Tools, Systems, and Methods for Downhole Monitoring

This application claims the benefit of U.S. Provisional Application Ser. No. 63/653,413 filed on May 30, 2024, entitled “TOOLS, SYSTEMS, AND METHODS FOR DOWNHOLE MONITORING”, which is incorporated herein by reference in its entirety.

The present invention relates generally to tools, systems, and methods for downhole monitoring.

Permanent downhole monitoring systems (“PDMS”) typically include one or more permanent downhole gauges (“PDGs”) which may be positioned at a single point or multiple points to generate continuous measurements of various downhole parameters including, for example, tubing pressure, annulus pressure, temperature, vibration, noise, strain, and flow, in oil and gas wells and reservoirs in real time. Such data assist operators in making suitable decisions to improve reservoir production or injection control to optimize recovery of the oil and gas contained in the reservoir, and avoid the need for risky, time-consuming, and costly well interventions. With a clearer picture of downhole conditions, both historically and in real-time, operators have the knowledge and flexibility to respond to short-term troubleshooting and long-term asset planning.

In such systems, multiple downhole gauges are typically connected in parallel by instrumentation wire. While protecting gauges from failure, conventional systems do not allow for continued communication of any gauges in the system; for example, some systems include a fuse or surface system which turns off communication and power to all gauges. Other systems include fuses or relays which disconnect the gauge from the instrumentation wire, preventing the gauge from communicating with the rest of the system. If a short is present in the wire and not the gauge, then disconnecting any or all devices does not return communication or power.

A further problem is that there is a delay in the time for an individual downhole gauge to transmit its data to the surface. Conventional downhole monitoring systems cannot collect samples from all downhole gauges simultaneously, which is critically needed during certain operations such as, for example, hydraulic fracturing.

Downhole gauges or similar tools may be connected to other devices to monitor various parameters. Such devices may include artificial lift devices which are used to facilitate extraction of downhole fluids such as hydrocarbons, water, or other fluids, where natural pressure is insufficient. One such device is an electrical submersible pump (“ESP”) which is lowered into an oil well on several 10 m tubing joints. The ESP pumps fluids from the reservoir to the surface via tubing installed in the wellbore. The ESP has an induction motor powered by a power supply in the form of an encapsulated three phase cable connected to the pump and running the length of the tubing on which the ESP is lowered. The motor is located downhole from the pump so that well fluids pass over the motor to help keep the motor cool.

An “ESP tool” is physically connected to the bottom of the pump and electrically connected to the motor's electrical y-point where three phase wires come together. The ESP tool measures various parameters and transmits the data via the power lines to provide the operator and automated control systems with real-time information about the performance of the motor, pump, and the downhole environment. The ESP is placed deep into the oil well, often exceeding 1000 m in depth. It would be desirable to have the ability to capture pressure and temperature data at multiple levels or depths below the ESP, while still relying on the ESP tool to transmit that data to the surface.

Accordingly, there remains a need for improved tools, systems, and methods for downhole monitoring which may overcome many of the shortcomings of existing technologies.

The present invention relates generally to tools, systems, and methods for downhole monitoring. Various embodiments of the present invention provide a system and method for controlling downhole gauges including downhole gauges electrically connected in parallel and positioned within a well for monitoring parameters downhole, and electronics assemblies electrically connected in series and positioned within the well to isolate the downhole gauges within defined zones. The electronics assemblies control power and communication across the downhole gauges within the defined zones, such that the downhole gauges within the defined zones remain operable during electrical and communication interruptions or failures.

Broadly, in one aspect, a system for controlling downhole gauges comprises:

In some embodiments, each electronics assembly comprises a housing encapsulating an electronics printed circuit board. In some embodiments, the downhole gauges are electrically connected to the electronics assemblies for transmitting electrical signals representative of the parameters to the electronics assemblies. In some embodiments, the electronics assemblies receive and process the electrical signals from the downhole gauges for transmission to surface equipment. In some embodiments, the downhole gauges comprise permanent downhole gauges mountable to a tubing within the well. In some embodiments, the electronics assemblies are mounted in alignment with the downhole gauges to the tubing.

In another aspect, a method for controlling downhole gauges comprises:

Various embodiments of the present invention relate to a computer program product, a non-transitory computer-readable medium, a system, and a computer-implemented method for obtaining real-time data representing downhole conditions at a same single timepoint from all downhole gauges sampling synchronously at multiple levels within a well.

Broadly, in one aspect, a computer program product has a series of operating instructions stored on a non-transitory computer-readable medium that cause one or more processors to perform operations to obtain downhole data, the operations comprising:

In another aspect, a non-transitory computer-readable storage medium has stored therein instructions which, when executed by one or more processors, cause the one or more processors to:

In another aspect, a system for obtaining downhole data comprises: one or more processors; and

In some embodiments, the downhole gauges comprise permanent downhole gauges positioned at multiple levels within a well for monitoring the parameters.

In another aspect, a computer-implemented method for obtaining downhole data comprises:

In some embodiments, the method further comprises adjusting or determining a wellbore operation based on the stored, processed, and analyzed data.

Various embodiments of the present invention relate to an ESP tool which captures data from the ESP motor above and downhole gauges below the ESP, and transmits all data to the surface equipment for storing, processing, and analyzing.

Broadly, in one aspect, a device for obtaining downhole data below an electrical submersible pump having a motor comprises:

In some embodiments, the device further comprises an electrical feedthrough assembly positioned in the head and configured to receive power from the motor for transmission to the electronics assembly, and to receive electrical signals from the electronics assembly for transmission to surface equipment.

In some embodiments, the device further comprises a temperature sensor positioned proximal to the electrical feedthrough assembly, and electrically connected to the electronics assembly for transmitting an electrical signal representative of motor oil temperature to the electronics assembly.

In some embodiments, the device further comprises a strap for securing the cable head to the housing. In some embodiments, the electronics assembly comprises a logic PCB for receiving and processing data from the downhole gauges before transmitting the data to the surface controller, and a voltage power PCB for routing power to the downhole gauges.

Additional aspects and advantages of the present invention will be apparent in view of the description which follows. It should be understood, however, that the detailed description and the specific examples, while indicating preferred embodiments of the invention, are given by way of illustration only, since various changes and modifications within the scope of the invention will become apparent to those skilled in the art from this detailed description.

Before the present invention is described in further detail, it is to be understood that the invention is not limited to the particular embodiments described, as such may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting, since the scope of the present invention will be limited only by the appended claims.

Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the invention. The upper and lower limits of these smaller ranges may independently be included in the smaller ranges and are also encompassed within the invention, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the invention.

Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. Although any methods and materials similar or equivalent to those described herein can also be used in the practice or testing of the present invention, a limited number of the exemplary methods and materials are described herein.

It must be noted that as used herein and in the appended claims, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. The term “horizontal” means the orientation of a plane or line that is substantially parallel to the plane of the horizon. The term “vertical” means the orientation of a plane or line that is substantially at a right angle to the horizontal plane.

The present invention relates generally to tools, systems, and methods for downhole monitoring. Various embodiments of the invention will now be described having reference to the accompanying figures.

In a first embodiment, the invention relates to systems and methods for controlling downhole gauges. Downhole gauges can be used in oil and gas wells, geothermal wells, and groundwater wells for geological surveys. In some embodiments, the downhole gauges are permanent downhole gauges. As used herein the term “permanent downhole gauge” refers to a measuring and communication device which is permanently installed in a well to monitor various downhole parameters. The system and method isolate problems with electrical integrity or stability, so that downhole gauges can continue operating normally during electrical or communication interruptions/failures. Further, the system and method prevent electrical shorting of the downhole gauges and instrumentation wire from knocking out power or communication to downhole gauges above a short. The system and method may negate the time and expense for repairing a short circuit or replacing damaged components.

schematically illustrates a portion of a conventional oil or gas well () in which the present invention is applied. The well () includes a wellbore () which has been drilled into a subterranean formation () for the purpose of recovering oil or gas; a casing () lining the wellbore () to prevents its collapse; and production tubing () through which oil and gas are brought from the subterranean formation () to the field surface facilities (not shown) for processing. While shown as extending vertically from the surface in, in some embodiments the wellbore () may be deviated, horizontal, and/or curved over at least some portions of the wellbore ().

In some embodiments, the system form of the invention generally includes one or more electronics assemblies (), one or more downhole gauges (), and connection means ().

In some embodiments, the electronics assembly () generally comprises a housing and the electronics printed circuit board (“PCB”) housed therein to prevent damage to the electronic components by protecting them from contact with the external environment. In some embodiments, the electronics PCB may be enclosed within the housing of a device other than the electronics assembly ().

In some embodiments, the electronics PCB comprises a laminated sandwich structure of conductive and insulating layers. In some embodiments, the electronics PCB is formed of laminate materials including, but not limited to, fiberglass and composite epoxy. In some embodiments, the electronics PCB is substantially circular-shaped. In some embodiments, the electronics PCB provides conductive pathways etched onto its surface for affixing various electronic components in specific positions, and electrical connections between the electronic components. In some embodiments, the electronics PCB comprises through holes which act as strain relief holes and through which wires are routed before connection to the electronics PCB. In some embodiments, the electronics PCB has a vibration specification ranging from 10-2000 Hz, 10 g RMS, and 550 g shock. In some embodiments, the electronics PCB is configured to withstand harsh environments up to 150° C. and 10 g vibration.

For the purposes of clarification and use, a person skilled in the art will recognize that a standard electronics PCB shall have, as a minimum, edged copper conductors normally understood as printed wiring or circuit traces, edged copper pads normally understood as pads, and metallically plated-through apertures normally understood as plated-through holes. Further, a person skilled in the art will recognize that a standard double-sided electronics PCB shall have as a minimum, a non-conductive substrate, a top copper-clad surface normally understood as upper surface or component side, and bottom copper-clad surface normally understood as lower surface or far-end side or circuit side. Further, a person skilled in the art will recognize that a standard multilayer electronics PCB shall have as a minimum, an upper surface and lower surface, and two inner conductive layers being electrically isolated from each other by a non-conductive substrate and for use as a voltage plane and a ground plane. Further, a person skilled in the art will recognize that electronic systems are generally implemented by a circuit design, a systems design, and systems tests.

In some embodiments, the electronics PCB comprises any appropriate type or number of such components assembled in any suitable configurations such that a functional circuit, when installed thereon, performs all the desired functions of the electronics assembly () including, but not limited to, controlling the flow of power and communication across downhole gauges (), as further described.

In some embodiments, the electronics PCB is in electrical communication with one or more various downhole gauges (). In some embodiments, the downhole gauges () are permanent downhole gauges permanently installed on the production tubing (). The downhole gauges () generate electrical signals representative of parameters and transmit the electrical signals to the electronics PCB. Such parameters may include, but are not limited to, pressure including, but not limited to tubing pressure and annulus pressure; temperature including, but not limited to, formation temperature; vibration, noise, strain, flow, acceleration, position, voltage, inclination, relative bearing, magnetic field data, laboratory data, equipment data, etc.

In some embodiments, one or more downhole gauges () generate, detect, and/or measure a magnetic field. A magnetic field can be generated to actuate magnetic devices external to the downhole gauges () or to produce a visible target for wireline operations. Magnetic field measurements are used for tool orientation and location, drilling and well guidance, and other geological applications.

In some embodiments, one or more downhole gauges () comprise lab on a chip (“LOC”) technology. LOC technology refers to the integration of miniature sensors and associated electronic circuitry onto a single chip for performing laboratory functions including, but not limited to, sampling downhole fluid to assess phase, chemical composition and processes. The downhole gauges () transmit electrical signals representative of the laboratory data to the electronics PCB.

In some embodiments, one or more downhole gauges () are operably connected or communicate wirelessly with various downhole equipment including, but not limited to, valves, sleeves, and pumps, to monitor parameters associated with the equipment. The downhole gauges () transmit electrical signals representative of the equipment data to the electronics PCB. In some embodiments, one or more downhole gauges () are operably connected or communicate wirelessly with one or more valves. The downhole gauges () detect and monitor the on/off state of the valves and provide electrical power to open or close the valves.

In some embodiments, one or more corrosion sensors are attached to one or more downhole gauges (). Monitoring the condition of materials and their rate of corrosion over time in corrosive environments is important in the oil and gas industry. Corrosion is an electrochemical process involving oxidation of metallic materials, causing mass loss and structural deterioration. Using corrosion sensors enables real-time in-situ detecting and monitoring of corrosion and associated parameters, thereby improving infrastructure security and reducing costs caused by catastrophic failures. One or more corrosion sensors can be easily installed onto one or more downhole gauges () by suitable attachment means including, but not limited to, threads and welds, to monitor real-time in-situ corrosion in the environment and to provide corrosion measurements. Suitable corrosion sensors include, but are not limited to, electrical resistance probes, corrosion coupons, electrochemical sensors, ultrasonic testing sensors, magnetic flux leakage sensors, electromagnetic sensors, and the like. The corrosion sensors transmit electrical signals representative of the corrosion measurements to the electronics PCB.

In some embodiments, one or more vibration sensors are attached to one or more downhole gauges (). Vibration sensors are used in the oil and gas industry to detect and measure the magnitude and frequency of vibrations caused by pipelines, machinery, and seismic activity, thereby monitoring structural integrity and detecting potential issues. Suitable vibrations sensors include, but are not limited to, accelerometers, seismometers, and vibrometers. The vibration sensors transmit electrical signals representative of the vibration measurements to the electronics PCB.

The electronics PCB processes the electrical signals from the downhole gauges (), corrosion sensors, and/or vibration sensors, and transmits data representative of the electrical signals via a communications link to a surface controller or computing system comprising control, data acquisition, processing, analyzing modules, etc. In some embodiments, transmission of the data is conducted using digital current or voltage modulation. The electronics PCB is electrically connected to a suitable power source to receive power for operation.

In some embodiments, the electronics PCB is electrically connected to the downhole gauges () using suitable connection means () including, but not limited to, wires such as, for example, instrumentation wires. In some embodiments, the electronics PCB is electrically connected directly to the same instrumentation wire () to which the downhole gauges () are electrically connected.

In some embodiments, the electronics PCB is wired in series, as opposed to parallel, with the downhole gauges (). A person skilled in the art will recognize that in a series circuit, the same amount of current flows through all the components placed within the circuit. In comparison, in parallel circuits, the components are placed in parallel with each other due to which the circuit splits the current flow. Wiring in series allows the electronics PCB to control the flow of electrical power and communication across the downhole gauges () in an on/off manner. In some embodiments, the on/off state is controlled by digital or analog communication.

In operation, as shown for example in, first and second electronics assemblies () comprising the electronics PCB are installed, mounted, positioned, or otherwise arranged in the wellbore (). In some embodiments, the first and second electronics assemblies () are positioned in alignment between adjacent downhole gauges (,) along the outer surface () of the production tubing (). The first and second electronics assemblies () and downhole gauges () are electrically connected to the instrumentation wire (). In some embodiments, the first and second electronics assemblies () are wired in series. In some embodiments, the downhole gauges () are wired in parallel.

The first and second electronics assemblies () control the on/off state of electrical power and communication across the downhole gauges () within corresponding first and second isolation zones (). The downhole gauges (,) positioned within the respective first or second isolation zone () are protected from any communication or electrical interruption/failure below, and continue to operate normally. The first electronics assembly () controls the first isolation zone () to protect downhole gauges (). The second electronics assembly () controls the second isolation zone () to protect downhole gauges (). In the event of a communication or electrical interruption/failure of any downhole gauge () or the instrumentation wire (), the first and second electronics assemblies () maintain electrical power and communication across the downhole gauges () within corresponding first and second isolation zones () above the communication or electrical interruption/failure below.

In some embodiments, the first isolation zone () overlaps the second isolation zone () to provide “failsafe” or back-up protection in the event of a communication or electrical interruption/failure below downhole gauge () which would affect the second electronics assembly () and downhole gauges () below. This overlap of the first and second isolation zones () enables the first and second electronics assemblies () to operate electrically and to provide the failsafe system and method. In addition, the system requires no extra wires than the four wires () needed for operation of the downhole gauges ().

To further illustrate operation of the overlap, consider an example in which there are three gauges labelled A, B, C with A at the top. Failsafe device X (i.e., an electronics assembly) is positioned between gauges A and B, and a second failsafe device Y is positioned between B and C. The devices X, Y start up in the off state, and can be turned on.