US20180313187A1

US20180313187A1 - Single body choke line and kill line valves

Info

Publication number: US20180313187A1
Application number: US15/583,279
Authority: US
Inventors: Ray Cummins
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2017-05-01
Filing date: 2017-05-01
Publication date: 2018-11-01

Abstract

A well control system including a kill line and a choke line where the system is mounted on a wellhead, the choke line is connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing, and the kill line is connected to the fluid in the drill pipe. The kill line includes a single valve body having first and second ends, and at least three cavities connected in series between the first and second ends. A first and second of the cavities includes a first and second gate valve, respectively, and a third of cavities includes a check valve. The choke line includes a single valve body having third and fourth ends, and a plurality of cavities connected in series between the third and fourth ends. A first and second of the cavities include a third and a fourth gate valve, respectively.

Description

BACKGROUND

Exploration for, location of, and extraction of subterranean fluids, including hydrocarbon fluids, typically involves drilling operations to create a well. Drilling operations, particularly drilling operations involving rotary drilling, often utilize drilling fluids, also called muds, for a variety of reasons including lubrication, removal of cuttings and other matter created during the drilling process, and to provide sufficient pressure to ensure that fluids located in subterranean reservoirs do not enter the borehole, or wellbore, and travel to the surface of the earth. Fluids located in subterranean reservoirs are under pressure from the overburden of the earth formation above them. Specialized equipment is used to provide control of all fluids used or encountered in the drilling of a well.

SUMMARY

This summary is provided to introduce a selection of concepts that are described further in the detailed description below. 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.
In one aspect, a well control system in accordance with the present disclosure may include a kill line and a choke line. The well control system may be mounted on a wellhead. The choke line may be connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing, and the kill line may be connected to the fluid in the drill pipe.
The kill line may include a single valve body having a first end, a second end, and at least three cavities connected in series between the first end and the second end. A first of the at least three cavities may include a first gate valve, a second of the at least three cavities may include a second gate valve, and a third of the at least three cavities may include a check valve.
The choke line may include a single valve body having a third end, a fourth end, and a plurality of cavities connected in series between the third end and the fourth end. A first of the plurality of cavities may include a third gate valve, and a second of the plurality of cavities may include a fourth gate valve.
In another aspect, a method in accordance with the present disclosure of controlling release of fluids from below the wellhead, using a well control system, may include at least one of closing a blowout preventer, closing at least one gate valve in a choke line, or introducing fluid into the well via a kill line. The well control system may include a blowout preventer, a kill line and a choke line. The well control system may be mounted on a wellhead. The choke line may be hydraulically connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing, and the kill line may be hydraulically connected to the fluid in the drill pipe.
The kill line may include a single valve body having a first end, a second end, and at least three cavities connected in series between the first end and the second end. A first of the at least three cavities may include a first gate valve, a second of the at least three cavities may include a second gate valve, and a third of the at least three cavities may include a check valve.
The choke line may include a single valve body having a third end, a fourth end, and a plurality of cavities connected in series between the third end and the fourth end. A first of the plurality of cavities may include a third gate valve, and a second of the plurality of cavities may include a fourth gate valve.
In a further aspect, a kill line in accordance with the present disclosure may include a single valve body having a first end, a second end, and at least three cavities connected in series between the first end and the second end. A first of the at least three cavities may include a first gate valve, a second of the at least three cavities may include a second gate valve, and a third of the at least three cavities may include a check valve.
Other aspects and advantages will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, where 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.

FIG. 1 is a schematic diagram showing an oilfield in accordance with one embodiment or more embodiments of the disclosure.

FIG. 2 is a schematic diagram showing a section view of a choke line with both a manual and a hydraulic gate valve.

FIG. 3 is a schematic diagram showing an isometric view of a single-body choke line valve assembly in accordance with one or more embodiments of the disclosure.

FIG. 4 is a schematic diagram showing a top view of single-body choke line valve assembly in accordance with one or more embodiments of the disclosure.

FIG. 5 is a schematic diagram showing an isometric view of a single-body kill line valve assembly in accordance with one or more embodiments of the disclosure.

FIG. 6 is a schematic diagram showing a top view of a single-body kill line valve assembly in accordance with one or more embodiments of the disclosure.

FIG. 7 is a schematic diagram showing a blowout preventer stack in accordance with one or more embodiments of the disclosure.

FIG. 8 is a schematic diagram showing one embodiment of a blowout preventer stack without single-body choke line valve assembly or single-body kill line valve assembly.

FIG. 9 is a schematic diagram showing a top view of a single-body choke line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure.

FIG. 10 is a schematic diagram showing a front view of a single-body choke line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure.

FIG. 11 is a schematic diagram showing a top view of a single-body kill line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure.

FIG. 12 is a schematic diagram showing a front view of a single-body kill line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure.

FIG. 13 is a schematic diagram showing a side view of a choke line valve arrangement.

FIG. 14 is a schematic diagram showing a side view of a kill line valve arrangement.

DETAILED DESCRIPTION

The present disclosure concerns single-body choke line valve assemblies and single-body kill line valve assemblies used in the drilling of subterranean wells and of the well control systems and methods that use them.
The following is directed to various exemplary embodiments of the disclosure. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, those having ordinary skill in the art will appreciate that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the present disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the present disclosure. In this regard, no attempt is made to show structural details of the present disclosure in more detail than is necessary for the fundamental understanding of the present disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the present disclosure may be embodied in practice. Further, like reference numbers and designations in the various drawings indicate like elements.
Certain terms are used throughout the following description and claims to refer to particular features or components. As those having ordinary skill in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first component is coupled to a second component, that connection may be through a direct connection, or through an indirect connection via other components, devices, and connections. Further, the terms “axial” and “axially” generally mean along or parallel to a central or longitudinal axis, while the terms “radial” and “radially” generally mean perpendicular to a central longitudinal axis. A “temperature/pressure sensor” herein may represent a sensor capable of measuring temperature, a sensor capable of measuring pressure, or a sensor capable of measuring both temperature and pressure. A “single valve body” as used herein indicates a single body disposing a plurality of valves.
FIG. 1 depicts a schematic view, partially in cross section, of a field (100) in which one or more embodiments may be implemented. In one or more embodiments, the field may be an oilfield. In other embodiments, the field may be a different type of field. In one or more embodiments, one or more of the modules and elements shown in FIG. 1 may be omitted, repeated, and/or substituted. Accordingly, embodiments should not be considered limited to the specific arrangements of modules shown in FIG. 1.
As shown in FIG. 1, the subterranean formation (104) may include several geological structures (106-1 through 106-4) of which FIG. 1 provides an example. As shown, the formation may include a sandstone layer (106-1), a limestone layer (106-2), a shale layer (106-3), and a sand layer (106-4). A fault line (107) may extend through the formation. In one or more embodiments, various survey tools and/or data acquisition tools are adapted to measure the formation and detect the characteristics of the geological structures of the formation. Further, as shown in FIG. 1, the wellsite system (110) is associated with a rig (101), a wellbore (103), and other field equipment and is configured to perform wellbore operations, such as logging, drilling, fracturing, production, or other applicable operations. The wellbore (103) may also be referred to as a borehole.
Well control is the technology focused on maintaining pressure on open formations (that is, exposed to the wellbore) to prevent or direct the flow of wellbore fluids into the formation and formation fluids into the wellbore. Formation fluids may include, among other things, water and such hydrocarbon fluids as oil and gas. Well control technology encompasses the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Also included are operational procedures to safely stop a well from flowing should an influx of formation fluid occur. To conduct well-control procedures, large valves are installed at the top of the well to enable wellsite personnel to close the well if necessary.
In one or more embodiments, a gate valve may be used in a well control system. FIG. 2 is a schematic diagram showing components of a manual gate valve (250) and a hydraulic gate valve (251) in accordance with one or more embodiments of the technology. A gate valve (250, 251) is a type of valve that incorporates a sliding gate (256, 257) to block fluid flow. The design of the valve operating and sealing systems typically requires that gate valves should be operated either fully open or fully closed. In one or more embodiments, a gate valve (250, 251) is a straight-through pattern valve whose sliding-gate closure element is a wedge or parallel-sided slab (256, 257), situated between two fixed seating surfaces (280, 281, 283, 284) with means to move it in or out of the flow stream in a direction perpendicular to the pipeline axis. In one or more embodiments, a manual gate valve (250) may comprise a hand wheel (260) for actuating the valve. In one or more embodiments, a gate valve (251) may comprise a hydraulic piston (258) used to open and close the valve. In one or more embodiments, a hydraulic gate valve (251) may comprise a locking wheel (259). In one or more embodiments, a gate valve (250) may comprise a manual actuator. In one or more embodiments, the manual actuator may be a hand wheel as shown in FIGS. 4-7.
FIG. 13 shows a side view of one or more embodiments of a choke line valve arrangement comprising a manual gate valve (1350) and a hydraulic gate valve (1351). FIG. 14 shows a side view of one or more embodiments of a kill line valve arrangement comprising a manual gate valve (1450) and a hydraulic gate valve (1451), and a check valve (1475). Details of gate valves are presented above with reference to FIG. 2. Details of check valves are presented below.
Choke lines comprise valves and either hard piping or flexible hose that carry high pressure drilling fluid from a blowout preventer (BOP) stack while it is on the wellhead. A wellhead is a system of spools, valves and assorted adapters that provide pressure control of a production well. A spool, is an extension added to a short face-to-face valve to conform to standard API 6A (or ISO 14313: 1999) face-to-face dimensions. API 6A specifies requirements and gives recommendations for the design, manufacturing, testing and documentation of ball, check, gate and plug valves for application in pipeline systems. The valves on a choke line include at least one hydraulically actuated gate valve and at least one manually actuated gate valve. In one or more embodiments, the choke line may be connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing.
An annulus is a space between two concentric objects, such as between the wellbore and casing, or between casing and tubing, where fluid can flow. Pipe may comprise drill collars, drill pipe, casing, tubing, and the like.
A choke is a device incorporating an orifice that is used to control fluid flow rate or downstream system pressure. Chokes are available in several configurations for both fixed and adjustable modes of operation. Adjustable chokes enable the fluid flow and pressure parameters to be changed to suit process or production requirements. Fixed chokes do not provide this flexibility, although they are more resistant to erosion under prolonged operation or production of abrasive fluids.
FIG. 3 is a schematic diagram showing an isometric view of a single-body choke line valve assembly in accordance with one or more embodiments of the technology. In one or more embodiments, a single-body choke line valve assembly comprises a single valve body. In one or more embodiments, the single valve body (360) comprises at least two cavities (not shown) in series and configured to contain valve components. The single valve body comprises two ends (365, 366) connected by the cavities in series. The ends (365,366) may include openings and flanges for connecting the valve assembly to other components such as a spool, piping, etc. Thus, the valve assembly may have multiple valves and valve cavities between the ends (365, 366) or flanges without having flanges therebetween. In one or more embodiments, the choke line valve assembly comprises a manually-actuated gate valve (363). The manually-actuated gate valve (363) comprises a hand wheel (364). In one or more embodiments, the choke line valve assembly comprises a hydraulically-actuated gate valve (361). In one or more embodiments, the hydraulically-actuated gate valve (361) comprises a hand wheel (362) configured to lock the valve.
FIG. 4 is a schematic diagram showing a top view of a single-body choke line valve assembly in accordance with one or more embodiments of the technology. In one or more embodiments, the single valve body (460) comprises at least two cavities (not shown) in series and configured to contain valve components. The single valve body comprises two ends (465, 466) connected by the cavities in series. In one or more embodiments, the choke line valve assembly comprises a manually-actuated gate valve (463). The manually-actuated gate valve (463) comprises a hand wheel (464). In one or more embodiments, the choke line valve assembly comprises a hydraulically-actuated gate valve (461). In one or more embodiments, the hydraulically-actuated gate valve (461) comprises a hand wheel (462) configured to lock the valve.
A kill line is a high-pressure pipe leading from an outlet on the blowout preventer (BOP) stack to the high-pressure rig pumps. During normal well control operations, kill fluid is pumped through the drillstring and annular fluid is taken out of the well through the choke line to the choke, which drops the fluid pressure to atmospheric pressure. If the drill pipe is inaccessible, it may be necessary to pump heavy drilling fluid in the top of the well, wait for the fluid to fall under the force of gravity, and then remove fluid from the annulus. In such an operation, while one high pressure line would suffice, it is more convenient to have two. In addition, this provides a measure of redundancy for the operation.
Kill lines comprise valves and either hard piping or flexible hose that carry high pressure drilling fluid to the blowout preventer (BOP) stack while it is on the wellhead. The valves on a kill line include at least one hydraulically actuated gate valve and at least one manually actuated gate valve. Kill lines also may include at least one check valve. In one or more embodiments, the kill line is hydraulically connected to the fluid in the drill pipe.
FIG. 5 is a schematic diagram showing an isometric view of a single-body kill line valve assembly in accordance with one or more embodiments of the technology. In one or more embodiments, a single-body kill line valve assembly comprises a single valve body. In one or more embodiments, the single valve body (570) comprises at least three cavities (not shown) in series and configured to contain valve components. The single valve body comprises two ends (565, 566) connected by the cavities in series. The ends (565,566) may include openings and flanges for connecting the valve assembly to other components such as a spool, piping, etc. Thus, the valve assembly may have multiple valves and valve cavities between the ends (565, 566) or flanges without having flanges therebetween. In one or more embodiments, the kill line valve assembly comprises a manually-actuated gate valve (563). The manually-actuated gate valve (563) comprises a hand wheel (564). In one or more embodiments, the kill line valve assembly comprises a hydraulically-actuated gate valve (561). In one or more embodiments, the hydraulically-actuated gate valve (561) comprises a hand wheel (562) configured to lock the valve. In one or more embodiments, the kill line valve assembly comprises a check valve (575).
A check valve is a mechanical device that permits fluid to flow or pressure to act in one direction only. Check valves are used in a variety of oil and gas industry applications as control or safety devices. Check valve designs are tailored to specific fluid types and operating conditions. Some designs are less tolerant of debris, while others may obstruct the bore of the conduit or tubing in which the check valve is fitted.
FIG. 6 is a schematic diagram showing a top view of a single-body kill line valve assembly in accordance with one or more embodiments of the technology. In one or more embodiments, the single valve body (660) comprises at least three cavities (not shown) in series and configured to contain valve components. The single valve body comprises two ends (665, 666) connected by the cavities in series. In one or more embodiments, the kill line valve assembly comprises a manually-actuated gate valve (663). The manually-actuated gate valve (663) comprises a hand wheel (664). In one or more embodiments, the kill line valve assembly comprises a hydraulically-actuated gate valve (661). In one or more embodiments, the hydraulically-actuated gate valve (661) comprises a hand wheel (662) configured to lock the valve. In one or more embodiments, the kill line valve assembly comprises a check valve (675).
A BOP is a large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes and pressure ratings. Some can effectively close over an open wellbore, some are designed to seal around tubular components in the well (drill pipe, casing or tubing) and others are fitted with hardened steel shearing surfaces that can actually cut through drill pipe. Since BOPs are critically important to the safety of the crew, the rig and the wellbore itself, BOPs are inspected, tested and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems. Types of BOPs include annular BOP, inside BOP, ram BOP, shear ram BOP, and blind ram BOP.
A BOP stack is a set of two or more BOPs used to ensure pressure control of a well. A typical BOP stack might consist of one to six ram-type preventers (ram BOPs) and, optionally, one or two annular-type preventers (annular BOPs). A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top. The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. For example, in a multiple ram configuration, one set of rams might be fitted to close on 5-inch diameter drill pipe, another set configured for 4½-inch drill pipe, a third fitted with blind rams to close on the open hole and a fourth fitted with a shear ram that can cut and hang-off the drill pipe as a last resort. It is common to have an annular preventer or two on the top of the stack since annulars can be closed over a wide range of tubular sizes and the open hole, but are typically not rated for pressures as high as ram preventers. The BOP stack also includes various spools, adapters and piping outlets to permit the circulation of wellbore fluids under pressure in the event of a well control incident.
FIG. 7 is a schematic diagram showing a BOP stack in accordance with one or more embodiments of the technology. In one or more embodiments, a BOP stack comprises two or more BOPs (720, 725, 730). In one or more embodiments, the top BOP (720) is an annular BOP. In one or more embodiments, the middle and bottom BOPs (725, 730) are ram BOPs. In one or more embodiments, the BOP stack may be mounted on or similarly coupled to a wellhead (735). In one or more embodiments, the BOP stack may comprise a single-body choke line valve assembly (740). In one or more embodiments, the single-body choke line valve assembly (740) may comprise a plurality of gate valves (741, 742). In one or more embodiments, the BOP stack may comprise a single-body kill line valve assembly (745). In one or more embodiments, the single-body kill line valve assembly (745) may comprise a plurality of gate valves (746, 747). In one or more embodiments, the single-body kill line valve assembly (745) may comprise a check valve (748). In one or more embodiments, a choke line may be coupled to a spool. In one or more embodiments, a kill line may be coupled to a spool.
In one or more embodiments, one or more of the BOPs (720, 725, 730) may comprise an outlet (736). In one or more embodiments, a unique choke line may be coupled to one or more of the outlets (736). In one or more embodiments, a unique kill line may be coupled to one or more of the outlets (736).
FIG. 8 is a schematic diagram showing one embodiment of a BOP stack without single-body choke line valve assembly or single-body kill line valve assembly. The BOP stack comprises three BOPs (720, 725, 730). The BOP stack is mounted on a wellhead (735). The BOP stack comprises a choke line comprising two single-body gate valves (749, 750) coupled together. The single-body gate valve includes a single cavity within the valve and thus flanges between adjacent valve cavities. The BOP stack comprises a kill line comprising two single-body gate valves (752, 753) and a single-body check valve (754) coupled together. It is known in the art to assemble valve structures in kill lines and choke lines by fastening individual valve structures together. Fastening may be done by bolting or clamping connections together, or by some similar means.
FIG. 9 is a schematic diagram showing a top view of a single-body choke line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure. Features and components that are similar to those described in FIG. 3 or 4 may not be repeated. In one or more embodiments of a single-body choke line valve assembly, a single valve body (960) may comprise two cavities. In one or more embodiments, a manually-actuated gate valve (963) may be disposed in one of the cavities. In one or more embodiments, a hydraulically-actuated gate valve (961) may be disposed in another cavity. In one or more embodiments, a temperature/pressure sensor (990) may be disposed in the single valve body (960). As described earlier, temperature/pressure sensors may measure temperature, pressure, or both.
FIG. 10 is a schematic diagram showing a front view of a single-body choke line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure. Features and components that are similar to those described in FIG. 3 or 4 may not be repeated. In one or more embodiments of a single-body choke line valve assembly, a single valve body (1060) may comprise two cavities. In one or more embodiments, a manually-actuated gate valve (1063) may be disposed in one of the cavities. In one or more embodiments, a hydraulically-actuated gate valve (1061) may be disposed in another cavity. In one or more embodiments, a plurality of temperature/pressure sensors (1090, 1095) may be disposed in the single valve body (1060). As described earlier, temperature/pressure sensors may measure temperature, pressure, or both.
FIG. 11 is a schematic diagram showing a top view of a single-body kill line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure. Features and components that are similar to those described in FIG. 5 or 6 may not be repeated. In one or more embodiments of a single-body choke line valve assembly, a single valve body (1170) may comprise three cavities. In one or more embodiments, a manually-actuated gate valve (1163) may be disposed in one of the cavities. In one or more embodiments, a hydraulically-actuated gate valve (1161) may be disposed in another cavity. In one or more embodiments, a check valve (1175) is disposed in another cavity. In one or more embodiments, a temperature/pressure sensor (1190) may be disposed in the single valve body (1170). As described earlier, temperature/pressure sensors may measure temperature, pressure, or both.
FIG. 12 is a schematic diagram showing a front view of a single-body kill line valve assembly including temperature/pressure sensors in accordance with one or more embodiments of the disclosure. Features and components that are similar to those described in FIG. 5 or 6 may not be repeated. In one or more embodiments of a single-body choke line valve assembly, a single valve body (1270) may comprise three cavities. In one or more embodiments, a manually-actuated gate valve (1263) may be disposed in one of the cavities. In one or more embodiments, a hydraulically-actuated gate valve (1261) may be disposed in another cavity. In one or more embodiments, a check valve (1275) is disposed in another cavity. In one or more embodiments, a temperature/pressure sensor (1290, 1295) may be disposed in the single valve body (1270). As described earlier, temperature/pressure sensors may measure temperature, pressure, or both.
Single-body valve assemblies for the choke line and the kill line have the advantages of reducing the size, weight, material used, overall length, and number of leak paths of the valve assemblies. This may be seen, for example, in comparing FIGS. 7 and 8. For example, in one embodiment, for 3 1/16 inch, 10M size (referring to 3 1/16 inch nominal flange size and a maximum service pressure rating of 10,000 pounds per square inch), the kill line can be reduced from 73.14 inches from the side outlet to 41.58 inches and the weight reduced from 1597 pounds to 1380 pounds, reductions of 31.56 inches and 217 pounds, respectively. In another example, for 3 1/16 inch, 10M size, the choke line can be reduced from 48.76 inches from the side outlet to 31.08 inches and the weight reduced from 1147 pounds to 1036 pounds, reductions of 17.68 inches and 111 pounds, respectively.
While the technology has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the technology as disclosed herein. Accordingly, the scope of the technology should be limited by the attached claims.

Claims

What is claimed is:

1. A well control system comprising:

a kill line; and

a choke line;

wherein the well control system is mounted on a wellhead,

wherein the choke line is connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing,

wherein the kill line is connected to the fluid in the drill pipe,

wherein the kill line comprises:

a single valve body having a first end, a second end, and at least three cavities connected in series between the first end and the second end;

wherein a first of the at least three cavities comprises a first gate valve, a second of the at least three cavities comprises a second gate valve, and a third of the at least three cavities comprises a check valve, and

wherein the choke line comprises:

a single valve body having a third end, a fourth end, and a plurality of cavities connected in series between the third end and the fourth end;

wherein a first of the plurality of cavities comprises a third gate valve, and a second of the plurality of cavities comprises a fourth gate valve.

2. The well control system of claim 1, wherein the first gate valve is hydraulically actuated.

3. The well control system of claim 1, wherein the second gate valve is manually actuated.

4. The well control system of claim 1 further comprising at least one blowout preventer,

wherein the blowout preventer is distal from the wellhead.

5. The well control system of claim 1 wherein the first end of the kill line is connected to a spool.

6. The well control system of claim 1 wherein the third end of the choke line is connected to a spool.

7. The well control system of claim 1, wherein the check valve is configured to prevent fluid flow out of the well.

8. The well control system of claim 1, further comprising a temperature/pressure sensor,

wherein the temperature/pressure sensor measures at least one member of the group consisting of temperature and pressure.

9. A method of controlling release of fluids from below the wellhead, using a well control system, comprising at least one of closing a blowout preventer, closing at least one gate valve in a choke line, or introducing fluid into the well via a kill line,

wherein the well control system comprises:

a blowout preventer;

a kill line; and

a choke line;

wherein the well control system is mounted on a wellhead,

wherein the choke line is hydraulically connected to an annulus formed between an outer wall of drill pipe and an inner wall of casing,

wherein the kill line is hydraulically connected to the fluid in the drill pipe,

wherein the kill line comprises:

wherein the choke line comprises:

10. The method of claim 9, wherein introducing fluid into the well via the kill line involves hydraulically actuating the first gate valve in the kill line.

11. The method of claim 9, wherein introducing fluid into the well via the kill line involves manually actuating the second gate valve in the kill line.

12. The method of claim 10, wherein the well control system further comprises a temperature/pressure sensor,

13. A kill line comprising a single valve body having a first end, a second end, and at least three cavities connected in series between the first end and the second end,

wherein a first of the at least three cavities comprises a first gate valve, a second of the at least three cavities comprises a second gate valve, and a third of the at least three cavities comprises a check valve.

14. The kill line of claim 13, wherein the first gate valve is hydraulically actuated.

15. The kill line of claim 13, wherein the second gate valve is manually actuated.

16. The kill line of claim 13, further comprising a temperature/pressure sensor,