US20230193707A1

US20230193707A1 - Smart well control method and apparatus using downhole autonomous blowout preventer

Info

Publication number: US20230193707A1
Application number: US17/554,921
Authority: US
Inventors: Baraket Mehri
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2021-12-17
Filing date: 2021-12-17
Publication date: 2023-06-22

Abstract

A method, a computer-readable medium, and a drilling rig are provided for responding to a well kick. The method may comprise monitoring downhole parameters in a wellbore. The method may further include, based on the downhole parameters, detecting a kick pressure signature. Next, the method may include, in response to detecting the kick pressure signature, automatically performing a well shut-in procedure. Lastly, the monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure may be performed by a computer without any human intervention.

Description

BACKGROUND

The exploration of petroleum resources is an important part of a modern economy. In addition to providing gasoline and diesel fuel for internal combustion engines, petroleum is used in the manufacture of a wide variety of industrial and consumer products. Such products include asphalt, tires, lubricants, wax, and a variety of plastic products, just to name a few. Consequently, there is a large effort dedicated to oil drilling and petroleum extraction. Oil drilling is a dangerous business. It is estimated that hundreds of millions of gallons of oil have inadvertently entered the environment due to well blowouts and uncontrolled drilling operations. A well blowout occurs when high pressure hydrocarbons enter the wellbore and overcome the counteracting pressure of the drill string and any drilling fluid. When the pressure of the released hydrocarbons is higher than the hydrostatic pressure in the wellbore, all of the drilling materials as well as the oil in the well will be ejected from the top of the wellbore. Gushing wells represent a catastrophic failure and can cause significant environmental damage and loss of life until they are brought under control. A problem with current well control technology is that it still relies on human intervention, which is fraught with failure. It is therefore an object of the present invention to provide advanced kick detection and autonomous blowout prevention in order to avoid catastrophic well failure. It is another object of the present invention to respond to dangerous well situations automatically without any human intervention. These and other topics will be discussed below.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. 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, embodiments disclosed herein relate to a method, a computer-readable medium, and a drilling rig designed for responding to a well kick.
In one embodiment, a method is provided for responding to a well kick. The method may comprise monitoring downhole parameters in a wellbore. The method may further include, based on the downhole parameters, detecting a kick pressure signature. Next, the method may include, in response to detecting the kick pressure signature, automatically performing a well shut-in procedure.
In one or more embodiments of the method, the monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by a computer without any human intervention.
In one or more embodiments of the method, the automatically performing the well shut-in procedure may include activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.
In one or more embodiments of the method, the modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.
In one or more embodiments of the method, the detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.
In one or more embodiments of the method, the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.
In one embodiment, a non-transitory computer-readable storage medium is provided. The non-transitory computer-readable storage medium may have computer-readable instructions stored thereon, which when executed by a computer cause the computer to perform one or more operations. The operations may comprise monitoring downhole parameters in a wellbore. The operations may further include, based on the downhole parameters, detecting a kick pressure signature. The operations may further include, in response to detecting the kick pressure signature, automatically performing a well shut-in procedure.
In one or more embodiments of the computer-readable medium, the monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by the computer without any human intervention.
In one or more embodiments of the computer-readable medium, the automatically performing the well shut-in procedure includes activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.
In one or more embodiments of the computer-readable medium, the modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.
In one or more embodiments of the computer-readable medium, the detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.
In one or more embodiments of the computer-readable medium, the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.
In one embodiment, a drilling rig is provided for responding to a well kick. The drilling rig may comprise a drilling computer, a bottomhole assembly, and a drilling pump. The drilling computer may be configured to monitor downhole parameters in a wellbore, and based on the downhole parameters, detect a kick pressure signature. The drilling computer may be further configured to, in response to detecting the kick pressure signature, automatically perform a well shut-in procedure.
In one or more embodiments of the drilling rig, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by the computer without any human intervention.
In one or more embodiments of the drilling rig, automatically performing the well shut-in procedure includes activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.
In one or more embodiments of the drilling rig, modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.
In one or more embodiments of the drilling rig, detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.
In one or more embodiments of the drilling rig, the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. This disclosed technology may, however, be embodied in many different forms and should not be construed as limited to the implementations set forth herein. The components described hereinafter as making up various elements of the disclosed technology are intended to be illustrative and not restrictive. Many suitable components that would perform the same or similar functions as components described herein are intended to be embraced within the scope of the disclosed electronic devices and methods. Such other components not described herein may include, but are not limited to, for example, components developed after development of the disclosed technology.

FIG. 1 shows an oil drilling rig in accordance with one or more embodiments.

FIG. 2 shows a horizontal oil drilling rig in accordance with one or more embodiments.

FIG. 3 shows a computing device in accordance with one or more embodiments.

FIG. 4 shows a flowchart of a drilling procedure in accordance with one or more embodiments.

DETAILED DESCRIPTION

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
It is also to be understood that the mention of one or more method steps does not preclude the presence of additional method steps or intervening method steps between those steps expressly identified. Similarly, it is also to be understood that the mention of one or more components in a device or system does not preclude the presence of additional components or intervening components between those components expressly identified.
Although various embodiments may be described with respect to a system, a non-transitory computer-readable medium, and a method, it is contemplated that embodiments with identical or substantially similar features may alternatively be implemented as methods, systems, and/or non-transitory computer-readable media.
FIG. 1 shows oil drilling rig 100 in accordance with some embodiments. Oil drilling rig 100 may include a platform 102 supported by one or more structural members 104. Platform 102 may be suspended over the ground 106 in the case of above-ground or onshore drilling. In alternative embodiments, platform 102 is suspended over water for offshore or water-based drilling. At the top of the platform 102 is a drillstring 110, which is encompassed by casing 108. A number of elements are situated along with the casing 108 between platform 102 and ground 106. Many of these elements assist in the drilling operation and may further be activated to prevent a well blowout, as will be discussed in further detail below. The combination of elements with the casing 108 between platform 102 and ground 106, depicted generally by element 134, is known as the tree. Below the ground 106, casing 108 and drillstring 110 may extend many thousands of feet (as shown by the dashed lines and arrows) and into a wellbore 112. Drillstring 110 may terminate with a drill bit 114 that comes into contact with a rock bed. Drilling is aided by pump 116, which pumps drilling fluid down drillstring 110 and out of fluid ports in the drill bit 114. The drilling fluid (also known as drilling mud) may help scavenge debris and rock fragments as they are ejected from the rock bed by drill bit 114. Pressure from the pump 116 forces the drilling fluid on a return path up the wellbore 112 inside the space between the drill string 110 and the walls of the casing 108. This space between the drill string 110 and the walls of the casing 108 is known as the annulus. The drilling fluid flows up the annulus until it is picked up by return port 118 and is dispensed into mud pit 120. Monitoring pressure of the fluid in the annulus and drill string 110 is critical to the operation of drilling rig 100 in a manner that prevents a blowout.
As drill bit 114 penetrates the rock bed, oil and hydrocarbons are released from the rock bed into wellbore 112 and subsequently become mixed with the drilling fluid. The oil and hydrocarbons released during drilling are typically scavenged from a geological formation, and they are thus known as formation fluids. Under normal operation, pressure from the drilling fluid counteracts the pressure from the released formation fluids and drilling is allowed to continue until a desired depth or fluid reservoir is reached. However, depending on the structure of a given geological formation, the oil and hydrocarbons may be under extreme pressure. When highly pressurized formation fluids mix with the drilling fluid, the pressure experienced by fluids returning in the annulus and at the return port 118 may exceed operational limits. This is known as a well kick and it is an undesirable situation. In extreme circumstances, highly pressurized formation fluids may reverse the flow of drilling fluid and force the fluid back up drill string 110. When all safety measures for controlling a well kick have failed, the situation is known as a blowout. As mentioned above, well blowouts cause significant personnel, property, and environmental damage. Thus, it is highly desirable to respond to well kicks in a way that safely manages fluid pressure and prevents a blowout.
On the tree 134 and in line with the casing 108 may be one or more blowout preventers 122. Blowout preventers 122 may include one or more annular blowout preventers 124 and one or more ram blowout preventers 126-130. Annular blowout preventer 124 may include an elastomer element that inflates around drill string 110 and completely seals off the annulus by coming into tight contact with the drill string 110 and the walls of the casing 108. When a kick has been controlled and it is determined that fluid pressures have reached safe levels, the annular blowout preventer 124 may be deflated and drilling allowed to resume. Ram blowout preventers 126-130 may include blind ram 126, pipe ram 128, and shear ram 130 blowout preventers. A blind ram blowout preventer 126 is intended to operate when there is no drill pipe in the casing 108. The blind ram blowout preventer 126 has two steel plates (rams) on opposite sides of the casing 108 that move tangentially to the casing 108 and meet in the center to fully seal off the annulus. The rams are typically actuated by pistons driven with hydraulic pressure. A pipe ram blowout preventer 128 is similar to a blind ram blowout preventer 126, except that the pipe ram blowout preventer 128 is intended for use when there is drill string 110 inside the casing 108. In the pipe ram blowout preventer 128, each of the steel plates has a semi-circle cutout so that when they meet in the center, they close around the drill pipe and seal off the annulus. The shear ram blowout preventer 130 is similar to the blind ram 126 and pipe ram 128 blowout preventers, except in the shear ram blowout preventer 130, the steel plates are replaced with steel blades. The blades in the shear ram blowout preventer 130 are designed to completely sever the drill pipe and close off the annulus. Each type of blowout preventer may be used in different particular situations, as will be discussed in further detail below.
Typically, a first line of response to a well kick situation is to inflate the annular elastomer blowout preventer 124 in order to seal off the return flow of fluids in the annulus. Next, a heavy weight drilling fluid is pumped into the drill string 110 in order to more effectively counteract the force of the high pressure formation fluids. The heavy weight drilling fluid may also be known as a kill fluid. There may be additional ports in the casing 108 below the annular blowout preventer 124 that allow for the heavy weight drilling fluid to be pumped directly into the annulus. During this process, the fluid in the annulus is monitored to determine whether pressures have returned to operational limits. Once pressures have returned to operational limits, the annular blowout preventer 124 is deflated and drilling is allowed to continue. Alternatively, if the kill fluid fails and pressures continue to rise to the extent that return fluids force their way past the annular blowout preventer 124, then the pipe ram blowout preventer 128 is actuated in an attempt to control the well. Also, at any time that drilling fluid is undesirably forced back up through the drill string 110, then one or more drill string valves 132 may be closed in an attempt to stop the reverse flow of drilling fluid. Finally, if all else fails and drilling fluid is forced past both the annular blowout preventer 124 and the pipe ram blowout preventer 128, then shear ram blowout preventer 130 is actuated to sever the drill string 110 and completely seal off the well. Also, shear ram blowout preventer 130 may be actuated anytime one or more of drill string valves 132 fails to effectively stop the reverse flow of drilling fluid in the drill string 110.
The situations described above with respect to monitoring pressures and operating the blowout preventers 124-130 have ordinarily been done manually by an operator in charge of reviewing the developing situation and making judgement calls. This manner of operating drilling rig 100 is fraught with failure, because the sequence of a well kick may develop faster than an operator can witness and respond with manual actuation of a blowout preventer 124-130. For example, an initial well kick may be controlled successfully with quick actuation of the annular blowout preventer 124 in combination with a kill fluid, as discussed above. However, if the initial well kick is not quickly controlled, the upward flow of formation fluids may accelerate to the point where all drilling fluids have been ejected from the well and the entire length of the annulus is filled with highly pressurized formation fluids. At this point it may be too late to use either the annular blowout preventer 124 or pipe ram blowout preventer 128, and actuation of the shear ram blowout preventer 130 may be necessary to save the well. In other words, the column of drilling fluid in the drill string 110 and annulus provide a certain amount of downward pressure on the formation fluid, and it is desirable to maintain these levels in order to help control a kick. Once the drilling fluid has been ejected, the benefits from its downward pressure are lost. A drilling computer 140 may be provided for controlling one or more components of drilling rig 100, as will be discussed in further detail below.
Turning to FIG. 2 , embodiments disclosed herein are shown and described with reference to a horizontal drilling rig 200. It will be appreciated that features of horizontal drilling rig 200 may also be implemented in other drilling arrangements, such as a vertical drilling rig. Horizontal drilling rig 200 may include well bore 202, casing 204, and drill string 206 disposed therein. Drill string 206 may terminate at drill bit 210. The space between drill string 206 and casing 204 may be referred to as the annulus 208. At the top of casing 204 is an annular seal 250 that forms a tight seal between casing 204 and drill string 206. The annular seal 250 is tight enough to prevent drilling fluids from escaping the annulus 208 while also flexible enough to allow rotational movement of the drill string 206 during drilling. At the top of horizontal drilling rig 200 may be a mud pump 212. Operation of mud pump 212 is aided by mud pump selector valve 214, which allows mud pump 212 to selectively pump drilling mud from mud reservoirs 216 and 218 into drill string 206. In similar fashion to the description provided for FIG. 1 above, drilling mud is pumped into drill string 206 and out of fluid ports in drill bit 210. The circulation of drilling mud helps to scavenge rock fragments and formation fluids that are the result of drill bit 210 coming into contact with a geological formation. The drilling mud, along with any rock fragments and formation fluids, then follows on a return path up the annulus 208 and out of a port in annular seal 250 that allows the return of drilling mud to mud reservoirs 216 and 218.
Reservoir selector valve 220 may allow drilling mud to be returned to either of reservoir 216 or reservoir 218. Reservoir 216 may contain an ordinary drilling fluid or drilling mud that is of such a viscosity as to support normal drilling operations. Reservoir 218 may contain a heavy weight drilling fluid known as a kill fluid. The kill fluid in reservoir 218 may be used during certain well kicks in order to help suppress an undesired pressure spike caused by the release of high pressure formation fluids. The forward flow of compressed drilling fluid traveling from mud pump 212 through drill string 206 to drill bit 210 is denoted generally by directional arrows accompanied with the letter “C.” Further, displaced fluids that may contain drilling fluids and formation fluids following a return path up annulus 208 and back to reservoirs 216 and 218 is denoted generally by directional arrows accompanied with the letter “D.”
Disposed around the drill string 206 in the annulus 208 at spaced intervals may be one or more downhole blowout preventers 222, 224, and 226. Downhole blowout preventers 222-226 may be annular blowout preventers similar to the annular blowout preventer 124 discussed in FIG. 1 above. Also disposed around drill string 206 in the annulus 208 may be an annular valve 228 that is used to control the flow rate and pressure of returning fluids in the annulus 208. At the surface of horizontal drilling rig 200 is ground 230, and everything below ground 230 may be generally denoted as bottomhole assembly (BHA) 232. On the drill string 206 ahead of blowout preventer 226 may be a lower drill string valve 234. Further, on the drill string 206 behind blowout preventer 226 may be a circulation port 236. At the top of drill string 206 may be an upper drill string valve 238. Operation of lower drill string valve 234, circulation port 236 and upper drill string valve 238 may allow for control of mud flow in the drill string 206, as well as control of communicating fluids between drill string 206 and annulus 208.
Feedback control of horizontal drilling rig 200 will now be discussed in accordance with one or more embodiments. Horizontal drilling rig 200 may be attached to a drilling computer 240. Drilling computer 240 may contain one or more electronic components that allow it to receive information from various sensors and transducers disposed on horizontal drilling rig 200, process the information in accordance with a drilling program, and output one or more commands as feedback to the various sensors and transducers on the horizontal drilling rig 200. Drilling computer 240 may have an above-ground antenna 256 for communicating with above-ground components. Communication signals radiated by above-ground antenna 256 may be electromagnetic radio waves. Drilling computer 240 may also have a below-ground antenna 258 for communicating with below-ground components. Communication signals radiated by below-ground antenna 258 may be electromagnetic radio waves or mechanical waves. Drilling computer 240 may also have one or more wired connections for communicating with above-ground and below-ground components.
Behind drill bit 210 may be a downhole instrument package 242. Downhole instrument package 242 may contain a downhole pressure sensor that measures the pressure of the drilling fluid at that location. Downhole instrument package 242 may also contain a downhole data transmission device, which may be a mud pressure encoded transducer that sends data up the mud column towards the surface using pressure waves in the drilling fluid. Alternatively, downhole data transmission device may be a radio device that communicates with drilling computer 240 using radio waves. The downhole instrument package 242 may be powered by a battery 244. In one embodiment, the battery 244 is charged by a generator that derives its energy from the flow of drilling fluid or from the rotation of the drill string 206, or both.
Packer element 246 may also be disposed on drill string 206. Additionally, packer element 246 may have a mid-pipe instrument package 248 containing a mid-pipe pressure sensor and a mid-pipe data transmission device, similar to downhole instrument package 242. Further, top-hole instrument package 252 may be disposed on annular seal 250. Top-hole instrument package 252 may have a top-hole pressure sensor and a top-hole data transmission device, similar to downhole instrument package 242 and mid-pipe instrument package 248.
At the top of return fluid path “D” on ground 230 may be a return drilling mud analyzer 254. Return drilling mud analyzer 254 may communicate with drilling computer 240 and provide feedback related to return mud pressure, flow rate, and particulate size. Return drilling mud analyzer 254 may also provide drilling computer 240 with information related to the chemical contents of the returning fluid, such as the presence of petroleum and hydrocarbons. Return drilling mud analyzer 254 may keep track of the ratio of drilling fluids and formation fluids in the returning fluid. Mud pump 212 may have mud analyzer circuitry similar to that of the return drilling mud analyzer 254. In this way, mud pump 212 may analyze all of the same parameters of the outgoing drilling fluid as those measured by the return drilling mud analyzer 254 on the returning drilling fluid. Finally, mud pump 212 may have a diversion path for diverting unwanted fluid to a diversion reservoir (not shown). For example, mud pump 212 may divert its pumping action to the diversion reservoir if the fluid it picks up from reservoirs 216 and 218 contain any unwanted constituents, such as large particulates or excess formation fluids.
Various drilling methods exist, such as Conventional Drilling Operations (CDO), Underbalanced Drilling (UBD), and Managed Pressure Drilling (MPD). When MPD is used, the downhole pressure must be kept within a Drilling Window between the fracture pressure and the pore pressure. This may also be referred to as the Acceptable Drilling Pressure Range (ADPR) or Constant Pressure Drilling (CPD).
Closed-loop feedback control is used to maintain the downhole pressure within acceptable limits if the mud is a Newtonian fluid, or a Bingham plastic fluid, or any other wellbore fluid. In some embodiments, this is done by requiring the drilling computer 240 to issue commands to mud pump 212 to continually adjust and update the pressure moment by moment to maintain the desired flow rate and to maintain the pressure at the drill bit 210 within the Drilling Window. This may be done by coordination of drilling computer 240 with mud pump 212, downhole instrument package 242, mid-pipe instrument package 248, top-hole instrument package 252, and return drilling mud analyzer 254. The drilling computer 240 controls the mud pump 212, and the mud pump 212 is able to control its output pressure as a first parameter at any instant in time, and its mud flow rate as a second parameter at any instant in time. Sensors measuring such quantities as pressure and flow rate are disposed as necessary along any portion of the fluid flow path “C” to “D” in order to ensure that the close-loop feedback system will maintain the pressure at the drill bit 210 within the Drilling Window.
FIG. 3 shows a computing device 300 for drilling operations in accordance with one or more embodiments. Computing device 300 may be similar to drilling computer 240 described in FIG. 2 above. The drilling computing device 300 includes processor 302, memory devices 310, power plug 308, network interface controller (NIC) 304, hard disk drive (HDD) 306, management and control circuit 312, boot drive 314, and input output (I/O) circuitry 316-320. Processor 302 comprises a processor and interface for communicating with various sensors and transducers via NIC 304 over I/O circuitry 316-320. Processor 302 also comprises a communication interface with memory 310. In some embodiments processor 302 may be an SoC (System-on-a-Chip), a general purpose processor, an application specific integrated circuit (ASIC), or another device that provides processing capability and communicates with I/O circuitry 316-320. In some embodiments, management and control circuit 312 manages conditions of drilling computer 300 such as temperature conditions. In some embodiments, management and control circuit 312 includes an interface for connecting with an external heath monitoring system, such as an intelligent platform management interface (IPMI). In some embodiments, memory devices 310 are RAM devices such as double data rate fourth generation synchronous dynamic random-access memory (DDR4) or other suitable RAM devices.
Power connector 308 may be configured to receive electrical power via a cable connection, and in some embodiments, power connector 308 may be configured to couple with a backplane and receive electrical power via the backplane. In some embodiments, boot drive 314 is a solid state drive that stores program instructions for booting drilling computer 300. In some embodiments, boot instructions for drilling computer 300 may be stored in a remote location and boot drive 314 may be omitted.
Processor 302 communicates over I/O circuitry 316-320 with the aid of NIC 304. In some embodiments, I/O circuitry 316-320 may provide wired connections, such as small form factor pluggable IEEE 802.3 Ethernet ports or other suitable ports for a wired connection. I/O circuitry 316-320 may also support wireless connections, such as IEEE 802.11 WLAN connections, 3GPP 4G and 5G cellular connections, or a combination of both. I/O circuitry 316-320 may all provide wired connections, all provide wireless connections, or provide both wireless and wired connections. Additionally, one or more of I/O circuitry 316-320 may provide measurement while drilling (MWD) and/or logging while drilling (LWD) connections. MWD and LWD connections may provide communication via one or more of mud pulse telemetry, electromagnetic telemetry, and wired drill pipe.
HDD 306 may permanently store data and programs necessary for the functioning of drilling computer 300. HDD 306 may include traditional storage technology such as rotating magnetic platters that are accessed by one or more electromagnetic heads, or, HDD 306 may include newer solid state disks (SSDs) that store information in flash memory, such as NAND flash and/or NOR flash. HDD 306 may employ any number of long-term storage transfer protocols, such as Parallel ATA (PATA), Serial ATA (SATA), and/or Small Computer System Interface (SCSI). HDD 306 may contain one or more drilling programs that guide the operations of drilling computer 300 in communication with various sensors and transducers on a drilling rig. In this manner, drilling computer 300 may provide closed-loop feedback control of a drilling rig, as described in FIG. 2 above. The drilling programs on HDD 306 may convert the components of drilling computer 300 from a general purpose computer to a special purpose computer for drilling operations. Drilling computer 300 may execute different drilling programs depending on what type of operation is needed for a given situation, as will be discussed in further detail below.
The term “storage mechanism” includes any type of memory, storage device or other mechanism for maintaining instructions or data in any format. “Computer-readable medium” is an extensible term including any memory, storage device, storage mechanism, and any other storage and signaling mechanisms including interfaces and devices such as network interface cards and buffers therein, as well as any communications devices and signals received and transmitted, and other current and evolving technologies that a computerized system can interpret, receive, and/or transmit. The term “memory” includes any random access memory (RAM), read only memory (ROM), flash memory, integrated circuits, and/or other memory components or elements. The term “storage device” includes any solid state storage media, disk drives, diskettes, networked services, tape drives, and other storage devices. Memories and storage devices may store computer-executable instructions to be executed by a processing element and/or control logic, and data which is manipulated by a processing element and/or control logic. The term “computer-readable storage medium” may refer to only tangible types of computer-readable media, which excludes intangible, transitory media, such as signals and carrier waves.
According to one or more embodiments, an automated drilling procedure is provided herein. The automated drilling procedure may be carried out by a drilling computer on a drilling rig. For example, the automated drilling procedure may be carried out by one or more of drilling computer 140 in FIG. 1 , drilling computer 240 in FIG. 2 , and/or drilling computer 300 in FIG. 3 . FIG. 4 depicts a flowchart detailing such an automated drilling procedure 400 in accordance with one or more embodiments. One or more blocks in FIG. 4 may be performed by one or more components as described in FIGS. 1-3 . Operations in FIG. 4 may be performed by components from only one of FIGS. 1-3 , or operations in FIG. 4 may be performed by components from several of FIGS. 1-3 . For example, operations in FIG. 4 may be performed by components of horizontal drilling rig 200 in combination with components of drilling rig 100. In one specific non-limiting embodiment, horizontal drilling rig 200 with bottomhole assembly 232 of FIG. 2 may be combined with an above-ground tree 134 of FIG. 1 . In such a configuration, the entire drilling rig may include downhole blowout preventers 222-226 in addition to tree blowout preventers 124-130. While the various blocks in FIG. 4 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.
The process begins at step 402, which includes an automated check of downhole parameters. With reference to FIG. 2 , this may include reading parameters from one or more components, including downhole instrument package 242, mid-pipe instrument package 248, top-hole instrument package 252, return drilling mud analyzer 254, and mud pump 212. Step 402 may include measuring one or more of pressure, temperature, flow rate, and fluid composition at one or more of the above-mentioned components in real-time. Step 402 may include analyzing all of the available parameters in order to operate the drilling rig in accordance with Managed Pressure Drilling (MPD), as discussed in FIG. 2 above. In step 402, when MPD is employed, the drilling computer 240 manages all of the components of drilling rig 200 in order to maintain the pressure at drill bit 210 within a Drilling Window. For example, using MPD in step 402, and based on all of the available parameters, the drilling computer 240 may increase or decrease the pressure output at mud pump 212, open or close one or more of circulation port 236 and drill string valves 234 and 238, and/or adjust the position of reservoir selector valve 220 and mud pump selector valve 214 to modify the composition of the drilling fluid being pumped from reservoirs 216 and 218.
The process continues at step 404, which asks whether a well kick has been detected. Similar to step 402, step 404 may include reading parameters from one or more components, including downhole instrument package 242, mid-pipe instrument package 248, top-hole instrument package 252, return drilling mud analyzer 254, and mud pump 212. Detecting a kick according to step 404 may also include determining the positions of circulation port 236 and drill string valves 234 and 238, as well as the positions of reservoir selector valve 220 and mud pump selector valve 214. Step 404 may include analyzing all of the parameters of drilling rig 200 that are available to drilling computer 240. In performing this analysis, drilling computer 240 may be looking for a particular pressure signature that indicates a kick. This may be known as a kick pressure signature. For example, the kick pressure signature may be confirmed as being detected when wellbore pressure, which may include the pressure of any released formation fluids, is higher than hydrostatic pressure. Wellbore pressure, or formation fluid pressure, may be constantly monitored by downhole instrument package 242 and fed back to drilling computer 240. As drill bit 210 comes into destructive contact with geological formations in the process of drilling, downhole instrument package 242 provides constant and instantaneous analysis of pressures in the wellbore due to any released formation fluids. Hydrostatic pressure may be defined as pressure due to a column of fluid that is not moving. That is, a column of fluid that is static, or at rest, exerts pressure due to the force of gravity on the column of the fluid. With reference to FIG. 2 , the column of fluid that constitutes hydrostatic pressure may be all of the fluids in annulus 208 that extend from drill bit 210 up the wellbore to annular seal 250. In some embodiments, normal hydrostatic pressure may be calculated based on a current depth of the drilling operation. For example, hydrostatic pressure may be defined as: Height (m) × Density (kg/m3) × Gravity (m/s2). Normal downhole fluid pressure may be defined as 0.5 pounds per square inch (psi) per foot of drilling depth. Normal downhole fluid pressure may also be defined as 0.47 psi per foot of drilling depth. In one or more embodiments, instant calculation of hydrostatic pressure may involve one or more of top-hole instrument package 252, mid-pipe instrument package 248, and downhole instrument package 242. Signals from each of these components may be fed back to drilling computer 240 for processing thereof. One important parameter related to the various pressures that are continuously available at drilling computer 240 is known as the delta pressure. The delta pressure may be the difference between formation fluid wellbore pressure and the hydrostatic pressure. A positive delta pressure indicates that formation fluid wellbore pressure has exceeded hydrostatic pressure, and a negative delta pressure indicates that formation fluid wellbore pressure is less than the current hydrostatic pressure, which may be preferable. The kick pressure signature may include detecting a pressure impulse of the delta pressure of a threshold magnitude occurring for a given duration. For example, the kick pressure signature may be confirmed as being detected when delta pressure becomes 125%, 150%, 175%, or 200% of normal delta pressure. Additionally, the kick pressure signature may be confirmed as being detected when the pressure impulse of the delta pressure lasts for 1 second, 5 seconds, 15 seconds, or 30 seconds. In one or more embodiments, detection of a kick pressure signature may automatically result in drilling rig 200 performing a number of well shut-in procedures. Accordingly, accurate detection of a kick pressure signature is critical, since premature detection thereof and automated shut-in of the drilling rig 200 may result in significant down time at the well. If there are no well kick experts on site, premature activation of well shut in may require soliciting additional personnel to the drilling site in order to assess the safety of the well and determine whether the shut-in process can be reversed and drilling allowed to continue. Alternatively, late or delayed detection of a kick pressure signature may result in the sequence of a well blowout developing faster than any remediation measures can be put in place to control it. It will be appreciated that accurate detection of a kick pressure signature may be a critical aspect to the invention. Further, drilling computer 240 may implement a number of analytics to measure ongoing delta pressure values in order to accurately detect a well kick. Drilling computer 240 may record delta pressures over a period of time and compare them to various kick signatures. The data comprising the delta pressures (e.g. delta pressure data) and the data comprising the kick signatures (kick signature data) may each be graphed to form a delta pressure graph and a kick signature graph. Detection of a well kick may involve a detailed comparison of delta pressure graph with kick signature graph. For example, a well kick may only be detected when the delta pressure graph exceeds the kick signature graph for at least a threshold period. Alternatively, a well kick may only be detected when the delta pressure graph exceeds the kick signature graph by at least a threshold amount. Finally, a well kick may only be detected when the delta pressure graph exceeds the kick signature graph for a combination of a threshold amount for at least a threshold period. The area between these graphs that is bounded by where the threshold amount exceeds the kick signature graph for the threshold period may be referred to as the kick volume. The activation of automatic well shut-in may be determined based on a comparison of the kick volume with various thresholds. For example, a kick with both a low threshold amount and a low threshold period may not be determined to satisfy the particular kick signature for that given scenario. Alternatively, a kick with a high threshold amount and a low threshold period may trigger the given kick volume for that scenario and cause well shut-in. Similarly, a kick with a low threshold amount but a long threshold period may also trigger the given kick volume for that scenario and cause s well shut-in. The kick signatures may be tailored specifically for one or more of: a given geological formation, a type of formation fluid, and constituent components of the bottomhole assembly 232. The design of each kick pressure signature may be carried out by well experts at an off site location and then sent or uploaded to drilling computer 240. If a well kick is not detected at step 404, then the process may return to step 402 where the process continues the automated check of downhole parameters as discussed above. If a well kick is detected at step 404, then the process may continue to step 406.
Upon detecting a well kick at step 404, step 406 may include alerting the drilling crew and/or initiating an automated shut-in procedure. Next, the process continues to step 408 where it is determined whether it has been indicated to perform a well shut-in at the surface and inside the well. In embodiments of the process 400 that only include the human-initiated well shut-in procedure, then steps 406 and 408 may only include continuing to notify the crew of the detected well kick and waiting for an indication from the crew to perform the well shut-in procedure. Alternative, in embodiments of the process 400 that include the computer-initiated automated well shut-in procedure, then steps 406 and 408 may include notifying the crew of the detected well kick and automatically performing well shut-in based on the detected kick. It is important to note that embodiments that include the computer-initiated automated well shut-in procedure may automatically cause a well shut-in without any human intervention whatsoever. In any case, when well shut-in is indicated at step 408, then the process proceeds to step 410.
At step 410, the process automatically starts mud pump circulation and performs packer inflation. Step 410 may include controlling mud pump 212 to adjust pressure and/or flow rate of the drilling fluid. For example, step 410 may include controlling mud pump 212 to increase pressure and/or flow rate of the drilling fluid. Step 410 may also include controlling mud pump 212 to adjust the composition of the drilling fluid being drawn from reservoirs 216 and 218 by modulating mud pump selector valve 214. Step 410 may include modulating mud pump selector valve 214 to only draw normal drilling fluid from reservoir 216, only kill fluid from reservoir 218, or a combination of fluids from reservoirs 216 and 218. Step 410 may also include retracting a protection sleeve around the packer elements of one or more of annular blowout preventers 124 and 222-226 using differential pressure. Step 410 may also include starting to inflate the packer elements of one or more of annular blowout preventers 124 and 222-226. Inflating the packer elements according to step 410 may include diverting drilling fluid from the annulus 208 into the packer elements using a diverter valve. Inflating the packer elements according to step 410 may also include injecting a hydraulic fluid that is not a drilling fluid into the packer elements. The hydraulic fluid may be stored in canisters that are proximal to the packer elements and are activated in response to a well kick. Inflating the packer elements according to step 410 may also include inflating the packer elements with a pressurized gas. The pressurized gas may be stored in canisters that are proximal to the packer elements and are activated in response to a well kick.
Step 410 may further include closing the surface blowout preventers, such as pipe ram blowout preventer 128. Step 410 may further include closing one or more of downhole drill string valve 234 and top-hole drill string valve 238. Step 410 may further include stopping top drive rotation of the drill string 206. Step 410 may further include stopping the mud pump 212 before activating the mud pump 212 again to achieve a desired pressure. Step 410 may further include opening a choke valve line (HCR). Step 410 may further include deactivating batter 244 from power all devices in the bottomhole assembly 232 besides annular blowout preventers 222-226.
Next, the process proceeds to step 412, which includes confirming that the downhole blowout preventers are set and the annulus is sealed. Step 412 may be performed by drilling computer 240 in coordination with one or more components of drilling rig 200. For example, step 412 may include drilling computer 240 receiving a signal from one or more of annular blowout preventers 124, 222-226 and annular seal 250 confirming that each of these elements is fully sealed. Step 412 may further include switching off mud pump 212 and bleeding off slow pump pressure (SPP).
Next, the process proceeds to step 414, which includes confirming that well shut-in at the surface and downhole is complete. Step 414 may be performed by drilling computer 240 in coordination with one or more components of drilling rig 200. For example, step 414 may include drilling computer 240 receiving signals from one or more of downhole instrument package 242, mid-pipe instrument package 248, top-hole instrument package 252, return drilling mud analyzer 254, and mud pump 212. Step 414 may include drilling computer 240 communicating with the above-mentioned components to confirm that the kick has been suppressed. Confirming that the kick has been suppressed according to step 414 may include detecting a suppression pressure signature. For example, the suppression pressure signature may be confirmed as being detected when downhole fluid pressure becomes 50%, 75%, 100%, 125%, or 150% of normal downhole fluid pressure. Additionally, the suppression pressure signature may be confirmed as being detected when the suppression pressure impulse lasts for 30 seconds, 1 minute, 5 minutes, 10 minutes, 15 minutes, 30 minutes, or an hour. Step 414 may further include the drilling computer 240 monitoring one or more calculated parameters, including shut-in drill pipe pressure (SIDPP), and/or shut-in casing pressure (SICP).
Step 414 may include one or more additional last-resort well control steps if the suppression pressure signature is not able to be confirmed. The last-resort well control steps may be initiated if the suppression pressure signature is not detected within a suppression period of time. The suppression period of time may be 1 minute, 5 minutes, 15 minutes, or 30 minutes. Alternatively, or in combination, the last-resort well control steps may be initiated if the kick pressure signature detected in step 404 exceeds a last-resort threshold. For example, the last-resort threshold may be confirmed as being detected when downhole fluid pressure becomes 150%, 200%, 300% or 400% of normal downhole fluid pressure. Additionally, the last-resort threshold may be confirmed as being detected when the pressure impulse lasts for 2 seconds, 5 seconds, 15 seconds, 30 seconds, 1 minute, 5 minutes, 10 minutes, 15 minutes, 30 minutes, or an hour.
In any case, initiation of the last-resort well control steps may occur if the suppression pressure signature is not detected and/or if the kick pressure signature exceeds the last-resort threshold. The last-resort well control steps may include activating the sheer ram blowout preventer 130. As discussed in FIG. 1 above, upon activation, sheer ram blowout preventer 130 severs the drill string and seals off the well. Additionally, once shear ram blowout preventer 130 has severed the drill string, blind ram blowout preventer 126 may also be activated to further protect the well from a blowout. These steps are considered a last resort, because once the drill string is severed, drilling cannot continue. It is preferable to respond to a well kick using annular blowout preventers, in accordance with the steps described above, quickly enough to suppress the kick and avoid using the last-resort well control steps. It will be appreciated that carefully tuning drilling computer 240 to detect the kick pressure signature will optimize the response of the drilling rig 200 to a developing well kick situation. As described above, drilling computer 240 may respond automatically to a developing well kick situation without any input from human operators. After monitoring the response of drilling computer 240 to various drilling operations and well kicks, drilling operators may continually tune the response of the drilling computer 240 to provide more optimal kick responses. Once step 414 is complete, the process continues to step 416.
At step 416, the process deflates the packer elements and applies a well control procedure. If the last-resort well control steps were initiated in step 414, then step 416 may include summoning additional drilling personal or blowout specialists to assess the well. In this situation, it may be determined that the well has been safely controlled and drilling may continue. Further, the ram-type blowout preventers may be retracted and the broken drill string retrieved from the well. After this point, drilling can continue. Alternatively, if the last-resort well control steps were not initiated in step 414, then step 416 may simply include deflating the annular blowout preventers and continuing drilling. If drilling continues, then the process may return to step 402. If drilling does not continue, then the process ends.
Embodiments disclosed herein provide a method and apparatus for automatically detecting any influx entering the well and controlling all types of wells (oil, gas and/or water) using an automated well shut-in process and downhole tools that are integrated in the bottom hole assembly (BHA). The downhole autonomous blow-out preventer technology is an electronically and automated controlled actuating gas tight mechanism used to seal, control and monitor oil, gas, and water wells to prevent blowouts, the uncontrolled release of any fluid (crude oil, natural gas, and/or water) from a well. The system includes a computerized surface and remote control system that programs the autonomous blow-out preventer.
The technology provides a new well control barrier, enables simple deployment while introducing a new way to detect the influx as soon as it enters the well, deal with kicks and control the well downhole and not at surface, in challenging conditions including HPHT wells, deepwater wells, H2S & CO2 etc. This new methodology has many advantages, including but not limited to, saving lives, prevent oil spills and toxic gas to reach the surface, and protecting company’s assets and reputation. Moreover, this technology contributes in better risk management, elimination of human errors, and time/cost savings. Once the electronic actuation features have exceeded the battery life, which should be the duration of the drilling phase (plus safety factor) presenting well control issues, the downhole BOP will be part of the drillstring without compromising the tubular integrity.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

What is claimed:

1. An automated method for responding to a well kick, the method comprising:

monitoring downhole parameters in a wellbore;

based on the downhole parameters, detecting a kick pressure signature;

in response to detecting the kick pressure signature, automatically performing a well shut-in procedure.

2. The method of claim 1, wherein monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by a computer without any human intervention.

3. The method of claim 2, wherein the automatically performing the well shut-in procedure includes activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.

4. The method of claim 3, wherein the modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.

5. The method of claim 1, wherein detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.

6. The method of claim 5, wherein the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.

7. A non-transitory computer-readable storage media having computer-readable instructions stored thereon, which when executed by a computer cause the computer to perform the method comprising:

monitor downhole parameters in a wellbore;

based on the downhole parameters, detect a kick pressure signature;

in response to detecting the kick pressure signature, automatically perform a well shut-in procedure.

8. The non-transitory computer-readable storage media of claim 7, wherein monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by the computer without any human intervention.

9. The non-transitory computer-readable storage media of claim 8, wherein the automatically performing the well shut-in procedure includes activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.

10. The non-transitory computer-readable storage media of claim 9, wherein the modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.

11. The non-transitory computer-readable storage media of claim 7, wherein detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.

12. The non-transitory computer-readable storage media of claim 11, wherein the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.

13. A drilling rig comprising:

a drilling computer;

a bottomhole assembly; and

a drilling pump

wherein the drilling computer is configured to:

monitor downhole parameters in a wellbore;

based on the downhole parameters, detect a kick pressure signature;

14. The drilling rig of claim 13, wherein monitoring the downhole parameters, detecting the kick pressure signature, and automatically performing the well shut-in procedure are performed by the computer without any human intervention.

15. The drilling rig of claim 14, wherein the automatically performing the well shut-in procedure includes activating one or more annular blowout preventers and modulating a drilling pump to achieve a shut-in fluid pressure.

16. The drilling rig of claim 15, wherein the modulating the drilling pump to achieve the shut-in fluid pressure further includes modulating a mud pump selector valve to control a content of a drilling fluid being pumped by the drilling pump and modulating one or more drillstring valves.

17. The drilling rig of claim 13, wherein detecting the kick pressure signature includes detecting a fluid pressure impulse that exceeds a normal drilling fluid pressure by a first amount for a threshold period of time, or detecting a fluid pressure impulse that exceeds the normal drilling fluid pressure by a second amount for any period of time.

18. The drilling rig of claim 17, wherein the first amount is 25% of the normal drilling fluid pressure, and the second amount is 50% of the normal drilling fluid pressure.