Patent Grant
10024147
The present disclosure relates generally to a downhole pressure maintenance system, and specifically a pressure maintenance system that maintains a pressure within an isolated annulus of a wellbore within a predetermined pressure range.
After a well is drilled and a target reservoir has been encountered, completion and production operations are performed, which may include gravel packing operations. Generally, gravel packing operations include placing a lower completion assembly, which forms part of a working string, downhole within a target reservoir in a formation. In a multi-zone completion, a number of packers are located within the lower completion assembly and are activated to isolate a portion of a wellbore annulus formed between the working string and the casing (if a cased hole) or the formation (if an open hole). Each of these portions may be production zones that are subsequently packed with gravel or coarse sand. Often, after one of the packers is set but prior to the gravel packing of the production zones, each production zone is isolated from the wellbore hydrostatic pressure. As the formation absorbs drilling fluids from each production zone, the wellbore annulus pressure within each of the production zones may drop, which may cause collapse of an open hole or influx of sand in an unconsolidated cased hole installation.
The present disclosure is directed to a downhole pressure maintenance system that overcomes one or more of the shortcomings in the prior art.
Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements.
Illustrative embodiments and related methods of the present disclosure are described below as they might be employed in a downhole pressure maintenance system. In the interest of clarity, not all features of an actual implementation or method are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would iii nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments and related methods of the disclosure will become apparent from consideration of the following description and drawings.
The foregoing disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as “beneath,” “below,” “lower,” “above,” “upper,” “uphole,” “downhole,” “upstream,” “downstream,” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures. The spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures. For example, if the apparatus in the figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” may encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.
Referring initially to
A wellbore 80 extends through the various earth strata including the formation 20 and has a casing string 85 cemented therein. Disposed in a substantially horizontal portion of the wellbore 80 is a lower completion assembly 87 that forms a part of the working string 75 and that may include an isolation packer 90 and a sump packer 95. The lower completion assembly 87 may also include packers 100 and 105 that at least partially define a first zone 110, a second zone 115, and a third zone 120 of the lower completion assembly 87. In one or more exemplary embodiments, a portion of the formation 20 that surrounds the first zone 110, the second zone 115, and the third zone 120 may be associated with a reservoir pressure. In one or more exemplary embodiments, the first zone 110, the second zone 115, and the third zone 120 are associated with production zones. In one or more exemplary embodiments, each of a flow regulating systems 125, 130, and 135 is located on the lower completion assembly 87 within each of the third zone 120, the second zone 115, and the first zone 110, respectively. In one or more exemplary embodiments, a pressure maintenance device (“PMD”) 140 is located on or in the lower completion assembly 87 within each of the first zone 110, the second zone 115, and the third zone 120. One or more communication cables, such as an electric cable 145, may pass through the packers 90, 100, and 105 and may be provided and extend from the lower completion assembly 87 to the surface in an wellbore annulus 150 formed between the working string 75 and the casing 85 or an interior surface 80a of the wellbore 80 when the wellbore 80 is an open hole wellbore.
Even though
In one or more exemplary embodiments and illustrated in
In one or more exemplary embodiments and illustrated in
In an exemplary embodiment, the flow path 175 forms a first section 175a that extends from the opening 185 to the valve 190, a second section 175b that extends from the valve 190 to the valve 195, a third section 175c that extends from the valve 195 to the valve 200, a fourth section 175d that extends from the valve 200 to the restrictor 300, and a fifth section 175e that extends from the check valve 205 to the opening 180.
In one or more exemplary embodiments, the valve 190 closes when a first pressure differential exceeds a first threshold pressure, such as for example 2,500 psi. In one or more exemplary embodiments, the first pressure differential is a pressure differential between an internal pressure, which is a pressure within the internal region, or the completion string annulus 165, and an external pressure, which is a pressure associated with the external region, or the wellbore annulus 150. Otherwise, and when the first pressure differential is less than 2,500 psi, the valve 190 is open to allow the fluid to flow through the flow path 175 from the first section 175a to the second section 175b. That is, when the internal pressure exceeds the external pressure by the first pressure differential, the valve 190 is closed. However, when the internal pressure exceeds the external pressure by an amount less than the first pressure differential, when the external pressure is equal to the internal pressure, and when the external pressure exceeds the internal pressure, the valve 190 remains open. In one or more exemplary embodiments, the first threshold pressure may be any predetermined pressure, such as for example 1,000 psi, 1,500 psi, 2,000 psi, 3,000 psi, 3,500 psi, or 4,000 psi.
In one or more exemplary embodiments, the valve 195 closes when a second pressure differential exceeds a second threshold pressure. Otherwise, the valve 195 remains open. In one or more exemplary embodiments, the second pressure differential is a pressure differential between the external pressure and a reference pressure. In one or more exemplary embodiments, the second threshold pressure may be any predetermined pressure, such as for example 100 psi, 200 psi, 300 psi, 400 psi, or 500 psi. In one or more exemplary embodiments, the second threshold pressure correlates to the desired pressure differential between the reservoir pressure and the pressure in the wellbore annulus 150. In an exemplary embodiment, the second threshold is 200 psi. In an exemplary embodiment, and when the reservoir pressure is 10,000 psi and the second threshold pressure is 200 psi, the ideal pressure within the wellbore annulus 150 is between 10,000 psi and 10,200 psi.
In one or more exemplary embodiments, the valve 200 is a flow control valve that opens when a third pressure differential exceeds a third threshold pressure. In an exemplary embodiment, the third threshold pressure is a pressure differential between the pressure within the third section 175c of the flow path 175 and the fourth section 175d of the flow path 175. In one or more exemplary embodiments, the third pressure differential may be any predetermined pressure, such as for example 50 psi. In an exemplary embodiment, the third pressure differential may be 150 psi. In one or more exemplary embodiments, the valve 200 controls the flow of the fluid through the flow path 175. For example, when the pressure within the third section 175c of the flow path 175 exceeds the pressure within the fourth section 175d of the flow path 175 by 150 psi, the valve 200 opens. In an exemplary embodiment and when the valve 200 is open, the fluid flows through the restrictor 300, which creates a back pressure that is communicated through a pilot line 305 as a feedback signal to flow control valve 200. In an example embodiment, this causes the valve 200 to move to create a higher pressure across the valve 200 thereby reducing the flow rate. In an exemplary embodiment, this continues until a stable value of flow rate is achieved, which will cause a spool in the valve 200 to remain in a stable state.
In one or more exemplary embodiments, the DPPMD 173 may also include a reference pressure assembly 310, which may include a valve 315 that controls the flow of a fluid into a pressurized fluid source, or an accumulator 320, from a pilot line 326 that extends between the accumulator 320 and the external region. In an exemplary embodiment, the valve 315 is also fluidically connected to the external region via the pilot line 326 and the second section 175b of the flow path 175 via a pilot line 327. In an exemplary embodiment, the fluid that pressurizes the accumulator 320 flows through the pilot line 326 towards the accumulator 320. In an exemplary embodiment, a fluid located within the wellbore annulus 150 pressurizes the fluid that flows through the pilot line 326 to pressurize the accumulator 320. In one or more exemplary embodiments, the accumulator 320 is pressurized to an initial pressure at the surface, such as for example using a fluid such as a nitrogen gas. A check valve 330 may form a portion of the pilot line 326 to prevent the flow of a fluid from the accumulator 320 and towards the valve 315. However, the check valve 330 may be omitted from the DPPMD 173. In one or more exemplary embodiments, a filtering device 331 and/or a piston 332 may form a portion of the pilot line 327. In an exemplary embodiments, a pilot line 335 extends between the accumulator 320 and the valve 195. In one or more exemplary embodiments, a pressure relief valve 340 is fluidically connected to the pilot line 335 and is configured to depressurize the reference pressure assembly 310 when the DPPMD 173 is pulled up to the surface. In an exemplary embodiment, the valve 315 may be a two-position spool valve having a latch feature that secures the valve 315 in the closed position. In an exemplary embodiment, the valve 315 closes when a fourth pressure differential exceeds a fourth threshold pressure, such as for example 100 psi. However, a variety of fourth threshold pressures are contemplated here. In an exemplary embodiment, the fourth threshold pressure is a pressure differential between the pressure within the second section 175b of the flow path 175 and the external pressure. In one or more exemplary embodiments, the fourth threshold pressure is less than the first threshold pressure so that the valve 315 will close prior to the valve 190 closing. In one or more exemplary embodiments, the accumulator 320 is a piston type accumulator such as for example, a gas-charged accumulator that is a hydraulic accumulator with gas as the compressible medium. In an exemplary embodiment, the pressure relief valve 340 is also connected to the external region via a pilot line 341. In an exemplary embodiment, the pressure relief valve 340 may be rated at 5,000 psi change of pressure, although a variety of pressure ratings are contemplated here. In an exemplary embodiment, the reference pressure assembly 310 may also include a rupture disk 342 that is fluidically connected to the pilot line 335 and the external region via a pilot line 343. In an exemplary embodiment, the rupture disk 342 may be rated at 7,000 psi, although a variety of pressure ratings are contemplated here.
In one or more exemplary embodiments, the DPPMD 173 may also include a pilot line 345 that extends between the external region and the valve 195. In one or more exemplary embodiments, the DPPMD 173 may also include a pilot line 346 that extends between the external region and the valve 190. In an exemplary embodiment, the DPPMD 173 may also include a pilot line 347 that extends from the pilot line 345 to the valve 200. A filtering device 360 and/or a piston 365 may form a portion of the pilot line 345. In an exemplary embodiment, a screen 375 and/or a piston 380 may form a portion of the pilot line 305. In one or more exemplary embodiments, the DPPMD 173 also includes a pilot line 381 extending between the internal region or the completion string annulus 165 (via the first portion 175a of the flow path 175) and the valve 190. A filtering device 382 and/or a piston 383 may form a portion of the pilot line 381.
In an exemplary embodiment, the DPPMD 173 also includes a flow path 384 that extends from an opening 385 that is exposed to a pressure within completion string annulus 165 to the second section 175b of the flow path 175. In an exemplary embodiment, a valve 386 may be located along the flow path 384. In one or more exemplary embodiments, a pilot line 387 extends between the accumulator 320 and the valve 386. In one or more exemplary embodiments, the valve 386 is fluidically connected to the pilot line 381. In an exemplary embodiment, the valve 386 may be a two-position spool valve that closes when a fifth pressure differential exceeds a fifth threshold pressure. In one or more exemplary embodiments, the fifth pressure differential is a difference between the pressure in the accumulator 320 and the internal pressure. That is, the fifth pressure differential is based on the reference pressure and the internal pressure. Generally, the valve 386 closes when the reference pressure exceeds the internal pressure by the fifth threshold pressure. In one or more exemplary embodiments, a filtering device 388 is located along the flow path 384 between the opening 385 and the valve 386. In an exemplary embodiment, the opening 185 and the opening 385 are spaced longitudinally along the lower completion assembly 87 such that the opening 185 is fluidically connected to the completion string annulus 165 at a location uphole from the sump packer 95 and the opening 385 is fluidically connected to the completion string annulus 165 at a location downhole from the sump packer 95. In one or more exemplary embodiments, the opening 385 is fluidically connected to the completion string annulus 165 at a location outside of the production zone. Thus, pressurized fluid within the completion string annulus 165 that is located downhole from the sump packer 95 may be used to pressurize the wellbore annulus 150 of the first zone 110, the second zone 115, and the third zone 120. Often, when the packers 100 and 105 are being set, the pressure within the completion string annulus 165 that is located uphole from the sump packer 95 may increase greatly, thus exceeding the first threshold pressure to close the valve 190. In order to continue pressurizing the external region, or the wellbore annulus 150 associated with the production zone of the lower completion system 87, while the isolation packers 100 and 105 are being set, pressurized fluid within the completion string annulus 165 that is located downhole from the sump packer 95 may flow through the flow path 384. In one or more exemplary embodiments, the DPPMD 173 may also include a filtering device 389 that may form a portion of the first section 175a of the flow path 175. In one or more exemplary embodiments, a filtering device 390 may form a portion of the fifth section 175e of the flow path 175. In one or more exemplary embodiments, the filtering devices 331, 360, 375, 382, 388, 389, and 390 may be any type of device to screens large solid particles, such as for example, a screen. In an exemplary embodiment, a check valve 391 may be located along the flow path 384 to prevent the fluid from flowing from the second section 175b of the flow path 175 to the valve 386.
In one or more exemplary embodiments and illustrated in
In one or more exemplary embodiments, the PMD 140 in the third zone 120 is a SPPMD 392′, which is substantially identical or identical to the SPPMD 392, and therefore the SPPMD 392′ will not be described in further detail. Reference numerals used to refer to the features of the SPPMD 392 that are substantially identical to the features of the SPPMD 392′ will correspond to the reference numerals used to refer to the features of the SPPMD 392. In one or more exemplary embodiments, the opening 185 of the SPPMD 392′ is fluidically connected to the internal region, or the completion string annulus 165, of the third zone 120.
With reference to
At the step 405, the lower completion system 87 is positioned downhole to pressurize the assemblies 310 of the SPPMD 392′, the SPPMD 392, and the DPPMD 173. Referring to
At the step 410, the packer 90 is set to isolate the production zone of the lower completion system 87 and to fix the reference pressures within each of the SPPMD 392′, the SPPMD 392, and the DPPMD 173. In one or more exemplary embodiments, setting the packer 90 will isolate the production zone of the lower completion system 87 from the wellbore hydrostatic pressure. In one or more exemplary embodiments, setting the packer 90 includes increasing the internal pressure within the completion string annulus 165 so that the packer 90 may expand to fluidically isolate the wellbore annulus 150 of the production zone of the lower completion system 87 from the wellbore annulus 150 that is uphole from the packer 90. In one or more exemplary embodiments, the internal pressure may be increased to about 3,600 psi, however any internal pressure is contemplated here. In one or more exemplary embodiments, increasing the internal pressure can cause the fourth pressure differential to exceed the fourth threshold pressure to close the valve 315. In one or more exemplary embodiments, the valve 315 has a latching mechanism to prevent the valve 315 from reopening once the fourth pressure differential recedes below the fourth threshold pressure. Accordingly, the accumulator 320 and the pilot line 335 and a portion of the pilot line 326 can no longer be pressurized and the reference pressure is “set” or fixed at the pressure within the accumulator 320 when the valve 315 closes. In one or more exemplary embodiments, increasing the internal pressure can also cause the first pressure differential to exceed the first threshold pressure differential to close the valve 190.
At the step 415 and referring back to
In one or more exemplary embodiments and as illustrated in
Returning to
At the step 425, the predetermined pressure range is maintained within the first zone 110 using the SPPMD 173. In an exemplary embodiment, the step 425 is identical to the step 415 and therefore, no additional detail will be provided here. However, as the production zone is now separated into the first zone 110, the second zone 115, and the third zone 120, the SPPMD 173 can only maintain the first zone 110 within the predetermined pressure range.
At the step 430, the first zone 110 is gravel packed while the predetermine pressure range is maintained in the second zone 115 using the SPPMD 392 and the predetermined pressure range is maintained in the third zone 120 using the SPPMD 392′. In one or more exemplary embodiments, maintaining the predetermined pressure range in the third zone 120 using the SPPMD 392′ and maintaining the predetermined pressure range in the second zone 115 using the SPPMD 392 is identical to maintaining the predetermined pressure range in the production zone using the DPPMD 173 except the sub-steps 415d, 415e, and 415f are omitted, as shown in
Referring back to
The process continues until each of the first zone 110, the second zone 115, and the third zone 120 of the production zone is gravel packed and/or frac-packed.
In an exemplary embodiment, a PMD 140 identical to the SPPMD 392 may be used in place of the DPPMD 173 and the steps 415 and 425 are omitted from the method 400. In an exemplary embodiment, the method 400 may also include a method of testing the lower completion system 87 at or near the surface. In an exemplary embodiment, the lower completion system 87 is lowered downhole to a first distance, for example, to 300 feet downhole. In an exemplary embodiment, the fluid is then flowed through the completion string annulus 165 and the pressure in the completion string annulus 165 and/or the wellbore annulus 150 is increased to a pressure less than the pressure differential associated with the valve 393, such as 500 psi. The pressure within the completion string annulus 165 and/or the wellbore annulus 150 is monitored while the valve 393 remains closed. Thus, the lower completion system 87 may be tested for leaks or other issues. Once the testing of the lower completion system 87 is complete, the interior pressure within the completion string annulus 165 may be increased such that the pressure differential associated with the valve 393 is exceed. In an exemplary embodiment, and once the pressure differential associated with the valve 393 is exceeded, the shear pin in the valve 393 is sheared and the collet is secured in the groove to lock the valve 393 in an open position.
In an exemplary embodiment, the pressure relief valve 340 and the rupture disk 342 are safety features useful in the event the lower completion system 87 is returned to the surface. In an exemplary embodiment, and when the pressure within the pressure assembly 310 has been “set” or fixed at 10,000 psi, a pressure differential between the pressure assembly 310 and the exterior region increases as the depth of the lower completion system 87 is reduced. Once the pressure differential reaches the rating of the pressure relief valve 340, such as 5,000 psi, the pressure relief valve 340 opens to decrease the pressure within the pressure assembly 310. In an exemplary embodiment and if the pressure relief valve 340 fails, then when the pressure differential reaches the rating of the rupture disc 342, such as 7,000 psi, the rupture disc 342 ruptures to decrease the pressure within the pressure assembly 310.
In one or more embodiments, each of the first, second, third, fourth, and fifth threshold pressures is a function of springs used within the valves 190, 195, 200, 315, and 386, respectively. In one or more exemplary embodiments, each spring constant and the initial pre-compression of the springs within the valves 190, 195, 200, 315, and 386 is selected to achieve a predetermined pressure differential threshold for each of the valves 190, 195, 200, 315, and 386. In an exemplary embodiment, the valves 190, 195, 200, 315, 386, and 393 include a pressure differential sensor that may include a spring and spool. In an exemplary embodiment, each of the valves 190, 195, 200, 315, 386, and 393 measures and compares two pressures using the spring and the spool. In an exemplary embodiment, the pilot lines 346 and 381 are in fluid communication with the pressure differential sensor of the valve 393. In an exemplary embodiment, the pilot lines 327 and 326 are in fluid communication with the pressure differential sensor of the valve 315. In an exemplary embodiment, the pilot lines 335 and 345 are in fluid communication with the pressure differential sensor of the valve 195. In an exemplary embodiment, the pilot line 380 and the flow path 175 are in fluid communication with the pressure differential sensor of the valve 200. In an exemplary embodiment, the pilot lines 387 and 381 are in fluid communication with the pressure differential sensor of the valve 386. In an exemplary embodiment, the pilot lines 394 and 395 are in fluid communication with the pressure differential sensor of the valve 393. In one or more exemplary embodiments, the DPPMP 173, the SPPMD 392, and the SPPMD 392′ form a portion of a wall of the working string 75 and each of the components (i.e., the valves 190, 195, 200, 315, 386) are of the cartridge type configuration. In one or more exemplary embodiments, the predetermined pressure range for each of the first zone 110, the second zone 115, and the third zone 120 is different and dependent upon each zone's formation, depth, etc.
In one or more embodiments, the method 400 may be used to maintain a certain desired excess pressure above the reservoir pressure in the wellbore annulus 150 to prevent or at least reduce uncontrolled fluid production into any part of the first zone 110, the second zone 115, and the third zone 120. In one or more exemplary embodiments, the method 400 encourages maintaining the wellbore annulus 150 in a clean state to prevent premature blocking of a proppant during a frac-pack or gravel pack operation. In one or more exemplary embodiments, the method 400 prevents or at least reduces the likelihood of the wellbore 80 collapsing in the case of an unconsolidated formation. In one or more exemplary embodiments, the method 400 may maintain the external pressure in the wellbore annulus 150 for an indefinite amount of time.
The present disclosure may be altered in a variety of ways. For example, the reference pressure assembly 310 may be omitted from the DPPMD 173, the SPPMD 392, and/or the SPPMD 392′ and be replaced by a pressure system that is structurally configured to be charged to an estimated reservoir pressure at the surface of the well, such as for example an accumulator that is charged at the surface of the well. In one or more exemplary embodiments, the DPPMD 173, the SPPMD 392, and the SPPMD 392′ or any combination thereof may include an isolation sleeve (not shown) that extends within the completion string annulus 165 and may be moved into a position to block the openings 185 or 385 or both.
In one or more exemplary embodiments and illustrated in
With reference to
At the step 515, the lower completion system 87, which includes the EPMD 450, is positioned downhole. In one or more exemplary embodiments, the isolation sleeve 505 is in the open position when the lower completion system 87 is positioned downhole.
At the step 520, the production zone of the lower completion system 87 is isolated from the wellbore hydrostatic pressure formed within the wellbore 80. In one or more exemplary embodiments, the lower completion system 87 is isolated by the setting of a packer, such as the packer 90.
At the step 525, the predetermined pressure range is maintained in the production zone using the EPMD 450. In one or more exemplary embodiments, maintaining the predetermined pressure range in the production zone using the EPMD 450 includes the controller 495 determining whether the external pressure within the wellbore annulus 150 as measured by the pressure sensor 492 is less than the predetermined pressure range. If the external pressure within the wellbore annulus 150 as measured by the pressure sensor 492 is within the predetermined pressure range or exceeds the predetermined pressure range, the controller 495 may activate the motor 485 to move the screw drive 480 and the piston valve 475 to block the flow path 465 such that fluid from the completion string annulus 165 does not flow to the wellbore annulus 150. If the external pressure within the wellbore annulus 150 as measured by the pressure sensor 492 is below the predetermined pressure range (and assuming the internal pressure as measured by the pressure sensor 490 is greater than the external pressure), the controller 495 may activate the motor 485 to move the screw drive 480 and the piston valve 475 to open the flow path 465 such that the fluid may flow from the completion string annulus 165 to the wellbore annulus 150. In an exemplary embodiment, the piston valve 475 may also be partially closed or partially opened to choke the flow of the fluid from the completion string annulus 165 to the wellbore annulus 150. In an exemplary embodiment, choking the flow of the fluid from the completion string annulus 165 to the wellbore annulus 150 allows the production zone to be pressurized even when the interior pressure exceeds the predetermined pressure range. In one or more exemplary embodiments, instructions may be sent from the surface to the controller 495 using the pressure sensor 490 and a telemetry system such as, for example, a mud pulse telemetry system. However, the EPMD 450 may be structurally configured to communicate with any telemetry system, such as for example an electromagnetic, an acoustic, a torsion, or a wired drill pipe telemetry system. The instructions received by the controller 495 may include instructions to open, close, or choke the fluid path 460. In one or more exemplary embodiments, the piston valve 475 may be partially opened when the internal pressure in the completion string annulus 165, as measured by the pressure sensor 490, is greater than the predetermined pressure range, to choke the flow into the wellbore annulus 150. In one or more exemplary embodiments, the instructions received by the pressure sensor 490 may include a new predetermined pressure range. In an exemplary embodiment, the predetermined pressure range is defined by a minimum pressure and a maximum pressure.
At the step 530, the production zone is gravel packed or frac-packed. Once the wellbore annulus 150 of the production zone is gravel packed or frac-packed, the risk of formation collapse is reduced.
At the step 535, the isolation sleeve of the EPMD 450 is closed. In one or more exemplary embodiments, the downhole tool, such as the shifting tool, is accommodated within the working string 75 during gravel pack or frac-pack operations. When the gravel pack or frac-pack operations are completed, the shifting tool may move uphole. During this movement uphole, the shifting tool couples to the isolation sleeve 505 and moves the isolation sleeve 505 from the open position to the closed position. In one or more exemplary embodiments, moving the isolation sleeve 505 to the closed position may prevent or at least discourage fluid flow through the fluid path 460 during production operations.
In one or more embodiments, the method 510 may be used to maintain a certain desired excess pressure above the reservoir pressure in the wellbore annulus 150 to prevent or at least reduce uncontrolled fluid production into any part of the production zone. In one or more exemplary embodiments, the method 510 encourages maintaining the wellbore annulus 150 in a clean state to prevent premature blocking of the proppant during a frac-pack or gravel pack operation. In one or more exemplary embodiments, the method 510 prevents or at least reduces the likelihood of the wellbore 80 collapsing in the case of an unconsolidated formation. In one or more exemplary embodiments, the method 510 may maintain the external pressure in the wellbore annulus 150 for an indefinite amount of time. In an exemplary embodiment, the method 510 may be used to maintain the predetermined pressure range during a variety of operations, such as for example, during the setting of the isolation packer, zone pressure testing, frac packing lower zones, and reversing out lower zones following the frac pack. In an exemplary embodiment, the method 510 will prevent or at least reduce the likelihood of cross flow between production zones and cross flow within one production zone. In one or more exemplary embodiments, the method 510 may also prevent or at least reduce the likelihood of over-pressurizing the formation 20.
The present disclosure may be altered in a variety of ways. For example, the EPMD 450 may include a Radio-frequency identification (“RFID”) reader or scanner such that when the shifter tool, which may include a RFID tag, passes near the RFID reader on the EPMD 450, the controller 495 would move the valve piston 475 to block the fluid path 460 regardless of the external pressure as measured by the pressure sensor 492. In one or more exemplary embodiments, if the shifter tool is tripped back down again, the RFID tag may signal the EPMD 450 to being maintaining the predetermined pressure range within the production zone. In one or more exemplary embodiments, the EPMD 450 may be configured to include a cartridge rod piston valve. In one or more exemplary embodiments, the EPMD 450 includes any valve that is controlled by an electronic module and pressure sensor. Additionally, each production zone with a multi-zone completion system may be associated with one (or more) EPMD 450. In another exemplary embodiment, the EPMD 450 may also include a filter (not shown) located between the completion string annulus 165 and the piston valve 475. In an exemplary embodiment, the piston valve 475 acts as a flow limiter and the EPMD 450 also includes a check valve (not shown) located between the piston valve 475 and the wellbore annulus 150. In an exemplary embodiment, the database 495c may store data relating to a reference pressure that is input at the surface or updated while the EPMD 450 is downhole using the telemetry system. That is, the controller 495 may receive instructions or an updated predetermined pressure range from a surface system by using pressure pulses detected in the internal region as measured by the pressure sensor 490. In an exemplary embodiment, the EPMD 450 may “report” the reservoir pressure to the surface or other pressure to the surface. In an exemplary embodiment, the EPMD 450 may also include a timer (not shown) that is included in the controller 495 or that may communicate with the controller 495, with the operation of the piston valve 475 dependent upon a time variable measured by the timer. In an exemplary embodiment, the EPMD 450 may be used to determine the location of the EPMD 450. For example, if the controller 495 communicates with a surface system that the external pressure or the internal pressure or both reaches a steady state, then this steady state could correspond to a desired location of the EPMD 450 within the wellbore 80. In an exemplary embodiment, data or instructions can be sent from the telemetry system or other system to the controller 495 to shut down the piston valve 475 during an unsafe event or other event. That is, the EPMD 450 may be actuated remotely. In an exemplary embodiment, the EPMD 450 may “report” localized downhole conditions to the surface, such as for example, a filter plug.
In one or more exemplary embodiments and illustrated in
In another exemplary embodiment, and as shown in
In one or more exemplary embodiments and as illustrated in
In one or more exemplary embodiments, and as illustrated in
The method of operation of the MPMD 555 or the MPMD 625 may include lowering the lower completion system 87, which includes the MPMD 555 or the MPMD 625, downhole, isolating a production zone of the lower completion system 87, maintaining the predetermined pressure range in the production zone of the lower completion system 87 using the MPMD 555 or the MPMD 625, gravel packing the production, and permanently closing the flow path 635 using the LOD 605. At the surface of the well, the pressure exerted on the piston 647 is sufficiently higher than the external pressure to close the valve 630. As the MPMD 555 or the MPMD 625 is lowered downhole, the external and internal pressure increases such that the valve 630 opens and fluid flows from the internal region to the external region. When a packer is set, the internal pressure increase greatly, thereby closing the valve 630. Once the internal pressure is reduced, the valve 630 opens to pressurize the external region. Gravel packing operations may then begin. After a period of time or once an internal pressure has been reached, the LOD 605 is activated and the flow path 635 is permanently blocked. In one or more embodiments, the MPMD 555 or the MPMD 625 may be used to maintain a certain desired excess pressure above the reservoir pressure in the wellbore annulus 150 to prevent or at least reduce uncontrolled fluid production into any part of the production zone. In one or more exemplary embodiments, the MPMD 555 or the MPMD 625 encourages maintaining the wellbore annulus 150 in a clean state to prevent premature blocking of the proppant during a frac-pack or gravel pack operation. In one or more exemplary embodiments, the MPMD 555 or the MPMD 625 prevents or at least reduces the likelihood of the wellbore 80 collapsing in the case of an unconsolidated formation. In an exemplary embodiment, the MPMD 555 or the MPMD 625 may be used to maintain the predetermined pressure range during a variety of operations, such as for example, during the setting of the isolation packer, zone pressure testing, frac packing lower zones, and reversing out lower zones following the frac pack. In an exemplary embodiment, the MPMD 555 or the MPMD 625 will prevent or at least reduce the likelihood of cross flow between production zones and cross flow within one production zone. In one or more exemplary embodiments, the MPMD 555 or the MPMD 625 may also prevent or at least reduce the likelihood of over-pressurizing the formation 20.
In one or more exemplary embodiments, the PMD 140 forms a portion of a wall of the tubing string 87 and each of the components are of the cartridge type configuration.
In several exemplary embodiments, the elements and teachings of the various illustrative exemplary embodiments may be combined in whole or in part in some or all of the illustrative exemplary embodiments. In addition, one or more of the elements and teachings of the various illustrative exemplary embodiments may be omitted, at least in part, and/or combined, at least in part, with one or more of the other elements and teachings of the various illustrative embodiments. For example, and in one or more exemplary embodiments, the LOD 605 may be present in the DPPMD 173, the SPPMD 392, and the EPMD 450. Additionally, and in one or more exemplary embodiments, the controller 495 may be present in the DPPMD 173, the SPPMD 392, the MPMD 555, and the MPMD 625.
In several exemplary embodiments, while different steps, processes, and procedures are described as appearing as distinct acts, one or more of the steps, one or more of the processes, and/or one or more of the procedures may also be performed in different orders, simultaneously and/or sequentially. In several exemplary embodiments, the steps, processes and/or procedures may be merged into one or more steps, processes and/or procedures. In several exemplary embodiments, one or more of the operational steps in each embodiment may be omitted. Moreover, in some instances, some features of the present disclosure may be employed without a corresponding use of the other features. Moreover, one or more of the above-described embodiments and/or variations may be combined in whole or in part with any one or more of the other above-described embodiments and/or variations.
Thus, a completion assembly has been described. Embodiments of the assembly may generally include an elongated base pipe having an external surface at least partially defining an external region and an internal surface at least partially defining an internal region; and a pressure maintenance device disposed in the base pipe and including a first flow path that extends between an opening in the external surface and an opening in the internal surface; a first valve that controls the flow of a first fluid from the internal region to the external region through the first flow path; a first pressure differential sensor that controls the actuation of the first valve and is in fluid communication with the external region; and a pressurized fluid source in fluid communication with the first pressure differential sensor; wherein a first pressure differential threshold associated with the first pressure differential sensor is the difference between a pressure within the external region and the pressurized fluid source. For any of the foregoing embodiments, the assembly may include any one of the following elements, alone or in combination with each other:
Thus, a method for maintaining an isolated portion of an external region of a completion string within a predetermined pressure range has been described. Embodiments of the method may generally include positioning a completion string that has an internal surface that at least partially defines an internal region and an external surface that at least partially defines an external region within a wellbore; pressurizing a pressurized fluid source located within a pressure maintenance device that is located within a wall of the completion string to a reference pressure that is associated with a wellbore hydrostatic pressure within the external region; isolating a portion of the external region from the wellbore hydrostatic pressure to form the isolated portion of the external region; and allowing a first fluid within the internal region to flow through a first flow path within the pressure maintenance device to the isolated portion of the external region when a pressure differential between the external region and the reference pressure is less than a first pressure differential threshold that is associated with the predetermined pressure range. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
Thus, a method of providing pressure maintenance is described. Embodiments of the method may generally include positioning a completion string within a wellbore, the completion string having an internal surface that at least partially defines an internal region and an external surface that at least partially defines an external region; isolating a portion of the external region from a wellbore hydrostatic pressure; fluidically connecting the internal region to the isolated portion of the external region via a first flow path; providing a first valve that controls the flow of a first fluid through the first flow path, the first valve including a first pressure differential sensor; opening the first valve when the first pressure differential sensor measures a pressure differential between an external pressure within the isolated portion of the external region and a reference pressure that is less than a first pressure threshold; and closing the first valve when the pressure differential between the external pressure and the reference pressure is greater than or equal to the first pressure threshold. For any of the foregoing embodiments, the method may include any one of the following, alone or in combination with each other:
The foregoing description and figures are not drawn to scale, but rather are illustrated to describe various embodiments of the present disclosure in simplistic form. Although various embodiments and methods have been shown and described, the disclosure is not limited to such embodiments and methods and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Accordingly, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the disclosure as defined by the appended claims.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2015/011225 | 1/13/2015 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2016/114765 | 7/21/2016 | WO | A |
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| Number | Date | Country | |
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| 20160356133 A1 | Dec 2016 | US |
