Patent Application
20240318529
The present disclosure relates generally to hydrocarbon producing wells and, more particularly, to the management of water production via utilization of flow measurement lines and inflow control device manipulation.
Oil is recovered from subterranean formations via wellbores that penetrate hydrocarbon producing subterranean formations. Operators attempt to maximize hydrocarbon production by drilling and completing wellbores that penetrate multiple producible reservoirs (or production zones). In an effort to accomplish multi-zone production, wellbores may be completed so as to simultaneously produce the greatest amount of hydrocarbons and limit, where possible, the amount of concurrent water production.
In the production of wells penetrating multiple reservoirs, fluid from each production zone is drawn into production tubing extended within the wellbore and flowed to surface. In a multi-zone producing wellbore, it is most efficient to have substantially even flow of fluid from each of the production zones, as uneven drainage may result in undesirable conditions such as water or gas coning. Water coning, for example, will cause an influx of water, which reduces the amount and quality of the produced oil. Similarly, gas coning causes an influx of gas into the wellbore, which may also significantly reduce oil production. Accordingly, it is advantageous to regulate the flow of formation fluids into the production tubing from the various production zones or intervals to minimize the potential of premature water (or gas) breakthrough and thus extend the hydrocarbon production life of the wellbore.
To regulate flow, operators often utilize inflow control devices (ICDs) to provide (or limit) access to multiple production zones in the same well. In order to strategically determine which zones should be accessible (or in the alternative, inaccessible) it is necessary that the operator have an understanding of the fluid type and flow rate of each individual reservoir. Accordingly, operators generally deploy logging tools to enable generation of a well flow profile which is indicative of the respective reservoir fluid phases (i.e., water, oil, and gas) and in-situ flow rates for each discrete reservoir. Based upon this information, the operator may properly determine which zones or reservoirs should be opened or closed. The entirety of the fluid management process, or more particularly, a water production management process, can often be inefficient, time consuming, and as a result, costly.
Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an extensive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.
According to an embodiment consistent with the present disclosure, a well system, may include a completion string operable within a wellbore that penetrates a subterranean formation wherein the completion string may include an inflow control device (ICD) having a flow regulation device. The well system may further include a downhole temporary intervention assembly that may be conveyable into the completion string and may include a downhole shifting device matable with the flow regulation device, a downhole propulsion device operatively coupleable to the downhole shifting device and operable to move the downhole shifting device when mated with the flow regulation device and thereby regulate fluid flow from the subterranean formation, a conveyance operatively coupleable to the downhole propulsion device, and a flow measurement line secured to the conveyance and operable to acquire well data related to the subterranean formation.
According to an embodiment consistent with the present disclosure, a downhole temporary intervention assembly may include a downhole shifting device matable with a flow regulation device of an inflow control device (ICD), the ICD attachable to a completion string arranged within a wellbore that penetrates a subterranean formation, and a flow measurement line securable to the conveyance and operable to acquire well data related to the subterranean formation.
According to an embodiment consistent with the present disclosure, a method may include conveying a downhole temporary intervention assembly into a completion string arranged within a wellbore penetrating a subterranean formation, the completion string including an inflow control device (ICD) with a flow regulation device. The downhole temporary intervention assembly may include a downhole shifting device matable with the flow regulation device, a downhole propulsion device operatively coupled to the downhole shifting device, a conveyance operatively coupled to the downhole propulsion device, and a flow measurement line secured to the conveyance. The method may further include acquiring real-time well data related to the subterranean formation with the flow measurement line.
Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.
Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.
Embodiments in accordance with the present disclosure generally relate to hydrocarbon producing wells and more particularly, to the management of produced water in oil producing wells. This disclosure describes using a particular means of conveyance in oil producing wellbores, comprising multiple producible reservoirs, wherein inflow control devices have been installed. Embodiments described herein discuss using flow measurement monitoring in combination with inflow control device manipulation tools for the purpose of regulating water production. The disclosure describes an efficient method for obtaining necessary information about the wellbore's flow profile, and concurrently using the acquired information to manipulate the appropriate inflow control devices. The embodiments described herein may be particularly beneficial in highly deviated wellbores that traverse numerous reservoirs with varying permeabilities for the specific purpose of regulating flow and/or minimizing water production in multi-reservoir, hydrocarbon (oil) producing wellbores.
A string of production tubing 112 may be positioned within the wellbore 102 and extend from a well surface location (not shown), such as the Earth's surface. The production tubing 112 provides a conduit for fluids extracted from the formation 110 to travel to the well surface location for production. A completion string 114 may be coupled to or otherwise form part of the lower end of the production tubing 112 and arranged within the horizontal section 106. The completion string 114 may include any number of components tailored to the needs of wellbore 102 and the production requirements. Most often, the completion string 114 may be configured to divide the wellbore 102 into various production intervals or producible “zones” adjacent the subterranean formation 110.
The completion string 114 may include one or more inflow control devices or “ICDs” 116 axially offset from each other along portions of the production tubing 112. Each inflow control device 116 may be positioned between a pair of wellbore packers 118. The packers 118 provide a fluid seal between the completion string 114 and the inner walls of the wellbore 102 (e.g., the casing 108 or open hole wellbore 102), and thereby isolate an annulus 120 above and below the respective packer 118. The packers 118 thus serve as mechanical barriers to flow between the discrete production intervals or reservoir zones. As shown in
Each ICD 116 includes a generally cylindrical, hollow body configured to permit fluid flow within its interior body. In some embodiments, flow into (or out of) the body of the ICD is regulated using a flow regulation device (not visible) arranged within the body and actuatable or movable to open or close the ICD. More specifically, the flow regulation device may be actuated to permit the flow of formation fluids 124 from the respective production zone into the interior body of the ICD 116. In some applications, as illustrated, one or more of the ICDs 116 may include a sand control screen assembly 122 (alternatively referred to as “screen 122”) configured to filter particulate matter out of incoming formation fluids 124 originating from the formation 110 such that particulates and other fines are not produced to the well surface location when the ICD 116 is actuated to an open position.
Regulating the flow of fluids 124 into the completion string 114 from each production interval may be advantageous in preventing water coning 126 and/or gas coning 128 within the subterranean formation 110. Other uses for flow regulation include, but are not limited to, balancing production from multiple multi-zone intervals, minimizing production of undesirable fluids and/or reservoir zones, maximizing production of desired fluids and/or reservoir zones, etc.
As used herein, the term “fluid” or “fluids” (e.g., the fluids 124) includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two of more fluids, water and fluids injected from the surface, such as water. Additionally, references to “water” includes fresh water but should also be construed to also include water-based fluids; e.g., brine or salt water.
Over time, as a hydrocarbon/oil well produces, some production zones develop higher water cut ratio (i.e., the ratio of produced water to total produced fluids) and thus such zones may develop water coning 126, which may be undesirable for production when considering the producibility of the entire wellbore 102. This is of particular concern in wellbores enabled by waterdrive (i.e., hydrocarbons pressurized and moved by active, natural aquifers or by water injection wells.) Conversely, in mature fields that employ water flooding as a recovery mechanism, production zones with higher water cut generally have better permeability and a higher reservoir pressure (pore pressure) because they are well connected to the water injector wells. In the event these production zones become isolated or “closed”, the well may cease to produce entirely as the weaker production zones do not have the permeability and/or reservoir pressure to generate the vertical lift necessary to lift (or flow) the production fluids to the surface.
To mitigate either scenario and to balance the flow of fluids from each producible zone, and, more particularly, to manage water production (e.g., water coning 126), operators may selectively operate or actuate the ICDs. Optimum manipulation or operation of the ICDs 116 is crucial to ensure balanced formation fluid 124 flow to the surface, and where possible, to mitigate premature water breakthrough via water coning 126.
In the illustrated embodiment, the flow ports 204 are angularly offset from each other about the circumference of the base pipe 202 and equidistantly spaced from each other. Moreover, the flow ports of 204 are axially aligned on the base pipe 202 at a respective location. In other embodiments, however, one or more of the flow ports in may be axially offset from each other. In one or more further embodiments, the flow ports 204 may comprise a single flow port, without departing from the scope of the disclosure.
The ICD 200 may optionally include a sand control screen assembly 208, which may be the same as or similar to the sand control screen assembly 122 of
The lower end ring 210b may be arranged about the base pipe 202 at or near the flow ports 204 and may define a flow passage 214 configured to receive formation fluids 124 from the surrounding formation 110 and convey (direct) the incoming formation fluids 124 to the flow ports 204 to be received within the interior 206 of the base pipe 202 during production operations.
The sand screen 212 may comprise a filter medium designed to allow fluids to flow therethrough but generally prevent the influx of particulate matter of a predetermined size. In some embodiments, the sand screen 212 may be a fluid-porous, particulate restricting device made from of a plurality of layers of a wire mesh that are diffusion bonded or sintered together to form a fluid porous wire mesh screen. In other embodiments, however, the sand screen 212 may have multiple layers of a weave mesh wire material having uniform pore structure and a controlled pore size that is determined based upon the properties of the formation 110.
As illustrated, the sand screen 212 may be radially offset from the base pipe 202, thereby defining a flow annulus 215 between the base pipe 202 and the sand screen 212. The radial offset may be caused by a plurality of ribs (not shown) that extend longitudinally between the end rings 210a,b and along the outer surface of the base pipe 202. The height or distance between the base pipe 202 and the sand screen 212 largely depends on the height of the ribs.
The ICD 200 may further include a flow regulation device 216 movably disposed within the base pipe 202 at or near the flow ports 204. The flow regulation device 216 may comprise any type of device or mechanism actuatable or movable to selectively allow or prevent the flow of formation fluids 124 into the interior 206 of the base pipe 202 via the flow ports 204. Accordingly, the flow regulation device 216 may be actuatable or otherwise movable to expose or occlude the flow ports 204. In the illustrated embodiment, the flow regulation device 216 is depicted as a sleeve slidably received within a recess 218 defined in the inner radial surface of the base pipe 202. As shown, the recess 218 encompasses the flow ports 204, and the flow regulation device 216 is axially movable within the recess 218 between a first or “open” position, where the flow regulation device 216 exposes the corresponding (adjacent) flow ports 204, and a second or “closed” position, where the flow regulation device 216 occludes the corresponding (adjacent) flow ports 204. The flow regulation device 216 is shown in
In some embodiments, the recess 218 may be omitted and the flow regulation device 216 may instead be arranged against the inner radial surface of the base pipe 202. In such embodiments, the ICD 200 may further include stop shoulders (not shown) defined on the inner radial surface and configured to stop uphole and downhole movement of the flow regulation device 216 when moved.
While the flow regulation device 216 is depicted in
In the example operation, the formation fluids 124 are drawn into the flow annulus 215 and conveyed along the outer circumference of the base pipe 202 into the flow passage 214. When the flow regulation device 216 is in the open position, as shown in
The flow regulation device 216 may be selectively actuatable between the open and closed positions using any type of suitable actuator, actuation system, or mechanism, such as, but not limited to, a mechanical actuator, an electric actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, or any combination thereof. In some embodiments, the flow regulation device 116 may be selectively actuatable to a position between open and closed positions. In the illustrated embodiment, a downhole shifting device 220 is conveyed downhole into the completion string 114 and may be configured to locate the inflow control device 200 to selectively manipulate the flow regulation device 216 between the open and closed positions.
In some embodiments, the downhole shifting device 220 may include or otherwise provide one or more actuatable dogs 222 configured to locate and mate with a profile 224 defined on the flow regulation device 216. The profile 224 may comprise an annular channel or groove defined in the inner radial surface of the flow regulation device 216. Once the dogs 222 are properly mated with the profile, the downhole shifting device 220 may be axially moved to correspondingly move the flow regulation device 216 to the open or closed positions, as described below.
In some embodiments, the downhole shifting device 220 may be axially moved uphole and downhole using a downhole propulsion device 226 conveyed into the completion string 114 with and otherwise attached to a conveyance 228. The conveyance 228 may comprise any type of downhole conveyance including, but not limited to, wireline, slickline, drill pipe, coiled tubing, or any combination thereof. The conveyance 228 may be operatively coupled to an uphole end of the downhole propulsion device 226, and the downhole end of the downhole propulsion device 226 may be operatively coupled to the downhole shifting device 220. As used herein, the term “operatively couple” refers to a direct or indirect coupling engagement between two components. In some embodiments, the downhole propulsion device 226 may be directly coupled to the downhole shifting device 220 at its downhole end. In other embodiments, however, the downhole propulsion device 226 may be indirectly coupled to the downhole shifting device 220 with an adapter 230, such as a length of tubing or the like.
In some embodiments, the downhole propulsion device 226 may comprise a downhole tractor selectively operable to advance the downhole shifting device 220 either downhole or uphole within the completion string 114. With the downhole shifting device 220 mated with the flow regulation device, operating the downhole propulsion device 226 may cause the flow regulation device 216 to open or close, depending on the operational direction of the downhole propulsion device 226. In the illustrated embodiment, the downhole propulsion device 226 includes a plurality of wheels 232 (two shown) mounted to a body of the downhole propulsion device 226 with corresponding arms 234. In some embodiments, the arms 234 may be actuatable and otherwise configured to extend radially outward to direct the wheels 232 into engagement with the inner walls of the completion string 114 (e.g., the inner wall of the base pipe 202). In at least one embodiment, the arms 234 may be spring-loaded, which allows the wheels 232 to dynamically adjust position against varying inner diameters of the completion string 114. In other embodiments, however, the arms 234 may be hydraulically-actuated and capable of being dynamically adjusted to extend the wheels 232 into contact with the adjacent inner walls.
While the downhole propulsion device 226 is shown in
In some embodiments, the conveyance 228 may comprise wireline that is operatively and communicably coupled to the uphole end of the downhole propulsion device 226. The wireline conveyance 228 may be configured to supply the necessary power (e.g., electrical power) to activate (operate) the downhole propulsion device 226. Moreover, the wireline conveyance 228 may also facilitate the transmission of signals and data to the downhole propulsion device 226, which allows a well operator to remotely operate the downhole propulsion device 226 from the well surface.
Highly deviated wellbores, such as those with deviations exceeding 60° to 65°, often limit the ability for a wireline conveyance to advance downhole, since the wireline loses the benefit of gravity and will settle on the low-side of the wellbore 102 (
In the illustrated embodiment, upon entering a deviated portion of the wellbore 102 (
Once powered and activated, the downhole propulsion device 226 self-propels and is able to move the downhole shifting tool 220 throughout the entirety of the completion string 114. To move the flow regulation device 216 to the closed position, the downhole propulsion device 226 may be operated to adjust the position of the downhole shifting device 220 until engagement with the profile 224 of the flow regulation device 216. Once the profile 224 is located, the dogs 222 may be actuated to mate with the profile 224. In at least one embodiment, however, the dogs 222 may be spring-loaded and naturally biased radially outward. In such embodiments, the dogs 222 will automatically expand radially outward upon locating the profile 224.
Once the downhole shifting device 220 is properly mated with the flow regulation device 216, an uphole axial load may be applied on the downhole shifting device 220. In some embodiments, the uphole axial load may be provided through the wireline conveyance 228, but could alternatively be provided with the downhole propulsion device 226. The resulting axial load may be transmitted to the flow regulation device 216, thereby resulting in the uphole sliding movement of the flow regulation device 216. The flow regulation device 216 may be moved uphole until occluding the flow ports 204.
It should be noted that while
In conventional water production management operations, and prior to actuating any installed inflow control devices, it is often desired to log the wellbore using production logging tools (PLT). In deploying PLTs, the operator will be able to acquire valuable data and metrics from the respective reservoir zones including, but not limited to, temperature and vibration, which may be indicative of active or potential water breakthrough or water coning 126 (
Often the PLTs are conveyed into the wellbore by means of electrical wireline (“e-line”) or coiled tubing. Such operations may require multiple runs and more particularly, will not be performed in the same run or conveyance utilized to actuate the ICDs. Multiple runs and utilization of varying means of conveyance (e.g. wireline/e-line and/or coiled tubing) can be costly and result in delayed actuation of flow control devices. Accordingly, delayed actuation of the inflow control devices may result in both cost and detrimental effects to hydrocarbon production.
According to the embodiments of the present disclosure, a flow measurement line 236 (shown in dashed lines) may be run along and otherwise secured to the conveyance 228 and may be configured to acquire real-time well data related to the reservoir water production (e.g., temperature and acoustics). In some embodiments, the flow measurement line 236 may comprise a fiber optic line that may enable distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) capabilities by detecting and transmitting continuous, real-time temperatures and acoustic measurements as the downhole propulsion device 226 moves within the wellbore 102 (
In some embodiments, the flow measurement line 236 comprises a fiber optic cable embedded within the conveyance 228. In the present example, the fiber optic cable is embedded within a wireline conveyance cable and is extendable from a surface control unit or control system jointly with the wireline conveyance cable. In other embodiments, however the flow measurement line 236 may be secured to the exterior of the conveyance 228. Moreover, in at least one embodiment, both the conveyance 228 and the flow measurement line 236 may be communicably and operatively coupled to the downhole propulsion device 226. Accordingly, a well operator may be able to communicate with the downhole propulsion device 226 via either the conveyance 228 or the flow measurement line 236, or both.
In some embodiments, as the downhole propulsion device 226 conveys the downhole shifting device 220 within the completion string 114 and toward the distal end of the wellbore 102 (
Accordingly, including the flow measurement line 236 in the downhole temporary intervention assembly 238 may prove advantageous in allowing a well operator to acquire sensitive downhole data in the same downhole run where the downhole shifting device 220 is used to manipulate the position of the flow regulation device 216. More specifically, combining the downhole propulsion device 226 and the flow measurement line 236 in a combined operation undertaken by the downhole temporary intervention assembly 238 enables the operator to simultaneously obtain real-time well data and selectively operate the ICD 200 in a much timelier and cost effective manner than conventional operations permit. Moreover, utilization of the flow measurement line 236 eliminates the need for PLTs and an additional run to actuate the ICD 200, since the flow measurement line 236 is capable of providing the operator with real-time reliable data that may identify water influx zones (e.g., water coning of
Closing the flow regulation device 216 can be accomplished by first locating the flow regulation device 216 with the downhole shifting device 220. The downhole propulsion device 226 may be operated to move the downhole shifting device 220 until the dogs 222 are able to mate with the profile 224 defined in the flow regulation device 216. Once the downhole shifting device 220 is properly mated to the flow regulation device 216, an uphole axial load (i.e., to the left in
If it is subsequently desired to re-open the flow regulation device, the downhole propulsion device 226 may again be operated to mate the downhole shifting device 220 with the flow regulation device 216. A downhole axial load (i.e., to the right in
The method 400 may further include acquiring real-time well data related to the subterranean formation with the flow measurement line, as at 404. The well data may be acquired via the flow measurement line, which may exhibit distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) capabilities. The method 400 may then further include detecting an influx of water with the flow measurement line, as at 406.
Upon detecting water influx, the operator may determine it desirable to move/actuate the flow regulation device for the ICD to thereby minimize the water influx. Accordingly, the method 400 may also include mating the downhole shifting device with the flow regulation device of the ICD, as at 408. The method 400 may include actuating the flow regulation device to regulate the influx of water through the flow regulation device, as at 410. The method 400 may include monitoring and identifying any changes in flow after actuating the flow regulation device, as at 412.
The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including.” “comprises”, and/or “comprising.” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
Terms of orientation are used herein merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.
The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.
While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.
