Pressure Pulse Reach Extension Technique

Abstract

A pressure pulse tool and techniques that allow for a reciprocating piston at a frequency independent of a flow rate of fluid which powers the reciprocating. The architecture of the tool and techniques employed may take advantage of a Coand{hacek over (a)} or other implement to alternatingly divert fluid flow between pathways in communication with the piston in order to attain the reciprocation. Frequency of reciprocation may be between about 1 Hz and about 200 Hz or other suitably tunable ranges. Once more, the frequency may be enhanced through periodic exposure to annular pressure. Extended reach through use of such a pressure pulse tools and techniques may exceed about 2,000 feet.

Description

BACKGROUND

Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on maximizing productivity over the course of the well's life. Thus, well logging, profiling and monitoring of well conditions are playing an ever increasing role in oilfield operations. Similarly, more actively interventional applications are regularly called for such as clean-out applications, opening or closing valves and sliding sleeves or any number of other maneuvers targeting maximized recovery and well life.

In addition to regular intervention for sake of monitoring and/or managing well operations, the well itself may also be of fairly sophisticated architecture. For example, in an attempt to maximize recovery from the reservoir and extend the useful life of the well, it may be of a fairly extensive depth and tortuous configuration. This may include overall depths in the tens of thousands of feet range. Once more, such wells may include extended horizontal or deviated sections of several thousand feet. For example, it is becoming increasingly more common for wells to include horizontal sections that are 10-15,000 feet long or more. As a result, interventions through such wells are becoming of ever increasing difficulty as noted below.

The above described interventions through deviated wells are generally achieved by way of coiled tubing, pipe or other suitable form of rigid or semi-rigid well access line or conveyance. Thus, a logging, clean-out, shifting or other application tool may be driven through deviated well sections. Unfortunately, after a few thousand feet of conveyance through such a section, the tubing will generally begin to undergo sinusoidal buckling. This is followed by helical buckling, and soon thereafter, helical lock of the line within the deviated section such that further advancement is impossible. As a practical matter, without added measures being taken, it is unlikely that conventional coiled tubing would be able to reach beyond about 2-6,000 feet into a horizontal well section. Of course, this is problematic where the target location for the application at hand is at a location beyond, 6,000 feet, for example. Further, this problem has become increasingly common given the ever increasing depths of wells and deviated well sections.

Various techniques or conveyance aids have been developed to help extend the reach of coiled tubing through such deviated sections such that the appropriate application tool may arrive at the desired target location. For example, typical coiled tubing of about 1.5 inches in diameter may be replaced with one of 2-3 inches in diameter. This larger tubing may noticeably extend reach. Unfortunately, use of such heavier tubing presents added equipment related compatibility issues at the oilfield surface. For example, this may require a specially built coiled tubing spool, injector, and other high dollar machinery to accommodate the heavier tubing. Thus, as an alternative, a coiled tubing may be utilized that is of a variable wall thickness, for example, being thinner near the downhole end. This may reduce some of the weight-related issues. However, the extent of the added reach remains unlikely to be more than a few hundred feet.

In conjunction with or in addition to utilizing larger coiled tubing, a coiled tubing straightener may be utilized. That is, as the tubing is being injected into the well, it may be simultaneously straightened upon entry. With this technique, wound coiled tubing is not only unwound from having been stored on a spool, but it is actually bent in a bit opposite the unwound direction. Thus, the coiled tubing entering the well is even straighter and capable of reaching a bit further into the well. Unfortunately, the extended reach is unlikely to be by more than a few hundred feet. Once more, utilizing a straightener in this fashion introduces fatigue on the coiled tubing, thereby reducing its overall effective life.

Alternatively, extending reach may be furthered by the addition of a friction reducer, introduced through the coiled tubing during conveyance, particularly through a deviated section. As a result, an added 10-15% or so of coiled tubing reach may be realized. In circumstances where the deviated well section is under about 3,000-5,000 feet, this may make all the difference in allowing the coiled tubing to fully traverse the section. However, as deviated well sections become longer and longer, use of a friction reducer in this manner is unlikely to do the trick. Once more, the use of a friction reducer introduces the expense of a friction fluid which may or may not be compatible with the fluid and environment of the ongoing coiled tubing application.

More sophisticated measures may also be undertaken in an effort to extend the reach of coiled tubing or other conveyance through a horizontal well section. For example, a downhole tractor may be used to pull the coiled tubing through the deviated well section. That is, well tractors may be attached to the coiled tubing, positioned in the well, and employed to advance downhole, pulling the coiled tubing through the well including such problematic deviated sections. Such tractoring may be fairly effective. Indeed, it would not be unreasonable to expect to be able to traverse more than 6,000 feet through a deviated section in this manner. Unfortunately, the cost of tractoring is often exorbitant. Once more, substantial time is spent rigging up tractoring equipment at the oilfield surface not to mention the expense involved in tractor retrieval should the tractor become stuck downhole which is not an uncommon occurrence.

As opposed to tractoring, another somewhat sophisticated extended reach technique may be employed by way of pressure pulse. For example, a fluidic switch may be incorporated into a downhole tool and utilized to provide a vibration to the advancing tubing in order to extend its reach. While this may not extend reach to the degree of utilizing a tractor, unlike other extended reach methods described above, pressure pulse is likely to reliably provide a reach extension of 1,000 feet or more without the degree of expense and complexity required during tractoring. Unfortunately, however, the natural operation of a fluidic switch is such that the vibrational frequency utilized is limited to practical geometry and flow-rate parameters that may not easily be manipulated.

SUMMARY

A pressure pulse tool for a downhole conveyance device is detailed herein. The conveyance device may be deployed from an oilfield with a fluid flow directed therethrough at a given rate. Further, the tool may include a housing coupled to the device for directing the fluid flow therethrough. A piston located within the housing may be configured to shift at a frequency directed by the operator at the oilfield surface in a manner that is independent of the flow rate. The pressure pulse tool may be incorporated into wellbore devices other than conveyance devices. In one embodiment, the tool may be a fluidic switch operating to direct the fluid flow and ultimately the frequency by taking advantage of a Coand{hacek over (a)} effect for the flowing fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of various structure and techniques will hereafter be described with reference to the accompanying drawings. It should be understood, however, that these drawings are illustrative and not meant to limit the scope of claimed embodiments.

FIG. 1A is a side cross-sectional view of an embodiment of a pressure pulse tool for a downhole conveyance.

FIG. 1B is a schematic view of an embodiment of a piezobender of the pressure pulse tool of FIG. 1A.

FIG. 2 is a side partially sectional view of a downhole conveyance accommodating the pressure pulse tool of FIG. 1A.

FIG. 3 is an overview of an oilfield with a well accommodating the downhole conveyance of FIG. 2 therein.

FIG. 4 is an enlarged side cross-sectional view of a portion of another embodiment of a pressure pulse tool for a downhole conveyance.

FIG. 5A is a side cross-sectional view of yet another embodiment of a pressure pulse tool for a downhole conveyance.

FIG. 5B is a chart depicting positive and negative pressure pulse magnitudes attainable from the tool of FIG. 5A.

FIG. 6 is a flow-chart summarizing an embodiment of employing a pressure pulse tool in a downhole conveyance for an application in a well.

DETAILED DESCRIPTION

Embodiments are described with reference to certain downhole applications utilizing a pressure pulse tool as an aid to the advancement of a downhole conveyance, for example, through a deviated well section. Specifically, the pressure pulse tool may be utilized to provide vibration assistance and reduce the probability of helical lockup for a conveyance by reducing friction between the conveyance and the well. In the embodiments depicted, the conveyance is coiled tubing used to deliver a cleanout tool to a target location in a deviated or horizontal well section. Thus, debris may be cleaned out for sake of enhancing production from the area of the target location. However, a variety of other applications may benefit from pressure pulse tool embodiments and techniques as detailed herein. For example, the conveyance may be coiled tubing, drill pipe, casing or any other forcible tubular conveyance. Indeed, other forms of wellbore devices may also utilize such pressure pulse tools. So long as a pressure pulse tool is utilized in which vibration is powered by a fluid flow while displaying a vibrational frequency independent of the fluid flow rate, appreciable benefit may be realized. Throughout this document, a “conveyance device” is referenced to a tubing string, such as coiled tubing, drill pipe, casing, production tubing or liner, which is used to enter the wellbore, and perform downhole operation.

Referring now to FIG. 1A, a side cross-sectional view of an embodiment of a pressure pulse tool 100 is shown. With added reference to FIG. 2, the tool 100 includes a housing configured to receive a fluid flow 155 through a primary channel 150 that is in fluid communication with an uphole bore 215 of a downhole conveyance such as the coiled tubing 210. As used herein the term “pressure pulse tool” is used to apply to a tool 100 that employs a fluidic switch or fluidic switch architecture such as that depicted here in FIG. 1A or as shown in the embodiments of FIGS. 4 and/or 5A.

More specifically, the pressure pulse tool 100 includes fluidic switch architecture in the form of the noted primary channel 150 which receives a fluid flow 155 and a secondary channel which receives a portion of fluid flow from 155 and directs it toward a neck 157 that splits into different fluid pathways 158, 159. Further, the portion of the fluid flow 155 which is drawn into the neck 157 will tend to initially divert to one of the pathways 158, 159. This is a result of what is referred to as the Coand{hacek over (a)} effect, or the tendency of a fluid flow to maintain physical attraction to a surface during flow. By way of example, in the embodiment shown, the diverted flow is shown entering the lower pathway 159 of the depiction. This in turn will act upon a piston 175 that is in communication with the pathway 159 and force it to move in a corresponding direction, indicated by an arrow 176.

At the same time, however, the piston 175 is also in communication with the other pathway 158 at an opposite side thereof. Thus, once diverted flow is forced into this upper pathway 158, the movement of the piston 175 will change direction and a cycle of piston reciprocation will be attained. Reciprocation of the piston 175 in the directions 176 may take place while also resulting in intermittent fluid flow 155 through the entirety of the tool 100. For example, in the embodiment shown, the piston 175 includes a passage 151 that is aligned with the primary channel 150 at an uphole side thereof while also in turn being cyclically ported to an outlet 153 and back into communication with the channel 150 at a downhole side thereof. Regardless, ongoing reciprocation of the piston 175 as described results in vibration that allows the pressure pulse tool 100 to serve as an aid to advancement of a downhole conveyance such as the coiled tubing 210 shown in FIGS. 2 and 3. More specifically, as the piston reciprocates, it intermittently interrupts fluid flow through the primary channel 150, which generates a water hammer effect of vibrating “pressure pulses”. This water hammer effect causes vibration along the coiled tubing 210 to which the pressure pulse tool 100 is attached.

As a practical matter, the indicated vibrations aid in tool advancement through a well 380 (again, see FIG. 3). Further, the frequency and effectiveness of these vibrations via the reciprocating piston 175 is thus, determined by the rate at which the fluid flow 155 through the neck 157 is alternated between the different pathways 158, 159 at either side of the piston 175. However, in the embodiment shown, unlike a conventional fluidic switch, the frequency of vibration obtained from the reciprocating piston 175 is achieved independent of the rate of the fluid flow 155. That is, while sufficient fluid flow 155 is available to drive the reciprocation, the actual rate at which fluid flow 155 through neck 157 is alternatingly switched between pathways 158, 159 is attained through a separate diverting mechanism 140 as detailed further below.

The diverting mechanism 140 is used to actively direct the portion of the fluid flow 155 travelling through the neck 157 to one of the two pathways 158, 159. In the embodiment shown, the diverting mechanism 140 is a Coand{hacek over (a)} implement. That is, the mechanism 140 is a physical implement tailored to take advantage of the tendency of the fluid to travel along a surface when flowing. So, for example, as shown in FIG. 1A, the mechanism 140 is deflected slightly downward and the corresponding fluid flow 155 is directed downward and through the lower pathway 159. However, the diverting mechanism 140 is coupled to a controller 130 and a power source 120 to govern the frequency with which the diverting mechanism alternates between the upper 158 and lower 159 pathways. For example, in the embodiment shown, the controller 130 is a conventional downhole circuit board powered by a standard lithium battery power source 120. Thus, without even requiring a power line, a frequency control signal from an oilfield surface 300 may be sent over a fiber optic telemetric line 110 and modulated by the controller 130 to dictate the rate at which the diverting mechanism 140 moves from pathway 159 to pathway 158 (see FIG. 3). Indeed, with added reference to FIG. 1B, a low power, variable frequency mode of alternatingly moving the diverting mechanism 140 between pathways 158, 159 is described where the mechanism 140 is a piezobender.

With specific reference to FIG. 1B, a schematic view of an embodiment of a piezo-based implement is shown for use as the diverting mechanism 140 of FIG. 1A. In this embodiment, the mechanism 140 may be made up of multiple layers of piezoceramic material having differently tailored polarizations. So, for example, when a voltage is applied one layer 142 may expand while the other 144 contracts, resulting in a deflection as shown (see arrow 147). In the depicted example of FIGS. 1A and 1B, the piezo-based bender implement 140 may have a natural orientation downward (e.g. and toward the lower pathway 159 as shown in FIG. 1A). However, repeated intermittent application of voltage across the implement 140 may result in a repeated deflection upward (e.g. and toward the upper pathway 158). When this rate of deflection is governed by the controller 130 at a set frequency, the reciprocation of the piston 175 of FIG. 1 may be established. Of course, the piezo-based form of the mechanism 140 may be differently configured, for example with more or fewer layers 142, 144, active deflection in both directions, or other conventional piezo options employed.

Use of a piezo-based implement as the diverting mechanism 140 may be particularly beneficial for use in the downhole environment. That is, a variable frequency may be readily achieved with low power requirements. For example, with no more than intermittent supply of well under a volt from the power supply 120, the mechanism 140 may be directed by the regulator 130 to display a frequency of 1 Hz-200 Hz or more. To maintain a peak pressure pulse, this is dramatically wider range and more controllable than a conventional fluidic switch that relies solely on flow rate to achieve a frequency By way of contrast, the embodiment of FIGS. 1A and 1B may maintain a constant flow rate of, for example, 3 BPM throughout while utilizing the diverting mechanism 140 to adjust frequency to anywhere from 1 Hz to 200 Hz depending on operating conditions. Variables of such operating conditions may include downhole conditions themselves or the length of the coiled tubing 210 in the well 380 (see FIG. 3). Regardless, the enhanced ability to adjust or tune the frequency as described may maximize the effect of friction reduction for the pressure pulse tool 100. Of course, these particular values are only exemplary as other flow rates and frequencies may be employed in conjunction with the described embodiments.

Referring now to FIG. 2, a side partially sectional view of a downhole conveyance 210 is shown. In the embodiment shown, this conveyance 210 is coiled tubing with a bottom hole assembly (BHA) 201 secured at the end thereof. For example, the coiled tubing conveyance 210 may be utilized to forcibly deliver the BHA 201 to a target location in a well 380 as depicted in FIG. 3. In this way an application may be run at the target location, for example, a cleanout application with a cleanout tool 275 of the BHA 201. Regardless, the BHA 201 is outfitted with the above described pressure pulse tool 100 of FIG. 1A. Therefore, an aid to reach extension is provided making it more likely that the application tool 275 will be able to traverse a deviated well 380 to the extent required in order to reach the target location (again, see FIG. 3).

With added reference to FIGS. 1A and 1B, along with FIG. 2 here, the pressure pulse tool 100 is shown coupled to the coiled tubing conveyance 210 with the telemetric line 110 traversing the bore 215 of the conveyance 210 in order to reach the tool 100. Thus, as detailed hereinabove, vibrational frequency may be governed by a diverting mechanism 140 within the tool 100. Power requirements for the vibrating may be met by a flow of fluid 155 whereas power for the diverting mechanism 140 may be supplied by a small power source 120 within the tool 100. However, in other embodiments, power for the mechanism 140 may be drawn from a power equipped version of the line 110. Additionally, power for the BHA 201, including for the mechanism 140 where so desired, may be provided by a larger downhole battery package 225. For example, in the embodiment shown, a logging tool 250 or the cleanout tool 275 may have functional components with power requirements to be met from a downhole source and that exceed what is available from a power source 120 such as that employed by the diverting mechanism 140.

Referring now to FIG. 3, an overview of an oilfield 300 is shown with a well 380 accommodating the downhole conveyance 210 of FIG. 2 therein. The well 380 may be defined by casing 385 as it vertically traverses various formation layers 390, 395. Further, it may extend several thousand feet through an uncased horizontal section 387. Thus, in order to reach a target location for an application in the horizontal section 387, added measures may be taken. For example, as shown in FIG. 3, the conveyance 210 is coiled tubing which may be forcibly advanced past a well head 375 and downhole by way of an injector 360.

As a matter of extending the reach further through the horizontal section 387 than otherwise possible, the above described pressure pulse tool 100 is also utilized. As indicated above, embodiments of the tool 100 may be employed over a wider range of frequencies due to the unique independent nature in which frequency is attained independent of the particular rate of fluid flow through the conveyance 210. As also indicated above, the extra reach for the BHA 201 may include well over 2,000 feet of extended reach as a result of the improved control of operating frequency available to the tool 100. Once more, this may be achieved without the requirement of tractoring or other larger and more complex and/or less reliable equipment options. Indeed, the surface equipment 325 for the conveyance 210 may even be mobile by way of a coiled tubing truck 340 accommodating a support rig 350 as shown.

Referring now to FIG. 4, an enlarged side cross-sectional view of a portion of another embodiment of the pressure pulse tool 100 is shown. In this case, the fluidic switch architecture, which is defined by a housing of the tool 100, remains but with the operation of the diverting mechanism 140 actuated differently from the embodiment depicted in FIGS. 1A and 1B. Specifically, in the embodiment of FIG. 4, the diverting mechanism 140 still operates under the principle of the Coand{hacek over (a)} effect but in this case is magnetically actuated.

Continuing with reference to FIG. 4, a portion of the fluid flow 155 entering into the tool 100 will travel through the nozzle shaped region of the tool 100, across a neck 157 and into one of two different pathways 158, 159. As detailed above, each of these pathways 158, 159 are in fluid communication with opposite sides of a piston 175 (see FIG. 1A). Thus, as flowing fluid is selectively alternated between the pathways 158, 159 by the diverting mechanism 140, a vibration or pressure pulse is provided by the tool 100.

The frequency of the pressure pulse vibrations is dependent upon the rate at which the diverting mechanism 140 is alternated between the corresponding pathways 158, 159. As noted above, in the embodiment shown, the diverting mechanism 140 is magnetically actuated. Specifically, the controller 130 is electronically coupled to a magnetic coil 400. The coil 400, in turn is provided about a portion of the neck 157 which surrounds a polarized end of the diverting mechanism 140. Specifically, the polarized end may include north 437 and south 427 portions. Thus, alternating the magnetic field in the coil 400 may induce deflection of the mechanism 140 back and forth. As shown, this back and forth would mean moving the diverting mechanism 140 back and forth between alignment with one pathway 158 or another 159. Using the power source 120 and controller 130 to guide deflective movement of the mechanism 140 in a magnetic fashion may be particularly beneficial in a controllability sense. That is, magnetic actuation is generally reliable and effective even with such small scale dimensions as are found in a pressure pulse tool 100 and components such as the diverting mechanism 140.

Referring now to FIG. 5A, a side cross-sectional view of yet another embodiment of the pressure pulse tool 100 is shown. In this embodiment, the diverting mechanism 140 again takes advantage of the Coand{hacek over (a)} effect. Indeed, the mechanism 140 may be either be piezo-based as in the embodiment of FIGS. 1A and 1B or magnetically actuated as in the embodiment of FIG. 4 described above. However, in this case, the water hammer effect of vibration during reciprocation of the piston 175 is enhanced by both positive and negative peaks. That is, the piston 175 is not only exposed to, and interrupting of, the primary channel 150 through the tool 100 but during reciprocation also provides an interrupted exposure that allows for the egress of fluid out of the tool 100 to an annular space 501 outside of the tool 100. Specifically, note the port 500 which provides reciprocating interrupted communication between an annular space 501 and primary flow channel 150 (see also FIG. 3).

Referring now to FIG. 5B, a chart depicting positive and negative pressure pulse magnitudes attainable from the tool of FIG. 5A is shown. With added reference to FIG. 3, the pressure within the tool 100 and/or conveyance 210 may be substantial and comparatively higher than the pressure within the annular space 501 of a well 380 at a given depth (e.g. 387). The impact of this potential disparity in pressures, depending on the location of the reciprocating piston 175, may be seen figuratively in a peak to peak analysis as shown in FIG. 5B. Specifically, the additional negative pressure pulse means that the overall pressure pulse magnitude (peak to peak) would be higher than conventional pressure tool, resulting in increased “water hammer effect” or vibration of the conveyance device, and ultimately a more extended reach. Regardless, in the embodiment shown, the diverting mechanism 140 remains independently directed through a controller 130 and is not dependent on any particular fluid flow rate regardless of origin. Thus, the range of frequencies that may be employed for the embodiments of FIGS. 5A and 5B is again enhanced as with the embodiments of FIGS. 1A and 1B (or FIG. 4).

Referring now to FIG. 6, a flow-chart is shown summarizing an embodiment of employing a pressure pulse tool in a downhole conveyance or other wellbore tool for an application in a well. Specifically, as indicated at 615, the wellbore device may be deployed into a well and advanced to a target location as noted at 630. This may be several thousand feet into a deviated well section or in another challenging region of the well in terms of access. Thus, as indicted at 645, a pressure pulse tool of a bottom hole assembly may be operated as the wellbore device is advanced downhole.

Operating the pressure pulse tool may include selectively diverting a fluid flow through the tool between fluid pathways as indicated at 660. This is done in a way that not only reciprocates a piston at a given frequency but does so in a manner that the frequency is independent of a flow rate of the fluid. In fact, the reciprocating piston may even periodically divert the fluid to the annulus to affect the overall peak to peak pressure pulse of the tool and enhance the extended reach (see 675).

Embodiments described hereinabove include a pressure pulse tool utilizing a fluidic switch to aid a wellbore device in achieving improved extended reach through a deviated well. This is achieved in a manner that avoids the complexity and expense of tractoring equipment while at the same time providing a realistic opportunity to provide extended reach of substantially beyond 1,000 feet. In fact, in contrast to more conventional vibration assistance, fluidic switch embodiments and techniques detailed herein may allow for a range of pressure pulse frequencies up to about 200 Hz or more. Thus, extra extended reach of 2,000 feet or more may be reliably achieved.

The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that 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. Regardless, 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.

Claims

1. A method of advancing a downhole conveyance device through a deviated section of a well, the method comprising:

deploying the downhole conveyance device into the well with a fluid flowing therethrough at a given rate;

alternatingly diverting the fluid flow between pathways of a pressure pulse tool for reciprocating a piston thereof at a given frequency independent of the given rate; and

advancing the conveyance device through the deviated section during the reciprocating of the piston and to a target location in the well.

2. The method of claim 1 wherein the reciprocating of the piston periodically interrupts fluid flow to generate pressure pulses as an aid to attaining the extended reach.

3. The method of claim 1 wherein the alternatingly diverting of the fluid flow between pathways further comprises alternatingly deflecting a diverting mechanism of the tool between the pathways to guide the fluid flow via a Coand{hacek over (a)} effect.

4. The method of claim 1 further comprising periodically exposing the reciprocating piston to annular pressure in the well.

5. The method of claim 1 further comprising tuning the given frequency to between about 1 Hz and about 200 Hz.

6. The method of claim 1 further comprising performing an application in the well at the target location with an application tool coupled to the downhole conveyance device.

7. A pressure pulse tool for a downhole device, the device configured for use in a well and to carry a fluid at a given flow rate, the tool comprising:

a housing coupled to the downhole device for directing the fluid therethrough; and

a piston located within the housing for shifting at a given frequency independent of the flow rate.

8. The pressure pulse tool of claim 7 wherein the given frequency is between about 1 Hz and about 200 Hz.

9. The pressure pulse tool of claim 7 wherein the housing defines a primary channel in fluid communication with an uphole bore of the downhole device for the directing of the fluid, the tool further comprising:

a nozzle-shaped region of the housing in communication with the primary channel, the nozzle-shaped region having a neck leading to first and second fluid pathways in fluid communication with the piston;

a diverting mechanism at least partially located within the neck for guiding fluid from the primary channel and alternatingly between the first and second pathways for the shifting thereof at the given frequency; and

a controller for controlling a rate of the alternating of the diverting mechanism between the pathways.

10. The pressure pulse tool of claim 9 wherein the piston is in periodic fluid communication with an annular port to the well.

11. The pressure pulse tool of claim 9 wherein the diverting mechanism is a Coand{hacek over (a)} implement.

12. The pressure pulse tool of claim 11 wherein the Coand{hacek over (a)} implement is one of a piezo-based implement and a magnetically actuated implement.

13. The pressure pulse tool of claim 12 wherein the piezo-based implement comprises piezoceramic material layers.

14. The pressure pulse tool of claim 12 wherein the magnetically actuated implement comprises north and south polarized end portions, the tool further comprising a magnetic coil located at least partially in the neck and adjacent the end portions.

15. An oilfield assembly for use at an oilfield, the assembly comprising:

a conveyance device;

a bottom hole assembly coupled to the conveyance device and having an application tool for use at a target location in a well; and

a pressure pulse tool of the bottom hole assembly, the tool having a housing in fluid communication with the conveyance device for directing fluid therethrough at a given flow rate for reciprocating a piston at a frequency independent of the given flow rate.

16. The oilfield assembly of claim 15 wherein the conveyance device is one of tubing string, coiled tubing, drill pipe, casing, production tubing and a liner.

17. The oilfield assembly of claim 15 wherein the pressure pulse tool comprises a Coand{hacek over (a)} element for directing fluid interchangeably between pathways at a given rate to effect the frequency of the reciprocating of the piston, the bottom hole assembly further comprising:

a downhole power source for the Coand{hacek over (a)} element; and

a controller for regulating the rate of fluid interchange between the pathways.

18. The oilfield assembly of claim 17 further comprising a telemetric line coupled to the controller and to surface equipment at a surface of the oilfield to allow operator direction of the controller.

19. The oilfield assembly of claim 18 wherein the telemetric line is a fiber optic line.