FLOW RATE MEASUREMENT TOOL BASED ON FLUID TRANSIT IN WELLS WITH POLYMER INJECTION, SEALING AND RECHARGING SYSTEM OF SAID TOOL, FLOW RATE MEASUREMENT METHOD USING SAID TOOL AND SIGNAL PROCESSING METHOD

Description

FIELD OF THE INVENTION

The present invention relates to the measurement of flow rate in polymer wells in enhanced oil recovery (EOR) projects. More specifically, the invention concerns a flow rate measurement tool based on fluid transit, a sealing and refilling system for said tool, a method for measuring flow rate using said tool, and a signal processing method applied to the signals obtained by a fluid transit tool, in order to determine the flow rate in polymer injector wells for tertiary oil recovery.

BACKGROUND OF THE INVENTION

The logging of radioactive tracers using a Tracer Log tool or a fluid transit tool is a conventional method for determining flow rates during secondary recovery (i.e., water injection wells). In this method, a radioactive tracer is injected into the main injection flow rate (water). Two radiation detectors are placed downstream to measure the transit time between both detectors. Since the geometry of the tubing and the tool (i.e., diameter and distance between detectors) is known in advance, the flow rate can be calculated by processing the sensor signals using the theoretical framework developed by G. I. Taylor, as described in his referenced work.

In both secondary and tertiary or enhanced oil recovery, the accuracy and reliability of injection flow rate measurements are critical for optimizing the injection process and supporting decision-making. However, when this technology is applied to polymer injection wells in EOR, it produces unclear or even contradictory results. The resulting curves are often irregular, as the high viscosity of the polymer solution induces laminar flow rate within the injector well, which hinders homogeneous tracer mixing and complicates the interpretation of the logs.

Several published works address different aspects of flow rate measurement using radioactive tracers in a main water flow rate, such as “Tracer-placement techniques for improved radioactive-tracer logging” by Hill, A. D., et al., and “Measurement of water flow rate in closed conduits-Tracer Methods-Part VII: Transit time method using radioactive tracers” from ISO standard 2975-7. These studies consist of an analysis demonstrating the influence of the tracer injector's positioning on the resulting curves used for flow rate measurement (Hill, A. D., et al.), and a standard outlining the various methods for interpreting such curves (ISO 2975-7). On the other hand, the work titled “Diffusion and Mass Transport in Tubes” by G. I. Taylor is a pioneering work showing the influence of flow rate regimes on the dispersion and diffusion behavior of a tracer within a primary water flow rate.

The aforementioned studies are exclusively focused on tracer dispersion in a main water-based flow rate. Although a few publications address the challenges associated with flow rate measurement in polymer injection streams—such as “Injection Profiling in Polymer Injectors in Daqing Oilfield” by Zheng, Hua et al.—they fail to provide technical specifics that would enable the rapid development of a reliable measurement technology.

At first glance, it may appear that the fundamental problem in achieving accurate and reliable flow rate measurements in polymer injector wells lies in ensuring proper mixing between the main flow rate fluid with the tracer-injected fluid. However, studies indicate that achieving such proper mixing is not always feasible.

There are tests and simulations showing that the tracer-based flow rate measurement system provides reliable results for turbulent flow rates, thus yielding accurate flow rate measurements. In contrast, for laminar flow rate—which is the type of flow rate observed at the flow rates typical of polymer injection wells—the result (the measured flow rate) strongly depends on the manner in which the tracer jet penetrates the main stream. The tracer penetration distance depends not only on the injection pressure but also on the main flow rate, which is precisely the parameter being measured. Moreover, the penetration distance and the shape of the injected jet—whether it forms a plume-like configuration, which promotes tracer mixing with the flow rate, or a filamentary form, with low mixing tendency—depend on the viscosity of the fluid into which the tracer jet is injected. This indicates a higher degree of complexity compared to conventional log-reading methods and explains why results are not repeatable unless the injection is performed in a controlled manner. Controlled injection cannot be ensured during field operation, given the inherent uncertainties of the process, such as not knowing exactly how the tool is positioned within the well, among others. Moreover, the variability of well-reservoir systems with perforations at different depths and in layers with varying intake capacities (commonly known as multilayer systems) further complicates the readings as depth increases. At greater depths, fluid properties change due to pressure and temperature variations, while the flow rate to be measured decreases. This is because part of the total injected flow rate escapes through each layer depending on its intake, thereby defining what is known as the “system intake profile,” in which the total injected flow rate partially escapes through some or all layers until fully discharged.

The radiation detectors or sensors of the fluid transit logging tool provide data in the form of radiation level curves, which relate to the presence and passage of the radioactive tracer. These curves (signals) are mathematically interpreted using known methods, as described in the references cited above, which perform adequately in the context of water injection wells. These methods rely on comparing the barycenters and peaks of the signals detected by both sensors. However, such methods assume an initial tracer distribution that is only achievable when the stream to which the tracer is injected turbulent (as in the case of water injection), but not when dealing with the laminar flow rate of a polymer solution. Other methods rely on comparing first arrivals to measure the transit time, but in the context of polymer injection, it cannot be guaranteed that first-arrival-based methods or any other traditional curve interpretation method will yield reliable results, or even obtain acceptable repetitive flow rate estimates for the same well, the same wellhead flow rate, and under similar conditions in general. Furthermore, when the received signals are generated from the commonly used tool, the power with which the ejection is carried out through the single tracer fluid ejector orifice of the state-of-the-art fluid transit tool is not sufficient to achieve an adequate initial tracer distribution and thus obtain a flow rate estimate with some signal interpretation method or combination thereof.

Therefore, there is a need to provide flow rate measurement means based on fluid transit that enable repeatable and reliable determination of flow rates in polymer injection wells used for tertiary recovery.

BRIEF DESCRIPTION OF THE INVENTION

Based on the foregoing considerations, the present invention provides a fluid transit-based flow rate measurement tool that enables controlled ejection of tracer fluid, a sealing and recharging system for said tool, a flow rate measurement method using said tool, and a signal processing method for obtaining the flow rate in polymer injection wells for tertiary recovery, wherein said tool and methods allow for the repeatable and reliable determination of polymer solution flow rate within an injection well.

Accordingly, in a first aspect, an object of the present invention is a fluid transit-based flow rate measurement tool for polymer injection wells, comprising:

• • an ejection assembly comprising:
    • a motor that drives, through a reduction gearbox, a rod connected to a plunger,
    • a retraction chamber and an ejection chamber separated by the plunger, said
    • retraction and ejection chambers defining an inner volume of the ejection assembly, and
    • an ejection body comprising the ejection chamber,
    • wherein said retraction chamber comprises a plurality of pressure equalization holes,
    • wherein said ejection body comprises a plurality of angularly spaced ejection holes, and
    • wherein said ejection chamber allows for storing a radioactive tracer fluid;
  • a first detection assembly comprising a first radiation sensor or detector, the first detection assembly being located downstream of the ejection assembly.
  • a second detection assembly comprising a second radiation sensor or detector, the second detection assembly being located downstream of the first detection assembly; y
  • control means that allow for motor operation and consequently the movement of the plunger, enabling the ejection of tracer fluid through the plurality of ejection holes in the form of shots.

In one embodiment of the tool of the present invention, the plurality of ejection holes comprises four ejection holes.

In one embodiment of the tool of the present invention, each ejection hole has a diameter ranging from 0.30 mm to 0.50 mm, preferably 0.50 mm.

In one embodiment of the tool of the present invention, the distance between the plurality of ejection holes and the first radiation sensor is between 3.5 m and 5.5 m, preferably between 4.5 m and 4.9 m.

In one embodiment of the tool of the present invention, the distance between the first radiation sensor and the second radiation sensor is between 1 m and 1.5 m, preferably between 1.1 m and 1.3 m, and more preferably, 1.18 m.

In one embodiment of the tool of the present invention, each of the first and second radiation sensors is a Geiger sensor.

In one embodiment of the tool of the present invention, the ejection chamber comprises a volume of between 20 ml and 30 ml, preferably 20 ml.

In one embodiment of the tool of the present invention, the reduction gearbox provides a transmission ratio of 14:1 or 23:1, preferably 14:1.

In one embodiment of the tool of the present invention, said tool further comprises at least one weight bar.

In a second aspect, an object of the present invention is a sealing and recharging system for the tool according to the first aspect, comprising:

• • a clamp comprising an upper body and a lower body joined together by a hinged connection located on one side thereof, the upper body having a through-hole and a plurality of centering projections, preferably two centering projections, and the lower body having a plurality of though-holes, preferably three through-holes, and a plurality of centering projections, preferably two centering projections, wherein the centering projections are evenly distributed around the clamp and extend radially inward the clamp allowing to hold and keep the tool centered with respect to the clamp;
  • a funnel located in the through-hole of the upper body of the clamp, said funnel allowing for the storage of radioactive tracer fluid;
  • three fastening means, each located in the through-holes of the lower body of the clamp, each fastening means comprising a lever and a rod with a rubber stop; and
  • a quick-closing mechanism comprising a spring and linking the upper and lower bodies of the clamp, ensuring its closure.

In one embodiment of the system of the present invention, the centering projections are spaced 72° apart.

In a third aspect, an object of the present invention is a fluid transit-based flow rate measurement method in polymer solution injection wells, wherein the method comprises the following steps:

• • lowering the fluid transit-based flow rate measurement tool according to the first aspect through an injection well to a determined depth;
  • performing at least one shot of radioactive tracer fluid from the tool, once polymer solution is being injected through said injection well;
  • obtaining signals from the first radiation sensor and the second radiation sensor; and
  • processing the signals obtained from the first radiation sensor and the second radiation sensor, wherein the processing of the signals comprises:
    • applying a plurality of flow rate determination techniques and obtaining respective flow rate values from said flow rate determination techniques, and
    • weighting the flow rate values so as to obtain the polymer solution flow rate in the well at the determined depth.

In one embodiment of the flow rate measurement method, the plurality of flow rate determination techniques comprises up to thirteen flow rate determination techniques selected from the group consisting of area-under-the-curve techniques and fractions thereof, first arrival techniques, techniques based on time intervals between maximums, cross-correlation techniques on the signal and its time derivatives, and techniques based on the initial slope of the curves. Preferably, the plurality of flow rate determination techniques consists of four area-under-the-curve techniques and fractions thereof, three first arrival techniques, one technique based on time intervals between maximums, two cross-correlation techniques on the signal and its time derivatives, and three techniques based on the initial slope of the curves.

In one embodiment of the flow rate measurement method, the tool is connected by cable to a control system that allows control of the tool and the power supply to the tool, wherein said tool control comprises controlling the depth to which the tool is lowered and operations such as shot time, initiation of the ejection chamber recharge, and shot initiation.

In a fourth aspect, an object of the present invention is a signal processing method for fluid transit-based flow rate measurement in polymer solution injection wells, wherein the method comprises the following steps:

• • obtaining signals from radiation sensors of a fluid transit tool located at a determined depth within a polymer injection well; and
  • processing the signals obtained from said radiation sensors, wherein the processing of the signals comprises:
    • applying a plurality of flow rate determination techniques and obtaining respective flow rate values from said flow rate determination techniques, and
    • weighting the flow rate values so as to obtain the polymer solution flow rate in the well at the determined depth.

In one embodiment of the signal processing method, the plurality of flow rate determination techniques comprises up to thirteen flow rate determination techniques selected from the group consisting of area-under-the-curve techniques and fractions thereof, first arrival techniques, techniques based on time intervals between maximums, cross-correlation techniques on the signal and its time derivatives, and techniques based on the initial slope of the curves. Preferably, the plurality of flow rate determination techniques consists of four area-under-the-curve techniques and fractions thereof, three first arrival techniques, one technique based on time intervals between maximums, two cross-correlation techniques on the signal and its time derivatives, and three techniques based on the initial slope of the curves.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows a schematic view of the fluid transit-based flow rate measurement tool of the present invention.

FIG. 2A shows a perspective view of the ejection assembly of the fluid transit-based flow rate measurement tool of the present invention. FIGS. 2B to 2D show a longitudinal section of the ejection assembly of FIG. 2A, said longitudinal section being divided into a first part (FIG. 2B), a second part (FIG. 2C), and a third part (FIG. 2D). FIGS. 2E to 2G show a longitudinal section, at 45 degrees with respect to the previous section, of the ejection assembly of FIG. 2A, said longitudinal section being divided into a first part (FIG. 2E), a second part (FIG. 2F), and a third part (FIG. 2G).

FIGS. 3A to 3D show perspective and side views of one embodiment of the ejection body.

FIGS. 4A, 4B and 4C show a perspective view and longitudinal sections, respectively, of one embodiment of a threaded ejection bolt. FIG. 4D shows a cross-section of the ejection body with the ejection bolts in place.

FIG. 5A shows a perspective view of the main body of the clamp of the sealing and recharging system of the present invention. FIGS. 5B and 5C show a front view and a longitudinal section, respectively, of the upper body of the clamp, while FIGS. 5D and 5E show a front view and a longitudinal section, respectively, of the lower body of the clamp. FIGS. 5F and 5G show two perspective views, respectively, of the funnel of the sealing and recharging system of the present invention. FIG. 5H shows the entire clamp assembly already positioned, securing the tool in the required manner for the loading operation.

FIG. 6 shows the method of the fluid transit-based flow rate measurement tool of the present invention

FIG. 7 shows a graph with the signals produced by the radiation sensors of the tool of the present invention in a polymer flow rate measurement assay.

FIG. 8 shows a graph with the flow rate values obtained after processing the signals collected by the radiation sensors in a pilot test for measuring the flow rate in a well with polymer injection through the tubing thereof.

FIG. 9 shows a graph with the flow rate values obtained after processing the signals collected by the radiation sensors in a pilot test for measuring the flow rate in a well with polymer injection through the casing thereof.

FIGS. 10A and 10B show graphs of the signals obtained from flow rate measurements in the tubing (FIG. 10A) and in the casing (FIG. 10B) using the tool of the present invention.

FIGS. 11A and 11B show graphs of the signals obtained from flow rate measurements in the tubing (FIG. 11A) and in the casing (FIG. 11B) using the tool of the present invention.

FIG. 12 shows the curves obtained using a simulator developed to estimate the shape of the signals depending on certain variables such as pipe diameter, angular positioning of the tool inside the pipe, viscosity, and flow rate.

FIG. 13 shows a histogram of coefficients by which the time differences must be affected for one of the flow rate estimation methods based on the first arrivals. The most probable coefficient is taken considering the shape of the distribution. In this case, the distribution is fitted using a log-normal function.

FIG. 14 shows a histogram of coefficients by which the time differences must be affected for another calculation method based on the signal from the first sensor. The most probable coefficient according to each method is taken considering the shape of the distribution. In this case, the distribution is fitted using a Gaussian function.

DETAILED DESCRIPTION OF THE INVENTION

Unless otherwise indicated, it should be understood that all numbers expressing quantities of elements, operating conditions, properties, etc., used in the specification and in the claims are modified in all instances by the term “approximately.” At a minimum, each numerical parameter must be considered at least in light of the number of significant digits reported and by applying ordinary rounding techniques. Accordingly, unless otherwise indicated, the numerical parameters presented in the specification and in the appended claims are approximations that may vary depending on the properties sought. Although the numerical ranges and parameters that describe the broad scope of the embodiments are approximations, the numerical values set forth in the specific examples are reported as precisely as possible. However, any numerical value inherently contains certain errors resulting from variations in experiments, test measurements, statistical analyses, etc.

For the purposes of the present description, the term “approximately” or “around” and grammatical variations thereof mean a quantity, level, degree, value, number, frequency, percentage, dimension, size, weight or length, as appropriate, that varies by as much as ±20, ±15, ±10, ±9, ±8, ±7, ±6, ±5, ±4, ±3, ±2, or ±1% from a cited quantity, level, degree, value, number, frequency, percentage, dimension, size, weight or length.

Hereinafter, the invention will be described in detail with reference to the attached figures, for a better understanding of the invention and not for the purpose of limiting its scope.

The tool, system, and methods of the present invention are described below with reference to FIGS. 1 to 14, where FIGS. 1 to 4D illustrate, by way of example, embodiments of the tool and system of the present invention and/or of the various elements or features that compose them. In such FIGS. 1 to 4D, the same numeric references are used to designate similar or identical elements of the tool of the present invention.

As used herein, the terms “tracer,” “radioactive tracer fluid,” “tracer fluid,” or similar terms are used interchangeably to refer to a radioactive tracer fluid that is injected into the main injection flow in an injection well, and that is used for determining the flow rate of said main injection flow. Additionally, as used herein, the term “polymer” or similar terms used in expressions such as “polymer flow rate measurement,” “polymer injection well” or similar, refers—unless the context clearly indicates otherwise—to a polymeric solution injected into wells for tertiary recovery purposes in order to enhance oil recovery from a reservoir.

FIG. 1 shows a schematic view of the fluid transit-based flow rate measurement tool 10 of the present invention. In particular, it can be seen that said tool 10 comprises a cylindrical body formed by various components, including an ejection assembly 11, a first detection assembly 12a, a second detection assembly 12b, weight bars 13a, 13b, and a casing collar locator (CCL) 14.

FIG. 2A, shows a perspective view of the ejection assembly 11. The ejection assembly 11 comprises several components, among which can be seen in FIG. 2A: an ejection body (or ejector) 20, four threaded ejection bolts 22, an equalizing body (or equalizer) 15, two threaded bolts 24 with equalizing holes, a protective housing for electronics and gearmotor assembly 16, a protective housing 17 for equalization and ejection chambers, and a protective housing 18 for electronics.

FIGS. 2B a 2D, show a longitudinal section of said ejection assembly 11, divided into a first part (FIG. 2B), a second part (FIG. 2C), and a third part (FIG. 2D). FIGS. 2E a 2F, show another longitudinal section of said ejection assembly 11 can be seen, carried out at 45 degrees with respect to the previous section, divided into a first part (FIG. 2E), a second part (FIG. 2F), and a third part (FIG. 2G). The ejection assembly 11 comprises a gearmotor assembly 25, comprised of a motor and a reduction gearbox, which drives a rod 26 connected to a plunger 27, said motor, gearbox, rod and plunger being located inside the ejection assembly 11; a retraction chamber 19, which is pressure-equalized with respect to the front of the piston, and an ejection chamber 28 separated by the plunger 27, said retraction chamber 19 and ejection chamber 28 defining an internal volume of the ejection assembly 11, and said ejection chamber 28 being downstream with respect to the retraction chamber 19; an ejection body (or ejector) 20 that connects, through ducts, said ejection chamber 28 with the orifices of the threaded ejection bolts 22. The retraction chamber 19, in turn, is pressure-equalized through two internal ducts located in the equalizing (or equalizer) body 15 that connect to the threaded bolts with equalizing holes 24. And two components for securing control electronics boards 29 and 33.

With reference to the ejection body 20, FIGS. 3A to 3D show an embodiment of the ejection body 20 comprising four holes 21 angularly spaced with respect to a longitudinal axis L of the ejection body. These four holes 21 are preferably spaced 90° from each other and comprise a respective thread that allows the respective threaded ejection bolt 22 to be inserted by threading.

Referring to the threaded ejection bolts, FIGS. 4A to 4C show a preferred embodiment of the ejection bolt 22. This embodiment comprises ejection holes 23 and a flat-head screwdriver slot 26. FIG. 4D shows a cross-section of the ejection body 20 illustrating four bolts 22 placed in operating position.

It should be noted that the embodiment of the ejection bolts illustrated in said FIGS. 4A to 4C should not be considered limiting, since said ejection bolts could have any other suitable geometric shape that ensures the absence of cavitation.

Each of the ejection holes 23 is located in the same plane transverse to the longitudinal axis L, and spaced 90° from the adjacent ejection hole with respect to the longitudinal axis L. Additionally, in any of the embodiments of the ejection bolt 22, the ejection holes 23 have a diameter between 0.30 mm and 0.50 mm, preferably 0.50 mm, as this allows the jet of tracer fluid being ejected to move further away from the tool.

With reference to the ejection chamber 28, it comprises a volume ranging from 20 ml to 100 ml, preferably from 20 ml to 50 ml, more preferably from 20 ml to 30 ml, and most preferably 20 ml (with the plunger, for example, having a diameter of 25 mm and a stroke length of 40 mm). In this way, the ejection chamber allows for the storage of a radioactive tracer fluid.

With reference to the retraction chamber 19 of the ejection assembly 11, it is connected, through two internal conduits in equalizer 15, to the pressure equalization holes in the pressure-equalizing threaded bolts 24, preferably, two threaded bolts 24 with pressure equalization holes located diametrically opposite one another in the equalization body 15 and, therefore, constituting the ejection assembly 11.

The threaded bolts 24 with pressure equalization holes allow the injection fluid (i.e., the polymeric solution) that is injected into the well to enter the retraction chamber 19 of the ejection assembly 11, ensuring that the plunger 27 does not have a pressure differential between its rear side (i.e., the face of the plunger 27 oriented toward the retraction chamber 19) and its front side (i.e., the face of the plunger 27 oriented toward the ejection chamber 28) when stationary. In this way, when the plunger 27 moves, it only needs to exert the force required to eject the tracer fluid without having to overcome the surrounding pressure, since the surrounding pressure acts on both the rear and front sides of the plunger.

The threaded bolts 24 with pressure equalization holes may comprise a mesh to prevent the entry of solid particles. If said pressure equalization holes do not include a mesh, they allow for better fluid passage into the retraction chamber.

The equalization body 15 comprises a size of equalization holes and a mesh opening size (in case it includes meshes) that reduce the possibility of blockage of the plunger due to the ingress of debris that could severely restrict the ejection of the tracer fluid as a consequence of the viscoelastic behavior of the polymer when faced with abrupt movements of the plunger.

With reference to the motor that drives the rod 26 connected to a plunger 27 through a reduction gearbox, the motor, and the reduction gearbox of the gearmotor assembly 25 are arranged upstream of the internal volume defined by the retraction chamber 19 and the ejection chamber 28. The motor is preferably a direct current (DC) motor, for example, a Faulhaber 2342R048CR motor. The reduction gearbox used allows the motor output speed to be reduced by a ratio of 14:1 or 23:1, preferably 14:1, in order to drive the plunger rod within the volume.

Referring to FIG. 1, the first detection assembly 12a and the second detection assembly 12b, located downstream of the ejection assembly 11, comprise within them a first radiation sensor and a second radiation sensor, respectively. Both radiation sensors are preferably Geiger sensors.

The first detection assembly 12a and the second detection assembly 12b are longitudinally spaced apart, with the second detection assembly 12b being located downstream relative to the first detection assembly 12a. Additionally, these detection assemblies 12a, 12b are also longitudinally separated from the plurality of ejection holes of the ejection body of the tool. In particular, the distance between the plurality of ejection holes and the first radiation sensor is between 3.5 m and 5.5 m, preferably between 4.5 m and 4.9 m. Meanwhile, the distance between the first radiation sensor and the second radiation sensor is between 1 m and 1.5 m, preferably between 1.1 m and 1.3 m, and more preferably, 1.18 m.

The first radiation sensor and the second radiation sensor allow the detection of the tracer fluid that is ejected through the ejection holes 21. In particular, once the tool 10 performs the tracer shot of fluid through the ejection holes 21, said tracer fluid mixes with the polymeric solution flow, which is injected and circulated through an injection well, and is first detected by the first radiation sensor of the first detection assembly 12a and then by the second radiation sensor of the second detection assembly 12b, both radiation sensors generating signals which, as will be seen in detail below, are processed to determine the flow rate of the polymeric solution at the depth at which the tool of the present invention is located.

With reference to the weight bars 13a, 13b, shown in FIG. 1, said weight bars allow the tool to descend through the well in a controlled manner, achieving adequate tension in the cable that allows the descent of the tool 10 through a given well. It should be noted that the tool 10 may have a different number of weight bars and in different configurations, as necessary. By way of example, the tool 10 could have a single weight bar instead of the two weight bars shown in FIG. 1; or it could have a weight bar between the ejection assembly 11 and the first detection assembly 12a, and a weight bar thereafter (i.e., downstream) of the second detection assembly 12b; or it could have two weight bars downstream of the second detection assembly 12b; among other possible variations.

In the case where there is one or more weight bars between the first detection assembly 12a and the ejection assembly 11, said weight bars are conductive of the signal from the radiation sensors. In contrast, in the case where weight bars are placed downstream of the second detection assembly 12b, said weight bars are non-conductive. In the case where there are weight bars between the first detection assembly 12a and the ejection assembly 11, it is important to know the quantity and length of said conductive weight bars, as this is relevant data for some of the signal processing methods which will be described in detail below.

With reference to locator 14, which is preferably positioned between the ejection assembly 11 and the first detection assembly 12a, as shown in FIG. 1, said locator 14 enables detection of coupling joints using a magnetic system and allows calculation of the exact depth at which the tool is located at all times.

The tool 10 further comprises control means that allow the actuation of the motor and consequently the movement of the plunger 27, allowing the recharging or refilling of the ejection chamber with tracer fluid from funnel 34, as described below, and the ejection or shot of tracer fluid through the plurality of ejection holes 21. In particular, the control means comprise an electronic board which preferably consists of an H-bridge built with N-channel and P-channel MOSFET transistors, IRFD9120 and IRFD110, respectively. In this way, the H-bridge allows the rotation of the motor in both directions and, due to its low impedance, is capable of handling the power required by the motor, even in the case of mechanical stress. Additionally, said electronic board allows the motor to be de-energized when the plunger reaches the end of its stroke.

Additionally, the control means comprise a microcontroller, for example, an Atmel attiny85 microcontroller, which enables the logical control of the electronic board and allows measurement of the line voltage and determination of the direction of motor rotation by activating one branch of the H-bridge when the voltage is lower than a certain voltage (for example, 26V) and the other branch of the H-bridge when the voltage is greater than said certain voltage (for example, 26V). The microcontroller's supply voltage is regulated using a combination of voltage regulators, for example, TL783 and TL7805 regulators, thereby allowing a wide and controlled range of input voltages to the microcontroller.

The control means of the tool of the present invention are connected to an external tool control system, external to the tool, and which may be housed inside an enclosure or inside a trailer or truck trailer, the latter being preferable. In the latter case, the tool control system is connected to the truck's electrical network of 220 V or 110 V.

The electronic board in the control means of the tool of the present invention and the tool control system are in data communication with each other. In this way, the tool control system not only enables control and operation of the tool of the present invention and the reception of information from it (for example, voltage applied to the motor, signals detected by the radiation sensors, etc.), but also supplies the necessary power to the tools control means. The tool control system of the present invention allows, among other things, greater power to drive the motor.

The tool control system comprises data acquisition means comprising a tool interface panel and a tool power control panel. The data acquisition means enable the acquisition of data (or signals) received from the radiation sensors of the tool, the interpretation and processing of said data, and their download to a PC. The tool power control panel may include instruments such as a voltmeter and an ammeter to monitor the voltage and current, respectively, in the tool.

The tool control system allows positioning of the tool at the desired depth and measurement of additional parameters such as the mechanical tension exerted on the tool cable, that is, the cable used to lower the tool.

The tool control system comprises command means for the tool that allow controlling the duration of the ejection (shot time) of the tracer fluid, being able to increase or decrease the shot time; the start of refilling the ejection chamber; and the start of the ejection or shot of the tracer fluid. Furthermore, the tool control system comprises a display where an operator can set the detection thresholds for positive and negative pulses associated with the radiation sensors in the tool.

The tool control system enables control of the voltage supplied to the tool through the tool power control panel. In this way, by controlling the voltage, the motor of the tool can be controlled to retract the plunger, which refills the ejection chamber of the tool with the tracer fluid when the tool is refilled outside the well, and to advance the plunger, which causes the ejection or shot of the tracer fluid through the ejection holes.

The tool control system comprises a controller, for example, an Arduino Nano V3 microcontroller, which connects the control system to the tool through relays in the presence of positive line voltages.

It should be noted that both the tool control system and the control means of the tool are transparent to the voltage that powers the radiation sensors and do not interfere with the pulse signal emitted by the radiation sensors as a result of detecting the radioactive tracer fluid. This is achieved by using voltages of different polarity for the sensors and for driving the electric motor.

It should be noted that the tool of the present invention is scalable and may have different sizes and/or lengths, for example, due to the size of the ejection chamber and/or the retraction chamber, or because the tool includes more or fewer weight bars, etc.

To perform the refilling of the tracer fluid into the ejection chamber, the tool of the present invention uses a sealing and refilling system that comprises a clamp; a funnel 34; three securing means; and a quick-release spring mechanism.

With reference to FIG. 5A, this shows the clamp 30 formed by an upper body 31 and a lower body 32 joined together by a hinged connection 31a that allows the upper body 31 to rotate relative to said hinge 31a and have relative movement with respect to the lower body 32.

The upper body 31 comprises a through-hole 31b and two centering projections 31c (as seen in FIGS. 5B and 5C), while the lower body 32 comprises three through-holes 32a and two additional centering projections 32b (as seen in FIGS. 5D and 5E). In this manner, the four centering projections 31c, 32b are evenly distributed around the clamp, extending radially inward, and enabling the securing and centering of the tool of the present invention. These centering projections 31c, 32b are preferably spaced 72° apart.

Referring to FIG. 5H, it shows the complete clamp assembly comprising bodies 31 and 32, the standard fastening components, for example, ARFIX brand (with ⅜ neoprene tips, Tcl1/4×44 Head Cap Screws, 5502a Quick Release with Spring and Arfix Af-sr42 Quick Fastener Clamp), and funnel 34 passing through the upper hole, the entire assembly already positioned, securing the tool 10 in the required manner for the loading operation.

Referring to funnel 34, shown in FIGS. 5F and 5G, it allows for storing the radioactive tracer fluid (e.g., Iodine-131) that will be used to refill the ejection chamber of the tool.

Regarding the three-fastening means, each comprises a lever and a rod with a rubber stopper (e.g., neoprene), which is actuated by the lever to exert pressure against the tool in order to fix its position and seal a respective ejection hole of the tool. As is evident, the lever also allows for quick release of the rod with the rubber stopper.

Finally, the quick-release mechanism with spring allows for securing the closure between the upper body and the lower body of the clamp, thereby preventing pivoting of the upper body. This mechanism, through its spring, provides a constant force that helps maintain tension and fastening, preventing unwanted movement of the components. Additionally, this mechanism facilitates quick opening when needed.

To reload the ejection chamber of the tool of the present invention using the sealing and reloading system, the tool is first placed on support points that allow it to be held and worked on. Then, one of the ejection bolts of the tool is removed, leaving the corresponding hole of the ejection body facing upward (in the highest position), thereby making this hole a reloading hole through which the ejection chamber of the tool will be refilled.

Silicone grease is applied to the ejection holes of the other three ejection bolts to seal these ejection holes, and then the clamp 30 is mounted around the tool, closing the bodies 31 and 32 around the section where the ejection holes and the reloading holes are located. The clamp must already comprise the three fastening means and the spring-loaded quick-release mechanism in place.

It is verified that the fastening means are aligned with the respective ejection holes and that the reloading hole is aligned with the corresponding port of the upper body 31, and the spring-loaded quick-release mechanism is closed. Subsequently, the funnel 34 is placed through the hole in body 31, said funnel 34 being threadedly connected to an extension that is threaded into the recharging hole. Then, the levers of the fastening means are actuated so that the respective rods press against the tool and seal the three ejection holes. It should be noted that the plunger inside the ejection chamber must be in its end-of-stroke position, ready to retract and proceed with reloading.

Next, funnel 34 is filled with radioactive fluid up to the level required to fill the ejection chamber, and funnel 34 is capped with an acrylic extension to allow air to escape without spilling fluid. Using the tool's control system, the motor is activated to retract the plunger (which generates a vacuum) and fill the ejection chamber.

Once the ejection chamber has been filled, the funnel 34 is removed and the previously removed ejection bolt is placed back, applying silicone grease to its corresponding ejection hole. The fastening means and the quick-release mechanism are then opened, the clamp is removed, and the tool is now loaded with tracer fluid and ready to be used in a polymer injection well.

In this way, the sealing and reloading system of the tool allows for the reloading of radioactive tracer fluid into the tool ejection chamber, minimizing and/or preventing the risk of leaks or spills of said radioactive fluid.

FIG. 6 shows the flow rate measurement method 60 by fluid transit in polymer injection wells for tertiary recovery. In particular, said flow rate measurement method 60 comprises step 61 of lowering the tool of the present invention through an injection well to a determined depth; step 62 of performing at least one shot of radioactive tracer fluid from the tool, once polymer solution is being injected through said injection well; step 63 of obtaining signals from the first radiation sensor and the second radiation sensor; and step 64 of processing the signals obtained from the first radiation sensor and the second radiation sensor, where the signal processing comprises applying a plurality of flow rate determination techniques (or flow rate estimation methods) and obtaining respective flow rate values from said flow rate determination techniques, and weighting the flow rate values to obtain the polymer solution flow rate at the determined depth in the well. It should be noted that step 64 is carried out by the tool control system.

The flow rate determination techniques consist of signal processing techniques of the two sensors both individually and comparatively. To process the signals, geometric data (e.g., pipe diameter, distance between sensors, distance from the injection point to the sensor, among others) and the rheology of the polymer solution must be known. The different techniques allow for the determination of characteristic time intervals. Each time interval, in order to reach the flow rate value, must be affected by coefficients that depend on the type of method considered and the fluid rheology. In this way, the measured time interval of each method can be linked to the time interval associated with fluid displacement at an average velocity. Once the average velocity is known, the flow rate determination results from considering the product of said average velocity with the flow rate cross-sectional area. Using this methodology, as many flow rate values are obtained as signal processing techniques used.

The most probable flow rate initially results from averaging the flow rates obtained with the different methods. However, it is better to consider the relative contribution of each method, so the calculation software of the tool control system obtains a weighted average by assigning different weights to each flow rate value obtained according to the method used, thus allowing more weight to be given to one or more flow rate determination techniques and less weight to other techniques.

The relative weight of each method is determined by considering a multiplicity of cases and is set within the software (although variable weights may also be established depending on the case). However, since the signal processing is carried out internally by the software based on the data entered by the operator, and considering that any of the thirteen techniques might yield an incorrect value, errors can occur in specific cases during signal processing. Therefore, criteria for discarding outlier values are applied when any of the techniques yields results with significant deviations from the flow rate at the wellhead, eliminating them from the weighted average, thus resulting in a weighted average with outliers discarded. In this way, contamination of the obtained average value by spurious values is avoided. The calculation software of the tool control system thus provides a weighted average of flow rates excluding outliers. A second weighted average of flow rates is also calculated, where the maximum and minimum values determined by the set of techniques are additionally excluded after outlier rejection. This second weighted average, obtained by discarding both outliers and then maximum and minimum values, is used to compare with the first one and determine a reliability coefficient. The closer these two values are, the higher the reliability of the measurement.

Once the flow rate is measured at the depth where the tool is located, said tool may be moved (i.e., lowered or raised) to any other depth to perform corresponding flow rate measurements at such other depth.

The flow rate determination techniques within the plurality of flow rate determination techniques in step 64 differ from one another in how they determine the average velocity of the radioactive tracer fluid ejected from the tool since, as previously mentioned, these techniques yield a characteristic time interval which is then multiplied by a coefficient (K) (which depends on the type of method used and the rheology of the fluid) to obtain the time interval associated with the average velocity, for subsequently considering a known displacement length, obtaining the injection flow rate of the polymeric solution is obtained.

Additionally, the plurality of flow rate determination techniques comprises up to thirteen flow rate determination techniques, which consist of area-under-the-curve techniques and fractions thereof, first-arrival techniques, techniques based on time intervals between maximums, cross-correlation techniques on the signal and its time derivatives, and initial slope of the curves techniques. Preferably, the plurality of flow rate determination techniques consists of four area-under-the-curve and fractions thereof techniques, three first-arrival techniques, one technique based on time intervals between maximums, two cross-correlation techniques on the signal and its time derivatives, and three initial slope of the curves techniques.

In particular, the weighting of flow rate values derived from these flow rate determination techniques allows for obtaining a flow rate value with a measurement error below 20%, which is considered more than acceptable in this technical field. This flow rate error estimation was obtained by conducting field tests considering flow rates measured at the wellhead using electromagnetic flowmeters and those obtained in the injection well before the first perforations. The obtained error includes, among other aspects, the uncertainty associated with the cross-sectional dimension of the conduit at each position due to, for example, incrustations or deformations that may alter the true value of this area. This last source of error is inherent to the system even when using the flow rate measurement tool known in the state of the art for water injection wells.

Referring to the flow rate determination techniques, as is well known in the field, the flow rate Q is obtained by considering the cross-sectional area orthogonal to the flow S_eff and the average velocity U_mean of the flow rate in the well. The area is computed by knowing the radius of the tool r_h and the radius of the conduit r_c through which the polymeric solution flows within the well. In particular,

S eff = π 4 · ( r c 2 - r h 2 ) ( 1 ) Q = S eff · U m ⁢ e ⁢ a ⁢ n ( 2 )

Additionally, as is well known in the field, the velocity U of the ejected tracer is obtained by dividing a distance L by a time difference δ t:

U = L δ ⁢ t ( 3 )

where the distance L is determined according to the data analysis strategy deemed appropriate, and may be the distance between both radiation sensors or a distance shorter than that between the ejection holes and the radiation sensors. This latter distance must take into account (either as a sum or a subtraction) the form factor of the sensors, since they do not fully collimate the signal and the sensors begin to indicate a signal before the radioactive tracer fluid actually passes in front of them. Determining this distance requires an initial calibration performed for a known flow rate.

To determine the average velocity U_mean it must be taken into account that there is a relationship between the velocity determined and the average velocity. The velocity (U) calculated according to expression (3) depends on the technique used to determine the time interval. For example, if it is assumed that this corresponds to the maximum velocity in the section (as in the case of the first-arrival technique), the relationship between this velocity and the average velocity must be considered. This relationship depends on the rheology of the flowing fluid and on the position of the tool. Given that the tool's position within the injection well is unknown, only the most probable relationship between the average velocity and the value of velocity U can be known. It is worth noting that if the tool were always in a fixed position, for example, centered, this relationship would be unambiguous. To find the most probable value, the tool control system uses a numerical signal simulator for each sensor, which assumes that the tool axis is always parallel to the axis of the conduit but positioned at any radial location and with any relative orientation of the injectors. This simulator also assumes that the flow in the passage section is laminar (as is typical for polymer solutions) and that the tracer jet emitted from each ejection orifice travels across and impacts the opposite wall. Under these conditions, for a given rheology, the downstream signals read by each sensor are unique. Thus, for different situations (tool positions and fluid rheology), different relationships can be established between velocities U and the average velocity (U_mean); that is, ultimately, a distribution of coefficients (K) by which the value of U must be adjusted to obtain the value of U_mean. The set of coefficients obtained for the various analyzed scenarios results in a distribution of coefficient values around the most probable value, which is used as a reference for calculations. These different tool positions are randomly generated in the simulator and, preferably, in a number not less than 1,000 cases. The numerically obtained coefficients are then corrected/contrasted against values obtained in injection wells where the wellhead flow rate is known (e.g., prior to perforation). This correction allows for consideration of, among other factors, misalignment between the axis of the tool and that of the conduit.

The determination of the K coefficients is developed based on a simulator that estimates the signal shapes of a pair of sensors 1 and 2 depending on the flow rate, viscosity, and orientation of the tool in the pipe (direction in which the injector holes are positioned). Based on fluid dynamics calculations, it is possible to estimate the approximate shape of the signals, defining, for example, the number of peaks and their possible spacing, which would be expected for a given situation.

Examples of K coefficient calculation:

FIG. 12 shows the results of the signals obtained from the simulation for the following conditions: Case Casing—100 m³/day—Viscosity@7.3 s⁻¹: 100 cPo. Cases corresponding to 8 scenarios with different positions and orientations of the tool in the section.

FIGS. 13 and 14 show, by way of example, histograms of coefficients by which time differences must be affected for two of the calculation methods based on 5,000 simulations. The most probable coefficient according to each method is taken considering the shape of the distribution. In FIG. 13, for the first arrivals method, the distribution is fitted with a log-normal distribution, whereas for the first sensor method, in FIG. 14, it is fitted with a Gaussian distribution.

The relative weight of each method in the total Wi is weighted by considering the relationship between the peak value and the dispersion of the results around that value (mean value μ and variance σ, respectively). The expression used is as follows:

Wi = 1 ⁢ σ i / μ i ∑ k ⁢ ( 1 ⁢ σ k / μ k )

These weightings are eventually corrected based on experimental validations carried out on a test bench.

For the purpose of background noise suppression, during the processing of each signal from each radiation sensor (with S1 being the signal from the first sensor and S2 the signal from the second sensor), the baseline levels

s 1 * ⁢ and ⁢ s 2 *

are detected as the average level of the raw signals ŝ₁ y ŝ₂ prior to the shot. These are defined as:

s 1 = s ˆ 1 - s 1 * s 2 = s ˆ 2 - s 2 *

Regarding the determination of time intervals, the area-under-the-curve technique is based on determining the time interval between the barycenters of the signal curves from both radiation sensors. For this analysis, the entire signal is not considered. According to Taylor G. I.'s theory in “Diffusion and mass transport in tubes,” the time intervals obtained correspond directly to the intervals associated with the average velocity. Conversely, if only a fraction of the area is considered—for instance, 10% or 25%—the determined velocity correlates more closely with the maximum flow velocity.

The area under the curve of the first sensor is defined as

S 0 : S 0 = ∫ 0 T f s 1 ⁢ dt ⁢ where ⁢ T f

is the total duration of the signal. The time difference required for the area under the curve of each sensor to reach a specific percentage of S₀ can be determined. The characteristic time intervals δ t₁=t₂−t₁ and δ t₂=t₄−t₃ are defined as:

∫ 0 t 1 s 1 ⁢ d ⁢ t S 0 = 10 ⁢ % ∫ 0 t 2 s 2 ⁢ d ⁢ t S 0 = 10 ⁢ % ∫ 0 t 3 s 1 ⁢ dt S 0 = 25 ⁢ % ∫ 0 t 4 s 2 ⁢ d ⁢ t S 0 = 25 ⁢ %

The characteristic time intervals δ t₁ and δ t₂ allow, evidently, the determination of two distinct flow rate values. To obtain two additional flow rate values—thus deriving flow rate values using four techniques based on the area under the curve and fractions thereof—the above equations must be equated to other percentages, for example, 40% and 50%, in order to subsequently obtain two additional characteristic δ t time intervals corresponding thereto.

To calculate the flow rate using any of these techniques (differentiated by the area fraction considered), a length—corresponding in this type of technique to the distance between the first and second sensors (e.g., 1.18 m)—must be divided by the characteristic time interval to obtain a velocity. The velocity thus obtained is multiplied by the coefficient K (previously determined and tabulated) to obtain the average velocity, which is finally multiplied by the area (or cross-section) obtained through equation (1), in order to determine, through equation (2), the flow rate of the polymeric solution in the injection well at the depth where the tool is located.

With respect to the first-arrival technique, the first arrivals are considered to be the time it takes for the tracer fluid to travel from the ejection point to the first and second radiation sensors. The first arrival is determined when the signal begins to emerge from the initial noise under tracer detection. A value is designated as 5% of the maximum of the first peak. A characteristic time interval δ t₃=t₆−t₅ is defined as:

s 1 ( t 5 ) = 0 .05 Max 0 T f ( s 1 ) s 2 ( t 6 ) = 0 .05 Max 0 T f ( s 2 )

To obtain the corresponding flow rate for this technique using the defined characteristic time interval, a length must be divided—this length corresponding in this case to the distance between the first and second sensor (e.g. 1.18 m)—by said characteristic time interval to obtain a velocity. The velocity thus obtained is multiplied by the coefficient K (previously determined) to obtain the average velocity, which is finally multiplied by the area (or cross-section) obtained through equation (1), in order to determine, through equation (2), the flow rate of the polymeric solution in the injection well at the depth where the tool is located.

To obtain two additional flow rate values using this technique, the characteristic δ t time intervals at times t₅ and t₆ (obtained from the above equations) can be used, i.e., the time it takes for the tracer to travel from the ejection point to the first radiation sensor and the time it takes to reach the second radiation sensor, respectively. The length used in each case to calculate the velocity is the distance between the ejection holes and the first sensor for time t₅, and the distance between the ejection holes and the second sensor for time t₆. In this way, velocity values are obtained by dividing the characteristic time intervals t₅ and t₆ by their corresponding lengths, and each of these velocities is then multiplied by the coefficient K (previously obtained) to determine a respective average velocity, which is finally multiplied by the area (or cross-section) obtained through equation (1), in order to determine, through equation (2), the corresponding flow rate of the polymeric solution in the injection well at the depth where the tool is located.

With respect to the time interval between maximums technique, this technique is based on determining the distance between the signal peaks between the sensors. In general, the first peak observed in each curve is considered. The characteristic time interval is defined as δ t₄=t₈−t₇ where:

s 1 ( t 7 ) = Max 0 T f ( s 1 ) s 2 ( t 8 ) = Max 0 T f ( s 2 )

To obtain the flow rate corresponding to this technique using the characteristic time interval, a length must be divided-this length corresponding in this technique to the distance between the first sensor and the second sensor (e.g. 1.18 m)—must be divided by the characteristic time interval to obtain a velocity. The velocity thus obtained is multiplied by the coefficient K (previously obtained) to determine the average velocity, which is finally multiplied by the area (or cross-section) obtained through equation (1), in order to determine, through equation (2), the flow rate of the polymeric solution in the injection well at the depth where the tool is located.

With respect to the cross-correlation technique, the velocity determined through this strategy is not based on a clearly established theory. Therefore, in the signal processing for the flow rate measurement method of the present invention, the velocity thus obtained is associated as the maximum velocity. As will be seen below, the technique is applied either directly to the signals or to their time derivatives, both of which are represented by sequences of data points for each signal, but in either case, it is required that the data points of both signals be equally spaced in time. If the sampling intervals obtained in the well are not equally spaced, the same are interpolated onto an equally spaced temporal grid.

Specifically, with s₁(t) and s₂(t) being the signals from the two detectors, the cross-correlation function is given by the following integral, which is based on computing a shifting time applied to the signal of the second sensor so that the integral is maximized:

R s 1 ⁢ s 2 ( τ ) = 1 T ⁢ ∫ 0 T s 1 ( t ) ⁢ s 2 ( t + τ ) ⁢ dt

The maximum of the cross-correlation function corresponds to the transit time, i.e., δ t=τ*, where τ* is the value of τ that maximizes R_s1s2(τ). The value of period T considered is the total time interval over which both curves occur. The shifting time τ is the time offset applied to the second signal to find the value τ* that maximizes the integral. This technique can also be applied to the derivative signals

s 1 ′ ( t ) ⁢ and ⁢ s 2 ′ ( t ) ,

where the characteristic time interval is the value of τ that maximizes the following cross-correlation function:

R s 1 ′ ⁢ s 2 ′ ( τ ) = 1 T ⁢ ∫ 0 T s 1 ′ ( t ) ⁢ s 2 ′ ( t + τ ) ⁢ dt

To obtain the flow rate corresponding to this technique—regardless of whether the characteristic time interval was obtained, i.e. from the signals or their derivatives—a length must be divided, which in this technique corresponds to the distance between the first sensor and the second sensor (e.g. 1.18 m), by the characteristic time interval to obtain a velocity. The velocity thus obtained is multiplied by the coefficient K (previously determined) to obtain the average velocity, which is finally multiplied by the area (or cross-section) obtained through equation (1), in order to determine, through equation (2), the flow rate of the polymeric solution in the injection well at the depth where the tool is located.

Regarding the initial slope technique, it considers the growth of the signal over time until its first maximum. The technique can be applied to each individual signal, taking into account the relative distance of the sensor from the ejection orifice, or in a comparative manner (thus resulting in three variants of the initial slope technique). The technique is based on the growth of the signal generated by an individual filament transported in a laminar manner by the flow from the ejection orifice to each sensor. It requires the incorporation of a correction to eliminate the transient associated with the RC relaxation time of the measurement circuit. The rate of signal growth can thus be related to the configuration and the adopted filament shape as it reaches the position of each sensor and passes through it. This can be applied individually to each sensor or averaged across both.

Specifically, the expression that allows determination of the maximum velocity U in this case adopts the following form

U = a t k - ( S ( t k ) / dS dt ] t k )

where α represents a distance between the ejection point and a point that accounts for the collimation of the sensor signal and is determined by the sensing cone angle, S is the normalized signal intensity with its time derivative, and t_k is the interval that elapses between the shot and any given moment t between t_A and t_peak. Here, t_A indicates the time of first arrival at the sensor, and t_peak the time of the first maximum detected by the sensor. Given that there is a significant range of t_k values for the same test from which the calculations can be performed, an average of 5 values within the interval t_A−t_peak is used.

The above calculation can be performed for the first sensor and for the second sensor, resulting in two separate calculation outputs. The difference between the two sensor signals can also be considered, in which case the expression is:

U = β ⁢ ( 1 t k ⁢ 1 - ( S ( t k ⁢ 1 ) / d ⁢ S d ⁢ t ] t k ⁢ 1 ) - 1 t k ⁢ 2 - ( S ( t k ⁢ 2 ) / d ⁢ S d ⁢ t ] t k ⁢ 2 ) )

where β is a constant related to the distance between the sensors, and subscripts 1 and 2 refer to the first and second sensors, respectively.

In any of the three cases, to obtain the average velocity, the maximum velocity U is multiplied by the previously obtained coefficient K, which accounts for the rheology and geometry of the flow passage section. The resulting average velocity is then multiplied by the area (or cross-section) obtained through equation (1) in order to calculate, via equation (2), the corresponding flow rate of the polymeric solution in the injection well at the depth where the tool is located.

It should be noted that the tool control system allows the detection of defective shots. This is achieved by analyzing the curves obtained from the radiation sensors, and if the curves do not reach a sufficient “counts” level—that is, if the peaks do not rise significantly above the signal noise—the shot is discarded. Additionally, another method of discarding a shot is by comparing the resulting flow rate against the expected value in well zones where the injection flow rate is known.

It must be understood that the tool and methods of the present invention, unlike traditional methods and flow transit tools known in the state of the art for flow rate determination, enable the measurement of flow rate in polymer injection wells for tertiary recovery in a repeatable and reliable manner, with an error margin of 20%, which is acceptable in this technical field. In particular, these advantages are achieved by combining the tool of the present invention with the signal processing method of the present invention, where regarding the tool of the present invention, the tool includes modifications to the electric motor, the reduction gearbox, the control means, and the number (and diameter) of ejection holes, in contrast to fluid transit tools known in the state of the art; and with respect to the signal processing method of the present invention, performed by the tool control system, up to thirteen flow rate determination techniques are used, and the flow rate values are weighted in order to obtain the final flow rate with a 20% margin of error.

The fact that the tool of the present invention comprises four ejection holes allows four tracer streams to enter the pipe instead of only one, thereby reducing the uncertainty caused by the unknown circumferential positioning of the holes. The modification of the motor and gearbox to achieve a higher plunger speed, combined with the appropriate orifice diameter, increases the impulse and velocity of the tracer as it is ejected through the four ejection holes. In this way, the tracer is ejected at a velocity sufficient to reach the wall of the pipe (either casing or tubing) where the tool is located, or at least with enough velocity to ensure it does not remain too close to the tool. This is important because the polymeric solution injected into the injection well, due to its high viscosity, results in laminar flow inside the well (unlike in water injection wells, where turbulent flow rate occurs). As the flow is laminar, the tracer may travel at different velocities along different trajectory lines (streamlines, assuming stationary flow), and this causes the calculated flow rate to depend on the streamline through which the tracer travels—a factor that cannot be controlled—leading to different measurement results depending on the tracer position within the flow. In laminar flow, the tracer does not mix and travels at a much lower velocity near the walls—whether of the tool body or the well pipe—compared to the average velocity or average flow of the polymeric solution circulating through the pipe. This does not occur in water injection wells, where the flow is turbulent and the tracer mixes with the flow, traveling along all streamlines, thus allowing for a good measurement of the average velocity.

If the four tracer threads reach the opposite wall of the pipe, or at least move sufficiently away from the tool (even considering that in polymer wells adequate and rapid mixing between the tracer fluid and the flowing polymeric solution cannot be achieved), the tracer travels through different streamlines, which promotes result repeatability, as long as the signal processing techniques of the present invention are used for determining or estimating the flow rate. In this manner, the fact that the ejection holes are angularly spaced around a longitudinal axis allows the tracer fluid to be injected in different directions, which, in combination with the increased impulse and velocity of the tracer fluid, and together with the signal processing techniques of the present invention, enables achieving repeatability in the results obtained.

The tool of the present invention also offers another advantage over other flow rate measurement methods that do not use radioactive tracers, namely, that the radiation penetrates the pipe walls, allowing for flow rate measurements during well completion operations. More precisely, the tool of the present invention allows for the detection of flow rates passing through the annular space (between casing and tubing), even when the tool is located inside the tubing. This is particularly important for detecting the seal integrity of packers and for detecting annular flow in selective injection installations, where the tubing reaches the bottom of the well.

Assays

In an initial laboratory test, shot trials were conducted with the tool of the present invention under both ambient pressure and high-pressure conditions. For the high-pressure tests, the tool was placed in a container where the pressure was increased to 250 kg/cm². The tests were performed by setting the shot voltage in the tool control system to 48 V (negative) and the shot duration to 200 ms. The power supply voltage for the motor was set to 50 V (negative), and the net shot time was 200 ms (with a setting of 675 ms in the tool, this time difference being due to a delay imposed by the electronic board of the tool, which is related to the need to cancel out the RC relaxation time of the cable connecting the tool to a truck).

In these tests, water was used as the fluid inside the tool, and the number of shots was 11 at ambient pressure and 10 and 11 at 250 kg/cm² pressure. The projection distance of the water jets generated from the ejection holes was always greater than 3 meters, which demonstrates that the tool correctly performs the shot operations.

Additionally, in said first test, the correct operation of the Geiger radiation sensors with the tool control system was verified through the passage of solid material contaminated with radioactive tracer through the sensors. Testing was carried out on each sensor, and the evolution of the signals as a result of the displacement of the contaminated material could also be observed.

Finally, the recharging of the ejection chamber operated correctly when a voltage of 26 V (negative) was applied to the tool control system using the sealing and recharging system of the present invention.

In a second test, considered a pilot test, the tool was lowered to a specific depth in an injection well where polymer solution was circulated. From this test, the signals produced by the radiation sensors of the tool of the present invention were obtained for the measurement of polymer flow rate. These signals are shown in the graph of FIG. 7, where the first curve in said graph corresponds to the signal from the first sensor and the second curve corresponds to the signal from the second sensor. These curves are formed due to the concentration of radioactive tracer in the main flow passing through the sensors. Additionally, this graph demonstrates the correct functioning of the tool, as the curve begins to rise when the first traces of the radioactive tracer reach the sensors (as the tracer concentration increases, the sensor perceives this as a rise in the curve), and a decrease in the curve is observed when the tracer concentration diminishes (i.e., after most of the radioactive tracer has passed through the respective sensor).

In this second test, a pilot test was also carried out in two polymer injection wells, where the nominal operating characteristics at the time of the pilot test were those detailed in Table 1 below. Two descents of the tool into the well were conducted per day, except on the first day when only one descent was made. The wells involved were DB-573 on the first and second days and DB-600 on the third day, both located in Desfiladero Bayo, belonging to YPF's Rincón de los Sauces Reservoir.

	TABLE 1
	Characteristic	Value

	Injection Flow rate (m3/day)	120
	Inner Tubing Diameter (m)	0.0620014
	Inner Casing Diameter (m)	0.12573
	Viscosity (cPo)	35

In these pilot tests, the processing of the radiation sensor signals from the tool of the present invention was performed in various wells, which were subjected to flow rates of 30 m³/day, 60 m³/day, 90 m³/day, and 120 m³/day. The flow rate values obtained in these wells after signal processing are represented in the graph of FIG. 8, where the polymer solution flowed through the tubing, and in the graph of FIG. 9, where the polymer solution flowed through the casing. Specifically, in said graphs, the weighted average of the flow rate (on the y-axis) from various flow rate estimation methods (thirteen in total) is presented against the injection flow rate of the well (on the x-axis) in areas prior to any perforation along the x-axis. This is relevant given that the flow rate measured by the tool should match the flow rate reported at the plant. It is important to note that the post-processing methods used in these initial pilot tests were not as developed as those described herein. Therefore, thirteen different techniques were not yet available, but only six.

It can be seen from FIGS. 8 and 9 that the graphs for both types of piping (tubing and casing) exhibit error margins of 20%, where, except for the highest flow rates, the results always fall within those margins. This discrepancy mainly occurs due to the relationship between the relevant times in those cases and the sampling frequency imposed by the operator.

The polymer solution flowing through the wells during those days had a viscosity at a shear rate of 7.34 1/s of 33 cPo on the first two days and 35 cPo on the last day. The wells were operated at flow rates ranging from 60-120 m³/day. The tool used comprised four ejection holes arranged at 90 degrees (with a diameter of said orifices of 0.35 mm).

The distance between centers of the Geiger sensors was 1.18 m, and the distance from the ejection holes to the first radiation sensor was approximately 4.75 m. In the wells analyzed, the verticality was greater in the case of well DB-600 compared to well DB-573. The well depths at which the shots were made correspond to pipe sections where the length of the tool was able to be entirely positioned between two perforations. Where possible, the tool was centered between pipe couplings.

Tables 2 and 3 show the results obtained in wells DB-573 and DB-600, respectively. These tables show results with shot times (Tiny) of 675 ms and 625 ms, applying six flow rate determination techniques. These are: two techniques of area under the curve, considering fractions of this area of 10% and 25%; a cross-correlation technique on the signal; two first-arrival techniques (one considering the difference between the first peaks of both signals, and another considering the first peak of the signal from the first sensor); and a technique based on time intervals between maximums. The average shown in the last column, for both Table 2 and Table 3, corresponds to an average considering three techniques, namely: the cross-correlation technique on the signal; the first-arrival technique considering the difference between the first peaks of both signals; and the first-arrival technique considering the first peak of the signal from the first sensor.

TABLE 2
										Average
Injected										CrossCorr,
flow										First Arr,
rate								Depth		First Arr inj
(m3/day)	Tiny	Area10	Area25	CrossCorr	FirstArrival	FirstArrInj	MaxArr	(m)	Position	(m3/day)

60	675	39.7	19.4	57.9	57.9	48.4	47.6	300	Tubing,	54.7
60	675	94.4	69.3	63.6	93.8	66.2	58.4	400	well 573	74.5
60	625	37.8	58.4	37.2	50.5	48.7	29.1	500		45.5
60	675	57.9	58.2	44.9	58.4	66.6	44.6	500		56.6
120	625	97.3	74.9	104.3	140.1	81.3	106.8	300		108.6
120	625	107.7	60.6	108.6	107.7	104.5	121.8	400		106.9
120	625	96.5	69.7	86.9	122.9	92.6	81.5	500		100.8
120	675	120.7	81.5	118.5	160.9	106.3	120.7	500		128.5
60	625	49.7	45.9	46.4	51.0	51.9	47.1	551	Casing,	49.8
60	675	51.0	47.1	45.6	76.5	54.2	48.3	55	well 573,	58.8
90	625	73.5	79.3	72.1	81.3	85.5	71.7	557	known	79.6
90	675	94.0	88.4	79.6	103.6	85.6	79.2	557	flow rate	89.6
120	625	92.9	108.3	89.4	92.7	113.7	92.6	557		98.6
120	675	215.6	5.7	106.5	130.0	119.4	108.3	557		118.7
90	625	17.6	16.7	16.7	18.1	16.9	15.1	596	Casing,	17.2
90	675	17.6	17.1	17.4	18.6	18.4	18.1	596	well 573,	18.1
120	625	20.3	20.3	20.3	23.2	22.7	19.1	596	unknown	22.1
120	675	19.1	15.8	19.3	21.6	23.5	15.5	596	flow rate	21.5
120	625	10.8	8.9	12.0	12.0	11.4	11.2	620		11.8
120	675	12.2	11.6	12.6	12.0	11.7	12.7	620		12.1
90	625	4.5	4.1	INF	1.7	231.1	−2.4	620	Reading	Null flow
									during	rate
									ascent

TABLE 3
										Average
Injected										CrossCorr,
flow										First Arr,
rate								Depth		First Arr inj
(m3/day)	Tiny	Area10	Area25	CrossCorr	FirstArrival	FirstArrInj	MaxArr	(m)	Position	(m3/day)

120	625	126.5	68.2	124.1	126.5	163.1	126.5	292	Tubing,	137.9
120	625	106.8	58.2	104.3	114.3	149.4	126.5	392	well 600	122.7
120	675	108.6	57.9	108.6	186.2	155.7	108.6	392		150.2
90	675	93.8	75.3	89.9	108.6	116.9	44.5	492		105.1
105	675	108.6	383.3	113.3	127.8	112.4	126.5	492		117.8
120	625	95.1	124.1	104.3	129	154.1	108.6	492		129.1
120	675	95.1	63	113.3	194.5	149.4	107.7	492		152.4
120	625	140.1	166.1	134.1	151.9	140.5	140.1	566	Casing,	142.2
75	675	91.1	91.1	85.7	86.9	83	86.7	566	well 600,	85.2
90	675	113.9	113.7	107.3	113.7	111.2	107	566	known	110.7
105	675	140.1	130	127.1	151.9	131.4	121.5	566	flow rate	136.8
120	675	140.4	130	140.7	140.1	149.5	121.5	566		143.4
120	625	33.3	31.7	33.5	33.3	39.9	−37.3	603	Casing,	35.6
120	675	31.7	30.2	29.6	35.2	37.6	30.2	603	well 600,	34.1
105	625	25.3	19.2	25.6	27.5	27.3	26.4	605	unknown	26.8
120	625	19.2	20.4	17	1049.8	822.2	17.6	643	flow rate	629.7
120	675	18.6	15.8	15.1	16.7	15	13.8	643		15.6
105	625	INF	126.9	92.9	−197.9	423.1	90.5	600		106.0

In said Tables 2 and 3, cases with known flow rate in the tubing and casing prior to the first perforation are presented. Results are also shown after the first perforation, which in both wells was located at approximately 575 m, with these results appearing in the rows indicating “unknown flow rate” or “reading during ascent” in the penultimate column titled “Position”. Although in the pilot tests in wells DB-573 and DB-600 the thirteen flow rate determination techniques described herein were not yet used, the results of these tests allow the establishment that the expected error lies within the +/−20% limits.

In said Tables 2 and 3, it must be understood, on the one hand, that the expression “INF” refers to an infinite or undetermined value (i.e., a mathematical indeterminacy) which will not be considered, and on the other hand, that the expression “Reading during ascent” refers to cases where the tool is at a depth where there is no longer measurable flow rate (i.e., null flow rate). Regarding the latter, it must be understood that, up to a certain depth, the flow rate is the same as at wellhead, because there is no outlet. However, after a certain depth where the perforations begin—usually several—each perforation takes a portion of the flow rate that goes into the formation. If a tracer shot is carried out at a depth where there is no longer injection flow rate, the sensor curves do not rise since nothing is detected (because the radioactive tracer remains immobile near the shot zone and does not reach the sensors). Observing this, an operator of the tool, after waiting a relatively long time without the curves rising, proceeds to pull the tool up, whereby the detectors pass through the radioactive fluid and detect it, and a flow rate value is obtained (which depends on the ascent velocity of the tool), which is subsequently discarded for not representing an actual measurement of the injected polymer flow rate (null flow rate is automatically adopted).

Field tests demonstrate the great variety of signals that can be produced in well measurements. The behavior between wells DB-573 and DB-600 is quite similar, with no substantial differences found.

The analysis of the obtained curves shows that, in all cases, a high correlation between the signals from both radiation sensors is achieved. In particular, FIGS. 10A and 10B show the signals obtained in well DB-573 (with a wellhead injection flow rate of 120 m³/day) for a flow rate measurement using the tool of the present invention in the tubing at a depth of 500 meters (FIG. 10A) and for a flow rate measurement using the tool of the present invention in the casing at a depth of 596 meters (FIG. 10B). Meanwhile, FIGS. 11A and 11B show the signals obtained in well DB-600 (with a wellhead injection flow rate of 120 m³/day) for a flow rate measurement using the tool of the present invention in the tubing at a depth of 492 meters (FIG. 11A) and for a flow rate measurement using the tool of the present invention in the casing at a depth of 566 meters (FIG. 11B). Each of the graphs in FIGS. 10A to 11B corresponds to the filtered sensor signals, in which the oscillations observed before the first arrival—when the curve begins to rise—were removed.

In FIGS. 10A to 11B, it can be seen that, as the tool is positioned at greater depths and the flow is reduced due to the perforations, the first arrival times increase, indicating a flow rate decrease as expected.

Also noteworthy are the changes appearing in the shape of the curve as flow rates vary due to the perforations. While at lower flow rates it is possible to retrieve curves similar to those observed with water injection, at higher flow rates curves generally appear with successive peaks corresponding to the behavior of tracer injection in filament form.

In general, the results from the different techniques show small dispersion. However, no technique appears entirely fail-safe for automatic use. The comparison between surface-measured flow rates and those measured in the casing prior to any perforation is relatively satisfactory. Those occurring in the tubing, however, show greater dispersion.

From the obtained curves, it is determined that the shot time is relevant with respect to the number of counts detected by the radiation sensors. The shape of the curves may change depending on the shot time, but the processing results are not very different, although there is a tendency toward underestimation for shorter shot times. This may be associated with difficulties in reaching the opposite wall during shorter discharge times.

Furthermore, in cases where the signals show multiple maximums, it is possible to use them to estimate the orientation of the tool and thus reduce the error made by assuming that the jet axis produced by a given orifice simultaneously contains the axis of the conduit.

Table 4 below shows the measurement results carried out in 2024 using the software with the thirteen techniques and their previously described weighted averages. A comparison was made between the wellhead flow rate and the measured flow rate obtained before perforations, and the difference or error between both values is reported, with the error in most cases being ±20%. Each row in Table 4 represents a different well on different days or the same well on different days.

The error between the wellhead flow rate and the measured flow rate obtained may be due to measurement errors or uncertainties related to the provided data, such as wellhead flow rate (known flow rate), pipe diameters, viscosity, etc., particularly when said error exceeds 20% in absolute value. It is worth noting that, although such data is available, it is quite possible that in some cases errors may be present, due to pipe scaling, discontinuities in the flow rate sent from the plant, among other possible reasons.

TABLE 4
					(Measured
					Flow rate
				(WellHead	before
	Province -		Approximate	Flow rate)	reservoir
Reservoir	Region	Date	viscosity [cPo]	m3/d	admission)	Difference

Desfiladero	Mza/Nqn	2024 Apr. 11	60	120	110.9	−7.60%
Bayo
Desfiladero	Mza/Nqn	2024 Apr. 12	32	80	84.4	5.50%
Bayo
Desfiladero	Mza/Nqn	2024 Apr. 15	30	120	131.8	9.80%
Bayo
Desfiladero	Mza/Nqn	2024 Apr. 17	32	120	166.4	38.70%
Bayo
Desfiladero	Mza/Nqn	2024 Apr. 22	36	120	156.4	30.30%
Bayo
Chachauen	Mza/Nqn	2024 Apr. 23	45	120	126.9	5.70%
Sur
Chachauen	Mza/Nqn	2024 Apr. 24	50	100	96.2	−3.80%
Sur
Chachauen	Mza/Nqn	2024 Apr. 25	45	100	93.1	−6.90%
Sur
Chachauen	Mza/Nqn	2024 Apr. 26	47	100	122.	22.00%
Sur
Chachauen	Mza/Nqn	2024 Apr. 30	37	100	107.3	7.30%
Sur
Chachauen	Mza/Nqn	2024 May 2	44	100	96	−4.00%
Sur
Chachauen	Mza/Nqn	2024 May 3	54	100	109.1	9.10%
Sur
Chachauen	Mza/Nqn	2024 May 7	32	60	60.5	0.80%
Sur
Chachauen	Mza/Nqn	2024 May 10	22	100	103.1	3.10%
Sur
Chachauen	Mza/Nqn	2024 May 10	26	105	144.8	37.90%
Sur
Chachauen	Mza/Nqn	2024 May 13	35	100	81.4	−18.60%
Sur
Chachauen	Mza/Nqn	2024 May 14	48	83	76.3	−8.10%
Sur
Desfiladero	Mza/Nqn	2024 Jun. 4	32	120	121.1	0.90%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 5	35	120	134.3	11.90%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 6	37	120	135.7	13.10%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 10	32	120	149.8	24.80%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 11	32	120	148	23.30%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 12	30	120	149.6	24.70%
Bayo
Desfiladero	Mza/Nqn	2024 Jun. 13	32	120	108.4	−9.70%
Bayo
Chachauen	Mza/Nqn	2024 Jun. 18	47	80	76.2	−4.70%
Sur
Chachauen	Mza/Nqn	2024 Jun. 18	42	90	124.3	38.10%
Sur
Desfiladero	Mza/Nqn	2024 Jun. 19	35	120	123.2	2.70%
Bayo
Chachauen	Mza/Nqn	2024 Jun. 24	40	120	119.7	−0.20%
Sur
Chachauen	Mza/Nqn	2024 Jun. 25	40	100	117	17.00%
Sur
Chachauen	Mza/Nqn	2024 Jul. 2	24	100	124	24.00%
Sur
Chachauen	Mza/Nqn	2024 Jul. 11	25	100	113.2	13.20%
Sur
Chachauen	Mza/Nqn	2024 Jul. 12	23	100	120	20.00%
Sur
Chachauen	Mza/Nqn	2024 Jul. 16	24	100	125	25.00%
Sur
Chachauen	Mza/Nqn	2024 Jul. 17	22	100	115.1	15.10%
Sur
Chachauen	Mza/Nqn	2024 Jul. 18	SD	36	38.8	7.80%
Sur

Those skilled in the art will recognize or be able to determine, using only routine experimentation, many equivalents of the specific procedures, embodiments, claims, and examples described herein. Such equivalents are considered to be within the scope of the present invention and covered by the appended claims. The invention has been illustrated in detail through the foregoing examples and attached figures, which should not be considered limiting.