Patent Application
20110100112
1. Technical Field
Embodiments described generally relate to flow meters for use in hydrocarbon wells. In particular, some embodiments of flow meters are detailed that are configured for long-term downhole disposal in hydrocarbon wells. Such flow meters may be well suited for use in conjunction with completion and production operations, although other operations may also be appropriate. Although a field has been described, this is primarily for the non-limiting purposes of simplifying the detailed description. Aspects and concepts detailed herein may apply to other related and non-related fields and applications.
2. Description of the Related Art
The following descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section.
Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of the potentially enormous expense of well completion, added emphasis has been placed on well monitoring and maintenance throughout the life of the well. That is, placing added emphasis on increasing the life and productivity of a given well may help ensure that the well provides a healthy return on the significant investment involved in its completion. Thus, over the years, well diagnostics and treatment have become more sophisticated and critical facets of managing well operations.
In certain circumstances, well diagnostics takes place on a near-continuous basis such as where pressure, temperature or other sensors are disposed downhole, for example, in conjunction with production tubing. That is, a monitoring tool with sensors may be affixed downhole with tubing in order to track well conditions during hydrocarbon recovery. In some cases, the monitoring tools may be fairly sophisticated with capacity to simultaneously track a host of well conditions in real time. Thus, both sudden production profile changes and more gradual production changes over time may be accurately monitored. Such monitoring allows for informed interventions or other adjustments where appropriate.
Monitoring tools as noted above are often equipped with flow meters in order to keep track of downhole fluid flow. Ultimately, continuous monitoring of downhole fluid flow may be a fairly direct indicator of the hydrocarbon recovery rate for a given well. The flow meter itself may be of a host of different variations. Some of the more common examples in the oilfield industry include rotameters, mass flow meters, electromagnetic flow meters, and venturi meters.
Unfortunately, the accuracy of the flow meters noted above may be severely affected by particular downhole conditions. For example, high turbulence and pressure variations may substantially affect flow meter readings for the variations noted above. Additionally, rotameters and mass flow meters are also particularly susceptible to variations in downhole fluid type. That is, the more the fluid flow varies over time in consistency in terms of water, hydrocarbon, gas bubbles, etc., the more unreliable the readings obtained by rotameters and mass flow meters. Thus, given the naturally variable and often turbulent conditions of the downhole environment, readings obtained with the noted flow meters are often compromised.
As an alternative to the above noted flow meter types, turbine meters are often incorporated into the monitoring tool. Like some other flow meter types, the turbine flow meter includes a cylindrical housing that defines a central channel through which downhole fluids may flow. However, the turbine based flow meter also includes at least one rotable turbine that is exposed to the central channel and any fluid flow there through. As such, the rate of rotation of the turbine blade may be utilized to continuously monitor flow rate through the flow meter.
The described turbine flow meter relies primarily on mechanical parts configured to display a great deal of movement (i.e. a rotating turbine blade). Additionally, the turbine flow meter is often employed downhole on a long term or near permanent basis, for example, following well completions. Unfortunately, given that the interior of the meter is configured for exposure to the well, this means that the meter is naturally subject to a great deal of corrosion and other undesirable buildup over time. Thus, unlike a more solid-state type of flow meter, such as a venturi meter, the turbine flow meter, is particularly susceptible to deterioration over time. That is, as corrosion takes effect at the surfaces of the turbine blade and supportive features, the ability of the turbine to rotate is markedly affected. Ultimately, the operator is again left with a compromised flow-meter option in terms of long term post completion deployment.
A meter for measuring downhole flow in a well is provided. The meter may include a cylindrical housing with a resonator beam secured to a wall thereof. The beam may extend into a channel through the housing and is integrated with piezo-material so as to generate a voltage in response to channeled flow induced vibration of the beam.
Other or alternative features will become apparent from the following description, from the drawings, and from the claims.
Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying drawings illustrate only the various implementations described herein and are not meant to limit the scope of various technologies described herein. The drawings are as follows:
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described illustrative embodiments may be possible. In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, “connecting”, “couple”, “coupled”, “coupled with”, and “coupling” are used to mean “in direct connection with” or “in connection with via another element”; and the term “set” is used to mean “one element” or “more than one element”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments.
Embodiments are described with reference to certain types of downhole hydrocarbon recovery operations. In particular, focus is drawn to flow meter tools and techniques which may be employed in conjunction with completion assemblies or production tubing. However, tools and techniques detailed herein may be employed in a variety of other hydrocarbon operations. These may include the use of a piezo-based downhole flow-meter in operations ranging from logging to well treatments, including a variety of interventional applications. Regardless, embodiments of flow-meters described herein are configured to acquire downhole flow data through a piezo-material integrated resonator beam. The resonator beam is configured to impart a flow generated voltage uphole which may be utilized in establishing downhole flow characteristics.
Referring now to
With particular reference to
Continuing with reference to
As indicated above, the resonator beam 101 may be integrated with piezo-material portion 102. The piezo-material may include conventional polymer or co-polymer voltage responsive materials such as polyvinylidene fluoride, among others. Additionally, voltage responsive ceramics such as lead zirconate may be employed. Regardless of the type of material, the piezo-material may be implemented at the beam 101, for example, as an integrated coating such as piezo-material portion 102. Thus, vibration of the beam 101 due to flow 160 may result in voltage generation as is expected with such materials. In the embodiment shown, this generated voltage may be picked up by an electrical line 150 terminally immersed in or electrically coupled to the piezo-material portion 102. As such, the generated voltage signal may be transmitted uphole, ultimately providing information corresponding to flow 160. As detailed further below, a variety of techniques may be employed for advancing and translating of this electrical signal in a manner that results in usable flow information.
In addition to the exemplary features noted above, the depicted flow-meter 100 may be provided with a configuration in which the diameter d at the inlet 125 and outlet 175 is smaller than the diameter D of the middle portion or belly 140. As a result, the overall profile of the flow meter 100 in the well 180 may reduced as compared to a uniform diameter configuration. Perhaps more significant however, the smaller diameter d of the inlet 125 relative to the belly 140 may be employed so as to reduce the speed of flow 160 in the area within the middle portion of the flow meter 100. Thus, the rate or speed of flow 160 at the belly 140, where the resonator beam 101 is located, may be reduced to a more manageable level as described below.
In one embodiment, the diameter d of the inlet 125 may be between about ½ and about 3 inches. In this situation, the diameter D of the belly 140 may be between about 5 and about 6 inches (with the beam 101 extending between about 2 and 3 inches into a central portion of the belly 140). Of course, however, the differences between the diameters d, D may be larger, smaller, or non-existent all together, depending upon the expected nature and flow conditions of the well 180. Regardless, the data obtained from the flow meter 100 may be evaluated and calibrated in light of the particular sizing and flow meter configuration employed.
In an alternate embodiment where flow rate is relatively low, a flow meter 100 may be disposed downhole that employs a larger diameter d inlet 125 as compared to the diameter D of the belly 140. So, for example, in this case, the inlet 125 may be of a diameter d that is between about 5 and about 6 inches, whereas the diameter D of the belly 140 may be reduced down to between about ½ and about 3 inches. Such an embodiment of flow meter 100 may be utilized in conjunction with a logging operation following a sudden loss of production. With a flow meter 100 having such a configuration, the rate of flow 160 may be increased at the location of the resonance beam 101 so as to acquire meaningful flow readings during the log. Of course, embodiments of the flow meter 100 may be configured such that the expected or actual flow rate proximate to the resonance beam 101 is adjusted to match an optimal frequency for the resonance beam 101, such that overall sensitivity of the flow meter 100 is enhanced.
In the embodiment of
The above-noted embodiment of lengthy section of enlarged casing 185 may be of a diameter that exceeds other adjacent casing 185 by at least the profile of the entire flow meter 100. For example, consider a flow meter 100 of a diameter of less than about 3 inches (e.g. at its belly 140) which is disposed within a generally 10 inch well 180. In such a circumstance, the enlarged section of casing 185 may be about 16 inches or more so as to fully remove the flow meter 100 secured there at from the main channel of the well 180. That is, as compared to the smaller adjacent casing 185, an extra three inches of accommodating diameter may be present at the enlarged section of casing 185. Furthermore, in order to ensure that flow 160 is computable and properly accounted for by the meter 100 at the enlarged section of casing 185, this enlarged section may be of a substantial length. For example, in one embodiment, the enlarged section of casing 185 may be of a length that is between about 7 and about 15 times the diameter of the inlet portion 125 of the flow meter 100.
Continuing now with reference to
In the overview of
The production tubing 285 is run to a location of the well 180 adjacent the production region 297 where it may be isolated by a packer assembly 275. This assembly 275 provides a sealing engagement between the tubing 285 and the wall of the well casing 185. As a result, any uphole flow 160 is directed through the production tubing 285 to the surface. With this in mind, the flow meter 100 located near the end of the production tubing 285 should acquire a direct measure of the total downhole flow 160. With added reference to
Referring now to
The fiber optic communication line 375 may be equipped with a protective jacket of stainless steel or other suitable corrosion resistant material. Nevertheless, the line 375 may be substantially smaller in diameter and lighter than a conventional electronic cable with metal conductive core. For example, in some embodiments the line 375 may have an outer diameter of less than about 0.25 inches. Given the minimal amount of available well 180 space and a potential distance to the surface of several thousand feet, use of a smaller diameter, lighter weight communication line may be of significant benefit.
Upon reaching the surface, the light signal may be received by the control unit 240 and converted back into usable electronic data with an opto-electric converter of the unit 240. In other embodiments where the flow meter 300 is positioned closer to surface, the data unit 350 may be equipped with a wireless transceiver for wireless communication with the control unit 240. Alternatively, the data unit 350 and the flow meter 300 may be provided as part of a basic logging tool or other form of access assembly that is not intended to utilize flow measurements in real-time. In such an embodiment, the data unit 350 may serve as a data storage unit from which flow data may be acquired and utilized at a later point in time (e.g. following an application with the tool or assembly).
Continuing with reference to
Referring now to
Each of the above described beams 301, 302, 303, 304 of
Referring now to
Due to the parallel orientation of the beam 401 relative to the flow 160, flow induced vibration of the beam 401 is primarily dependent upon a resonator head 440. That is, the resonator head 440 is positioned at the lagging end (downstream) of the beam 401. Relative to the previous illustrative embodiment, any vortex shedding 310 (as seen in
The leading orientation or upstream configuration of the resonator head 441 avoids any potential shedding interference resulting from the support structure 431 interfacing the flow 160 in advance of the resonator features 441, 411. That is, with such an orientation, the resonator features 441, 411 are ensured to interface and interact with a relatively undisturbed fluid flow 160. Further, regardless of the configuration of the resonator head 411, a leading orientation provides the detecting components (i.e., 441, 411) of the flow meter 450 with an inherent natural instability that may enhance sensitivity to the fluid flow 160. Accordingly, even a substantially low flow rate is likely to generate a detectable frequency in the beam 411 sufficient for voltage generation by an associated piezo-material. Such an embodiment of flow meter 450 may be especially useful in low flow operations when incorporated into a logging tool.
Referring now to
A resonator beam within the flow meter may then be exposed to flow as indicated at 550 so as to generate a vibrational frequency in the beam. With the beam vibrating, a piezo-material integrated with the beam may be utilized to generate voltage data corresponding to flow rate as indicated at 570. This data may then be analyzed to determine the flow rate (see 580).
Embodiments described herein include a flow meter for use in the downhole environment of a well without the reliance on a rotating turbine blade or other substantial moving parts. Rather, the flow meter may be substantially solid state in nature in that a cohesive structure may be provided. Thus, unlike a turbine-based flow meter, embodiments detailed herein may be particularly beneficial for disposal in a well for near permanent monitoring of downhole flow rate. That is, embodiments described herein may be provided with an inherent degree of corrosion resistance and are not particularly susceptible to the buildup of debris as may be the case of flow meters employing rotating turbine blades. As a result, substantially reliable flow monitoring over extended periods of time may be achieved with aspects of the described embodiments of representative flow meters.
The preceding description has been presented with reference to presently preferred embodiments. However, other embodiments not detailed herein may be employed. Furthermore, persons skilled in the art and technology to which these embodiments pertain will appreciate that still other alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle and scope of these embodiments. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.
