Systems and Methods for Surface Supervision of a Downhole Tool

For drilling of a borehole, directional drilling allows creation of a non-linear borehole or a linear borehole through varying earth formations. Directional drilling units conventionally communicate with the surface to transmit status information and/or receive instructions through lengthy pulse communications. Reduction of communication time can increase the uptime of a drilling system.

In some aspects, the techniques described herein relate to a method of providing fluid pressure in a downhole environment, the method including: expanding a first packer against a borehole wall; expanding a second packer against the borehole wall; expanding a third packer against the borehole wall; expanding a fourth packer against the borehole wall; and pressurizing an interior zone longitudinally between the second packer and the third packer to a first pressure relative to a hydrostatic borehole pressure that is greater than a second pressure of at least one exterior zone, wherein a first exterior zone is longitudinally between the first packer and the second packer and a second exterior zone is longitudinally between the third packer and fourth packer.

In some aspects, the techniques described herein relate to a downhole system including: a first packer configured to expand against a borehole wall to create a first packer seal; a second packer positioned in a first longitudinal direction from the first packer and configured to expand against a borehole wall to create a second packer seal; a third packer positioned in the first longitudinal direction from the second packer and configured to expand against a borehole wall to create a third packer seal; a fourth packer positioned in the first longitudinal direction from the third packer and configured to expand against a borehole wall to create a fourth packer seal; an interior fluid port configured to pressurize an interior zone longitudinally between the second packer and the third packer to a first pressure; and an exterior fluid port configured to pressurize an exterior zone longitudinally outside the second packer and the third packer to a second pressure different from the first. In some aspects, the downhole system comprises a fluid conduit having a longitudinal direction and the first, second, third and fourth packers are positions on the fluid conduit.

In some aspects, the techniques described herein relate to a downhole device including: a first packer; a second packer positioned in the longitudinal direction from the first packer; a third packer positioned in the longitudinal direction from the second packer; a fourth packer positioned in the longitudinal direction from the third packer; an interior port to an interior zone longitudinally between the second packer and the third packer configured to provide an interior pressurizing fluid to the interior zone; a first exterior port to a first exterior zone longitudinally between the first packer and the second packer configured to provide a first exterior pressurizing fluid different from the interior pressurizing fluid to the first exterior zone; and a second exterior port to a second exterior zone longitudinally between the third packer and the fourth packer configured to provide a second exterior pressurizing fluid different from the interior pressurizing fluid to the second exterior zone. In some aspects, the downhole system comprises a fluid conduit having a longitudinal direction and the first, second, third and fourth packers are positions on the fluid conduit.

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

Additional features and aspects of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and aspects of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims or may be learned by the practice of such embodiments as set forth hereinafter.

Embodiments of the present disclosure generally relate to devices, systems, and methods for providing a fluid in a downhole environment. More particularly, the present disclosure relates to the isolation (or partially isolation) of a longitudinal segment of a borehole into which a pressurized fluid is pumped to apply a fluid pressure to a surrounding formation or other material forming the borehole wall. In some embodiments, the pressurized fluid is used for hydraulic fracturing of the formation. In some embodiments, the pressurized fluid is used to test production of the formation. In some embodiments, the pressurized fluid is used to test an integrity of the borehole wall (such as that of a casing on the borehole).

In some embodiments, a device according to the present disclosure includes a longitudinal series of expandable packers that isolate (or at least partially isolate) adjacent zones from one another by limiting and/or preventing fluid flow between the zones. For example, the series of expandable packers create a series of packer seals against the borehole wall, limiting and/or preventing fluid flow between the zone through the borehole. In some embodiments, systems and methods described herein allow for fluid pressure of the pressurized fluid in at least one zone of the borehole to be greater than a maximum pressure differential across a single packer. For example, the packer seals may fail when a fluid pressure differential across the packer seal exceeds a maximum pressure differential of the seal. A series of packer seals that are pressurized to the maximum pressure differential can allow an interior zone to have a fluid pressure that is greater than the hydrostatic pressure in the borehole, and, therefore, the interior zone can apply a fluid pressure to the borehole wall and/or formation that is greater than with a conventional two-packer device.

illustrates an embodiment of a drilling system and downhole environment.shows one example of a drilling systemfor drilling an earth formationto form a borehole. The drilling systemincludes a drill rigused to turn a drilling assemblywhich extends downward into the borehole. The drilling assemblymay include a drill stringand a bottomhole assembly (BHA)attached to the downhole end of the drill string. Where the drilling systemis used for drilling formation, a drill bitcan be included at the downhole end of the BHA.

The drill stringmay include several joints of drill pipeconnected end-to-end through tool joints. The drill stringtransmits drilling fluid through a central bore and can transmit rotational power from the drill rigto the BHA. In some embodiments, the drill stringmay further include additional components such as subs, pup joints, etc. The drill pipeprovides a hydraulic passage through which drilling fluidis pumped from the surface. The drilling fluiddischarges through selected-size nozzles, jets, or other orifices in the bitfor the purposes of cooling the bitand cutting structures thereon, for lifting cuttings out of the boreholeas it is being drilled, and for preventing the collapse of the borehole. The drilling fluidcarries drill solids including drill fines, drill cuttings, and other swarf from the boreholeto the surface based on a hydrostatic pressure of the borehole. The drill solids can include components from the earth formation, the drilling assemblyitself, from other man-made components (e.g., plugs, lost tools/components, etc.), or combinations thereof.

The BHAmay include the bitor other components. An example BHAmay include additional or other components (e.g., coupled between to the drill stringand/or the bit). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, directional steering tools, section mills, hydraulic disconnects, jars, vibration dampening tools, other components, or combinations of the foregoing.

In general, the drilling systemmay include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, safety valves, centrifuges, shaker tables, and rheometers). Additional components included in the drilling systemmay be considered a part of the surface system (e.g., drill rig, drilling assembly, drill string, or a part of the BHA, depending on their locations and/or use in the drilling system).

The bitin the BHAmay be any type of bit suitable for degrading downhole materials. For instance, the bitmay be a drill bit suitable for drilling the earth formation. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits. In other embodiments, the bitmay be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bitmay be used with a whipstock to mill into casinglining the borehole. The bitmay also be a junk mill used to mill away tools, plugs, cement, other materials within the borehole, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface by the drilling fluidor may be allowed to fall downhole. The conditions of the equipment of the drilling system, the formation, the borehole, the drilling fluid, or other part of the wellsite can change during operations.

is a side view of a devicefor pressuring a portion of a wellbore. In some embodiments, the deviceincludes a series of expandable packersthat are positioned on a fluid conduit. The expandable packersare positioned with longitudinal spacesbetween the packerswith fluid portsin the longitudinal spacesbetween the packers. In some embodiments, the deviceincludes at least four packers, such as the first packer-, second packer-, third packer-, and fourth packer-positioned in a longitudinal series along a longitudinal directionof the fluid conduit. While embodiments of systems and devices are described herein including four packers, it should be understood that other embodiments may include more, such as 6, 8, 10, or other even quantities of expandable packers in series.

In some embodiments, the expandable packershave a retracted state and an expanded state. The retracted state has a width in a radial direction(e.g., in a direction perpendicular to the longitudinal direction) that is less than the width of the expandable packer in the expanded state. In some embodiments, an expandable packer expands out toward the expanded state from the retracted state and contacts a wellbore wall, a liner, a casing, or other object substantially surrounding the expandable packerin the radially outward direction. In some embodiments, the object prevents expansion of the expandable packer in the radially outward direction, and the expandable packer applies an expansive force to the object before reaching a stable width while contacting the object.

In some embodiments, at least one expandable packerhas a retracted width (e.g., in a retracted state) that is at least 50% of an expanded width (e.g., in an expanded state). In some embodiments, actuation of the expandable packerceases at some positioned between the retracted state and the expanded state when the expandable packeris in contact with a surrounding object. In some embodiments, an expandable packeris actuated toward the expanded state and continues attempting to expand while in contact with the object.

At least one expandable packerof the device, in some embodiments, includes a resilient memberthat is expanded outward in the radial direction. The expandable packeris actuated between the retracted state and the expanded state by an actuation mechanism. In some embodiments, the resilient memberis expanded an actuation mechanism that introduced an expansion fluidinto the resilient member. In some embodiments, the expandable packerincludes a resilient memberthat is urged outward by a mechanical actuation mechanism. For example, one or more hydraulic pistons may be actuated (i.e., through one or more valves) to expand the resilient memberoutward. In some examples, an electric motor may expand at least a portion of the packeroutward. In some embodiments, a radially outward surface of the expandable packerlacks a resilient member and includes a plurality of rigid segments that allow outward expansion.

In some embodiments, the expandable packers(e.g., the first packer-, second packer-, third packer-, and fourth packer-) are substantially identical. For example, the expandable packersmay have one or more of the same retracted width, the same expanded width, the same longitudinal length, and the same actuation mechanism. In some embodiments, an interior pair of packers (e.g., the second packer-and the third packer-) are substantially identical, and an exterior pair of packers (e.g., the first packer-and the fourth packer-) are substantially identical. In some embodiments, the interior pair of packers is different from the exterior pair of packers. For example, the interior pair of packers may vary from the exterior pair of packers in at least one of the retracted width, the expanded width, the longitudinal length, and the actuation mechanism.

In some embodiments, the deviceincludes fluid portsto provide a pressurizing fluid to the longitudinal spacesbetween the packers. In some embodiments, the deviceincludes at least one fluid portbetween each adjacent pair of packers. For example, a first fluid port-may be positioned longitudinally between the first packer-and the second packer-. A second fluid port-may be positioned longitudinally between the second packer-and the third packer-. A third fluid port-may be positioned longitudinally between the third packer-and the fourth packer-.

In some embodiments, the first fluid port-(positioned between the first packer-and the second packer-) and third fluid port-(positioned between the third packer-and the fourth packer-) are exterior fluid ports, while the second fluid port-(positioned between the second packer-and the third packer-) is an interior fluid port. For example, the first fluid port-may be a first exterior port, the second fluid port-may be an interior fluid port, and the third fluid port-may be a second exterior port. While the fluid ports are configured to provide a pressurizing fluid between the packers, in some embodiments, the interior fluid port and the exterior fluid ports are configured to provide different pressurizing fluids. For example, the interior fluid port may provide a first pressurizing fluid including a proppant suspended therein, while the exterior fluid ports provide a second pressurizing fluid lacking a proppant. In some embodiments, the interior fluid port and the exterior fluid port are configured to provide the same pressurizing fluid.

In some embodiments, the interior fluid port and the exterior fluid port are configured to provide the pressurizing fluid (or fluids) at different fluid pressures. In some embodiments, the interior fluid port and the exterior fluid port are configured to provide the pressurizing fluid (or fluids) at substantially the same fluid pressures.

In some embodiments, one or more of the pressurizing fluids is the same as an expansion fluidused to expand one or more of the packers. In some embodiments, one or more of the pressurizing fluids and the expansion fluid(s) are different from one another.

In some embodiments, the fluid conduitis a segment of a drill string, such as the drill stringdescribed in relation to. In some embodiments, the fluid conduitis separate from a drill string. In some embodiments, a pressurizing fluid is a drilling fluid, such as the drilling fluiddescribed in relation to. In some embodiments, the pressurizing fluid is a different fluid. In some embodiments, the pressurizing fluid is a clean fluid that is transported downhole in the device and/or in the drill string. For example, the clean fluid may be water, glycerin, or another liquid fluid. In some examples, the clean fluid is carbon dioxide or another gaseous fluid.

While some embodiments illustrated and described herein include the pressurizing deviceand/or components of the pressurizing deviceconnected to a fluid conduit, it should be understood that at least some components of the pressurizing devicemay be delivered downhole via wireline. In such embodiments, the packersmay be connected by a body of the device that is not a fluid conduit but may contain one or more conduits therein to deliver fluid to the portsthereof. As described herein, the pressurizing devicemay include a bottle or other container of clean fluid to expand the packersand/or pressurize the zones between the packers. In such embodiments, the pressurizing deviceis not part of a drill string (as described in relation to) and is inserted independently of a drill string.

In some embodiments, the device can isolate longitudinal zones of the wellbore and introduce a pressurizing fluid to those zones to test or fracture the wellbore wall, such as a liner or casing, or a portion of the surrounding formation. For example, the device can isolate longitudinal zones of the wellbore and introduce a pressurizing fluid to those zones to test or fracture the formation and measure one or more properties of the formation.

is a side cross-sectional view of an embodiment of a pressurizing devicein a wellbore. In some embodiments, a pressurizing deviceis tripped into a boreholein a formation. In some embodiments, the boreholeincludes a casing (such as described in relation to) or other material between the boreholeand the formation. The pressurizing deviceis moved longitudinally through the boreholeto a location of the borehole(or adjacent formation) to be pressurized. In some embodiments, the pressurizing deviceis tripped downhole with the packersin a retracted state. In some embodiments, one or more of the packersis not in a retracted state. For example, one or more of the packers may be at least partially expanded with a widthof the packerless than a diameterof the borehole.

In some embodiments, the packersare expanded simultaneously to contact the borehole walland form a packer seal between each of the expandable packersand the borehole wall. In some embodiments, the packersare expanded individually or with at least one of the packersexpanded separately from another packer. In some embodiments, the interior pair of packers (e.g., the second packer-and the third packer-) is expanded simultaneously. In some embodiments, the exterior pair of packers (e.g., the first packer-and the fourth packer-) is expanded simultaneously.

In some embodiments, the interior pair of packers is expanded against the borehole wallbefore the exterior pair of packers is expanded against the borehole wall. For example, the interior pair of packers may define an interior zone in which the borehole walland/or formationis to be tested, and expanding the interior pair of packers first may confirm the position of the pressurizing deviceand/or allow simplified repositioning of the pressurizing devicebefore expanding the exterior pair of packers.

In some embodiments, the exterior pair of packers is expanded against the borehole wallbefore the interior pair of packers is expanded against the borehole wall. For example, the interior pair of packers may define an interior zone in which the borehole walland/or formationis to be tested, and expanding the exterior pair of packers first may secure the position of the pressurizing devicerelative to borehole wallbefore expanding the interior pair of packers to provide an improved packer seal between the interior pair of packers and the borehole wall.

In some embodiments, the packersare expanded with an expansion fluid inside the packers. In some embodiments, the packersare expanded to contact the borehole walland form a packer seal between each of the expandable packersand the borehole wallbased on an internal pressure. For example, each packermay be expanded with the same internal pressure. In some embodiments, at least one of the packersis expanded at a different internal pressure from another packer. In some embodiments, the interior pair of packers (e.g., the second packer-and the third packer-) is expanded to a first internal pressure, and the exterior pair of packers (e.g., the first packer-and the fourth packer-) is expanded to a second internal pressure. In some embodiments, the first internal pressure is greater than the second internal pressure. In some embodiments, the first internal pressure is less than the second internal pressure.

In some embodiments, the packersare expanded to contact the borehole walland form a packer seal between each of the expandable packersand the borehole wallwith a contact pressure therebetween. For example, each packermay be expanded to form a packer seal with the same contact pressure as the other packer seals. In some embodiments, at least one of the packersis expanded to form a packer seal with a different contact pressure from another packer seal. In some embodiments, the interior pair of packers (e.g., the second packer-and the third packer-) is expanded to produce interior packer seals with a first contact pressure, and the exterior pair of packers (e.g., the first packer-and the fourth packer-) is expanded to produce exterior packer seals with a second contact pressure. In some embodiments, the first contact pressure is greater than the second contact pressure. In some embodiments, the first contact pressure is less than the second contact pressure.

After the packersare expanded and the packer seals between the borehole walland the packersare formed, a pressurizing fluid may be provided into the borehole.is a side cross-sectional view of an embodiment of a pressurizing devicein a wellbore with pressurized zones isolated by packers. In some embodiments, the interior pair of packers (e.g., the second packer-and the third packer-) define an interior zonelongitudinally therebetween. An interior fluid port (e.g., the second fluid port-) is configured to provide a first pressurizing fluidto the interior zoneto apply a fluid pressure to the formation or other borehole wall.

In some embodiments, the exterior pair of packers (e.g., the first packer-and the fourth packer-) define exterior zones-,-longitudinally adjacent to the interior zone. In some embodiments, exterior fluid ports (e.g., the first fluid port-and third fluid port-) are configured to provide a second pressurizing fluidto the exterior zones-,-to apply a fluid pressure to the formation or other borehole wall and to the interior pair of packers. The fluid pressure in the first exterior zone-supports the second packer-against the fluid pressure in the interior zone, and the fluid pressure in the second exterior zone-supports the third packer-against the fluid pressure in the interior zone.

While the fluid portsare configured to provide a pressurizing fluid,between the packers, in some embodiments, the interior fluid port and the exterior fluid ports are configured to provide different pressurizing fluids. For example, the interior fluid port may provide a first pressurizing fluidincluding a proppant suspended therein, while the exterior fluid ports provide a second pressurizing fluidlacking a proppant. In some embodiments, the interior fluid port and the exterior fluid port are configured to provide the same pressurizing fluid.

In some embodiments, the pressurizing deviceis configured to isolate the fluid pressures in the zones,-,-between the packerswith the packer seals therebetween. Each packer seal may have a maximum pressure differential across the packer seal between zones. For example, the maximum pressure differential may be based at least partially on the contact pressure of the packer seal, the area of the packer seal, a material of the packer, a material or surface of the wellbore wall, or combinations thereof. In some embodiments, the maximum pressure differential across the interior packer seals (e.g., the packer seals of the interior pair of packers between the interior zoneand the exterior zones) is the same as the maximum pressure differential across the exterior packer seals (e.g., the packer seals of the exterior pair of packers between the exterior zonesand the hydrostatic pressure of the borehole). In some embodiments, the maximum pressure differential across the interior packer seals is greater than the maximum pressure differential across the exterior packer seals. In some embodiments, the maximum pressure differential across the interior packer seals is less than the maximum pressure differential across the exterior packer seals.

The longitudinal series of packer seals, in some embodiments, allows the interior zoneto apply a fluid pressure to the formation and/or wellbore wall (e.g., the hydrostatic pressure) that is greater than the maximum pressure differential across the interior packer seals. For example, the maximum pressure differential across the exterior packer seals may be 6 kilo-Pascals (kPa), and the maximum pressure differential across the interior packer seals may be 6 kPa. While a conventional packer system may be limited to applying a 6 kPa fluid pressure to the formation or wellbore wall, the serial configuration of the interior zonebetween the exterior zonesallows the interior zoneto apply a 12 kPa pressure to the formation. For example, the exterior zonesmay be each pressurized to 6 kPa above the hydrostatic pressure (e.g., the maximum pressure differential across the exterior packer seals), and the interior zonemay be pressurized to 6 kPa above the exterior zone fluid pressure (e.g., the maximum pressure differential across the interior packer seals). The resulting interior zone fluid pressure may be a total of 12 kPa greater than the hydrostatic pressure.

is a flowchart illustrating an embodiment of a methodof providing fluid pressure in a downhole environment. The methodincludes expanding a first packer against a borehole wall at, expanding a second packer against the borehole wall at, expanding a third packer against the borehole wall at, and expanding a fourth packer against the borehole wall at. Expanding the packers against the borehole wall creates a packer seal between each packer and the borehole wall. In some embodiments, the borehole wall is or includes the surrounding formation. In some embodiments, the borehole wall is or includes a wellbore liner or casing.

In some embodiments, expanding the packers,,,includes expanding all of the packers simultaneously. In some embodiments, the packers are expanded individually or with at least one of the packers expanded separately from another packer. In some embodiments, the interior pair of packers (e.g., the second packer and the third packer) is expanded simultaneously. In some embodiments, the exterior pair of packers (e.g., the first packer and the fourth packer) is expanded simultaneously.

In some embodiments, the interior pair of packers is expanded against the borehole wall before the exterior pair of packers is expanded against the borehole wall. For example, the interior pair of packers may define an interior zone in which the borehole wall and/or formation is to be tested, and expanding the interior pair of packers first may confirm the position of the pressurizing device and/or allow simplified repositioning of the pressurizing device before expanding the exterior pair of packers.

In some embodiments, the exterior pair of packers is expanded against the borehole wall before the interior pair of packers is expanded against the borehole wall. For example, the interior pair of packers may define an interior zone in which the borehole wall and/or formation is to be tested, and expanding the exterior pair of packers first may secure the position of the pressurizing device relative to borehole wall before expanding the interior pair of packers to provide an improved packer seal between the interior pair of packers and the borehole wall.

In some embodiments, the packers are expanded with an expansion fluid inside the packers. In some embodiments, the packers are expanded to contact the borehole wall and form a packer seal between each of the expandable packers and the borehole wall based on an internal pressure. For example, each packer may be expanded with the same internal pressure. In some embodiments, at least one of the packers is expanded at a different internal pressure from another packer. In some embodiments, the interior pair of packers (e.g., the second packer and the third packer) is expanded to a first internal pressure, and the exterior pair of packers (e.g., the first packer and the fourth packer) is expanded to a second internal pressure. In some embodiments, the first internal pressure is greater than the second internal pressure. In some embodiments, the first internal pressure is less than the second internal pressure.

In some embodiments, the packers are expanded to contact the borehole wall and form a packer seal between each of the expandable packers and the borehole wall with a contact pressure therebetween. For example, each packer may be expanded to form a packer seal with the same contact pressure as the other packer seals. In some embodiments, at least one of the packers is expanded to form a packer seal with a different contact pressure from another packer seal. In some embodiments, the interior pair of packers (e.g., the second packer and the third packer) is expanded to produce interior packer seals with a first contact pressure, and the exterior pair of packers (e.g., the first packer and the fourth packer) is expanded to produce exterior packer seals with a second contact pressure. In some embodiments, the first contact pressure is greater than the second contact pressure. In some embodiments, the first contact pressure is less than the second contact pressure.

The methodfurther includes pressurizing an interior zone longitudinally between the second packer and the third packer to a first pressure (e.g., an interior fluid pressure) relative to a hydrostatic borehole pressure that is greater than a second pressure (e.g., an exterior fluid pressure) of at least one exterior zone at. In some embodiments, a first exterior zone is longitudinally between the first packer and the second packer. In some embodiments, a second exterior zone is longitudinally between the third packer and the fourth packer. In some embodiments, the methodincludes further pressurizing the at least one exterior zone to the second pressure, where the second pressure is greater than the hydrostatic pressure of the borehole. In some embodiments, the first pressure is greater than the second pressure relative to the hydrostatic pressure of the borehole.

In some embodiments, a first pressurizing fluid provided to the interior zone and a second pressurizing fluid provided to the at least one exterior zone are the same fluid. For example, the pressurizing fluid may be a drilling fluid. In some embodiments, the first pressurizing fluid provided to the interior zone and the second pressurizing fluid provided to the at least one exterior zone are different fluids. For example, the first pressurizing fluid may be a hydraulic fracturing fluid, which may include a proppant, and the second pressurizing fluid may be another fluid, such as a drilling fluid.

In some embodiments, each of the packer seals has a maximum pressure differential before the packer seal fails and allows fluid flow across the packer in the wellbore. In some embodiments, the first pressure relative to the second pressure is less than a maximum pressure differential of a packer seal therebetween (e.g., the packer seal of the second packer between the interior zone and the first exterior zone) and the first pressure relative to the hydrostatic pressure of the borehole is greater than the maximum pressure differential of a packer seal between the first pressure and the second pressure. In some embodiments, the first pressure relative to the second pressure is less than a maximum pressure differential of a packer seal therebetween (e.g., the packer seal of the second packer between the interior zone and the first exterior zone) and the first pressure relative to the hydrostatic pressure of the borehole is greater than the maximum pressure differential across any packer seal of the pressuring device.

In some embodiments, an exterior maximum pressure differential of the exterior packer seals (e.g., the first packer seal and the fourth packer seal) is greater than an interior maximum pressure differential of the interior packer seals (e.g., the second packer seal and the third packer seal). For example, leakage or failure of the interior packer seals may create an increase in the exterior fluid pressure, and a greater exterior maximum pressure differential of the exterior packer seals may allow the exterior packer seals to limit or prevent fluid flow thereacross in the event of a sudden increase in the exterior fluid pressure relative to the hydrostatic borehole pressure. In some embodiments, an exterior maximum pressure differential of the exterior packer seals (e.g., the first packer seal and the fourth packer seal) is less than an interior maximum pressure differential of the interior packer seals (e.g., the second packer seal and the third packer seal). For example, the interior zone may be adjacent to the region of interest for the highest fluid pressure and pressurizing the interior zone to a proportionately higher fluid pressure than the exterior zone(s) may require less pressurizing fluid and therefore less pressurization time. The shorter pressurization time may allow more higher pressure testing and/or testing of more locations in the same total amount of time.

Embodiments of the present disclosure generally relate to devices, systems, and methods for providing a fluid to a downhole environment. More particularly, the present disclosure relates to the isolation (or partially isolation) of a longitudinal segment of a borehole into which a pressurized fluid is pumped to apply a fluid pressure to a surrounding formation or other material forming the borehole wall. In some embodiments, the pressurized fluid is used for hydraulic fracturing of the formation. In some embodiments, the pressurized fluid is used to test production of the formation. In some embodiments, the pressurized fluid is used to test an integrity of the borehole wall (such as that of a casing on the borehole).

In some embodiments, a device according to the present disclosure includes a longitudinal series of expandable packers that isolate (or at least partially isolate) adjacent zones from one another by limiting and/or preventing fluid flow between the zones. For example, the series of expandable packers create a series of packer seals against the borehole wall, limiting and/or preventing fluid flow between the zone through the borehole. In some embodiments, systems and methods described herein allow for fluid pressure of the pressurized fluid in at least one zone of the borehole to be greater than a maximum pressure differential across a single packer. For example, the packer seals may fail when a fluid pressure differential across the packer seal exceeds a maximum pressure differential of the seal. A series of packer seals that are pressurized to the maximum pressure differential can allow an interior zone to have a fluid pressure that is greater than the hydrostatic pressure in the borehole, and, therefore, the interior zone can apply a fluid pressure to the borehole wall and/or formation that is greater than with a conventional two-packer device.

In some embodiments, the pressurizing device includes a series of expandable packers that are positioned on a fluid conduit. The expandable packers are positioned with longitudinal spaces between the packers with fluid ports in the longitudinal spaces between the packers. In some embodiments, the device includes at least four packers, such as the first packer, second packer, third packer, and fourth packer positioned in a longitudinal series along a longitudinal direction of the fluid conduit. While embodiments of systems and devices are described herein including four packers, it should be understood that other embodiments may include more, such as 6, 8, 10, or other even quantities of expandable packers in series.

In some embodiments, the expandable packers have a retracted state and an expanded state. The retracted state has a width in a radial direction (e.g., in a direction perpendicular to the longitudinal direction) that is less than the width of the expandable packer in the expanded state. In some embodiments, an expandable packer expands out toward the expanded state from the retracted state and contacts a wellbore wall, a liner, a casing, or other object substantially surrounding the expandable packer in the radially outward direction. In some embodiments, the object prevents expansion of the expandable packer in the radially outward direction, and the expandable packer applies an expansive force to the object before reaching a stable width while contacting the object.