties of the energy signal transmitted by the source 90 with the properties of the modified energy signal.
Although the technology herein has been described with reference to particular embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the present technology. It is therefore to be understood that numerous modifications may be made to the illustrative embodiments and that other arrangements may be devised without departing from the spirit and scope of the present technology as defined by the appended claims.
