LOW PRESSURE FLUID STORAGE TECHNIQUE FOR A HIGH PRESSURE APPLICATION

Abstract

A technique for pre-storing an application fluid in coiled tubing for use in a downhole application. The technique includes filling the coiled tubing with the application fluid in a manner that utilizes pressures substantially below that of the pressures utilized in the downhole application itself. The coiled tubing may then be charged to near the application pressure and placed in hydraulic communication with a well for the downhole application. Thus, the coiled tubing may serve as an application fluid storage device without the requirement of coiled tubing deployment or associated equipment and related costs.

Description

BACKGROUND

Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, oilfield efforts are often largely focused on techniques for maximizing recovery from each and every well. Whether the focus is on drilling, unique architecture, or step by step interventions directed at well fracturing or stimulation, the techniques have become quite developed over the years. One such operation at the well site directed at enhancing hydrocarbon recovery from the well is referred to as a stimulation application. Generally, in conjunction with fracturing, a stimulation application is one in which a large amount of proppant, often a type of sand, is directed downhole at high pressure in the form of a fluid slurry. So, for example, downhole well perforations into a formation adjacent the well which have been formed by fracturing may be further opened and/or reinforced for sake of recovery therefrom.

In order to help ensure that the proppant containing slurry is able to reach all well perforations, for sake of reinforcement as noted above, a diverter application may be run. A diverter application is another high pressure application in which a chemical diverter material slurry is introduced to the well prior to the introduction of the proppant so as to help ensure that access to all perforation locations by the proppant is available.

For effectiveness, slurries such as those described above are often supplied downhole at considerable rates and pressures. For example, it would not be uncommon for slurries to be pumped at more than 60 or 100 barrels per minute (BPM) at pressures exceeding 10,000 PSI. Thus, in order to ensure that a sufficient volume, rate and pressure of the slurry is delivered during the applications, a host of positive displacement pumps are often positioned at the oilfield for sake of driving the applications. Specifically, each one of several pumps may be fluidly linked to a manifold which coordinates the overall delivery of the slurry fluid downhole.

Each of the noted positive displacement pumps may include a plunger driven by a crankshaft toward and away from a chamber in order to dramatically effect a high or low pressure on the chamber. This makes it a good choice for high pressure applications. Indeed, even outside of stimulation operations, where fluid pressure exceeding a few thousand pounds per square inch (PSI) is to be generated, a positive displacement pump is generally employed. In the case of stimulation operations specifically though, this manner of operation is used to effectively direct an abrasive containing fluid through a well.

As is often the case with large systems and industrial equipment, regular monitoring and maintenance of positive displacement pumps may be sought to help ensure uptime and increase efficiency. In the case of hydraulic fracturing applications, a pump may be employed at a well and operated for an extended period of time, say six to twelve hours per day for more than a week. Over this time, the pump may be susceptible to wearing components such as the development of internal valve leaks. This is particularly of concern at conformable valve inserts used at the interface of the valve and valve seat. These “inserts” are elastomeric seals that are located in relatively challenging internal pump locations and must be manually inspected. Generally, due to the minimal costs involved, regardless of whether the inspection reveals defects, the seals will be replaced once the scheduled inspection has begun.

However, perhaps of greater concern regarding such valves, is the susceptibility to clogging. For example, even though pumping a proppant may wear on seals, it is unlikely to lead to clogging of valves within the pump due to the minimal sizes of the proppant particles that are generally utilized. However, as noted above, other applications, such as a diverter application or flowback prevention efforts may use larger fiber particles or beads. More specifically, it would not be uncommon to see fibers in excess of 4-5 mm in length utilized in such applications (or similarly sized flakes or rods). However, the architecture of a positive displacement pump is tailored to maximizing and maintaining pressure. So, for example, under current architectural protocol, the clearance space at valves within such pumps is generally no more than about 4 mm. Thus, unfortunately, when pumping a slurry utilizing constituents in excess of 4 mm, a high probability of clogging at the valves within the pump may result. Furthermore, a host of other applications driven by a positive displacement pump may utilize constituents exceeding 4 mm, such as ball launching applications and others.

The hazards of a clogged valve may be quite dramatic. For example, a plunger of a clogged positive displacement pump may continue reciprocating and driving up pressure within the pump which can lead to a blowout. This may consist of a pres sure-based explosion of a fitting or other connection to the pump resulting in operator injury at the oilfield.

Efforts have been undertaken to avoid running large particle slurries through high pressure pumps. For example, a storage manifold containing the slurry may be pressurized to near the level of an adjunct high pressure pump and connected to the pump at its high pressure side. Thus, the manifold's contents may be pumped out of storage and toward the well by a fluid that does not include such large particles. In this manner, the large particle slurry never actually goes through the pump and valves thereof. However, this type of “injecting” of the large particle containing slurry is only practical in limited volumes. That is, where an application calls for 25-100 barrels or more of slurry, it would not be practical to load and place a conventional pressurizable tank adjacent to the pump. This would be the equivalent of placing an enormous pressurized tank with seams and other weakpoints at the wellsite. The measures required to ensure safety of such a tank would be impractical in terms of required wall thicknesses, seam reinforcement and overall expense.

SUMMARY

A method of delivering fluid to a downhole location in a well for an application therein. The method includes pumping the fluid into coiled tubing that is positioned at an oilfield surface adjacent the well. This pumping of the fluid into the coiled tubing takes place at a filling pressure. The fluid may subsequently be transferred from the coiled tubing to the downhole location at an application pressure that is greater than the filling pressure. Additionally, pressure in the coiled tubing may be increased from the filling pressure to a pre-application pressure that is closer to the application pressure than the filling pressure prior to the transferring of the fluid downhole.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a side view of an embodiment of a pre-application storage system including coiled tubing storage equipment accommodating high and low pressure lines.

FIG. 2A is a side cross-sectional view of an embodiment of a high pressure pump of the pre-application storage system of FIG. 1.

FIG. 2B is a side cross-sectional view of the coiled tubing equipment of FIG. 1 filled with an application fluid.

FIG. 3 is a side view of the coiled tubing equipment of FIG. 1 revealing hookup detail on the high and low pressure lines thereto.

FIG. 4 is a schematic overview of an embodiment of the pre-application storage system of FIG. 1 positioned at an oilfield for use in a high pressure application.

FIG. 5 is a side cross-sectional view of a well at the oilfield of FIG. 4 upon running the high pressure application supported by the pre-application storage system.

FIG. 6 is a flow-chart summarizing an embodiment of utilizing a pre-application storage system to support a high pressure application in a well.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the embodiments described may be practiced without these particular details. Further, numerous variations or modifications may be employed which remain contemplated by the embodiments as specifically described.

Embodiments are described with reference to certain embodiments of oilfield operations. Specifically, stimulation operations involving fracturing or stimulating of a well are detailed herein. These operations may include the introduction of slurries containing chemical diverter materials, flowback inhibiting fibers and other sizable particles that often present challenges to pumping at high pressures for stimulation operations. However, other types of oilfield operations may benefit from the pre-application storage techniques detailed herein. For example, storing a sizable amount of application fluid at the wellsite in readily available coiled tubing that is uniquely brought on-line may be of benefit for any number of applications regardless of fluid particle sizes involved. Indeed, so long as coiled tubing is filled with an application fluid at an initial pressure and then utilized to deliver the application fluid at an application pressure above the initial pressure, appreciable benefit may be realized.

Referring specifically now to FIG. 1, a side view of an embodiment of a pre-application storage system 101 is shown. In this embodiment, coiled tubing storage equipment 100 is utilized to accommodate an application fluid such as a stimulation-related slurry in advance of being used in a downhole application in a well. That is, as opposed to running the slurry through a high pressure application pump 175 such as the one depicted, the slurry is first delivered and stored in coiled tubing 110 by another less pressurized means. The fluid may then later be pumped from the tubing 100 by utilizing the application pump 175 of the system 101. Specifically, the application pump 175 may pump a driving fluid toward the coiled tubing 110 to send the slurry therefrom at an appropriate application pressure. Thus, as depicted, the coiled tubing equipment 100 includes hookups for connections to both a high pressure line 125 for fluid coupling to the application pump 175 as well as a low pressure line 150 for fluid coupling to a source for obtaining the slurry during filling.

Pre-storing the application slurry in coiled tubing 110 means that the slurry does not need to be routed through the application pump 175 in order to be utilized in a downhole application. This may be particularly advantageous where the slurry contains particles that are sizeable enough to potentially clog or obstruct valves within the application pump 175. For example, in the embodiment shown, the application pump 175 is a conventional triplex pump of a type that is commonly utilized at oilfield worksites. The pump 175 is coupled to an engine 160 that powers a sizable crankshaft 140 to drive internal plungers toward and away from valves that regulate flow and pressure of fluid through the pump 175. In this way, pressure of the fluid may be dramatically driven up, for example, to in excess of 10,000 or in excess of 15,000 PSI if need be for an oilfield application. While this makes such pumps 175 a good option for certain oilfield applications that require such pressure, as described further below, the valves are generally of limited clearance, often below about 5 mm, in order to ensure such pressures. However, in an embodiment as shown, where the coiled tubing 110 is utilized to pre-store the slurry, the limited clearance afforded by the valves of the pump 175 has no bearing on particle sizes utilized in the slurry. Thus, if the optimal slurry for the application at hand involves the use of fibers or particles exceeding 4-5 mm, or a large volume of similarly sized balls, flakes, rods, etc., the limited clearance of the valves in the pump 175 are not at issue. The slurry is already filled in the coiled tubing 110.

Since the pump used to fill the coiled tubing 110 need not be utilized for actually running the downhole application with the slurry, it also does not need to provide higher application pressures like the application pump 175. Therefore, it does not face the valve clearance limitations faced by the application pump 175. Instead, with added reference to FIG. 4, slurry supply equipment 450 may include a slurry tank and pump assembly where a conventional transfer pump directs the slurry to the coiled tubing 110 through the low pressure line 150 at less than about 200 or less than about 500 PSI. That is, enough pressure to achieve loading of the coiled tubing 110 with the slurry is sufficient. For example, a c-pump or other fan-type pump may be utilized. Thus, valve clearances and other constraints are not at issue.

Continuing with reference to FIG. 1, the depicted system 101 utilizes generally known oilfield equipment. For example, as noted the application pump 175 and associated machinery may be provided as part of a standard mobile pump truck 145 (also see FIG. 4). Further, the outlet pipe 180 for providing the high pressure fluid, which ultimately supports the driving of the slurry, is routed to a manifold 190 where the noted high pressure line 125 delivers the driving fluid to common coiled tubing 110. However, it is worth noting that the high pressure, larger slurry constituent type applications suggested here are not traditional coiled tubing applications. Thus, it is likely that but for being deliberately brought on sight for sake of slurry storage, no coiled tubing would be available. Indeed, even in the depicted embodiment, the coiled tubing 110 is not provided to support direct coiled tubing delivery of the slurry. Thus, the expense of providing and maintaining an injector and other large equipment such as a crane or mast unit, mixing equipment, etc. to support such deployment need not be undertaken in the depicted embodiment. Instead, the coiled tubing 110 alone is deliberately brought on site as a unique non-interventional slurry storage device with advantages over conventional pressurizable storage tanks or vessels as detailed further below.

As also detailed further below, in one embodiment the coiled tubing 110 may be coiled tubing that was previously considered “retired”. That is, for traditional coiled tubing use, there is an estimated “coil life” in terms of the number of deployments into a well and recoiling before repeated plastic deformation, cracking and other wear is considered such that the coiled tubing 110 should be retired. So, for example, depending on materials, construction, wall thickness and other tolerance factors, a given coiled tubing 110 may be assigned a “coil life” of 50 deployments and scheduled for retirement upon reaching 90% of this expected life (e.g. after 45 deployments). Of course, other retirement guidelines may be applied. For example, retirement may be scheduled to take place once the coiled tubing reaches anywhere between about 75% and 95% of coil life. Regardless, while such coiled tubing 110 may no longer be ideal for further deployments, it may be perfectly sufficient for use as a unique slurry storage device as detailed herein. Thus, as opposed to discarding the potentially several hundred thousand dollar coiled tubing 110, it may be reliably repurposed after the “coil life” to a next “storage life” of potentially indefinite duration. Further, this “repurposing” does not require substantial added labor or equipment cost to attain other than the time required to reclassify and keep track of the coiled tubing 110 going forward.

In other circumstances, the coiled tubing 110 may be retired for other reasons. For example, coiled tubing 110 may be trimmed after repeated uses resulting in a coiled tubing that is no longer practically usable for available interventions. Nevertheless, this shorter coiled tubing 110 may provide more than adequate volume for sake of storing application fluid 215 as detailed herein (see FIG. 2).

As a storage device, the coiled tubing 110 can readily hold in excess of 30 or in excess of 60 or in excess of 100 or in excess of 150 or in excess of 200 or in excess of 300 or in excess of 400 hundred barrels of slurry or other fluid, need not be subjected to further deployment and plastic deformation and is even compactly wound in such a manner as to be self-reinforcing. Indeed, in the embodiment shown, in addition to the retaining sidewalls 107 of the equipment reel, containment bars 105 may also optionally be provided across the outer portion of the reel. This provides added support to the outermost exposed portions of coiled tubing 110, particularly once pressurized and does not present an obstacle to utilizing the coiled tubing 110 as a storage device (i.e. in the general circumstance where the tubing 110 is not intended to be deployed).

Referring now to FIG. 2A, a side cross-sectional view of an embodiment of the high pressure application pump 175 of FIG. 1 is shown. In this view, the driving fluid 200 that is circulated through the pump 175 which is ultimately directed at the coiled tubing 110 of FIG. 1, does not contain particles, fibers or other materials prone to occluding the internal valves 270, 255. With added reference to FIG. 2B, such materials (e.g. 240) may be called for in the applications slurry 215 that is stored in the coiled tubing 110. However, the driving fluid 200 through the pump 175 need not serve as a downhole application fluid. Thus, it is free to be tailored with viscosity and other characteristics suited to advance pressure and drive the application fluid 215 without the requirement of including large application fluid particles itself.

As noted above, the plunger 225 of the pump 175 is stroked toward and away from a chamber 205 to draw in and then drive up fluid pressure therein. That is, as the plunger 225 moves away from the chamber 205, the pressure in the chamber decreases to a predetermined point that lifts the lower valve 255 drawing in the driving fluid 200. Then, as the plunger 225 moves toward the chamber 205, pressure in the chamber 205 increases until the upper valve 270 is forced open. In this manner, the driving fluid 200 is pressurized and ultimately circulated out of the pump 175 (e.g. toward the coiled tubing 110 and application fluid 215 as shown in FIG. 2B). As noted above, in spite of the potentially limited clearance between an open valve 270 and seat 275, the driving fluid 200 does not serve as the application fluid 215 and need not include potentially large occlusive particles which may be found in the application fluid 215 (again, see FIG. 2B).

Referring now to FIG. 2B, a side cross-sectional view of the coiled tubing 110 of FIG. 1 is shown that reveals the application fluid 215 therein. As with any coiled tubing 110, the structure is defined by a continuous tubular wall 210 that includes only a single seam for welding together. In effect, the only practical leak points for the coiled tubing 110 under standard oilfield application pressures would be the unlikely scenario of leakage from one end or another thereof. Even in a circumstance where the tubing 110 is straightened out, as opposed to wrapped around itself as depicted, a reliably high pressure rating is readily attainable. For example, even for coiled tubing 110 that is retired in terms of coil life as described above, a pressure rating of 15,000 to 20,000 PSI may be reasonably expected.

As noted above, coiled tubing 110 inherently has advantages over a conventional storage tank due to the excessive wall thickness requirements, potential numerous seams and other tank-related drawbacks where a substantial pressure rating is at issue. Specifically, in addition to the singular seam that is present in coiled tubing construction, the dimensions are such that the surface (i.e. inner surface) to volume ratio of the coiled tubing wall 210 to the volume of application fluid 215 therein is large enough to enhance the pressure rating or capacity of the structure. For example, given that standard coiled tubing 110 is likely less than about 3 inches in diameter, the surface to volume ratio will be at least 1.3333 per unit length of coiled tubing 110 (e.g. 2÷ the radius (1.5) of the coiled tubing 110). For a common 2⅜ inch diameter coiled tubing 110, which generally has an inner diameter of about 2 inches, the surface to volume ratio would go up to 2 (e.g. 2÷ the radius (1) of the coiled tubing 110).

As used herein, the term “coiled tubing” as applied for a fluid storage device is not necessarily meant to be limited to conventional coiled tubing that has at some point been utilized in a prior deployment for a downhole application or constructed for such operations. Just as a “retired” coiled tubing may suffice as a storage device for application fluid 215 as described above, so too would any tubular having a surface to volume ratio of at least about 1 or at least about 1.2 or at least about 1.3 or at least about 1.5 or at least about 2, whether or not such is considered coiled tubing in the conventional sense.

As depicted in FIGS. 1 and 2B, as a matter of practicality and user-friendliness, circumstances would generally dictate that the coiled tubing 110 be wrapped about itself on a reel to accommodate potentially thousands of feet thereof. Thus, not only is the coiled tubing 110 able to store in excess of about 30 or in excess of about of 30 or in excess of 60 or in excess of 100 or in excess of 150 or in excess of 200 or in excess of 300 or in excess of 400 hundred barrels barrels of application fluid 215 at several thousand PSI, but it also displays a self-reinforcing character once pressurized.

In FIG. 2B it is apparent that upon wrapping about itself, the continuous wall 210 of coiled tubing 110 repeatedly overlays and contacts itself at a variety of interfacing locations 220. These locations 220 appear to be isolated points in the cross-sectional depiction of FIG. 2B. However, the degree of reinforced interfacing generally continues for a distance as one stretch of coiled tubing 110 abuts another in a close wrapped fashion. Further, while the coiled tubing 110 is shown almost perfectly circular for ease of illustration, a certain degree of flattening or plastic deformation is likely as the weight and stress of the coiled tubing 110 builds upon itself as it wraps about itself. Thus, the interfacing locations 220 are likely to be of a broader nature than an isolated point. As a result, the greater surface area of the interfacing provides a greater degree of self-reinforcement. Thus, not only is the coiled tubing 110 readily high pressure rated even in an unwrapped state, as a practical matter, a wrapped “retired” coiled tubing 110 may be even more reliably safe for high pressure use as a high pressure fluid storage device.

Continuing with reference to FIG. 2B, the pressurized space 260 within the coiled tubing 110 accommodates an application slurry 215 as noted. Unlike the driving fluid 200 of FIG. 2A, there is no longer a concern over valve clearance issues. Thus, the slurry 215 may include large constituents 240. In the embodiment shown, these constituents exceed about 4 mm and are fibrous in nature, such as flowback inhibiting or diverting fibers often utilized with proppant 245 during stimulation applications. Indeed, with a standard 2⅜ inch coiled tubing having just under 2 inches in inner diameter to work with, balls or large diverter material of 1.5 inches or so may be utilized without concern over size issues. This is in sharp contrast to circumstances in which the application fluid is to be pumped through the application pump 175 of FIG. 2A where use of constituents of such size would be impractical.

In addition to the specifically noted applications here, those in which a slurry incorporates irregular particle shapes that may present clearance issues may also be candidates for use with coiled tubing 110 as a pre-application storage device. Further, high concentration fiber pill applications of 500 to 1,000 ppt or more may be benefically stored in coiled tubing 110 prior to application. Similarly, superconcentrated sand slurries with up to 20 lbs. of sand per gallon of clean fluid may be pumped through the coiled tubing 110, for example to slow down the other pumps 445 or dilute the sand of the superconcentrated slurry without concern over damage to the application pump 175 (see FIG. 4). The same hold true for ball launcher applications, viscous pill applications and even applications that employ materials or constituents that are potentially damaging to pump parts such as valve seals.

The slurry 215 of FIG. 2B includes different constituents 240, 245 that have been mixed and supplied to the coiled tubing 110 from another location (e.g. see 450 of FIG. 4). Another added advantage of utilizing coiled tubing 110 in place of a more unitary large volume tank-type of structure to serve as a storage device is the control over the mixed slurry 215. That is, the narrow geometrical fluid space 260 of less than about 2 inches stretched out over potentially thousands of feet, as would be common for coiled tubing 110, discourages settling and separation among such mixed components 240, 245. Indeed, utilizing a sufficient viscosity in the base fluid in combination with coiled tubing 110 as a storage device should substantially eliminate the occurrence of settling and/or separation.

At the same time, however, once the driving fluid 200 of FIG. 2A is used to push the slurry 215, the area of interface between the fluids 200, 215 is also limited by the coiled tubing dimensions. Thus, any contamination of the application fluid 215 with the driving fluid 200 is also kept to a minimum. Ultimately, this means that once the application fluid 215 is delivered downhole during an application as described further below, it is likely to be enhanced in terms of lack of contamination and dilution as well as maintenance of mixed constituents 240, 245.

Continuing now with reference to FIG. 3, a side view of the coiled tubing equipment 100 of FIG. 1 is shown. From this side view, hookup detail for the high 125 and low 150 pressure lines is visible. In this view, the retaining sidewalls 107 are not shown so as to reveal the underlying coiled tubing 110. An inlet line 375 to the coiled tubing 110 emerges from a common manifold 300 secured to the hub 340 of the equipment reel 100. The low pressure line 150 is used to allow application fluid 215 into the inlet 375, for example, from lower pressure pump equipment 450 as described above (also see FIGS. 2B and 4).

The low pressure line 150 also includes a loading port 325. Thus, continuing with added reference to FIG. 2B, a foam plug, viscous pill, ball, dart or other implement may be introduced to the application fluid 215 through the port 325 during the filling of the coiled tubing 110 therewith. For example, once the coiled tubing 110 is largely filled, a plug may be dropped into the low pressure line 150. After a moment, once the plug has at least reached the inlet 375, the low pressure line 150 may be closed off at the manifold 300. At this point, the coiled tubing 110 may simply serve as a storage device of application fluid 215 at the oilfield. However, when the time arises to deliver the application fluid 215, the high pressure line 125 may be opened and driving fluid 200 used to interface the plug and push application fluid 215 out of the coiled tubing 110 (see also FIG. 2A). While a plug may provide a barrier to minimize mixing of application 215 and driving 200 fluids, this is not necessarily required. Indeed, a driving fluid 200 that is of greater viscosity than the application fluid 215 may be sufficient to prevent substantial mixing. Furthermore, given the coiled tubing 110 manner of storage mixing may not be of considerable concern, regardless.

Referring now to FIG. 4, a schematic overview of an embodiment of the pre-application storage system 101 of FIG. 1 is shown positioned at an oilfield 400 for use in a high pressure application. As would generally be the case in such circumstances a central manifold 470 or “missile” is used to acquire a low pressure slurry from a mixer 465 for distribution to a host of high pressure pumps 445. These pumps 445 may be used to drive up the pressure of the slurry substantially, for example, from less than 200 PSI to several thousand PSI, and then send the pressurized slurry back to the missile 470. In this way the missile 470 is able to direct the pressurized slurry to a wellhead 490 over a delivery line 475 for an application downhole in a well. In the embodiment shown, the mixer 465 is a mobile unit that acquires fluid and other constituents from adjacent tanks 467 for blending with proppant or other materials from another mobile unit 460 in order to form the slurry. Regardless, for the embodiments described here, none of these constituents, proppants or other materials are of a size to present a challenge to internal valves of the high pressure pumps 445.

Continuing with reference to FIG. 4, with added reference to FIG. 2B, the unique pre-application storage system 101 is provided for circumstances where sizable materials are called for that may present challenges to internal high pressure pump valves due to clearance limitations. More specifically, as noted above, slurry supply equipment 450 may be used to direct an application fluid 215 over a low pressure line 150 to a coiled tubing storage device 100. That is, without the requirement of particularly high pressure, the application fluid 215 may include large particles, lengthy fibers and other materials that might otherwise be prone to face internal valve issues if directed through a high pressure pump (e.g. 445). Instead, with the coiled tubing storage device 100 pre-loaded with the application fluid 215, high pressure may be supplied by an application pump 175 at a mobile pump truck 145.

In the embodiment shown, driving fluid 200 from a fluid tank 415 may be drawn over a delivery line 430 into the application pump 175 where it is pressurized and directed over the high pressure line 125 to the coiled tubing storage device 100. In this way, the application fluid 215 may be pressurized. Pressurization of the application fluid 215 may be a matter of charging the fluid 215 for later use. For example, once a predetermined pressure is reached, a remotely actuated valve 480 may be kept closed and the fluid 215 saved for later use. In one embodiment, the predetermined pressure is approximately that of the pressure attained by the high pressure pumps 445 as applied to a slurry being directed at the wellhead 490 as described above. So, for example, consider an embodiment where the slurry is a proppant containing slurry for use in a fracturing application, and the pressure to be attained by the missile 470 is 15,000 PSI. In this situation, the corresponding pressure charge of the application fluid 215 in the coiled tubing equipment 100 may be held at between about 14,000 PSI and 16,000 PSI.

Continuing with the example scenario above, once the application protocol calls for the introduction of the application fluid 215, for example to provide large flowback inhibiting fibers to the fracturing application, the valve 480 may be remotely opened. In this way, the application fluid 215 may be added to the fracturing application without ever subjecting high pressure pumps 445 to large fibers that might present pumping issues. The pre-charging of the coiled tubing equipment 100 may help to avoid any pressure differential induced shock to the system during the adding of the application fluid 215. Further, as suggested above, during the addition of the application fluid 215 to the process, the application pump 175 may operate to maintain pressure and continue advancement of the fluid 215. In one embodiment this may include remotely opening the valve 480 and operating the pump 175 for a predetermined period in order to deliver a known quantity of the application fluid 215 to the system for downhole delivery.

Of course, a variety of other configurations may be employed for introducing the pre-stored application fluid 215 to the system. For example, the valve 480 may be opened allowing the application fluid 215 to be drawn into the delivery line 475 without any support from an application pump 175. This could be achieved by having the coiled tubing equipment 100 intentionally supercharged above the application pressure of the high pressure pumps 445 and/or coupling to the delivery line 475 in a Venturi-like manner to allow the application fluid 215 to bleed into the process.

Referring now to FIG. 5, a side cross-sectional view of a well 580 is shown at the oilfield 400 of FIG. 4. The well 580 extends below the wellhead 490 traversing multiple formation layers 590, 595 before reaching perforations 575. The perforations 575 extend beyond casing 585 defining the well and into the surrounding formation 595 to encourage the production of hydrocarbons therefrom. As described above, the perforations 575 are shown accommodating flowback inhibiting fibers 240 to enhance the performance of proppant directed at the perforations 575. While these fibers 240 may present challenges to being delivered by pumping through a conventional high pressure pump, for embodiments herein, they have been provided by way of pre-storing at a coiled tubing storage device positioned at the oilfield 400 without being run through such a pump. Thus, such pumping issues are effectively eliminated.

While the example depicted in FIG. 5 illustrates the benefit of delivering large fibers downhole while avoiding pumping issues, a variety of other large particle materials may be delivered to the well 580 in a similarly beneficial manner. For example, diversion material, cement, balls and other projectiles, and a variety of other sizable materials may be delivered to the well 580 according to the techniques described herein.

Referring now to FIG. 6, a flow-chart is depicted which summarizes an embodiment of utilizing a pre-application storage system to support a high pressure application in a well. Specifically, coiled tubing is filled with an application fluid at a filling pressure as noted at 620. This filling pressure is lower than the application pressure that is later utilized during an application with the application fluid. With the coiled tubing containing the application fluid, it may be stored at an oilfield location for an operator-determined period (see 635). However, at some point, the application fluid is delivered to a downhole application as noted at 695. This delivery takes place at a higher application pressure. In one embodiment, the application fluid in the coiled tubing is pre-charged to a pre-application pressure above the filling pressure (see 665). The application pressure is closer to this pre-application pressure than the filling pressure. In another embodiment, a plug is introduced to the application fluid in advance of the charging to the pre-application pressure so as to provide a barrier between the application fluid and a subsequently introduced driving fluid (see 650). That is, as indicated at 680, with or without such a barrier, a driving fluid may be directed at high pressure to aid in the delivering of the application fluid to the well from the coiled tubing.

Embodiments detailed hereinabove provide unique methods and equipment setups for running high pressure applications without running an application fluid through a high pressure pump. Further, these methods and setups do not rely on the use of conventional storage manifolds or jointed piping that are subject to small volume application limits. Similarly, the methods and setups herein do not require the impractical construction of potentially hazardous and expensive pressurizable tanks for use at a worksite. Instead, generally readily available coiled tubing equipment may be uniquely reconfigured and incorporated into a pre-application system for storing and delivering the application fluid in a safe, reliable and practical manner.

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. For example, storing the application fluid in the coiled tubing in advance of the application may be beneficial in circumstances other than those of large particle size. This may include situations where the application fluid includes flammables, hazardous substances or substances that are naturally damaging to the application pump. Also, constituents provided in dissolvable pouches or packets may pose similar challenges and may be well suited for pre-storing in the coiled tubing. The same may be true where multiple application fluid types are to be utilized sequentially or where one is employed to trigger another. For example, two or more different fluids can be loaded into the coiled tubing one after another. For instance, a first fluid can precondition the formation to receive a second fluid. Spacers can also be used between such fluids. Also, in low temperature formations some diverters (such as PLA based diverters) can take a long time to degrade. An accelerator fluid can be loaded in the coiled tubing either before, after or both before and after the diverter fluid in the coiled tubing to enhance contact of the accelerator with the diverter after the fluids are placed in the formation. A fluid and a triggering agent for such fluid can also be loaded sequentially into the coiled tubing (with or without a spacer fluid). 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.

Claims

1. A method of delivering an application fluid to a downhole location in a well from a wellsite, the method comprising:

filling the coiled tubing with the application fluid at a filling pressure with the coiled tubing positioned at the oilfield surface; and

transferring the application fluid from the coiled tubing to the downhole location at an application pressure that is substantially greater than the filling pressure.

2. The method of claim 1 further comprising storing the application fluid in the coiled tubing at the wellsite for an operator-determined period after the filling thereof and prior to the transferring of the application fluid to the downhole location.

3. The method of claim 1 further comprising increasing pressure in the coiled tubing from the filling pressure to a pre-application pressure that is closer to the application pressure than the filling pressure in advance of the transferring of the fluid from the coiled tubing to the downhole location.

4. The method of claim 1 wherein the transferring of the application fluid from the coiled tubing to the downhole location comprises pumping a driving fluid in communication with the coiled tubing at the application pressure to direct the application fluid from the coiled tubing to the well.

5. The method of claim 4 further comprising introducing a barrier plug to the application fluid in the coiled tubing in advance of the pumping of the driving fluid to minimize mixing of the application fluid and the driving fluid.

6. The method of claim 4 wherein the viscosity of the driving fluid is greater than the viscosity of the application fluid to minimize mixing of the application fluid and the driving fluid.

7. The method of claim 4 further comprising remotely opening a valve for a predetermined period to direct a predetermined amount of the application fluid from the coiled tubing.

8. The method of claim 1 further comprising:

deploying the coiled tubing in an interventional downhole application; and

retiring the coiled tubing from further interventional downhole deployment based on an assessment of coil life therefor, the deploying of the coiled tubing and the retiring thereof taking place in advance of the filling of the coiled tubing with the application fluid.

9. A system for positioning at an oilfield, the system comprising:

a tubular storage device having a surface to volume ratio of at least about 1, the volume to accommodate an application fluid for use in an application at the oilfield;

a transfer pump coupled to the tubular storage device for filling the device with the application fluid at a filling pressure; and

an application pump coupled to the tubular storage device for pressurizing the filled device to a pressure substantially greater than the filling pressure.

10. The system of claim 9 wherein the application fluid includes at least one constituent having a size of greater than about 4 mm.

11. The system of claim 10 wherein the constituent is selected from a group consisting of a fiber, balls, proppant, projectiles, diverter material, a fiber pill, a viscous pill, cement particles and particles of irregular shape.

12. The system of claim 9 wherein the filling pressure is under about 500 PSI.

13. The system of claim 12 wherein the application pump is a triplex pump and the substantially greater pressure is in excess of about 15,000 PSI.

14. The system of claim 13 wherein the triplex pump accommodates a driving fluid substantially free of constituents having a size of greater than about 4 mm.

15. The system of claim 14 wherein the tubular storage device is coiled tubing.

16. The system of claim 15 wherein the system further comprises:

a support reel to accommodate the coiled tubing in a wound manner thereabout; and

a port supported by the reel for controlled fluid communication with the coiled tubing to allow introduction of a plug barrier between the driving fluid and the application fluid.

17. A fluid storage assembly for positioning at an oilfield to support a downhole application in a well, the assembly comprising:

non-interventional coiled tubing for retaining at the oilfield to supply stored application fluid therein to the well for the application; and

a reel to support the coiled tubing wound thereabout, the reel accommodating a low pressure line coupled to the coiled tubing for filling with the application fluid at a filling pressure and accommodating a high pressure line coupled to the coiled tubing for pressurizing the application fluid in the coiled tubing to a pressure substantially greater than the filling pressure.

18. The fluid storage assembly of claim 17 wherein the non-interventional coiled tubing is of a capacity to store in excess of 30 barrels of the application fluid.

19. The fluid storage assembly of claim 17 wherein the non-interventional coiled tubing comprises coiled tubing with a predetermined interventional coil life that is retired to a non-interventional status after about 75% of the coil life.

20. The fluid storage assembly of claim 17 further comprising containment bars located about the reel to reinforce the non-interventional coiled tubing during the pressurizing of the application fluid therein.