Patent Application
20250122784
This invention relates generally to the field of downhole pumping systems, and more particularly, but not by way of limitation, to systems and methods for protecting downhole tubulars and equipment from corrosive gases without impairing the performance of the 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.
A PRIOR ART pumping system 200 is illustrated in
Although effective at mitigating corrosion, the packer 216 frustrates the use of the gas separator 212 because gas expelled by the gas separator 212 is trapped in the annular space below the packer 216. Over time, gas accumulates in the annulus below the packer 216 until it reaches the pump 214 and gas separator 212. The presence of accumulated gas at the intake to the gas separator 212 or pump 214 could create a gas lock condition in which the pump 214 loses prime or fails to function efficiently.
Without the gas separator 212, however, the gas produced by the well 202 is removed through the pumping system 200. The elevated gas fraction of the wellbore fluids reduces the efficiency of the pump 214. There is, therefore, a need for an improved system that mitigates the corrosive effect of hydrogen sulfide gas on downhole tubulars without impairing the efficiency of the pump 214. It is to these and other deficiencies in the prior art that the disclosed embodiments are directed.
In one aspect, the present disclosure is directed to a pumping system deployed in a wellbore for producing two-phase fluids through production tubing to a wellhead, where the wellbore includes an annular space surrounding the pumping system and the production tubing. The pumping system includes a pump, a gas separator upstream from the pump, a packer above the pump, and a gas evacuation module between the pump and the packer. The packer blocks the movement of gases through the annular space and forms a gas collection space between the packer and the pump. The gas evacuation module is configured to remove gas from the gas collection space and mix the gas with liquid-dominant fluids received from the pump. The gas separator includes an intake configured to receive the two-phase fluids, a gas discharge configured to eject gas-dominant fluids into the annular space, and a liquid discharge configured to provide the pump with liquid-dominant fluids.
In another aspect, the present disclosure is directed to a pumping system deployed in a wellbore for producing two-phase fluids through production tubing to a wellhead, where the wellbore includes an annular space surrounding the pumping system and the production tubing. In these embodiments, the pumping system includes a pump and a gas separator upstream from the pump. The gas separator includes an intake configured to receive the two-phase fluids, a gas discharge configured to eject gas-dominant fluids into the annular space, and a liquid discharge configured to provide the pump with liquid-dominant fluids. The pumping system further includes a packer above the pump. The packer forms a gas collection space in the annular space between the packer and the pump. The pumping system also includes a gas evacuation module between the pump and the packer. The gas evacuation module includes a body, an inlet having an inlet diameter, an outlet having an outlet diameter, and a central passage extending through the body. The central passage has a throat between the inlet and the outlet and wherein the throat has a throat diameter that is smaller than the inlet diameter and the outlet diameter. The gas evacuation module further includes one or more gas intake ports that extend through the body to the central passage.
In yet another aspect, the present disclosure is directed to a method for producing two-phase fluids from a wellbore with a pumping system that is connected to production tubing, where the pumping system includes a pump, a gas separator, and a packer positioned above the pump and the gas separator. The method includes the steps of ingesting the two-phase fluids into the gas separator, separating gases from liquids with the gas separator, ejecting gases from the gas separator into an annular space in the wellbore surrounding the pumping system, and providing the pump with liquids separated by the gas separator. The method continues with the steps of allowing the gases in the annular space to collect in a gas collection space below the packer and removing gases from the gas collection space through a gas evacuation module connected to the production tubing.
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 “two-phase” refers to a fluid that includes a mixture of 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” is 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 radial positions within discrete components in the pumping system 100.
The pumping system 100 includes some combination of a pump 108, a motor 110, and a seal section 112. The seal section 112 shields the motor 110 from mechanical thrust produced by the pump 108 and provides for the expansion of motor lubricants during operation. The pump 108 may include two or more separate pumps that are each connected to one another. In exemplary embodiments, the pump 108 is a multistage centrifugal pump that includes a plurality of stages that each include an impeller and a diffuser.
The pumping system 100 also includes a gas separator 114 positioned upstream from the pump 108. The gas separator 114 can be connected between the seal section 112 and the pump 108. The gas separator 114 includes an intake 116, an internal mechanism for separating liquids and gasses, a gas discharge 118, and a liquid discharge 120. Two-phase wellbore fluids are drawn into the intake 116 of the gas separator 114, where the gaseous components are separated from liquid components using paddles, agitators, spiraled flights, or other mechanisms for inducing rotation within the two-phase fluid so that denser liquid-dominant fluids are pulled outward under centrifugal force, while lighter gaseous fluids remain in the central portion of the gas separator 114. The gaseous components can be collected by a crossover and ejected through the gas discharge 118 into an annular space 122 in the wellbore 104, while the liquid components are carried to the pump 108 through the liquid discharge 120. It will be understood that the components of the gas separator 114 may be integrated into the pump 108 rather than presented as a separate component. It will be further understood that in certain embodiments, the pumping system 100 may include multiple gas separators 114, which may be connected together in a tandem configuration or separated by other components within the pumping system 100.
To reduce the impact of corrosive gases on the production tubing 102 and cased wellbore 104, the pumping system 100 includes a packer 124 or other zonal isolation device. The packer 124 is installed in the annular space 122 above the pumping system 100 in the wellbore 104. The packer 124 generally prevents the passage of fluid through the annular space 122, while providing passages for accessories, power cables and the production tubing 102. Gases moving through the annular space 122 below the packer 124 are collected in a gas collection space 126 within the annular space 122 below the packer 124.
The pumping system 100 further includes a gas evacuation module 128. In the embodiment depicted in
Turning to
The gas evacuation module 128 also includes one or more gas intake ports 146. The gas intake ports 146 extend through the body 130 from the throat 138 to the outer surface of the gas evacuation module 128. In the embodiment depicted in
Each gas intake port 146 optionally includes a check valve 148. In some embodiments, the check valves 148 are configured to prevent the discharge of fluids from the gas evacuation module 128 into the annular space 122 through the gas intake ports 146. In other embodiments, the check valves 148 are configured to open when the pressure differential between the annular space 122 and the throat 138 exceeds a threshold valve opening pressure differential. In exemplary embodiments, the threshold valve opening pressure differential is selected by determining the anticipated pressure drop within the throat 138 of the gas evacuation module 128 and the anticipated pressure in the gas collection space 126 when the gas collection space 126 is maintained above the pump 108. In this way, the check valves 148 can be configured to open before the pressure in the gas collection space 126 increases to an extent that the gas collection space 126 displaces enough fluid from the annular space 122 that gas could be drawn into the gas separator 114 or pump 108. In some embodiments, the check valves 148 are configured to prevent liquids from entering the gas evacuation module 128. In other embodiments, the check valves 148 are configured to selectively admit two-phase fluids into the gas evacuation module 128. The check valves 148 can be manufactured according to applicable standards issued by the National Association of Corrosion Engineers (NACE).
During use, liquid-dominant fluids pumped through the gas evacuation module 128 create a low pressure region within the throat 138 that encourages the check valves 148 to open when a sufficient pressure is present in the surrounding gas collection space 126. Once the check valves 148 open, gas accumulated within the gas collection space 126 is drawn into the gas evacuation module 128 through the gas intake ports 146 and mixed within liquid-dominant fluids from the inlet 132. The mixed-phase fluids are then pumped to the surface through the production tubing 102.
In this way, the pumping system 100 provides a system in which gases, including hydrogen sulfide gas, are expelled into the annular space 122 by the gas separator 114 to improve the operational efficiency of the pump 108. The gases move upward through the annular space 122 and collect in the gas collection space 126 under the packer 124. The gases are then drawn out of the gas collection space 126 by the gas evacuation module 128, mixed with liquid-dominant fluid discharged by the pump 108, and moved to the wellhead 106 through the production tubing 102 as a mixed-phase fluid. The pumping system 100 thereby protects a large portion of the production tubing 102 and other downhole equipment from corrosive wellbore gases without sacrificing the operational efficiency of the pump 108, and without increasing the risk of gas locking the pump 108 with the accumulation of gases in the annular space 122 under the packer 124.
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 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.
