Patent Application
20240209709
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present embodiments. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
To meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money in finding and extracting oil, natural gas, and other subterranean resources from the earth. Particularly, once a desired subterranean resource such as oil or natural gas is discovered, drilling and production systems are often employed to access and extract the resource. These systems may be located onshore or offshore depending on the location of a desired resource. Further, such systems generally include a wellhead assembly through which the resource is accessed or extracted. These wellhead assemblies may include a wide variety of components, such as various casings, valves, fluid conduits, and the like, that control drilling or extraction operations, with such components arranged in a stack or subsea production tree configuration, for example.
Wellhead assemblies typically include control pods that, as the name suggests, control and manage the delivery of control fluid to various components. For example, the control pods may direct control fluid to and from blowout preventers, actuators and valves via tubing coupled to a control-fluid source. When a particular hydraulic function is to be performed (e.g., closing a ram of a blowout preventer), a control pod valve associated with that function opens to supply control fluid to the component responsible for carrying out the hydraulic function (e.g., a piston of the blowout preventer). To provide redundancy in subsea applications, American Petroleum Institute Specification 16D (API Spec 16D) requires a subsea wellhead assembly include two subsea control pods—designated as a “yellow” pod and a “blue” pod—for controlling the assembly's hydraulically operated components.
For over forty years, the industry has relied on control fluid as the primary mechanism for actuating various drilling components—like a BOP—for both onshore and offshore operations. As a result, most wellhead assemblies have banks of accumulators storing pressurized control fluid, which often adds to the weight of the BOP system and, potentially, the supporting rig or vessel. Control-fluid accumulators can also be difficult to recharge in an efficient manner. And it is difficult to monitor the operational status of the control fluid in the accumulators, as well as the control fluid in the system as a whole.
Certain aspects of some embodiments disclosed herein are set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention. Indeed, the invention may encompass a variety of aspects that may not be set forth below.
Embodiments of the present disclosure generally relate to electrically operated drilling and production systems and components. In one embodiment, most if not all of the previously hydraulically operated components within the drilling system are replaced with electrically driven and controlled ones. For example, in one embodiment, the accumulator banks are replaced with devices that supply and/or store electrical current, such as batteries or a flywheel generator. The supplied current then feeds into various electrically operated components, like electrical motors and actuators. As another example, the hydraulic control pods may be replaced with electrical communications and distribution equipment.
Removing hydraulically operated components from a drilling or production system—whether it is land based or subsea—provides a number of advantages, including improved operational control, reduced rig and equipment weight, and improved data collection, to name but a few.
Various refinements of the features noted above may exist in relation to various aspects of the present embodiments. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter.
These and other features, aspects, and advantages of certain embodiments will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:
One or more specific embodiments of the present disclosure will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, any use of “top,” “bottom,” “above,” “below,” other directional terms, and variations of these terms is made for convenience, but does not require any particular orientation of the components.
Turning now the figures,
Subsea drilling and production operations are quite complex, requiring a myriad of equipment. Fluid flow into and out of the well 12 is managed by stack equipment 14 connected to the sea floor. As shown, the stack equipment 14 (which may also be referred to as a subsea wellhead assembly) includes a wellhead 16 that's mounted to the sea floor and that provides an interface point to the well 12. The wellhead 16 also provides a support structure onto which other stack equipment, like a BOP stack 18, can be mounted.
The primary function of the BOP (blowout preventer) stack 18 is to assist controlling the ingress and egress of wellbore fluid (e.g., drilling mud, formation fluids, hydrocarbons, inhibitors) with respect to the well. There are numerous types of BOPs that can be assembled into the stack, but some of the most common are annular BOPs and ram BOPs. Annular BOPs typically have a large rubber “doughnut” that is compressed to seal around a drillpipe that is extending into the well 12 through the BOP, while ram BOPs have horizontally opposed rams that are actuated toward one another to seal the well. These rams may be shear rams designed to cut through drillpipe before sealing off the well; the rams may be pipe rams designed to seal against the outer surface of the drillpipe; or the rams may be blind rams designed to seal against one another when there is no drillpipe or other component extending through the BOP, for example.
In a subsea drilling system, as is shown, the stack equipment 14 is connected to a rig 20 or vessel located at the sea's surface via a riser string 22. In short, the riser string 22 creates an artificial “bore” that allows wellbore fluid to be conveyed between the rig 20 at the sea's surface and the stack equipment 14 located at the sea floor. The riser string 22 typically comprises multiple segments of riser pipe that are coupled to one another until the desired length of riser string 22 is achieved. To facilitate the riser string's connection, the stack equipment 14 may include an LMRP (lower marine riser package). As an example, the LMRP 24 may include a flex joint connection that accommodates the upper end of the riser—which may be coupled to a floating vessel—moving with respect to the lower end of the riser mounted to the stack equipment fixed to the sea floor. Moreover, in an emergency situation, the LMRP can be activated to release the riser string, allowing the rig to move away from the stack equipment and well.
Control and operation of the stack equipment 14 can be facilitated by surface equipment 26 located on the rig 20. For example, the surface equipment 26 may include a human-machine interface (HMI) that allows the operator to input various commands that are communicated to a controller 28, which may be located on the subsea stack 14, via a cabling system 30. The surface equipment 26 May also include a variety of devices and systems, such as pumps, power supplies, cable and hose reels, control units, a diverter, a gimbal, a spider, and the like. Certain surface equipment, and their control relationship with the subsea stack equipment, are discussed in further detail below.
The exemplary system 10 May be an all-, substantially or predominately electric system, in which many of the hydraulically operated components traditionally found on drilling and production systems have been replaced or removed. Advantageously, replacing the hydraulically operated components with electrically controlled ones provides a number of benefits, including improved control, weight reduction, and better data collection, to name a few.
The nerve center of the exemplary networks is the command architecture 36, certain components of which may be located on the rig 20 in a driller's cabin or disbursed throughout the drilling system. The command architecture 36 May include processing equipment, like a processor or programmable logic circuity, that receives inputs from various locations and provides commands based on programming. Or, for manual operation, a human-machine interface (HMI) 38 facilitates the rig's operator providing commands to and receiving data regarding the drilling system. And the rig's operator need not be resident on the rig. Command inputs and operating data may also be communicated via a wireless communications system 40 connected to the data network 32, facilitating real-time monitoring and remote operation of the drilling system 10. Moreover, the command architecture may include one or more data ports 41—similar to an OBD-II port on automobiles, for instance—to facilitate communications with and control via a portable device.
Management of the exemplary drilling system's communication is conducted by a communication and distribution panel 42, which may operate using well-known protocols like TCP/IP or Ethernet/IP, or a proprietary protocol, among others.
In the illustrated drilling system 10, the data network 32 employs two general methodologies for communications between the surface equipment 26 and the subsea stack equipment 14. The first is a cabled connection, in which a cable 44 extends from the rig down to the subsea stack equipment 14. Any number of cable types may be employed, including fiber optic cables, cables designed to carry both data and power, MUX cables, or bundled cables, to name but a few. As shown in
These cabled connections can include more than just simple cables. For example, the cable connection may include magnetic elements—like rare earth magnets—that enable the cable to mechanically connect to the riser system 22. Moreover, the cable connection may be incorporated into the riser itself. That is, some or all of the riser segments in the riser string 22 May include integrated cable segments that couple to one another through a wet mate connector, or connectors that inductively communicate data, or a combination of the two. In another embodiment, the cables may be secured to the risers by clamps that close to secure the cable with respect to the riser string.
The second general communication methodology employs acoustics. In the exemplary system 10, the command architecture 36 includes an acoustic command unit 46 coupled to a transducer 48. Using the seawater as a medium, the transducer 48 transmits and receives acoustic signals sent to and from a transducer on the subsea equipment stack 14, on a remote operated vehicle (ROV), or on an autonomous underwater vehicle (AUV). But these two methodologies are just examples. It is also envisaged that the rig 20 May communicate with the subsea stack, or other components or devices located subsea, via radio waves employing very-low frequency (VLF) and super-low frequency (SLF) signals, for instance.
Communications between the rig 20 and the subsea stack 14 in the illustrated drilling system are transmitted by or to one or more controllers 28 located on the subsea stack 14. For example, the illustrated drilling system includes an LMRP electronics control module 50, which manages the communications and power distributions to various components on the LMRP 24. Put differently, this control module 50 controls the activation and deactivation of various “functions” on the LMRP, functions that are traditional hydraulically controlled using control fluid. The illustrated LMRP control module 50 manages five functions—namely the operation of five actuators on the LMRP—but the module can be sized to control more or fewer functions, if desired. As discussed in further detail below, a command signal may be sent to the LMRP control module 50, causing the module 50 to provide another command signal to switching circuitry, like a relay 51 or a solid state switching circuit, that directs operating power to the given actuator, effecting the desired function. That is, appropriately conditioned power—whether AC or DC—is routed to an electric motor to effect a function, like opening or closing a choke or activating or releasing a connector, through actuation. Advantageously, data collected from sensors on the drilling system, including sensors on the LMRP and the BOPs, can communicate operational data back to the rig 20 via the given controller 28, like the module 50.
The illustrated BOP stack 18 is operated in a similar manner, employing a BOP control module 54 that controls the activation and deactivation of various “functions” on the BOP stack, again functions that are traditional hydraulically controlled using control fluid. As shown, the BOP control module 54 controls ten functions on that BOP stack, such as the opening and closing of various valves, rams, annulars, and connectors (which are examples of pressure control equipment) on the BOP stack 18. Indeed, the subsea stack 14 includes an LMRP connector and a BOP wellhead connector that are energized and released via an electrically driven actuator having linear or push motor to drive collet connectors, for example. While five functions are depicted as controlled by the LMRP control module 50 and ten functions are depicted as controlled by the BOP control module 54 in the present illustration as examples, it will be appreciated that these control modules 50 and 54 can control other functions (e.g., pressure control functions) in addition to, or instead of, those presently depicted. Although depicted together in
The BOP control module 54 May be in communication with the LMRP control module 50, or it may be in direct communication with the rig 20 via direct cabling. Moreover, each of the control modules 50, 54 May include its own acoustic system 46 with a transducer 48, for acoustic communications with the rig 20.
Moreover, these control systems 50, 54 May be in communication with and provide power to equipment related to the riser system 22. For example, these systems 50, 54 May manage and control a riser recoil system that mitigates unwanted movement of the riser during disconnect operations.
Advantageously, in an all- or predominantly electric drilling system, much of the hydraulic cabling, the accumulator banks feeding the cables, and the associated supporting equipment (e.g., reels, hydraulic power units, rig plumbing, fluid mixes, umbilicals) can be removed from the rig 20, reducing the rig's complexity and weight. Moreover, in a hydraulic system, adding additional functions to the control pod requires significant redesign and a significant increase in the hydraulic control fluid needed for operation, whereas adding further functions to electrical systems is significantly easier.
If the command architecture 36 and data network 32 are the nervous system, then the power network 34 is the drilling system's circulatory track. To provide electrical power, the rig 20 includes a power supply 56, which may be any one of a number of devices that generate electrical current. For example, the power supply may be a solar array, a hydrogen fuel cell, a generator that converts diesel, gasoline or natural gas into electric current, a turbine electric generator, or a wave energy generator that converts the kinetic energy of the sea into electrical current; and these power generation systems may output three-phase AC, single-phase AC, or DC power, for example, depending on the needs of the drilling system. Indeed, the drilling system may include conditioning circuitry to condition the generated current (e.g., rectify, invert, pulse-width modulate, reduce voltage) so as to be appropriate for the given components.
On the rig 20, the power supply 56 is connected to a back-up or uninterruptable power supply 57, which may have a number of configurations. For example, the back-up may be a battery rack or capacitor bank that's trickle charged by the power supply, electricity generated through movement of a piezo-electric element, solar panels during quiescent operations, or via the power generation devices discussed above. Alternatively, the back-up may be a fly-wheel based system that converts the mechanical rotation of a fly wheel—motion effected by the primary supply, for example, during normal operation—into electrical energy when the primary supply is lost. Upon a loss of primary power, the back-up provides operating current to the drilling system, albeit for a limited duration as compared to the primary supply. But the backup power may also be employed even if the primary power is available, if desired.
These power generation and back-up systems need not be only located on the rig 20. The subsea stack equipment 14 May receive power from their own power supplies. For example, the LMRP control module 50 May be coupled to a subsea power generator 60, and the BOP control module 54 May be coupled to its own power generator 62 or to the LMRP's. These power generators 60, 62 May be similar to those on the rig, including a both a primary supply and a back-up supply or just one of those.
Moving to electrical operation of the subsea stack 14 yields a number of advantages. It eliminates the need for large banks of hydraulic accumulators—and their associated equipment, like hydraulic power units, hoses and hose reels, and piping, to name a few—to be deployed with the subsea stack equipment. This reduces the overall weight, size, and cost of the subsea stack equipment.
Moreover, traditional hydraulic systems do not provide the desired resolution regarding operational conditions. For example, depletion of hydraulic control fluid from the accumulators can be measured, but it may not be sufficiently granular so as to provide the operator with good information regarding the system's true condition. In contrast, electric systems can provide more accurate representations of power levels and battery levels, for example. Another advantage of electrical systems is that they provide more accurate feedback regarding the position of various components. That is, in conventional hydraulic systems, it is difficult to, with a high degree of resolution, determine the amount of movement of a piston driving a BOP ram, that movement being caused by the hydraulic control fluid. However, in an electrically driven system in which movement of the BOP rams is effected by an electric motor, for instance, the location information is more accurate, as fewer environmental factors affect the electrical system as compared to the hydraulic system, reducing the number of variables that must be factored to make an assessment. Ultimately, having better data and operational knowledge of the system can create a feedback loop, where analysis of the data yields more accurate estimates of potential failure points and need for maintenance. The surface and subsea components may include data or event loggers that, using the data network, collect and record data regarding the system. In the event of a malfunction or other incident, these loggers can be used to investigate and assess conditions leading up to the undesired event.
Further still, electrically actuated components can provide actuation much faster than hydraulic control fluid, particularly if there is a large distance between the hydraulic fluid source and the operated function.
But there are embodiments in which some hydraulic fluid may still be employed to operate the subsea equipment stack 14, even though it is predominately electric. For example, in one embodiment, the various functions may be effected by hydraulic control fluid that is pressurized locally by an electrically driven subsea pump, for example, powered by the above-described electrical power supplies. In at least some embodiments, the rig 20 is not connected to the subsea wellhead assembly 14 so as to provide hydraulic control fluid from the rig to the subsea wellhead assembly to enable drilling functions of the subsea wellhead assembly. That is, even if hydraulic control fluid is used by the subsea wellhead assembly 14 to perform a drilling function in some embodiments, that drilling function can be performed with a local, subsea source of hydraulic control fluid rather than with hydraulic control fluid provided from the rig 20 (e.g., via an umbilical) at the time the drilling function is performed.
To operate in harsh environments, like those found when operating subsea, the drilling system has redundancy. The left sides of
The exemplary system 10 also has a number of remote-operating vehicle
(ROV) ports and access points that facilitate continuous operation of the drilling system. For example, each of the functions of the subsea stack 14 includes one or more ROV access points 63 through which an ROV can effect a function, whether mechanically or electrically. That is, the ROV may be operated to manually open or close valves, or the ROV may provide command signals and power to close the valve, as examples.
The ROV may also couple to subsea power and control components. For example, in the illustrated drilling system, the subsea power generator 62 has an ROV charging port 66 that allows ROV to provide electrical power to the subsea stack equipment 14, whether directly or indirectly, by charging the battery back-up, for instance. Moreover, the system may include an ROV interface port 68 that allows the ROV to communicate with the data network 32 and/or a data storage device located in a subsea electronic module recording the system's data, independent of the command architecture. Thus, if control at the rig 20 is lost, the ROV can fully operate and communicate with the subsea stack equipment 14. And command controls from the ROV can even be communicated to the subsea stack equipment 14 acoustically, with the ROV having a transducer that communicates with the transducer on the subsea stack's acoustic system. It's also envisaged that the two ROV ports 66, 68 can be integrated into a single port that allows power and data communications over a single connection with the ROV.
Turning to
Concluding with
While the aspects of the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. But it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
This application is a continuation of U.S. patent application Ser. No. 18/340,639, filed Jun. 23, 2023, which is a continuation of U.S. Pat. No. 11,739,605, filed Dec. 26, 2018, which is a National Stage Entry of PCT/US2017/041367, filed Jul. 10, 2017, which claims the benefit and priority of U.S. Provisional Application No. 62/360,404, filed Jul. 10, 2016. Each of the above applications is hereby expressly incorporated by reference in its entirety as if fully set forth below and for all applicable purposes.
| Number | Date | Country | |
|---|---|---|---|
| 62360404 | Jul 2016 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 18340639 | Jun 2023 | US |
| Child | 18435083 | US | |
| Parent | 16313460 | Dec 2018 | US |
| Child | 18340639 | US |
