US20150267475A1

US20150267475A1 - Rotating jetting device and associated methods to enhance oil and gas recovery

Info

Publication number: US20150267475A1
Application number: US14/576,238
Authority: US
Inventors: Philip Marlow
Original assignee: Individual
Current assignee: Individual
Priority date: 2014-03-19
Filing date: 2014-12-19
Publication date: 2015-09-24

Abstract

Disclosed are a method, device and/or a system of rotating jetting device and associated methods to enhance oil and gas recovery. In one aspect, a jetting device includes a motor gearbox inside the jetting device, a central processing system coupled to the motor gearbox, a transducer assembly coupled with the motor gearbox and the central processing system, and a top assembly. The top assembly is electromechanically coupled with the motor gearbox, the transducer assembly, and the central processing system and causes the jetting device to rotate based on the set of instructions received from the central processing system.

Description

CLAIMS OF PRIORITY

This patent application is a non-provisional and claims priority of the U.S. provisional patent application No. 61/955,229, titled ‘AUTONOMOUS DOWNHOLE DATA MEASUREMENT AND UNDERBALANCED ROTATING MULTI-LATERAL JETTING DEVICE’ filed on Mar. 19, 2014.

FIELD OF TECHNOLOGY

This disclosure relates generally to data processing devices and, more particularly, to a method, a device and/or a system of rotating jetting device and associated methods to enhance oil and gas recovery.

BACKGROUND

An oil well may be a boring into the Earth that is designed to bring petroleum oil hydrocarbons to the surface. Over time, resources extractable (e.g., oil, gas) in the oil well may deplete and the oil well may not be able to be productively operated. Challenges may include pressure depletion, formation damage, low permeability, low porosity, and/or formation access. For example, pressure depletion may contribute to lower production rates and/or a gradual drop in fluid mobility through the reservoir. In addition, formation damage (e.g., damage to the surrounding Earth around the wellbore) can be a short to medium radius effect around a wellbore. This formation damage may cause lower than expected production rates and/or in some cases total restriction of flow. Moreover, low permeability can extend out all the way throughout the reservoir and create an issue for fluid mobility and production into the wellbore (e.g., regardless of the nature of the well design and/or perforation design).
In addition, low porosity may create a number of issues for production flow through the reservoir and into the wellbore. Further, perforations may involve hazardous operations. In older, depleted wells, such perforations may be made with low quality tools that provided very short radius access to the formation, while creating small restrictive casing exits through which to accept production flow. This may impede productivity of the oil well.

SUMMARY

Disclosed are a method, a device and/or a system of rotating jetting device and associated methods to enhance oil and gas recovery.
In one aspect, a jetting device includes a motor gearbox inside the jetting device to cause the jetting device to rotate based on a set of instructions (e.g., while downhole in a wellbore). The jetting device includes a central processing system coupled to the motor gearbox, a transducer assembly, and a top assembly to electromechanically couple with the motor gearbox, the transducer assembly, and the central processing system. The motor gearbox causes the jetting device to rotate based on a set of instructions received from the central processing system.
A rotation of the jetting device may be controlled precisely to a nearest one degree while the jetting device is still at a target depth in a wellbore based on a programming of the central processing system through a command from an above ground computing system communicated to the jetting device while still inserted in the wellbore or a pre-programmed script automatically executed while the jetting device is inside the wellbore.
The pre-programmed script may be automatically overridden utilizing a pressure pulse technology in which a pressure signal is transmitted to the jetting device while it is downhole in the wellbore at the target depth to cause the jetting device to rotate. The jetting device may automatically align to a pre-made casing exit in the wellbore at the target depth to reach a formation encompassing the wellbore. A pumping liquid may be passed using a jetting hose having a nozzle through the pre-made casing exit to cause the jetting hose to cut up to a 100 meter lateral tunnel perpendicular to the wellbore using the nozzle. The jetting device may automatically rotate to the next casing exit while at the target depth and/or to cut up to eight or more lateral tunnels at the target depth through additional pre-made casing exits at the target depth.
The rotation of the jetting device may be programmed wirelessly from the above ground computing system through a wireless network formed between the jetting device (e.g., downhole in the wellbore) and the above ground computing system. A temperature data and/or a pressure data may be captured using the transducer assembly at the target depth. The temperature data and/or the pressure data may be stored locally on a storage device of the central processing unit (e.g., or wirelessly communicated to the above ground computing system).
In another aspect, a method includes programming a rotation of a jetting device using a central processing system coupled with the jetting device through a command from an above ground computing system communicated to the jetting device while the jetting device is still inserted in a wellbore and a pre-programmed script automatically executed while the jetting device is inside the wellbore. The method causes a motor gearbox inside the jetting device to induce the rotation of the jetting device while the jetting device is downhole in the wellbore based on the programming of the rotation of the jetting device using a processor and a memory of the central processing system coupled with the jetting device through the command from the above ground computing system communicated to the jetting device while the jetting device is still inserted in the wellbore and/or the preprogrammed script automatically executed while the jetting device is inside the wellbore. The programming is controlling precisely to a nearest one degree while the jetting device is still at a target depth in the wellbore in this another aspect.
The method may include automatically overriding the preprogrammed script utilizing a pressure pulse technology in which a pressure signal is transmitted to the jetting device while it is downhole in the wellbore at the target depth to cause the jetting device to rotate. Further, the method may automatically align the jetting device to a pre-made casing exit in the wellbore at the target depth to reach a formation encompassing the wellbore. A pumping liquid may be channeled using a jetting hose having a nozzle through the pre-made casing exit to cause the jetting hose to cut up lateral tunnels (e.g., 100 meters) perpendicular to the wellbore using the nozzle. The jetting device may be automatically rotated to the next casing exit while at the target depth (e.g., may cut any number of lateral tunnels at the target depth through additional pre-made casing exits at the target depth).
A temperature data and/or a pressure data may be captured using a transducer assembly at the target depth. The rotation of the jetting device may be wirelessly programmed from the above ground computing system through a wireless network between the jetting device and the above ground computing system. The temperature data and/or the pressure data may be communicated to the central processing unit and/or the above ground computing system through the central computing system after the jetting device is removed from the wellbore. For example, the temperature data and/or the pressure data may be communicated in real time through the wireless network (e.g., and/or a wired network) communicating directly to the above ground computing system.
In yet another aspect, a jetting device includes a motor gearbox inside the jetting device to cause the jetting device to rotate based on a set of instructions while inside a wellbore at a target depth, a central processing system coupled to the motor gearbox, a transducer assembly coupled with the motor gearbox and the central processing system to capture a temperature data and a pressure data at the target depth inside the wellbore. Furthermore, a top assembly electromechanically couples with the motor gearbox, the transducer assembly, and the central processing system to cause the jetting device to rotate based on the set of instructions received from the central processing system in this yet another aspect.
The methods and systems disclosed herein may be implemented in any means for achieving various aspects, and may be executed in a form of a non-transitory machine-readable medium embodying a set of instructions that, when executed by a machine, cause the machine to perform any of the operations disclosed herein. Other features will be apparent from the accompanying drawings and from the detailed description that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The embodiments of this invention are illustrated by way of example and not limitation in the figures of the accompanying drawings, in which like references indicate similar elements and in which:

FIG. 1 is a schematic diagram of a jetting device showing the inside assembly of the jetting device, according to one embodiment.

FIG. 2 is an environment view of the jetting device of FIG. 1 communicatively coupled with an above ground computing system inside a wellbore, according to one embodiment.

FIG. 3 is an environment view of the jetting device of FIG. 2 inside the wellbore automatically aligning to a pre-made casing exit at a target depth and cutting a lateral tunnel perpendicular to the wellbore using a nozzle, according to one embodiment.

FIG. 4 is a user interface view of the jetting device of FIG. 1, according to one embodiment.

FIG. 5 is a process flow describing a method of jetting device of FIG. 1 to program a rotation of a jetting device using a central processing system coupled with the jetting device through a command from the above ground computing system communicated to the jetting device while the jetting device is still inserted in a wellbore, according to one embodiment.

FIG. 6 is a schematic diagram of computing device that can be used to implement the methods and systems disclosed herein, according to one or more embodiments.

Other features of the present embodiments will be apparent from the accompanying drawings and from the detailed description that follows.

DETAILED DESCRIPTION

Example embodiments, as described below, may be used to provide a method, a system and/or a device rotating jetting device and associated methods to enhance oil and gas recovery.
In one embodiment, a jetting device 100 includes a motor gearbox 102 inside the jetting device 100 to cause the jetting device 100 to rotate based on a set of instructions 104 while downhole in a wellbore. The jetting device 100 includes a central processing system 106 coupled to the motor gearbox 102, a transducer assembly 108, and a top assembly 110 to electromechanically couple with the motor gearbox 102, the transducer assembly 108, and the central processing system 106. The motor gearbox 102 causes the jetting device 100 to rotate based on a set of instructions 104 received from the central processing system 106.
A rotation 202 of the jetting device 100 may be controlled precisely to a nearest one degree 204 while the jetting device 100 is still at a target depth 206 in a wellbore 208 based on a programming 210 of the central processing system 106 through a command 212 from an above ground computing system 214 communicated to the jetting device 100 while still inserted in the wellbore 208 or a pre-programmed script 216 automatically executed while the jetting device 100 is inside the wellbore 208.
The pre-programmed script 216 may be automatically overridden utilizing a pressure pulse technology 218 in which a pressure signal 220 is transmitted to the jetting device 100 while it is downhole in the wellbore 208 at the target depth 206 to cause the jetting device 100 to rotate. The jetting device 100 may automatically align to a pre-made casing exit 302 in the wellbore 208 at the target depth 206 to reach a formation 304 encompassing the wellbore 208. A pumping liquid 306 may be passed using a jetting hose 308 having a nozzle 310 through the pre-made casing exit 302 to cause the jetting hose 308 to cut up to a 100 meter lateral tunnel(s) 312 perpendicular to the wellbore 208 using the nozzle 310. The jetting device 100 may automatically rotate to the next casing exit while at the target depth 206 and/or to cut up to eight or more lateral tunnel(s) 312 at the target depth 206 through additional pre-made casing exits at the target depth 206.
The rotation 202 of the jetting device 100 may be programmed wirelessly from the above ground computing system 214 through a wireless network 201 formed between the jetting device 100 downhole in the wellbore 208 and the above ground computing system 214. A temperature data 314 and/or a pressure data 316 may be captured using the transducer assembly 108 at the target depth 206. The temperature data 314 and/or the pressure data 316 may be stored locally on a storage device 318 of the central processing unit (e.g., or wirelessly communicated to the above ground computing system 214).
In another embodiment, a method includes programming 210 a rotation 202 of a jetting device 100 using a central processing system 106 coupled with the jetting device 100 through a command 212 from an above ground computing system 214 communicated to the jetting device 100 while the jetting device 100 is still inserted in a wellbore 208 and a pre-programmed script 216 automatically executed while the jetting device 100 is inside the wellbore 208. The method causes a motor gearbox 102 inside the jetting device 100 to induce the rotation 202 of the jetting device 100 while the jetting device 100 is downhole in the wellbore 208 based on the programming 210 of the rotation 202 of the jetting device 100 using a processor 203 and a memory 205 of the central processing system 106 coupled with the jetting device 100 through the command 212 from the above ground computing system 214 communicated to the jetting device 100 while the jetting device 100 is still inserted in the wellbore 208 and/or the pre-programmed script 216 automatically executed while the jetting device 100 is inside the wellbore 208. The programming 210 is controlling precisely to a nearest one degree 204 (e.g. rotation 202) while the jetting device 100 is still at a target depth 206 in the wellbore 208 in this another aspect.
The method may include automatically overriding the pre-programmed script 216 utilizing a pressure pulse technology 218 in which a pressure signal 220 is transmitted to the jetting device 100 while it is downhole in the wellbore 208 at the target depth 206 to cause the jetting device 100 to rotate. Further, the method may automatically align the jetting device 100 to a pre-made casing exit 302 in the wellbore 208 at the target depth 206 to reach a formation 304 encompassing the wellbore 208. A pumping liquid 306 may be channeled using a jetting hose 308 having a nozzle 310 through the pre-made casing exit 302 to cause the jetting hose 308 to cut up lateral tunnel(s) 312 (e.g., 100 meters) perpendicular to the wellbore 208 using the nozzle 310. The jetting device 100 may be automatically rotated to the next casing exit while at the target depth 206 (e.g., may cut any number of lateral tunnel(s) 312 at the target depth 206) through additional pre-made casing exits at the target depth 206).
A temperature data 314 and/or a pressure data 316 may be captured using a transducer assembly 108 at the target depth 206. The rotation 202 of the jetting device 100 may be wirelessly programmed from the above ground computing system 214 through a wireless network between the jetting device 100 and the above ground computing system 214. The temperature data 314 and/or the pressure data 316 may be communicated to the central processing unit and/or the above ground computing system 214 through the central computing system (e.g. central processing system 106) after the jetting device 100 is removed from the wellbore 208. For example, the temperature data 314 and/or the pressure data 316 may be communicated in real time through the wireless network (e.g., and/or a wired network) communicating directly to the above ground computing system 214.
In yet another embodiment, a jetting device 100 includes a motor gearbox 102 inside the jetting device 100 to cause the jetting device 100 to rotate based on a set of instructions 104 while inside a wellbore 208 at a target depth 206, a central processing system 106 coupled to the motor gearbox 102, a transducer assembly 108 coupled with the motor gearbox 102 and the central processing system 106 to capture a temperature data 314 and a pressure data 316 at the target depth 206 inside the wellbore 208. Furthermore, a top assembly 110 electromechanically couples with the motor gearbox 102, the transducer assembly 108, and the central processing system 106 to cause the jetting device 100 to rotate based on the set of instructions 104 received from the central processing system 106 in this yet another aspect.
FIG. 1 is a schematic diagram of a jetting device 100 showing the inside assembly of the device. Particularly, FIG. 1 illustrates a motor gearbox 102, a set of instructions 104, a central processing system 106, a transducer assembly 108, a top assembly 110, a J-tool sub 112, and N2 port(s) 114, according to one embodiment.
Particularly, FIG. 1 illustrates the jetting device 100 may be a mechanical and/or electronic equipment used for spouting a high-velocity fluid stream forced under pressure out of a small-diameter opening (and/or e.g., an orifice). The motor gearbox 102 may be a collection of mechanical components (e.g., a set of gears with its casing) powered by electricity or internal combustion that deliver maximum power from an engine by managing a series of gear ratios that in turn operate a transmission. The set of instructions 104 may be a program that causes the jetting device 100 to rotate. The central processing system 106 may be the part of a computer that performs logical and arithmetical operations on the data as specified in the set of instructions 104 to cause rotation of the jetting device 100. The transducer assembly 108 may be a process of putting together a group of mating components to operate as a device that converts variations in a physical quantity, such as pressure or brightness, into an electrical signal, or vice versa and transmit it to the central processing system 106. The top assembly 110 may be a group of mating components to operate as a device to cause the jetting device 100 to rotate based on the set of instructions 104 received from the central processing system 106. The J-tool sub 112 may be the mechanical and/or electronic equipment inside the jetting device that enables the jetting device 100 (e.g., jetting hose and/or nozzle) to turn 90 degrees and enter the formation and/or the wellbore. The N2 port(s) 114 may be an aperture (e.g., opening and/or hole), especially controlled by a valve, by which fluid may enter or leave the cylindrical head of the jetting device 100, according to one embodiment.
FIG. 1 illustrates the jetting device 100 may include the motor gearbox 102 inside the jetting device 100. The central processing system 106 may be coupled to the motor gearbox 102. The transducer assembly 108 may be coupled with the motor gearbox 102 and the central processing system 106. The top assembly 110 may be electromechanically coupled with the motor gearbox 102, the transducer assembly 108, and the central processing system 106, according to one embodiment.
FIG. 2 is an environment view 250 of the jetting device 100 of FIG. 1 communicatively coupled with an above ground computing system 214 inside a wellbore 208, according to one embodiment.
Particularly, FIG. 2 builds on FIG. 1, and further adds a wireless network 201, a rotation 202, a processor 203, a nearest one degree 204 (of rotation 202), a memory 205, a target depth 206, a database 207, a wellbore 208, a user 209, a programming 210, a command 212, an above ground computing system 214, a pre-programmed script 216, a pressure pulse technology 218, a pressure signal 220, a ground ocean surface 222, and a rig 224, according to one embodiment.
The wireless network 201 (e.g., and/or a wired network) may be any type of computer network that do not use any cable data connections for connecting network nodes (e.g. transducer assembly 108 to an above ground computing system 214). The rotation 202 may be a process of turning or spinning of the jetting device 100 based on the set of instructions 104 received from the central processing system 106. The processor 203 may be a part of a computer, such as the central processing system 106, that performs calculations or other manipulations of data to enable rotation 202 of the jetting device 100 based on the set of instructions 104. The nearest one degree 204 (e.g., of rotation 202) may be a precisely controlled degree of rotation 202 of the jetting device 100 based on the set of instructions 104 at desired depth. The memory 205 may be a physical device used to store programs (e.g., set of instructions 104) or data (e.g. program state information) on a temporary or permanent basis for use in a computer or other digital electronic device (e.g., central processing system 106). The target depth 206 may be the selected depth below the ground where the jetting device 100 is programmed to perform drilling based on the set of instructions 104 received from the central processing system 106. The database 207 may be a structured set of data held in a computer that is accessible in various ways through the wireless network 201. The wellbore 208 may be a hole that is drilled to aid in the exploration and recovery of natural resources including oil, gas or water. The user 209 may be the person operating or managing the above ground computing system 214, according to one embodiment.
The programming 210 may be the action or process of scheduling the rotation 202 of the jetting device 100 based on the set of instructions 104 received from the central processing system 106 at the target depth 206. The command 212 may be a directive to a computer program for the jetting device 100 to perform the specific task of drilling at the target depth 206. The above ground computing system 214 may be a system of one or more computers and associated software with common storage above the ground necessary for the execution of the program of drilling at the target depth 206. The pre-programmed script 216 may be previously written text provided to the jetting device 100 with coded instructions for the automatic performance of precisely controlled rotation inside a wellbore 208 for drilling operation. The pressure pulse technology 218 may be a proven injection technology that allows improving the flow of fluids in hydraulically connected porous media inside a wellbore 208. The pressure signal 220 may be an electrical impulse or radio wave transmitting the amount of continuous physical force to be exerted by the jetting device 100 causing it to rotate inside the wellbore 208. The ground ocean surface 222 may be the location where the jetting device 100 is to be installed for oil/gas exploration. The rig 224 may be a structure with equipment for drilling an oil well for its exploration, according to one embodiment.
FIG. 2 illustrates the transducer assembly 108 inside the jetting device 100 that may be communicatively coupled with the above ground computing system 214 through the wireless network 201 while the jetting device is inside the wellbore 208. The user 209 of the above ground computing system 214 may be communicatively coupled to the transducer assembly 108 through the wireless network 201, according to one embodiment.
FIG. 3 is an environment view 350 of the jetting device of FIG. 2 inside the wellbore 208 automatically aligning to a pre-made casing exit 302 at a target depth 206 and cutting a lateral tunnel(s) 312 perpendicular to the wellbore 208 using a nozzle 310, according to one embodiment.
Particularly, FIG. 3 builds on FIG. 1 and FIG. 2, and further adds a pre-made casing exit 302, a formation 304, a pumping liquid 306, a jetting hose 308, a nozzle 310, a lateral tunnel(s) 312, a temperature data 314, a pressure data 316, and a storage device 318, according to one embodiment.
The pre-made casing exit 302 may be a prefabricated opening in the wellbore 208 for the jetting device 100 to automatically align for drilling. The formation 304 is the formal structure or arrangement of ground strata surrounding the wellbore 208. The pumping liquid 306 may be the high-velocity fluid stream forced under pressure through the pre-made casing exit 302 to make an underground passageway surrounding the wellbore 208. The jetting hose 308 may be a flexible tube used for spouting a high-velocity fluid stream forced under pressure out of a small-diameter opening to make an underground passageway surrounding the wellbore 208. The nozzle 310 may be a cylindrical or round spout at the end of a flexible tube used to control a jet of high-velocity fluid stream to make an underground passageway surrounding the wellbore 208. The lateral tunnel(s) 312 may be an underground or underwater passageway, dug perpendicularly to the surface of the wellbore through the surrounding soil. The temperature data 314 may be an autonomous recording of temperature in the wellbore 208 while cutting of lateral tunnel(s) 312 over a defined period of time as captured by the transducer assembly 108. The pressure data 316 may be an autonomous recording of pressure in the wellbore 208 while cutting of lateral tunnel(s) 312 over a defined period of time as captured by the transducer assembly 108. The storage device 318 may be a piece of computer equipment of the central processing system 106 on which information can be stored and wirelessly communicated to the above ground computing system 214, according to one embodiment.
FIG. 3 illustrates the jetting hose 308 inside the lateral tunnel(s) 312 may be communicatively coupled with the above ground computing system 214 through the wireless network 201. The transducer assembly 108 may transmit the temperature data 314 and pressure data 316 through the wireless network 201 communicatively coupled to the above ground computing system 214, according to one embodiment.
FIG. 4 is a user interface view 450 of the user 209 of the jetting device 100 of FIG. 1, monitoring the various parameters of the transducer assembly while cutting of lateral tunnel(s) 312 perpendicular to the surface of the wellbore 208, according to one embodiment.
Particularly, FIG. 4 illustrates a pumping liquid pressure 402, a depth at minimum applied pressure 404, a depth at maximum applied pressure 406, a start position 408A, a bleed off position 408B, a rotational time 410, and a temperature 412, according to one embodiment.
The pumping liquid pressure 402 may be the fluid pressure applied at a minimum rate (e.g., approximately 100 ft above the jetting device 100) to commence running in hole with coiled tubing. The depth at minimum applied pressure 404 may be the distance at which the user 209 commences running in hole. This may show the start position 408A of the jetting device. The depth at maximum applied pressure 406 may be the distance at which the maximum pumping liquid pressure 402 is applied when the user 209 continues to run in hole until the jetting device 100 is reached and the tool string weight is lost. This may enable the coiled tubing to run in hole (e.g., for approximately 10 to 15 feet) showing the depth at maximum applied pressure 406. The bleed off position 408B may be the position of the jetting device 100 when the pumping liquid pressure 402 is bled off to zero enabling the jetting hose 308 to travel around the exit of the jetting device 100. The rotational time 410 may be the pre-determined time elapsed to rotate the jetting device 100 by 90 degree to the next pre-made casing exit 302. The temperature 412 may be the temperature in the wellbore 208 while cutting of lateral tunnel(s) 312 over a defined period of time as captured by the transducer assembly 108, according to one embodiment.
FIG. 5 is a process flow 550 of the computer server of FIG. 1 to program a rotation 202 of a jetting device 100 using a central processing system 106 coupled with the jetting device 100 through a command 212 from the above ground computing system 214 communicated to the jetting device 100 while the jetting device 100 is still inserted in a wellbore 208, according to one embodiment.
In operation 502, the rotation 202 of the jetting device 100 may be programmed using a central processing system 106 coupled with the jetting device 100 through the command 212 from the above ground computing system 214 communicated to the jetting device 100 while the jetting device 100 is still inserted in the wellbore 208. In operation 504, the pre-programmed script 216 may be automatically executed while the jetting device 100 is inside the wellbore 208. In operation 506, the motor gearbox 102 inside the jetting device 100 may cause to induce the rotation 202 of the jetting device 100 while the jetting device 100 is downhole in the wellbore 208 based on the programming 210 of the rotation 202 of the jetting device 100 using the processor 203 and the memory 205 of the central processing system 106 coupled with the jetting device 100 through the command 212 from the above ground computing system 214 communicated to the jetting device 100 while the jetting device 100 is still inserted in the wellbore 208. In operation 508, the programming 210 may control precisely to a nearest one degree (of rotation 202) while the jetting device 100 is still at the target depth 206 in the wellbore 208, according to one embodiment.
FIG. 6 is a schematic diagram 680 of the representative computing devices 600 (e.g., above ground computing system 214) and a mobile device 630 that can be used to perform and/or implement any of the embodiments disclosed herein. In one or more embodiments, above ground computing system 214 of FIG. 2 may be the representative computing devices 600.
The representative computing devices 600 (e.g., above ground computing system 214) may represent various forms of digital computers, such as laptops, desktops, workstations, personal digital assistants, servers, blade servers, mainframes, and/or other appropriate computers. The mobile device 630 may represent various forms of mobile devices, such as smartphones, camera phones, personal digital assistants, cellular telephones, and other similar mobile devices. The components shown here, their connections, couples, and relationships, and their functions, are meant to be exemplary only, and are not meant to limit the embodiments described and/or claimed.
The representative computing devices 600 (e.g., above ground computing system 214) may include a processor 602, a memory 604, a storage device 606, a high speed interface 608 coupled to the memory 604 and a plurality of high speed expansion ports 610, and a low speed interface 612 coupled to a low speed bus 614 and a storage device 606. In one embodiment, each of the components heretofore may be inter-coupled using various buses, and may be mounted on a common motherboard and/or in other manners as appropriate.
The processor 602 may process instructions for execution in the representative computing devices 600 (e.g., above ground computing system 214), including instructions stored in the memory 604 and/or on the storage device 606 to display a graphical information for a GUI on an external input/output device, such as a display unit 616 coupled to the high speed interface 608. In other embodiments, multiple processor(s) 602 and/or multiple buses may be used, as appropriate, along with multiple memories and/or types of memory 604. Also, a plurality of representative computing devices 600 (e.g., above ground computing system 214) may be coupled with, with each device providing portions of the necessary operations (e.g., as a server bank, a group of blade servers, and/or a multi-processor system).
The memory 604 may be coupled to the representative computing devices 600 (e.g., above ground computing system 214). In one embodiment, the memory 604 may be a volatile memory. In another embodiment, the memory 604 may be a non-volatile memory. The memory 604 may also be another form of computer-readable medium, such as a magnetic and/or an optical disk. The storage device 606 may be capable of providing mass storage for the representative computing devices 600 (e.g., above ground computing system 214). In one embodiment, the storage device 606 may be included of a floppy disk device, a hard disk device, an optical disk device, a tape device, a flash memory and/or other similar solid state memory device. In another embodiment, the storage device 606 may be an array of the devices in a computer-readable medium previously mentioned heretofore, computer-readable medium, such as, and/or an array of devices, including devices in a storage area network and/or other configurations.
A computer program may be included of instructions that, when executed, perform one or more methods, such as those described above. The instructions may be stored in the memory 604, the storage device 606, a memory 604 coupled to the processor 602, and/or a propagated signal.
The high speed interface 608 may manage bandwidth-intensive operations for the representative computing devices 600 (e.g., above ground computing system 214), while the low speed interface 612 may manage lower bandwidth-intensive operations. Such allocation of functions is exemplary only. In one embodiment, the high speed interface 608 may be coupled to the memory 604, the display unit 616 (e.g., through a graphics processor and/or an accelerator), and to the plurality of high speed expansion ports 610, which may accept various expansion cards.
In the embodiment, the low speed interface 612 may be coupled to the storage device 606 and the low speed bus 614. The low speed bus 614 may be included of a wired and/or wireless communication port (e.g., a Universal Serial Bus (“USB”), a Bluetooth® port, an Ethernet port, and/or a wireless Ethernet port). The low speed bus 614 may also be coupled to scan unit 628, a printer 626, a keyboard, a mouse 624, and a networking device (e.g., a switch and/or a router) through a network adapter.
The representative computing devices 600 (e.g., above ground computing system 214) may be implemented in a number of different forms, as shown in the figure. In one embodiment, the representative computing devices 600 (e.g., above ground computing system 214) may be implemented as a standard server 618 and/or a group of such servers. In another embodiment, the representative computing devices 600 (e.g., above ground computing system 214) may be implemented as part of a rack server system 622. In yet another embodiment, the representative computing devices 600 (e.g., above ground computing system 214) may be implemented as a general computer 620 such as a laptop and/or desktop computer. Alternatively, a component from the representative computing devices 600 (e.g., above ground computing system 214) may be combined with another component in a mobile device 630.
In one or more embodiments, an entire system may be made up of a plurality of representative computing devices 600 (e.g., above ground computing system 214) and/or a plurality of representative computing devices 600 (e.g., above ground computing system 214) coupled to a plurality of mobile device 630. In one embodiment, the mobile device 630 may include a mobile compatible processor 632, a mobile compatible memory 634, and an input/output device such as a mobile display 646, a communication interface 652, and a transceiver 638, among other components. The mobile device 630 may also be provided with a storage device, such as a Microdrive and/or other device, to provide additional storage. In one embodiment, the components indicated heretofore are inter-coupled using various buses, and several of the components may be mounted on a common motherboard.
The mobile compatible processor 632 may execute instructions in the mobile device 630, including instructions stored in the mobile compatible memory 634. The mobile compatible processor 632 may be implemented as a chipset of chips that include separate and multiple analog and digital processors. The mobile compatible processor 632 may provide, for example, for coordination of the other components of the mobile device 630, such as control of user interfaces, applications run by the mobile device 630, and wireless communication by the mobile device 630.
The mobile compatible processor 632 may communicate with a user 209 through the control interface 636 and the display interface 644 coupled to a mobile display 646. In one embodiment, the mobile display 646 may be a Thin-Film-Transistor Liquid Crystal Display (“TFT LCD”), an Organic Light Emitting Diode (“OLED”) display, and another appropriate display technology. The display interface 644 may include appropriate circuitry for driving the mobile display 646 to present graphical and other information to a user 209. The control interface 636 may receive commands from a user 209 and convert them for submission to the mobile compatible processor 632. In addition, an external interface 642 may be provided in communication with the mobile compatible processor 632, so as to enable near area communication of the mobile device 630 with other devices. External interface 642 may provide, for example, for wired communication in some embodiments, and/or for wireless communication in other embodiments, and multiple interfaces may also be used.
The mobile compatible memory 634 may be coupled to the mobile device 630. The mobile compatible memory 634 may be implemented as a volatile memory and a non-volatile memory. The expansion memory 658 may also be coupled to the mobile device 630 through the expansion interface 656, which may include, for example, a Single In Line Memory Module (“SIMM”) card interface. The expansion memory 658 may provide extra storage space for the mobile device 630, and/or may also store an application and/or other information for the mobile device 630. Specifically, the expansion memory 658 may include instructions to carry out the processes described above. The expansion memory 658 may also include secure information. For example, the expansion memory 658 may be provided as a security module for the mobile device 630, and may be programmed with instructions that permit secure use of the mobile device 630. In addition, a secure application may be provided on the SIMM card, along with additional information, such as placing identifying information on the SIMM card in a non-hackable manner.
The mobile compatible memory 634 may include a volatile memory (e.g., a flash memory) and a non-volatile memory (e.g., a non-volatile random-access memory (“NVRAM”)). In one embodiment, a computer program includes a set of instructions that, when executed, perform one or more methods. The set of instructions may be stored on the mobile compatible memory 634, the expansion memory 658, a memory coupled to the mobile compatible processor 632, and a propagated signal that may be received, for example, over the transceiver 638 and/or the external interface 642.
The mobile device 630 may communicate wirelessly through the communication interface 652, which may be included of a digital signal processing circuitry. The communication interface 652 may provide for communications using various modes and/or protocols, such as: a Global System for Mobile Communications (“GSM”) protocol, a Short Message Service (“SMS”) protocol, an Enhanced Messaging System (“EMS”) protocol, a Multimedia Messaging Service (“MMS”) protocol, a Code Division Multiple Access (“CDMA”) protocol, Time Division Multiple Access (“TDMA”) protocol, a Personal Digital Cellular (“PDC”) protocol, a Wideband Code Division Multiple Access (“WCDMA”) protocol, a CDMA2000 protocol, and a General Packet Radio Service (“GPRS”) protocol. Such communication may occur, for example, through the transceiver 638 (e.g., radio-frequency transceiver). In addition, short-range communication may occur, such as using a Bluetooth®, Wi-Fi, and/or other such transceiver. In addition, a GPS (“Global Positioning System”) receiver module may provide additional navigation-related and location-related wireless data to the mobile device 630, which may be used as appropriate by a software application running on the mobile device 630.
The mobile device 630 may also communicate audibly using an audio codec 640, which may receive spoken information from a user 209 and convert it to usable digital information. The audio codec 640 may likewise generate audible sound for a user 209, such as through a speaker (e.g., in a handset of the mobile device 630). Such a sound may include a sound from a voice telephone call, a recorded sound (e.g., a voice message, a music files, etc.) and may also include a sound generated by an application operating on the mobile device 630.
The mobile device 630 may be implemented in a number of different forms, as shown in the figure. In one embodiment, the mobile device 630 may be implemented as a smartphone 648. In another embodiment, the mobile device 630 may be implemented as a personal digital assistant (“PDA”). In yet another embodiment, the mobile device, 630 may be implemented as a tablet device.
An example embodiment will now be described. The ACME Oil Company in Galveston, Tex. may have been engaged in oil exploration and/or production activities in remote areas of the United States. For some time, the company may have been facing dipping stock prices caused by significantly lowered production, high working cost, and/or inefficient oil production.
The reasons identified for low production may be attributed to depleting resources extractable (e.g., oil, gas) in the oil well and/or structural issues in the well bore. Therefore, ACME Oil Company may not have been able to profitably operate using existing technology that the company was employing. Other challenges may have included pressure depletion, formation damage, low permeability, low porosity, and/or formation access resulting into a gradual drop in fluid mobility through the reservoir. In addition, formation damage (e.g., damage to the surrounding Earth around the wellbore) may have had short to medium radius effect around the wellbore. This formation damage may have caused lower than expected production rates and/or in some cases total restriction of flow. Moreover, low permeability may have extended out all the way throughout the reservoir and/or created an issue for fluid mobility and production into the wellbore (e.g., regardless of the nature of the well design and/or perforation design).
In addition, low porosity at the Galveston site may have created a number of issues for production flow through the reservoir and into the wellbore. Further, perforations may have created hazardous conditions and in depleted wells. In addition, perforations may have been made with low quality tools that provided very short radius access to the formation, while creating small restrictive casing exits through which to accept production flow. This may have impeded productivity of the oil well.
To counter the downward trend, the ACME Oil Company may have decided to invest in inventions described herein (e.g., use of various embodiments of the FIGS. 1-6) for enhancing their oil and gas recovery.
The use of various embodiments of the FIGS. 1-6, reduced the amount of operational time required on location while also provided ACME Oil Company with valuable well-bore data, taken prior to, during and after each jetting and stimulation process.
Depending on the target formations, the ACME Oil Company may have designed specific fluid programs, using the technologies described in various embodiments of the FIGS. 1-6, in conjunction with the underbalanced jetting tools which may have enabled to jet the lateral tunnels more easily than expected (e.g., reducing the overburden of hydrostatic fluids and cuttings exerted on the formation and vastly improving the lateral clean out process). The various embodiments of technologies of FIGS. 1-6 may have also enabled the ACME Oil Company to gain deeper and wider access from the well bore, increased fluid mobility through the reservoir to the wellbore, augmented pressure, higher permeability and/or increased porosity in the formation resulting in higher productivity.
The various embodiments of the FIGS. 1-6 may have also provided the ACME Oil Company the ability to create layered, multi-lateral channels off any existing wellbore at 90°, each one extending out past any damaged zones. These laterals may have been inserted using an underbalanced jetting process, to intersect fractures and/or trapped reserves while also preventing further formation impairment around the wellbore using the various embodiments of FIGS. 1-6.
With the use of various embodiments of the FIGS. 1-6, the ACME Oil Company may have enhanced their oil and gas recovery, and thereby cutting their production cost (e.g., enabling ACME to run their operations more efficiently and effectively, and cause its publicly traded stock to spike).
In another example embodiment, the ACME Resources Corporation may have been struggling to meet the increased growing domestic demand for energy despite utilizing best available technology in the market. The technology they may have been using had multiple loopholes, namely, restricted and slow access to formations and/or inability to unlock additional hydrocarbons from their reservoirs, etc.
To meet their increased growing demand, the innovative technology, as described in various embodiments of the FIGS. 1-6, came to their rescue. With this technology ACME Resources Corporation may have now been able to enhance the recovery of hydrocarbons more effectively. The ACME Resources Corporation may have able to create multi-lateral channels off an existing wellbore for the purpose of surface injection, with the laterals being placed specifically in the direction of a producing well using the technologies of the various embodiments as described in conjunction with FIGS. 1-6. The directional channeling of the laterals using the various technologies described herein may have improved the efficiency of their reservoirs. With the innovative technology as described in FIGS. 1-6, the ACME Resources Corporation may now easily meet the increased growing domestic demand for energy without investing heavily for drilling new wellbores.
With reference to the figures a down hole tool system enabling the reservoir formation to be laterally jetted up to 100 meters. If required by the client the tool system would allow this to be done.
Downhole wellbore rotating tools may be used to position other devices and/or tools that may be configured together on a drilling or tubing string (e.g., using the various embodiments of FIGS. 1-6), in the course of drilling and/or extraction of oil and/or gas and/or specifically the rotation and/or alignment of multi-lateral jetting tools. Some of the oilfield tool providers may use the various embodiments of FIGS. 1-6 to position their downhole tools and some may be controlled or activated from the surface (e.g., using the various embodiments of FIGS. 1-6). As problems may be encountered and/or rotation not verified, the drilling or tubing string may not need to be withdrawn and/or inspected or repositioned (e.g., using the various embodiments of FIGS. 1-6). The various embodiments may provide current indexing alternatives to provide a precise rotation to nearest one degree or programmable rotational devices that can be set or adjusted whenever required, without the indexing tool requiring to be withdrawn and/or removed from the wellbore upon each successive rotation to check for accuracy (e.g., using the various embodiments of FIGS. 1-6).
There are other types of hydraulic and electrical motors that may serve as rotational devices downhole, and the suspension string itself may be capable of rotating the downhole string and tools, however a drilling or tubing string alone may be capable of a precise controlled rotation and will not require hydraulic or electrical motors to provide a drive an additional mechanism downhole to position the tools (e.g., using the various embodiments of FIGS. 1-6). At high pressure, under fluid and at depth within the wellbore additional elements of uncertainty may be common, which may not affect such tools that utilize motors and their ability to rotate at the desired rates and distances (e.g., using the various embodiments of FIGS. 1-6). High pressure environments downhole pushing inward on the rotating components of the tool, may create frictional forces that add unique effects on the devices, which can be overcome (e.g., using the various embodiments of FIGS. 1-6) without affecting the actual expected results and indexing positions of the rotating tools. This need for a sealed, precision actuation device that can be programmed to position downhole tools in exactly the right direction once at a desired depth in the wellbore, and to be automatically rotated to additional precise positions at any time required while remaining within the wellbore can be achieved using the various embodiments of FIGS. 1-6.
The various embodiments of FIGS. 1-6 may also allow for a single tool system to rotate and align the multi-lateral jetting tool precisely aligned to the pre made casing exit (e.g., using the various embodiments of FIGS. 1-6). Previously there would be a need for several runs into the wellbore using multi tool types. The various embodiments of FIGS. 1-6 may allow the multi-lateral jetting tool to be aligned with the casing exit prior to the downhole jetting being run in the hole through the production string.
Even when the drilling or tubing string is rotated on surface there may be assurances that the desired rotation is achieved at the selected depth downhole (e.g., using the various embodiments of FIGS. 1-6). Adding length to the string may significantly increase weight and certainty of rotational accuracy, as does the angle of the wellbore with current methods proving to be a very effective in deviated or horizontal wells due to friction and drag, which can be overcome using the various embodiments of FIGS. 1-6.
The various embodiments of FIGS. 1-6 may allow for pre-set rotational instructions to be pre-set at surface before the tool running string in deployed. One added function may be the pre-set rotational instructions can be overridden by utilizing pressure pulse technology and method. This method may allow for a pressure signal to transmit to the downhole tool causing the tool system to rotate (e.g., using the various embodiments of FIGS. 1-6).
The autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) may be programmed at surface for its rotational timings, also programmed for its pulse backup operations. The autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) string may be made up at surface, the entire id's od's and lengths may be recorded (e.g., using the various embodiments of FIGS. 1-6). The tool assembly may consist of, standalone multi set tubing anchor, down-hole data measurement and under balanced rotational device (e.g., jetting device 100), and X-over to production tubing or drill pipe. The tool string as listed above may then run in hole by the service rig to re-latch onto the tubing anchor that is still set at the reservoir depth. Once the tool string has latched on to the anchor, the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) may immediately be aligned with one of the casing exits cut previously by the autonomous multi angle hydraulic casing exit tool because of the design of the anchor on off tool. The lateral jetting coiled tubing unit well head equipment may be rigged up to the production tubing drill pipe (e.g., using the various embodiments of FIGS. 1-6).
The supervisor (e.g. user 209 of the various embodiments of FIGS. 1-6) may commence running in hole with coiled tubing pumping liquid at a minimum rate to approximately 100 ft above the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100). The fluid rate may then be increased to maximum and the supervisor (e.g. user 209 of the various embodiments of FIGS. 1-6) may continue to run in hole until the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) is reached and tool string weight is lost, approximately 10 to 15 extra feet of coiled tubing is run in hole. At this point, the fluid pressure may bleed off to zero enabling the jetting hose 308 to travel around the exit of the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100). Once this is achieved, the full weight of the tool string may return. At this point, the fluid rate may again be brought back to the maximum enabling the jetting hose 308 and nozzle 310 to cut up to a 100 meter lateral tunnel. The lateral jetting hose 308 may then be retrieved into the tubing to allow for the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) to be orientated to the next casing exit. This may be achieved by the internal CPU energizing the motor at a pre-determined time to rotate 90° to the next casing exit 90°. Operation may then be repeated an additional 3 times. The lateral jetting hose and coiled tubing may then be retrieved from the production tubing or drill pipe. The autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) string may then be retrieved from the well by mean of unlatching the anchor on off tool from the anchor by setting the string in balance position and turning to the left ¼ of a turn and pulling out of hole. An anchor on-off tool may then run into the well to retrieve the tubing anchor from the well (e.g., using the various embodiments of FIGS. 1-6).
There may be a need to provide an improved downhole indexing device and methods allowing for adjustable parameters to be set prior to running downhole, after which the device may be fully automated, with no further control from surface actions.
As shown in the various embodiments of FIGS. 1-6, an underbalanced formation exit tool system may include standalone multi set tubing anchor, autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100), and X-over to drill pipe or production tubing.
As shown in the various embodiments of FIGS. 1-6, the autonomous down-hole data measurement and under balanced rotational device (e.g. jetting device 100 as shown in the various embodiments of FIGS. 1-6) assembly may consist of a slip and pin female connector used to connect assembly to the standalone multi set tubing anchor, N2 ports used if the client requires the lateral jetting sequence to be completed in under balanced mode, the jetting exit ports that allow the jetting hose 308 to exit the tool at 90° to the vertical wellbore, a male slip and pin connector used to connect the assembly to the production tubing or drill pipe (not Shown), the final assembly, and the top sub which connects the various embodiments of FIGS. 1-6.
As shown in the various embodiments of FIGS. 1-6, the programmable CPU may be the surface computer programmable assembly that dictates the rotational timings of the jetting exit ports. At surface before the tool is assembled a battery may be inserted into the CPU. The CPU may be connected to a computer and programmed with a sequence of instructions and timings that may be performed once the tool has reached its desired depth and the predetermined time delay as expired. The motor gearbox assembly once connected to the CPU and battery and inserted into the motor gearbox housing and secured. It is then connected to the transducer sub assembly. The transducer assembly may read bottom hole temperature and pressure and via internal wiring stores the information on the CPU. The transducer assembly may also allow the tool to be reprogrammed from surface via pressure pulses on the annulus in the event of a failure or the need to change rotational timings.
As shown in FIG. 1, the complete assembly may be connected the top sub. This may be used to connect the electronics and gearbox assembly to the jetting exit ports.
In an operation to laterally jet the reservoir, the system, as shown in the various embodiments of FIGS. 1-6, may be attached to the production tubing or drill pipe string (not shown) using the crossover. The autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) may be attached to the crossover, the stand alone multi set tubing anchor may be attached to the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100).
The system is then pushed into the well to re-latch onto the tubing anchor that may still set at the reservoir depth. Once the tool string has latched on to the anchor, the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) may immediately be aligned with one of the casing exits cut previously by the autonomous multi angle hydraulic casing exit tool because of the design of the anchor on off tool. The lateral jetting coiled tubing unit well head equipment may be rigged up to the production tubing or drill pipe. The supervisor (e.g. user 209 of the various embodiments of FIGS. 1-6) may commence running in hole with coiled tubing pumping liquid at a minimum rate to approximately 100 ft above the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100).
The supervisor (e.g. user 209 of the various embodiments of FIGS. 1-6) may then calculate the position of the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) depending on timing he may decide to wait until the next rotation of the tool before commencing the lateral jetting run. Once calculated, the fluid rate may then be increased to maximum and the supervisor may continue to run in hole until the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) is reached and tool string weight is lost, approximately 10 to 15 extra feet of coiled tubing is run in hole. At this point, the fluid pressure may bleed off to zero enabling the jetting hose to travel around the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100). Once this is achieved the full weight of the tool string may return. At this point, the fluid rate may again be brought back to the maximum enabling the jetting hose and nozzle to cut up to a 100 meter lateral tunnel. At this point, if the supervisor requires, the jetting phase may be completed underbalanced by circulating nitrogen into the annulus between the coiled tubing and the production tubing or drill pipe and out through the underbalanced nitrogen ports.
The lateral jetting hose may then be retrieved into the tubing to allow for the autonomous down-hole data measurement and under balanced rotational device (e.g., jetting device 100) via the surface preprogrammed timings to move to the next exit point. This operation may be carried out 3 more time until 4 up to 100 meter lateral tunnels have been cut. The lateral jetting hose and coiled tubing may then be retrieved from the production tubing. The lateral jetting tool string (e.g., using the various embodiments of FIGS. 1-6) may then be retrieved from the well by means of unlatching the anchor on off tool from the anchor by setting the string in balance position and turning to the left ¼ of a turn. An anchor on off tool may then run into the well to retrieve the tubing anchor.
Although the present embodiments have been described with reference to specific example embodiments, it will be evident that various modifications and changes may be made to these embodiments without departing from the broader spirit and scope of the various embodiments. For example, the various devices and modules described herein may be enabled and operated using hardware circuitry (e.g., CMOS based logic circuitry), firmware, software or any combination of hardware, firmware, and software (e.g., embodied in a non-transitory machine-readable medium). For example, the various electrical structure and methods may be embodied using transistors, logic gates, and electrical circuits (e.g., application specific integrated (ASIC) circuitry and/or Digital Signal Processor (DSP) circuitry).
In addition, it will be appreciated that the various operations, processes and methods disclosed herein may be embodied in a non-transitory machine-readable medium and/or a machine-accessible medium compatible with a data processing system (e.g., data processing device). Accordingly, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense.
A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the claimed invention. In addition, the logic flows depicted in the figures do not require the particular order shown, or sequential order, to achieve desirable results. In addition, other steps may be provided, or steps may be eliminated, from the described flows, and other components may be added to, or removed from, the described systems. Accordingly, other embodiments are within the scope of the following claims.
It may be appreciated that the various systems, methods, and apparatus disclosed herein may be embodied in a machine-readable medium and/or a machine accessible medium compatible with a data processing system (e.g., a computer system), and/or may be performed in any order.
The structures and modules in the figures may be shown as distinct and communicating with only a few specific structures and not others. The structures may be merged with each other, may perform overlapping functions, and may communicate with other structures not shown to be connected in the figures. Accordingly, the specification and/or drawings may be regarded in an illustrative rather than a restrictive sense.

Claims

What is claimed is:

1. A jetting device, comprising:

a motor gearbox inside the jetting device to cause the jetting device to rotate based on a set of instructions;

a central processing system coupled to the motor gearbox;

a transducer assembly coupled with the motor gearbox and the central processing system; and

a top assembly to electromechanically couple with the motor gearbox, the transducer assembly, and the central processing system and to cause the jetting device to rotate based on the set of instructions received from the central processing system.

2. The jetting device of claim 1:

wherein a rotation of the jetting device is controlled precisely to a nearest one degree while the jetting device is still at a target depth in a wellbore based on a programming of the central processing system through at least one a command from an above ground computing system communicated to the jetting device while still inserted in the wellbore and a pre-programmed script automatically executed while the jetting device is inside the wellbore.

3. The jetting device of claim 2:

wherein the pre-programmed script is automatically overridden utilizing a pressure pulse technology in which a pressure signal is transmitted to the jetting device while it is downhole in the wellbore at the target depth to cause the jetting device to rotate.

4. The jetting device of claim 2:

wherein the jetting device to automatically align to a pre-made casing exit in the wellbore at the target depth to reach a formation encompassing the wellbore.

5. The jetting device of claim 4:

wherein a pumping liquid is passed using a jetting hose having a nozzle through the pre-made casing exit to cause the jetting hose to cut up to a 100 meter lateral tunnel perpendicular to the wellbore using the nozzle.

6. The jetting device of claim 5:

wherein the jetting device to automatically rotate to the next casing exit while at the target depth and to cut up to eight lateral tunnels at the target depth through additional pre-made casing exits at the target depth.

7. The jetting device of claim 2:

wherein the rotation of the jetting device is programmed wirelessly from the above ground computing system through a wireless network between the jetting device and the above ground computing system,

wherein at least one of a temperature data and a pressure data is captured using the transducer assembly at the target depth, and

wherein the temperature data and the pressure data is at least one stored locally on a storage device of the central processing unit and wirelessly communicated to the above ground computing system.

8. A method, comprising:

programming a rotation of a jetting device using a central processing system coupled with the jetting device through at least one a command from an above ground computing system communicated to the jetting device while the jetting device is still inserted in a wellbore and a pre-programmed script automatically executed while the jetting device is inside the wellbore;

causing a motor gearbox inside the jetting device to induce the rotation of the jetting device while the jetting device is downhole in the wellbore based on the programming of the rotation of the jetting device using a processor and a memory of the central processing system coupled with the jetting device through at least one of the command from the above ground computing system communicated to the jetting device while the jetting device is still inserted in the wellbore and the preprogrammed script automatically executed while the jetting device is inside the wellbore, and

wherein the programming is controlling precisely to a nearest one degree while the jetting device is still at a target depth in the wellbore.

9. The method of claim 8 further comprising:

automatically overriding the preprogrammed script utilizing a pressure pulse technology in which a pressure signal is transmitted to the jetting device while it is downhole in the wellbore at the target depth to cause the jetting device to rotate.

10. The method of claim 8 further comprising:

automatically aligning the jetting device to a pre-made casing exit in the wellbore at the target depth to reach a formation encompassing the wellbore.

11. The method of claim 10 further comprising:

channeling a pumping liquid using a jetting hose having a nozzle through the pre-made casing exit to cause the jetting hose to cut up to a 100 meter lateral tunnel perpendicular to the wellbore using the nozzle.

12. The method of claim 11:

automatically rotating the jetting device to the next casing exit while at the target depth and to cut up any number of lateral tunnels at the target depth through additional pre-made casing exits at the target depth.

13. The method of claim 8 further comprising:

capturing at least one of a temperature data and a pressure data using a transducer assembly at the target depth;

programming wirelessly the rotation of the jetting device from the above ground computing system through a wireless network between the jetting device and the above ground computing system; and

communicating the temperature data and the pressure data to at least one of the central processing unit and the above ground computing system through at least one of the central computing system after the jetting device is removed from the wellbore, and in real time through the wireless network communicating directly to the above ground computing system.

14. A jetting device, comprising:

a motor gearbox inside the jetting device to cause the jetting device to rotate based on a set of instructions while inside a wellbore at a target depth;

a central processing system coupled to the motor gearbox;

a transducer assembly coupled with the motor gearbox and the central processing system to capture at least one of a temperature data and a pressure data at the target depth inside the wellbore; and

15. The jetting device of claim 14,

wherein a rotation of the jetting device is controlled precisely to a nearest one degree while the jetting device is still at the target depth in the wellbore based on a programming of the central processing system through at least one a command from an above ground computing system communicated to the jetting device while still inserted in the wellbore and a pre-programmed script automatically executed while the jetting device is inside the wellbore.

16. The jetting device of claim 15:

17. The jetting device of claim 15:

18. The jetting device of claim 17:

19. The jetting device of claim 18:

20. The jetting device of claim 15:

wherein the rotation of the jetting device is programmed wirelessly from the above ground computing system through a wireless network between the jetting device and the above ground computing system, and