EA041160B1 - DEVICE AND SYSTEM FOR OIL PRODUCTION - Google Patents

Description

This application claims priority under 35 U.S.C. § 119(e) over the following provisional patent applications by Applicant Hydroacoustics, Inc.: U.S. Provisional Application No. 62/627310 Oil Recovery Device by R. Valtierra et al. filed February 7, 2018; and U.S. Provisional Application No. 62/659825 Oil Recovery Device by R. Valtierra, filed April 19, 2018; and claiming priority under 35 U.S.C. § 120 of co-pending U.S. Patent Application No. 16/263136 Fluid Sensor and Pumping Machine Control System by R. Valtierra et al., filed January 31, 2019, all of the above applications are incorporated herein by reference in their entirety.

The technical field to which the invention belongs

The disclosed systems and methods are directed to generating sound waves. The downhole oil recovery device provides a seismic source to improve oil recovery. The systems and methods disclosed herein improve oil recovery by vibratory stimulation, for example, to reduce capillary forces and stimulate the degree of displacement and pooling of oil held in a formation within a porous oil formation medium.

State of the art and essence of the invention

After an oil well has been in production for some time, its productivity often decreases to the point where the operation of the well is minimal or not economically viable. It is often the case, however, that significant amounts of crude oil remain in the ground in the areas of these dry wells, however, cannot be released by conventional technologies. Methods are often considered to effectively increase the productivity of a well, provided that they can be performed in a cost-effective manner. Often, the wellbore may serve as an injection well or monitoring well, and may allow the introduction of a water hammer seismic pressure wave generator downhole.

Many methods have been disclosed to improve oil recovery efficiency, including those disclosed in US Pat. No. 8,113,278 to DeLaCroix et al. titled System and Method for Improved Oil Recovery Using an IN-SITU Seismic Energy Generator (February 14, 2012), which is hereby incorporated by reference in its entirety. However, large volumes of hydrocarbons remain in oil-rich formations after the second or even third of the recovery methods that have been applied. It is believed that the main factor causing retention of hydrocarbons in such formations is the impossibility of applying direct sufficient pressure forces to the hydrocarbon droplets remaining in the pore spaces of the formations. Conventional oil recovery is typically performed as a two-stage process, the primary or initial process dependent on the natural flow or pumping of oil within the wellbore to depletion. Once the free-flowing oil has been removed, a second method is required. A substantially immiscible fluid, such as water, is injected into an injection well to flush out the oil contained in the formation in the production well. In the past, it has not been cost effective to improve the third method or improved oil recovery methods (also referred to as EOR (enhanced oil recovery)), even if up to seventy percent of the total oil may still remain in an abandoned oil well after conventional oil recovery techniques have been applied.

Another technology that has been applied to increase oil recovery is the introduction of low frequency vibrational energy. Low frequency vibrations from the surface or downhole sources have been applied to influence the recovery of liquid hydrocarbons from subterranean formations. This type of oscillation, at nominal frequencies substantially less than 1 kHz, is referred to in the literature as sonic, acoustic, seismic, longitudinal or elastic wave well stimulation. For example, low frequency oscillation stimulation has been effectively used to improve oil recovery from flooded formations. Literature examples also show that low frequency excitation can accelerate or improve maximum oil recovery. Explanations as to why the low frequency excitation creates a difference vary, however, it is believed that the introduction of vibrational energy causes the oil droplets to coalesce and restore the continuous oil phase due to displacement of the oil droplets from the formation so that they can coalesce and coalesce. Additionally, it is believed that sound waves reduce capillary forces by changing the surface and interfacial tensions, and thereby release droplets and/or allow them to coalesce. For example, US Patent No. 5,184,678 to Pechkov et al., issued Feb. 9, 1993, discloses a method and apparatus for stimulating fluid production in an existing production well using a sound wave energy emitter located in the wellbore within the productive zone. However, Pechkov only provides information that ultrasonic radiation removes fine fines and reduces the viscosity of the well fluid near the perforations through agitation, thereby increasing the production of fluid from the production well.

- 1 041160

Ultrasonic waves can improve and/or accelerate the recovery of oil from a porous medium. The problem with ultrasonic waves is that, as such, the penetration depth, or distance ultrasonic waves can travel into the formation from a source, is limited to no more than a few feet, while low frequency or sonic waves can essentially travel hundreds of feet. or thousands of feet through porous rock. While methods and apparatuses for sonic stimulation to improve the flow of liquid hydrocarbon have achieved some success in stimulating or improving the production of liquid hydrocarbons from subterranean formations, sonic wave energy emitters used to date do not have substantially sufficient acoustic power, to provide a significant impulse wave. Accordingly, there remains an unmet need for improved methods and apparatuses that use sound wave energy to stimulate or improve the recovery of liquid hydrocarbons from subterranean formations. Sound wave energy is emitted from the sound wave energy emitter in the form of pressure waves that pass through the liquid hydrocarbons into the formation, with the result that the mobility of the liquid hydrocarbon is improved and it flows more freely towards the wellbore. As a definition, elastowave is a specific type of wave that propagates within elastic or viscoelastic materials. The elasticity of the material aids in the propagation of the wave, and when such waves occur in the subsurface, they are essentially referred to as seismic waves.

The size of barrels of oil and the demand for oil is creating a lot of interest in third ways to improve oil production to further increase potential oil production by rehabilitating old wells, even those that were closed due to a high proportion of water compared to the volume of total oil produced, which is essentially referred to as the oil water cut. The main goal of improved oil recovery is to provide a means to initiate the flow of pre-entrained oil by effectively increasing the relative permeability of the reservoir with the injected oil and reducing the viscosity and surface tension of the oil. Numerous technologies that improve oil recovery are currently being put into practice in the field, including thermodynamics, chemistry and mechanics. Some of these methods have been found to be commercially viable, with varying degrees of success and limitations. Heating oil with steam has proven to be an effective means to reduce viscosity, provided that steam power is readily available and costs for more than half of the oil have now been recovered. The use of chemical surfactants and solvents such as CO2 to reduce surface tension and viscosity, while being effective, is not widely used due to cost, pollution and environmental concerns. However, seismic stimulation does not have any of the above limitations and continues to be regarded as an effective technique for improving oil recovery.

Low frequency rock formation vibrations are believed to contribute to improved oil recovery by (i) reducing capillary forces, (ii) reducing adhesion between rocks and fluids, and (iii) causing oil droplets to coalesce and allow them to flow within the injected water. Studies at the Los Alamos National Laboratory by Peter Roberts have shown that this method can increase oil recovery over much larger areas of the reservoir at a significantly lower cost than other stimulation methods that improve oil recovery.

The systems and methods disclosed herein provide a low cost third solution to help recover oil that was previously uneconomic to recover. Therefore, the main purpose of the embodiments described herein is to include the use of downhole vibrators that can generate elastic wave vibratory stimulation within a previously abandoned oil field in order to recover stationary oil. Through the use of a device for generating sound waves, additional oil production is stimulated within the oil field by fluid contact with a wellbore in which a source of sound waves can be placed.

In accordance with the described embodiments, an electro-hydraulic seismic pressure wave source configured as an oil recovery device is disclosed. Operation of the disclosed oil recovery device is facilitated by reducing the mechanical complexity of the device while improving its overall reliability. Improvements include integrating a frameless motor into a device where the motor is specifically designed to function in a water-saturated environment. The motor rotor is directly connected to the rotary valve actuator, which causes the seismic wave to be generated. The valve is constructed with at least one and possibly several openings for releasing seismic energy. In one embodiment, the oil recovery device may include smaller openings along its length to provide a conical hydraulic bearing. Through hydraulic support, the valve uses pressurized water as a support material to reduce friction and can thereby eliminate the need for custom mechanical supports. Through the connected rotor and valve and hydraulic support, the device

- 2 041160 significantly reduced to a single movable (rotating) part. Additionally, the rotor is designed with a hollow shaft which, when attached to the valve, provides a direct path for pressurized water entering the device to flow to the valve. This allows for increased fluid flow and reduced potential for cavitation (bubbles formed in the water). Additional water passes into and around the motor stator, providing cooling to the motor while the unit is running. Additionally, the incorporation of a frameless, water-saturated motor allows the tool to be reduced in diameter compared to prior downhole tools, thereby allowing improvements over a larger borehole diameter range from about 4 inches (1.016 dm).

Described in the embodiments herein is an oil recovery apparatus for transmitting waveform seismic wave energy in an oil reservoir, in a waveform, so as to change the capillary forces of the residual oil containing the body; a source of pressurized fluid; and a frameless, brushless motor operatively located within said housing to receive pressurized fluid and generate seismic waves.

Further disclosed in the embodiments herein is an apparatus for generating sound waves in an environment to stimulate oil production in an oil reservoir, comprising an elongated and substantially cylindrical body operable to pass through a wellbore; battery; a source of pressurized fluid; a power transfer section, where the power transfer section may include a pressure transfer valve and further include a frameless engine; a hollow shaft rotor having an outlet; and a stator having a corresponding outlet, whereby the energy of the fluid is transferred after the alignment of the said holes of the rotor and the stator, where the frameless motor is operatively connected to the hollow shaft rotor and where the fluid passes through this to the accumulator; and a pressure transfer valve, where a pressurized fluid is stored within said accumulator and then moved, whereby seismic wave energy is released through the openings into the fluid surrounding the device.

Also disclosed herein is a method of generating seismic wave pressure energy in oil-bearing formations, comprising placing a sound wave generator in contact with a fluid in the formation; accumulating fluid pressure energy in a sound wave generator and periodically releasing and moving the pressure energy through said generator to create wave energy that is moved by the fluid into the porous formation medium, where the energy is released and moved by a frameless motor driving a rotary valve generator, said valve generator uses a hollow shaft to pass a fluid, whereby the relative relationship of the outlets on both the rotor and the stator in the fluid generator controls the release and transmission of systematic pressure pulses to generate a seismic pressure wave.

Further disclosed herein is an oil production system for improving the recovery of oil in a reservoir, including: a pressurized fluid source; a submersible oil recovery device for transmitting seismic wave energy in an oil reservoir, in the form of a wave, so as to change the capillary forces of the residual oil at that location, containing the housing; and a frameless, brushless motor operatively located in said housing to receive pressurized liquid or gas and generate seismic waves; and a control system configured to monitor and control system components including at least an oil recovery device and a pressurized fluid source to generate seismic waves in the formation.

Also disclosed herein is a system for generating sound waves in an oil stimulation environment in an oil reservoir, comprising: a pressurized fluid source, wherein said pressurized fluid source includes a renewable fluid reservoir and a pressurization system for maintaining pressurized pressure. fluid from said container and passing pressurized fluid through a conduit terminating at an opposite end of the oil recovery device, said oil recovery device comprising an elongated and substantially cylindrical body operable to pass through the wellbore; battery; a power transfer section comprising a frameless motor, a hollow shaft rotor having an outlet, and a stator having a corresponding outlet, whereby fluid energy is transferred while aligning said rotor and stator holes, where the frameless motor is operatively connected to the hollow shaft rotor, and where the fluid passes through it to the battery; a pressure transfer valve, where a pressurized liquid or gas is stored within said accumulator and then transferred, whereby seismic wave energy is released through the openings into the fluid surrounding the device; and a control system configured to monitor and control at least the oil production device and the pressurized fluid source in order to generate a seismic

- 3 041160 mic waves in the reservoir.

Brief description of the drawings

Fig. 1-3 are front, side and top illustrations of an embodiment of an oil recovery apparatus;

fig. 4 and 5 are, respectively, cross-sectional views of FIG. 1 and 2 along lines A-A and B-B;

fig. 6 and 7 are, respectively, cross-sectional views of FIG. 4 and 5 along the lines and FIG. 8 is a partially cutaway illustration of an embodiment of an oil recovery apparatus;

fig. 9 and 10 are enlarged, sectional illustrations of alternative embodiments for assembling an engine and port portions of an oil recovery device;

fig. 11-13 are illustrations of various components for a typical drive motor for the oil recovery apparatus of FIG. 1, with FIG. 12 showing a cross section along the lines A-A of FIG. eleven;

fig. 14-17 are illustrations of various embodiments and applications for a Venturi effect sensor in accordance with the disclosed system and method;

fig. 18-19 illustrate, respectively, exemplary venturi sensor mounting methods and monitoring and control circuitry for incorporating the sensor into a pumping unit of a downhole system;

fig. 20-24 illustrate graphs of typical data for pressure and capacitance represented by the described disclosed sensor and control system; and fig. 25-27 provide schematic illustrations of an exemplary oil recovery system and method using Venturi sensors and an oil recovery apparatus in accordance with an embodiment of the disclosed oil recovery system.

The various embodiments described herein are not intended to limit the disclosure of the invention by means of these described embodiments. On the contrary, the purpose is to cover all variations, modifications, and equivalents that may be included within the spirit and scope of the various embodiments and equivalents presented below. For a general understanding, reference is made to the drawings. In the drawings, like references have been used throughout designated identical or similar elements. It should also be noted that the drawings may not be drawn to scale and that certain areas may be deliberately stretched out of proportion so that details and aspects can be displayed properly.

Description of preferred embodiments of the invention

Embodiments of an early oil recovery (ORT) device utilizing pressurized fluid released in pulses as described herein. Such devices require the use of complex mechanical components and internal fluid paths, sealed supports to provide fluid to the device and to generate suitable seismic energy or waves. Earlier devices also required separate pump(s) in order to withdraw and compress the fluid.

Oil extraction device

The embodiments of the oil recovery device 110 described herein can be used to transfer seismic wave energy (eg, in the form of a wave) in an oil reservoir to thereby change the capillary forces of the residual oil. The device includes a housing 112; a pressurized fluid source 114; and electrical energy. And, as described with respect to FIG. 1-13, the housing integrates a frameless, brushless motor operatively located in the housing to receive pressurized fluid and rotate the rotor with respect to the stator and align corresponding holes in them to generate seismic waves.

In accordance with the improved embodiments shown in FIG. 1-13, an electro-hydraulic seismic pressure wave source configured as an oil recovery device 110 is illustrated. Operation of the disclosed oil recovery device 110 is facilitated by reducing the mechanical complexity of the device while improving its overall reliability. The improvements include integrating the frameless motor assembly 120 into an apparatus where the motor is specifically designed to function in a water-saturated environment. The motor rotor 122 is directly connected to the rotary valve rotor assembly 130 which causes the seismic wave to be generated. The valve assembly is designed with multiple holes 134 (166) to release seismic energy and with the addition of smaller holes 136 along its length to provide conical hydraulic support. The apertures are slit-shaped in cross section, but may also be shaped such as circular, square cutouts, and the like, in order to change the profile and characteristics of the generated seismic wave.

The valve assembly rotor 122 may be supported to rotate with respect to the surrounding stator using any of a number of possible support devices, including frictionless materials such as Teflon®, to support the surfaces of the rotor.

- 4 041160

Custom made roller bearings are also provided using conventional inner and outer rings supported by balls or rollers and including seals to reduce friction due to bearing contamination. In another embodiment, the hydraulic valve seat uses pressurized water (from source 114 flowing through motor assembly 120 and rotor 154) as a support material to reduce friction and thereby eliminate the need for custom mechanical bearings and associated seals. Through the assembly of the associated rotor and valve and hydraulic support, the device is substantially reduced to a single movable (rotating) part - the valve rotor 154 of the assembly, driven by the attached rotor 122 of the frameless motor 120. Additionally, both rotors are designed with a hollow shaft or core 126, which, when connected to the assembly valve, provides a direct path for pressurized incoming water entering device 110 to flow through the motor to assembly valve and accumulator 180. This allows for increased fluid flow and reduced potential for cavitation (bubbles formed in the water) . Additional water passes into and around the motor stator (eg, in passageways 116 in FIGS. 9-10) to provide cooling to the motor during operation of the device. Additionally, the incorporation of a frameless, water-saturated motor makes it possible for the outer casing 112 of the device to be reduced in diameter compared to prior device designs, thereby allowing this embodiment to be applied inside smaller boreholes, with borehole diameters ranging from as small as about 4 .0 in. (1.016 in.).

Referring to FIG. 1, 4-5, and 8-10, in particular, they display cross-sectional and perspective illustrations of the oil recovery device (ORT) 110 of embodiments and assembled mechanical components. Specific components are labeled and include, for example, motor assembly 120, upper bearing surface 150, rotor 154, stator 158, rotor bore or passage 162, stator bore or passage 166, lower bearing surface 170, and pressure accumulator 180. From FIG. 1-10, it can be seen how the motor and rotary valve assembly are operatively connected together into a single rotating part, and how they are tightly integrated into the device 110.

Taking into account FIG. 9 and 10 shown are enlarged views of the assembly of motor 120 in two alternative embodiments of apparatus 110. Motor stator 156 and motor rotor 122 are shown, and the rotor rotates within the stator. Mating 128 of valve 130 is shown along with a specialized threaded screw 190 that connects the rotor motor to the valve. As illustrated in more detail in FIG. 11-13, the rotor includes a core surrounded by permanent magnets 127. The rotor rotates inside the stator. In one embodiment, the stator includes motor windings that receive power to control the operation of the motor from the surface via wires passing through the bulkhead. In the embodiment illustrated in FIG. 1-8, in order to increase the downhole interval (depth) of the device 110, the motor controller 194 may also be included in the body of the device such that electrical connections to the surface are only required to turn on the power supply and control signals. Motor speed controller 194 is part of a small printed circuit board or similar electronic assembly that is configured to fit in housing 112 and motor assembly 120 is connected to and powered by the controller via wires 196.

With reference to FIG. 10 illustrates an alternative design for the engine assembly section 120 of the device 110. In the alternative design, certain components are modified or added, some to accommodate the high pressures of the device 110 according to the depth of the pulled hole. The modifications additionally serve to prevent water ingress into the controller chamber and to eliminate erosion of the sealing material caused by pressurized fluid. Some of the changes include the 158 stator, which is no longer locally adapted. Also, O-rings 152 are enlarged (e.g., longer and/or thicker) to provide higher operating pressures up to 4000 psi (27.6 MPa) and to provide increased isolation of the motor stator from the housing and surroundings. components. Motor assembly 120 may include a longer or elongated titanium sleeve 144 to provide additional insulation to the O-rings 152 located on the top and bottom of the motor stator chamber. The stator 156 of the motor assembly 120 is also biased to the top position by the spacer 146 being pressed by the lower end of the stator by the wave spring 148 supported by the lug 150. The O-rings 146 further protect the motor sealing material from damage by the wave spring 148 by distributing the spring force, and thereby reduce vibration and pulsation transmitted directly from the spring to the sealing material.

With attention to the screw 190, the full aspect of the screw can be seen to illustrate the passage 192 for water supplied to the valve directly through the motor. Shown in red is a conventional 198 rack type coupler, the applied electrical route from the motor

- 5 041160 body outside the device 110.

Referring then to FIG. 11-12, they display parts of the assembly of a frameless engine 120. There are internal (eg, titanium) and external (eg, stainless steel) metal shells 144, 222, and 224, respectively, placed adjacent to the stator 158 along with encapsulating resin 230 to protect the engine from environmental wear, corrosion and stress caused by high water pressure, abrasion from the injected water flow, etc. As previously noted with respect to the embodiment of FIG. 10, the motor stator 158 may be isolated from the embodiment by an O-ring 152.

Thus, the oil production device 110 is a device for generating acoustic/seismic waves in a medium to stimulate oil production in an oil reservoir. The described embodiments of the oil recovery device 110 include an elongated and substantially cylindrical body 112 configured to pass through a wellbore (not shown). The housing can be made from a single material or a combination of materials including stainless steel (304, 409, or 2507) or plated steel (for example, chemically reduced nickel, boron nickel, or SeaTEC 100). The apparatus includes an accumulator 180 for storing pressurized fluid in the formation, such as from a surface source. In one embodiment, the accumulator 180 includes commercially available components such as a rubber bladder that separates the pulsations from the pressure supply. While various technologies can be applied to provide an accumulator to collect pressurized fluid for release through the orifices, in one embodiment of the device the pressure is released multiple times (e.g., twice) during each complete rotation (360°) of the rotor. 122; where the holes are essentially closed, however, open for approximately 5-15° each half-turn. The effective area of the port or opening (eg, axial length x rotational length) is in conjunction with the size of the accumulator fluid pressure, causing the pressure drop, and the associated sound wave energy, released during each exhaust cycle. It is also possible that a wide or elongated slot 162, 166 (increased area), all other aspects being constant, will reduce the average accumulator pressure. In addition to hole size, hole shapes can be made to customer specifications to modify the harmonic distortion and the acoustic pulse generated by the device.

The device also includes a power transfer section including a pressure transfer valve, and includes a frameless motor 120, a hollow shaft rotor 154 having an outlet, and a stator 158 having a corresponding outlet, whereby the stored energy of the fluid that moves through the outlets after aligning the openings of the rotor and stator, and where the frameless motor is operatively connected to the hollow shaft rotor (and fluid flows through to the accumulator). A pressure transfer valve is used where a pressurized fluid is stored within the accumulator and then moved, whereby seismic wave energy is released into the surrounding wellbore fluid/formations through openings.

As will be appreciated, a method for generating a pressure wave in oil-bearing formations using the oil recovery device 110 may include placing the device in contact with a fluid in the formation; storing fluid pressure energy (eg, sound waves) within the device; and intermittently releasing and moving pressure energy by means of a device to create wave energy by releasing fluid into the porous medium of the formations, where the release and movement of energy is performed by a frameless motor driving a rotary valve generator - a device using a hollow shaft to pass a fluid through whereby the relative relationship of the outlets on both the rotor and the stator in the housing controls the release and transmission of systematic pressure pulses or waves.

output control

With the described oil removal device, attention is drawn to a fluid detection system configured to detect fluid removed from the well. With reference to FIG. 14-17, depicted herein are various views of fluid sensor 610. In the illustrated example, fluid sensor 610 includes a two-dimensional venturi 620 where the venturi effect causes pressurized fluid(s) to be pumped through it to assume a controlled thickness shape. non-layered fluid as fluid streams. The two-dimensional venturi 620 reduces or eliminates the delamination of the fluid flowing through it as a result of combining the area of the two-dimensional venturi and narrowing downstream of the cylindrical inlet fluid passage 622 into a thin, planar region 624. The venturi 620 also includes a first sensor 630 fluid pressure, located at the inlet 632 to the venturi to measure the pressure for the pumped incoming fluid. A second fluid pressure sensor 640 is located on the outlet side 642 of the venturi 620 to measure the pressure of the fluid being discharged. It should be noted that

- 6 041160 one or both of the sensors 630 and 640 may also be configured to detect the temperature of the passing fluid in order to provide fluid temperature data as well as pressure data.

In one embodiment, the venturi 620 may be 3D printed from a stereolithographically compatible resin or similar non-magnetic material. It is also contemplated that the Venturi may be manufactured by injection molding or by machining using other well known techniques. For durability, the venturi or other sensor components can be incorporated into a metal tube (eg, FIG. 14) and sealed with a strong epoxy resin. Pressure sensors 630 and 640 are sensors that can be obtained from TE Connectivity, for example as Part No. MS5803-05BA. While a fluidic sensor 610 made using polymeric components such as polyvinyl chloride (PVC) and the like) can be configured to handle relatively limited (low) pressures in the ranges of up to 50 psi (345 kPa) or even 70 psi (483 kPa), it should be appreciated that a liquid sensor can be designed for higher pressure applications in excess of 70 psi (483 kPa). For example, through alternative materials and seals (eg thickened steel or stainless steel components, high pressure gaskets and seals, etc.), the disclosed sensor can be applied to pressure wells and the like. In such an embodiment, applying the sample(s) at different pressures is considered to move an increased range of pressures that can be experienced.

Another aspect of the 2D venturi 620 is that it provides large flat areas 624 on one side to which a capacitive sensor 660 is attached adjacent to the venturi. More specifically, the capacitive sensor includes a pair of parallel electrically conductive metal plates 664 (for example, made of copper, brass, etc., and approximately 5 square inches (32 cm2) in size and 0.01 inches (0.254 mm) thick) located on each side of the two-dimensional venturi tube.In one embodiment, copper plates are used because they are easy to cut to a suitable size, and ordinary solder can be used to attach the electrical wire leads to the sensor plates 664. The capacitance measured between the plates is the lead as the dielectric strength of a fluid flowing through a venturi, where the capacitive reactance provides characterization of the fluid - and in particular the ability to distinguish between the presence of water versus oil flowing through the sensor, by means of a relative difference in dielectric strength.

In application, the differential pressure is measured as the difference between the outputs of the first pressure sensor 630 and the second pressure sensor 640, and it is possible to determine the fluid flow rate as a result of the size of the two-dimensional venturi and/or the calibration of the venturi itself. Accordingly, fluid sensor 610 enables the device to determine fluid flow as a function of incoming fluid pressure from sensor 630 and outgoing fluid pressure from sensor 640.

In one embodiment, such as that shown in FIG. 14 and 17, the sensor 610 is housed in a housing 670 which is provided with standard threaded nipples 672 or similar fittings 674 at one of its two ends in order to provide the sensor as a complete assembly capable of being vertically mounted or inline. into a pumping unit of a well piping system, such as that shown in FIG. 18. Furthermore, as a result of the depicted design, the venturi 620 and transducer 610 are fully self-draining after the pumping unit is turned off, thereby avoiding accumulation of fluid (e.g., water) and possible damage to the transducer due to freezing conditions, etc. P. As previously suggested, the use of a two-dimensional venturi design, in combination with a tapering cylindrical tube cross-section to a linear slot at the venturi inlet (see, for example, end view of planar region 624 in FIG. 16), eliminates fluid delamination. Another characteristic of the disclosed environmental sensor is to maximize the surface area of the capacitive plate while maintaining a compact sensor assembly.

With the fluid sensor 610 details described, attention is also drawn to FIG. 1819, which are provided to illustrate an embodiment of monitoring the environment of the pumping unit and the control system, as well as the data collected from this system and processed. More specifically, pumping unit monitoring and control system 610, such as those shown in FIG. 18-19 may consist of or include an in-line fluid sensor 610 in a housing 670 where the sensor is operatively connected or vertically mounted, such as via connections 674, to receive fluid from a pumping unit 720 associated with the wellhead. In the depicted configuration, sensor 610 is used to generate and output signals of pressure and capacitance in relation to fluid output, the output signals are transmitted via wire or cable 726 to monitor and record circuitry within electrical venturi controller 740. The fluid sensor, as described above, includes a first fluid pressure sensor at the venturi inlet, a second fluid pressure sensor at the outlet of the venturi

Venturi and capacitive sensor, along a two-dimensional venturi tube, where the capacitive sensor includes a pair of parallel electrically conductive metal plates on each side of the two-dimensional venturi tube.

System 710 also consists of or includes a controller 740, an operating microprocessor or similar microcontroller 754 in accordance with a set of preprogrammed instructions. The controller 740 includes a printed circuit board 750, with an input/output port that receives an output signal from a fluid sensor 710 via a cable 726 connected at an opening 728 and processes the output signals. In addition to retrieving data, connections to other devices may provide for the exchange of information other than sensor data, including software updates and the like. In one operating mode, the 740 controller (for example, a single board computer available from Texas Instruments) can function simply as a data acquisition device, receiving and storing output signals from a sensor in memory (not shown), including converting signals from an analog output form to digital. values to save. Also included is a plug or port (eg, 4-pole) 764 allowing wiring for the pumping unit (eg, control signals for power and motor). Wireless connectivity is also provided via a localized Bluetooth or Wi-Fi connection between the controller and a laptop computer (not shown), and a mobile phone or satellite link is also provided that can be integrated into the controller 240 to facilitate remote communication. In addition, a digital display 260 may be provided with the controller 240 to provide status or operating data as well as real-time output pressure or other data. Although not shown, it should be appreciated that system 210 further includes a power supply that may include one or more batteries as the primary power source or for backup power.

Referring briefly to FIG. 18-19, in one embodiment, the Venturi sensor may include an embedded digital controller with which it communicates with the controller 740 via a universal asynchronous transceiver (UART) signal (eg, RS232). The Venturi transducer system sends pre-digitized values for pressure, temperature and capacitance to the controller. Electronic equipment is placed in a sheath, such as a pipe, and then filled (sealed) with epoxy resin. The central electronic board includes a microcontroller that is connected to the pressure sensors 630, 640, measures the capacitance, stores and transmits the digital data stream of the data sensor to the pumping unit controller 740. Two external boards 830, 840 can be used to mount pressure sensors. Alternatively, as illustrated in FIG. 15, the pressure sensors 630 and 640 are directly connected to the electronic board 618 via electrical wiring or bus. For example, used in one embodiment is a digital bus 650 (ribbon cable) that the microcontroller uses to connect to pressure sensors. An integrated digital controller is mainly used to convert analog sensor signals to digital signals in order to reduce the noise that is essentially associated with the transmitted analog signal (especially when measuring capacitance). Finally, the ability to determine the temperature of the fluid flowing through the sensor allows for more accurate characterization of fluid pressures.

In another embodiment, the controller or other computer processor (not shown) to which the controller 740 is connected (wiredly (eg, through port 728) or wirelessly) may apply output signals to control the output of the pumping unit and, based on such signals , analyze and report the performance of the pumping unit, as shown in FIG. 20-24. In addition, the controller or other computer may process the outputs to sum the amount of oil and/or water pumped from the wellhead over a period of time based on the pressure difference between the first and second pressure sensors. As stated above, the pumping unit monitoring and control system may include a wireless transceiver to communicate with another computerized device.

Pumping unit monitoring and control system 710 may also process data from sensor 610 and modify pumping unit operation to optimize oil recovery from the wellhead. For example, the system can be applied to determine, based on real time output signals from sensor 610, oil, water, or gas is being pumped into and passing through the sensor. And, based on such determination, the operation of the pumping unit may be continued, stopped, or otherwise adjusted, as appropriate. As an example, upon detection of oil pumping, the operation of the pumping unit is continued, while upon detection of water or gas, the operation of the pumping unit can be stopped or modified. In one embodiment, the system determines or discriminates the type of fluid in the sensor based on the pressure and capacitance signals generated by the sensor. For example, the system may apply one or more of the following rules:

a) oil = high pressure stroke combined with low capacitance;

b) water = high pressure stroke combined with high capacitance; and/or

c) gas = low pressure stroke combined with low/fluctuating capacitance.

As illustrated in FIG. 20, for example, each stroke of the pumping unit creates an ejection pressure in the differential pressure (610) between the inlet and outlet of the sensors (630 and 640, respectively). And, as the fluid moves from oil to water, at approximately 80 s in the flow chart, the change in pressure profile (slight decrease in peak pressure due to water) coincides with a similar increase in measured capacitance (also consistent with water instead of oil present). in a two-dimensional Venturi tube).

As illustrated in FIG. 21, the observed differential (or absolute) pressure initially increases (eg, in pressurization region 410) above the nominal level when the pumping unit starts up and begins pumping fluid through the transducer. And when the accumulated well fluid has been pumped out (eg, the pumped out area 420 of the well), the pressure is reduced back to near the nominal pressure, as shown in FIG. 22.

Fig. 23 is provided to illustrate how the controller logs a time series for a full pump cycle. Data collection creates the opportunity for post-processing to calculate oil volume/water cut data, which can then be used to help improve measurement accuracy. At any time a fluid is pumped out of a well, it is contemplated that the fluid may be a combination of oil and water. Typically, the oil water cut is the ratio or percentage of the oil/water mixture that has been pumped out. For example, for well performance testing (see, for example, FIG. 23), more than 95% of the injected fluid may be water. Accordingly, the oil water cut can be characterized as 95%. The applicability and analysis of data collected over complete pumping cycles facilitates the use of technical experience, including comparison against historical data and identification of the nature of the process within the data, which facilitates the adjustment of control parameters based on past performance data for the pumping unit / wells. Also, as suggested above and in FIG. 24, data from the sensor may also be used to allow the system to determine the presence of gas or foam within the fluid pumped from the well and passed through the sensor. For example, area 430 on the graph shows a combination of low pressure plus low/fluctuating capacitance, which may indicate the presence of foam or gas.

Oil production system

With both the oil production apparatus and the recovery control system described, configured for use in the oil field 1110, attention is now directed to FIG. 25-27. Shown in FIG. 25 are a plurality of wells 1120 each associated with a pump or other mechanism for extracting and collecting fluids (including oil) from the well. At least one of the wells also has a ground level monitoring system 1130, such as shown in FIG. 14-19 operatively associated with the well, whereby the monitoring system is capable of generating data indicative of the amount of oil produced from the well 1120. The ground level monitoring system may also be capable of storing or transmitting data indicative of the volumes of oil and additional information. to the remote terminal 1150 via one or more communication channels (wired, wireless (eg, satellite, microwave, WiFi, etc.)). Remote terminal 1150 includes both a computer system and a data storage system, where the computer system is capable of parsing and analyzing collected data from one or more wells in oil field 1110 in order to evaluate the performance of the field and individual wells over time and over time. according to different processes and treatments. One such treatment may include the application of seismic or sonic wave energy to stimulate the oilfield so as to increase well recovery and thereby improve the overall performance of the oilfield.

Referring also to FIG. 26 depicted herein is an oil recovery system 1210 where an oil recovery device 110 is applied within a wellbore 1240 (eg, at or below fluid level) and controlled by the system 1250 as depicted in FIG. 26. The oil production system 1210 for improving oil recovery in the reservoir includes a pressurized fluid source 1260, an oil submersible device 110 for transmitting seismic wave energy in the oil reservoir 1110, in a waveform, so as to change the capillary forces of the residual oil in there, and a control system 1250 configured to monitor and control system components including at least an oil recovery device and a source of pressurized fluid to create or generate seismic/sound wave energy in the formation. The oil recovery device 110 includes a housing and a frameless, brushless motor operatively disposed within the housing as detailed above to receive pressurized fluid and, in response to electrical energy, generate seismic/sound wave energy waves. by releasing pressurized fluid through the in-line openings of the rotor and stator.

The pressurized fluid source includes a reservoir 1264 of a renewable fluid (eg, water), a pressurization system for pressurizing the fluid from the reservoir and passing the pressurized fluid through conduit 1268 to the oil recovery device 110. The pressurization system includes a pump 1272 driven by a motor 1270 in combination with a filter 1274 along with at least one sensor 1276 (e.g., pressure (P) of fluid supplied from the pump, flow rate (F) of fluid supplied to oil production device, current (A) of the pump motor, backpressure (PB) of the fluid on the filter, etc.), generating a signal and supplying this signal to the specified control system.

As illustrated in FIG. 26, the control system 1250 further includes a programmable logic controller 1280, a single board computer 1282, and at least one transceiver for external communication (Tx/Rx 1284) (for example, WiFi, Bluetooth, Ethernet, satellite modem (Irridium). The programmable logic controller uses a multi-core microcontroller and provides low-level control by interfacing and providing control signals and/or power (e.g., control/contactor for motors) to both of the motor pump 1270 and the frameless, brushless motor in the oil recovery device 110, and where the single board computer is operatively connected, to exchange commands and data with the PLC to execute various operations of the oil production system 1210 in order to stably produce seismic wave energy.In one embodiment, the single board computer 1282 uses the Linux operating system, and the stored software tools Actions are used for many functions. As will be appreciated, the oil production system, by means of a transceiver for external communication, and in connection with a single board computer, enables both autonomous and remote control of the oil production system. Such remote control may be executed by remote terminal 1150 as shown in FIG. 25, whereby the operation, regulation, and monitoring of the system 1210 can be performed remotely or at a centralized control desk. Among other data, the oil production system enables remote monitoring of the operating parameters of the system (e.g., sensor data, status monitoring, system faults, etc.) and facilitates the remote generation of commands to adjust certain parameters (e.g., restoring device engine speed ( The suitability for controlling the operation of an oil recovery device has the potential to eliminate the time and expense of performing preliminary studies of an oil field in order to determine in advance the desired performance. oil production can be located inside the field and, by means of previously described control equipment, operations can be controlled and regulated in such a way as to optimize performance and tune them for the oil field.

In order to ensure reliable performance, various system components can be optimized. For example, conduit 1268 used to provide pressurized fluid to oil recovery apparatus 110 is capable of moving fluid at pressures of up to at least 1500 psi (10 MPa), although normal operating pressures are substantially in the range from about 250 to about 350 pounds per square inch (1.7-2.4 MPa). Further, in one embodiment, the tubing may be formed from a flexible (coilable) material capable of being repeatedly wound and unwound on a bobbin to raise and lower the device within the wellbore, where the tubing further serves as a releasable connection attached to an oil recovery device and configured to lower and raise it relative to the wellbore 1240 to control its depth. Alternatively, instead of being flexible, the conduit may be formed from a substantially rigid material (e.g., stainless steel stringers with end-to-end conduit assembly), where the stainless steel stringers, by assembly, serve as a composite connection and are capable of lowering and raising a device for oil production relative to the wellbore.

Thus, the system shown in Fig. 25-25 is capable of generating sound waves within a fluid to stimulate oil production in an oil reservoir. The system includes a pressurized fluid source 1260, where the source includes a reservoir 1264 of renewable fluid (e.g., water) and a pressurization system (motor 1270, pump 1272, filter 1274, and sensors 1276) to maintain pressurized fluid from the reservoir and pass pressurized fluid through a conduit, conduit 1268 terminating at the opposite end of the oil recovery device 110. And, as described above, the oil recovery device is essentially limited to an elongated, and essentially cylindrical body, configured to pass through the wellbore. The device also includes a battery; power transmission section

- 10 041160 (which may include a pressure transmission valve), a frameless motor, a hollow shaft rotor having an outlet, and a stator having a corresponding outlet, whereby fluid energy is transferred after the rotor and stator holes are aligned, and where the frameless motor is functionally connected to the hollow shaft rotor in such a way that the fluid passes through it to the accumulator. The frameless motor is powered from the surface by a programmable logic controller through current-carrying wires connected to the pipeline.

As described, the oil recovery device and the frameless motor thus function as a pressure transfer valve, where pressurized fluid is stored inside the accumulator and then transferred through openings to the environment, whereby seismic wave energy is released into the fluid surrounding the device. The control system 1250 is configured to monitor and control at least the oil recovery device and a source of pressurized fluid in order to generate seismic waves in the formation. The oil production system 1210 generates a seismic wave at a frequency between about 10-100 Hz, and more preferably between 20-40 Hz.

As will be appreciated, the programmable logic controller 1280 and the single board computer 1282 each include respective software instructions for their operation, and the single board computer includes software instructions configured to interface and control certain operations of the programmable logic controller. As previously described with respect to FIG. 27, the system may also include a remote computer or computing center 1150, a remote computer including an information storage medium configured to store program instructions, where these instructions facilitate remote communication with the single board computer 1282 via a communication channel selected from the group consisting of WiFi , Bluetooth®, Ethernet and satellite modem. When using a remote computer, it is possible to both monitor well production using the ground level monitoring system 1130 and control and adjust the seismic output of the oil production device 110 in order to optimize the output of the oil field 1110.

The various components described with respect to system 1210 depicted in FIG. 25-27 are required to function in a reliable manner even during fluctuations and power outages. In order to ensure that the system 1210 is operational or returns to operation after a shutdown, the programmable logic controller and/or single board computer includes non-volatile memory (NVM) configured to store data generated by the system. In one embodiment, the stored data includes an indication of whether the system restarts after one of at least two events (eg, a scheduled power down or an accidental power down).

With reference to FIG. 27, the upper portion of the figure shows a ground level monitoring system 1130 providing output from a sensor, such as a venturi type sensor, where the data can be processed (e.g., classified) by a processor 1252 so as to characterize the amount or rate of oil produced. from the respective well. The oil production data is then passed through or further processed (e.g., by remote terminal 1150) where the oil production data is compared and contrasted and an algorithm or other artificial intelligence operation can be applied to determine whether the production system 1210 should be adjusted for performance. oil, whereby the remote terminal can provide a change of new parameter settings (eg, frequency, pressure, depth) back to the system in order to optimize the performance of the oil field. It should further be appreciated that a remote terminal may process input from multiple well monitoring systems and that oil production data from such monitoring systems may be simultaneously applied to optimize the production of a number of wells in a field, even though one or more wells may not be themselves themselves are optimized. Thus, the classifier (eg, processor 1252) analyzes the raw data from the Venturi sensors in the monitoring system 1130 to automatically determine the movement of oil/water and summarize the oil production from the sensor data. The oil production data is then fed to a remote terminal where an advanced algorithm and/or artificial intelligence system combines the production data and sets the output of the oil production system and device automatically to optimize oil field performance in an autonomous manner.

As another alternative, some or all of the components shown in FIG. 25, including a motorized reel 1300 for raising and lowering the flexible conduit, can be mounted on a trailer to make the system 1210 more portable. Also, in the presence of environmentally portable working equipment, alternative, identical and/or redundant power supply systems can also be switched on, so that downtime due to power interruptions in relation to system location can be reduced or eliminated.

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Claims (19)

It should be understood that various changes and modifications to the embodiments described herein will be apparent to those skilled in the art. Such changes and modifications may be made without departing from the spirit and scope of the present invention and without diminishing its intended advantages. Therefore, it is intended that all such changes and modifications be covered by this invention. CLAIM 1. An oil recovery system for improving the recovery of oil in an oil reservoir, comprising a pressurized fluid source located outside the oil reservoir; a submersible oil recovery device for transmitting seismic wave energy in an oil reservoir in a waveform so as to change the capillary forces of the residual oil at that location, comprising the housing; pressurized fluid storage accumulator; a hollow shaft motor operatively located in said housing to receive pressurized fluid and generate seismic waves; a hollow shaft rotor having an outlet, the motor hollow shaft being operatively connected to the hollow shaft rotor for passing a pressurized fluid through the hollow shaft to the accumulator; a stator having an outlet corresponding to the outlet of the rotor for transmitting pulsating energy of the fluid from the housing while aligning said outlet of the rotor and the outlet of the stator; and a control system configured to monitor and control components of the system, including at least the rotation of a rotor in the oil recovery device and a source of pressurized fluid to generate seismic waves in the oil reservoir. 2. The oil production system according to claim 1, in which the specified source of fluid under pressure contains a container for renewable fluid; a pressurization system for pressurizing the fluid from said fluid reservoir and passing the pressurized fluid through a pipeline to the oil recovery device. 3. The oil production system of claim 2, wherein said pressurization system comprises a pump in combination with a filter, along with at least one sensor to generate a signal and feed said signal to said control system. 4. The oil production system according to claim 1, in which the specified control system contains a programmable logic controller; a single board computer and at least one transceiver for external communication, wherein the programmable logic controller provides low-level control by interfacing and providing control signals and/or power to both of the motor pump and the motor in the oil recovery device, and wherein the single board computer is operatively connected, to exchange commands and data with the programmable logic controller to execute various operations of the oil production system to stably generate seismic wave energy. 5. The oil production system of claim 4, wherein said external communication transceiver, in conjunction with said single board computer, enables both offline and remote control of the oil production system. 6. The oil production system of claim 2, wherein said pipeline is capable of moving fluid at a pressure of up to at least 1500 psi (10 MPa). 7. The oil production system of claim 6, wherein said pipeline is formed from a flexible material capable of being repeatedly wound and unwound on a bobbin. 8. The oil production system of claim 7, wherein said pipeline further serves as a detachable connection to the oil production device and is configured to lower and raise it relative to the wellbore. 9. The oil production system of claim 6, wherein said pipeline is formed from a substantially rigid material. 10. The oil production system of claim 9, wherein said conduit further serves as a releasable connection to the oil production device and is configured to lower and raise it relative to the wellbore. 11. System for generating sound waves in an environment to stimulate oil production in oil- - 12 041160 nom reservoir, containing a source of fluid under pressure, and the specified source of fluid under pressure contains a reservoir for renewable fluid located outside the oil reservoir, and a system for creating pressure to maintain an increased pressure of the fluid from the specified reservoir for fluid and transmission pressurized fluid through a conduit terminating at an opposite end of the oil recovery device, said oil recovery device comprising an elongated and substantially cylindrical body operable through the wellbore; an accumulator for storing pressurized fluid; a power transmission section comprising a motor using a hollow shaft and a pressure transfer valve comprising a hollow shaft rotor having an outlet, the motor hollow shaft being operatively connected to the hollow shaft rotor to pass pressurized fluid through the motor hollow shaft to the accumulator, and a stator having an outlet corresponding to the outlet of the rotor for transmitting fluctuating fluid energy while aligning said outlet of the rotor and the outlet of the stator, thereby generating a seismic wave in the oil reservoir by transmitting the pulsed fluid energy through the outlets; and a control system configured to monitor and control at least the oil production device and the pressurized fluid source. 12. The system of claim 11 wherein said seismic wave produced by the oil recovery device has a frequency between about 10-100 Hz and more preferably between 20-40 Hz. 13. The production system of claim 11, wherein said pressurization system comprises a pump in combination with a filter, together with at least one sensor to generate a signal and feed said signal to said control system. 14. The system according to claim 13, in which the specified control system contains a programmable logic controller; a single board computer; and at least one transceiver for external communication, wherein the programmable logic controller provides low-level control by interfacing and providing control signals and/or power to both of the motor pump and the motor in the oil recovery apparatus, and wherein the single board computer is operatively connected to exchange commands and data with the programmable logic controller to execute various operations of the oil production system to stably generate seismic wave energy. 15. The oil production system of claim 14, wherein the external communication transceiver, in conjunction with said single board computer, enables both offline and remote control of the oil production system. 16. The oil production system of claim 14, wherein said PLC and said single board computer contain appropriate software instructions for their operation, and wherein said single board computer includes software instructions configured to interface and control certain operations of the programmable logic controller. 17. The oil production system according to claim 16, further comprising a remote computer that includes an information storage medium configured to store program instructions therein, these program instructions facilitate remote communication with a single-board computer via a communication channel selected from the group, consisting of WiFi, Bluetooth®, Ethernet and satellite modem. 18. The system of claim 16, wherein at least one of said programmable logic controller and said single board computer includes a non-volatile memory (NVM) configured to store data generated by said system, said stored data including an indication, executes whether the system is restarting after one of at least two cases. 19. A method for generating seismic wave pressure energy in oil-saturated formations, comprising the steps of placing a wave generator in contact with a fluid in the formation; providing a source of pressurized fluid, wherein said source of pressurized fluid comprises a renewable fluid reservoir located outside the oil reservoir and a pressurization system for maintaining pressurized fluid from said fluid reservoir and passing pressurized fluid through a pipeline to the gene -