Patent ID: 12203351

DETAILED DESCRIPTION

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 a wellbore system and method for venting free gas that may accumulate below a packer and above a submersible pump. The system may include a hydraulically activated sliding sleeve valve defined in a production tubing string that may be opened selectively and periodically to vent the free gas into the production tubing string.

FIG.1is a schematic view of a wellbore system100that includes an ESP system102in accordance with example embodiments of the present disclosure. The ESP system102is disposed in a wellbore106extending from a surface location “S” and traversing a geologic formation “G.” In the illustrated example, the wellbore106is substantially vertical. In other embodiments, however, aspects of the disclosure may be practiced in a wide variety of vertical, directional, deviated, slanted and/or horizontal portions therein, and may extend along any trajectory through the geologic formation “G.” As illustrated inFIG.1, the wellbore106is lined with a casing string108, however, in other embodiments, the wellbore106may not be cased.

In the example embodiment illustrated, the ESP system102is deployed on a tubing string110such as a production tubing or coiled tubing. An annulus112is defined radially between the tubing string110and the surrounding structure, e.g., the casing string108. The tubing string110extends through an isolation device, such as packer114, which forms a seal with the tubing string110and the surrounding casing string108. The packer114fluidly isolates a lower portion of the annulus112L surrounding the ESP system102from an upper portion112U above the packer114.

The ESP system102includes a submersible pump116and a gas handler118operatively coupled at a lower end of the tubing string110. The submersible pump116may be a multi-stage centrifugal pump that operates by transferring pressure to the wellbore fluids122to draw the wellbore fluids122into the tubing string110and propel the wellbore fluids122to the surface location “S” at a desired pumping rate. The submersible pump116may have any suitable size or construction based on the characteristics, e.g., wellbore size, desired pumping rate, etc., of the wellbore operation for which the submersible pump116is employed. The submersible pump116may operate to transfer pressure to the wellbore fluids122by employing a motor (not shown) operably coupled to one or more impellers (not shown) and diffusers (not shown) as generally recognized in the art.

The gas handler118includes an inlet120submerged in the wellbore fluid122, which may include a gas component122G and a liquid component122L. The wellbore fluid122may include hydrocarbons or other resources that flow into the wellbore106through perforations124formed through the casing string108and into the geologic formation “G.” Where the wellbore fluid122has a relatively high gas-to-liquid ratio, e.g. 20% or more, the gas component122G can interfere with the pumping efficiency of the submersible pump116.

The gas handler118may generally operate to separate the liquid component122L of the wellbore fluid122from the gas component122G. Various types of gas handlers118may be employed in the ESP system102. For example, a static gas separator may slow the flow of wellbore fluid to permit gravity to naturally separate the liquid and gas components122L,G. Dynamic gas separators may employ a centrifuge to radially separate the liquid and gas components. The liquid component122L□ may be delivered to the submersible pump116, which may pump the liquid component122L to the surface location “S” through the tubing string110. It should be appreciated that the liquid component122L pumped to the surface location may still include some gas entrained therein. The gas component122G that is separated by the gas handler118may be exhausted (discharged) into the annulus112through exhaust ports126defined in the gas handler118. The gas component122G exhausted through the exhaust ports126may bubble up through the wellbore fluid122to form a gas pocket130in the annulus112below the packer114.

In some embodiments, the gas handler118may be excluded without departing from the scope of the disclosure. In such embodiments, some separation of the liquid122L and gas components122G may occur as the wellbore fluid122enters an inlet (not shown) to the submersible pump116, and the gas component122G may be discharged to accumulate in the gas pocket130.

The gas pocket130may be defined generally between the packer114and an upper surface of the wellbore fluid122. In other embodiments, the gas pocket130may be defined between a different ceiling and the upper surface of the wellbore fluid122. For example, where a packer114is not provided, the gas pocket130may be defined between a wellhead132and the surface of the wellbore fluid122. Accordingly, the upper limit or “ceiling” of the gas pocket130may be defined by a variety of wellbore structures or devices. As wellbore fluid122is produced, the gas component122G may gradually and progressively accumulate in the gas pocket130, causing the volume of the gas pocket130to increase and otherwise grow downward toward the inlet120of the ESP system102. If the gas pocket130grows to reach the inlet120, the submersible pump116risks undergoing a gas lockup condition, which can adversely affect pump performance.

To release the gas component122G from the gas pocket130, one or more vent ports134is provided in the tubing string110. A sliding sleeve138is provided around the tubing string to selectively close and open the vent ports134. In other embodiments, the sliding sleeve138may be replaced other types of valve closure members capable of occluding and exposing the vent port(s)134, without departing from the scope of the disclosure. In the closed position, as illustrated inFIG.1, the sliding sleeve138covers (occludes) the vent ports134to permit production of the wellbore fluid122through the tubing string110to the wellhead132, while simultaneously preventing the gas within the gas pocket130from migrating into the tubing string110via the vent port(s)134. Moving the sliding sleeve138to an open position, as schematically depicted inFIG.2B, will permit the gas accumulated in the gas pocket130to vent into the tubing string110via the vent port(s)134.

To operate the sliding sleeve138, a hydraulic pump142and an associated controller144are provided at the surface location “S” in the embodiment illustrated inFIG.1. In other embodiments, the hydraulic pump142and/or the controller144may be provided at a downhole location without departing from the scope of the disclosure. The controller144is operably coupled to the hydraulic pump144to provide instructions (command signals) thereto. In some embodiments, the controller144may also be communicatively coupled to a sensor150to receive data therefrom. The sensor150may be disposed in the wellbore106adjacent the inlet120and may provide data regarding the composition or conditions of the wellbore fluid122. In some embodiments, the controller144may be a computer-based system that may include a processor, a memory storage device, and programs and instructions, accessible to the processor for executing the instructions utilizing the data stored in the memory storage device. In other embodiments, the controller144may include manual controls that may be manipulated by an operator to control any of the procedures and equipment described herein.

In some embodiments, the controller144may be operable to provide an alert to an operator that the gas pocket130may be approaching the inlet120. The controller144may determine that the gas pocket130is approaching the inlet based on physical and operational characteristics of the wellbore system such as an available volume in the annulus112, a gas to liquid ratio of a wellbore fluid122and a production rate of the wellbore fluid122. Additionally or alternatively, the controller144may determine that the gas pocket130may be approaching the inlet120based on data provided by the sensor150. In some example embodiments, the controller144may be operably coupled to the submersible pump116to interrupt (stop, cease, etc.) operation of the submersible pump116in the event the controller144determines that the gas pocket130is approaching the inlet120.

As illustrated, the controller144includes an input144A operable to receive variables determinative of the gas pocket130approaching the inlet120. The variables may include a gas to liquid ratio of a wellbore fluid, a production rate of the wellbore fluid and an annulus volume between a ceiling and the inlet120to the ESP system102. The variables may also include a characteristic of the wellbore fluid122provided by the sensor150. The controller includes a logic module144B operable to determine from the variables that the gas pocket130is approaching the inlet120, and further includes an output144C operable to perform at least one function in response to determining that the gas pocket130is approaching the inlet120. These functions may include providing an alert to an operator. For example, the output includes a display operable to provide a visual indication that the gas pocket130is approaching the inlet120. The functions performed by the output144cmay also include interrupting (stopping, ceasing, etc.) operation of the ESP system102and providing instructions to an actuator, e.g., hydraulic pump142to open the vent ports134.

A hydraulic line152extends from the hydraulic pump144into the wellbore106through the wellhead132. The hydraulic line144extends to an actuator154, which may selectively drive the sliding sleeve138between the closed position, where the sliding sleeve138obstructs fluid flow through the vent ports134, and an open position (FIG.2B), where the sliding sleeve138permits fluid flow through the vent ports134.

Referring toFIGS.2A and2B, the wellbore ESP system102is illustrated schematically with the sliding sleeve138in closed and open positions, respectively. As illustrated inFIG.2A, the sliding sleeve138is in a closed position and otherwise occluding the port(s)134. When the sliding sleeve138covers the vent ports134, the liquid component122L of the wellbore fluid122may be produced through production tubing110. The gas component122G and any other free gas around the ESP system102accumulates beneath the packer114to form gas pocket130. The gas pocket130is illustrated as approaching the gas handler118.

Before the gas pocket130reaches the inlet120(FIG.1) of the gas handler118, the sliding sleeve138may be moved to the open position, as illustrated inFIG.2B. Upon moving to the open position, the vent ports134are uncovered (exposed), which permits the gas component122G and any other free gas in the gas pocket130to be vented through the production tubing110. As the free gas within the gas pocket130is vented, the volume of the gas pocket130is reduced and no longer approaches the gas handler118where the free gas may enter the ESP102and induce the gas lockup condition. Rather, the wellbore fluid122may progressively fill the void of the decreasing volume of the gas pocket130.

Referring toFIG.3, and with reference toFIGS.1through2B, an example procedure300is illustrated for venting free gas from the wellbore106. Initially, at step302, a gas to liquid ratio of a wellbore fluid122and a production rate of the wellbore fluid is determined. Estimates for the gas to liquid ratio and the production rate may be estimated empirically or experimentally. A rate of separation of the gas component122G may be calculated from these estimates. Next, at step304, an annulus volume is calculated between a tubing-casing-annulus (TCA) ceiling and an inlet120of ESP system102installed in the wellbore106. The annulus volume represents an available space for free gas to accumulate before the gas pocket130approaches the inlet120. At step306, the duration of a production pumping cycle may be estimated from the annulus volume, production rate and gas to liquid ratio, which will not permit the gas pocket130to extend to the inlet120. The duration estimated in step306represents a threshold duration that the submersible pump116should be operated before venting the free gas.

At step308, the ESP system102is operated to pump the wellbore fluid122to the surface location “S.” As the operation of the ESP system102continues, and as gas starts accumulating within the wellbore106, the volume of the gas pocket130may progressively expand downwardly from the packer114and toward the inlet120of the gas handler118. At step310, the operation of the ESP system102may be interrupted before the expiration of the duration estimated in step306. Moreover, in some embodiments, the operation of the ESP system102may be interrupted before the gas pocket130reaches the inlet120, which could result in a gas lockup condition for the ESP system102.

At step312, the sliding sleeve138is moved (actuated) to the open position (seeFIG.2B) where the vent ports134are uncovered. An operator may manipulate controls of the controller144to move the sliding sleeve138, for example, in response to an alert provided by the controller144that the gas pocket130may be approaching the inlet120. In other embodiments, however, the controller144may be programmed to trigger actuation of the sliding sleeve138upon determining that the gas pocket130is within a predetermined distance of the inlet120. The controller144may instruct the hydraulic pump142to operate to apply a suitable hydraulic pressure on the sliding sleeve138to cause the sliding sleeve138to move to the open position. Moving the sliding sleeve138will permit the gas component122G of the wellbore fluid122and any other free gas accumulating beneath the packer114to be vented through the production tubing110. The volume of the gas pocket130is thereby reduced, and a risk of free gas entering the ESP102and inducing the gas lockup condition is mitigated or entirely prevented.

Once the free gas is vented, the procedure300proceeds to step314where the sliding sleeve138is moved back to the closed position (seeFIG.2A) where the vent ports134are once again covered (occluded). The operator may manipulate controls of the controller144to cause the hydraulic pump142to operate to apply a suitable hydraulic pressure on the sliding sleeve to138to move the move the sliding sleeve138to the closed position. Alternatively or additionally, the controller may instruct the hydraulic pump to operate in response to determining that the gas pocket130has been sufficiently reduced. Moving the sliding sleeve138to the closed position prevents the loss of any of the liquid component122L or other production fluids through the vent ports134.

The procedure300then proceeds to step316where the submersible pump116and any other components of the ESP102may be restarted. Production of the liquid component122L may be continued with a reduced risk of the gas lockup condition occurring.

The procedure300has been described as one example operation in which the sliding sleeve138may be used to vent free gas through the production tubing110. In other embodiments, the sliding sleeve138may be operated in response to a gas lockup condition being detected. The free gas may be vented as part of a troubleshooting and restarting procedure for the ESP system102. In some other embodiments, it may be determined that the gas pocket130is approaching the inlet120by detecting a characteristic of the wellbore fluid122with the sensor150that is indicative of the approaching gas pocket130. For example, the sensor150may detect a gas content of the wellbore fluid122that is above a predetermined threshold. In other embodiments, the free gas may be vented, even if the gas pocket130is not approaching the inlet120, for example when the ESP is not operating for maintenance or any other interruption in production.

Embodiments disclosed herein include:A. A method of producing a wellbore fluid from a wellbore is disclosed and includes operating an electrical submersible pump (ESP) system in a wellbore to draw the wellbore fluid into a tubing string arranged within the wellbore and propel the wellbore fluid toward a surface location, determining that a volume of a gas pocket containing free gas is approaching an inlet of the ESP system, the gas pocket being provided in an annulus around the tubing string, and interrupting operation of the ESP system in response to a determination that the volume of the gas pocket is approaching the inlet. The method may further include opening one or more vent ports defined in the tubing string above the ESP system to vent the free gas from the annulus to an interior of the tubing string while operation of the ESP system is interrupted.B. A system for producing a wellbore fluid from a wellbore is disclosed and includes an electric submersible pump (ESP) system disposed in the wellbore and operable to draw the wellbore fluid into a tubing string arranged within the wellbore and pump the wellbore fluid toward a surface location within the tubing string, a controller operable to determine that a volume of a gas pocket of free gas is approaching an inlet of the ESP system, the gas pocket being provided in an annulus around the tubing string, and one or more vent ports defined between the annulus and an interior of the tubing string. A closure member may be selectively operable to move between a closed position, where the closure member occludes one or more vent ports defined in the tubing string, and an open position, where the closure member is moved to expose the one or more vent ports. The closure member may be moved to the open position in response to the gas pocket approaching the inlet, and the free gas may be vented from the annulus to an interior of the tubing string when the closure member is in the open position.C. A controller for an electric submersible pump (ESP) system in a wellbore is disclosed and may include an input operable to receive variables determinative of a volume of a gas pocket of free gas approaching an inlet to the ESP system, a logic module operable to determine from the variables that the volume of the gas pocket is approaching the inlet, and an output operable to perform at least one of the functions in the group consisting of providing an alert to an operator that the volume of the gas pocket is approaching the inlet, interrupting operation of the ESP in response to determining that the volume of the gas pocket is approaching the inlet and providing instructions to an actuator to open one or more vent ports in response to determining that the volume of the gas pocket is approaching the inlet.

Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein determining that the volume of the gas pocket is approaching the inlet includes determining that a threshold quantity of a gas component of the wellbore fluid has been separated from a liquid component of the wellbore fluid. Element 2: further comprising separating the gas component from the liquid component with a gas handler in the wellbore. Element 3: wherein determining that the volume of the gas pocket is approaching the inlet includes detecting a characteristic of the wellbore fluid indicative of the gas pocket approaching with a sensor arranged adjacent the inlet of the ESP system. Element 4: further comprising providing an alert to an operator in response to determining that the volume of the gas pocket is approaching the inlet. Element 5: wherein opening the one or more vent ports includes longitudinally displacing a sliding sleeve disposed around the tubing string. Element 6: wherein displacing the sliding sleeve includes applying a hydraulic pressure to the sliding sleeve with a hydraulic pump. Element 7: wherein venting the free gas from the annulus includes bypassing a packer installed in the annulus. Element 8: further comprising closing the one or more vent ports subsequent to venting the free gas, and restarting the ESP system to continue producing the wellbore fluid.

Element 9: wherein the ESP system includes a gas handler that provides the inlet and is operable to separate a gas component from a liquid component of the wellbore fluid, and wherein the gas component is discharged as a portion of the free gas accumulating within the gas pocket. Element 10: wherein the ESP system further includes a submersible pump coupled to the gas handler to receive the liquid component of the wellbore fluid from the gas handler. Element 11: further comprising a sensor adjacent the inlet and operable to detect a characteristic of the wellbore fluid indicative of the volume of the gas pocket approaching the inlet. Element 12: wherein the closure member comprises a sliding sleeve disposed around or within the tubing string. Element 13: further comprising a hydraulic pump operably coupled to the sliding sleeve to apply a hydraulic pressure to the sliding sleeve to longitudinally move the sliding sleeve and thereby transition the closure member between the closed and open positions. Element 14: further comprising a packer installed around the tubing string in the annulus and defining a ceiling for the gas pocket. Element 15: wherein the packer is installed above the one or more vent ports.

Element 16: wherein the output includes a display operable to provide a visual indication that the volume of the gas pocket is approaching the inlet. Element 17: wherein the logic module is operable to determine that the volume of the gas pocket is approaching the inlet from the variables including a gas to liquid ratio of a wellbore fluid, a production rate of the wellbore fluid and an annulus volume between a ceiling and the inlet to the ESP system.

By way of non-limiting example, exemplary combinations applicable to A, B, and C include: Element 1 with Element 2; Element 5 with Element 6; Element 9 with Element 10; Element 12 with Element 13; and Element 14 with Element 15.

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.

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.