Patent Grant
11708746
In hydrocarbon well development, it is common practice to use electrical submersible pumping systems (ESPs) as a primary form of artificial lift. A challenge with ESP operations is sand and solids precipitation and deposition on top of the ESP string. In order to reduce the need to remove the ESP from the well to perform well intervention operations downhole, a sand trap device is employed in which the ESP pumps fluid through the sand trap.
During the production phase, a common incident can occur where solids fallback into the ESP stages which can cause the ESP to get stuck or fail. Deposition of solids can result in an increase in ESP trips, failures, and jams. The ESP and equipment downhole must be pulled and reinstalled. Executing ESP pulls and reinstalls can be a costly and time-consuming procedure. Accordingly, there exists a need for a device to control flow direction and prevent solids from falling back into the ESP stages.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In one aspect, embodiments disclosed herein relate to a system comprising: a solids catcher that is centered with respect to a central axis of a tubing and comprising an inner annulus, an outer annulus, and a chamber between the inner annulus and the outer annulus, wherein a solids accumulation zone is formed in the chamber; a pump disposed offset from the central axis of the tubing, wherein the pump is fluidly connected to the solids catcher through the outer annulus; and a fluid stream carrying solids flowing from the pump, wherein the fluid stream carrying solids is configured to follow a path delimited by the outer annulus and the chamber until the fluid stream deposits the solids in the solids accumulation zone and departs the solids catcher via the inner annulus into a tubing.
In one aspect, embodiments disclosed herein relate to a method comprising: installing a tubing in a well, providing an annular space between a casing and the tubing; providing a solids catcher in the annular space in a central axis of the tubing, wherein the solids catcher comprises an inner annulus, outer annulus, and a chamber between the inner annulus and the outer annulus; installing a pump disposed offset from the central axis of the tubing for pumping fluid through the solids catcher; pumping fluid containing solids, via the pump, from the well through a flow path delimited by the outer annulus and the chamber; forming a solids accumulation zone, via the flow path, in the chamber between the pump and the tubing; depositing solids into the solids accumulation zone, via the flow path; and departing the solids catcher, via the inner annulus, into the tubing.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure 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.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
Embodiments disclosed herein relate to a device for catching solids by controlling the direction of flow in a well with solids production.
The ESP string (112) may include a motor (118), motor protectors (120), a gas separator (122), a multi-stage centrifugal pump (124) (herein called a “pump” (124)), and an electrical cable (126). The ESP string (112) may also include various pipe segments of different lengths to connect the components of the ESP string (112). The motor (118) is a downhole submersible motor (118) that provides power to the pump (124). The motor (118) may be a two-pole, three-phase, squirrel-cage induction electric motor (118). The motor's (118) operating voltages, currents, and horsepower ratings may change depending on the requirements of the operation.
The size of the motor (118) is dictated by the amount of power that the pump (124) requires to lift an estimated volume of produced fluids (102) from the bottom of the well (116) to the surface (114). The motor (118) is cooled by the produced fluids (102) passing over the motor housing. The motor (118) is powered by the electrical cable (126). The electrical cable (126) may also provide power to downhole pressure sensors or onboard electronics that may be used for communication. The electrical cable (126) is an electrically conductive cable that is capable of transferring information. The electrical cable (126) transfers energy from the surface equipment (110) to the motor (118). The electrical cable (126) may be a three-phase electric cable that is specially designed for downhole environments. The electrical cable (126) may be clamped to the ESP string (112) in order to limit electrical cable (126) movement in the well (116). In further embodiments, the ESP string (112) may have a hydraulic line that is a conduit for hydraulic fluid. The hydraulic line may act as a sensor to measure downhole parameters such as discharge pressure from the outlet of the pump (124).
Motor protectors (120) are located above (i.e., closer to the surface (114)) the motor (118) in the ESP string (112). The motor protectors (120) are a seal section that houses a thrust bearing. The thrust bearing accommodates axial thrust from the pump (124) such that the motor (118) is protected from axial thrust. The seals isolate the motor (118) from produced fluids (102). The seals further equalize the pressure in the annulus (128) with the pressure in the motor (118). The annulus (128) is the space in the well (116) between the casing string (108) and the ESP string (112). The pump intake (130) is the section of the ESP string (112) where the produced fluids (102) enter the ESP string (112) from the annulus (128).
The pump intake (130) is located above the motor protectors (120) and below the pump (124). The depth of the pump intake (130) is designed based off of the formation (104) pressure, estimated height of produced fluids (102) in the annulus (128), and optimization of pump (124) performance. If the produced fluids (102) have associated gas, then a gas separator (122) may be installed in the ESP string (112) above the pump intake (130) but below the pump (124). The gas separator (122) removes the gas from the produced fluids (102) and injects the gas (depicted as separated gas (132) in
The pump (124) is located above the gas separator (122) and lifts the produced fluids (102) to the surface (114). The pump (124) has a plurality of stages that are stacked upon one another. Each stage contains a rotating impeller and stationary diffuser. As the produced fluids (102) enter each stage, the produced fluids (102) pass through the rotating impeller to be centrifuged radially outward gaining energy in the form of velocity. The produced fluids (102) enter the diffuser, and the velocity is converted into pressure. As the produced fluids (102) pass through each stage, the pressure continually increases until the produced fluids (102) obtain the designated discharge pressure and has sufficient energy to flow to the surface (114).
In other embodiments, sensors may be installed in various locations along the ESP string (112) to gather downhole data such as pump intake volumes, discharge pressures, shaft speeds and positions, and temperatures. The number of stages is determined prior to installation based of the estimated required discharge pressure. Over time, the formation (104) pressure may decrease and the height of the produced fluids (102) in the annulus (128) may decrease. In these cases, the ESP string (112) may be removed and resized. Once the produced fluids (102) reach the surface (114), the produced fluids (102) flow through the wellhead (134) into production equipment (136). The production equipment (136) may be any equipment that can gather or transport the produced fluids (102) such as a pipeline or a tank.
The remainder of the ESP system (100) includes various surface equipment (110) such as electric drives (137), production controller (138), the control module, and an electric power supply (140). The electric power supply (140) provides energy to the motor (118) through the electrical cable (126). The electric power supply (140) may be a commercial power distribution system or a portable power source such as a generator. The production controller (138) is made up of an assortment of intelligent unit-programmable controllers and drives which maintain the proper flow of electricity to the motor (118) such as fixed-frequency switchboards, soft-start controllers, and variable speed controllers. The production controller (138) may be a variable speed drive (VSD), well choke, inflow control valve, and/or sliding sleeves. The production controller (138) is configured to perform automatic well operation adjustments. The electric drives (137) may be variable speed drives which read the downhole data, recorded by the sensors, and may scale back or ramp up the motor (118) speed to optimize the pump (124) efficiency and production rate. The electric drives (137) allow the pump (124) to operate continuously and intermittently or be shut-off in the event of an operational problem.
The solids catcher (200) may include but is not limited one or more paths for produced fluid (102) to flow. The solids catcher (200) may be made of any material capable handling erosion from flowing solids at high velocities and withstanding solid impingement such as stainless steel. The decision of the material of the solids catcher (200) may be affected by economics. Specific to this embodiment, the solids catcher (200) includes an outer annulus (204), an inner annulus (206), and a chamber (208).
The outer annulus (204) may be of tube shape in the outer portion of the solids catcher (200). The outer annulus (204) is symmetric around the well center, while the fluid entrance is offset from the central axis of the tubing and, thus, fluids (102) are only pumped into the solids catcher (200) from one side. The inner annulus (206) may be of tube shape in the inner portion of the solids catcher (200). The chamber (208) may be a containment structure between the outer annulus (204) and the inner annulus (206). The produced fluids (102) may follow a path in the solids catcher (200) delimited by the outer annulus (204) and the chamber (208). The outer annulus (204) may be a structure that allows the produced fluids (102) to flow from the pump (124) into the solids catcher (200). The outer annulus (204) may direct the produced fluids (102) flow to reverse in direction into the chamber (208).
The chamber (208) may produce a solids accumulation zone (210). The solids accumulation zone (210) may allow solids (202) to settle and separate from the produced fluids (102). The solids (202) may fall back into the solids accumulation zone (210). The chamber (208) may direct the produced fluids (102) to reverse in direction from the solids accumulation zone (210) into the inner annulus (204). The inner annulus (206) may allow the produced fluids (102) to depart from the solids catcher (200) and into the production tubing (117). The inner annulus (206) may be of the same circumference as the production tubing (117). The produced fluids (102) may have less solids (202) flowing from the chamber (208). The produced fluids (102) flow may be directed through walls of the solids catcher (200). The walls of the solids catcher (200) may be cylindrical in shape.
Several forms of a cleaning component for a solids catcher (200), in accordance with one or more embodiments, are shown in
In Block 500, the pump (124) is installed offset from the central axis of the tubing. The pump (124) may be part of an artificial lift system. In Block 502, production tubing (117) is installed in the well (116) and the solids catcher (200) with an inner annulus (206), an outer annulus (204), and a chamber (208) is provided in the annular space. The production tubing (117) provides an annular space between the casing string (108) and the production tubing (117). The annular space may be the annulus (128). The solids catcher (200) may have an upper connection and a lower connection in fluid communication with the production tubing (117).
In Block 504, the pump (124) pumps fluid containing solids (202) through a flow path delimited by the outer annulus (204) and the chamber (208). The pump (124) may pump fluid from the lower connection to the upper connection of the solids catcher (200). The fluid may be produced fluid (102) pumped from the well. In Block 506, a solids accumulation zone (210) is formed in the chamber (208) via the flow path. The solids accumulation zone (210) may be between the pump (124) and the production tubing (117). In Block 508, the produced fluid (102) deposits solids (202) into the solids accumulation zone (210) via the flow path. In Block 510, the produced fluid (102) departs the solids catcher (200) through the inner annulus (206) into the production tubing (117).
In Block 512, the solids accumulation zone (210) is cleaned. The solids (202) may be cleaned from the solids accumulation zone (210) by a cleaning component. The cleaning component may include a DCT (300) with a packer (142). The cleaning component may include a venturi junk basket (310) with nitrogen. The solids (202) may be disposed from the solids accumulation zone (210). The pump (124) may then resume pumping fluid containing solids (202) from the well (116) through the solids catcher (200).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
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