Integrated Pressure Barrier-Related Completion System for Gas-Lift Wells

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.

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.

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.

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.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

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.

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

Specifically,shows a wellheadcapping a wellbore (not pictured) drilled into the surface of the Earth. A gas lineis connected to the wellhead. The gas lineis transporting a gas to the wellheadto be used for gas-lift operations. The gas lineis equipped with a proximate manual gate valveand a distal manual gate valve. The proximate manual gate valveis located closest to the wellheadand the distal manual gate valveis located furthest from the wellhead, when compared to one another. The proximate manual gate valveand the distal manual gate valveare used to shut off the flow of the gas from the gas lineinto the wellhead.

In accordance with one or more embodiments, two manual gate valves are provided to create redundancy in case one fails. The proximate manual gate valveand the distal manual gate valveare operated manually. Thus, when an emergency occurs, the gate valve pressure barrier systemrelies on human detection and reaction. Consequentially, the gate valve pressure barrier systemis 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 systemdoes not provide real-time monitoring of well conditions.

Beyond the deficiencies listed above, gate valve pressure barrier systemshave other limitations. For example, gate valve pressure barrier systemsare 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 systemsare 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.

Thus, many gate valve pressure barrier systemsrequire 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. Components from different manufacturers may have compatibility issues, leading to weak points in the system.

For all the reasons listed above, the gate valve pressure barrier system'sability 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 wellshaving a gas-lift system.

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.

shows a gas-lift systemfor a wellhaving an integrated and automated pressure barrier system in accordance with one or more embodiments. A person skilled in the art will appreciate the wellshown inis 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.

The wellshown inhas a wellboredrilled into the surfaceof the Earth. The wellboretraverses a reservoircontaining production fluids. The production fluidsmay 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.

A casing stringextends from the surfaceand is disposed and cemented within the wellbore. The casing stringis housed in a wellheadat the surface. A lineris hung within the casing stringand extends to a depth in the wellboredownhole from the casing string.

Production tubingis disposed inside of the casing stringand the liner. The production tubingextends from the surfaceand ends at a predetermined depth within the liner. In accordance with one or more embodiments, the depth of the production tubingdepends on the calculated height of the production fluidswithin the interior of the wellthroughout the life of the well. For example, the production tubingmay extend to the depth of the lowest conceivable depth of production fluidswithin the interior of the well.

The casing string, the liner, and the production tubingare 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 linermay be hung within the casing stringusing a liner hanger (not pictured) and a packer (not pictured). The production tubingmay include various equipment associated with production, such as sub-surface sensors.

An annulusis shown as the space between an outer circumferential surface of the production tubingand an inner circumferential surface of the casing stringand the liner. A production packeris disposed in the annulusbetween the production tubingand the liner. In accordance with one or more embodiments, the production packeris located on a downhole end of the production tubing.

The production packerprevents the production fluidsfrom migrating in an up hole direction from a location downhole from the production packerto a location up hole from the production packer. The production packermay be any type of packer known in the art such as a hydraulic or mechanical packer. The sub-surface sensorsmay be located anywhere along the production tubing, such as up hole or downhole from the production packer.

The production fluidis configured to flow from the reservoirinto the linerthrough perforationscreated in the liner, or through an exposed, unlined portion of the wellbore. The production fluidflows from the linerinto the production tubing.

The production tubingis configured to transport the production fluidto the surface. However, the production fluidmay be too heavy to naturally flow to the surfaceusing reservoirpressure. As such, the wellis completed with a gas-lift production scheme to enable production of the production fluids.

The gas-lift production scheme includes a combination of surface equipment and downhole equipment that work together to operate the gas-lift systemand to provide a pressure barrier. The surface equipment includes a gas source, a gas pump, a gas line, a surface annular safety valve, a surface gas injection valve, a proximate manual gate valve, a production tank, and surface sensors. The downhole equipment includes a SSSV, the sub-surface sensors, the production packer, and a downhole gas injection valve.

The gas-lift systemcan be remotely monitored and automatically controlled using an automated gas-lift manager. The automated gas-lift managerreceives inputs, such as data, from the gas-lift systemand sends outputs, such as commands, to the gas-lift system. The automated gas-lift manageris outlined in further detail in.

Generally, the gas-lift systemoperates as follows. A gasis pumped from the gas source, via the gas pump, into the wellhead. The gasis pumped from the wellheadinto the annulus. The downhole gas injection valveis used to allow the gasto enter the production tubingto mix with the production fluids. The gasmixes with the production fluidsto lower the density of the production fluidsto a level such that the reservoirpressure is sufficient to allow the production fluidsto flow to the surface. At the surface, the production fluidsflow out of the wellheadto a production tank.

The gasmay be any type of gas that may be used in a gas-lift operations, such as associated gas, natural gas, etc. The gas sourcemay be any type of gas source known in the art. For example, the gas sourcemay be an accumulation of associated gas that is produced with the production fluids. The gas sourcemay 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.

The gas pumpmay be any type of pump known in the art, such as a displacement pump, a reciprocating pump, a centrifugal pump, etc. The gas pumpmay be powered using any means known in the art, such as solar power, electric power, diesel-generated power, etc. The gas lineis used to transport gasfrom the gas sourceto the gas pumpand from the gas pumpto the wellhead.

The surface gas injection valveis disposed along the gas lineand is used to control the gasflow into the wellhead. The surface gas injection valvemay be operated using a hydraulic actuation system or an electronic actuation system.

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

The SSSVis located along the production tubingwithin the casing string. In accordance with one or more embodiments, the SSSVis located proximate an up-hole end of the production tubing. The SSSVmay be operated using a hydraulic actuation system or an electronic actuation system. The SSSVis closed to prevent the production fluidsfrom flowing through the production tubingto the wellhead.

The downhole gas injection valveis located along the production tubing, preferably at a location in the production tubingthat will be submerged in the production fluidswhen the production fluidsare unable to flow. In accordance with one or more embodiments, there may be multiple downhole gas injection valveslocated at different depths within the production tubingbased on the varying heights of the production fluidsover the life of the well.

The downhole gas injection valvemay be operated using a hydraulic actuation system or an electronic actuation system. In other embodiments, the downhole gas injection valvewill automatically open based on pre-determined pressures seen in the wellbore. When the downhole gas injection valveopens, the gasis able to flow from the annulusinto the production tubingto mix with the production fluid.

shows a schematic diagram in accordance with one or more embodiments. Components shown inthat are the same as or similar to components shown inhave not be re-described for purposes of readability and have the same description and function as outlined above.

illustrates the gas-lift systemthat may include the automated gas-lift managercoupled to one or more user devices, surface sensors, sub-surface sensors, a surface pressure barrier system, and a sub-surface pressure barrier system. The automated gas-lift managermay include hardware and/or software that includes functionality for monitoring and/or controlling the gas-lift system.

In accordance with one or more embodiments, the surface pressure barrier systemincludes a surface actuation systemcoupled to one or more gas pumps, the surface annular safety valve, and one or more surface gas injection valves. The surface actuation systemmay have one or more sub-systems that are coupled to each component. Furthermore, the surface actuation systemmay be a hydraulic actuation system, an electronic actuation system, or a combination thereof without departing from the scope of the disclosure herein.

In accordance with one or more embodiments, the sub-surface pressure barrier systemincludes a sub-surface actuation systemcoupled to the SSSVand one or more downhole gas injection valves. The sub-surface actuation systemmay have one or more sub-systems that are coupled to each component. The sub-surface actuation systemmay be wholly located downhole or may be located on the surfaceand extend downhole. The sub-surface actuation systemmay be a hydraulic actuation system, an electronic actuation system, or a combination thereof without departing from the scope of the disclosure herein.

In accordance with one or more embodiments, the automated gas-lift managertransmits one or more commands (e.g., surface safety commandand sub-surface safety command) to various control systems (e.g., the surface actuation systemlocated within the surface pressure barrier system, or the sub-surface actuation systemlocated within the sub-surface pressure barrier system.

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.

In accordance with one or more embodiments, the automated gas-lift managermay transmit a surface safety commandto the surface actuation systemlocated within the surface pressure barrier systeminstructing the system to actuate the gas pump, the surface annular safety valve, or the surface gas injection valve.

In accordance with one or more embodiments, the automated gas-lift managermay transmit a sub-surface safety commandto the sub-surface actuation systemlocated within sub-surface pressure barrier systeminstructing the system to actuate the SSSVor the downhole gas injection valve.

In accordance with one or more embodiments, the surface safety commandand the sub-surface safety commandmay be the outputsshown inthat are transmitted from the automated gas-lift managerto the gas-lift system. Which command and the specific actuation instruction within the command is based on an operation analysis of the gas-lift systemperformed by the automated gas-lift manager.

In accordance with one or more embodiments, the automated gas-lift managerperforms this operation analysis using pressure and temperature data, flow rate data, atmospheric gas concentration data, and valve position datareceived from the surface sensorsand the sub-surface sensors. In accordance with one or more embodiments, the automated gas-lift manageruses this data to make decision on the operation of the gas-lift operation, such as adjusting the gasinjection rate to optimize production fluidproduction.

The automated gas-lift manageruses this data to determine if an incident is occurring. When an incident is detected, the automated gas-lift managermay automatically send the surface safety commandor the sub-surface safety commandto actuate the surface pressure barrier systemand/or the sub-surface pressure barrier system, depending on the location and cause of the incident.

In accordance with one or more embodiments, the surface sensorsinclude a gas inlet pressure and temperature sensor, a production fluid outlet pressure and temperature sensor, an annular safety valve position sensor, a gas inlet flowmeter, a production fluid outlet flowmeter, an atmospheric gas concentration sensor, a surface gas injection valve position sensor, and a proximate manual gate valve position sensor.

The gas inlet pressure and temperature sensoris located along the gas line, preferably at the inlet where the gasenters the wellhead. The gas inlet pressure and temperature sensorrecords and sends pressure and temperature data of the gaswithin the gas lineto the automated gas-lift manager. This data from the gas inlet pressure and temperature sensoris considered part of the pressure and temperature datathe automated gas-lift manageruses to perform the operation analysis.

For example, the automated gas-lift managermay monitor the value of the pressure and temperature readings from the gas inlet pressure and temperature sensorand compare them to the operational parameters of the gas-lift system. If the value of the pressure and temperature readings from the gas inlet pressure and temperature sensorexceed the operational parameters, the automated gas-lift managermay send the surface safety commandand/or the sub-surface safety commandto perform a particular functionality to control the gas-lift operation, such as shutting down the gas-lift operation.

The production fluid outlet pressure and temperature sensoris located at the outlet of the wellheadwhere the production fluidsexit the wellheadto flow to the production tank. The production fluid outlet pressure and temperature sensorrecords and sends pressure and temperature data of the production fluidsexiting the wellheadto the automated gas-lift manager. This data from the production fluid outlet pressure and temperature sensoris considered part of the pressure and temperature datathe automated gas-lift manageruses to perform the operation analysis.

The annular safety valve position sensormay be located on the surface annular safety valveor on the portion of the surface actuation systemused to control the surface annular safety valve. The annular safety valve position sensorrecords and sends data regarding whether the surface annular safety valveis opened or closed to the automated gas-lift manager. This data from the annular safety valve position sensoris considered part of the valve position datathe automated gas-lift manageruses to perform the operation analysis.