US20140165715A1

US20140165715A1 - Methods and Apparatus for Determining Downhole Parameters

Info

Publication number: US20140165715A1
Application number: US14/125,300
Authority: US
Inventors: Abdur Rahman Adil; Elena Borisova; Tullio Moscato; Rex Pastrana Burgos; Luis Eugenio Davila De Garate
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2011-06-13
Filing date: 2012-06-13
Publication date: 2014-06-19
Also published as: US20140102695A1; WO2012174038A3; US9753179B2; WO2012174036A2; BR112013032103B1; US20140150546A1; US9804291B2; MX2013014651A; US10393919B2; NO2834239T3; EP2718544A2; WO2012174034A9; BR112013032103A2; MX368620B; WO2012174034A3; US20140157884A1; WO2012174051A2; WO2012174048A2; US10365400B2; WO2012174046A3

Abstract

Example methods and apparatus for determining downhole parameters are disclosed herein. An example method includes pumping a fluid in a first direction to substantially fill a first area of a fluid flow passageway with the fluid and determining a fluid parameter via a sensor disposed in a second area adjacent the first area. The sensor includes a heater and a temperature sensor. The example method also includes determining if the first fluid has flowed in a second direction into the second area based on the fluid parameter.

Description

RELATED APPLICATIONS

This patent claims the benefit of U.S. Provisional Patent Application Ser. No. 61/496,180, entitled “System and Method for Determining Downhole Fluid and Borehole Parameters,” which was filed on Jun. 13, 2011, and is incorporated herein by reference in its entirety.

BACKGROUND

A well may be drilled through a subterranean formation to extract hydrocarbons. Conditions in the well may be harsh. For example, temperatures inside the well may be from about negative 25° C. to about positive 150° C. and pressures may be up to or exceed about 12,500 psi.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
An example method disclosed herein includes pumping a fluid in a first direction to substantially fill a first area of a fluid flow passageway with the fluid and determining a fluid parameter via a sensor disposed in a second area adjacent the first area. The sensor includes a heater and a temperature sensor. The example method also includes determining if the first fluid has flowed in a second direction into the second area based on the fluid parameter.
Another example method disclosed herein includes pumping a first fluid into a first area of a wellbore via a downhole tool. The downhole tool includes a sensor having a heater and a temperature sensor. The example method also includes pumping a second fluid into a second area of the wellbore in fluid communication with the first area and determining a fluid parameter via the sensor. Based on the fluid parameter, if the first fluid has substantially filled a portion of the second area is determined
Another example method disclosed herein includes disposing a downhole tool in a wellbore. The downhole tool includes a sensor having a heater and a temperature sensor. The example method further includes pumping fluid into the wellbore via the downhole tool and determining a response of the sensor. Based on the response, if the fluid substantially filled a portion of the wellbore is determined.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of methods and apparatus for determining downhole parameters are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.

FIG. 1A illustrates an example system in which embodiments of methods and apparatus for determining downhole parameters can be implemented.

FIG. 1B illustrates various components of an example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 1C illustrates various components of the example device of FIG. 1B that can implement embodiments of the example methods and apparatus for determining downhole parameters.

FIG. 1D illustrates various components of another example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 2A illustrates various components of an example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 2B illustrates various components of the example device of FIG. 2A that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 2C illustrates various components of the example device of FIG. 2A that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 2D illustrates various components of another example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 2E illustrates various components of yet another example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 3 is a graph depicting sensor measurements taken using the example device of FIG. 2B.

FIG. 4A illustrates various components of an example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 4B illustrates various components of an example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 5A is a graph illustrating sensor measurements.

FIG. 5B is another graph illustrating sensor measurements.

FIG. 6 is a graph of sensor measurements and fluid flow based on the sensor measurements.

FIG. 7 illustrates various components of an example device that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 8 illustrates various components of an example device of that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 9 illustrates various components of an example device of that can implement embodiments of the methods and apparatus for determining downhole parameters.

FIG. 10 illustrates example method(s) for determining downhole parameters in accordance with one or more embodiments.

FIG. 11 illustrates example method(s) for determining downhole parameters in accordance with one or more embodiments.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments or examples for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features such that the first and second features may not be in direct contact.
Although some example fluid sensing systems disclosed herein are discussed as being positioned on treatment tools of a coiled tubing system, other examples are employed with and/or without treatment tools. For example, a fluid sensing element may be employed apart from the coiled tubing system. Thus, in some examples, the fluid sensing system may be deployed by a drill pipe, a drill string or any other suitable conveyance device.
FIG. 1A is a schematic depiction of a wellsite 100 with a coiled tubing system 102 deployed into a well 104. The coiled tubing system 102 includes surface delivery equipment 106, including a coiled tubing truck 108 with reel 110, positioned adjacent the well 104 at the wellsite 100. The coiled tubing system 102 also includes coiled tubing 114. In some examples, a pump 115 is used to pump a fluid into the well 104 via the coiled tubing. With the coiled tubing 114 run through a conventional gooseneck injector 116 supported by a mast 118 over the well 104, the coiled tubing 114 may be advanced into the well 104. That is, the coiled tubing 114 may be forced down through valving and pressure control equipment 120 and into the well 104. In the coiled tubing system 102 as shown, a treatment device 122 is provided for delivering fluids downhole during a treatment application. The treatment device 122 is deployable into the well 104 to carry fluids, such as an acidizing agent or other treatment fluid, and disperse the fluids through at least one injection port 124 of the treatment device 122.
The example treatment device 122 is optional and its use will depend on the various applications. The coiled tubing system 102 of FIG. 1A is depicted as having a fluid sensing system 126 positioned about the injection port 124 for determining parameters of fluids in the well 104. The fluid sensing system 126 is configured to determine fluid parameters, such as fluid direction and/or velocity. In other examples, other downhole parameters are determined.
In some examples, the coiled tubing system 102 includes a logging tool 128 for collecting downhole data. The logging tool 128 as shown is provided near a downhole end of the coiled tubing 114. The logging tool 128 acquires a variety of logging data from the well 104 and surrounding formation layers 130, 132 such as those depicted in FIG. 1A. The logging tool 128 is provided with a host of well profile generating equipment or implements configured for production logging to acquire well fluids and formation measurements from which an overall production profile may be developed. Other logging, data acquisition, monitoring, imaging and/or other devices and/or capabilities may be provided to acquire data relative to a variety of well characteristics. Information gathered may be acquired at the surface in a high speed manner, and, where appropriate, put to immediate real-time use (e.g. via a treatment application). Some examples do not employ the logging tool 128.
With reference still to FIG. 1A, the coiled tubing 114 with the treatment device 122, the fluid sensing system 126 and the logging tool 128 thereon is deployed downhole. As these components are deployed, treatment, sensing and/or logging applications may be directed by way of a control unit 136 at the surface. For example, the treatment device 122 may be activated to release fluid from the injection port 124; the fluid sensing system 126 may be activated to collect fluid measurements; and/or the logging tool 128 may be activated to log downhole data, as desired. The treatment device 122, the fluid sensing system 126 and the logging tool 128 are in communication with the control unit 136 via a communication link (FIGS. 1B-1D), which conveys signals (e.g., power, communication, control, etc.) therebetween. In some examples, the communication link is located in the logging tool 128 and/or any other suitable location. As described in greater detail below, the communication link may be a hardwire link or an optical link.
In the illustrated example, the control unit 136 is computerized equipment secured to the truck 108. However, the control unit 136 may be portable computerized equipment such as, for example, a smartphone, a laptop computer, etc. Additionally, powered controlling of the application may be hydraulic, pneumatic and/or electrical. In some examples, the control unit 136 controls the operation, even in circumstances where subsequent different application assemblies are deployed downhole. That is, subsequent mobilization of control equipment may not be included.
The control unit 136 may be configured to wirelessly communicate with a transceiver hub 138 of the coiled tubing reel 110. The receiver hub 138 is configured for communication onsite (surface and/or downhole) and/or offsite as desired. In some examples, the control unit 136 communicates with the sensing system 126 and/or logging tool 128 for conveying data therebetween. The control unit 136 may be provided with and/or coupled to databases, processors, and/or communicators for collecting, storing, analyzing, and/or processing data collected from the sensing system and/or logging tool.
In one example, the communication link between the treatment device 122, fluid sensing system 126 and/or logging tool 128 and the surface or control unit 136 may be implemented using a fiber optic or wired telemetry system. As such, the communication link/system may include tubing that provides and/or possesses a certain amount of stiffness in compression, similar to coiled tubing. In some such examples, a fiber optic tube is disposed inside coiled tubing. In some examples, a cross-sectional area of the fiber optic tube may be small relative to an inner area defined by the coiled tubing to limit a physical influence of the fiber optic tube on mechanical behavior of the coiled tubing during deployment and retrieval, thereby preventing “bird-nesting” or bundling within the coiled tubing. In some examples, optical fiber equipped coiled tubing is deployed into and retrieved from a wellbore at a greater speed than coiled tubing with wireline.
FIG. 1B illustrates an example communication link 200 between the treatment device 122, the fluid sensing system 126, the logging tool 128, and/or the surface or control unit 136. In the illustrated example, the communication link 200 includes a tubular 105 within which a duct or tube 203 is disposed. In the illustrated example, an optical fiber 201 is disposed in the tube 203. In some examples, more than one optical fiber is disposed in the tube 203. In the illustrated example, a surface termination 301 and a downhole termination 207 are provided to couple the optical fiber 201 to one or more devices or sensors 209. In some examples, the optical fiber 201 is a multi-mode optical fiber. In other examples, the optical fiber 201 is a single-mode optical fiber. The devices or sensors 209 are, for example, gauges, valves, sampling devices, temperature sensors, pressure sensors, distributed temperature sensors, distributed pressure sensors, flow-control devices, flow rate measurement devices, oil/water/gas ratio measurement devices, scale detectors, actuators, locks, release mechanisms, equipment sensors (e.g., vibration sensors), sand detection sensors, water detection sensors, data recorders, viscosity sensors, density sensors, bubble point sensors, composition sensors, resistivity array devices and sensors, acoustic devices and sensors, other telemetry devices, near infrared sensors, gamma ray detectors, H₂S detectors, CO₂detectors, downhole memory units, downhole controllers, perforating devices, shape charges, firing heads, locators, and other devices.
FIG. 1C is a cross-sectional view of the communication link 200 of FIG. 1B. Inside the tube 203, an inert gas such as nitrogen may be used to fill the space between the optical fiber or fibers 201 and the interior of the tube 203. In some examples, the fluid is pressurized to prevent the tube 203 from buckling. In some examples, a laser-welding technique is performed in an enclosed environment filled with an inert gas such as, for example, nitrogen to avoid exposing the optical fiber 201 to water or hydrogen during manufacturing. In some examples, the tube 203 is constructed by bending a metal strip around the optical fiber 201 and then welding that strip to form the tube 203. An example laser-welding technique is described in U.S. Pat. No. 4,852,790, which is hereby incorporated herein by reference in its entirety. In some examples, gel including palladium or tantalum is inserted into an end of the tube 203 to separate hydrogen ions from the optical fiber 201 during transportation of the communication link 200.
Materials suitable for use in the tube 203 provide stiffness to the tube 203, are resistant to fluids encountered in oilfield applications, and/or are rated to withstand the high temperature and high pressure conditions found in some wellbore environments. In some examples, the tube 203 is a metallic material and the tube 203 may include metal materials such as, for example, Inconel™, stainless steel, or Hasetloy™.
In some examples, the tube 203 has an outer diameter of about 0.071 inches to about 0.125 inches. In some examples, the tube 203 is less than or equal to about 0.020 inches (0.508 mm) thick. The above-noted dimensions are merely examples and, thus, other dimensions may be used without departing from the scope of this disclosure
FIG. 1D illustrates another example communication link 212. In the illustrated example, the communication link 212 includes a tubular 105 and a first tube 203 and a second tube 203. A first optical fiber 201 is disposed in the first tube. A second optical fiber 201 and a third optical fiber 201 are disposed in the second tube 203. In some example, the first optical fiber 201 is coupled to one of the devices 209, and the second optical fiber 201 and the third optical fiber 201 are coupled to one or more other ones of the devices 209. In some examples, more than one of the devices 209 may be coupled to a single optical fiber 201.
FIGS. 2A-2C are schematic views of a portion of a coiled tubing system 202 with a treatment device 222 and fluid sensing system 226 on a coiled tubing 214 thereof, which may be used to implement the coiled tubing system 102, the treatment device 122 and/or the fluid sensing system 126 of FIG. 1A. FIG. 2A is a longitudinal view, partially in cross-section, depicting the fluid sensing system 226 positioned about the treatment device 222. As shown, the treatment device 222 has injection ports 224 for dispersing injection fluids into a well 204 as schematically depicted by the dashed arrows.
The injection fluid may be dispersed to treat a portion of a well 204, such as pay zone 240, to enhance production of fluid therefrom. As illustrated in FIG. 2A, stimulation fluid, such as acid, may be injected into the well 204 nearby the pay (or oil producing) zone 240 by means of the treatment tool 222. The acid is intended for the pay zone 240, but is shown positioned downhole therefrom. Precisely positioning the injection ports 224 against a zone of interest may be a challenging task due to uncertainties that may exist in target depth and/or tool position. The sensing system 226 around the injection port 224 may be tailored to measure a flow split upstream and downstream of the injection ports 224 in the well 204. Fluid movement may be used to indicate where the pay zone 240 is located relative to the injection port 224. Once known, the position of the treatment device 222 and the injection ports 224 may be positioned to affect treatment as desired.
As the fluid is released from the treatment device 222, the flow of the fluid is split with an upstream portion of the fluid moving upstream and a downstream portion of the injection fluid moving downstream. The upstream portion of the injection fluid travels upstream at a given velocity as indicated by the arrows labeled V1. The downstream portion of the injection fluid travels downstream at a given velocity as indicated by the arrows labeled V2. While the fluid is depicted as flowing in a specific direction, it will be appreciated that the flow of the fluid may vary with operating conditions.
While the example sensing system 226 illustrated in FIGS. 1 and 2A-2C is described in conjunction with the coiled tubing system 102 for determining fluid parameters, the sensing system 226 may also be used in other fluid flow applications such as, for example, detection of fluid cross-flow between zones, production logging (e.g., for single phase velocity, or in conjunction with Flow Scanner Imaging (FSI) complementary to a spinner in a low velocity range), downhole or surface testing in conjunction with use of a flowmeter (e.g., low speed Venturi based flowmeter applications), leakage detection (e.g., with dynamic seals), with other tools where flow velocity measurements is desired, among others. The sensing system 226 may be positioned on any surface, downhole and/or other movable equipment, such as a downhole tool, and/or in fixed equipment, such as a casing (not shown).
The sensing system 226 is depicted in FIG. 2A as having a plurality of sensor elements 242 a,b positioned about the treatment device 222. In some examples, one or more sensor elements 242 a,b are positioned about the coiled tubing system 102 to perform fluid and/or other downhole measurements. In some such examples, the sensor elements 242 a,b are positioned about the injection port(s) 224 to measure fluid parameters. The fluid measured is the injection fluid dispersed from the treatment device 222, but may also include other fluids in the well (e.g., water, hydrocarbons, gases, etc.) that mix with the injection fluid as it is dispersed.
An upstream portion of the sensor elements 242 a are depicted as being positioned on the treatment device 222 a distance upstream therefrom. A downstream portion of the sensor elements 242 b are depicted as being positioned on the treatment device 222 a distance downstream therefrom. The upstream sensor elements 242 a and/or the downstream sensor elements 242 b may be arranged radially about the treatment apparatus 222. In the illustrated example of FIG. 2B, the sensor elements 242 a,b are positioned at various radial locations x,y,z about the treatment apparatus 222. While a specific configuration for the sensor elements 242 a,b is depicted in FIGS. 2A and 2B, it will be appreciated that one or more sensor elements may be positioned at various locations (longitudinally and/or radially) about the coiled tubing system 202 and/or well 204.
At least some of the sensor elements 242 a,b are capable of sensing fluid parameters, such as fluid direction and velocity. In some examples, more than one of the sensor elements 242 a,b may be capable of measuring the fluid parameters. In some examples, at least one of the sensor elements 242 a for measuring fluid parameters is positioned upstream from the injection port 224, and at least one of the sensor elements 242 b for measuring fluid parameters is positioned downstream from the injection port 224. In this configuration, the measurements of the upstream and the downstream fluid sensors 242 a,b may be compared to determine fluid parameters, such as fluid direction and/or fluid velocity. The ratio between upper and lower velocities and fluid direction obtained from measurements of the upstream and downstream sensing elements 242 a,b may be used to generate real-time monitoring of where the fluid is flowing during the treatment, as will be described further herein. Other downhole parameters may also optionally be measured with the fluid sensing system 226 and/or other sensors positioned about the well.
Comparison of multiple sensing elements 242 a,b may be used to account for differences in measurements taken by the various sensing elements 242 a,b. In some examples, multiple sensing elements 242 a,b are used to provide sufficient redundancy and confidence in the measurement results. This redundancy may also reduce the severity of impact where one or more sensor elements 242 a,b fails, such as in harsh downhole environments involving the use of acids. The multiple sensing elements 242 a,b may also be used to generate fluid direction and/or velocity information. In such cases, at least one upstream sensor element 242 a and at least one downstream sensor element 242 b may be used. In some examples, additional sensor elements 242 a,b are provided to enhance reliability of the values generated.
In some examples, it may be useful to consider the position of the sensing element 242 a,b about the treatment tool 222. The number of arrays (or sets of sensing elements 242 a,b), as well as the number of sensing elements 242 a,b per array, may vary. As shown in FIG. 2A, the sensing elements 242 a,b are positioned upstream and downstream to measure fluid as it passes upstream and downstream from the injection ports 224. In some examples, when using corresponding upstream and downstream sensing elements 242 a,b, the corresponding sensing elements 242 a,b, are positioned at equal distances from the injection port 224. In some examples, corresponding sensing elements 242 a,b are identically matched. Matched sensing elements may be spaced at equal distances.
In the illustrated example, multiple sensing elements 242 a,b are also positioned about the circumference of the tool at 90-degree intervals x, y, and z as shown in FIG. 2B. As shown in FIG. 2B, the sensing elements 242 b are positioned at radial locations x, y and z about the treatment device 222. The sensing element 242 b at position x is against a wall 205 of the well 204. The azimuthal arrangement of sensing elements 242 a,b at positions x, y, and z provides redundancy in case one side of measurements is impeded.
An issue may appear when the tool body (e.g., the treatment tool 222) is eccentric (or not concentric) with the well 204 as shown in FIG. 2B. In the illustrated example, the sensing element 242 b _xlocated closer to the wall 205 of the well 204 may read a lower flow value than the sensing elements 242 b _y, 242 b _zpositioned farther from the wall. In such cases, it may be desirable to ignore or remove measurements from potential obstructed sensing elements, such as the sensing element 242 b _x.
As shown in FIG. 2B, the sensing elements 242 b are positioned on an outer surface 223 of the treatment tool 222. The sensing elements 242 b may be flush with the outer surface 223, recessed below the outer surface 223 or extended a distance therefrom. In some examples, the sensing elements 242 b are positioned such that each sensing element 242 b contacts fluid for measurement thereof, but remains protected. To prevent damage in harsh downhole conditions, protrusion of the sensing elements 242 b from the treatment tool may be reduced. As shown in FIG. 2C, the sensing elements 242 b may also be positioned inside the treatment tool 222, for example, on an inner surface 225 thereof.
FIGS. 2D and 2E illustrate other portions of the coiled tubing system 202 including the fluid sensing system 226, which may be used to implement the example coiled tubing system 102 of FIG. 1A. In FIG. 2D, the example sensing system 226 is disposed at a lower end of the coiled tubing 114.
In FIG. 2E, the example sensing system 226 is disposed between the logging tool 128 and the treatment tool 122. In the illustrated example, the logging tool 128 is disposed above the sensing system 226 and the treatment tool 122 is disposed below the sensing system 226 in the orientation of FIG. 2E. In some examples, the fluid enters the well 104 as shown by arrows V3. In other examples, the sensing system 226 is disposed at one or more other locations on the coiled tubing 114.
FIG. 3 is a graph 350 depicting sensor data taken from the example sensing elements 242 b of FIG. 2B. The graph 350 plots flow velocity (x-axis) as a function of sensor output (y-axis) for sensing elements 242 b _x, 242 b _y, and 242 b _zat positions x, y and z, respectively. As depicted by the graph 350, the flow velocity of the sensing elements 242 b _yand 242 b _zat positions y and z are different from the flow velocity of the sensing element 242 b _xat position x. In other words, readings of the top sensing element 242 b _zand the 90-degree sensing element 242 b _yare substantially consistent in determining the flow velocity. However the bottom sensing element 242 b _xhas a flow velocity that is lower.
The graph 350 indicates that the sensing element 242 b _xat position x is pressed against the wall 205 of the well 204 and is unable to obtain proper readings. Thus, the measurements depicted by line 242 b _xtaken by sensing element 242 b at position x may be disregarded. The measurements depicted as lines 242 b _yand 242 b _ztaken by sensing elements 242 b at positions y and z, respectively, may be combined using conventional analytical techniques (e.g., curve fitting, averaging, etc.) to generate an imposed flow 244. Thus, by placing several sensing elements 242 a,b azimuthally around the circumference of a tool and detecting the lowest reading sensing element (e.g., 242 b _x), the azimuth of a flow obstruction may be determined. The sensing element located opposite to the lowest-reading sensing element (e.g., 242 b _y), or combinations of other sensing elements, may then be used to perform the flow measurement.
FIGS. 4A and 4B are schematic views of sensing elements 442 p and 442 q usable as the sensing elements 242 a,b of FIGS. 2A and 2B. Each of the sensing elements 442 p,q has a heater 454 p,q and a sensor 456 p,q, respectively, positioned in a sensor base 452. In the illustrated example, the sensor 456 p,q is a temperature sensor (or temperature sensor) capable of measuring fluid temperature.
In some examples, the sensor elements 442 p,q are calorimetric type flow sensors (or flow meters) that have two sensing elements such as, for example, a sensor for velocity measurement (scalar sensor) and a sensor for directional measurement (vector sensor). The heater 454 p,q and the temperature sensor 456 p,q interact to operate as velocity (or scalar) and directional (or vector) sensors.
To determine fluid velocity, the sensing elements 442 p,q act as calorimetric sensors. The heater 454 p,q (or hot body) of each sensor elements 442 p,q is placed in thermal contact with the fluid in the well 104. The rate of heat loss of the heater 454 p,q to the fluid is a function of the fluid velocity as well as thermal properties. A heat dissipation rate of the heater 454 p,q may be measured, and a flow velocity can be determined for a known fluid. The heater 454 p,q generates heat (e.g., from electricity), and dissipates the heat to the fluid in contact. The rate of heat generation and the temperature may be readily measurable during operation.
The temperature sensor 456 p,q may be used to monitor ambient temperature of the fluid, while the heater 454 p,q measures its own temperature during heating. The difference between the temperature of the heater 454 p,q and the ambient temperature of the fluid is defined as temperature excursion. The temperature excursion, ΔT, may be written as follows:
ΔT=T _h −T _a. Equation (1):
In Equation 1, T_arepresents the ambient temperature of the fluid as measured by the temperature sensor; T_hrepresents the temperature of the heater; and the temperature excursion is proportional to the heater power at a given flow condition. A thermal property between the heater and the fluid such as, for example, thermal conductance, G_th, may be calculated according to following expression:
$\begin{matrix} G_{th} = \frac{P}{T_{h} - T_{a}} = \frac{P}{Δ T} . & Equation (2) \end{matrix}$
In Equation 2, P represents the heater power in steady state. The inverse of this proportionality (or the thermal conductance) correlates the flow velocity V_flowbecause V_flowis a function of G_th. As provided by Equation 1, the thermal conductance is determined from three quantities: P (the heater power), T_h(the temperature of the heater) and T_a(the temperature of the fluid ambient). The quantities may be measured in steady state. Theoretically, the amount of power or temperature excursion used during measurement is immaterial to resultant thermal conductance. However, power and temperature excursion may affect accuracy because physical measurements have limits. In some cases, such as the configuration of FIG. 4B, a ΔT of a few degrees in Kelvin (K) may be considered appropriate.
In other examples, other thermal properties such as, for example, a normalized power dissipation are calculated to determine the flow velocity. The normalized power dissipation may be calculated according to the following expression:
$\begin{matrix} \frac{P}{S (T_{h} - T_{a})} . & Equation (3) \end{matrix}$
In Equation 3, the normalized power dissipation is calculated by dividing the power of the heater by the temperature excursion and an area of a heating surface of the sensor, S.
The measurements taken by the calorimetric sensing elements 454 p,q may be used obtain the heater-fluid thermal conductance, the normalized dissipated power, and/or other thermal properties. A measurement technique may involve either constant excursion or constant power. For the constant excursion technique, power sent to the heater may be regulated by electronics (e.g., the control unit 136) such that the heater temperature may be maintained at a constant excursion above the fluid ambient temperature. In steady state, the power measured is monotonically related to the thermal conductance, the normalized power dissipation, and/or other thermal properties. For the constant power technique, the heater may be supplied with a constant and predetermined power, while the heater temperature T_hvaries and may be determined by flow velocity.
FIG. 5A is a graph 657 depicting a flow response of a calorimetric sensor, such as the sensing elements 442 a,b depicted in FIGS. 4A and 4B. The resulting thermal conductance verses flow curve 658 demonstrates that thermal conductance is non-linear relative to the flow velocity. However, the thermal conductance verses flow curve 658 is monotonic. Therefore, a correlation can be established to invert the measurement, and the flow velocity can be obtained as described in conjunction with Equations 1-3.
The measurement of flow velocity is a measurement of the thermal conductance, the normalized power dissipation, and/or other thermal properties between the heater 454 p,q and the fluid. The measurement of thermal conductance and/or the normalized power dissipation may be determined with constant temperature excursion (ΔT) or constant heater power. The constant temperature excursion may regulate temperature. The constant heater power may regulate power. Either measurement technique may involve the heater 454 p,q and the temperature sensor 456 p,q.
Referring back to FIGS. 4A and 4B, the sensing elements 442 p,q may also act as scalar sensors to determine fluid direction. In the illustrated example, the sensing elements 442 p,q are capable of acting as both calorimetric sensors for determining fluid velocity and vector sensors for measuring fluid direction. calorimetric sensors may be unable to determine fluid direction. In such examples, the calorimetric sensors may respond to fluid velocity regardless of direction. Fluid direction may be acquired by a second measurement, such as by using vector sensors capable of fluid direction detection. Fluid direction may also be acquired by, for example, the sensing elements 442 p,q of FIGS. 4A and 4B configured for measurement of both fluid velocity and direction. Physics that enables directional detection may also involve detection of asymmetry in temperature between upstream and downstream sensing elements (e.g., caused by heat from the heater 454 p of the upstream sensing element), such as the upstream sensing elements 242 a and the downstream sensing elements 242 b of FIG. 2A.
FIGS. 4A and 4B depict configurations of the sensing element 442 p,q capable of detecting both fluid flow rate and direction. FIG. 4A depicts a thermocouple (TC) sensing element 442 p. FIG. 4B depicts a dual sensing element 442 q. The base 452 for each sensing element 442 p,q is sized for hosting the heater 454 p,q, the sensor 456 p,q and/or other devices therein.
In some examples, the base 452 has a minimum thickness, or is recessed in the downhole tool, to prevent damage in the well 104. The sensor base 452 is positionable downhole, for example, on the treatment device 122, 222 and/or the coiled tubing 114, 214 (FIGS. 1, 2A, 2B). The base 452 may be round as shown in FIG. 4A or rectangular as shown in FIG. 4B. The base 452 may be made of epoxy, PEEK molding and/or any other material.
The heater 454 p,q and the temperature sensor 456 p,q may be positioned in close proximity in base 452, but are thermally isolated from each other. In the illustrated example, because the heater 454 p,q creates a temperature gradient in the fluid, the temperature sensor 456 p,q is provided with sufficient thermal isolation from the heater 454 p,q to prevent the temperature sensor 456 p,q from being disturbed by the heat flux of the heater 454 p,q or thermally coupling with the heater 454 p,q, which may result in an erroneous measurement value. The temperature sensor 456 p,q may optionally be positioned in a separate package spaced from the heater 454 p,q.
The TC sensing element 442 p of FIG. 4A is depicted as having a pair of TC junctions (or sensors) 456 p _1,2on either side of a heating pad (or heater) 454 p. The TC junctions 456 p _1,2are linked by a metal wire 460. Each TC junction 456 p _1,2has a TC pad with leads 462 a,b extending therefrom. In some examples, the leads 462 are also wires operatively coupled to a controller 436 for operation therewith.
The TC junctions 456 p positioned on either side of the heater 454 p may be used to detect a temperature imbalance therebetween, and convert it into a TC voltage. A small voltage is present if the two TC junctions 456 p _1,2are at a different temperatures. The TC junctions 456 p _1,2are positioned very close to the heater 454 p (one on each side) for maximum contrast of temperature. At zero flow, the heater 454 p may heat up both TC junctions 456 p _1,2. However, the heating does not produce voltage.
Two metal pads 464 p are depicted as supporting the TC junctions 456 p _1,2. The metal pads 464 p may be provided to improve the thermal contact between the TC junctions 456 p _1,2and the fluid. The metal pads 464 p may be useful in cases where the TC junctions 456 p _1,2are of a small size. The metal pads 464 p and the TC junctions 456 p _1,2may be held together by thermal adhesives such as silver epoxies or any other thermally conductive adhesives. The metal pads 464 p are positioned in alignment with the heater 454 p, thereby defining a flowline 466 p along the sensing element 442 p as indicated by the arrow.
TC voltage (y-axis) as a function of flow velocity (x-axis) is show in a graph 659 of FIG. 5B. The graph 659 exhibits an odd function of the flow velocity measured by the TC junctions 456 p _1,2. The magnitude of a maxima near zero flow tapers off gradually with increasing velocity. At zero crossing, the TC signal output undergoes an abrupt change in polarity from negative to positive as indicated by curves 661 a,b, respectively. This change in signal polarity may be used to detect the fluid direction as described in greater detail below.
The temperature profile along a flow stream of, for example, the sensing element 442 p is shown schematically in FIG. 6. FIG. 6 is a graph 663 depicting temperature (y-axis) versus velocity (x-axis). As depicted by this graph, the heater 454 p generates a constant heat T_hmeasurable by the TC junction 456 p _1,2on either side thereof. Heat from the heater 454 p is carried downstream by the fluid forming a hot stream. The velocity V1, V2 and V3 are measured at, for example, different time intervals. Visibility of the thermal gradient may depend on the velocity. The thermal gradient between upstream and downstream is detectable with the sensor element 442 p. This creates a temperature contrast between the upstream and downstream TC junctions 456 p _1,2. This indicates that the flow is moving towards the TC junctions 456 p ₂, thereby indicating fluid flow direction. By detecting asymmetry between the TC junctions 456 p _1,2, the fluid direction can be determined as indicated by the arrow.
The dual-element sensing element 442 q of FIG. 4B is depicted as having two identical elements (sensors/heaters) 456 q/454 q. The sensors/heaters 456 q/454 q are depicted as Element M and Element N in the sensing element 442 q. In some examples, the heater 454 q and the sensor 456 q (and, therefore, Elements M and N) are interchangeable in function and operation. In some such cases, the sensor 456 q is capable of performing the functions of the heater and the heater 454 q is capable of performing the functions of the sensor. The Elements M and N are operatively linked via links 455 to the controller 436 for operation therewith.
In some examples, a desired measurement may be operated in self-referenced mode in which a single Element M or N plays a dual role, both as heater and as temperature sensor. In some such cases, the heater and the temperature sensor may utilize a time multiplexing technique. In some examples, the role of the heater 454 q and temperature sensor 456 q may be reassigned at anytime. This measurement scheme may be used to provide flexibility in designing and/or operating the sensor element 442 q, which may be tailored to a particular application.
An asymmetry of temperature between the identical Elements M and N is detectable by the dual-element sensor 442 q. The two identical Elements M and N are positioned along a line of flow of the fluid as indicated by the arrow. The Elements M and N may be positioned in close proximity, for example, within the same base (or package) 452.
Measurement by the sensor element of FIG. 4B may be achieved using various methods. A first method involves measuring the heater power in flow using Element M as the heater and Element N as the temperature sensor. After a stable reading is attained, the roles of Elements M and N interchange and the measurement is repeated. Comparing the power of the two measurements, fluid direction can be ascertained. The heater that consumes more power is located upstream, provided that the flow does not vary in the meantime. A second method that may be used involves measuring by heating both elements M and N simultaneously with the same amount of power. The measurements of each element may be compared. Whichever element reveals a higher temperature is downstream in the direction of the fluid flow. A third method that may be used involves watching the temperature of Element M while switching on and off Element N at a certain power level. If an alteration of temperature is noticed, Element N may be assumed to be upstream of Element M. No change may suggest otherwise.
With the first two methods, where quantities are compared across Elements M and N, a good match of characteristics of the two elements M, N reduces potential errors. The match of elements may be achieved by calibration and normalization. The third method, on the other hand, may be used without as good of a match. Dual-element sensors are usable, for example, for bi-directional flow.
When the temperature sensor 456 p,q and the heater 454 p,q of FIGS. 4A and 4B reside in the same package (for instance, due to space constraint), the temperature sensor 456p,q is positioned upstream of the heater 454 p,q (or element M is upstream of Element N). If flow goes in both directions, the temperature sensor 456 p,q and heater 454 p,q (or Elements M and N) may be positioned in a side-by-side (or flowline) configuration in line with the flow of the fluid as shown in the sensing elements 442 p,q of FIGS. 4A and 4B.
While FIG. 4A depicts a single heater 454 p with a pair of TC junctions 456 p and FIG. 4B depicts a single heater 454 p with a single temperature sensor 456 q, other examples employ multiple heaters 454 p,q and/or sensors 456 p,q. Additional sensors and/or other devices may be incorporated into the sensing elements 442 p,q and/or used in combination therewith. In sensor systems including multiple heaters 454 p,q, one temperature sensor 456 p,q can serve multiple heaters 454 p,q. Some multi-elements sensors have more than two elements (e.g., M, N, P, D . . .). As shown in FIG. 4B, a third element O may be provided. In another method of measurement, the three or more elements (e.g., M, N, O) may be used to detect fluid direction by heating a middle element and comparing the temperature between upstream and downstream elements thereabout.
As shown, the sensing elements 442 p,q of FIGS. 4A and 4B (and/or the sensors, heaters, elements and/or other components used therein and/or therewith) are operatively coupled to the controller 436 for providing power, collecting data, controlling and/or otherwise operating the sensing element 442 p,q. The controller 436 may be, for example, the logging tool 128, the control unit 136 and/or other electronics capable of providing power, collecting data, controlling and/or otherwise operating the temperature sensors 456 p,q, heater 456 p,q and/or other elements of the sensing elements 442 p,q. The power sources may be batteries, power supplies and/or other devices internal to and/or external to the sensing elements. In some cases, other devices such as the logging tool 128 of FIG. 1A may provide power thereto. Such electronic devices may be internal and/or external to the sensing elements. Communication devices may be provided to wire and/or wirelessly coupled the sensing elements to downhole and/or surface communication devices for communication therewith. In some cases, communication devices, such as transceivers may be provided in the sensing elements. In other cases, the sensing elements may be linked to the logging tool 128 (FIG. 1A) or other devices for communication as desired.
The sensing elements are also operatively coupled to and/or in communication with databases, processors, analyzers, and/or other electronic devices for manipulating the data collected thereby. The power, electronic and/or communication devices may be used to manipulate data from the sensing elements, as well as other sources. The analyzed data may be used to make decisions concerning the wellsite and operation thereof In some cases, the data may be used to control the well operation. Some such control may be done automatically and/or manually as desired.
While elements of the heater and the temperature sensor may be physically identical, the sensor can have a variety of types, forms and/or shapes. FIG. 7 depicts the sensor 770 usable as an element of the sensor elements 454 p,q of FIGS. 4A and/or 4B. FIG. 7 depicts the sensor 770 usable as the heater 454 q and/or the temperature sensor 456 q, as elements M, N and/or O, or in combination therewith. A shown, the sensor 770 is positionable in the base 452. The sensor 770 may be operatively coupled to the controller 436 via wires 774 for operation therewith in the same manner as previously described for the sensor elements 442 p,q.
The example sensor 770 of FIG. 7 is an RTD type sensor with a resistance that varies with temperature. In some examples, the sensor 770 is used for temperature sensing purposes. However, the sensor 770 may generate heat when current passes through the sensor 770. Thus, the example sensor 770 can be used both as a heater and a temperature sensor (e.g., 454 p,q and 456 p,q of FIG. 4B).
A thin-film type RTD capable of use as both a heater and temperature sensor may be used so that it can interchangeably operate as the Element M, N and/or O of FIG. 4B. As shown in FIG. 7, the sensor 770 positioned in the base 452 has a front surface (or contact surface) 772 positionable adjacent the fluid for taking measurements therefrom. In some examples, the sensor 770 employs platinum in the form of either wire or thin film (or resistor) 774 deposited on a heat-conductive substrate 776, such as sapphire or ceramic. The wire 774 is positioned in the film 776 and extends therefrom for operative linkage with the controller 436. The heat-conductive substrate 776 may be adhered or bonded to a thin pad 778 (made of, for example, Inconel or ceramic substrate) by a thermally conductive adhesive 780, such as silver epoxy, or by brazing. In some examples, such bonding provides low thermal resistance.
In the illustrated example, the sensor 770 is wrapped in protective packaging, but they may differ by thermal mass and, hence, response time. The shape of the pad 778 may be square, circular or any other shape capable of supporting the RTD in the base 452. In some examples, the pad 778 has a dimension of about 10 mm (or more or less), and a thickness sufficient for mechanical viability. The thickness and material selected may determine the performance of heater-fluid thermal contact.
The example sensor 770 may be configured with a large surface area for contact with the fluid and/or large thermal mass for passage of heat therethrough. A larger thermal mass may result in a relatively slower measurement response. However, the thermal mass may also assist in reducing (e.g., averaging out) spurious variations in readings caused by turbulence. Sensor electronics may also be provided to reduce spurious variations.
The sensor 770 and/or the sensing element 442 q may be configured in a surface (or non-intrusive) form with a low profile (or thickness) as shown in FIGS. 7 and 4B. The sensor 770 and/or the sensing element 442 q may be positionable downhole via a downhole tool (e.g., coiled tubing system 102 of FIG. 1A) extending a small distance (if any) therefrom. This low profile or non-intrusive surface form may be provided to reduce the disturbance to the fluid flowing across the sensor, while still allowing for measurement of the fluid. Moreover, the low profile surface form may also be configured to limit the amount of protrusion from the downhole the tool and, therefore, potential damage thereto.
FIG. 8 illustrates an example downhole tool 800, which may be used to implement the example coiled tubing system 102 of FIG. 1A. The example downhole tool 800 is disposed in a wellbore 802. In the illustrated example, the downhole tool 800 is disposed adjacent a packer 804. The example downhole tool 800 includes at least the sensing element 242 a. In some examples, the downhole tool 800 includes a plurality of sensing elements 242 a disposed about a circumference of coiled tubing 805 of the downhole tool 800.
In the illustrated example, a first fluid 806 is pumped via the downhole tool 800 in a first direction (e.g., downward in the orientation of FIG. 8) to substantially fill a first area 808 of the wellbore 802 adjacent the packer 804. In some examples, the first area 808 is below the downhole tool 800 in the orientation of FIG. 8. In the illustrated example, the first fluid 806 is cement, which may fill in or plug a portion of the wellbore 802. As the first fluid 806 fills the first area 808 (e.g., once the portion of the wellbore 802 is plugged), the first fluid 806 flows in a second direction (e.g., upward in the orientation of FIG. 8). In some examples, a second fluid 810 (e.g., a protection fluid such as, for example, water) is pumped in the first direction into a fluid flow passageway 812 in fluid communication with the first area 808 to substantially fill a second area 814 of the wellbore 802 adjacent the first area 808 (e.g., to enable the cement to set). In the illustrated example, the fluid flow passageway 812 is an annulus between the downhole tool 800 and the wellbore 802.
The example sensing element 242 a may be used to determine if the first fluid 806 has flowed in a second direction into the second area 814. In some examples, the sensing element 242 a may be used to determine if the first fluid 806 flowed in the second direction into the second area 814 based on a fluid parameter (e.g., direction of the fluid flow, thermal properties, etc.). For example, if the sensing element 242 a is used to determine that the first fluid 806 and/or the second fluid 810 is flowing in the first direction, the first fluid 806 may not have filled the first area 808 and/or the second fluid 810 may be substantially filling the second area 814. If the sensing element 242 a is disposed in the second area 814 and is used to determine that the second fluid 810 is moving in the second direction, the first fluid 806 may have flowed into the second area 814.
In some examples, a thermal property (e.g., thermal conductance, normalized power dissipation, temperature, etc.) may be determined via the example sensing element 242 a, which may indicate that the first fluid 806 has substantially filled a portion of the second area 814 and/or the first area 808 (e.g., from at least the packer 804 to the sensing element 242 a). For example, if the sensing element 242 a is disposed in the second area 814 and a thermal property value that is associated with the first fluid 806 is determined via the sensor 242 a (e.g., a thermal conductance of the first fluid 806 is determined to be about the same as a reference thermal conductance of cement), the first fluid 806 may have flowed into and/or substantially filled a portion of the second area 814. In some examples, the downhole tool 800 is moved from a first position to a second position along the wellbore 802 to determine which portions of the first area 808 and/or the second area 814 the first fluid 806 and/or the second fluid 810 have substantially filled.
FIG. 9 illustrates an example downhole tool 900, which may be used to implement the example coiled tubing system 102 of FIG. 1A. The example downhole tool 900 is disposed in a wellbore 902. In the illustrated example, the downhole tool 900 is disposed adjacent a first production zone 904 and a second production zone 906. The example downhole tool 900 includes the sensing element 242 a and the sensing element 242 b. In some examples, the downhole tool 900 includes a plurality of the sensing elements 242 a,b disposed about a circumference of coiled tubing 908 of the downhole tool 900.
In the illustrated example, a first fluid 910 is pumped via the downhole tool 900 in a first direction (e.g., downward in the orientation of FIG. 9) to substantially fill a first area 912 of the wellbore 902 adjacent the first production zone 904. In some examples, the first area 912 is below (in the orientation of FIG. 9) a portion of the downhole tool 900 including the sensing element 242 a and/or the sensing element 242 b. In the illustrated example, the first fluid 910 is treatment fluid, which may be pumped via a treatment device 914. The example treatment device 914 may be implemented using the example treatment device 122. When the first fluid 910 fills the first area 912, the first fluid 910 prevents (e.g., reduces or prohibits) a first production fluid 916 (e.g., water) from flowing from the first production zone 904 into the first area 912.
In some examples, a second fluid 918 (e.g., a protection fluid such as, for example, water) is pumped in the first direction into a fluid flow passageway 920 in fluid communication with the first area 912 to substantially fill a second area 922 of the wellbore 902 adjacent the first area 912. In some examples, the second fluid 918 is pumped into the second area 922 to prevent the first fluid 910 and, thus, the first production fluid 916 from flowing into the second production zone 906 and/or mix with a second production fluid 924 of the second production zone 906. In the illustrated example, the fluid flow passageway 920 is an annulus between the downhole tool 900 and the wellbore 902.
One or both of the example sensing elements 242 a and 242 b may be used to determine if the first fluid 910 has flowed in a second direction (e.g., upward in the orientation of FIG. 9) into the second area 922. In some examples, the sensing element 242 a and/or the sensing element 242 b may be used to determine if the first fluid 910 flowed in the second direction into the second area 922 based on a fluid parameter (e.g., direction of the fluid flow, thermal properties, etc.). For example, if the sensing element 242 a and/or the sensing element 242 b is used to determine that the first fluid 910 and/or the second fluid 918 is flowing in the first direction, the first fluid 910 may not have filled the first area 912 and/or the second fluid 918 may be substantially filling a portion of the first area 912 and/or the second area 922. If the sensing element 242 a is disposed in the second area 922 and is used to determine that the second fluid 918 is moving in the second direction, the first fluid 910 may have flowed into the second area 922. In some examples, if a first velocity of the first fluid 910 determined via the sensing element 242 b is greater than a second velocity of the second fluid 918 determined via the sensing element 242 a, the first fluid 910 may be flowing downward in the orientation of FIG. 9 and/or flowing into the first production zone 904.
In some examples, a thermal property (e.g., thermal conductance, normalized power dissipation, etc.) may be determined via the example sensing element 242 a and/or the example sensing element 242 a, which may indicate that the first fluid 910 has substantially filled a portion of the second area 922 and/or the first area 912. For example, if the sensing element 242 a is disposed in the second area 922 and a thermal property value that is associated with the first fluid 910 is determined via the sensor 242 a (e.g., a thermal conductance of the first fluid 910 is determined to be about the same as a reference thermal conductance of water), the first fluid 910 may have flowed into and/or substantially filled a portion of the second area 922. In some examples, the downhole tool 900 is moved from a first position to a second position to determine which portions of the first area 912 and/or the second area 922 the first fluid 910 and/or the second fluid 918 have substantially filled.
FIGS. 10-11 are flowcharts representative of example methods disclosed herein. At least some of the example methods of FIGS. 10-11 may be carried out by a processor, the logging tool 128, the controller 436 and/or any other suitable processing device. In some examples, at least some of the example methods of FIGS. 10-11 are embodied in coded instructions stored on a tangible machine accessible or readable medium such as a flash memory, a ROM and/or random-access memory RAM associated with a processor. Some of the example methods of FIGS. 10-11 may be implemented using any combination(s) of application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), field programmable logic device(s) (FPLD(s)), discrete logic, hardware, firmware, etc. Also, one or more of the operations depicted in FIGS. 10-11 may be implemented manually or as any combination of any of the foregoing techniques, for example, any combination of firmware, software, discrete logic and/or hardware.
Further, although the example methods are described in reference to the flowcharts illustrated in FIGS. 10-11, many other methods of implementing the example methods may be employed. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, removed, sub-divided, or combined. Additionally, any of the example methods of FIGS. 10-11 may be carried out sequentially and/or carried out in parallel by, for example, separate processing threads, processors, devices, discrete logic, circuits, etc.
FIG. 10 illustrates an example method 1000 disclosed herein that may be used to determine one or more fluid parameters. At block 1002, a downhole system such as, for example, the coiled tubing system 100 of FIG. 1A is deployed into a well with a sensor (e.g., one of the example sensor elements 242 a,b of FIG. 2A) thereon. In some examples, the sensor includes a heater (e.g., the example heater 454 of FIG. 4, the example RTD sensor 770 of FIG. 7) and a temperature sensor (e.g., the example temperature sensor 456 of FIG. 4, the example RTD sensor 770 of FIG. 7). At block 1004, fluid is injected from the downhole system into the well via an injection port (e.g., the example injection port 224 of FIG. 2) of the downhole system.
At block 1006, a first measurement (e.g., a temperature of the fluid) is taken with the temperature sensor. At block 1008, a second measurement (e.g., power dissipated via the heater, a temperature of the heater, etc.) is taken with the heater. At block 1010, a fluid parameter (e.g., a fluid velocity, a direction of fluid flow) is determined based on the first measurement and the second measurement. At block 1012, the fluid parameter is analyzed. In some examples, the measurements and/or the parameter are stored, processed, reported, and/or manipulated, etc.
FIG. 11 illustrates another example method 1100 disclosed herein, which may be used to determine if a first fluid has substantially filled a portion of a wellbore. The example method 1000 begins by disposing a downhole tool (e.g., the example downhole tool 800 of FIG. 8, the example downhole tool 900 of FIG. 9) in a wellbore (block 1102). In some examples, the downhole tool includes a sensor (e.g., one of the example sensor elements 242 a,b of FIG. 2A) having a heater (e.g., the example heater 454 of FIG. 4, the example RTD sensor 770 of FIG. 7) and a temperature sensor (e.g., the example temperature sensor 456 of FIG. 4, the example RTD sensor 770 of FIG. 7). At block 1104, a first fluid is pumped into a first area of the wellbore.
For example, cement may be pumped into the first area of the wellbore to fill in and/or plug an end of the wellbore. In some examples, a treatment fluid is pumped into the first area to prevent a first production fluid from flowing from a first production zone into the first area. In some examples, the first fluid is pumped into the first area in a first direction (e.g., away from a surface of Earth.) At block 1106, a second fluid (e.g., protection fluid) is pumped into a second area of the wellbore in fluid communication with the first area (e.g., the second area is adjacent the first area). The second fluid may be pumped in the first direction into the second area. In some examples, the sensor is disposed in the second area.
At block 1108, a response of the sensor is obtained. For example, a power dissipated by the heater, a fluid temperature, and/or a temperature of the heater may be obtained. Based on the response, a fluid parameter (e.g., a direction of fluid flow, a normalized heat dissipation, a thermal property of the fluid such, as, for example, temperature, thermal conductance, etc.) is determined (block 1110). At block 1112, if the first fluid substantially filled (e.g., flowed into) a portion of the second area is determined based on the fluid parameter. For example, if the sensor is disposed in the second area and the fluid flow direction determined via the sensor is in a second direction, it is determined that the first fluid has substantially filled (e.g., flowed into) the portion of the second area. In some examples, if the sensor is disposed in the second area and the fluid parameter is associated the first fluid (e.g., the thermal conductance of the first fluid is determined to be about the same as a reference thermal conductance of the first fluid), it is determined that the first fluid has substantially filled the portion of the second area.
If it is determined that the first fluid has not substantially filled the portion of the second area, the example method 1100 returns to block 1104. If it is determined that the first fluid substantially filled the portion of the second area, the downhole tool is moved from a first position to a second position (block 1114). In such some examples, a plurality of sensor responses are obtained to determine an amount of the first area and/or the second area filled by the first fluid and/or the second fluid. In other examples, if it is determined that the first fluid substantially filled a portion of the second area, the example method returns to block 1106.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

What is claimed is:

1. A method, comprising:

pumping a fluid in a first direction to substantially fill a first area of a fluid flow passageway with the fluid;

determining a fluid parameter via a sensor disposed in a second area adjacent the first area, the sensor comprising a heater and a temperature sensor; and

based on the fluid parameter, determining if the first fluid has flowed in a second direction into the second area.

2. The method of claim 1 further comprising determining if the first fluid substantially filled a portion of the second area.

3. The method of claim 2 further comprising moving the sensor from a first position to a second position if the fluid has substantially filled the portion of the second area.

4. The method of claim 1 wherein determining the fluid parameter comprises determining a fluid flow direction.

5. The method of claim 1 wherein determining the fluid parameter comprises determining an amount of heat dissipated by the heater.

6. The method of claim 1 wherein the fluid flow passageway is a wellbore and wherein pumping the first fluid comprises pumping cement into the wellbore via a downhole tool.

7. The method of claim 1 further comprising pumping a second fluid into the second area.

8. The method of claim 7 wherein pumping the second fluid comprises pumping the second fluid in the first direction.

9. A method, comprising:

pumping a first fluid into a first area of a wellbore via a downhole tool, the downhole tool including a sensor comprising a heater and a temperature sensor;

pumping a second fluid into a second area of the wellbore in fluid communication with the first area;

determining a fluid parameter via the sensor; and

based on the fluid parameter, determining if the first fluid has substantially filled a portion of the second area.

10. The method of claim 9 wherein pumping the first fluid comprises pumping cement.

11. The method of claim 9 wherein pumping the second fluid comprises pumping protection fluid.

12. The method of claim 9 wherein pumping the first fluid into the first area comprising pumping the first fluid below a portion of the downhole tool and wherein pumping the second fluid into the second area comprises pumping the second fluid into an annulus between the downhole tool and the wellbore.

13. The method of claim 9 wherein determining the fluid parameter comprises determining a fluid flow direction.

14. The method of claim 9 wherein determining the fluid parameter comprises determining an amount of heat dissipated by the heater.

15. A method, comprising:

disposing a downhole tool in a wellbore, the downhole tool comprising a sensor having a heater and a temperature sensor;

pumping fluid into the wellbore via the downhole tool;

determining a response of the sensor; and

based on the response, determining if the fluid substantially filled a portion of the wellbore.

16. The method of claim 15 further comprising moving the downhole tool from a first position to a second position if the fluid substantially filled the portion of the wellbore.

17. The method of claim 15 wherein pumping fluid into the wellbore comprises pumping cement into the wellbore.

18. The method of claim 15 wherein determining the response of the sensor comprises determining an amount of heat dissipated by the heater.

19. The method of claim 15 wherein determining if the fluid substantially filled the portion of the wellbore comprises determining a fluid flow direction.

20. The method of claim 15 further comprising pumping protection fluid into the wellbore.