Coiled Tubing Degradable Flow Control Device

BACKGROUND OF THE DISCLOSURE

Inflatable packers may be attached to coiled tubing and deployed into a wellbore to perform various hydrocarbon wellbore operations. For example, such operations include setting an inflatable packer to seal off a section of the wellbore and stimulating the wellbore formation above or below the packer by pumping a treatment fluid (e.g., acid) into the formation. Another example operation includes setting the inflatable packer and pumping a water shutoff fluid above or below the packer to stop water flow into the wellbore from a particular zone of the formation. In such scenarios, among others, the packer is deflated for retrieval from the wellbore after the wellbore operation. In other scenarios, the packer is permanently set and then detached from the coiled tubing, such as for when cement may then be poured on top of the packer to create a plug in the wellbore.

To inflate the packer, pressurized fluid communicated through the coiled tubing may be injected into the packer. However, the differential pressure between the inside and outside of the packer may be excessive, causing damage to the inflatable packer. For example, in sub-hydrostatic wells, the pressure of the fluid inside the coiled tubing is greater than the bottom hole pressure in the wellbore, resulting in a large pressure differential that may damage the packer or cause the packer to inadvertently start inflating as the coiled tubing is lowered into the wellbore.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces an apparatus that includes an assembly for inclusion in a tool string conveyed via coiled tubing within a wellbore. The assembly includes a mandrel, a packer, and a flow control device. The mandrel includes a passage for receiving fluid via the coiled tubing. The packer is disposed about the mandrel and is expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage. The flow control device controls flow of the fluid from the passage into the packer, and includes a degradable material reactive to the fluid.

The present disclosure also introduces an apparatus that includes a tool string conveyed via coiled tubing within a wellbore. The tool string includes an assembly that includes a mandrel, a packer, and a flow control device. The mandrel includes a passage for receiving fluid via the coiled tubing. The packer is disposed about the mandrel and is expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage. The flow control device controls flow of the fluid from the passage into the packer, and includes a degradable material reactive to the fluid.

The present disclosure also introduces a method that includes conveying a tool string via coiled tubing within a wellbore. The tool string includes a mandrel, a packer, and a flow control device. The mandrel includes a passage for receiving fluid via the coiled tubing. The packer is disposed about the mandrel and is expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage. The flow control device controls flow of the fluid from the passage into the packer, and includes a degradable material reactive to the fluid. The method also includes degrading the degradable material by communicating the fluid through the flow control device, via the coiled tubing and the passage, such that the fluid communicated through the flow control device then inflates the packer into sealing contact with the wall of the wellbore.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic sectional view of a portion of an example implementation of the apparatus shown in FIG. 1 according to one or more aspects of the present disclosure.

FIG. 3 is an axial view of a portion of an example implementation of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.

FIG. 4 is an axial view of another example implementation of the apparatus shown in FIG. 3 according to one or more aspects of the present disclosure.

FIG. 5 is a sectional view of a portion of an example implementation of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.

FIG. 6 is a sectional view of another example implementation of the apparatus shown in FIG. 5 according to one or more aspects of the present disclosure.

FIG. 7 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

FIG. 1 is a schematic view of at least a portion of an example implementation of a wellsite system 100 according to one or more aspects of the present disclosure, representing an example coiled tubing environment in which one or more apparatus described herein may be implemented, including to perform one or more methods and/or processes also described herein. However, it is to be understood that aspects of the present disclosure are also applicable to implementations in which other tubular or fluid conveying members, such as drill pipe, are utilized instead of or in addition to the coiled tubing.

FIG. 1 depicts a wellsite surface 105 upon which various wellsite equipment is disposed proximate a wellbore 120. FIG. 1 also depicts a sectional view of the Earth below the wellsite surface 105 containing the wellbore 120, as well as a tool string 110 positioned within the wellbore 120. The wellbore 120 extends from the wellsite surface 105 into one or more subterranean formations 130. When utilized in cased-hole implementations, a cement sheath 124 may secure a casing 122 within the wellbore 120. However, one or more aspects of the present disclosure are also applicable to open-hole implementations, in which the cement sheath 124 and the casing 122 have not yet been installed in the wellbore 120.

At the wellsite surface 105, the wellsite system 100 may comprise a control center 180 comprising processing and communication equipment operable to send, receive, and process electrical and/or optical signals. The control center 180 is operable to control at least some aspects of operations of the wellsite system 100. The control center 180 may comprise an electrical power source (not shown) operable to supply electrical power to components of the wellsite system 100, including the tool string 110. The electrical signals, the optical signals, and the electrical power may be transmitted between the control center 180 and the tool string 110 via conduits 184, 186 extending between the control center 180 and the tool string 110. The conduits 184, 186 may each comprise one or more electrical conductors, such as electrical wires, lines, or cables, which may transmit electrical power and/or electrical control signals from the control center 180 to the tool string 110, as well as electrical sensor, feedback, and/or other data signals from the tool string 110 to the control center 180. The conduits 184, 186 may each further comprise one or more optical conductors, such as fiber optic cables, which may transmit light pulses and/or other optical signals between the control center 180 and the tool string 110. In an embodiment, the conduits 184, 186 may comprise only fiber optics for transmitting signals such as between the tool string 110 and the control center 180.

The conduits 184, 186 may collectively comprise a plurality of conduits or conduit portions interconnected in series and/or in parallel and extending between the control center 180 and the tool string 110. For example, as depicted in the example implementation of FIG. 1, the conduit 184 extends between the control center 180 and a reel 160 of coiled tubing 162, such that the conduit 184 may remain substantially stationary with respect to the wellsite surface 105. The conduit 186 extends between the reel 160 and the tool string 110 via the coiled tubing 162, including the coiled tubing 162 spooled on the reel 160. Thus, the conduit 186 may rotate and otherwise move with respect to the wellsite surface 105. The reel 160 may be rotatably supported on the wellsite surface 105 by a stationary base 164, such that the reel 160 may be rotated to advance and retract the coiled tubing 162 within the wellbore 120. The conduit 186 may be contained within an internal fluid passage of the coiled tubing 162, secured externally to the coiled tubing 162, or embedded within the structure of the coiled tubing 162. A rotary joint 150, such as may be known in the art as a collector, provides an interface between the stationary conduit 184 and the moving conduit 186.

The wellsite system 100 further comprises a fluid source 140 from which a fluid may be conveyed by a pump 141 and fluid conduits 142 to the reel 160 of the coiled tubing 162. The fluid conduits 142 extending between the pump 141 and the coiled tubing 162 may be fluidly connected to the coiled tubing 162 by a swivel or other rotating coupling (obstructed from view in FIG. 1). The coiled tubing 162 may be utilized to convey the fluid received from the fluid source 140 (via the pump 141) to the tool string 110 coupled at a downhole end of the coiled tubing 162 within the wellbore 120.

The wellsite system 100 may further comprise a support structure 170, such as may include or otherwise support a coiled tubing injector 171 and/or other apparatus for facilitating movement of the coiled tubing 162 in the wellbore 120. Other support structures may also be included, such as a derrick, a crane, a mast, a tripod, and/or other structures. A diverter 172, a blow-out preventer (BOP) 173, and/or a fluid handling system 174 may also be included as part of the wellsite system 100. For example, during deployment, the coiled tubing 162 may be passed from the injector 171, through the diverter 172 and the BOP 173, and into the wellbore 120. The tool string 110 may be conveyed along the wellbore 120 via the coiled tubing 162 in conjunction with the coiled tubing injector 171, such as may apply an adjustable uphole and downhole force to the coiled tubing 162 to advance and retract the tool string 110 within the wellbore 120.

During downhole operations, the fluid from the fluid source 140 may be conveyed through the coiled tubing 162 into the wellbore 120 adjacent the tool string 110. For example, the fluid may be directed into the wellbore 120 through one or more ports (not shown) in the tool string 110. Thereafter, the fluid may flow in the uphole direction and out of the wellbore 120. The diverter 172 may direct the returning fluid to the fluid handling system 174 through one or more conduits 176. The fluid handling system 174 may clean the fluid and/or prevent the fluid from escaping into the environment. The fluid may then be returned to the fluid source 140 or otherwise contained for later use, treatment, and/or disposal.

The tool string 110 may comprise one or more modules, sensors, and/or downhole tools 112, 114, hereafter collectively referred to as the tools 112, 114. For example, one or more of the tools 112, 114 may be or comprise at least a portion of a monitoring tool, an acoustic tool, a density tool, a drilling tool, an electromagnetic (EM) tool, a formation testing tool, a fluid sampling tool, a formation logging tool, a formation measurement tool, a gravity tool, a magnetic resonance tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a surveying tool, and/or a tough logging condition (TLC) tool, among other examples within the scope of the present disclosure. One or more of the tools 112, 114 may also be or comprise a perforating gun and/or another perforating or cutting tool.

One or more of the tools 112, 114 may also be or comprise a depth correlation tool, such as a casing collar locator (CCL) for detecting ends of casing collars by sensing a magnetic irregularity caused by a relatively high mass of an end of a collar of the casing 122. One or more of the tools 112, 114 may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation. The CCL and/or GR tools may transmit signals in real-time to the wellsite surface 105, such as the control center 180, via the conduits 184, 186. The CCL and/or GR tool signals may be utilized to determine the position of the tool string 110, such as with respect to known casing collar numbers and/or positions within the wellbore 120. Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string 110 within the wellbore 120, such as during well service operations described below.

One or more of the tools 112, 114 may also be or comprise a telemetry tool to facilitate communication between the tool string 110 and the control center 180. The telemetry tool may be a wired electrical telemetry tool and/or an optical telemetry tool, among other examples.

One or more of the tools 112, 114 may also comprise one or more sensors 113, 115, respectively. The sensors 113, 115 may include inclination and/or other orientation sensors, such as accelerometers, magnetometers, gyroscopic sensors, and/or other sensors for utilization in determining the orientation of the tool string 110 relative to the wellbore 120. The sensors 113, 115 may also or instead include sensors for utilization in determining petrophysical and/or geophysical parameters of a portion of the formation 130 along the wellbore 120, including measuring and/or detecting one or more of pressure, temperature, strain, composition, and/or electrical resistivity, among other examples within the scope of the present disclosure. The sensors 113, 115 may also or instead include fluid sensors for utilization in detecting the presence of fluid, a certain fluid, or a type of fluid within the tool string 110 or the wellbore 120. The sensors 113, 115 may also or instead include fluid sensors for utilization in measuring properties and/or determining composition of the fluid sampled from the wellbore 120 and/or the formation 130, such as spectrometers, fluorescence sensors, optical fluid analyzers, density sensors, viscosity sensors, pressure sensors, and/or temperature sensors, among other examples within the scope of the present disclosure. Although FIG. 1 shows the coiled tubing 162 containing the conduit 186 disposed therein and extending between the reel 160 and the tool string 110, it is to be understood that the conduit 186 may be omitted from the coiled tubing 162, such as when performing well service operations or other downhole operations that do not utilize wired signal communication between the downhole tools 112, 114 and/or sensors 113, 115 and the control center 180.

The tool string 110 may also include a packer assembly 200, comprising an inflatable packer 202 disposed about a mandrel 204. The packer 202 may be set (i.e., expanded) into sealing contact against the wall 126 of the wellbore 120 to form a fluid seal selectively isolating portions of the wellbore 120 during performance of various testing, treatment, and/or well service operations. Although the tool string 110 shown in FIG. 1 comprises a single packer assembly 200 coupled between the two downhole tools 112, 114, it is to be understood that additional packer assemblies 200 may be included, and in other locations within the tool string 110. For example, two or more packer assemblies 200 may be utilized to isolate an interval within the wellbore 120 for performing various testing and/or treatment operations utilizing one or more of the tools 112, 114. The tool string 110 may also comprise a different number of tools 112, 114 relative to the example implementation depicted in FIG. 1, and each tool 112, 114 may be directly and/or indirectly coupled with the packer assembly 200.

The packer 202 is inflated by introducing fluid into the packers through the coiled tubing 162 via the mandrel 204. To increase the pressure of the fluid in the mandrel 204 to a level that is sufficient to inflate the packer 202, the tool string 100 may also comprise a fluid control device 117 for blocking the flow of the fluid from the tool string 110 into the wellbore 120. The fluid control device 117 is depicted in FIG. 1 as being coupled between the mandrel 204 and the downhole tool 114. However, the fluid control device 117 may also be located below the downhole tool 114, and may form a portion of the downhole tool 114.

The fluid control device 117 may comprise a fluid barrier for plugging the flow area of an internal fluid passage 206 (shown in FIG. 2) extending through the mandrel 204 and other portions of the tool string 110. For example, the fluid barrier may comprise a plug, a drop ball, a gate valve, a flapper valve, a ball valve, or an isolation valve. The fluid control device 117 may also or instead comprise a flow-restricting device for reducing or restricting flow of the fluid from the passage 206 into the wellbore 120. For example, the flow-restricting device may comprise a flow restrictor, a choke, or a drain valve. The fluid control device 117 may also or instead comprise a pressure control device, such as a pressure-responsive opening and closing valve for preventing fluid from flowing from the passage 206 into the wellbore 120 until the fluid within the passage 206 achieves a predetermined pressure. The fluid control device 117 may also or instead comprise a check valve, such as may prevent wellbore fluid from flowing from the wellbore 120 into the passage 206 but permit the fluid to flow from the passage 206 into the wellbore 120 when a pressure differential across the check valve reaches a predetermined value. The fluid control device 117 may also or instead comprise an inline universal valve, such as may be selectively operable to block fluid flow or freely permit fluid flow from the passage 206 into the wellbore 120.

The fluid utilized to inflate the packer 202 may be a workover fluid, such as may include a mixture of water and diesel or water and methanol. The fluid utilized to inflate the packer 202 may instead be a brine solution, such as may comprise water and sodium chloride, calcium chloride, and/or potassium chloride. The water utilized as part of the workover fluid or the brine solution may include fresh water or seawater. However, workover fluids and brine solutions are merely examples, and it is to be understood that other fluids may be utilized to inflate the packer 202 within the scope of the present disclosure.

After the packer 202 is set against the wall 126 of the wellbore 120, various testing operations may be performed utilizing one or more of the downhole tools 112, 114 and/or sensors 113, 115. The packer assembly 200 may also be utilized for well pressure control, such as when changing surface equipment or tubing. The packer assembly 200 may also be utilized as a downhole equipment hanger for attaching other tools downhole from the packer assembly 200.

The packer assembly 200 may also be utilized for well service or treatment operations, such as fracturing operations, well stimulation operations, acid treatment operations, water shut-off operations, well abandonment operations, well testing operations, gravel packing operations, cementing operations, and perforating operations, among other examples. During such well service operations, a stimulation fluid, a treatment fluid, and/or other fluids may be communicated through the coiled tubing 162 and into the tool string 110 for injection into the wellbore 120 adjacent the tool string 110. The fluid may be directed into the wellbore 120 downhole from the tool string 110 and/or into an annular area between the wall 126 of the wellbore 120 and the coiled tubing 162 uphole from the packer 202. Accordingly, the tool string 110 may comprise an additional fluid control device 116 located uphole from the packer assembly 200. The fluid control device 116 is depicted in FIG. 1 as being coupled between the mandrel 204 and the downhole tool 112. However, the fluid control device 116 may also be located above the downhole tool 112, and may form a portion of the downhole tool 112. The fluid control device 116 may comprise a fluid barrier, a flow-restricting device, a pressure control device, a check valve, or an inline universal valve, as described above with respect to the fluid control device 117. However, the fluid control devices 116, 117 may be different ones of these examples, and still be utilized to selectively block, divert, and/or permit fluid flow between the fluid passage 206 and a selected portion of the wellbore 120.

For example, if the fluid is intended to be injected into the wellbore 120 uphole from the packer 202, the fluid control device 117 may comprise the fluid barrier described above, and may be utilized to prevent the fluid from flowing into the wellbore 120, while the fluid control device 116 may comprise the inline universal valve described above, and may be utilized to permit fluid flow into the wellbore 120 via one or more ports (not shown). However, if the fluid is intended to be injected into the wellbore 120 downhole from the packer 202, the fluid control device 116 may be omitted, or may comprise the above-described inline universal valve being set to prevent fluid flow into the wellbore 120 and permit fluid flow along the passage 206, while the fluid control device 117 may also comprise an inline universal valve that is set to permit fluid flow from the passage 206 into the wellbore 120. Prior to injecting the fluid into the wellbore 120 downhole from the packer 202, the fluid barrier may be retrieved or otherwise removed after the packer 202 is set, thereby clearing the passage 206 through the tool string 110 to allow fluid communication with the wellbore 120.

One or both of the fluid control devices 116, 117 may comprise a mandrel (not shown) having flow ports for fluidly connecting the fluid passage 206 and the wellbore 120, and a sliding sleeve (not shown) disposed within the mandrel and movable to selectively open and close the flow ports. The fluid control device 116 may also comprise a circulating valve for circulating the fluid through the coiled tubing 162 and the annular portion of the wellbore 120 uphole from the packer 202.

FIG. 2 is a schematic sectional view of a portion of an example implementation of the packer assembly 200 shown in FIG. 1 according to one or more aspects of the present disclosure. The following description refers to FIGS. 1 and 2, collectively.

The packer assembly 200 comprises the mandrel 204, which at least partially defines the fluid passage 206 extending longitudinally through the tool string 110 and the mandrel 204 for receiving the fluid via the coiled tubing 162. The mandrel 204 may comprise multiple portions collectively forming the mandrel 204 and, thus, collectively defining the fluid passage 206. For example, in the example implementation depicted in FIG. 2, the mandrel 204 comprises an upper mandrel 208 defining an upper passage 209 and a lower mandrel 210 defining a lower passage 211, such that the upper and lower passages 209, 210 collectively form at least a portion of the fluid passage 206. Other implementations within the scope of the present disclosure, however, include implementations in which the mandrel 204 is a single, discrete member, as well as implementations in which the mandrel 204 comprises more than the two separate mandrels 208, 210 shown in FIG. 2.

In the context of the present disclosure, the terms “upper” and “lower” refer to location and/or orientation relative to the wellbore 120. Thus, for example, the upper mandrel 208 is located further uphole than the lower mandrel 210, and the lower mandrel 210 is located further downhole than the upper mandrel 208.

The upper mandrel 208 comprises a mechanical interface 212 for mechanically coupling the upper mandrel 208 with a corresponding mechanical interface 214 of the lower mandrel 210 in a manner permitting fluid communication between the upper and lower passages 209, 211. The upper and lower interfaces 212, 214 may each comprise threaded connectors, fasteners, box-pin couplings, and/or other mechanical coupling means. Although the upper and lower mandrels 208, 210 are depicted in FIG. 2 as being coupled directly together, the upper and lower mandrels 208, 210 may instead be indirectly coupled via intermediate mandrels, conduits, tools, and/or other devices in a manner permitting fluid communication between the upper and lower passages 209, 211.

The uphole end of the mandrel 204 (e.g., the uphole end of the upper mandrel 208) comprises a mechanical interface (not shown) for mechanically coupling the packer assembly 200 with a corresponding mechanical interface (not shown) of the uphole-adjacent component of the tool string 110, such as the downhole tool 112 or the fluid control device 116. A downhole end of the mandrel 204 (e.g., the downhole end of the lower mandrel 210) comprises a mechanical interface (not shown) for mechanically coupling the packer assembly 200 with a corresponding mechanical interface (not shown) of the downhole-adjacent component of the tool string 110, such as the downhole tool 114 or the fluid control device 117. Such interfaces of the mandrel 204 may be integrally formed with the mandrel 204, or may be discrete components coupled to the mandrel 204 via threaded connection and/or other means. The interfaces may each comprise threaded connectors, fasteners, box-pin couplings, and/or other mechanical coupling means for coupling with the adjacent components of the tool string 110.

The packer 202 is expandable into sealing contact with the wall 126 of the wellbore 120 in response to receiving fluid from the fluid passage 206. That is, the packer 202 comprises or at least partially defines an expandable volume 216 for receiving the fluid from the passage 206. For example, upper and lower ends 203 of the packer 202 may each be secured to the mandrel 204 by a corresponding collar 218. Each collar 218 may comprise an overlay portion 220 extending longitudinally over the corresponding end 203 of the packer 202. The mandrel 204 comprises one or more fluid passages 215 extending through a wall 217 of the mandrel 204 to fluidly connect the fluid passage 206 with the expandable volume 216. For example, at least one of the collars 218 (e.g., the upper collar 218 in the example implementation depicted in FIG. 2) comprises a fluid passage 222 fluidly connecting the one or more fluid passages 215 of the mandrel 204 and the expandable volume 216 of the packer 202. However, while the fluid passage 222 is depicted in FIG. 2 as extending through the upper collar 218, the passage 222 and/or other means for fluidly connecting the passage 206 and the expandable volume 216 of the packer 202 may instead be formed within another portion of the packer assembly 200.

A check valve 225 may be disposed within and form a portion of the fluid passage 222. The check valve 225 may permit fluid to flow from the passage 206 into the expandable volume 216 while preventing fluid from escaping back into the fluid passage 206 after the packer 202 is set. The check valve 225 may be of typical design known in the art, such as may comprise a fluid blocking member 226 contained within a flow-through housing 227. A closure seat 228 on an inlet side of the housing 227 may cooperate with the fluid blocking member 226 to fluidly seal against the fluid blocking member 226. Fluid flow directed through the seat 228 displaces the fluid blocking member 226 from the seat 228 to permit fluid flow into the expandable volume 216. Attempted flow directed in an opposite direction against the fluid blocking member 226 imposes a pressure differential force on the fluid blocking member 226 that urges the fluid blocking member 226 against the seat 228 to form the fluid seal and, thus, prevent fluid flow out of the expandable volume 216. The fluid blocking member 226 may be freely disposed within the housing 227, or the fluid blocking member 226 may be spring-loaded or otherwise mechanically biased against the seat 228. The check valve 225 may be set to permit fluid to flow through the check valve 225 when a pressure differential across the check valve reaches a predetermined threshold. For example, the predetermined threshold may range between about 50 pounds per square inch (PSI) and about 250 PSI, although other values are also within the scope of the present disclosure.

As described above, excessive pressure differential between the packer-setting fluid within the fluid passage 206 and wellbore fluid within the wellbore 120 surrounding the packer 202 may cause excessive fluid flow into the packer 202, which may damage and/or prematurely inflate the packer 202. Such excessive pressure and/or flow may be the result of the pressure of the packer-setting fluid discharged from the pump 141 and/or the hydrostatic pressure of the column of packer-setting fluid within the coiled tubing 162. However, the packer assembly 200 of the present disclosure also comprises a flow control device 230 within the passage 206, interposing the column of packer-setting fluid within the coiled tubing 162 and the portion of the passage 206 that is in fluid communication with the expandable volume 216 of the packer 202. The flow control device 230 reduces or otherwise controls flow and/or pressure of the fluid flowing from the coiled tubing 162 into the portion of the passage 206 the fluidly communicates with the expandable volume 216 of the packer 202, thereby reducing or preventing damage to the packer 202 during inflation operations.

The flow control device 230 is located uphole from the fluid passages 215 so as to control the flow rate and pressure of the fluid entering the fluid passages 215. The flow control device 230 may be disposed within the upper passage 209 of the upper mandrel 208, as depicted in FIG. 2, or within the lower passage 211 of the lower mandrel 210, or elsewhere within the passage 206 of the mandrel 204 in a manner permitting the flow control device 230 to reduce or otherwise control the flow and/or pressure of the fluid introduced into the packer 202 from the coiled tubing 162 via the fluid passages 206, 215, 222. For example, the flow control device 230 may instead be disposed within the fluid passages 215 and/or the fluid passages 222.

At least a portion of the flow control device 230 comprises a degradable material 232 reactive to the packer-setting fluid communicated through the coiled tubing 162. The degradable material 232 may be disposed within a flow-through housing 234 in a manner permitting the degradable material 232 to initially remain within the housing 234 during the inflation operations. The housing 234 may also permit the flow control device 230 to be installed or otherwise retained within the mandrel 204 along the fluid passage 206. A passage 236 formed in the degradable material 232 is initially open to fluid flow through the flow control device 230, such that the flow control device 230 may act as a choke or similar flow restrictor to reduce the flow and/or pressure of the fluid introduced into the packer 202.

The degradable material 232 may be an alloy or other combination of elements, compounds, and/or other constituents formulated such that the degradable material 232 degrades (e.g., dissolves, erodes, breaks down) when exposed to the packer-setting fluid. Accordingly, as the packer-setting fluid flows through the flow control device 230, the passage 236 enlarges as the degradable material 232 degrades in reaction to the packer-setting fluid, thus permitting a gradually increasing fluid flow rate through the flow control device 230, and a correspondingly decreasing pressure drop across the flow control device 230. The degradable material 232 may be selected based on its mechanical strength (i.e., hardness) and rate of degradation in reaction to the packer-setting fluid. The mechanical strength and rate of degradation of the degradable material 232 may depend on the amounts and perhaps relative orientations of its constituents. The rate of degradation of the degradable material 232 may also be affected, for example, by wellbore conditions, including fluid chemistry, temperature, and pressure. Accordingly, the degradable material 232 may also be selected based on the anticipated wellbore conditions.

The degradable material 232 may be a material degradable by water or a fluid comprising water. For example, the degradable material 232 may be degradable by fresh water, seawater, or a brine solution, such as comprising sodium chloride, calcium chloride, and/or potassium chloride. The degradable material 232 may be degradable by a workover fluid, which may include a mixture of water and diesel or water and methanol. However, it is to be understood that the degradable material 232 may be degradable by other fluids within the scope of the present disclosure, including fluids utilized during well service operations.

The degradable material 232 may be an aluminum alloy comprising at least aluminum (Al), magnesium (Mg), and gallium (Ga). In some implementations, the alloy may have a ratio of magnesium to gallium ranging between about 0.5 and about 3.5. The alloy may also comprise indium (In), and perhaps silicon (Si). Some implementations may also comprise zinc (Zn). Example alloys are set forth below in Table 1, in which the compositions are listed by weight percentage. Table 1 also lists the Hardness Vickers Number (HVN) for each example alloy measured directly after casting of each alloy, and after performing heat treatment (HT) on each alloy. However, the present disclosure is not limited to the examples listed in Table 1, and it is to be understood that the degradable material 232 may comprise other alloys within the scope of the present disclosure. For example, the degradable material 232 may comprise a degradable polymer, such as polyactide (PLA) or polyglycolide (PGA), among other examples. The degradable material 232 may also or instead comprise a degradable ceramic material.

TABLE 1

HVN
HVN

Al
Mg
Ga
In
Si
Mg/Ga
(As Cast)
(After HT)

Example 1
98.5
0.5
0.5
0.5
0
1.00
42
78

Example 2
97.5
0.5
1.0
1.0
0
0.50
42
78

Example 3
96.0
2.0
1.0
1.0
0
2.00
50
90

Example 4
94.5
3.5
1.0
1.0
0
3.50
60
99

Example 5
85.4
8.0
3.8
1.6
1.2
2.10
88
132

Example 6
86.6
8.0
3.8
1.6
0
2.11
85
136

FIG. 3 is an axial view of at least a portion of the flow control device 230 shown in FIG. 2. The following description refers to FIGS. 2 and 3, collectively. The initial flow passage 236 is a single orifice extending axially through the degradable material 232 for communicating the fluid through the flow control device 230. The passage 236 comprises a decreased inner diameter 244, relative to the inner diameter 245 of the housing 234, that causes a pressure drop across the flow control device 230 and a decrease in the flow rate through the flow control device 230. The inner diameter 244 of the passage 236 increases as the degradable material 232 degrades in reaction to contact with the fluid flowing through the passage 236, resulting in an increasing flow rate through the flow control device 230 and a decreasing pressure drop across the flow control device 230.

FIG. 4 is an axial view of another example implementation of the flow control device 230 shown in FIG. 3 according to one or more aspects of the present disclosure, and designated in FIG. 4 by reference numeral 250. The flow control device 250 depicted in FIG. 4 is substantially similar in structure and operation to the flow control device 230 depicted in FIG. 3, including where indicated by like reference numbers, except as described below. The following description refers to FIGS. 2-4, collectively.

The flow control device 250 also comprises the degradable material 232 disposed within the housing 234. However, whereas the flow control device 230 shown in FIGS. 2 and 3 comprises a single initial passage 236, the flow control device 250 comprises multiple initial passages 252, 254, 256, each formed in and extending longitudinally through the degradable material 232 for communicating the fluid through the flow control device 250. Each passage 252, 254, 256 has a corresponding inner diameter 253, 255, 257 that causes a pressure drop across the flow control device 250 and a decrease in the flow rate through the flow control device 250. The inner diameters 253, 255, 257 increase as the degradable material 232 degrades in reaction to contact with the fluid flowing through the passages 252, 254, 256, resulting in an increasing flow rate through the flow control device 250 and a decreasing pressure drop across the flow control device 250.

Although FIG. 4 depicts the flow control device 250 as comprising three initial passages 252, 254, 256, it is to be understood that the flow control device 250 may be implemented with other quantities of initial passages, including two, four, five, six, or more. Furthermore, although FIG. 4 shows each of the passages 252, 254, 256 as having a different inner diameter 253, 255, 257, it is to be understood that the passages 252, 254, 256 may have substantially similar inner diameters 253, 255, 257.

FIG. 5 is a sectional view of another example implementation of the flow control device 230 shown in FIG. 3 according to one or more aspects of the present disclosure, and designated in FIG. 5 by reference numeral 260. The flow control device 260 depicted in FIG. 5 is substantially similar in structure and operation to the flow control device 230 depicted in FIG. 3, including where indicated by like reference numbers, except as described below. The following description refers to FIGS. 2, 3, and 5, collectively.

The flow control device 260 also comprises the degradable material 232 disposed within the housing 234. However, the degradable material 232 is provided as a plurality of concentric layers 262, 264, 266 of different degradable materials that are reactive to the packer-setting fluid at different rates. For example, the degradable material 232 may include a radially outer layer 262, an intermediate layer 264, and a radially inner layer 266. The degradable material of the inner layer 266 may be substantially more reactive to the packer-setting fluid than the degradable material of the intermediate layer 264, and the degradable material of the intermediate layer 264 may be substantially more reactive to the packer-setting fluid than the degradable material of the outer layer 262.

The initial passage 236 is formed in and extends axially through the inner layer 266 for initially communicating the packer-setting fluid through the flow control device 260. The inner diameter 244 of the initial passage 236 increases as the degradable material of the inner layer 266 degrades in reaction to contact with the packer-setting fluid flowing through the passage 236, resulting in an increasing flow rate through the flow control device 260 and a decreasing pressure drop across the flow control device 260. As the inner diameter 244 of the passage 236 increases, the inner layer 266 substantially degrades, such that the intermediate layer 264 then substantially defines the passage 236. Similarly, the intermediate layer 264 will then also substantially degrade, such that the outer layer 262 substantially defines the passage 236, until ultimately the degradable material 232 is substantially removed from the housing 234. Furthermore, if the degradable material of the inner layer 266 is substantially more reactive to the packer-setting fluid than the degradable material of the intermediate layer 264, and the degradable material of the intermediate layer 264 is substantially more reactive to the packer-setting fluid than the degradable material of the outer layer 26, then the inner diameter 244 of the passage 236 will increase at a slower rate as each of the layers 262, 264, 266 successively degrades in reaction to contact with the packer-setting fluid flowing through the passage 236, thereby resulting in a gradually increasing flow rate through the flow control device 260 and a gradually decreasing pressure drop across the flow control device 260.

FIG. 6 is a sectional view of another example implementation of the flow control device 260 shown in FIG. 5 according to one or more aspects of the present disclosure, and designated in FIG. 6 by reference numeral 270. The flow control device 270 depicted in FIG. 6 is substantially similar in structure and operation to the flow control device 260 depicted in FIG. 5, including where indicated by like reference numbers, except as described below.

The flow control device 270 also comprises the degradable material 232 disposed as concentric layers 262, 264, 266 within the housing 234, with the initial passage 236 formed in and extending axially through the inner layer 266. However, each layer 262, 264, 266 is axially offset from the adjacent layer 262, 264, 266. Consequently, as the packer-setting fluid flows through the flow control device 270, degradation of the layers 262, 264, 266 will form an inwardly tapered upper portion 274, while a lower portion 276 may remain substantially cylindrical.

FIG. 7 is a flow-chart diagram of at least a portion of an example implementation of a method (300) according to one or more aspects of the present disclosure. The method (300) may utilize at least a portion of a wellsite system and valves, such as the wellsite system 100 shown in FIG. 1 and the flow control devices 230, 250, 260, 270 shown in FIGS. 2-6. The following description refers to FIGS. 1-6, collectively.

The method (300) comprises conveying (310) the tool string 110 via the coiled tubing 162 within the wellbore 120. As described above, the tool string 110 includes the packer assembly 200, which comprises the mandrel 204 having the passage 206 for receiving fluid via the coiled tubing 162, the packer 202 disposed about the mandrel 204 and expandable into sealing contact with the wall of the wellbore 120 in response to receiving the fluid from the passage 206, and a flow control device controlling flow of the fluid from the passage 206 into the packer 202 and comprising degradable material 232 reactive to the fluid. The flow control device may be one of the flow control devices 230, 250, 260, 270 shown in FIGS. 2-6 and/or other implementations within the scope of the present disclosure. The method (300) also comprises degrading (320) the degradable material 232 by communicating the fluid through the flow control device, via the coiled tubing 162 and the passage 206, such that the fluid communicated through the flow control device then inflates the packer 202 into sealing contact with the wall of the wellbore 120.

As described above, the flow control device initially reduces fluid flow rate from the passage 206 to the packer 202, and permits an increasing fluid flow rate from the passage 206 to the packer 202 as the degradable material 232 degrades in reaction to the fluid. Thus, an area open to fluid flow through the flow control device (e.g., the passage 236 depicted in FIGS. 2, 3, 5, and 6 or the passages 252, 254, 256 depicted in FIG. 4) increases as the degradable material 232 degrades in reaction to the fluid.

The method (300) may also comprise performing (330) a wellbore operation while the packer 202 is in sealing contact with the wall of the wellbore 120. The wellbore operation may be a scale removal operation, a fracturing operation, a cleanout operation, or an acidizing operation, as described in U.S. Pat. No. 7,617,873, the entire disclosure of which is hereby incorporated herein by reference.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: an assembly for inclusion in a tool string conveyed via coiled tubing within a wellbore, wherein the assembly comprises: a mandrel comprising a passage for receiving fluid via the coiled tubing; a packer disposed about the mandrel and expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage; and a flow control device controlling flow of the fluid from the passage into the packer and comprising a degradable material reactive to the fluid.

The mandrel may comprise: a first mandrel comprising a first passage; and a second mandrel comprising a second passage. The first and second mandrels may be at least indirectly coupled in a manner permitting fluid communication between the first and second passages. The packer may be disposed about one of the first and second mandrels. The flow control device may be disposed in one of the first and second mandrels.

The degradable material may degrade when exposed to the fluid.

The flow control device may restrict the fluid flow from the passage into the packer until the degradable material degrades in reaction to the fluid.

The flow control device may permit an increasing fluid flow rate as the degradable material degrades in reaction to the fluid.

The flow control device may comprise an orifice initially open to fluid flow, and a flow area of the orifice may increase as the degradable material degrades in reaction to the fluid. The orifice may be formed in and extend through the degradable material. An inner diameter of the orifice may increase as the degradable material degrades in reaction to the fluid.

The flow control device may comprise a plurality of orifices initially open to fluid flow the flow control device, and each of the plurality of orifices may be formed in and extend through the degradable material. An inner diameter of each of the plurality of orifices may increase as the degradable material degrades in reaction to the fluid.

The degradable material may comprise a plurality of degradable materials reactive to the fluid at different corresponding rates.

The degradable material may comprise a plurality of layers each formed of a corresponding one of a plurality of different degradable materials each reactive to the fluid at different corresponding rates. The plurality of layers may comprise a radially inner layer of a first degradable material and a radially outer layer of a second degradable material, wherein the first degradable material may be substantially more reactive to the fluid than the second degradable material, and wherein the radially inner layer may initially define a passage for communicating the fluid through the flow control device.

The degradable material may comprise aluminum, an alloy comprising aluminum and magnesium, an alloy comprising aluminum and gallium, or an alloy comprising aluminum, magnesium, and gallium. For example, the degradable material may comprise an alloy comprising 85.4-98.5% aluminum, 0.5-8.0% magnesium, and 0.5-3.8% gallium, by weight.

The present disclosure also introduces an apparatus comprising: a tool string conveyed via coiled tubing within a wellbore, wherein the tool string includes an assembly comprising: a mandrel comprising a passage for receiving fluid via the coiled tubing; a packer disposed about the mandrel and expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage; and a flow control device controlling flow of the fluid from the passage into the packer and comprising a degradable material reactive to the fluid.

The tool string may further comprise one or more of: an isolation valve operable for fluidly isolating the passage from the wellbore; a flow restrictor operable for restricting flow of the fluid from the passage into the wellbore; a check valve operable for permitting flow of the fluid from the passage into the wellbore and preventing flow of the fluid from the wellbore into the passage; a telemetry tool operable for facilitating communication between the tool string and surface equipment; a depth correlation tool operable for determining location of the tool string within the wellbore; and/or a casing collar locator operable for determining location of the tool string within the wellbore.

The flow control device may permit an increasing fluid flow rate as the degradable material degrades in reaction to the fluid.

The flow control device may comprise an orifice initially open to fluid flow through the flow control device, and a flow area of the orifice may increase as the degradable material degrades in reaction to the fluid. The orifice may be formed in and extend through the degradable material. The flow control device may comprise a plurality of the orifices.

The present disclosure also introduces a method comprising: conveying a tool string via coiled tubing within a wellbore, wherein the tool string comprises: a mandrel comprising a passage for receiving fluid via the coiled tubing; a packer disposed about the mandrel and expandable into sealing contact with a wall of the wellbore in response to receiving the fluid from the passage; and a flow control device controlling flow of the fluid from the passage into the packer and comprising a degradable material reactive to the fluid; and degrading the degradable material by communicating the fluid through the flow control device, via the coiled tubing and the passage, such that the fluid communicated through the flow control device then inflates the packer into sealing contact with the wall of the wellbore.

The flow control device may permit an increasing fluid flow rate from the passage to the packer as the degradable material degrades in reaction to the fluid.

An orifice extending through the degradable material and initially open to fluid flow through the flow control device may increase as the degradable material degrades in reaction to the fluid.

The method may further comprise performing a wellbore operation while the packer is in sealing contact with the wall of the wellbore. The wellbore operation may be a scale removal operation, a fracturing operation, a cleanout operation, or an acidizing operation, among other example applications also within the scope of the present disclosure.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Coiled Tubing Degradable Flow Control Device

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