Integrated pressure barrier-related completion system for gas-lift wells

Abstract

A gas-lift system comprises a surface and sub-surface pressure barrier system, a plurality of surface sensors and sub-surface sensors, and an automated gas-lift manager. The plurality of surface sensors are coupled to the surface pressure barrier system and the plurality of sub-surface sensors are coupled to the sub-surface pressure barrier system. The automated gas-lift manager is coupled to the surface pressure barrier system, the sub-surface pressure barrier system, the plurality of surface sensors, and the plurality of sub-surface sensors, wherein the automated gas-lift manager is configured to monitor and control the surface pressure barrier system and the sub-surface pressure barrier system based on data received from the plurality of surface sensors and the plurality of sub-surface sensors.

Description

BACKGROUND

[0001] Hydrocarbons are located in porous rock formations beneath the Earth's surface. Wells are drilled into these formations to access and produce the hydrocarbons. Wells are completed in a myriad of ways, depending on many factors like reservoir pressure. In certain scenarios, the reservoir pressure is insufficient to allow formation fluids to naturally flow to the surface. Gas-lift is a completion scheme that may be used to help produce formation fluids in these scenarios. Gas-lift wells use a gas, such as natural gas, to lift the formation fluids to the surface. Specifically, the gas is pumped into the production tubing of the well to mix with the formation fluids. This mixture reduces the density of the formation fluids to a point where the reservoir pressure is sufficient to flow the formation fluids to the surface. Ensuring sufficient pressure barriers is an inherent component of any oil and gas operation, but doing so for gas-lift wells is of the utmost importance due to the complexity of the completion design and the presence of multiple, distinct fluid flows.SUMMARY

[0002] 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.

[0003] This disclosure presents, in accordance with one or more embodiments methods and systems for monitoring and controlling a gas-lift system for a well having production tubing configured to convey production fluids to a surface location. The gas-lift system comprises a surface and sub-surface pressure barrier system, a plurality of surface sensors and sub-surface sensors, and an automated gas-lift manager. The surface pressure barrier system comprises a gas pump configured to pump a gas into an annulus of the well, a surface annular safety valve located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead, and a surface actuation system coupled to and configured to actuate the gas pump and the surface annular safety valve. The sub-surface pressure barrier system comprises a downhole gas injection valve configured to actuate to allow or prevent the gas from entering the production tubing to mix with the production fluids to lower a density of the production fluids, a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, and a sub-surface actuation system coupled to and configured to actuate the downhole gas injection valve and the sub-surface safety valve. The plurality of surface sensors are coupled to the surface pressure barrier system and the plurality of sub-surface sensors are coupled to the sub-surface pressure barrier system. The automated gas-lift manager is coupled to the surface pressure barrier system, the sub-surface pressure barrier system, the plurality of surface sensors, and the plurality of sub-surface sensors, wherein the automated gas-lift manager is configured to monitor and control the surface pressure barrier system and the sub-surface pressure barrier system based on data received from the plurality of surface sensors and the plurality of sub-surface sensors.

[0004] The method includes pumping a gas from the surface location into an annulus of the well using a gas pump; opening a downhole gas injection valve to allow the gas to enter the production tubing from the annulus of the well; mixing the gas with the production fluids to lower a density of the production fluids and allow the production fluids to flow to the surface location using the production tubing; monitoring the gas-lift system using a plurality of surface sensors coupled to a surface pressure barrier system and a plurality of sub-surface sensors coupled to a sub-surface pressure barrier system, wherein data is sent from the plurality of surface sensors and the plurality of sub-surface sensors to an automated gas-lift manager; detecting, using the automated gas-lift manager, an incident in the gas-lift system using the data from the plurality of surface sensors and the plurality of sub-surface sensors; and sending a command signal from the automated gas-lift manager to a surface actuation system in the surface pressure barrier system or to a sub-surface actuation system in the sub-surface pressure barrier system to perform one or more functionalities based on the detection of the incident. The functionalities comprise turning off the gas pump, using the surface actuation system, to prevent the gas from being pumped into the well, closing a surface annular safety valve, using the surface actuation system, to prevent the production fluids from migrating through an annulus of a wellhead capping the well, and closing a sub-surface safety valve, using the sub-surface actuation system, to prevent the production fluids from flowing to the wellhead.

[0005] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0006] 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.

[0007] FIG. 1 shows a gate valve pressure barrier system that is conventionally used as a barrier system for gas-lift wells in accordance with one or more embodiments.

[0008] FIG. 2 shows a gas-lift system for a well having an integrated and automated pressure barrier system in accordance with one or more embodiments.

[0009] FIG. 3 shows a schematic diagram in accordance with one or more embodiments.

[0010] FIG. 4 shows the computer system in accordance with one or more embodiments.

[0011] FIG. 5 shows a flowchart in accordance with one or more embodiments.DETAILED DESCRIPTION

[0012] 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.

[0013] 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.

[0014] Gas-lift well completion operations face significant challenges in ensuring safety, integrity, and environmental protection, especially in demanding environments such as offshore, high-pressure, and sour gas fields. The primary problem addressed by the present disclosure is the need for a comprehensive and fail-safe pressure barrier system that can effectively isolate hydrocarbon gases from the surface. It is important to have a sufficient barrier system that can prevent leakage and environmental contamination while ensuring the safety of the crew and equipment.

[0015] Current well completion practices in gas-lift operations often rely on a combination of valves and personnel monitoring systems to maintain well integrity. FIG. 1 shows a gate valve pressure barrier system 100 that is conventionally used as a barrier system for gas-lift wells in accordance with one or more embodiments.

[0016] Specifically, FIG. 1 shows a wellhead 102 capping a wellbore (not pictured) drilled into the surface of the Earth. A gas line 104 is connected to the wellhead 102. The gas line 104 is transporting a gas to the wellhead 102 to be used for gas-lift operations. The gas line 104 is equipped with a proximate manual gate valve 106 and a distal manual gate valve 108. The proximate manual gate valve 106 is located closest to the wellhead 102 and the distal manual gate valve 108 is located furthest from the wellhead 102, when compared to one another. The proximate manual gate valve 106 and the distal manual gate valve 108 are used to shut off the flow of the gas from the gas line 104 into the wellhead 102.

[0017] In accordance with one or more embodiments, two manual gate valves are provided to create redundancy in case one fails. The proximate manual gate valve 106 and the distal manual gate valve 108 are operated manually. Thus, when an emergency occurs, the gate valve pressure barrier system 100 relies on human detection and reaction. Consequentially, the gate valve pressure barrier system 100 is not only labor-intensive but also prevent emergencies from being timely addressed and mitigated. Even with two manual valves, a single point of failure exists in situations in which both are left open due to human error, or both fail to close properly when the combined operating system fails. Furthermore, the gate valve pressure barrier system 100 does not provide real-time monitoring of well conditions.

[0018] Beyond the deficiencies listed above, gate valve pressure barrier systems 100 have other limitations. For example, gate valve pressure barrier systems 100 are not designed to withstand impacts from dropped objects, which are a common hazard in offshore operations. This can lead to breaches in the well's containment, posing risks to both personnel and the environment. Furthermore, existing gate valve pressure barrier systems 100 are not always rated for the extreme pressures and environments encountered in high-pressure and sour gas fields. Over time, wear and tear or exposure to corrosive gases can lead to failures, risking uncontrolled releases of hydrocarbons.

[0019] Thus, many gate valve pressure barrier systems 100 require frequent surveillance and well interventions to monitor for and address potential leakages. These operations are not only costly but also increase the risk to personnel and extend the downtime of the well, impacting productivity. Moreover, integrating various components into a cohesive system that can maintain integrity under all operational conditions is often challenging with gate valve pressure barrier systems 100. Components from different manufacturers may have compatibility issues, leading to weak points in the system.

[0020] For all the reasons listed above, the gate valve pressure barrier system's 100 ability to prevent environment and safety incidents is limited. Thus, gas-lift pressure barrier systems and methods that address these limitations are beneficial. As such, the present disclosure outlines an integrated pressure barrier system for wells 202 having a gas-lift system 200.

[0021] This system is designed to provide a comprehensive solution to well integrity issues by ensuring all components, including surface annular valves, pressure / temperature sensors, packers, gas-lift valves, and orifice valves, are rated for the highest anticipated pressures and external impacts, minimizing the risk of containment loss. This system also reduces the need for well intervention and in-person surveillance through the use of remote monitoring and usage of robust, fail-safe components that offer long-term reliability without frequent maintenance. The system also offers a fully integrated solution that ensures compatibility and seamless operation among all components, enhancing the overall safety and efficiency of gas-lift operations.

[0022] FIG. 2 shows a gas-lift system 200 for a well 202 having an integrated and automated pressure barrier system in accordance with one or more embodiments. A person skilled in the art will appreciate the well 202 shown in FIG. 2 is shown for example purposes only and variations of the well schematic, well structure, well trajectory, completion scheme, etc. may be used without departing from the scope of the disclosure herein.

[0023] The well 202 shown in FIG. 2 has a wellbore 204 drilled into the surface 206 of the Earth. The wellbore 204 traverses a reservoir 208 containing production fluids 210. The production fluids 210 may be any type of fluid known in the art, such as hydrocarbons, water, brine, fluid remnants from drilling / completing the well, frac fluid remnants, or a mixture therein.

[0024] A casing string 212 extends from the surface 206 and is disposed and cemented within the wellbore 204. The casing string 212 is housed in a wellhead 102 at the surface 206. A liner 214 is hung within the casing string 212 and extends to a depth in the wellbore 204 downhole from the casing string 212.

[0025] Production tubing 216 is disposed inside of the casing string 212 and the liner 214. The production tubing 216 extends from the surface 206 and ends at a predetermined depth within the liner 214. In accordance with one or more embodiments, the depth of the production tubing 216 depends on the calculated height of the production fluids 210 within the interior of the well 202 throughout the life of the well 202. For example, the production tubing 216 may extend to the depth of the lowest conceivable depth of production fluids 210 within the interior of the well 202.

[0026] The casing string 212, the liner 214, and the production tubing 216 are made of one or more tubulars threaded, or otherwise connected, together. The tubulars may be made out of any material known in the art, such as carbon steel, corrosion resistant alloys, etc. The liner 214 may be hung within the casing string 212 using a liner hanger (not pictured) and a packer (not pictured). The production tubing 216 may include various equipment associated with production, such as sub-surface sensors 218.

[0027] An annulus 220 is shown as the space between an outer circumferential surface of the production tubing 216 and an inner circumferential surface of the casing string 212 and the liner 214. A production packer 222 is disposed in the annulus 220 between the production tubing 216 and the liner 214. In accordance with one or more embodiments, the production packer 222 is located on a downhole end of the production tubing 216.

[0028] The production packer 222 prevents the production fluids 210 from migrating in an up hole direction from a location downhole from the production packer 222 to a location up hole from the production packer 222. The production packer 222 may be any type of packer known in the art such as a hydraulic or mechanical packer. The sub-surface sensors 218 may be located anywhere along the production tubing 216, such as up hole or downhole from the production packer 222.

[0029] The production fluid 210 is configured to flow from the reservoir 208 into the liner 214 through perforations 224 created in the liner 214, or through an exposed, unlined portion of the wellbore 204. The production fluid 210 flows from the liner 214 into the production tubing 216.

[0030] The production tubing 216 is configured to transport the production fluid 210 to the surface 206. However, the production fluid 210 may be too heavy to naturally flow to the surface 206 using reservoir 208 pressure. As such, the well 202 is completed with a gas-lift production scheme to enable production of the production fluids.

[0031] The gas-lift production scheme includes a combination of surface equipment and downhole equipment that work together to operate the gas-lift system 200 and to provide a pressure barrier. The surface equipment includes a gas source 226, a gas pump 228, a gas line 104, a surface annular safety valve 230, a surface gas injection valve 232, a proximate manual gate valve 106, a production tank 234, and surface sensors 236. The downhole equipment includes a SSSV 238, the sub-surface sensors 218, the production packer 222, and a downhole gas injection valve 240.

[0032] The gas-lift system 200 can be remotely monitored and automatically controlled using an automated gas-lift manager 242. The automated gas-lift manager 242 receives inputs 244, such as data, from the gas-lift system 200 and sends outputs 246, such as commands, to the gas-lift system 200. The automated gas-lift manager 242 is outlined in further detail in FIG. 3.

[0033] Generally, the gas-lift system 200 operates as follows. A gas 248 is pumped from the gas source 226, via the gas pump 228, into the wellhead 102. The gas 248 is pumped from the wellhead 102 into the annulus 220. The downhole gas injection valve 240 is used to allow the gas 248 to enter the production tubing 216 to mix with the production fluids 210. The gas 248 mixes with the production fluids 210 to lower the density of the production fluids 210 to a level such that the reservoir 208 pressure is sufficient to allow the production fluids 210 to flow to the surface 206. At the surface 206, the production fluids 210 flow out of the wellhead 102 to a production tank 234.

[0034] The gas 248 may be any type of gas that may be used in a gas-lift operations, such as associated gas, natural gas, etc. The gas source 226 may be any type of gas source known in the art. For example, the gas source 226 may be an accumulation of associated gas that is produced with the production fluids 210. The gas source 226 may also be additional gas that is transported to the wellsite, for example in situations where the volume of associated gas is not sufficient to keep up with the production operation.

[0035] The gas pump 228 may be any type of pump known in the art, such as a displacement pump, a reciprocating pump, a centrifugal pump, etc. The gas pump 228 may be powered using any means known in the art, such as solar power, electric power, diesel-generated power, etc. The gas line 104 is used to transport gas 248 from the gas source 226 to the gas pump 228 and from the gas pump 228 to the wellhead 102.

[0036] The surface gas injection valve 232 is disposed along the gas line 104 and is used to control the gas 248 flow into the wellhead 102. The surface gas injection valve 232 may be operated using a hydraulic actuation system or an electronic actuation system.

[0037] The surface annular safety valve 230 is disposed within the valve removal profile of the wellhead 102. That is, the surface annular safety valve 230 is disposed directly within the wellhead 102. In accordance with one or more embodiments, the surface annular safety valve 230 is operated using a hydraulic actuation system or an electronic actuation system. When the surface annular safety valve 230 is closed, the surface annular safety valve 230 prevents fluids from flowing through an annulus of the wellhead 102.

[0038] The SSSV 238 is located along the production tubing 216 within the casing string 212. In accordance with one or more embodiments, the SSSV 238 is located proximate an up-hole end of the production tubing 216. The SSSV 238 may be operated using a hydraulic actuation system or an electronic actuation system. The SSSV 238 is closed to prevent the production fluids 210 from flowing through the production tubing 216 to the wellhead 102.

[0039] The downhole gas injection valve 240 is located along the production tubing 216, preferably at a location in the production tubing 216 that will be submerged in the production fluids 210 when the production fluids 210 are unable to flow. In accordance with one or more embodiments, there may be multiple downhole gas injection valves 240 located at different depths within the production tubing 216 based on the varying heights of the production fluids 210 over the life of the well 202.

[0040] The downhole gas injection valve 240 may be operated using a hydraulic actuation system or an electronic actuation system. In other embodiments, the downhole gas injection valve 240 will automatically open based on pre-determined pressures seen in the wellbore 204. When the downhole gas injection valve 240 opens, the gas 248 is able to flow from the annulus 220 into the production tubing 216 to mix with the production fluid 210.

[0041] FIG. 3 shows a schematic diagram in accordance with one or more embodiments. Components shown in FIG. 3 that are the same as or similar to components shown in FIGS. 1 and 2 have not be re-described for purposes of readability and have the same description and function as outlined above.

[0042] FIG. 3 illustrates the gas-lift system 200 that may include the automated gas-lift manager 242 coupled to one or more user devices 300, surface sensors 236, sub-surface sensors 218, a surface pressure barrier system 302, and a sub-surface pressure barrier system 304. The automated gas-lift manager 242 may include hardware and / or software that includes functionality for monitoring and / or controlling the gas-lift system 200.

[0043] In accordance with one or more embodiments, the surface pressure barrier system 302 includes a surface actuation system 306 coupled to one or more gas pumps 228, the surface annular safety valve 230, and one or more surface gas injection valves 232. The surface actuation system 306 may have one or more sub-systems that are coupled to each component. Furthermore, the surface actuation system 306 may be a hydraulic actuation system, an electronic actuation system, or a combination thereof without departing from the scope of the disclosure herein.

[0044] In accordance with one or more embodiments, the sub-surface pressure barrier system 304 includes a sub-surface actuation system 308 coupled to the SSSV 238 and one or more downhole gas injection valves 240. The sub-surface actuation system 308 may have one or more sub-systems that are coupled to each component. The sub-surface actuation system 308 may be wholly located downhole or may be located on the surface 206 and extend downhole. The sub-surface actuation system 308 may be a hydraulic actuation system, an electronic actuation system, or a combination thereof without departing from the scope of the disclosure herein.

[0045] In accordance with one or more embodiments, the automated gas-lift manager 242 transmits one or more commands (e.g., surface safety command 310 and sub-surface safety command 312) to various control systems (e.g., the surface actuation system 306 located within the surface pressure barrier system 302, or the sub-surface actuation system 308 located within the sub-surface pressure barrier system 304.

[0046] The commands may include data messages transmitted over one or more network protocols using a network interface, such as through wireless data packets. Likewise, the commands may also be a control signal, such as an analog electrical signal that triggers one or more operations in a particular control system.

[0047] In accordance with one or more embodiments, the automated gas-lift manager 242 may transmit a surface safety command 310 to the surface actuation system 306 located within the surface pressure barrier system 302 instructing the system to actuate the gas pump 228, the surface annular safety valve 230, or the surface gas injection valve 232.

[0048] In accordance with one or more embodiments, the automated gas-lift manager 242 may transmit a sub-surface safety command 312 to the sub-surface actuation system 308 located within sub-surface pressure barrier system 304 instructing the system to actuate the SSSV 238 or the downhole gas injection valve 240.

[0049] In accordance with one or more embodiments, the surface safety command 310 and the sub-surface safety command 312 may be the outputs 246 shown in FIG. 2 that are transmitted from the automated gas-lift manager 242 to the gas-lift system 200. Which command and the specific actuation instruction within the command is based on an operation analysis of the gas-lift system 200 performed by the automated gas-lift manager 242.

[0050] In accordance with one or more embodiments, the automated gas-lift manager 242 performs this operation analysis using pressure and temperature data 314, flow rate data 316, atmospheric gas concentration data 318, and valve position data 320 received from the surface sensors 236 and the sub-surface sensors 218. In accordance with one or more embodiments, the automated gas-lift manager 242 uses this data to make decision on the operation of the gas-lift operation, such as adjusting the gas 248 injection rate to optimize production fluid 210 production.

[0051] The automated gas-lift manager 242 uses this data to determine if an incident is occurring. When an incident is detected, the automated gas-lift manager 242 may automatically send the surface safety command 310 or the sub-surface safety command 312 to actuate the surface pressure barrier system 302 and / or the sub-surface pressure barrier system 304, depending on the location and cause of the incident.

[0052] In accordance with one or more embodiments, the surface sensors 236 include a gas inlet pressure and temperature sensor 322, a production fluid outlet pressure and temperature sensor 324, an annular safety valve position sensor 326, a gas inlet flowmeter 328, a production fluid outlet flowmeter 330, an atmospheric gas concentration sensor 332, a surface gas injection valve position sensor 334, and a proximate manual gate valve position sensor 336.

[0053] The gas inlet pressure and temperature sensor 322 is located along the gas line 104, preferably at the inlet where the gas 248 enters the wellhead 102. The gas inlet pressure and temperature sensor 322 records and sends pressure and temperature data of the gas 248 within the gas line 104 to the automated gas-lift manager 242. This data from the gas inlet pressure and temperature sensor 322 is considered part of the pressure and temperature data 314 the automated gas-lift manager 242 uses to perform the operation analysis.

[0054] For example, the automated gas-lift manager 242 may monitor the value of the pressure and temperature readings from the gas inlet pressure and temperature sensor 322 and compare them to the operational parameters of the gas-lift system 200. If the value of the pressure and temperature readings from the gas inlet pressure and temperature sensor 322 exceed the operational parameters, the automated gas-lift manager 242 may send the surface safety command 310 and / or the sub-surface safety command 312 to perform a particular functionality to control the gas-lift operation, such as shutting down the gas-lift operation.

[0055] The production fluid outlet pressure and temperature sensor 324 is located at the outlet of the wellhead 102 where the production fluids 210 exit the wellhead 102 to flow to the production tank 234. The production fluid outlet pressure and temperature sensor 324 records and sends pressure and temperature data of the production fluids 210 exiting the wellhead 102 to the automated gas-lift manager 242. This data from the production fluid outlet pressure and temperature sensor 324 is considered part of the pressure and temperature data 314 the automated gas-lift manager 242 uses to perform the operation analysis.

[0056] The annular safety valve position sensor 326 may be located on the surface annular safety valve 230 or on the portion of the surface actuation system 306 used to control the surface annular safety valve 230. The annular safety valve position sensor 326 records and sends data regarding whether the surface annular safety valve 230 is opened or closed to the automated gas-lift manager 242. This data from the annular safety valve position sensor 326 is considered part of the valve position data 320 the automated gas-lift manager 242 uses to perform the operation analysis.

[0057] The gas inlet flowmeter 328 is located along the gas line 104, preferably at the inlet where the gas 248 enters the wellhead 102. The gas inlet flowmeter 328 records and sends the flowrate of the gas 248 within the gas line 104 to the automated gas-lift manager 242. This data from the gas inlet flowmeter 328 is considered part of the flow rate data 316 the automated gas-lift manager 242 uses to perform the operation analysis.

[0058] The production fluid outlet flowmeter 330 located at the outlet of the wellhead 102 where the production fluids 210 exit the wellhead 102 to flow to the production tank 234. The production fluid outlet flowmeter 330 records and sends the flowrate of the production fluids 210 exiting the wellhead 102 to the automated gas-lift manager 242. This data from the production fluid outlet flowmeter 330 is considered part of the flow rate data 316 the automated gas-lift manager 242 uses to perform the operation analysis.

[0059] For example, the automated gas-lift manager 242 may measure the volume or rate of gas 248 flowing into the well 202 using the gas inlet flowmeter 328 and may measure the volume or rate of production fluids 210 flowing out of the well 202 using the production fluid outlet flowmeter 330. The automated gas-lift manager 242 may use this data, to monitor the gas-lift operation and send the surface safety command 310 and / or the sub-surface safety command 312 to perform a particular functionality to control the gas-lift operation, such as adjusting the rate of gas 248 flowing into the well 202 based on a comparison of the rate of gas 248 flowing into the well 202 and the rate of production fluids 210 flowing out of the well 202. In further embodiments, the automated gas-lift manager 242 may analyze the data from the production fluid outlet flowmeter 330 to identify blockages or leaks.

[0060] The atmospheric gas concentration sensor 332 may be located anywhere along the surface 206 proximate the wellhead 102. In accordance with one or more embodiments, there may be a multitude of atmospheric gas concentration sensors 332 located at different locations, such as at the gas pump 228, at the inlet to the wellhead 102, at the outlet of the wellhead 102, at the gas source 226, etc.

[0061] The atmospheric gas concentration sensor 332 is used to detect a concentration of the gas 248 in the atmosphere. The atmospheric gas concentration sensor 332 may record and send this data to the automated gas-lift manager 242. The atmospheric gas concentration sensor 332 may be any type of gas sensor known in the art such as an electrochemical sensor, a catalytic sensor, an infrared sensor, and a photoionization sensor. This data from the atmospheric gas concentration sensor 332 is considered part of the atmospheric gas concentration data 318 the automated gas-lift manager 242 uses to perform the operation analysis.

[0062] The surface gas injection valve position sensor 334 may be located on the surface gas injection valve 232 or on the portion of the surface actuation system 306 used to control the surface gas injection valve 232. The surface gas injection valve position sensor 334 records and sends data regarding whether the surface gas injection valve 232 is opened or closed to the automated gas-lift manager 242. This data from the surface gas injection valve position sensor 334 is considered part of the valve position data 320 the automated gas-lift manager 242 uses to perform the operation analysis.

[0063] The proximate manual gate valve position sensor 336 may be located on the proximate manual gate valve 106. The proximate manual gate valve position sensor 336 records and sends data regarding whether the surface proximate manual gate valve 106 is opened or closed to the automated gas-lift manager 242. This data from the proximate manual gate valve position sensor 336 is considered part of the valve position data 320 the automated gas-lift manager 242 uses to perform the operation analysis.

[0064] For example, the automated gas-lift manager 242 may monitor the position of the proximate manual gate valve 106 using the proximate manual gate valve position sensor 336. An operator may use this data to understand the effect of a manual intervention on the gas-lift system 200.

[0065] In accordance with one or more embodiments, the sub-surface sensors 218 may include an upper pressure and temperature sensor 338, a lower pressure and temperature sensor 340, a downhole gas injection valve position sensor 342, a production tubing flowmeter 344, and a SSSV position sensor 346.

[0066] The upper pressure and temperature sensor 338 is located up hole from the production packer 222. The upper pressure and temperature sensor 338 may be located and measure the environment inside of the production tubing 216, or the upper pressure and temperature sensor 338 may be located and measure the environment outside of the production tubing 216 in the annulus 220. In other embodiments, there may be multiple upper pressure and temperature sensors (338) located on the production tubing 216 measuring both the environment inside the production tubing 216 and in the annulus 220.

[0067] The upper pressure and temperature sensor 338 records and sends pressure and temperature data of the gas 248 in the annulus 220 and / or the production fluids 210 inside the production tubing 216 to the automated gas-lift manager 242. This data from the upper pressure and temperature sensor 338 is considered part of the pressure and temperature data 314 the automated gas-lift manager 242 uses to perform the operation analysis.

[0068] The lower pressure and temperature sensor 340 is located downhole from the production packer 222. The lower pressure and temperature sensor 340 may be located and measure the environment inside of the production tubing 216, or the lower pressure and temperature sensor 340 may be located and measure the environment inside the portion of the liner 214 downhole from the production packer 222. In other embodiments, there may be multiple lower pressure and temperature sensors 340 located on the production tubing 216 measuring both the environment inside the production tubing 216 and in the liner 214.

[0069] The lower pressure and temperature sensor 340 records and sends pressure and temperature data of the production fluids 210 located downhole from the production packer 222 to the automated gas-lift manager 242. This data from the lower pressure and temperature sensor 340 is considered part of the pressure and temperature data 314 the automated gas-lift manager 242 uses to perform the operation analysis.

[0070] The downhole gas injection valve position sensor 342 may be located on the downhole gas injection valve 240 or on the portion of the sub-surface actuation system 308 used to control the downhole gas injection valve 240. The downhole gas injection valve position sensor 342 records and sends data regarding whether the downhole gas injection valve 240 is opened or closed to the automated gas-lift manager 242. This data from the downhole gas injection valve position sensor 342 is considered part of the valve position data 320 the automated gas-lift manager 242 uses to perform the operation analysis.

[0071] The production tubing flowmeter 344 is located downhole along the production tubing 216. The production tubing flowmeter 344 records and sends the flowrate of the production fluids 210 flowing through the production tubing 216 to the automated gas-lift manager 242. This data from the production tubing flowmeter 344 is considered part of the flow rate data 316 the automated gas-lift manager 242 uses to perform the operation analysis.

[0072] The SSSV position sensor 346 may be located on the SSSV 238 or on the portion of the sub-surface actuation system 308 used to control the SSSV 238. The SSSV position sensor 346 records and sends data regarding whether the SSSV 238 is opened or closed to the automated gas-lift manager 242. This data from the SSSV position sensor 346 is considered part of the valve position data 320 the automated gas-lift manager 242 uses to perform the operation analysis.

[0073] The pressure and temperature sensors outlined above may be any type of pressure and temperature sensors known in the art, such as negative temperature coefficient thermistors, resistance temperature detectors, thermocouples, differential pressure transducer, strain gauge sensors, barometers, etc. The flowmeters outlined above may be any type of flowmeter known int eh art such as ultrasonic flowmeters, differential pressure flowmeters, magnetic flowmeters, etc.

[0074] As outlined above, the automated gas-lift manager 242 may be equipped with hardware and / or software that includes functionality for monitoring and / or controlling of the gas-lift system 200. For example, the automated gas-lift manager 242 may include one or more programable logic controllers (PLCs). Specifically, the PLC may control valve and pump states throughout the gas-lift system 200. In particular, a PLC may be a ruggedized computer system with functionality to withstand vibrations, extreme temperatures, wet conditions, and / or dusty conditions, for example, around a well site. In other embodiments, the automated gas-lift manager 242 may include or be a computer 402 system outlined below with respect to FIG. 4.

[0075] Furthermore, the automated gas-lift manager 242 may be equipped with an algorithm that uses the pressure and temperature data 314, the flow rate data 316, the atmospheric gas concentration data 318, and the valve position data 320 to monitor the rate of gas 248 being injected into the well, the rate of production fluid 210 being produced from the well 202, the pressures and temperatures at various points in the gas-lift system 200, and the amount of gas in the atmosphere located proximate the gas-lift system 200.

[0076] In accordance with one or more embodiments, the automated gas-lift manager 242 may use the algorithm to determine whether or not there is an incident based on elevated pressures / temperatures / flowrates or based on detection of higher-than-normal concentrations of gas 248 in the atmosphere proximate the gas-lift system 200. The algorithm may also use the source (i.e., the particular sensor / flowmeter) of the data to determine where the incident is occurring.

[0077] With this information, the automated gas-lift manager 242 may send the surface safety command 310 to the surface pressure barrier system 302 to close the gas pump 228, the surface annular safety valve 230, and / or the surface gas injection valve 232. The automated gas-lift manager 242 may alternatively or conjunctly send the sub-surface safety command 312 to the sub-surface pressure barrier system 304 to close the SSSV 238 and / or the downhole gas injection valve 240.

[0078] Once the incident has been resolved and the gas-lift system 200 is available to re-start production, the automated gas-lift manager 242 may send signals via the surface safety command 310 and / or the sub-surface safety command 312 to open designated valves or pumps to re-start production.

[0079] In accordance with one or more embodiments, the automated gas-lift manager 242 may transmit the data to the user device 300 and a user can use the user device 300 to view any of the data or incidence reports gathered / determined by the automated gas-lift manager 242.

[0080] Furthermore, the surface safety command 310 and / or the sub-surface safety command 312 may be sent to the gas-lift system 200 using the user device 300 by the user, rather than automatically being sent from the automated gas-lift manager 242. The user may be able to specify which components to actuate using the user device 300.

[0081] Embodiments outlined above may be implemented on a computer 402 system. For example, the automated gas-lift manager 242 may be the computer 402 system or be located on a computer 402 system. FIG. 4 shows the computer 402 system in accordance with one or more embodiments. Specifically, FIG. 4 shows a block diagram of a computer 402 system used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure, according to an implementation. The illustrated computer 402 is intended to encompass any computing device such as a server, desktop computer, laptop / notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device.

[0082] Additionally, the computer 402 may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer 402, including digital data, visual, or audio information (or a combination of information), or a GUI.

[0083] The computer 402 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer 402 is communicably coupled with a network 430. In some implementations, one or more components of the computer 402 may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).

[0084] At a high level, the computer 402 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 402 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).

[0085] The computer 402 can receive requests over network 430 from a client application (for example, executing on another computer 402) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 402 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.

[0086] Each of the components of the computer 402 can communicate using a system bus 403. In some implementations, any or all of the components of the computer 402, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 404 (or a combination of both) over the system bus 403 using an application programming interface (API) 412 or a service layer 413 (or a combination of the API 412 and service layer 413. The API 412 may include specifications for routines, data structures, and object classes. The API 412 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 413 provides software services to the computer 402 or other components (whether or not illustrated) that are communicably coupled to the computer 402.

[0087] The functionality of the computer 402 may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 413, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or other suitable format. While illustrated as an integrated component of the computer 402, alternative implementations may illustrate the API 412 or the service layer 413 as stand-alone components in relation to other components of the computer 402 or other components (whether or not illustrated) that are communicably coupled to the computer 402. Moreover, any or all parts of the API 412 or the service layer 413 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

[0088] The computer 402 includes an interface 404. Although illustrated as a single interface 404 in FIG. 4, two or more interfaces 404 may be used according to particular needs, desires, or particular implementations of the computer 402. The interface 404 is used by the computer 402 for communicating with other systems in a distributed environment that are connected to the network 430. Generally, the interface 404 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network 430. More specifically, the interface 404 may include software supporting one or more communication protocols associated with communications such that the network 430 or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer 402.

[0089] The computer 402 includes at least one computer processor 405. Although illustrated as a single computer processor 405 in FIG. 4, two or more processors may be used according to particular needs, desires, or particular implementations of the computer 402. Generally, the computer processor 405 executes instructions and manipulates data to perform the operations of the computer 402 and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

[0090] The computer 402 also includes a non-transitory computer 402 readable medium, or a memory 406, that holds data for the computer 402 or other components (or a combination of both) that can be connected to the network 430. For example, memory 406 can be a database storing data consistent with this disclosure. Although illustrated as a single memory 406 in FIG. 4, two or more memories may be used according to particular needs, desires, or particular implementations of the computer 402 and the described functionality. While memory 406 is illustrated as an integral component of the computer 402, in alternative implementations, memory 406 can be external to the computer 402.

[0091] The application 407 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 402, particularly with respect to functionality described in this disclosure. For example, application 407 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application 407, the application 407 may be implemented as multiple applications 407 on the computer 402. In addition, although illustrated as integral to the computer 402, in alternative implementations, the application 407 can be external to the computer 402.

[0092] There may be any number of computers 402 associated with, or external to, a computer system containing computer 402, each computer 402 communicating over network 430. Further, the term “client,”“user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer 402, or that one user may use multiple computers 402.

[0093] FIG. 5 shows a flowchart in accordance with one or more embodiments. The flowchart outlines a method for monitoring and controlling a gas-lift system 200 using an automated gas-lift manager 242. Various steps shown in FIG. 5 may be performed or may use one or more of the components outlined above in FIGS. 1-4. While the various blocks in FIG. 5 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.

[0094] In S500, a gas 248 is pumped from a surface 206 location into an annulus 220 of the well 202 using a gas pump 228. In accordance with one or more embodiments, the gas 248 is pumped from a gas source 226 to a wellhead 102 capping the well 202 through a gas line 104. A surface gas injection valve 232 may be installed along the gas line 104. The surface gas injection valve 232 may be used to control flow of the gas 248 into the well 202. In other embodiments, turning the gas pump 228 on or off may also control the flow of the gas 248 into the well 202.

[0095] From the wellhead 102, the gas 248 flows into the annulus 220 of the well 202. In S502, a downhole gas injection valve 240 is opened to allow the gas 248 to enter the production tubing 216 from the annulus 220 of the well 202. In S504, the gas 248 is mixed with the production fluids 210 to lower a density of the production fluids 210 and allow the production fluids 210 to flow to the surface 206 location using the production tubing 216.

[0096] In accordance with one or more embodiments, a production packer 222 is installed on the production tubing 216 to prevent the production fluids 210 migrating up the annulus 220. The production packer 222 forces the production fluids 210 to flow from the reservoir 208 into the production tubing 216. The production fluids 210 flow through the production tubing 216, out of the wellhead 102, and into a production tank 234. In accordance with one or more embodiments associated gas 248 may be removed from the production tank 234 to be used as the gas source 226.

[0097] In S506, the gas-lift system 200 is monitored using a plurality of surface sensors coupled to a surface pressure barrier system 302 and a plurality of sub-surface sensors 218 coupled to a sub-surface pressure barrier system 304. Data is sent from the plurality of surface sensors 236 and the plurality of sub-surface sensors 218 to an automated gas-lift manager 242.

[0098] In accordance with one or more embodiments, the surface pressure barrier system 302 includes a surface actuation system 306 coupled to one or more gas pumps 228, a surface annular safety valve 230, and one or more surface gas injection valves 232. The sub-surface pressure barrier system 304 includes a sub-surface actuation system 308 coupled to a SSSV 238 and one or more downhole gas injection valves 240.

[0099] In accordance with one or more embodiments, the surface sensors 236 include a gas inlet pressure and temperature sensor 322, a production fluid outlet pressure and temperature sensor 324, an annular safety valve position sensor 326, a gas inlet flowmeter 328, a production fluid outlet flowmeter 330, an atmospheric gas concentration sensor 332, a surface gas injection valve position sensor 334, and a proximate manual gate valve position sensor 336.

[0100] In accordance with one or more embodiments, the sub-surface sensors 218 may include an upper pressure and temperature sensor 338, a lower pressure and temperature sensor 340, a downhole gas injection valve position sensor 342, a production tubing flowmeter 344, and a SSSV position sensor 346.

[0101] The gas-lift well 202 may be monitored by using the automated gas-lift manager 242 to track the data received from the surface sensors 236 and the sub-surface sensors and alert to any deviations. For example, the automated gas-lift manager 242 may monitor flowrates of gas 248 or production fluids 210 at different locations in the gas-lift system 200. The automated gas-lift manager 242 may also monitor the pressure and temperature of the gas 248 or production fluids 210 at different locations in the gas-lift system 200. The automated gas-lift manager 242 may also monitor the position of the various valves in the gas-lift system to determine which are opened or closed. The automated gas-lift manager 242 may also monitor a concentration of gas in the atmosphere at the surface 206 location.

[0102] The automated gas-lift manager 242 may be programmed with instructions for which valves should be opened or closed to start, pause, or stop gas-lift production operations. The automated gas-lift manager 242 may use this programming to start, pause, or stop gas-lift production operations based on detection of an incident while monitoring the gas-lift system 200.

[0103] In S508, the automated gas-lift manager 242 detects an incident in the gas-lift system 200 using the data from the plurality of surface sensors 236 and the plurality of sub-surface sensors 218. In accordance with one or more embodiments, the automated gas-lift manager 242 receives pressure and temperature data 314, flow rate data 316, atmospheric gas concentration data 318, and valve position data 320 from the surface sensors 236 and the sub-surface sensors 218.

[0104] An incident may be detected in a myriad of ways. For example, the automated gas-lift manager 242 may monitor the pressure and temperature data 314. While monitoring the pressure and temperature data 314, the automated gas-lift manager 242 may detect a spike in the temperature or the pressure at one or more locations in the gas-lift system 200. Furthermore, the automated gas-lift manager 242 may monitor the concentration of gas 248 in the atmosphere at the surface 206 location. While monitoring the concentration of gas 248, the automated gas-lift manager 242 may detect a spike in the concentration of gas 248. The detected incident may be indicative of a gas leak in the equipment or a kick of production fluids 210 in the well 202.

[0105] In S510, a command signal is sent from the automated gas-lift manager 242 to a surface actuation system 306 in the surface pressure barrier system 302 or to a sub-surface actuation system 308 in the sub-surface pressure barrier system 304 to perform one or more functionalities based on the detection of the incident. In accordance with one or more embodiments, the specific instruction in the command relating to the functionality that should be performed may be based on what the automated gas-lift manager 242 detected.

[0106] In accordance with one or more embodiments the functionalities include turning off the gas pump 228, using the surface actuation system 306, to prevent the gas 248 from being pumped into the well 202, closing a surface annular safety valve 230, using the surface actuation system 306, to prevent the production fluids 210 from migrating through an annulus of a wellhead 102 capping the well 202, and closing a SSSV 238, using the sub-surface actuation system 308, to prevent the production fluids 210 from flowing to the wellhead 102.

[0107] In further embodiments, the functionalities may also include closing the surface gas injection valve 232, using the surface actuation system 306, to prevent the gas 248 from flowing to the wellhead 102. The functionalities may also include closing the downhole gas injection valve 240 to prevent the gas 248 from flowing into the production tubing 216 from the annulus 220 of the well 202.

[0108] As shown above, the gas-lift system 200 integrates advanced safety features, real-time monitoring capabilities, and specialized components designed to enhance well 202 integrity, reduce maintenance needs, and protect the environment. The adaptability of the gas-lift system 200 allows for easy integration into existing well architectures without the need for extensive modifications, significantly reducing installation and operational efforts. Furthermore, the gas-lift system 200 fully complies with international safety standards, such as the Norwegian shelf's competitive position (NORSOK) safety standards and American Petroleum Institute (API) safety standards. For example, the gas-lift system 200 meets various rigorous testing protocols, like API 6FD / FB fire testing, which are not fully covered by the conventional pressure barrier systems. As such, this design reflects a comprehensive approach to improving gas-lift systems 200, particularly in terms of safety and environmental sustainability.

[0109] In particular, the integration of the various pressure and temperature sensors (e.g., 322, 324, 328, 340) in the gas-lift system 200 allows the gas-lift system 200 to be continuously monitored which allows for the early detection of anomalies that could lead to failure, with the gas-lift system 200 capable of automatically responding to changes without the need for human intervention.

[0110] Due to the coupling of the automated gas-lift manager 242 to valve position sensors (e.g., 326, 334, 336, 342, 346) and actuation systems (e.g., 306 and 308), the gas-lift system 200 can automatically adjust valve settings or initiate a shutdown if a risk is detected. This rapid response capability significantly reduces the risk of a catastrophic event and provides a higher level of safety than a conventional setup with manual valves.

[0111] The surface pressure barrier system 302 and the sub-surface pressure barrier systems 304 in the gas-lift system 200 are designed to withstand extreme pressures and corrosive environments, providing a more reliable isolation than standard manual gate valves. While conventional manual gate valves offer protection at the surface, they do not address subsurface risks. The gas-lift system's 200 inclusion of a pressure-rated production packer 222 and gas-lift valves (e.g., 232 and 240) ensure the integrity of the well 202 at all levels, not just where the manual valves are located.

[0112] By combining the surface pressure barrier system 302 and the sub-surface pressure barrier systems 304 into a cohesive gas-lift system 200, the setup provides a comprehensive approach to well 202 safety, addressing multiple potential points of failure that a conventional setup might miss. Furthermore, the gas-lift system's 200 design minimizes the need for well 202 intervention, reducing the exposure of personnel to hazardous conditions and decreasing the likelihood of human error.

[0113] Due to the automation of the gas-lift system 200 using the automated gas-lift manager 242, the gas-lift system 200 is flexible and adaptable, capable of performing reliably in a range of operational environments, including high-pressure and sour gas fields. This includes modular components and adjustable settings for sensors to accommodate different pressures and temperatures.

[0114] The incorporation of the atmospheric gas concentration sensor 332 and associated data allows the system to incorporate advanced leak detection and mitigation capabilities to promptly identify and address potential leaks, significantly reducing the risk of environmental contamination. This ensures rapid response and corrective action to prevent leaks from escalating.

[0115] 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.

Claims

1. A gas-lift system for a well having production tubing configured to convey production fluids to a surface location, the gas-lift system comprising:a surface pressure barrier system comprising:a gas pump configured to pump a gas into an annulus of the well,a surface annular safety valve located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead, anda surface actuation system coupled to and configured to actuate the gas pump and the surface annular safety valve;a sub-surface pressure barrier system comprising:a downhole gas injection valve configured to actuate to allow or prevent the gas from entering the production tubing to mix with the production fluids to lower a density of the production fluids,a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, anda sub-surface actuation system coupled to and configured to actuate the downhole gas injection valve and the sub-surface safety valve;a plurality of surface sensors coupled to the surface pressure barrier system;a plurality of sub-surface sensors coupled to the sub-surface pressure barrier system; andan automated gas-lift manager coupled to the surface pressure barrier system, the sub-surface pressure barrier system, the plurality of surface sensors, and the plurality of sub-surface sensors, wherein the automated gas-lift manager is configured to monitor and control the surface pressure barrier system and the sub-surface pressure barrier system based on data received from the plurality of surface sensors and the plurality of sub-surface sensors.

2. The gas-lift system of claim 1, wherein the plurality of surface sensors and the plurality of sub-surface sensors comprise valve position sensors coupled to the surface annular safety valve, the downhole gas injection valve, and the sub-surface safety valve.

3. The gas-lift system of claim 2, wherein the automated gas-lift manager is configured to monitor and control the gas-lift system by detecting a position of the surface annular safety valve, the downhole gas injection valve, and the sub-surface safety valve using data from to the valve position sensors.

4. The gas-lift system of claim 1, wherein the plurality of surface sensors and the plurality of sub-surface sensors comprise pressure and temperature sensors.

5. The gas-lift system of claim 4, wherein the automated gas-lift manager is configured to detect an incident based on data received from the pressure and temperature sensors.

6. The gas-lift system of claim 5, wherein the automated gas-lift manager is configured to send a command to the gas-lift system to shut down operations based on detection of the incident.

7. The gas-lift system of claim 6, wherein the command is sent to the surface actuation system or the sub-surface actuation system to close or shut down the gas pump, the surface annular safety valve, or the sub-surface safety valve.

8. The gas-lift system of claim 1, wherein the plurality of surface sensors comprise an atmospheric gas concentration sensor located at the surface location and the automated gas-lift manager is configured to detect an incident based on data received from the atmospheric gas concentration sensor.

9. The gas-lift system of claim 8, wherein the automated gas-lift manager is configured to send a command to the gas-lift system to shut down operations based on detection of the incident.

10. The gas-lift system of claim 9, wherein the command is sent to the surface actuation system or the sub-surface actuation system to close or shut down the gas pump, the surface annular safety valve, or the sub-surface safety valve.

11. A method for a gas-lift system for a well having production tubing configured to convey production fluids to a surface location, the method comprising:pumping a gas from the surface location into an annulus of the well using a gas pump;opening a downhole gas injection valve to allow the gas to enter the production tubing from the annulus of the well;mixing the gas with the production fluids to lower a density of the production fluids and allow the production fluids to flow to the surface location using the production tubing;monitoring the gas-lift system using a plurality of surface sensors coupled to a surface pressure barrier system and a plurality of sub-surface sensors coupled to a sub-surface pressure barrier system, wherein data is sent from the plurality of surface sensors and the plurality of sub-surface sensors to an automated gas-lift manager;detecting, using the automated gas-lift manager, an incident in the gas-lift system using the data from the plurality of surface sensors and the plurality of sub-surface sensors; andsending a command signal from the automated gas-lift manager to a surface actuation system in the surface pressure barrier system or to a sub-surface actuation system in the sub-surface pressure barrier system to perform one or more functionalities based on the detection of the incident, the functionalities comprising:turning off the gas pump, using the surface actuation system, to prevent the gas from being pumped into the well,closing a surface annular safety valve, using the surface actuation system, to prevent the production fluids from migrating through an annulus of a wellhead capping the well, andclosing a sub-surface safety valve, using the sub-surface actuation system, to prevent the production fluids from flowing to the wellhead.

12. The method of claim 11, wherein the plurality of surface sensors and the plurality of sub-surface sensors comprise valve position sensors coupled to the surface annular safety valve, the downhole gas injection valve, and the sub-surface safety valve.

13. The method of claim 12, wherein monitoring the gas-lift system further comprises detecting a position of the surface annular safety valve, the downhole gas injection valve, and the sub-surface safety valve using data from the valve position sensors.

14. The method of claim 11, wherein the plurality of surface sensors and the plurality of sub-surface sensors comprise pressure and temperature sensors.

15. The method of claim 14, wherein detecting the incident further comprises detecting a spike in temperature or a spike in pressure using data from the pressure and temperature sensors.

16. The method of claim 15, wherein sending the command signal from the automated gas-lift manager further comprises diagnosing the incident using locations associated with the data received from the pressure and temperature sensors.

17. The method of claim 16, wherein sending the command signal from the automated gas-lift manager further comprises determining which functionality to perform based on the diagnosis of the incident.

18. The method of claim 11, wherein the plurality of surface sensors comprise an atmospheric gas concentration sensor located at the surface location.

19. The method of claim 18, wherein detecting the incident further comprises detecting an increase in a concentration of gas using the atmospheric gas concentration sensor.

20. The method of claim 19, wherein sending the command signal from the automated gas-lift manager further comprises determining which functionality to perform based on the detection of the increase in the concentration of the gas.

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