METHOD OF CAPTURING GASSES FROM UPSTREAM WELL DURING PLUG DRILL-OUT OPERATIONS, WITH THE USE OF SEPERATORS, REGULATION CONTROL, FLARING AND CROSS-COMPRESSION TECHNIQUE

Abstract

A method to capture gasses from an upstream underground well during a frac plug drill-out operations, with the use of multiple separation vessels, cross-compression units, flaring and regulation control. The method allows capturing gasses out of a fluid mixture, from the underground well, with flowing the fluid mixture from the underground well towards sequentially a mud-gas separation vessel and a separation vessel, whereby the fluid mixture contains a solid and liquid phase and a gas phase. The method also includes separating the fluid mixture into the solid and liquid phase and the gas phase. The method further includes simultaneously flowing the gas phase towards a flare for burning and towards a sales line, through one or more cross-compression units. One goal of the method may be to recover most of the gas phase towards the sales line for valuing it instead of discharging it to the atmosphere.

Description

BACKGROUND

The field of use includes the capturing of gasses from the upstream well during the frac plug drill out operations. Typical upstream wells will contain gasses, liquids, and solids. These liquids and solids are typically not permitted into the onsite sales line in large quantities, so they may need to be separated and sent to an additional pipeline or vessel. Example of additional vessels may be either adjoining pipelines, vessels, or tanker trucks.

Most wells, during the frac plug drill out operation currently flare or vent all gasses produced. They are not currently capable of transferring these gasses to the sales line, as one limitation may that the sales line pressure would be greater than the pressures being produced downstream from the onsite mud gas separator.

A typical existing method used to de-gas a well during the frac plug drill out operation is to use a flare stack, designed to burn the evacuated gasses. During this process, the flare typically receives 100% gas throughout the entire drill out process. From the well there may be a mud gas separator to remove the solids and most of the liquid from the gas. The gas may then be sent to a secondary separation vessel, piped in upstream of the flare which would catch most liquids and solids that make it out of the mud gas separator. Fluids collected in this separation vessel may then be emptied manually by on-site labor.

When using this existing method, all the gas product being produced by the well may be treated as waste and consumed by the flare. Therefore, all value of the gas product inside the well may be lost and the combustion of the entire volume of product within the well may increase the amount of released emission in the atmosphere.

Another existing prior-art may include the use of a multi-phase wielding unit to push product from the well into an sales line. These units may be most effective during the portion of the operation when the gas pressure from the well is strong enough to overcome the current pressure within the sales line. If the pressure from the wielding unit cannot overcome the pressure within the sales line, the gasses may be sent to the flare. The window that the wielding unit is able to send gas to the sales line may be very small.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed description of the embodiments of the disclosure, reference will now be made to the accompanying drawings.

FIG. 1 represents a schematic of the components and connections related to the proposed invention.

FIG. 2 represents a detailed method flowchart with the major steps of the invention linked to FIG. 1.

FIG. 3 represents a schematic of the components and connections as depicted on FIG. 1 with possible sensors, parameters and connection for a method regulation control.

FIG. 4 represents a possible regulation flow diagram linked with the proposed invention.

DETAILED DESCRIPTION

It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention.

Even if advantages and other features will become apparent from the following schematics, description and proposed claims, the proposed list of advantages may be limiting.

The proposed invention process may use a combination of some elements of the methods described in the existing art section, while adding specific usage, features and control method.

One advantage of the proposed invention would be to capture as much gas as practical from the well, while completing the gas capture in the same time frame as a typical flaring operation would take. The proposed invention may therefore result in a higher proportion of gas recovery from the well, typically between 80% and 100%, while limiting the combustion of hydrocarbon product in the atmosphere, and while keeping the reduced time of straight flaring operation. Overall, the proposed invention may improve both the financial and environmental aspects of the frac plug drill out operation.

The following item numbers refer to the FIGS. 1 to 4, which are depicting the proposed invention.

As depicted in FIG. 1, The proposed invention process may include a separation vessel 1 and a mud-gas separation vessel 48, inline between an underground well 24, a sales line 4 and a flare 7. The separation vessel 1 may also be considered as a filter vessel.

The underground well 24 may have various shapes. As represented in FIG. 1 as a non-limiting example, the underground well 24 may include a horizontal or deviated section 25. Typically, frac plugs may be placed during fracking operation in the horizontal section 25 of the underground well 24. Upon completions of the fracking operations, the plugs may be drilled-out or pushed towards the well bottom, to facilitate the production of the well. The drill-out operations are typically done with a coiled-tubing drilling unit. Some plugs may also be dissolvable with the ability to degrade inside the fluid within the underground well 24.

The underground well 24 may be the producer of gas, that needs to be captured. The underground well 24 may be filled with a fluid mixture 26, including a liquid and solids phase as well as a gas phase. Depending on the composition fluid mixture 26 and other parameters like the geographical region, geological parameters, depth, the pressure inside the underground well 24 may vary. The gas phase may also be designated as vapor.

The flow equipment displayed on FIG. 1, including the separation vessel 1 and the mud-gas separation vessel 48, may typically be located at proximity of a well head 21 and above ground level 54. A fluid mixture flow line 12 may be connected to the well head 21 through an isolation valve 5. The fluid mixture flow line 12 may be used to flow the fluid mixture 26 out of the underground well 24 and towards the mud-gas separation vessel 48.

The mud-gas separation vessel 48 may be used to separate fluid mixture 26 into an intermediary gas phase 14 and a solid and liquid phase 15. The solid and liquid phase 15 may have typically a higher density as the intermediary gas phase 14, therefore the solid and liquid phase 15 may be located at the bottom of mud-gas separation vessel 48. At the bottom of mud-gas separation vessel 48, a bottom connection 20 may be linked to an open tank 39, which may be dedicated to the capture and storage of the solid and liquid phase 15.

The intermediary gas phase 14 may be located at the top of the mud-gas separation vessel 48 and be linked to a vessel top connection 2. The vessel top connection 2 may convey the intermediary gas phase 14 towards the separation vessel 1, through a flow line 11. The intermediary gas phase 14 may include both a gas phase 16 and liquid phase 17, as the mud-gas separation vessel 48 may have not isolate the gas phase completely through a first separation process phase through the mud-gas separation vessel 48. Therefore, the separation vessel 1 may then be used as a second separation process phase to further isolate the gas phase 16 from the liquid phase 17.

Downstream of the separation vessel 1, a connection point 27 may connect the flow of the gas phase 16 towards to a flare section 28, before reaching the cross-compression unit 10. The flare section 28 may include a flow-control valve 9, which may regulate a gas phase 16 to flow to the flare 7. The flare 7 may be a device to combust, oxidize or vent the excess gas, represented as gas phase 16 within the separation vessel 1. The flare 7 may also be designated as flare stack, combustor, incinerator, thermal oxidizer, burner, vent stack, stack pipe or riser.

Further downstream of the separation vessel 1, passed the connection point 27, a cross-compression unit 10 may be used to flow the gas phase 16 out of the separation vessel 1, towards the sales line 4, through an adjoining gas section 29. The cross-compression unit 10 may also help the flow of the fluid mixture 26, first through the mud-gas separation vessel 48, allowing the first separation process phase, and then further through the separation vessel 1, allowing the second separation process phase. The cross-compression unit 10 or a group of cross-compression units 10 may move the gas phase 16 present inside the separation vessel 1 into the sales line 4 through an adjoining gas section 29. The gas phase 16 may pass through a check valve 18 and connect to the sales 4 through an adjoining section connection valve 6. The check valve 18 may only allow passing the gas towards one downstream direction and therefore may avoid any return of the gas phase 16 back to the cross-compression unit 10.

The flare 7 may mainly be used to combust the excess of the gas phase 16, which the cross-compression unit 10 may not safely handle from a rate or volume point of view towards the sales line 4.

The separation vessel 1, also designated as knock-out tank, or gas buster, or slug catcher, or trap tank, filter unit, may have the shape of a barrel or tank, either in a vertical position or horizontal position. The separation vessel 1 would typically include a feed-in connection, with a flow line 11. The typical function of the separation vessel 1 would be to separate liquid phase 17 from gas phase 16 within the vessel. A liquid to gas level within the separation vessel 1 would be symbolized as level 13. Different types of separation vessel 1 could be used, such as mechanical, gravity or centrifugal. The usage, shape and types of separation vessel 1 could depend on the proportion of fluid versus gas to be separated, the type of fluid or gas such as the expansion ratio between liquid and gas, the quantities of mixture being separated, the time and capacity of operation, the environment parameters such as pressure and temperature.

The cross-compression unit 10 may be operated manually, remotely, or automated. The cross-compression unit 10 may function through pneumatic, pressure, electrical, mechanical, or other hydraulic means. The type of the cross-compression unit 10 may include a piston pump, a screw pump, a diaphragm pump, a centrifugal pump, a gear pump, a lobe pump, a metering pump, a progressive cavity pump, a plunger pump or multi-phase pump. The cross-compression unit 10 would displace the gas phase 16 at a rate, typically between 0 and 2,000 mcf per day or thousand cubic feet per day [0 to 56,600 cubic meter per day]. FIG. 1 displays a single cross-compression unit 10, though more than one cross-compression unit 10 may be present, like two or more cross-compression units in series or in parallel. Additional cross-compression units may typically be used to handle higher gas rates compared to the rate that one single cross-compression unit may handle.

The sales line 4 may have the shape of pipeline as depicted in FIG. 1, or the shape of a tank or vessel. The sales line 4 may be itself connected to a secondary adjoining vessel, not shown in FIG. 1, which would be used as a recovery vessel.

The flow control valve 9 may be a device or group of devices to restrict or control the flow of gas flowing to the flare 7 through the flare section 28. The flow control valve 9 may be operated manually, remotely or automated. The operation mode of the flow control valve 9 may be through pneumatic, pressure, electric, mechanical, hydraulic or manual means. The flow control valve 9 may be designated as regulator, choke, throttle valve, float valve, gate valve, globe valve, butterfly valve, pinch valve, diaphragm valve, reducing valve, regulator valve or needle valve.

The flow of gas through the flare section 28, controlled by the flow control valve 9, may correspond to excess gas volume that the cross-compression unit 10 may not safely handle. The objective of the process may to capture the greatest amount of volume from the underground well 24 as possible, while keeping operating within the limits of the cross-compression unit 10, including for example the pressure and the volume. Keeping a high flowrate out of the underground well 24 may ensure the transfer of more gasses to the sales line 4.

The liquid phase 17 may be displaced by a fluid pump 37 out of the separation vessel 1 from a vessel bottom connection 3, typically located at the bottom of the separation vessel 1. The liquid phase 17 may therefore be reinjected back into the mud-gas separation vessel 48 for a complementary separation within the mud-gas separation vessel 48. Alternatively, the liquid phase 17 may be removed from separation vessel 1 by use of a vacuum truck 38. A three-way connection valve 8 may be used to direct the liquid phase 17 either towards the mud-gas separation vessel 48 or towards the vacuum truck 38.

FIG. 2 depicts a flowchart sequence method, related to the flow schematic described in FIG. 1.

A first step 101, with starting the sequence method, includes flowing the fluid mixture 26, present in the underground well 24 towards a two-steps separation process, with the equipment positioned downstream of the well head 21. The fluid mixture 26, from the underground well 24, includes the solid and liquid phase 15 and the gas phase 14. The fluid mixture 26 is the result from the drill-out operation inside the underground well 24, as well as production fluid which may include gasses and liquids, such as hydrocarbons in a liquid or vapor stage.

The two-steps separation process includes a first step using the mud-gas separation vessel 48 and a second step using the separation vessel 1.

The flow of the fluid mixture 26 from the underground well 24 is initiated through the cross-compression unit 10, whereby the cross-compression unit is positioned downstream of both the mud-gas separation vessel 48 and the separation vessel 1. The flow of the fluid mixture 26 from the underground well 24 towards the well head 21 may be also initiated from an overpressure of the fluid mixture 26 present at the bottom or the horizontal section 25 compared to the hydrostatic pressure of the fluid column, due to the depth of the underground well 24. Therefore, if the pressure at the well bottom is higher than the hydrostatic pressure of the fluid column, the fluid mixture 26 may flow partially by itself. Other mean of the flow of the fluid mixture 26 may be also possible, such as submersible pumps, artificial lift, pumping techniques, as well as the use of multiple tubing's within the underground well 24, having multiple flow section such as an annulus section versus a tubing or a liner section.

In step 102, the fluid mixture 26 is separated into the intermediary gas phase 14 and the solid and liquid phase 15, through the mud gas separation vessel 48. This first separation into the intermediary gas phase 14 and the solid and liquid phase 15 corresponds to the first step of the two-steps separation process. Through the first step of the two-steps separation process, a remaining liquid phase remains as part of the intermediary gas phase 14. The intermediary gas phase 14 is further conveyed towards the separation vessel 1, to be further separated in step 103.

In step 103, the intermediary gas phase 14 is separated into the gas phase 16 and the liquid phase 17, inside the separation vessel 1. This second separation corresponds to the second step of the two-steps separation process.

Further, in step 103, the liquid phase 17, located at the bottom of the separation vessel 1, is pulled out of the separation vessel 1 through the vessel bottom connection 3 to be flown back towards the mud-gas separation vessel 48, which was used in step 102, as the first step of the two-steps separation process. The reinjection of the liquid phase 17 towards the mud-gas separation vessel is performed with the use of the fluid pump 37.

Alternatively, the fluid phase 17 can be pulled by the vacuum truck 38. The vacuum truck 38 can be used as the storage for the fluid phase 17. The direction of the flow of the fluid phase 17 can be selected through the position of the three-way connection valve 8. Therefore, depending on the position of the three-way connection valve 8, the fluid phase 17 may be directed back towards the mud-gas separation vessel 48 or towards the vacuum truck 38.

In step 104, the gas phase 16 is flown from the separation vessel 1 towards both the sales line 4 and the flare 7, using the cross-compression unit 10.

The flow of the gas phase 16 is separated in a main flow within the adjoining gas section 29 and in an excess flow within the flare section 28. The main flow passing through the adjoining gas section 29 will flow towards the sales line 4, through the adjoining section connection valve 6. The excess flow passing through the flare section 28 will flow towards the flare 7, regulated by the flow control valve 9.

Steps 101, 102, 103 and 104 may occur simultaneously or sequentially. Typically, both steps of the two-steps separation process may occur simultaneously, as well as the flow the gas phase 16 towards the sales line 4 and the flare 7.

As depicted in FIG. 1 and further in FIG. 3, the separation vessel 1 may include a level indicator 60. The level indicator 60 may indicate visually the position of a level 13, showing the interface between the liquid phase 17 and the gas phase 16. The level indicator 60 may correspond to the position of a floater linked to the liquid phase upper surface present inside the separation vessel 1. At the position of the level indicator 60, a level controller may also be present within the separation vessel 1. The level controller may include a sensing unit able determine the level 13 and indicate the amount of the liquid phase 15 as well as of the gas phase 16, within the separation vessel 1. The level controller may be linked to a float gauge as well as to other types of ultrasonic or pressure measurement to determine the level 13. The level controller may be connected to an electronic recorder or converter, which may convert the physical level 13 in a digital or electronic form. The electronic recorder may itself be linked to a feedback connection which may communicate for example with the cross-compression unit 10 or to the flow control valve 9 or to the fluid pump 37. Other communication may adjust the position of various valve connections such as 2, 3, 5, 6, 8, 20, 27. The feedback connection may have the form of a wire connection or a wireless connection.

FIG. 3 represents the component schematic of FIG. 1 with possible sensors, parameters for the method regulation control.

Parameters 30 represent the variables which may be significant for the flow line 11, between the mud-gas separation vessel 48 and the separation vessel 1. Parameters 30 may be described as following:

Q_A would represent the flowrate of the intermediary gas phase 14, further present within the separation vessel 1.

P_A would represent the pressure of the intermediary gas phase 14 within the flow section 11.

R_A would represent the gas to liquid ratio within the intermediary gas phase 14, flowing inside the flow section 11. A R_A of 1 would mean a full gas phase, and a R_A of 0 would mean a full liquid phase.

Parameters 31 represent the variables which may be significant within the separation vessel 1. Parameters 31 may be described as the following:

P_B would represent the pressure of the intermediary gas phase 14 within the separation vessel 1. Standard P_B pressure would typically be close to the pressure P_A.

R_B would represent the gas to liquid ratio, present within the separation vessel 1. A R_B of 1 would mean a full gas phase, and a R_B of 0 would mean a full liquid phase. The ratio R_B would relate directly to the level 13 within the separation vessel 1. The ratio R_B could be derived from the level indicator 60 or the level controller, as described in FIG. 1.

Parameters 32 represent the variables which may be significant for the gas phase, between the separation vessel 1 and connection point 27. Parameters 32 may be described as the following:

Q_C would represent the flowrate of the gas phase flowing outside the separation vessel 1.

P_C would represent the pressure of the gas phase flowing outside the separation vessel 1.

Parameters 33 represent the variables which may be significant for the gas phase 16 flowing through the adjoining gas section 29, after passing through the cross-compression unit 10. Parameters 33 may be described as the following:

Q_D would represent the flowrate of the gas phase flowing inside adjoining gas section 29.

P_C would represent the pressure of the gas phase flowing inside adjoining gas section 29.

FIG. 4 represents a regulation flow diagram as a part of the proposed invention.

A primary goal of the regulation method, represented as a regulation loop 80 in FIG. 4, as steady mode, includes regulating R_B, or the gas to liquid ratio within the separation vessel 1.

R_Bactual 81 would represent an input or actual measured ratio or level inside the separation vessel 1. R_Bcommand 82 would represent a target ratio or level considered as a command. R_Bcommand could include a wished ratio, typically between 0.1 to 0.4, as well as a R_Bmin, representing the minimum ratio for an optimum operation, and a R_Bmax, representing the maximum ratio for an optimum operation. A typical R_Bmin value may be between 0.05 and 0.15. A typical R_Bmax value may be between 0.3 and 0.5. The consequence of the R_B regulation may be to maintain P_A above a predetermined limit. The difference between R_Bactual 81 and R_Bcommand 82 would be calculated as the regulation difference ε83. A typical goal of the regulation loop 80 may be to keep the regulation difference ε83 as small as possible or within predetermined limits corresponding to the minimum and maximum wished ratio R_Bmin and R_Bmax.

The regulation loop may include R_Bactual 81 as input. A first output action 85 may be the adjustment of the adjustment of the speed or flowrate of the cross-compression unit 10 and of the fluid pump 37, which may directly influence Q_C. A second output action 86 may be the adjustment of the opening position of the flow control valve 9, which may directly influence Q_D. A secondary goal of the regulation loop 80 may be to keep Q_D as high as possible, while having Q_C as small as possible. This way, most of the gas phase 16 may be recovered towards the sales line 4, instead of being flared through the flare 7. Typically, a goal of Q_D above 80% compared to Q_C below 20% may be achieved.

The regulation loop 80 may be controlled by a control system 84 performing at a predetermined frequency, either manual or automatic, typically between once every 1 second to once every 10 hours.

The control system 84 may also control the opening/closing position of the valve connections, which may have an influence on the various pressures and flowrates within the flow system, namely P_A, Q_A, P_B, Q_C, P_C, Q_D, PD. The valves which may be part of the regulation system includes the isolation valve 5, the vessel top connection 2, the vessel bottom connection 20, the connection point 27, and the adjoining section connection valve 6.

Other regimes may also be part of the regulation loop 80, with additional output and specific actions. Other regimes may include a start regime or an end regime. Example of a start regime, which may be performed as part of the process, may include the removal of contaminates such as air, nitrogen within the separation vessel 1. Other start regimes may include the purge of the flowlines 11, 12, 27 and 29.

Claims

1. A method to capture gasses out of a fluid mixture, from an underground well, during a frac plug drill-out operation comprising: flowing the fluid mixture from the underground well towards sequentially a mud-gas separation vessel and a separation vessel, whereby the fluid mixture contains a solid and liquid phase and a gas phase;separating the fluid mixture in the solid and liquid phase and the gas phase, inside sequentially the mud-gas separation vessel and the separation vessel;simultaneously flowing the gas phase towards a flare for burning and towards a sales line, through one or more cross-compression units.

2. The method of claim 1, whereby flowing the gas phase towards the flare for burning, includes passing through a flow control valve.

3. The method of claim 1, whereby the mud-gas separation vessel and the separation vessel are positioned in series, whereby one output of the separation of the fluid mixture inside the mud-gas separation vessel is an intermediary gas phase, whereby the intermediary gas phase is the input of the separation vessel.

4. The method of claim 3, whereby the intermediary gas phase is separated into a liquid phase and into the gas phase, inside the separation vessel.

5. The method of claim 4, whereby the liquid phase is pulled out of the separation vessel towards either a vacuum truck or back to the mud-gas separation vessel through a fluid pump.

6. The method of claim 2, whereby adjusting the volumetric flow rate of the gas phase towards the flare versus adjusting the volumetric flow rate of the gas phase towards the sales line is achieved by both adjusting the flow control valve and adjusting the rate of the one or more cross-compression units.

7. The method of claim 1, whereby the sales line is used to recover and value the gas phase for future use.

8. The method of claim 7, whereby adjusting the volumetric flow rate of the gas phase towards the flare versus adjusting the volumetric flow rate of the gas phase towards the sales line, is achieved through a regulation method.

9. The method of claim 8, whereby the regulation method is manual or automated, whereby the regulation method is updated at a frequency between 1 sec and 10 hours.

10. The method of claim 8, whereby the regulation method achieves maintaining the ratio of the volumetric flow rate of the gas phase towards the sales line versus the volumetric flow rate of the gas phase towards the flare, at a wished ratio level, wherein a ratio level of 1 means 100% of the volumetric flow rate of the gas phase towards the sales line and 0% of the volumetric flow rate of the gas phase towards the flare,wherein the wished ratio level of volumetric flow rate of the gas phase towards the sales line, versus the volumetric flow rate of the gas phase towards the flare, is between 0.6 and 1.

11. The method of claim 10, wherein the volumetric flow rate of the gas phase towards the flare is considered as an excess product.

12. The method of claim 10, whereby the wished level of volumetric flow rate of the gas phase towards the sales line, versus the volumetric flow rate of the gas phase towards the flare, depends on the discharge rate of the one or more cross-compression units.

13. The method of claim 5, whereby the separation vessel includes a level indicator or a level controller, wherein the level indicator or the level controller allows determining the position of the liquid phase versus the gas phase inside the separation vessel.

14. The method of claim 13, whereby the level indicator or the level controller provides a feedback signal to operate the fluid pump for the back pull of the fluid phase towards the mud-gas separation vessel or to operate the vacuum truck.

15. The method of claim 1, whereby the mud-gas separation vessel and the separation vessel are located on surface, at proximity of a well head of the underground well.