Patent Application
20240125216
This invention relates generally to the field of downhole pumping systems, and more particularly to systems and methods for managing gas and liquid slugging events in submersible pumping systems.
Submersible pumping systems are often deployed into wells to recover petroleum fluids from subterranean reservoirs. Typically, a submersible pumping system includes a number of components, including an electric motor coupled to one or more pump assemblies. Production tubing is connected to the pump assemblies to deliver the wellbore fluids from the subterranean reservoir to a storage facility on the surface. In many cases, the pump assemblies are multistage centrifugal pumps that include a plurality of stages, with each stage including a stationary diffuser and a rotary impeller that is connected to a shaft driven by the electric motor.
Wellbore fluids often contain a combination of liquids and gases. Because most downhole pumping equipment is primarily designed to recover liquids, excess amounts of gas in the wellbore fluid can present problems for downhole equipment. For the centrifugal pump to operate, the pump must maintain its “prime,” in which fluid is located in and around the “eye,” or central intake portion, of the first impeller of the pump or gas separator. If, for example, a gas slug moves through the well to the pump intake, the pump may lose its prime and will thereafter be unable to pump liquids while gas remains around the eye of the impeller. The pump can be re-primed by moving fluids to the intake for the first impeller. Once the impeller is provided with a sufficient volume of liquid to displace the trapped gas, the pump will begin pumping against to clear the gas slug through the pump.
While it is known in the art to provide self-priming centrifugal pumps, the re-priming systems can be unreliable and even brief periods of gas lock may result in damage to downhole components in addition to the loss of production. There is, therefore, a continued need for an improved system for preventing a gas locked condition that would require re-the submersible centrifugal pump. It is to these and other deficiencies in the prior art that the disclosed embodiments are directed.
In some embodiments, the present disclosure is directed to a submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, where the pumping system includes a motor and a pump driven by the motor, wherein the pump includes an intake and a discharge. The pumping system also includes an intake fluid density control system that has a control fluid reservoir positioned above the pump and configured to release a density control fluid to the intake of the pump under the force of gravity. In some embodiments, the intake fluid density control system also includes a dump valve and a dump line connected to the dump valve, where the dump line terminates near the intake of the pump.
In other embodiments, the present disclosure is directed to a submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, where the pumping system has a motor and a pump driven by the motor. The pump includes an intake and a discharge connected to the production tubing. The pumping system further includes an intake fluid density control system that includes a density control fluid source, a delivery pump connected to the density control fluid source, and an injection line extending from the delivery pump to the intake of the pump.
In yet other embodiments, the present disclosure is directed to a submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, where the pumping system includes a motor controlled by a motor drive, a pump driven by the motor, and one or more downhole sensors configured to measure conditions at the motor and pump. The pumping system further includes an intake fluid density control system that has a control fluid reservoir positioned above the pump that is configured to release a density control fluid to the intake of the pump under the force of gravity, a dump valve, and a dump line connected to the dump valve, where the dump line directs the density control fluid to pass from the control fluid reservoir to a location at or near the intake of the pump. In these embodiments, the dump valve can include a valve member and an actuator configured to move the valve member between open, closed or intermediate positions in response to a control signal based on measurements made by the downhole sensors or motor drive.
As used herein, the term “petroleum” refers broadly to all mineral hydrocarbons, such as crude oil, gas and combinations of oil and gas. The term “fluid” refers to both liquids, gases or a mixture of liquids and gases, while the term “two-phase” specifically refers to a fluid that includes a mixture of both gases and liquids. It will be appreciated by those of skill in the art that, in the downhole environment, a two-phase fluid may also carry solids and suspensions. Accordingly, as used herein, the term “two-phase” not exclusive of fluids that contain liquids, gases, solids, or other intermediary forms of matter.
For the purposes of the disclosure herein, the terms “upstream” and “downstream” shall be used to refer to the relative positions of components or portions of components with respect to the general flow of fluids produced from the wellbore. “Upstream” refers to a position or component that is passed earlier than a “downstream” position or component as fluid is produced from the wellbore 104. The terms “upstream” and “downstream” are not necessarily dependent on the relative vertical orientation of a component or position.
It will be appreciated that many of the components in the pumping system 100 are substantially cylindrical and have a common longitudinal axis that extends through the center of the elongated cylinder and a radius extending from the longitudinal axis to an outer circumference. Objects and motion may be described in terms of axial, longitudinal, lateral, or radial positions within components in the pumping system 100. Although the pumping system 100 is disclosed in a vertical deployment, it will be appreciated that the pumping system 100 can also be deployed in horizontal and other non-vertical wellbores. The pumping system 100 can be deployed in onshore and offshore applications.
The pumping system 100 includes some combination of a motor 110, a seal section 112, and a pump 114. The motor 110 receives power from a surface-based drive 116 (e.g., a variable speed drive or a variable frequency drive) through one or more power cables 118. Generally, the motor 110 is configured to drive the pump 114 through a series of interconnected shafts (not shown). The seal section 112 shields the motor 110 from mechanical thrust produced by the pump 114 and provides for the expansion of motor lubricants during operation.
In some embodiments, the pump 114 is a turbomachine that uses one or more impellers and diffusers to convert mechanical energy into pressure head. In alternate embodiments, the pump 114 is configured as a positive displacement pump. The pump 114 transfers a portion of this mechanical energy to fluids within the wellbore 104, causing the wellbore fluids to move through the production tubing 102 to the wellhead 106 on the surface. The pump 114 includes an intake 120 and a discharge 122. The intake 120 receives fluids from the wellbore 104 and the discharge is connected to the production tubing 102.
The pumping system 100 also includes an intake fluid density control system 124. The intake fluid density control system 124 is generally configured to supply liquid directly or indirectly to the intake 120 of the pump 114 to control the overall density of fluids being drawn into the pump 114. In the embodiment depicted in
As illustrated in the close-up cross-sectional view in
In the embodiments depicted in
In the variations depicted in
In the variation depicted in
During a gas slugging event, the reduction in pressure around the outside of the control fluid reservoir 126 causes the actuator 148 to move the valve member 146 into an open position, which permits the dump valve 130 to drain the density control fluid from the control fluid reservoir 126 to the pump intake 120 through the dump line 132. In this way, the dump valve 130 can be a pressure-modulated mechanical valve. In other variations, the actuator 148 and valve member 146 can include various combinations of diaphragms, springs and seating elements that are automatically shifted between open, closed and intermediate positions depending on the pressure gradient across the dump valve 130.
In other embodiments, as depicted in the variation of
The control line 150 can be connected to surface-based equipment, like the motor drive 116, or to downhole sensors 152 connected to the pumping system 100. In each case, the dump valve 130 can be manually or automatically changed between binary open and closed states, or proportional intermediate states by sending appropriate control signals through the control line 150. In some embodiments, the downhole sensors 152 are configured to detect the presence of large gas pockets approaching the pump intake 120, which would reduce the pump intake pressure (PIP) measured by the downhole sensors 152. The downhole sensors 152 can be configured to automatically open the dump valve 130 by sending an appropriate “open” signal through the control line 150. Once the pump intake pressure (PIP) has returned to a value within the acceptable operating range, the downhole sensors 152 are configured to close the dump valve 130 by sending an appropriate “close” signal through the control line 150. The downhole sensors 152 can be configured to operate the dump valve 130 based on other measurements, including casing pressure, temperature, and the liquid-to-gas ratio of wellbore fluids approaching the pump intake 120.
In other embodiments, the control signal is generated by the motor drive 116 in response to a change in the operation of the motor 110. For example, the control signal can be generated based on a decrease in power (amperage) drawn by the motor 110 which reflects a lack of liquid inside the pump 114, or an increase in the temperature of the motor 110 which reflects a lack of convective cooling by liquids surrounding the motor 110. It will be appreciated that the dump valve 130 can be controlled using a combination of factors and measurements that are combined to produce the appropriate binary or proportional control signal. For example, the dump valve 130 can be instructed to open when the downhole sensors 152 measure a decrease in the pump intake pressure followed by a decrease in the power drawn by the motor 110.
In each case, the rate at which the density control fluid is delivered to the pump intake 120 by the intake fluid density control system 124 can be modulated based on the amount of gas present or predicted at the pump intake 120. This allows the intake fluid density control system 124 to deliver liquid-rich density control fluid to the pump intake 120 over an extended period, or on a continuous basis, while excess gas is present at the pump intake 120. Unlike prior art systems that attempt to relieve a gas locking condition by re-priming the pump, the intake fluid density control system 124 can be configured to proactively prevent or mitigate the gas locking condition by delivering the density control fluid to the pump intake 120 to increase the overall density of fluid passing through the pump 114.
During use, the control fluid reservoir 126 may collect sediment, sand, or other solid particles that are entrained within the pumped fluid from the production tubing 102. To prevent solid particles from blocking or becoming trapped in the dump valve 130, the control fluid reservoir 126 optionally includes a drain intake 174 that that extends upward into the control fluid reservoir 126 from the dump valve 130 and lower hanger 140.
Turning to
In exemplary embodiments, the pump tap 156 is strategically placed within the pump 114 such that the pressure head available in the fill tube 158 is approximately equal to the static height between the pump tap 156 and the upper portion of the control fluid reservoir 126. As such, once the control fluid reservoir 126 has been filled by the bypass pump fill assembly 154 is configured to fill the control fluid reservoir 126, the force applied by the column of fluid above the pump tap 156 prevents further fluid from being discharged from the pump 114 through the fill tube 158.
If the pump 114 loses prime or becomes inefficient because of excess gas in the pumped fluid, the pressure inside the pump 114 will decrease and will no longer be able to support the weight of the fluid within the fill tube 158 and control fluid reservoir 126. This causes the reverse flow of density control fluid from the control fluid reservoir 126 to enter the pump 114 through the fill tube 158 and pump tap 156. Draining the control fluid reservoir 126 back through the pump 114 can increase the overall density of fluids at the pump intake 120, which can return the pump 114 to normal operation. Once the pump 114 has resumed normal operation and the pressure generated at the pump tap 156 returns to a normal range, the control fluid reservoir 126 is filled again by fluid diverted through the pump tap 156 and fill tube 158. In this way, the bypass pump fill assembly 154 relies on the fill tube 158 and pump tap 156 to both fill and drain the control fluid reservoir 126 without the need for the dedicated fill valve 144 or dump valve 130. In this embodiment, the fill ports 142 may be present or omitted from the reservoir top 144.
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It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. It will be appreciated that concepts from one embodiment can be combined with concepts from another embodiment. For example, it may be desirable to employ the bypass pump fill assembly 154 in combination with the control fluid reservoir 126 that utilizes the packer 162 rather than the upper and lower hangers 138, 140. It will be further appreciated by those skilled in the art that the teachings of the present invention can be applied to other systems without departing from the scope and spirit of the present invention.
