In-well gas abatement apparatus

Abstract

An apparatus for controlling the flow of production fluids in a wellbore, comprises a flow control system designed to regulate the flow of production fluids, minimizing gas slugs and gas accumulation that interfere with the operation of an artificial lift system, a static gas separator positioned below the artificial lift system, configured to separate gas from the liquid phase in the production fluid, a gas storage volume located in an annular space between the well casing and inner tubing, configured to store the gas separated from the fluid by the static gas separator, one or more gas communication orifices positioned in the inner tubing, configured to allow stored gas from the gas storage volume to re-enter the production fluid stream, facilitating the recombination of gas and liquid phases for delivery to the artificial lift system, a pressure drop mechanism integrated into the inner tubing, configured to create a pressure differential that draws gas from the gas storage volume into the production flow through the gas communication orifices, and a well packer positioned between the tubing and the casing, sealing the annular space to prevent movement of the flow control apparatus and providing a defined gas storage area.

Description

[0001] In-Well Gas Abatement Apparatus

[0002] Description

[0003] BACKGROUND

[0004] The invention relates generally to oil wells and, more specifically, to a system and method for controlling flow and gas surges in a well production system.

[0005] Generally, artificial lift systems are used in wellbore applications for pumping production fluids, such as water and petroleum. Insufficient well reservoir pressure can be overcome with artificial lift systems such as electrical submersible pumps, sucker rod pumps, progressive cavity pumps, gas lift, plunger lift, or the like. The function of the pumps is to reduce bottom hole pressure and increase the rate of production.

[0006] The formation of a gas surge or gas slug within a wellbore is intricately influenced by a multitude of fluid and wellbore characteristics. Parameters such as fluid density, viscosity, the ratio of gas to liquid volume, in conjunction with wellbore properties like inclination, tubular dimensions, and overall length collectively orchestrate the dynamics of gas and liquid flow along the wellbore's trajectory. Under specific circumstances, a phenomenon known as gas slugging emerges.

[0007] Gas slugging, a phenomenon of notable importance, finds its prevalence particularly pronounced within elongated horizontal well configurations. This phenomenon gains momentum in scenarios characterized by sluggish fluid velocities and a substantial presence of gas within the fluid stream. Notably, this phenomenon becomes acutely critical in instances where extended horizontal sections manifest undulating profiles, thereby furnishing the optimal milieu for the creation of gas slugs.

[0008] In practice, the genesis of gas slugs is observed to unfold in a manner where gas agglomerates within the upper reaches of the casing, propelling its transit at a pace swifter than that of the accompanying liquid phase. Consequently, this differential velocity grants the gas accumulations an opportunity to coalesce and endure, leading to the manifestation of the distinct gas slug formations.

[0009] While this exposition primarily focuses on the intricacies within horizontal well architectures, the significance of this phenomenon extends beyond such confines. The innovative technology, pivotal to this provisional patent, extends its applicability to an array of wellbore configurations, encompassing vertical and inclined orientations. Furthermore, the technology's versatility seamlessly translates to subsea arrangements, wherein subsea flowlines and risers also stand as potential hosts for its implementation.

[0010] Many of such wells deviate from a straight path in order to enter production zones and follow geological formations that are often within a narrow band. Further, these directionally drilled wells often extend vertically down to reach the depth of the production formation and then extend horizontally along the formation for production of natural gas and oil.

[0011] In such a well configuration, all produced liquids and gases must flow along a substantially horizontal portion of the well to reach a single artificial lift intake location. The gas accumulation is often referred to as a "gas slug" and is known to interfere with the operation of the pump, resulting in reduced production and damage to the pump. For an artificial lift system that includes a single intake passage, all production fluids migrate along the wellbore to reach the intake so that the production fluids can be lifted to the surface. In the case of horizontal wells having a single or multiple individual production zones distributed along the length of the well, production zones located closest to the intake, deliver fluids with less resistance to the artificial lift system. Production zones further away from the intake deliver fluids less effectively because of increased flow resistance between the production zone and the intake. Such drawbacks reduce the production rate and the total recovery of resources from the well.

[0012] Frequently, subterranean wells produce solids with the well fluid which will damage equipment and surfaces with abrasive and erosive wear. In severe cases equipment and surface are enhanced to minimize the damage.

[0013] Venturis are used to inject a liquid or gas into another liquid. Venturis are also used to measure the speed of a fluid, by measuring the pressure changes from one point to another along the venture. A venturi comprises a nozzle and a decreased diameter throat. When fluid flows through the venturi a pressure drop occurs at the throat that is used to suction a liquid or gas from a reservoir. It can also be stated, that a venturi is used to create an area of low pressure in the fluid inlet line that pulls the fluid from the reservoir when fluid flow is initiated.

[0014] There is a desire for a system and method for controlling flow in a well to minimize the gas slugging that allows increased production rates and total recovery involving a solution with no moving parts.

[0015] BRIEF DESCRIPTION

[0016] According to the present invention, there is provided an apparatus according to claim 1.

[0017] The apparatus described resides below an artificial lift system and is designed to abate gas and gas slugs in a well production system. Notably, this apparatus operates without any moving parts.

[0018] In certain embodiments, the apparatus can facilitate chemical treatment of both the apparatus itself and the well volume below the apparatus, ensuring flexibility in well maintenance and treatment processes.

[0019] The gas abatement apparatus can also be applied to free-flowing wells that operate without artificial lift systems, allowing it to function across a range of well types and configurations. Some embodiments include a well packer, a gas separator arrangement, a gas storage volume, and a section designed to reduce pressure. Additionally, they incorporate one or more gas communication orifices for reintroducing stored gas into the fluid flow.

[0020] In some configurations, the apparatus can be used in free-flowing wells, where no artificial lift system is required, extending its application to different types of wells.

[0021] The apparatus is designed with an inner diameter reduction that creates a pressure drop within the tubing, enhancing the separation and reintegration of gas into the fluid flow.

[0022] In certain embodiments, the apparatus features special modifications to the inner diameter reduction that further enhance the pressure drop, improving gas flow control.

[0023] The system may also be equipped with pressure-relieving valves as an alternative to metering orifices, providing additional control over gas and fluid flow in the well.

[0024] In some embodiments, the apparatus can incorporate multiple flow control devices arranged in series, allowing it to handle more complex well architectures or higher flow volumes.

[0025] The apparatus may also include meters and / or sensors to monitor various parameters such as pressure, flow, and temperature. These sensors can be placed inside or outside the tubing and may be used for performance tracking and optimization.

[0026] A solids storage volume may be integrated into the apparatus, designed to capture and store solid materials from the well fluid, preventing damage to the artificial lift system.

[0027] In some configurations, the apparatus may also feature a ball check, flapper valve, relief valve, or similar device to allow captured sand or other solids to be evacuated from the storage volume during well operations or fluid fallback phases.

[0028] In accordance with one exemplary embodiment, a flow control system for a horizontal well production system situated below the artificial lift system which includes a well packer, flow intake including static gas separator, annular gas storage space, and metering gas orifices that can also include features such as venturi to increase differential pressure between annulus and stinger to increase flow volume ingress thru the orifices. The flow control system deploys separately or attached to the submersible pump or any other artificial lift method, including but not limited to sucker rod, PCP, or gas lift. During the normal production of fluid with or without gas, the production fluid enters the wellbore, then travels to the flow control system. A large portion of the entrained gas separates in the static gas separator while entering the flow control device. The more liquid rich fluid enters the inner tubing. The separated gas enters the gas storage volume below the packer and in the annular space between the well casing and inner tubing. A pressure drop occurs inside the inner tubing that may as well be forced by a venturi or another static tool which encourages the stored gas to enter the inner tubing through a single or plurality of orifices in the inner tubing and situated near the packer.

[0029] An alternate embodiment stores solids below the gas separator until the well fluid direction reverses after the artificial lift system stops operating.

[0030] An alternate embodiment would be with pressure relieving valves rather than metering orifices.

[0031] BRIEF DESCRIPTION OF THE DRAWINGS

[0032] Other objects and advantages of the invention may become apparent upon reading the following detailed description and upon reference to the accompanying drawings.

[0033] Figure 1 is a diagram illustrating a typical ESP system.

[0034] Figure 2 is a diagram illustrating a typical ESP system and flow control device.

[0035] Figure 3A is a diagram illustrating an ESP system and flow control device in a horizontal well.

[0036] Figure 3B is a diagram illustrating a horizontal well with gas accumulation.

[0037] Figure 3C is a diagram illustrating a horizontal well with gas blockage.

[0038] Figure 3D is a diagram illustrating a horizontal well with a gas surge.

[0039] Figure 4A is a cross section diagram of the well with the flow control device.

[0040] Figure 4B is a cross section diagram of the flow control device.

[0041] Figure 4C is a cross section diagram of the flow control device with a diameter reducer.

[0042] Figure 4D is a cross section diagram of the flow control device with a venturi inducing feature.

[0043] Figure 4E is a cross section diagram of the flow control device with small diameter piping causing a venturi.

[0044] Figure 4F is a cross section diagram of the flow control device with well fluid flow.

[0045] Figure 4G is a cross section diagram of the flow control device with well fluid and gas flow. Figure 5A is a cross section diagram of the flow control device with a sand cleanout valve.

[0046] Figure 5B is a cross section diagram of the flow control device with a sand cleanout valve during normal production phase.

[0047] Figure 5C is a cross section diagram of the flow control device with a sand cleanout valve during fluid fallback phase.

[0048] DETAILED DESCIPTION OF EXEMPLERARY EMBODIMENTS

[0049] One or more embodiments of the invention are described below. It should be noted that these and any other embodiments described below are exemplary and are intended to be illustrative of the invention rather than limiting.

[0050] Referring to figure 1, there is shown a typical ESP system in a subterranean well. The ESP system 120 is installed inside the wellbore 150 and above the well perforations 140. The downhole ESP system 120 consists of an electric motor 121, seal section 122, and multistage centrifugal pump 123. Power cable 112 conveys power provided by the variable speed drive 110. Power cable 112 connects to the motor 121. Motor 121 rotates the seal section 122 and multistage centrifugal pump 123. Pump 123 pushes the fluid up the production tubing 130.

[0051] Referring to Figure 2, there is shown a typical ESP system with a flow control device. The flow control device 250 resides below the ESP system 220 and is usually above the well perforations 240.

[0052] Referring to Figure 3A, there is shown a cross sectional view of a typical horizontal well with ESP system 320 and flow control device 350. A portion of the horizontal wellbore 360 arches upwards. Fluid 370 flows inside wellbore 340 from the right of the horizontal well towards the ESP system 320.

[0053] Referring to Figure 3B, there is shown a cross sectional view of a typical horizontal well with gas 380 accumulating in the elevated section 360 of the horizontal well. Fluid 370 exiting the reservoir entrains gas 385. The gas 385 migrates towards the upper region of the wellbore 340. The heavier fluid 370 migrates towards the bottom of the horizontal wellbore. Trapped gas 380 accumulates in the elevated section 360 of the horizontal well. Referring to Figure 3C, there is shown a cross sectional view of a typical horizontal well with trapped gas 380 blocking the elevated section 360 of the horizontal well.

[0054] Referring to Figure 3D, there is shown a cross sectional view of a typical horizontal well with a gas surge. Fluid 370 carries a surge 390 of the gas 380 accumulated in the elevated section 360 of the horizontal well. The surge 390 travels to the artificial lift system 320.

[0055] Referring to Figure 4A, there is shown a cross sectional view of a typical well with a flow control device. The flow control device 430 resides inside the well casing 410.

[0056] Referring to Figure 4B, there is shown a cross sectional view of a typical well and flow control device. The flow control device 430 consists of a length of smaller diameter piping 440 attached to a packer 420 above and a length of larger diameter piping 450 below. The bottom end of the larger diameter piping 450 is closed. The insertion of the bottom of smaller diameter pipe 440 into the top of larger diameter pipe 450 create a static gas separator. The packer 420 adheres to the well casing 410 sealing the anulus to force accumulation of gas and prevents movement of the flow control device 430. The smaller diameter piping 440 has a hole or a plurality of holes 445 below the packer 420.

[0057] Referring to Figure 4C, there is shown a cross sectional view of a typical well and flow control device. The flow control device 430 has a reduced inner diameter section 460 to induce a pressure drop inside smaller diameter piping 440.

[0058] Referring to Figure 4D, there is shown a cross sectional view of a typical well and flow control device with a venturi. The flow control device 430 utilizes a reduced diameter section 470 with a single or plurality of cross drilled holes 475. A pressure drop across the reduced diameter section 470 creates a venturi pulling gas and fluid from the volume between the piping 440 outer diameter and the well casing 410 inner diameter to the piping 440 inner diameter.

[0059] Referring to Figure 4E, there is shown a cross sectional view of a typical well and flow control device with a venturi. The flow control device 430 utilizes a reduced diameter piping section 460 with a single or plurality of cross drilled holes 445. A pressure drop across the reduced diameter piping section 460 creates a venturi pulling gas and fluid from the volume between the piping 440 outer diameter and the well casing 410 inner diameter, and the volume between the smaller diameter piping section 460 outer diameter and the well casing 410 inner diameter, to the piping 440 inner diameter. The holes 445 may be located in the smaller diameter piping 460 section 460 and larger diameter piping section 440, or in either location.

[0060] Referring to Figure 4F, there is shown a cross sectional view of a typical well and flow control device with mobilized well fluid. The well fluid 460 encounters the flow control device 430. The close ended larger diameter piping 450 directs the fluid 460 to the annular space between the larger diameter piping 450 outer diameter and the casing 410 inner diameter. The fluid 460 entering the annular space between the smaller diameter piping 440 outer diameter and the larger diameter piping 450 inner diameter reverses direction. The fluid 460 reverses direction again entering the inner diameter of pipe 440 before traveling towards the artificial lift device.

[0061] Referring to Figure 4G, there is shown a cross sectional view of a typical well and flow control device with mobilized well fluid and well gas. The well fluid 460 and gas 470 encounter the flow control device 430. The larger diameter piping 450 directs the fluid 460 and gas 470 to the annular space between the larger diameter piping 450 outer diameter and the casing 410 inner diameter. The fluid 460 and gas 470 enter the static gas separator created by inserting smaller diameter piping 440 inside larger diameter piping 450. Liberated gas 470 travels upwards in the storage space between the casing 410 inner diameter and the smaller diameter piping 440 outer diameter. Fluid entering the smaller diameter piping 440 travels towards the gas injection holes 445. Hydraulic friction inside the smaller diameter piping 440 reduces pressure such that the pressure inside the smaller diameter piping 440 at the level of the orifices 445 is less than the pressure in the annular space between the smaller diameter piping 440 outer diameter and the casing 410 inner diameter. Consequently, gas 480 moves from the storage reservoir between the smaller diameter piping 440 outer diameter and the casing 410 inner diameter through the orifices 445 to the smaller diameter piping 440 inner diameter. The fluid 460 and gas 470 traveling upwards inside of the smaller diameter piping 440 recombines into a homogenous mixture. The fluid 470 inside the smaller diameter piping 440 carries the gas 470 to the artificial lift system.

[0062] The flow control device may be monitored with pressure sensors, flowmeters, and / or temperature sensors inside pipe 440, outside pipe 440, above the flow control device 430, or below the flow control device 430. The configuration can consist of one sensor or meter, or a plurality. The sensors and meters can be discrete points or continuous, such as with fiber optic sensors. The data generated shall be used for performance tracking, optimization, maximizing well production, or to achieve other objectives. Referring to Figure 5A, there is shown a cross sectional view of a typical well and flow control device with a solids storage volume. Below the gas separator 550 within the flow control device 530 resides a solids storage volume 585. A ball check arrangement with a ball 560 and seat 595 are located at the bottom of the solids storage volume 585. A pin 590 stops the ball 565 when the ball check valve opens.

[0063] Referring to Figure 5B, there is shown a cross sectional view of a typical well and flow control device with a solids storage volume during normal well fluid production phase. Fluid 575 entering the bottom of the flow control device 530 forces ball 560 into seat 595. Well fluid 575 and entrained solids 570 located in the annular space between the casing 510 inner diameter and the flow control device 530 outer diameter enters the flow control device 530 depositing the solids 570 in the storage volume 585.

[0064] Referring to Figure 5C, there is shown a cross sectional view of a typical well and flow control device with a solids storage volume during fluid fallback phase after the artificial lift system stops producing well fluid. Ball 565 falls with gravity encountering pin 590 exposing the opening in ball seat 595. Falling well fluid 575 enters the flow control device 530 pushing the solids 570 from the storage volume 585 through the opening in the ball seat 595.

[0065] The embodiment shown in figures 5A to 5C shows a solid treatment feature in addition to the gas treatment feature, however, it should be noted that the solid treat could be implemented without the gas treatment feature; the following configurations are noted:

[0066] Feature 1: An apparatus for controlling the flow of production fluids in a wellbore, comprising: a flow control system designed to regulate the flow of production fluids, minimizing the accumulation of solids that may interfere with the operation of an artificial lift system; a static solids separator positioned below the artificial lift system, configured to separate solid particles from the liquid phase in the production fluid; a solids storage volume located in the flow control device, designed to collect and store the separated solids, preventing the solids from entering the artificial lift system; a discharge mechanism integrated into the solids storage volume, configured to allow for the evacuation of stored solids during specific operational phases, such as during fluid fallback; a well packer positioned between the tubing and the casing, sealing the annular space to prevent movement of the flow control apparatus and providing a defined storage area for solids accumulation.

[0067] Feature 2: The apparatus according to Feature 1, wherein the discharge mechanism comprises a ball check valve, flapper valve, or similar device to facilitate the controlled release of accumulated solids during periods of well fluid reversal or fallback.

[0068] Feature 3: The apparatus according to Feature 1 or 2, further comprising pressure, flow, and / or temperature sensors installed inside or outside the flow control device, configured to monitor the accumulation of solids and the operational performance of the apparatus.

[0069] Feature 4: The apparatus according to any preceding feature, wherein the solids storage volume is designed to handle abrasive and erosive materials, minimizing wear on the artificial lift system and other well components.

[0070] Feature 5: The apparatus according to any preceding feature, further configured for chemical treatment to enhance operational performance and prevent issues such as scaling, corrosion, or solids buildup within the apparatus and wellbore.

[0071] Feature 6: The apparatus according to Feature 5, wherein the chemical treatment is applied to the solids storage volume and the surrounding well volume below the apparatus.

[0072] Feature 7: The apparatus according to any preceding feature, further comprising a gas separation system configured to abate gas accumulation and gas slugs that may interfere with well production.

[0073] Feature 8: The apparatus according to Feature 7, wherein the gas separation system includes a static gas separator positioned below the artificial lift system, separating gas from the production fluid before it reaches the artificial lift system.

[0074] Feature 9: The apparatus according to Feature 7 or 8, wherein the gas separator is connected to a gas storage volume located in an annular space between the well casing and inner tubing, configured to store the separated gas for re-entry into the fluid flow.

[0075] Feature 10: The apparatus according to Feature 9, wherein the apparatus includes a pressure drop mechanism that induces a pressure differential to draw stored gas into the production flow through one or more gas communication orifices in the inner tubing.

Claims

CLAIMS1. An apparatus for controlling the flow of production fluids in a wellbore, comprising: a flow control system designed to regulate the flow of production fluids, minimizing gas slugs and gas accumulation that interfere with the operation of an artificial lift system; a static gas separator positioned below the artificial lift system, configured to separate gas from the liquid phase in the production fluid; a gas storage volume located in an annular space between the well casing and inner tubing, configured to store the gas separated from the fluid by the static gas separator; one or more gas communication orifices positioned in the inner tubing, configured to allow stored gas from the gas storage volume to re-enter the production fluid stream, facilitating the recombination of gas and liquid phases for delivery to the artificial lift system; a pressure drop mechanism integrated into the inner tubing, configured to create a pressure differential that draws gas from the gas storage volume into the production flow through the gas communication orifices; and a well packer positioned between the tubing and the casing, sealing the annular space to prevent movement of the flow control apparatus and providing a defined gas storage area.

2. An apparatus according to claim 1, wherein the apparatus is installed below an artificial lift system.3: The apparatus according to either previous claim 1, wherein the pressure drop mechanism comprises a venturi mechanism or other features configured to create a pressure differential, thereby pulling gas and fluid from the gas storage volume into the inner tubing.4: The apparatus according to claim 3, wherein the venturi mechanism is formed by a section of reduced diameter piping, inducing the pressure drop that increases fluid flow and facilitates gas reentry into the production flow.5: The apparatus according to any previous claim, further comprising a plurality of flow control devices arranged in series to optimize gas abatement and flow control in wells with complex geometries or long horizontal sections.6: The apparatus according to any previous claim, wherein pressure-relieving valves are utilized in place of metering orifices to control gas re-entry into the production flow based on pressure conditions in the annular gas storage volume.7: The apparatus according to any previous claim, further configured to allow chemical treatment of the flow control device and the well volume below the device, to enhance operational performance and prevent issues such as scaling or corrosion.8: The apparatus according to any previous claim, further comprising sensors and meters (including pressure, flow, and / or temperature sensors) installed inside or outside the flow control device for continuous monitoring and optimization of well production.9: The apparatus according to any previous claim, wherein the flow control system includes a solids storage volume designed to collect solids entrained in the well fluid, preventing solids from entering the artificial lift system and causing damage.10: The apparatus according to claim 9, wherein a ball check valve, flapper valve, or similar device is used to facilitate the evacuation of accumulated solids during well fluid fallback phases, preventing solids buildup in the storage volume.

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