Technical field of the invention

The invention concerns technology for monitoring fluid flow in a conduit, for example a subterranean borehole. More specifically, the invention concerns a tool assembly, a system, and a method, as set out by the preambles of claims 1, 10, and 14, respectively. The invention is useful for monitoring fluids (liquid phase or gas phase) that are injected into a subterranean formation

Background of the invention Fluids (liquids or gases) are injected into subterranean formations for a number of reasons. For example, carbon dioxide, hazardous waste water, and other hazardous fluids, may be injected into porous geologic formations for sequestration. Another example includes injecting water, brine, slurries, or aqueous chemicals, into oil or gas wells in order to stimulate hydrocarbon (oil and/or gas) production. Fluids having sealing properties may also be injected into cracks or fissures in order to stabilize or seal off a portion of a formation.

The fluids are normally injected via a borehole that extends inside the subterranean formation. The borehole may extend in any direction and orientation, and may be several kilometers long. The borehole may be formed specifically for injection purposes (e.g. for depositing toxic waste of harmful substances), or may be drilled into a hydrocarbon reservoir in order to extract hydrocarbons found inside the formation. In the latter case, the borehole is often referred to as a wellbore. The borehole may comprise a tubular element (e.g. one or more casings (or liners)) that has been installed inside the borehole (e.g. by cement), or may be a so-called “open-hole” borehole. If a casing is present, portions of it are perforated before fluid injection commences. These regions of perforated casing are often referred to as wellbore zones, and may be separated by seals (packers) arranged between the casing and the borehole wall (the formation).

The fluid to be injected may be fed from any upstream location, such as uphole facilities or from facilities within the borehole (including fluids from surrounding formations). The facilities are configured to control the fluid flow in the borehole. This control must ideally be based on information of the fluid being injected into the formation, and at what position(s) along the length of the borehole the fluid is being injected. Efficient control requires continuous and accurate information of the injected fluid quantity and flow rate, at one or more positions (e.g. the different injection zones) along the borehole. For example, in carbon dioxide sequestration, long horizontals may utilize much more of the storage place available if the injection is distributed evenly over the length of the borehole. This realization has increased the need for precise monitoring in order to determine fluid injection profiles.

Various methods and devices for monitoring downhole fluid injection exist. Four- dimensional seismic imaging is used for injection monitoring of hydrocarbon wells on a larger scale, but does not provide real-time monitoring of specific injection zones. Distributed temperature sensing (DTS) devices in the form of optical fibers permanently installed along the borehole length are sometimes inadequate in determining zonal fluid injection rates. The injected fluid generates a cooler region in the injection zone, and fluid injection must be stopped for a period in order for the fluid to be re-heated by the surrounding formation ("warm-back").

An objective of the invention is to provide a technology whereby fluid injection may be monitored more precisely, both in terms of volume and location, and in real-time.

Summary of the invention

The invention is set forth and characterized in the main claim, while the dependent claims describe other characteristics of the invention.

It is thus provided a tool assembly, characterized by

- a heat pulse module, a control and communication module, and a cable module, said cable module being configured for storing and at least releasing a cable; wherein the modules are functionally interconnectable; and wherein at least the heat pulse module is configured for installation in connection with a fluid conduit (1) and comprises means for imposing at least one heat pulse into a fluid flowing in the fluid conduit.

In one embodiment, tool assembly comprises a drag device connected to the cable module via the cable and the drag device is configured to be carried with fluid flowing in the conduit, whereby the drag generated by the drag device in the fluid at least party contributes to deploying the cable from the cable module.

In one embodiment, the drag device and the cable module are permanently connected so as to form one unit to be carried with the fluid flowing in the conduit, and the cable is a fiberoptic cable connecting the cable module and the control and communication module. In another embodiment, the drag device and the cable module are separate units, and the cable is connecting the cable module and drag device.

The drag device may comprise a stand-off assembly with one or more device stand-off devices configured to prevent the drag device from contacting the conduit inner wall. One or more of the stand-off devices may comprise elastic elements.

In one embodiment, the drag device comprises one or more sensor modules configured for sensing one or more of the list comprising temperature, pressure waves, strain, vibrations, inclination, salinity, acidity, gas concentration.

In one embodiment, the cable is a fiberoptic cable and the control and communication module comprises a fiber interrogator. The fluid conduit (1) may be a subterranean borehole. In one embodiment, two or more of said modules are physically interconnected.

It is also provided a system for monitoring a fluid injected into a fluid conduit, characterized by

- a heat pulse module arranged in connection with the injected fluid and comprising means for imposing at least one heat pulse into the fluid, and

- one or more devices for distributed detection of temperature arranged in or in thermal connection with the fluid conduit, and downstream of the heat pulse module.

The devices for distributed detection of temperature may comprise a fiberoptic cable deployed in the injected fluid or/and a fiberoptic cable permanently installed in or in thermal connection with the conduit. The conduit may comprise a subterranean borehole. In one embodiment, the fluid is being injected from an uphole location.

It is also provided a method of determining an injection profile (flow rate) of a fluid injected into a conduit, characterized by the steps of: a) releasing one or more heat pulses into the fluid to generate one or more heat waves that propagate with fluid; b) sensing the temperature of one or more heat waves at one or more downstream locations to determine a temperature profile, and transmitting temperature data to an uphole system; c) determining the flow injection profile at one or more openings in the conduit wall based on the sensed temperature.

In one embodiment, method step b) is performed by utilizing DTS or ATS. Method step c) may comprise correlating the temperature profile with information about the borehole, and utilizing flow models to provide information as to the flow profile at a desired location along the borehole. Said information may comprise positions of injection zones and/or apertures.

The invented tool and method enables precise and real-time monitoring of injection profiles in any borehole or conduit. With invented tool and method, a variation of rates injected to the borehole from an upstream location (either uphole, e.g. topside, or downhole) can be tested, and for each stabilized rate a temperature profile is determined. The temperature profile may be determined on the basis of one or more heat waves detected by one or more sensors arranged in or in connection with the fluid, downstream of the heat pulse generator. The heat wave, or waves, may be sensed in a time domain (e.g. virtually instantaneously and by e.g. a fiberoptic cable), or in a space domain (e.g. passing one or more sensors in succession, that also may detect heat wave distortion). The temperature profile will provide information about flow injection profiles and uneven reservoir pressures in various formations.

Brief description of the drawings These and other characteristics of the invention wall become clear from the following description embodiments of the invention, given as non-restrictive examples, with reference to the attached schematic drawings, wherein:

Figure 1 illustrates a first embodiment of the tool assembly according to the invention: Figure 2 is an exploded view of the tool assembly illustrated in figure 1, illustrating various tool modules;

Figure 3 illustrates an embodiment of the tool assembly in a deployed and activated state in a borehole;

Figure 4 corresponds to figure 3, and illustrates an embodiment of a drag device at four different stages of deployment of a cable;

Figure 5 illustrates a deployment procedure corresponding to that of figure 4, and illustrates a standoff assembly connected to the drag device;

Figure 6 illustrates the standoff assembly and drag device shown in figure 5;

Figure 7 is a close-up view of the drag device, the standoff assembly, and a portion of the cable during deployment in an open-hole borehole;

Figure 8 illustrates a second embodiment of the tool assembly according to the invention, in which a control and communication module is arranged at an uphole location and a heat pulse module and a cable module are deployed in the borehole;

Figure 9 illustrates a third embodiment of the tool assembly according to the invention, in which a control and communication module and a cable module are arranged at an uphole location, and a heat pulse module is installed in the borehole;

Figure 10 illustrates the heat pulse module in use in a borehole having pre- installed sensors;

Figure 1 1 illustrates a fourth embodiment of the tool assembly according to the invention;

Figure 12 is an exploded view of the tool assembly illustrated in figure 11, illustrating various tool modules; and

Figure 13 illustrates the fourth embodiment of the tool assembly in a deployed and activated state in a borehole. Detailed description of embodiments of the invention

The following description may use terms such as “horizontal”, “vertical”, “lateral”, “back and forth”, “up and down”, ’’upper”, “lower”, “inner”, “outer”, “forward”, “rear”, etc. These terms generally refer to the views and orientations as shown in the drawings and that are associated with a normal use of the invention. The terms are used for the reader’s convenience only and shall not be limiting.

Referring initially to figure 1, a first embodiment of the well intervention tool assembly 30 according to the invention comprises a heat pulse module 31, a control and communication module 32, and a cable module 33.

The heat pulse module 31 comprises one or more heat pulse generators (not shown) that are configured to induce one or more heat pulses into fluid flowing past the heat pulse module. The heat pulse module 31 and its heat pulse generators may be remotely controlled and powered, or may be pre-programmed to generate the heat pulses at predetermined durations, moments, or intervals. The heat source may be a heat tube comprising an exothermic heat source. A heat pulse generator may be of any type known in the art, for example as described in WO 2017/131530 A1 and WO 2020/167135 A1.

The cable module 33 is configured for storing and controllably deploying and retrieving an elongate member, such as a cable. The cable may be stored in, deployed from, and retrieved into, the cable module 33 in any manner known in the art, which therefore need no further description. The cable module may also comprise a cable cutting device, in case it is necessary or desired to abandon the cable (and its associated components, describe below) in the borehole.

The heat pulse module 31, control and communication module 32, and cable module 33 may be contained in one housing as indicated by figure 1, but may also be arranged and installed as separate units. This is indicated in figure 2, where reference number 2a indicates data and/or power signals between the heat pulse module 31 and the control and communication module 32. It should be understood that these signals may be transmitted in any way known in the art (cable or wireless, etc.), suitable for the specific application. Reference number 2b indicates data signals between the control and communication module 32 and the cable module 33. Although not specifically illustrated, signals between the three modules 31, 32, 33, as well as between the three modules and other devices, downhole or uphole, may be transmitted and received in any manner known in the art which is suitable for the intended purpose. The three modules may be powered and controlled from external facilities or by internal devices (e.g. batteries).

Also illustrated in figure 2 is a cable 10 which has been partly deployed from the cable module 33. Attached to the free end of the cable 10 is a drag device 34 which is designed to produce drag forces when released from the cable module 33 and deployed into a fluid flow, and thus pull the cable 10 out from the cable module 33. The drag device may for example be a disk, chute, or swab cup, or any other device that provides a drag force in interaction with the fluid. Although not illustrated, it should be understood that other devices than the drag device 34 may be employed for deploying the cable 10.

Figure 3 illustrates a borehole 1 extending from an uphole location U and down into a subterranean formation T. Although the figure illustrates a horizontal borehole section with a heel 5 and a toe 6, and a vertical borehole section with an upper casing 4, it should be understood that the borehole may have any orientation. The borehole may be lined with one or more tubulars (e.g. casings, not shown) that may be fixed (e.g. cemented) inside the length of the borehol e, or may be a so-called open-hole wellbore in which the borehole wall is defined by the formation. In figure 3, the borehole is lined by an upper casing 4 that extends down to the region inside the formation where a fluid F is to be injected. A permanent downhole gauge (PDG) 3 is installed on the upper casing 4. It should be understood that the invention is equally applicable to both lined and open- hole boreholes, and that PDG’s may be installed at other downhole locations.

Although the drawings indicate that the fluid F is fed into the conduit (borehole) 1 from an uphole location, the invention is equally applicable to well systems and methods in which the injected fluid is sourced -- completely or partially --- from within the borehole. For example, fluid may be sourced from a hydrocarbon well or aquifer in the subterranean formation. The formation may be a hydrocarbon reservoir, in which case the borehole may be referred to as a wellbore. However, the formation may be any subterranean formation into which a fluid is to be injected.

Figure 3 also illustrates how a number of apertures P provide fluid pathways between the borehole 1 and the formation. If the borehole is lined with a casing, the apertures P may have been formed in the casing wall by methods and devices well known in the art. If the borehole is open-hole, the apertures P may be cracks, fissures, or any other opening naturally occurring in the formation wall or having been formed by methods and devices ’well known in the art. Figure 3 identifies four separate fluid injection zones A-D, each comprising apertures P. The fluid injection zones may be separated by packers or other barriers. However, the invention is equally applicable for boreholes without such discrete injection zones.

The uphole location U, in figure 3 illustrated only schematically, may be on a seabed, on a location above water, or on dry' land. Equipment and devices needed to inject fluid (liquid and/or gas) into the borehole, to control the intervention tool assembly 30, and to receive and process recorded data, are collectively referred to as an uphole system 20. The individual components and functions of the uphole system 20 are well known in the art, and need therefore not be described in further detail. Although the uphole system 20 is illustrated as one unit in figure 3, it should be understood that the individual components and functions of the uphole system may be located at different locations.

The uphole system 20 comprises equipment for injecting a fluid F or a mixture of fluids into the borehole in a controlled manner. The fluid F may be a liquid, a gas, or a mixture of one or more liquids and one or more gases. The fluid may comprise entrained objects (e.g. particles) and other substances. The fluid may for example be carbon dioxide, slurrified drill cuttings, facility waste water, hazardous waste water or other hazardous fluids, or a liquid for injection into a hydrocarbon formation in order to stimulate hydrocarbon production .

Figure 3 illustrates how fluid F is flowing into the borehole, along the borehole, and into the formation through apertures P. The uphole system 20 also comprises power, communication, and control means, a Surface Read-Out module, as well as necessary' devices and systems for deploying, controlling, and retrieving the intervention tool assembly 30 (as one unit or in parts), and communications devices for sending and receiving data to and from the intervention tool assembly 30 and its components.

In figure 3, the well intervention tool assembly 30 has been deployed a distance into the borehole 1, to a position upstream of (i.e. closer to the uphole location than) the apertures P. The figure illustrates a typical configuration in which the well intervention tool assembly 30 has been lowered towards the lower end of the upper casing 4, for example to a location where a restriction R (e.g. debris, deposits, etc.) prevents further deployment of the well intervention tool assembly 30. However, the drag device 34 is designed with a size and/or elasticity that allows it to pass beyond the restriction. The well intervention tool assembly 30 may be run into the borehole by wireline or any other devices known in the art, indicated by the power and data cable 11 .

In figure 3, the drag device 34 has been released and has been carried with the fluid F to the borehole toe 6, and thus contributed to the deployment of the cable 10, pulling it out from the cable module 33. The cable module 33 comprises power and control devices (not shown) to control (i.e. retard, release, stop) the cable deployment at any point along the borehole. Also included in the cable module 33 are devices (not shown) to measure and record how much of the cable 10 has been deployed.

When the well intervention tool assembly 30 has been deployed to a desired location inside the borehole, the heat pulse module 31 may be activated to release one or more heat pulses into the fluid, as described above. The time-dimension (i.e. the duration) of the heat pulse, and/or its intensity (e.g. heat released per unit of time), may be pre-set or controlled based on applicable conditions (e.g. ambient fluid temperature and flowrate, borehole length). The heat pulses will impose their temperature in localized fluid regions - referred to in the following as heat waves H - in which the temperature differs from the ambient fluid temperature.

Figure 4 illustrates the cable 10 and drag device 34 at four different stages of deployment. Pertinent data may be recorded by the cable 10 or drag device as the cable is being deployed. Such data may be pressure waves, vibrations, strain, etc., as wall be described in more detail below. The cable deployment may be stopped momentarily at desired locations 34(1-4) and sensed parameters may be used to determine the location of the drag device inside the borehole, and to determine how much cable has been deployed. The cable module 33 may also comprise a measurement device by means of which the length of deployed cable may be monitored.

Figure 6 illustrates an embodiment of the drag device 34 which comprises a sensor module 37. The sensor module 37 may comprise sensors to detect and transmit data related to temperature, pressure waves, strain, vibrations, inclination, salinity, acidity, gas concentration, etc. Illustrated in figures 5 and 6 is a standoff assembly 35, having two standoff devices 35a,b interconnected by a body 35c. The body may have a sensor module 37 of the type mentioned above. The standoff devices 35a,b comprise rigid but elastic elements (e.g. “fingers”) that serve to centralize the drag device 34 in the borehole and to prevent the drag device 34 from being drawn toward apertures P or being stuck against the borehole wall. In another embodiment, the standoff device may be shaped such that it is bidirectional, whereby the cable 10 may be retracted, towards to the cable module.

Figure 7 illustrates how the standoff assembly prevents the drag device from being drawn towards the borehole wall by injected fluid escaping into apertures P.

Figure 8 illustrates a second embodiment of the tool assembly in which the control and communication module 32 is arranged at an uphole location, and a cable 36 (e.g. a fiberoptic cable) extends between the control and communication module 32 and the cable module 33. Although not illustrated, a power and data cable extends between the uphole location and the downhole modules.

Figure 9 illustrates a third embodiment of the tool assembly in which the control and communication module 32 and cable module 33 are arranged at an uphole location, while the heat pulse module 31 is permanently installed in the borehole, above the reservoir.

Figure 11 and figure 12 illustrate a fourth embodiment of the tool assembly 30’. This fourth embodiment is similar to the embodiments described above, with the exception that the cable module 33’ and drag device 34’are permanently connected, that the cable 10 is a fiberoptic cable, and the fiberoptic cable is connected to the control and communication module (32). Although not illustrated, it should thus be understood that this fourth embodiment may comprise e.g. standoff devices and sensors described above.

When the drag device 34’ is carried with the fluid flow as described above and illustrated in figure 13, the cable 10 is deployed from the cable module 33’ which is connected to the drag device 34’. One advantage with this embodiment is the absence of tension in the fiberoptic cable 10, as the cable is paid out as the drag device is carried with the fluid. Another advantage is that friction forces between the fiberoptic cable and the borehole/completion walls are avoided since the fiberoptic cable has no movement relative to the wall. Erosion of the fiberoptic cable will then be minimal

Various embodiments and applications of the invented tool assembly 30 will now be described.

The cable 10 preferably comprises a waveguide and is preferably a fiberoptic cable, and the control and communication module 32 comprises a fiber interrogator. In the fourth embodiment, described above, the cable must be a fiberoptic cable. The fiberoptic cable 10 functions as a linear sensor, where temperatures are recorded along the cable as a continuous profile. The control and communication module 32 thus comprises devices and functionality required to send light pulses (e.g. laser) through the fiberoptic cable 10 and to record scattered and reflected light, and analyze and process the information (including converting the optical signals to electrical signals). This technology - using Distributed Optical -Fiber Sensors (DOFS) - is well known in the art. One application of the DOFS technology is Distributed Temperature Sensing ( DTS ). DTS technology for downhole use is described in US 9,448,312 Bl.

The heat pulses generated by the heat sources are distributed in a pattern to enable the best estimation of well ootflow profile. The heat waves propagate with the flow towards downstream temperature sensors (in this embodiment: the fiberoptic cable 10). The detection by the sensors of a heat wave will be regarded as a verification of flow towards each downstream sensor. This forms the basic information to be extracted.

The heat waves H will travel with the fluid F along the borehole and into apertures P, as described above and indicated by the arrows in figure 3. When a heat wave H is travelling with the fluid, its magnitude (i.e. the difference between the temperature of the wave and the temperature of the fluid surrounding the wave) will be reduced. The heat wave is attenuated by convection with the surrounding fluid, by turbulent diffusion, and/or by parts of it escaping with the fluid through the apertures and into the formation.

This heat wave attenuation in the direction towards the borehole toe 6 (depicted schematically in figure 3) will be detected by the fiberoptic cable 10, for example utilizing DTS principles and technology, as mentioned above. The fiberoptic cable 10 thus functions as a linear temperature sensor, and a continuous temperature profile along the entire length of the cable may thus be produced . Correlating the temperature profile with information about the borehole (e.g. the positions of injection zones A-D, and/or apertures P), and utilizing existing flow models, will provide information as to the flow profile at a desired location along the borehole.

Zonal outflow rates (q.) --- at the apertures P --- may then be determined from heat wave arrival times and derived time-of-flight (At.) between the heat source and the position on the downstream linear sensor (fiberoptic cable).

The last interpretation stage is to vary parameters of a numerical model in a systematic way to match recordings with simulations. When best match is obtained, an outflow profile estimate can be extracted from the model. The model is comprehensive and the bulk residence time (i.e. Residence Time Distribution; RTD) in the flow system includes (i) heat energy transfer from source to surrounding fluids, (ii) wave dispersion while propagating with multiphase fluids, (iii) heat energy exchange between fluids and steel wall, and (iv) residence time distribution in flow voids. Each physical effect is described in numerous academic papers and gives a basis for model implementation. The inventors have performed a variety of experiments to calibrate the models.

The above-mentioned fiberoptic cable 10 and control and communication module 32 (comprising a fiber interrogator) may also be used to determine the fluid injection profile using another aspect of the DOFS technology: Distributed Acoustic Sensing (DAS), in which the fiberoptic cable is a sensing element and detects acoustic frequency strain signals and temperature variations over large distances. The temperature pulses are generated by the heat pulse module 31 described above. The acoustic signals may be generated by turbulence induced by features in the flow (e.g. objects, or the apertures P).

In another embodiment, the cable 10 is an electric cable or a fiberoptic cable with several sensors (e.g. Bragg gratings) placed in and along the cable, and temperature detection is based on the Array Temperature Sensing (ATS) technology. An ATS system is described in US 8,768,111 B2.

In all of the embodiments described above, the cable 10 comprises physical properties that makes it neutrally buoyant in the fluid.

Another aspect of the invention comprises the use of the heat pulse module and the procedure described above in combination with pre-installed borehole sensors. This is illustrated in figure 10, where reference number 39 denotes a fiberoptic cable permanently installed in the borehole, and reference number 40 denotes pre-installed and/or retrofitted sensors (e.g. a PDG). Such sensors 40 may be installed - permanently or temporarily - at selected positions along the borehole. Communication lines and devices are not shown, as these are known in the art and also described above. It should be understood that the permanent cable 39 and sensors 40 may be installed separately and not in the same borehole as shown in figure 10. Sensors 40 may also comprise wireless gauges.

The commonality of the deployable cable 10, the sensor 37 on the drag device and stand-off assembly, the permanently installed cable 39, and the sensors 40, is that they comprise sensor features and functions that enable them to sense at least temperature, and thus sense the changes in heat waves generated by the heat pulse module 31. The cables 10, 39 and sensors 37, 40 may thus collectively be referred to as a device for distributed detection of temperature.

Features and functions described above with reference to the first embodiment shall apply for the second, third and fourth embodiments unless otherwise noted above. Although the invention has been described with reference to a subterranean borehole, it should be understood that the invention is applicable for monitoring fluid flow in any conduit.