Riser isolation joint

Abstract

A well control system includes a rig, a subsea blowout preventer / wellhead assembly, a riser extending from the rig to a subsea BOP stack of the assembly, a riser joint including a first end connected to the riser, and second end configured to connect to the assembly, a plurality of fluid lines that exit the BOP stack and run along an outside of the riser joint and the riser to surface, a first plurality of isolation valves installed on a first fluid line of the plurality of fluid lines, and a second plurality of isolation valves installed on second fluid line of the plurality of fluid lines. The BOP stack has a first working pressure rating, the first and second plurality of isolation valves have a second working pressure rating, and the second working pressure rating is higher than the first working pressure rating.

Description

RISER ISOLATION JOINTCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of and priority to U.S. Provisional Patent Application No. 63 / 609,400, entitled “Depth Adjusted Working Pressure for High Pressure and High Temperature Well Control Systems,” filed December 13, 2023, and U.S. Provisional Patent Application No. 63 / 643,505, entitled “Riser Isolation Joint,” filed May 7, 2024. Each of these applications is incorporated by reference herein in its entirety.BACKGROUND

[0002] A well construction system may include a well control system for maintaining well pressure control. The well control system may include a blowout preventer (BOP) stack installed on a wellhead to seal and control an oil and gas well during drilling operations. A drill string may be suspended inside a drilling riser from a rig through the BOP stack into the wellbore. A choke line and a kill line are also suspended from the rig and coupled to the BOP stack.

[0003] During drilling operations, drilling fluid, or mud, is delivered through the drill string, and returned up an annulus between the drill string and casing that lines the wellbore. In the event of a rapid influx of formation fluid into the annulus, commonly known as a “kick,” the BOP stack is actuated to seal the annulus. The kick may be circulated up to rig processing equipment. Alternatively, heavier drilling mud may be delivered through the drill string, forcing fluid from the annulus through the choke line or kill line to protect the well equipment disposed above the BOP stack from the high pressures associated with the formation fluid.SUMMARY

[0004] According to one or more embodiments of the present disclosure, a well control system includes a rig, a subsea blowout preventer (BOP) / wellhead assembly including a subsea BOP stack secured to a wellhead at a seabed of a well, a riser extending from the rig tothe subsea BOP stack, a riser joint including: a first end connected to the riser; and a second end configured to connect to the subsea BOP I wellhead assembly; a plurality of fluid lines that exist the subsea BOP stack and run along an outside of the riser joint and the riser to surface, a first plurality of isolation valves installed on a first fluid line of the plurality of fluid lines; and a second plurality of isolation valves installed on a second fluid line of the plurality of fluid lines, wherein the subsea BOP stack has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

[0005] According to one or more embodiments of the present disclosure, a riser joint includes a first end configured to connect to a drilling riser, a second end configured to connect to a subsea blowout preventer (BOP) / wellhead assembly, the subsea BOP I wellhead assembly including a subsea BOP stack secured to a wellhead at a seabed of a well, a choke line having a first plurality of isolation valves installed thereon; and a kill line having a second plurality of isolation valves installed thereon, wherein the subsea BOP / wellhead assembly that the second end is configured to connected to has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

[0006] A method according to one or more embodiments of the present disclosure includes installing a first plurality of isolation valves on a choke line of a riser joint, installing a second plurality of isolation valves on a kill line of the riser joint, connecting a first end of the riser joint to a drilling riser, connecting a second end of the riser joint to a subsea BOP stack, and securing the subsea BOP stack to a wellhead on the seabed, wherein the subsea BOP stack has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

[0007] A well control system according to one or more embodiments of the present disclosure includes a rig; a blowout preventer (BOP) stack secured to a wellhead at a seabed of a well; a riser extending from the rig to the BOP stack; and a choke / kill system including: a choke line leading from a first side outlet on the BOP stack, to a choke, and to a choke manifoldat surface; and a kill line leading from a second side outlet on the BOP stack to a pump at the surface, wherein the choke line and the kill line run along an outside of the riser from the BOP stack to the surface, wherein the BOP stack has a first working pressure rating, wherein the choke / kill system has a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

[0008] However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:

[0010] FIG. 1 shows a system schematic of a subsea BOP stack in a well control system according to one or more embodiments of the present disclosure;

[0011] FIG. 2 shows a riser choke / kill isolation joint according to one or more embodiments of the present disclosure; and

[0012] FIG. 3 shows a method according to one or more embodiments of the present disclosure.DETAILED DESCRIPTION

[0013] In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and / or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

[0014] In the specification and appended claims, the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting,” are used to mean “in direct connection with,” in connection with via one or more elements.” The terms “couple,” “coupled,” “coupled with,” “coupled together,” and “coupling” are used to mean “directly coupled together,” or “coupled together via one or more elements.” The term “set” is used to mean setting “one element” or “more than one element.” As used herein, the terms “up” and “down,” “upper” and “lower,” “upwardly” and “downwardly,” “upstream” and “downstream,” “uphole” and “downhole,” “above” and “below,” “top” and “bottom,” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure. Commonly, these terms relate to a reference point at the surface from which drilling operations are initiated as being the top point and the total depth being the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal, or slanted relative to the surface.

[0015] In general, embodiments of the present disclosure relate to well control systems. More particularly, one or more embodiments of the present disclosure relate to 15,000 psi (“15K”) rated working pressure (“RWP”) well control systems that have been modified to install a series of 20,000 psi (“20K”) rated isolation valves on the choke / kill lines of the riser, thereby creating a 20K rated riser choke / kill isolation joint (“RIJ”). As such, well control system components above the 20K rated RIJ, including the drilling rig and riser, will have a 20K RWP, and well control system components below the 20K rate RIJ, including the wellhead and the subsea BOP stack, will remain at the 15K RWP. According to one or more embodiments of the present disclosure, the subsea BOP stack is secured to the wellhead at a seabed of the well, thereby creating a subsea BOP I wellhead assembly, according to one or more embodiments of the present disclosure. Because well control system components below the 20K rated RU remain at 15K RWP, a traditional 15K rated subsea BOP stack may be used during the drilling and completion of wells where the anticipated wellbore pressure at the seabed of the well is greater than the RWP of the BOP stack, but less than the depth adjusted working pressure (“DAWP”), as further described below.

[0016] For applications where the wellbore pressure at the wellhead exceeds 350° / 15K psi, the US regulator for offshore operations (the Bureau of Safety and EnvironmentalEnforcement, or BSEE), requires that the well control system have a rated working pressure in excess of the anticipated wellbore pressure. That is, if the anticipated wellbore pressure exceeds 15K, the well control system needs to include a 20K rated BOP.

[0017] One or more embodiments of the present disclosure utilizes a traditional 15K well control system, including a 15K rated BOP stack, and the external seawater pressure to reduce the differential pressure across the barrier (wall) of the equipment, effectively utilizing what the industry refers to as DAWP.

[0018] For example, when testing a BOP on surface, the internal wellbore pressure is 15K, and the external pressure is about Opsi (round-off as it is actually about 14.7psia (atmospheric pressure) at sea level). However, when testing a BOP at depth, the hydrostatic pressure of seawater, which is approximately 0.45psi / ft of water depth, comes into play. So, if the BOP is at 10,000 ft water depth, the external pressure acting on the BOP is Pext = 0.45x10000 = 4500 psi. If the wellbore pressure is raised to 15,000 psia, and the external pressure acting on the BOP is 4500 psia, the pressure across the wall of the BOP is only 10,500 psia (15,000 psia - 4500 psia = 10,500 psia). The concept of DAWP implies that the rated working pressure of the BOP may be safely raised by the amount of external pressure available. In this example, the 15K RWP BOP would be acceptable for use at 19,500 psid (differential pressure).

[0019] As explained above, it may be acceptable to use a 15K rated BOP (and other properly designed components) of the well control system at the seabed when taking advantage of DAWP. However, during a well control event, the choke / kill system of the well control system, which begins at the side outlet of the BOP and ends at the choke / kill manifold at surface, may still experience a true 20,000 psia. This means that while the valves at depth could take DAWP into effect, the valves on surface would still experience the effects of higher wellbore pressures.

[0020] Thus, one or more embodiments of the present disclosure modifies a 15K rated RIJ by installing a series of 20K rated isolation valves on the choke / kill lines of the riser, thereby creating a 20K rated RIJ. As such, the 20K rated RIJ according to one or more embodiments of the present disclosure has the ability to isolate pressure differences in the choke / kill lines above and below the RIJ such that the subsea BOP stack below the RIJ can operate at a lower RWP (i.e., 15K) than the RWP of the riser and the drilling rig.

[0021] Referring now to FIG. 1 , a system schematic of a subsea BOP stack in a well control system according to one or more embodiments of the present disclosure is shown. Specifically, FIG. 1 shows which components of a 15K well control system would need to be upgraded to a 20K working pressure rating to comply with offshore operations regulations, thereby improving safety and protecting well control system equipment in case an adverse well control event occurs.

[0022] For example, at the surface 100, moonpool flexible lines, kill and choke lines, and the kill and choke manifold may be upgraded to a 20K RWP, according to one or more embodiments of the present disclosure. At the slip joint 102, kill and choke lines and the hands free goose neck may be upgraded to a 20K RWP, according to one or more embodiments of the present disclosure. With respect to CML / MPD (controlled mud level / managed pressure drilling) 104, the kill and choke lines may be upgraded to a 20K RWP, according to one or more embodiments of the present disclosure. At the drilling riser 106, kill and choke lines, and if applicable, floatation, may be upgraded to a 20K RWP, according to one or more embodiments of the present disclosure. At the subsea BOP stack 108, side outlet valves, kill and choke lines, kill and choke line connectors, and tester valves may be upgraded to a 20K RWP, according to one or more embodiments of the present disclosure.

[0023] According to one or more embodiments of the present disclosure, the choke / kill system, which may be upgraded to a 20K working pressure rating as previously described, may include choke / kill lines, valves, a choke, a choke manifold at the surface, and a kill pump at the surface, for example.

[0024] As previously described in view of FIG. 1, one of the components of a 15K well control system that would need to be upgraded to a 20K RWP to comply with offshore operations and regulations is the drilling riser 106. According to one or more embodiments of the present disclosure, the drilling riser 106 may be upgraded from a 15K RWP to a 20K RWP by installing a series of 20K rated isolation valves on the choke / kill lines of the drilling riser 106, thereby creating a 20K rated RIJ 200, as previously mentioned and as shown in FIG. 2.

[0025] Referring now to FIG. 2, the 20K rated RIJ includes a first end configured to connect to the drilling riser 106, and a second end configured to connect to the subsea BOP 108 / wellhead assembly, according to one or more embodiments of the present disclosure. As also shown in FIG. 2, the 20K rated RIJ 200 includes a series of 20K rated isolation valves 202installed on the choke line 204, and a series of 20K rated isolation valves installed on the kill line 206 of the drilling riser 106, according to one or more embodiments of the present disclosure. Each series of 20K rated isolation valves 202 may include a plurality of 20K rated isolation valves, such as a double gate valve, or any series of valves that have the ability to isolate pressure differences in the choke / kill lines above and below the RIJ such that components of the 15K well control system below the 20K rated RIJ 200, including the wellhead and subsea BOP stack 108, can continue to operate at 15K RWP, and components of the 15K well control system above the 20K rated RU 200, including the drilling riser 106, the drilling rig at surface 100, and all well control components disposed therebetween, may be upgraded to 20K RWP in compliance with offshore operations regulations.

[0026] As previously mentioned, the 20K rated RIJ 200 includes a series of 20K rated isolation valves 202 installed on the choke line 204, and a series of 20K rated isolation valves 202 installed on the kill line 206 of the drilling riser 106, according to one or more embodiments of the present disclosure. The choke line 204 and the kill line 206 are examples of fluid lines that exit the subsea BOP stack 108 and run along an outside of the riser joint 200 and the riser 106 to the surface 100 in the well control system, according to one or more embodiments of the present disclosure. In one or more embodiments, the choke line 204 leads from a first side outlet on the subsea BOP stack 108 to a choke, and to a choke manifold at the surface 100, and the kill line 206 leads from a second side outlet on the subsea BOP stack 108 to a pump at the surface 100. According to one or more embodiments of the present disclosure, the choke line 204 is used to run a choke operation, and the kill line 206 is used to run a kill operation, as understood by persons having ordinary skill in the art. However, the choke line 204 may also be used to run a kill operation, and the kill line 206 may be used to run a choke operation in certain situations without departing from the scope of the present disclosure.

[0027] In addition to the choke and kill lines, 204, 206 the 20K rated RU 200 according to one or more embodiments of the present disclosure may also include a plurality of auxiliary lines 208 for hydraulic fluid supply, as shown in FIG. 2. While two auxiliary lines are shown in FIG. 2, the RIJ 200 may include 3, 4, or even more auxiliary lines without departing from the scope of the present disclosure. As such, one or more embodiments of the present disclosure may be applied to any riser design having choke and kill lines and a plurality of auxiliary lines.

[0028] In an example well control system according to one or more embodiments of the present disclosure, the RWP of the plurality of isolation valves 202 installed on the choke and kill lines 204, 206 will be 20 ksia (absolute), and the RWP of the BOP stack 108 will be 15 ksia (absolute) and 20 ksid (differential I DAWP).

[0029] Referring now to FIG. 3, a method 300 according to one or more embodiments of the present invention is shown. As shown in FIG. 3, a method 300 according to one or more embodiments of the present disclosure includes installing a first plurality of 20K rated isolation valves on a choke line of a riser joint 302, installing a second plurality of 20K rated isolation valves on a kill line of the riser joint 304, connecting a first end of the riser joint to a drilling riser 306, connecting a second end of the riser joint to a 15K rated subsea BOP stack 308, and securing the 15K rated subsea BOP stack to a wellhead on the seabed 310. At least some steps in the method 300 may be performed simultaneously, in a different order, or omitted without departing from the scope of the present disclosure.

[0030] By installing 20K rated isolation valves on the choke line 204 and the kill line 206 of the RIJ 200, components of the well control system, including the drilling rig and the riser 106, will have a true RWP above the 20K rated isolation valves 202 installed on the RIJ 200, and a lower RWP below the 20K rated isolation valves 202 utilizing DAWP. By utilizing the RU 200 and a subsea BOP stack 108 validated for DAWP, end users could maintain a traditionally rated subsea BOP stack 108, such as a 15K rated subsea BOP stack 108, to reduce the size, weight, and cost of the subsea BOP stack 108 and rig, while leveraging DAWP to utilize seawater backup for the subsea BOP stack 108. As such, existing 15K well control equipment, such as the wellhead and the subsea BOP stack 108, may be used to facilitate the drilling of high pressure wells, as the DAWP (i.e., seawater pressure) acts to allow the 15K well control equipment to effectively operate at 20K RWP to comply with offshore operations regulations.

[0031] Language of degree used herein, such as the terms “approximately,” “about,” “generally,” and “substantially” as used herein represent a value, amount, or characteristic close to the stated value, amount, or characteristic that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” “generally,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and / or within less than 0.01% of the statedamount. As another example, in certain embodiments, the terms “generally parallel” and “substantially parallel” or “generally perpendicular” and “substantially perpendicular” refer to a value, amount, or characteristic that departs from exactly parallel or perpendicular, respectively, by less than or equal to 15 degrees, 10 degrees, 5 degrees, 3 degrees, 1 degree, or 0.1 degree.

[0032] Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

Claims

CLAIMSWhat is claimed is:

1. A well control system, comprising: a rig; a subsea blowout preventer (BOP) / wellhead assembly comprising a subsea BOP stack secured to a wellhead at a seabed of a well; a riser extending from the rig to the subsea BOP stack; a riser joint comprising: a first end connected to the riser; and a second end configured to connect to the subsea BOP / wellhead assembly; a plurality of fluid lines that exit the subsea BOP stack and run along an outside of the riser joint and the riser to surface; a first plurality of isolation valves installed on a first fluid line of the plurality of fluid lines; and a second plurality of isolation valves installed on a second fluid line of the plurality of fluid lines, wherein the subsea BOP stack has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

2. The well control system of claim 1, wherein the first working pressure rating is 15,000 psi, and wherein the second working pressure rating is 20,000 psi.

3. The well control system of claim 1, wherein the riser joint and the riser have the second pressure rating.

4. The well control system of claim 3, wherein the first working pressure rating is 15,000 psi, andwherein the second working pressure rating is 20,000 psi.

5. The well control system of claim 1, wherein a wellbore pressure at the seabed of the well is greater than the first working pressure rating, and wherein a pressure across a wall of the BOP stack at depth subsea is less than or equal to the first working pressure rating.

6. The well control system of claim 3, wherein the second working pressure rating is greater than the wellbore pressure at the seabed of the well.

7. The well control system of claim 1, wherein one of the first fluid line and the second fluid line of the plurality of fluid lines is a choke line and the other is a kill line.

8. The well control system of claim 7, wherein the choke line leads from a first side outlet on the subsea BOP stack, to a choke, and to a choke manifold at the surface, and wherein the kill line leads from a second side outlet on the subsea BOP stack to a pump at the surface.

9. The well control system of claim 8, wherein the choke line is used to run a choke operation, and wherein the kill line is used to run a kill operation.

10. The well control system of claim 8, wherein the choke line is used to run a kill operation, and wherein the kill line is used to run a choke operation.

11. The well control system of claim 1, wherein the riser joint comprises at least one auxiliary line.

12. A riser joint, comprising: a first end configured to connect to a drilling riser;a second end configured to connect to a subsea blowout preventer (BOP) / wellhead assembly, the subsea BOP I wellhead assembly comprising a subsea BOP stack secured to a wellhead at a seabed of a well; a choke line having a first plurality of isolation valves installed thereon; and a kill line having a second plurality of isolation valves installed thereon, wherein the subsea BOP / wellhead assembly that the second end is configured to connect to has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

13. The riser joint of claim 12, wherein the drilling riser has the second working pressure rating.

14. The riser joint of claim 12, wherein the first working pressure rating is 15,000 psi, and wherein the second working pressure rating is 20,000 psi.

15. The riser joint of claim 12, further comprising: at least one auxiliary line.

16. A method comprising: installing a first plurality of isolation valves on a choke line of a riser joint; installing a second plurality of isolation valves on a kill line of the riser joint; connecting a first end of the riser joint to a drilling riser; connecting a second end of the riser joint to a subsea BOP stack; and securing the subsea BOP stack to a wellhead on the seabed, wherein the subsea BOP stack has a first working pressure rating, wherein the first plurality of isolation valves and the second plurality of isolation valves have a second working pressure rating, andwherein the second working pressure rating is higher than the first working pressure rating.

17. The method of claim 16, wherein the drilling riser has the second working pressure rating.

18. The method of claim 16, wherein the first working pressure rating is 15,000 psi, and wherein the second working pressure rating is 20,000 psi.

19. The method of claim 17, wherein the first working pressure rating is 15,000 psi, and wherein the second working pressure rating is 20,000 psi.

20. A well control system, comprising: a rig; a blowout preventer (BOP) stack secured to a wellhead at a seabed of a well; a riser extending from the rig to the BOP stack; and a choke / kill system comprising: a choke line leading from a first side outlet on the BOP stack, to a choke, and to a choke manifold at surface; and a kill line leading from a second side outlet on the BOP stack to a pump at the surface, wherein the choke line and the kill line run along an outside of the riser from the BOP stack to the surface, wherein the BOP stack has a first working pressure rating, wherein the choke / kill system has a second working pressure rating, and wherein the second working pressure rating is higher than the first working pressure rating.

21. The well control system of claim 20, wherein the first working pressure rating is 15,000 psi, and wherein the second working pressure rating is 20,000 psi.

22. The well control system of claim 20, wherein a wellbore pressure at the seabed of the well is greater than the first working pressure rating, and wherein a pressure across a wall of the BOP stack at depth subsea is less than or equal to the first working pressure rating.

23. The well control system of claim 22, wherein the second working pressure rating is greater than the wellbore pressure at the seabed of the well.

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