Apparatus for Preventing Unintentional Valve Operation During Wireline Operations

Abstract

A method of preventing valve operations which may inadvertently shear a wireline, causing a downhole tool string loss. Logic control of actuated valve control equipment in a wireline operation enables and disables or set valve states when a wireline is passing through dependent on tool string placement. Emergency override is available to shear wirelines and drop tool strings prior to valve operations to avoid possible interference with valve closures.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119(e) from co-pending U.S. Provisional Patent Application No. 62/825,304, by Jason Pitcher, “Apparatus for Preventing Unintentional Valve Operations During Wireline Operations” filed 28 Mar. 2019, which, by this statement, is incorporated herein by reference for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

REFERENCE TO SEQUENCE LISTING, A TABLE, OR A COMPUTER PROGRAM LISTING COMPACT DISC APPENDIX

Not Applicable.

BACKGROUND OF THE INVENTION

Field of the Invention

The invention relates generally to wireline operations in drilling operations. More particularly, the invention relates to instrumenting and monitoring wireline equipment to prevent unintentional valve operation shearing a wireline.

Background of the Invention

Wireline operations are defined as any oil and gas exploration or production activity that involves lowering a tool, or plurality of tools (a tool string) into a well bore using a wire or braided cable. Braided cables are usually referred to as wirelines and single strand cables are referred to as slicklines. The reasons for making a distinction has to do with the technical challenge of forming a pressure seal around the different surfaces, but is irrelevant for purpose of this discussion, and thus may be used interchangeably.

Wireline operations are used for a wide variety of purposes throughout the various phases of exploration and production activities. During these exploration and production activities a well is usually under pressure, and care must be taken to avoid losing control of the well. A blowout can be financially costly, and environmentally impactful, as well as possibly causing human injury/fatality.

Moving equipment in and out of a wellbore with anywhere from 5,000 psi to over 20,000 psi requires the use of pressure control devices as well as experience and careful planning. Wireline operations require the wireline tools to be inserted and removed from the well in such a way that pressure is constantly maintained. This is done through what is generally referred to as a lubricator.

A lubricator is a long, high-pressure pipe fitted to the top of a wellhead or Christmas tree with a master valve to provide access to the wellbore. The lubricator is usually made up of a variety of elements depending on the task at hand, including, but not limited to: one or more risers, optional tool traps, a head catcher, high-pressure grease-injectors, adapters, and sealing elements.

The tool string is placed in the lubricator and the lubricator is pressurized to wellbore pressure. The master valve, and other valves comprising the tree are then opened, enabling the tool string to enter the wellbore. To remove the tools, the tool string is brought into the lubricator under wellbore pressure, the master valve is closed, the lubricator pressure is bled off, then the lubricator is opened to remove the tools.

A master valve is of such importance to well operation that there is usually an upper master valve and a lower master valve herein referenced collectively as a single master valve. Additionally, a well is commonly protected against blowouts by one or more devices called blowout preventors generally various forms of actuated valves that are referred to as BOPs. BOPs are incorporated into a well stack or Christmas tree and elsewhere on the well. In the event of an emergency, BOPs close off the well to contain the pressure and prevent the escape of environmentally damaging fluids. The BOPs close off the well through the use of hydraulic shear seal rams, which are powerful enough to shear drill pipe and crush any tool string in the process.

Federal and International laws require lubricators used in wireline operations also include one or more wireline rams (AKA wireline valves or wireline BOPs) between the lubricator and the wellbore, which may serve as or supplement a master valve. This is in addition to the BOPs already incorporated into the well. Wireline rams may be wireline sealing rams or blind shear rams. Wireline sealing rams have small openings through which wireline may pass when the rams are closed. Blind shear rams are similar to the shear seal rams described above, but wireline operation equipment may also include wire cutters which sever the wireline during an emergency allowing the tool string to fall down the wellbore.

BOPs are a primary safety element in preventing well blowout. Due to the high impact their malfunction could have on the environment and/or worker safety, BOPs are government regulated. BOP focused government regulations require routine maintenance, regular operations, and extensive testing, sometimes to a daily level. Additionally, BOPs are often remotely activated because of the likely inhospitable state of their immediate surroundings in the instances their uses proved mandatory.

Given the circumstances, it is not surprising that a common failure during wireline operations is the accidental and/or unintentional activation of a valve in the stack or elsewhere along the line, causing severing of the wireline. The result is damaged or lost equipment, time delays while fishing operations occur, or new equipment is procured for the scheduled wireline operations. While sometimes the valve operation may be necessary to avert an emergency situation, it is desirable to prevent the avoidable instances. Wireline operations and the resulting time a well is not producing can already be expensive without the cost increases of unnecessary delays and mistakes.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an exemplary arrangement of common components typically incorporated into a lubricator, though variations would be dictated by the specific intended task.

FIG. 2 illustrates a lubricator supported atop a Christmas tree by a telescoping gin pole.

FIGS. 3A and 3B show an instrumented riser for detecting the presence of a tool string in accordance with an exemplary embodiment of the innovation.

FIGS. 4A and 4B show alternative embodiments of instrumenting a lubricator riser for detecting the presence of a tool string within the riser's internal cavity in accordance with an exemplary embodiment of the innovation.

FIG. 5 shows a partial cutaway view of a manually operated tool trap instrumented in accordance with an exemplary embodiment of the innovation.

FIG. 6 shows a partial cutaway view of a dual option mechanized or manually operated tool trap instrumented in accordance with an exemplary embodiment of the innovation.

FIG. 7 shows an exemplary configuration for utilizing instrumented risers and electronic controllers, for an implementation in accordance with the innovation presented herein.

DETAILED DESCRIPTION OF THE INNOVATION

This innovation seeks to prevent the wasted resources caused by inadvertent or unintentional closing of hydraulic operated frac valves while wireline tool strings are deployed by instrumenting the lubricator to monitor the deployment of a tool string, and selectively disable hydraulic frac valves through which the wireline passes. The same teachings may equally be applied to other types of wireline operations.

As an additional advantage, other valves, including BOPs may also be selectively disabled in similar fashion, anywhere along the line where actuators may be controlled. This includes valves which are electrically, hydraulically, or pneumatically actuated, or valves where actuation is controlled by electrical, hydraulic, or pneumatic control signals. In another embodiment the control method may be by manipulation of the motive power source for valves.

Manually operated valves may also be controlled by setting and removing interlocks or providing physical indicators to operating personnel of desired activity. One skilled in the arts would appreciate the extensive selection of equipment and the wide range of options for operations, in deployment on surface, subsea, or sub-surface and control options including manual, local, automatic, and/or remote.

For simplicity the system is described as enabling or disabling hydraulic valve operations. This may range from power control of hydraulic pumps, their control equipment, disabling or interrupting control signals, setting local worker lockouts, or simply notifying an operator the valve is unavailable. All of these details can be appreciated by one skilled in the art, and therefor are outside the scope of this disclosure.

The following methods describe control of hydraulically actuated valves during wireline fracturing operations unless otherwise indicated by the context. While one skilled in the art would appreciate the application to many configurations, the exemplary use is a lubricator with a plurality of risers for holding a tool string above the wellhead valve prior to and after wireline operations. A tool trap at the lower end of the lubricator is connected between the risers and a master valve leading to the well bore. Also included are a plurality of other hydraulically operated valves, including, but not limited to wireline BOPs and Well BOPs, all of which may be collectively references as articulated valves or BOPs.

The wireline or slickline exits the top of the lubricator thorough a grease injection control head (typically needed for wirelines, but not slicklines) then through a line wiper and a stuffing box, finally passing over a sheave. The wireline or slickline then passes through a floor block (also known as a hay pulley) to bring the wireline down to a position where it is horizontal from the tree to the drum reel/logging truck/wireline rig. This shifts the pulling force from the top of the lubricator to the base of the tree reducing the side loading on the lubricator.

Once positioned, the lubricator can be hydrostatic tested, then the wellhead's master valve is opened, and the tool string is inserted into the wellbore. To remove the tool string, the process is essentially reversed. The wireline draws the tool string up the wellbore and into the lubricator's risers. The master valve is closed, and pressure is reduced in the riser so the lubricator can be taken from the stack and the tool string removed.

The innovation includes the use of one or more sensor(s) instrumenting the lubricator to monitor the tool string. In the preferred embodiment, a sensor mounted to the lubricator, identifies when the tool string occupies the riser. Logic control such as a programmable controller, a computing device, or specialized electronic circuitry disables actuated valves in the tool string path. In other embodiments the circuitry may only disable certain operations of the actuated valves, while allowing others to function. In another embodiment, the circuitry may actuate more or more of the actuated valves to be positioned in a desired configuration.

In another embodiment, if valves are positioned outside the immediate area of the lubricator, additional monitoring of the tool string location (for example by knowing the length of the wireline or slickline) would allow for disabling of actuated valves based on proximity of the control valve to the tool string or its attached wireline.

One skilled in the art would appreciate that monitoring may be via an electronic sensor having a physical triggering element such as a contact switch, an electrical probe, or other sensing element that is repositioned, deformed, excited, activated, or otherwise triggered by the presence (or absence) of a proximate tool string.

In another embodiment, electrical induction may be employed by sensors to non-intrusively detect the presence/absence of equipment in the lubricator. Such an embodiment would have the additional advantage of not compromising the strength of the high-pressure containment vessels. Sensor triggering elements may detect the tool string through alteration of monitored characteristics such as optical interruption, magnetic induction, electrical conduction, acoustical resonance, etc.

However, in such an embodiment, care would be required to ensure sensors do not confuse the presence of a tool string with that of the wireline or slickline passing through the lubricator. One skilled in the arts would understand sensitivity adjustment and/or calibration procedures to identify a substantial mass difference or otherwise identify particular material compositions. The preferred embodiment reduces potential false triggers by utilization of a plurality of sensors, the specific quantity, deployment, configuration being depending on the reliability of the sensory method employed.

As an example, a contact switch extending outward from an interior wall toward the center of a riser would be deflected by a tool string occupying that interior space. An optical interrupter positioned across the interior of a riser would likewise detect a tool string occupying the interior space.

In another example, a plurality of optical interrupters may be positioned, such that all of the sensors would not be impeded by a tool string. This allows comparisons between the plurality of interrupters to distinguish true and false triggers or identify sub-optimal conditions impairing reliable detection.

In another example, the movement of a tool string, (usually having a generally cylindrical shape and primarily of metallic composition) can induce an electro-magnetic change in a coil sensor. One skilled in the arts would recognize other characteristics that may be monitored by sensors for varying situations.

Tool strings comprised of electronics, hydraulics, and or other components which may move, change, adjust, or otherwise produce emissions that can be detected by sensors specific to the configuration. In a preferred embodiment, the sensor utilized may be configurable during deployment for a situation dictated by the specific equipment.

In another embodiment the sensors may detect movement of the tool string such as induction of an electrical/magnetic signal as a tool string moves past the sensor inducing a change to a triggering element through the riser to a sensor attached to the external surface. One skilled in the arts would appreciate that a plurality of such sensors and the order triggered could identify direction of movement.

As an example, an inductive sensor would detect change to a magnetic field inducted by a moving tool string. Two optical sensors placed at different points along the length of a riser would allow detection of a tool string leaving or entering the lubricator and determine which had occurred by the order of their triggering.

In another embodiment, sensor may be removably attached to the riser's external surface, such as by Velcro™ or elastic bands, adhesive, clamps, etc. In another embodiment the sensors may be incorporated into a connector sub to be installed between other components in the lubricator assembly. In another embodiment, sensors may be positioned above and below the tool trap or may work in conjunction with the tool trap's flap operation to detect tool string movement.

For example, a logic control may monitor tool trap operations to determine state changes. When the tool trap opens, it is possible for the tool string to pass. Therefore, an immediate check of the sensor to determine that the tool string is in the riser indicates it may be about to enter the wellbore. In response, the logic control would disable valve closing, and possibly verify the positions of various actuated valves before enabling other equipment or signaling clearance for the tool string to enter the wellbore.

When the tool trap closes, a check of the sensor showing the tool string is in the riser means it is essentially trapped there, unable to move into the wellbore. So, it is safe for the logic control to enable all valve controls, and optionally trigger closure of the master valve.

This logic ensure actuated valves are disabled before the tool string begins leaving the riser and are not enabled until the tool string is secured back in the riser. In another embodiment, the logic may be enhanced to control specific operations, to allow actuated valve closings are disabled preventing tool string damage, but openings are controlled by users.

In another embodiment, the logic may be further enhanced to automate valve actuations, ensuring a clear passage into the wellbore, or delaying openings until the tool string position requires a valve activation. An alternative lubricator may utilize a wire cutter configured to monitor BOP control signals, emergency sensors, or manual switches which signal a need to override wireline operations. An override, as described above, could be configured for emergency purposes. The act of someone being required to initiate an override ensures the valve operation was intentional and necessary, rather than carelessness.

By implementing an override for emergencies, the control logic can, in response to an override signal, if the tool string is not in the lubricator: 1) activate the wireline cutter, 2) delay to allow the tool string to drop, then 3) close the master valve and 4) enable all other actuated valves that may be disabled by the logic control, and 5) optionally move one or more actuated valves a pre-programmed position. This allows the safety measure of BOPs to operate in an emergency but controlled by wireline operators aware of current situations rather than, for example, as an automated test triggered by remote operators unaware of current operations.

The delay between activating the wireline cutter and closing the master valve/enabling the BOPs may be minimal, or substantially non-existent. The intent of a delay is to allow the tool string to fall down the well bore, pulling the severed wireline free of valve bodies, which may be compromised by the presences of the wireline or tool string. This is because the specific location of the tool string in not known, only that it is not in the lubricator, and therefore it may potentially be in a position compromising to BOP operations.

DETAILED DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an exemplary arrangement of common components typically incorporated into a lubricator, though variations would be dictated by the specific intended task. The lubricator's (100) bottom element is a well head flange adapter (40) to mate the lubricator (100) to a well head, Christmas tree, diverter, drilling platform, etc., (“the wellbore”).

The purpose of the lubricator (100) is to allow wireline operations to introduce tool strings into the well bore. A well has various configurations and locations for connection, but a lubricator (100) may have its own controls/master valve(s) (35). These master valve(s) (35) may vary in number, type, and arrangement but serve the purpose of closing off the lubricator (100) from the wellbore. They also may be of manual, electrical, or hydraulic operation, and must be operationally tested after installation.

A tool trap (30) is generally positioned above the master valve (35) to protect its inner seals from damage caused by a tool string's impact. The tool trap (30) also prevents the loss of a tool string down a wellbore if the wire strips. A tool trap (30) may be manually, electrically, or hydraulically operated, and generally is configured to return to and remain in a closed position after activation.

A lubricator's riser or simply riser (20) allows the wireline tool string to be raised above the master valve (35) prior to and after wireline operations and therefore enable the master valve (35) to be opened and closed allowing entry of the tool string into the wellbore, and close off pressure upon its exit from the well bore.

The functional requirements of master valve (35) logically require the risers (20) to be positioned so as to allow the tool string to be lifted above the BOPs and master valve (35) to close off the wellbore during wireline operations.

Risers (20) may also be supplemented with the inclusion of other components: including but not limited to: wire cutter, tool clamp, tool catcher, etc., none of which are shown here for simplicity. The lubricator (100) is generally capped with a grease injection control head (10) or a stuffing box (7) and sheave/pulley (5) for introduction of the wireline, which may be mated to the lubricator (100) by a sub adapter (15).

FIG. 2 illustrates a lubricator supported atop a Christmas tree by a telescoping gin pole. A gin pole (60) is attached to a Christmas tree (50) to support a rope block (55) that lifts and supports a lubricator (100) for connection of it's well head adapter flange (40) to the top of the Christmas tree (50). Once a lubricator (100) is positioned, a wireline (70) attached to a tool string located in the lubricator's (100) risers (20, not labeled) can be used to move a tool string in and out of the wellbore.

A hay-block or floor pulley (65) is generally used to direct the wireline (70) down to a position where it is horizontal to the Christmas tree (50). This shifts the point of wireline (70) pulling force from the top of the lubricator (100) down toward the master valve (35) and adapter flange (40) near the well head's tree (50) reducing side loading of the lubricator (100).

FIGS. 3A and 3B show an instrumented riser for detecting the presence of a tool string in accordance with an exemplary embodiment of the innovation. A riser (20, see previous FIG.) may be instrumented with sensors (210) to create an instrumented riser (200). The sensors (210) detect the presence or absence of a tool string (150) within the instrumented riser (200).

FIGS. 3A and 3B show an embodiment of a physically switched sensor (210A) which comprises a physical plunger (215) shrouded behind a guiding spring/shield (220). The plunger (215) depresses to switch the sensor (210A) indicating the absence or presence of a tool string (150) within the instrumented riser (200). Entry of the tool string (150), deflects the spring/shield (220) which depresses the plunger (215) triggering the sensor (210A). Exiting of the tool string (150), allows the plunger (215) to reset the spring/shield (220) toward the middle of the riser's (200) internal cavity.

FIGS. 4A and 4B show alternative embodiments of instrumenting a lubricator riser for detecting the presence of a tool string within the riser's internal cavity in accordance with an exemplary embodiment of the innovation. Sensors (210) in this embodiment have emitters (210B) and detectors (210C) which transmit (255) across the interior space of the riser (200). A tool string (150) interrupts the signal (255) indicating the presence of the tool string (150).

In another embodiment sensors (210) may be one or more passive receivers (210D) positioned along the external surface of a riser (200). These sensors (210) may detect sound, magnetism, electrical emissions, inductance, etc. through the riser (200) body.

FIG. 5 shows a partial cutaway view of a manually operated tool trap instrumented in accordance with an exemplary embodiment of the innovation. A tool trap (30, see prior FIG.) is instrumented with a sensor (330) to create an instrumented tool trap (300). A sensor (330) is triggered by changing the position of the flapper (340).

Flappers (340), shown here in the open position, are generally configured to be stable in the closed position. The embodiment illustrated shows a manual handle (310) lifted to open the flapper (340) and trigger the sensor (330). Releasing the handle (310) causes it to drop, returning the flapper (340) to the closed position, which is also detected by the sensor (330). In one embodiment the sensor may be passive so it must be polled to determine current position. In another embodiment an active sensor may transmit a signal upon changes in state.

FIG. 6 shows a partial cutaway view of a mechanized or manually operated tool trap instrumented in accordance with an exemplary embodiment of the innovation. The instrumented tool trap's (300′) sensor (330) detects the position of the flapper (340).

The embodiment illustrated has an activator (320) which operates the same mechanism as the manual handle (310) to open the flapper (340) detected by the sensor (330). Releasing the handle (310) or de-energizing the activator (320) causes the flapper (340) to return to the closed position, again detected by the sensor (330).

FIG. 7 shows an exemplary configuration for utilizing instrumented risers and electronic controllers for an implementation in accordance with the innovation presented herein. The control system (400) implementation illustrated has a control unit (410) which implements a programmable logic system having input signals (420 & 420′) from sensors (210, and 330, internal to 300) and output signals (430, 430′, & 430″) for controlling various functions.

In the illustrated system (400), a dedicated logic controller regularly reads the sensors (210) of the instrumented riser (200). Upon detecting an empty riser (200) the controller sends output signals (430 & 430′) to selectively disable or manipulate actuated valves (35 & 45). This may be a direct signal (430) to a master valve (35), or an indirect signal (430′) to a hydraulic unit (440), or other controller providing hydraulic motive power for operations (450) to BOPs (45).

In an alternative implementation of the illustrated system (400), a dedicated logic controller may be triggered by an input signal (420′) from an instrumented tool trap (300) when opened by either the hydraulic mechanism or the manual handle (310). Upon sensing the tool trap (300) has opened, the control unit (410) sends output signals (430 & 430′) disabling the one or more operations of various actuated valves (35 & 45). In an embodiment, the control unit (410) is configured to open and/or disable actuated valves (35 & 45) to prevent closure during tool string work of a wireline operation involving a tool string deployed down a wellbore.

When the tool trap (300) flapper (340) closes, the control unit (410) reads the sensor(s) (210) of the instrumented riser (200). If the tool string (150, not shown) is detected, then the valves may be enabled. Otherwise they remain disabled. So, the actuated valves are only enabled upon closing of the tool trap (300) flapper (340) and confirmation of the tool string (150, not shown) being in a safe location.

An override command in the control unit (410) may exist for emergencies. This override command can be trigger by other sensors, a manual panic switch, a dead-man switch, or other situations indicating an emergency requiring close off of a well. The control unit (410) first detects if the tool string (150, not shown) is in the riser (200) and the tool trap (300) is closed, which would mean any BOPs should be enabled. However, the control unit (410) may also be configured to signal the BOPs to close off the well in response to an override command from the control unit (410) rather than waiting for secondary activation of the BOPs.

If the control unit (410) does not detect the tool string (150, not shown) in the riser (200), it would first send a command (430″) to the wireline cutter (215) to sever the wireline and drop the tool string (150) down the wellbore before proceeding with the valve operations described above.

The diagrams represent exemplary embodiments of the present innovation and are provided as examples which should not be construed to limit other embodiments within the scope of the innovation. Physical elements should not be interpreted as to-scale and should not be construed to limit the innovation to the particular proportions, quantities, or configurations illustrated. Elements illustrated in singularity may be implemented in a plurality. Elements illustrated in plurality may vary in count. Illustrated forms may vary in detail, and any numerical data values provided, or other specific information is illustrative of possible implementations to be interpreted in the broadest scope possible and not limiting of the innovation. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Claims

1. An apparatus for wireline operations comprising:

a lubricator having one or more risers;

an optional tool trap;

one or more sensors for detecting a tool string;

one or more actuated valves, one being a master valve between the lubricator and the wellbore;

a programmable logic system;

wherein the logic system is programmed to monitor the sensor, and

enable or disable operation of the one or more actuated valves.

2. An apparatus as described in claim 1 wherein the one or more actuated valves are electrically, hydraulically, or pneumatically actuated.

3. An apparatus as described in claim 1 wherein enable or disable operation of a valve comprises controlling an energy source of the articulated valve.

4. An apparatus as described in claim 1 wherein the one or more actuated valves are manually operated valves with actuated interlocks to restrict manual operations.

5. An apparatus as described in claim 4 wherein the articulated interlocks comprise an indicator to authorize or prohibit manual operation of the valve.

6. An apparatus as described in claim 3 wherein the logic system further comprises:

an override, wherein the override: enables energy sources to one or more actuated valves; closes the master valve, and optionally sets one or more of the actuated valves to known states.

7. An apparatus as described in claim 1 wherein the sensors detect the presents or absence of the tool string in one or more of the risers.

8. An apparatus as described in claim 1 wherein the sensors detect the movement of the tool string past one or more of the sensors.

9. An apparatus as described in claim 8 wherein a plurality of sensors detecting the movement of the tool string determines the direction of the movement of the tool string.

10. An apparatus as described in claim 9 wherein the sensors identify the movement of the tool string into or out of the one or more risers.

11. An apparatus as described in claim 9 wherein the sensors identify the movement of the tool string through the tool trap.

12. An apparatus as described in claim 1 wherein a sensor is mechanical.

13. An apparatus as described in claim 1 wherein a sensor is magnetic.

14. An apparatus as described in claim 1 wherein a sensor is passive.

15. An apparatus as described in claim 1 wherein a sensor is removably attached to an external surface of the lubricator.

16. An apparatus as described in claim 1 wherein a sensor is internal to the lubricator.

17. An apparatus as described in claim 8 wherein the lubricator further comprises a connector sub having sensors.

18. An apparatus as described in claim 17 wherein the connector sub is between two risers.

19. An apparatus as described in claim 17 wherein the connector sub is between the lowest riser and the tool trap.

20. A method of preventing valve operations during wireline operations comprising:

monitoring the movement and/or position of a tool string;

determining the relationship of the tool string to one or more actuated valves;

disconnecting or connecting motive power to the one or more actuated valves.