METHOD AND SYSTEM TO DRILL OUT WELL COMPLETION PLUGS

Abstract

A system for controlling load on a downhole tool for drilling out wellbore plugs is provided. The system includes a downhole drilling tool connected with a drill string extending within a cased wellbore. A drilling fluid flows into a casing space of the cased wellbore from the downhole drilling tool or a distal end outlet of the drill string. A fluid back pressure system comprising a variable flow restriction device applies flow restriction in the casing space to restrict fluid flow therein. At least one sensor measures a drilling fluid pressure within the drill string and at least one second sensor measures the casing fluid pressure. A processor is adapted to monitor the drilling fluid pressure and the casing space fluid pressure during a drilling operation to adjust a mechanical load on the downhole drilling tool to drill out wellbore plugs based on a difference pressure value between the drilling fluid pressure and the casing space fluid pressure.

Description

RELATED APPLICATIONS

This application is related to and claims priority from U.S. Provisional Application No. 62/067,934 entitled “Method and System to Drill Out Well Completion Plugs” filed on Oct. 23, 2014 and U.S. Provisional Application No. 62/068,543 entitled “Method and System to Drill Out Well Completion Plugs” filed on Oct. 24, 2014, which are expressly incorporated by reference herein.

FIELD

The present embodiments generally relate to a method and a system for drilling out well completion plugs.

BACKGROUND

Just prior to beginning production, oil and natural gas wells are completed using a complex process called “fracturing.” This process involves securing the steel casing pipe in place in the wellbore with cement. The steel and cement barrier is then perforated with shaped explosive charges and the surrounding oil or gas reservoir is stimulated or “fractured” in order to start the flow of gas and oil into the well casing and up to the wellhead. This fracturing process can be repeated several times in a given well depending on various environmental factors of the well, such as the depth of the well, length of the wellbore in the productive zone or permeability of the rock, reservoir pressure, and the like. Because of these factors, some wells may be fractured at only a few depth intervals along the wellbore and others may be fractured at as many as thirty (30) or more depths intervals (frac stages).

Typically, as the well is prepared for fracturing at each desired depth interval or zone of the well, a temporary well completion plug is set in the bore of the steel well casing pipe with a setting tool just below the level where the fracturing will perforate the steel and cement barrier. When the barrier is perforated, well fluids and sand are pumped down to the perforations and into the reservoir. Then, a temporary plug set above the fraced depth interval to isolate and seal it from next depth interval to be fraced.

This process is repeated several times, as the operation moves up the wellbore until all the desired depth intervals have been stimulated. At each interval, the temporary completion plugs are usually left in place, so that they can all be drilled out at the end of the process which is often time-consuming drilling operation with multiple pipe trips. Temporary plugs are typically made of cast iron and generally require several passes of the drilling fixture to completely drill out the plugs.

A need exists for a method and system which can cut through well completion plugs and obstructions in a cased wellbore in a least required number of trips into and out of the hole, without the needed for unplanned insertions into the cased wellbore.

A further need exists for a system and method that provides a downhole motor connected to a downhole cutting device during the cutting process.

A further need exists for a method and system which can cut through well completion plugs and obstructions in a cased wellbore in a single trip into and out of the hole, without the needed for repeated insertion into the cased wellbore.

The present embodiments meet these needs.

SUMMARY

An aspect of the present invention includes a system for controlling load on a downhole tool of a well drilling equipment of an oil or gas rig. The system comprises: a downhole drilling tool, including a drill bit, connected in operable communication with a drill string extending within a wellbore, the drill string being adapted to permit a drilling fluid to flow to the downhole drilling tool, wherein the drilling fluid flows into an annular space from the downhole drilling tool or a distal end outlet of the drill string, the annular space being formed between the drill string and the wellbore wall; a pump for pumping the drilling fluid from a drilling fluid tank through the drill string into the annular space; a fluid back pressure system comprising a variable flow restriction device for applying flow restriction in the annular space to restrict fluid flow therein; at least one first sensor disposed in operable communication with the drill string for measuring a drilling fluid pressure within the drill string; at least one second sensor disposed in operable communication with the annular space for measuring an annular space fluid pressure therein; and a processor adapted to monitor the drilling fluid pressure and the annular space fluid pressure during a drilling operation, to adjust a mechanical load on the downhole drilling tool based on a difference pressure value between the drilling fluid pressure and the annular space fluid pressure.

Another aspect of the present invention comprises a method of controlling load on a downhole tool of a well drilling equipment of an oil or gas rig. The method comprises: disposing a downhole drilling tool, including a drill bit, connected in operable communication with a drill string extending within a wellbore, the drill string being adapted to permit a drilling fluid to flow to the downhole drilling tool, wherein the drilling fluid flows into an annular space from the downhole drilling tool or a distal end outlet of the drill string, the annular space being formed between the drill string and the wellbore wall; pumping the drilling fluid from a drilling fluid tank through the drill string into the annular space; applying flow restriction in the annular space to restrict fluid flow therein using a fluid back pressure system comprising a variable flow restriction device; disposing at least one first sensor in operable communication with the drill string for measuring a drilling fluid pressure within the drill string; disposing at least one second sensor in operable communication with the annular space for measuring an annular space fluid pressure therein; monitoring the drilling fluid pressure and the annular space fluid pressure by a processor during a drilling operation; and advancing the drill string to add mechanical load on the downhole drilling tool based on a difference pressure value between the drilling fluid pressure and the annular space fluid pressure.

Yet another aspect of the present invention includes a system to drill through at least one wellbore plug in a cased wellbore. The system comprises: a downhole motor connected to a tubing string; a downhole cutting device hydraulically connected to the downhole motor; a wellbore fluid pump for pumping a wellbore fluid through the tubing string, the wellbore fluid pump connected to the downhole motor for rotating the downhole cutting device while weight is simultaneously applied on the downhole cutting device, thereby enabling the downhole cutting device to contact and cut through the at least one wellbore plug in the cased wellbore; a tubing pressure sensor connected to the tubing string for producing tubing pressure sensor data; at least one casing pressure sensor installed in communication with the cased wellbore producing a casing pressure sensor data; a processor connected to the tubing pressure sensor and the at least one casing pressure sensor; and a data storage connected to the processor, the data storage comprising: computer instructions to instruct the processor to receive and store the tubing pressure sensor data and the casing pressure sensor data; at least one differential pressure set point limit for the downhole motor; computer instructions to instruct the processor to compare the tubing pressure sensor data to the casing pressure sensor data to calculate a measured differential pressure for the downhole motor; computer instructions to instruct the processor to compare the measured differential pressure for the downhole motor to the at least one differential pressure set point limit of the downhole motor; and computer instructions to instruct the processor to selectively transmit a message when the measured differential pressure for the downhole motor is either: (i) less than the at least one differential pressure set point limit for the downhole motor, (ii) equal to the at least one differential pressure set point limit for the downhole motor, or (iii) greater the at least one differential pressure set point limit for the downhole motor, wherein the message is transmitted to an autodriller to advance the tubing string by operating a drawworks.

BRIEF DESCRIPTION OF THE DRAWINGS

The detailed description will be better understood in conjunction with the accompanying drawings as follows:

FIG. 1 is a schematic illustration of a rig connected to a cased wellbore with a plurality of wellbore plugs;

FIG. 2 is a schematic illustration of a system of the present invention including a rig secured to a cased wellbore with the downhole cutting device inserted in the cased wellbore;

FIG. 3 is a schematic diagram of a control and monitoring system of the present invention with various sensors connected to a processor via a network according to one or more embodiments;

FIGS. 4A-4B are schematic diagrams of the data storage usable with the control and monitoring system; and

FIG. 5 is a diagram of a method of the present invention according to one or more embodiments.

The present embodiments are detailed below with reference to the listed Figures.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Before explaining the present method and system in detail, it is to be understood that the method and system are not limited to the particular embodiments and that they can be practiced or carried out in various ways.

The present invention relates to a drilling system and method for drilling wellbores while monitoring and controlling a drill bit weight (load) while utilizing differential pressures between a drilling fluid and fluids existing within the wellbore. The present invention may provide an automated drilling system to drill wellbore plugs in cased wellbores prepared for gas or oil extraction. A downhole cutting device powered by a downhole motor, which may be operably connected to a drill string or tubing, may be used to cut a wellbore plug using data from a tubing pressure sensor and a casing pressure sensor. A system processor may compare the sensor data or pressure measurements to produce a measured differential pressure for the downhole motor, and compares the produced value to the differential pressure set point limits of the downhole motor. When the measured differential pressure for the downhole motor is either (i) less than the differential pressure set point limit for the downhole motor or (ii) equal to or greater than the differential pressure set point limit for the downhole motor, an autodriller is instructed to advance the tubing string by operating the drawworks, thereby increasing the load on the downhole cutting device, or stopping operation of the drawworks.

A benefit of the present invention is that it provides increased safety after fracing a well for hands on the rig as only a planned number of trips is needed into the well to drill out the frac plugs or other wellbore obstructions in the well. Another benefit of the invention is a reduced chance for toxic spills at the rig site because unplanned pipe trips out of the well are not needed, where toxic fluids can spill from the well each time.

Various terms are used herein. The term “data storage” as used herein refers to a non-transitory computer readable medium capable of storing sensor data, pressure and weight limits, and computer instructions. The data storage is adapted to store computer instructions on operation of the system as well including algorithms for determining differential pressure in the cased wellbore. The term “downhole motor” as used herein can be either a turbine or a positive displacement motor. The term “processor” as used herein can refer to a computer, a laptop, a cellular phone, a tablet, or another processing device capable of bidirectional communication having a data storage.

During a drilling operation, after a horizontal or deviated wellbore is drilled and cased in a shale formation or tight rock, it is fraced to allow better flow of hydrocarbon into the wellbore. Fracing of a well may require a mixture of water and sand to be pumped under pressure into the wellbore. To keep the surface pressure manageable, the well may be fraced in several stages. In most horizontal wells (deviated wells), it is not uncommon to have 30-40 frac stages. A fracing operation may start at the toe of the wellbore (distal end) and successfully moves toward the heel (curved section between a vertical and horizontal sections of the wellbore). After each frac stage, a wellbore plug may be placed to isolate the newly fraced wellbore section from the next stage to be fraced. Therefore, at the end of fracing operations, there may be left a plurality of wellbore plugs, such as 30-40 plugs, disposed in the wellbore. To open the well to gas or oil production, a drill bit may be lowered into the wellbore to drill out each wellbore plug.

For example: After a wellbore having 8.5 inch in diameter is drilled, a 5.5 inch diameter casing may be run and cemented. Then, perforation guns are delivered to near the toe of the wellbore and holes are shot into the casing. Later, a slurry of mostly water and sand is pumped to the well through the perforation's holes into the surrounding rock. After the rock is fraced, a wellbore plug is placed at the shallow end of the stage or section. In one example, plugs may be about 4.37 inch in diameter and expands to seal inside of a 5.5 inch in diameter casing. The above process is repeated from toe to heel until whole horizontal wellbore is fraced and he plugs are put in place.

Turning now to the Figures, FIG. 1 and FIG. 2 show an embodiment of a system 10 of the present invention that may be used for wellbore plug drilling operations as described below.

In one embodiment, the system 10 may include a rig 32 mounted on the earth surface 28 and connected to a wellbore 14. In this embodiment, the rig 32 may be drilling rig but it may also be a workover rig. In this exemplary embodiment, the wellbore 14 may be a cased wellbore including a casing 16 substantially covering an inner perimeter of the wellbore 14 and at least one wellbore plug 12 sealing the cased wellbore at a predetermined depth. As illustrated, a tubing string 26 or drill string extending between the drilling rig 32 and a downhole tool 13 which is disposed within the wellbore 14 with the casing 16. The tubing string 26 may be a jointed pipe string or a coiled tubing, which are well known in hydrocarbon drilling technologies. An annular space 48, or casing space, may be defined between the tubing string 26 and the casing 16, i.e., the wellbore wall. In embodiments, the annular space 48 of the wellbore 14 may be a few inches wide, such as 1-3 inches, space formed concentrically around the tubing string 26. In this exemplary embodiment, the wellbore 14 may include a plurality of wellbore plugs 12 such as the wellbore plugs 12a and 12b sealing the wellbore at different depths within the wellbore. The wellbore plugs 12a and 12b may be removed by a drilling operation using the system of the present invention. In embodiments, the wellbore having the casing 16 may be 500 feet to 5 miles long, vertical, deviated or both.

Referring back to FIGS. 1 and 2, the drilling rig 32 may include a derrick with hoists, sheaves, and a hook 90. The hook 90 suspends the tubing string 26 as it is installed into the wellbore. An autodriller device 60 on the rig 32 may be used to advance the tubing string 26 by operating a drawworks 81 or by stopping operation of the drawworks 81. During a drilling operation, a load is placed on the downhole drilling tool 13 when the tubing string 26 is advanced downwardly within the wellbore 14. The downhole tool 13 is connected to a distal end of the tubing string 26 within the wellbore 14. A proximal end of the tubing string may be connected to, for example, a top rotational drive 61 of the drilling rig 32 to apply torque to the tubing string 26 when needed during a wellbore operation, such advancing through vertical or deviated sections of the wellbore 16 as shown in FIG. 1. The top drive 61 may be held by the hook 90.

The downhole drilling tool 13 may include a downhole motor 15, which may be connected in operable communication with the tubing string 26 at the back, and a downhole cutting device 24 such as a drill bit connected to the front of the downhole motor 15. The drill bit 24 may be hydraulically driven by the downhole motor 15 using a wellbore fluid 37, or drilling fluid, delivered to the downhole motor through the tubing string 26. A wellbore fluid pump 36 on the surface 28 may be configured to pump the wellbore fluid 37, through the tubing string 26, to the downhole motor 15 to drive the drill bit 24. The pressure from the wellbore fluid 37 flowing into the downhole motor 15 rotates the drill bit 24 while weight or load is simultaneously applied on the drill bit 24, which enables the drill bit to contact and cut through the wellbore plug 12 within the wellbore 14. To drill out the plugs 12, the drill bit 24 may have a bit size of about 4.75 inches. The downhole motor 15 may be about 2.88 inches to about 3.5 inches in diameter. The typical size of the tubing string 26, such as a coiled tubing or a jointed pipe string, may be about 2 inches to about 2.38 inches in diameter. The wellbore fluids may be drilling mud or a saline solution.

The wellbore fluid 37 used by the downhole drilling tool 13 may be discharged into the annular space 48 and may flow through the annular space 48 towards the earth surface 28 carrying along the cuttings produced by the drilling operation. In this respect, the annular space 48 may contain the wellbore fluid 37 from the drilling operation and other fluids and/or operational fluids. The annular space 48 may be sealed at the wellhead by a valve 20, such as a BOP device (Blow-Out-Preventer). The valve 20 surrounds the drill string at the well head on the earth surface 20 and seals the annular space 48. A fluid backpressure system including an adjustable flow restriction device 99, also called as casing choke valve, may control and/or restrict the fluid flow out of the annular space 48. Depending on the drilling operation conditions, the state of casing choke valve 99 may be varied between fully open state to fully closed state, i.e., it may be partially open or fully closed or fully open.

Typically, while drilling with downhole motors, changes in pump pressure at the surface may be monitored as an indication or weight on the drilling bit. Monitoring and keeping a constant weight (load) on the drilling bit is critical to advance drilling at an optimal rate. The changes in pump pressure may indicate overloading of the downhole motor and the drilling bit or, on the other extreme, not having enough weight to drill effectively perform material removal during drilling. Monitoring wellbore fluid pump pressure to infer weight on bit may be adequate when the fluid flow from the annular space (casing return flow) is open to atmosphere, in which case the annular space surface pressure (casing surface pressure) may be a constant.

In the case of drilling out wellbore plugs in horizontal wells or the horizontal portion of the wells, often times high pressure formation fluids (liquids and gases) from the geological structures may be present within the well environment. As soon as the first wellbore plug is drilled out, influx of such fluids may also enter the wellbore. The influx of fluids along with the wellbore drilling fluids through the tubing string and the downhole motor as well as the drill bit may continue to flow into the annular space while drilling the rest of the wellbore plugs. To safely control the fluid return to the earth surface, a choke line tied to the annular space via the BOP at the surface is operated. Casing pressures, which may be measured adjacent the casing choke valve, may be manipulated to safely expel the fluid influx from the annular space. It is not uncommon to fluctuating annular space fluid pressures (casing pressures) to reach 1500 psi while drilling out the wellbore plugs. In this respect, the wellbore fluid pump pressures at the surface have to overcome total frictional pressures in the wellbore plus the casing pressure. While drilling the wellbore plugs, any change in the annular space fluid pressure (casing pressure) may cause wellbore drilling fluid pump pressures to change. The conventional autodriller systems only work under drilling conditions where there is no casing pressure on the well. Therefore only a tubing string pressure sensor data is used to control the auto driller and to control optimum drilling weight on downhole motors and drill bits, implicitly assuming casing pressure is constant and atmospheric. However, simply monitoring the pressure of the wellbore fluid pumped from the wellbore fluid pump into the tubing string may not be enough to monitor the weight on the drilling bit. The system of the present invention provides a control and monitoring process involving the measurement of both the pressure of the casing fluid and the pressure of the wellbore fluid delivered through the tubing string to accurately infer weight on the downhole motor and the drill bit.

For example, when the drill bit is disposed just above a wellbore plug (moments before it is further lowered to start drilling), wellbore fluid pressure and casing fluid pressure can be measured and recorded as the beginning pressure values. Next, as the drilling bit is lowered onto the wellbore plug and when the drilling operation commences, the changes both on the wellbore fluid pump and the casing pressures are continuously monitored to decide if the change in the wellbore fluid pump pressure is due to weight on the downhole motor and the drilling bit or due to influx of formation fluids within the casing (annular space). In one example, initially, depending on the downhole motor and the drill bit, a pressure difference value is assigned, for example, 250 psi. Next, as the drill bit is disposed just above the wellbore plug, the wellbore fluid pressure and the casing fluid pressure can be measured and recorded as the beginning pressure values, for example 2000 psi and 300 psi, respectively. Next, a differential pressure set point can be determined by adding the pressure difference value to the difference of the wellbore fluid pressure and the casing pressure, which in this case 1950 psi. During the drilling process, if simultaneous pressure measurements, as described, give a pressure value below the differential pressure set point, the tubing string may be advanced to increase the pressure; however, if the measured pressure value is greater or equal to the differential pressure set point the tubing string may be stopped.

In accordance with the present invention at least one casing pressure sensor 42, or annular space pressure sensor, may be disposed in operable communication with the annular space for measuring the casing pressure, or annular space fluid pressure, therein.

Referring back to FIG. 2, in this embodiment, there may be plurality of casing pressure sensors, such as a first casing pressure sensor 42a and a second casing pressure sensor 42b, to measure fluid pressure within the annular space 48. The first casing pressure sensor may be disposed on a fluid outlet between the BOP device 20 and adjustable flow restriction device 99 in communication with the annular space 48 for generating a first casing pressure sensor data. Alternatively, the second casing pressure sensor 42b may be disposed within the annular space 48 of the wellbore 14 and adjacent the surface 28 for generating a second casing pressure sensor data. At least one tubing pressure sensor 38, or drill string pressure sensor, may be disposed in operable communication with the tubing string 26 to monitor and detect drill fluid pressure within the tubing string 26 and generate casing pressure sensor data. An exemplary tubing pressure sensor may be a Model 170 Hammer Union pressure transmitter made by GP 50, US. An exemplary casing pressure sensor can be Model 509 by Viatran, US. In embodiments, the downhole motor 15 may be a SPIROSTAR™ made by Bico Drilling Tool, US. In embodiments, the downhole cutting device can be a METAL MUNCHER™ made by Baker Hughes, US. An example of the second casing pressure sensor can be Model 1502 by Stellar Technology, US.

As shown in FIG. 3, a processor 50 of the system 10 may be in communication with the tubing pressure sensor 38 and the casing pressure sensor 42 to receive tubing pressure values or data and casing pressure values or data, respectively, during a wellbore operation such as drilling the wellbore plugs. The processor 50 may also be in communication with a data storage 52 which may register the tubing pressure 100 and casing pressure data 105 transmitted to the processor 50 from the sensors 38 and 42. The tubing pressure data 100 and the casing pressure data 105 stored in the data storage are shown in FIGS. 4A-4B. The processor 50 may be adapted to monitor the wellbore fluid pressure and the casing fluid pressure during a drilling operation, to adjust a mechanical load on the downhole drilling tool based on a difference pressure value between a tubing pressure value or data, i.e., the wellbore fluid pressure within the tubing string, and a casing pressure value, i.e., the fluid pressure within the annular space 48. The processor 50 is further adapted to adjust the load, i.e., by either advancing the tubing string 26 or by stopping its movement, in response to a change in the difference pressure value that is at least one of an increase and a decrease beyond a previously selected operation pressure threshold. The mechanical load may be a weight on the drill bit generated by the advancing tubing string 26 so that more force may be applied by the drill bit while drilling the wellbore plugs. A pump stroke counter 98 may be secured to the wellbore fluid pump 36 to transmit pump stroke data to the processor 50. The pump stroke data may include a count of pump strokes by the pump over time. The pump stroke data may be transferred to the processor 50 to be stored in the data storage. The pump stroke counter can be an inductive transducer connected to the wellbore fluid pump. In embodiment, the wellbore fluid pump can be a PZ-9XXX made by National Oilwell Varco (“NOV”), US.

The processor 50 may be a computer, a laptop, a programmable logic controller, or a similar controller with processing capabilities and bidirectional communication capabilities. The data storage is a non-transitory computer readable medium. The processor 50 and/or the data storage 52 may be a plurality of processors and/or data storages connected in series or in parallel, such as a cloud based processing and data storage system. A display 39 may be connected to the processor 50. The display can enable an operator to view a message from the processor 50 to manually advance the tubing string 26 by operating the drawworks on the rig or stopping operation of the drawworks on the rig. The autodriller 60, which may be electrically connected to a drawworks 81 on the rig 32, can be used to receive commands from the processor 50 and slack off weight on the tubing string 26 to advance the tubing string by operating the drawworks 81 on the rig 32 or stopping operation of the drawworks on the rig. An example of a usable autodriller 60 can be a WILDCAT™ autodriller as made by National Oilwell Varco, US.

A torque sensor 80 may be positioned to or in communication with the processor 50 for transmitting torque sensor data to the data storage 52. An example of a torque sensor 80 can be a Model 509 by Viatran, US. A hook load sensor 88 may connected to or may be in communication to the processor. An example of a hook load sensor can be hook load sensors made by Source Technology, US.

A pump stroke counter 98 can be in communication with the processor to transmit pump stroke data 150, which includes a count of pump strokes to the processor for storage in the data storage. The pump stroke data 150 is shown in FIGS. 4A-B. The casing choke valve 99 may be in communication with the processor 50. The casing choke valve 99 may be open, close, or partially close based on commands from the processor. An exemplary casing choke valve may be one made by Power Chokes, US. A video capture device 106 can be connected to or in communication with the processor 50 for visually monitoring the tubing string and the rig. An exemplary video capture device may be a video camera made by Panasonic. The processor 50 may be in communication or may connect to a network 41. Examples of usable networks can include a satellite network, a cellular network, a global communication network, such as the internet, a local area network, a wide area network, a similar network or combinations thereof.

The network 41 can be in communication with at least one client device 143. The client device 143 can be a computer, a laptop, a smart phone, a tablet, or similar device for bidirectional communication and receipt of messages from the processor. The network 41, which may be connected to the processor 50 and to at least one client device 143 receives the message and transmits the message to the client device for slacking off weight on the tubing string to advance the tubing string 26 to put load on the drill bit or stopping operation of the downhole cutting device. In embodiments, the system drills sequentially through a plurality of wellbore plugs in a cased well in a single trip.

FIGS. 4A-4B show a diagram of the data storage usable with the system. The data storage 52 may contain various data points, information and computer instructions. The data storage 52 may contain a message 53. In embodiments, the message 53 may be transmitted to the autodriller to slack off weight on the tubing string by operating a drawworks on the rig or stopping operation of the drawworks on the rig and the message can be transmitted to the display connected to the processor enabling an operator to manually slack off weight on the tubing string by operating the drawworks on the rig or stopping operation of the drawworks on the rig. The data storage 52 can contain tubing pressure sensor data 100, which can be obtained from the tubing pressure sensor.

The data storage 52 may contain casing pressure sensor data 105, which can be obtained from at least one casing pressure sensor 38. The data storage 52 may also contain casing pressure limits, such as 1500 psi. The data storage 52 may contain differential pressure set point limits 110 for the downhole motor. The data storage 52 may contain autodriller differential value 115. The data storage 52 may contain torque sensor data 120, which may be obtained from the torque sensor connected to the tubing string 26. The data storage 52 may contain torque limits 125 and torque differential value 130. An example of a torque limit may be a set point, such as 4000 foot pounds of torque for about 2⅞ inches in diameter tubing. The data storage 52 may contain the hook load sensor data 135, which may be transmitted by the hook load sensor from a location where the tubing string engages the hook. The data storage 52 may contain a hook load limit 140, specifying the weight limit, and hook load differential value. 145. The data storage 52 may contain pump stroke data 150, which can be obtained from the pump stroke counter.

The data storage 52 may contain computer instructions 500 to instruct the processor to transmit the pressure set point to autodriller, wherein the autodriller sets weight on the tubing string and power to the downhole cutting device based on the pressure set point. The data storage 52 may contain computer instructions 505 to instruct the processor to receive and store tubing pressure sensor data and casing pressure sensor data. The data storage 52 may contain computer instructions 506 to receive and store the torque sensor data. The data storage 52 may contain computer instructions 507 to receive and store the hook load data. The data storage 52 may contain computer instructions 508 to instruct the processor to store and receive the pump stroke data and to calculate flow rates of the wellbore fluid pump using the pump stroke data. The pump stroke data may be 100 strokes per minute for the wellbore fluid pump. The data storage 52 may contain computer instructions 510 to instruct the processor to compare the tubing pressure sensor data and the casing pressure sensor data to the pressure set point, thereby creating an autodriller differential value.

The data storage 52 may contain computer instructions 511 to instruct the processor to compare torque sensor data to the torque limits, thereby creating a torque differential value, and transmit a torque message to a top drive on the rig or a power swivel on the rig to start or stop rotation of the tubing string or change speed of rotation of the tubing string.

The data storage 52 may contain computer instructions 512 to instruct the processor to compare hook load data to the hook load limits, thereby creating a hook load differential value, and provide a hook load command transmitted to at least one of: an autodriller on the rig to slack off weight on the tubing string by operating a drawworks on the rig or stopping operation of the drawworks on the rig; and a display connected to the processor enabling an operator to manually slack off weight on the tubing string by operating the drawworks on the rig or stopping operation of the drawworks on the rig.

The data storage 52 may contain computer instructions 516 to instruct the processor to transmit the torque differential value to a power swivel to start rotation of the tubing string, change speed of rotation of the tubing string, or stop rotation of the tubing string. The data storage 52 may contain computer instructions 517 to instruct the processor to transmit the hook load differential value to the client device to have user to add or remove the weight on the tubing string. The data storage 52 may contain computer instructions 520 to instruct the processor to transmit the downhole motor differential value to the autodriller. The data storage 52 may also contain computer instructions 521 to instruct the processor to transmit the pressure set point as adjusted to the client device to have a user adjust manually the weight on the tubing string and the power to the downhole cutting device based on the pressure set point. The data storage 52 may contain computer instructions 522 to instruct the processor to transmit the torque differential value to the client device to have a user adjust manually the power swivel to start rotation of the tubing string, change speed of rotation of the tubing string, or stop rotation of the tubing string. The data storage 52 may contain computer instructions 525 to instruct the processor to log sensor data for post operational analysis.

The data storage 52 may also contain computer instructions to instruct the processor to compare the tubing pressure sensor data to the casing pressure sensor data to produce a measured differential pressure for the downhole motor. The data storage 52 may also contain computer instructions to instruct the processor to compare the measured differential pressure for the downhole motor to the differential pressure set point limits of the downhole motor. The data storage 52 may also include computer instructions to instruct the processor to transmit calculated flow rates of the wellbore fluid pump using the pump stroke data to a display. The data storage 52 may also contain computer instructions to instruct the processor to transmit a message when the measured differential pressure for the downhole motor is either (i) less than the differential pressure set point limit for the downhole motor or (ii) equal to or greater than the differential pressure set point limit for the downhole motor.

The data storage 52 may also contain computer instructions to instruct the processor to compare casing pressure sensor data to casing pressure limits and transmit a command to a casing choke valve on the rig to open, close, or partially close. An exemplary casing pressure limit can be 1500 psi on the casing. The data storage 52 may also contain computer instructions to instruct the processor to provide an operator dashboard and an administrative dashboard simultaneously for on-location and off-location simultaneous monitoring and control of the system to drill sequentially through a plurality of wellbore plugs.

The data storage 52 may also contain computer instructions to instruct the processor to provide an administrative dashboard configured to simultaneously monitor and control multiple systems to drill sequentially through multiple cased wellbores, each having a plurality of wellbore plugs. The data storage 52 may also contain an operator dashboard. The operator dashboard can have the name of the well, the owner of the well, a location of the well, a date, a time stamp, and a graphical presentation of measured data and set point limits of the system. The data storage 52 may also contain an administrative dashboard. The administrative dashboard can have the name of one or a group of wells, names of an owner or groups of owners of wells, all locations of the wells, a date, a time stamp, and a graphical presentation of measured data and set point limits for each well being treated by one of the systems.

FIG. 5 is a diagram of a method according to one or more embodiments. The method may include as step 600 connecting an autodriller to a downhole cutting device and to a tubing string on a rig. The method may include as step 610 applying weight to the tubing string while the downhole cutting device is rotating simultaneously. The method may include as step 615 contacting a wellbore plug in the casing with a downhole cutting device, whereby wellbore fluid is pumped through the tubing string. The method may include as step 620 transmitting tubing pressure sensor data from the tubing string and casing pressure sensor data from the annulus of the cased wellbore are transmitted to a processor during drilling of the wellbore plug. The method may include as step 625 comparing the tubing pressure sensor data to weight limits for penetrating the wellbore plug and comparing casing pressure sensor data to pressure limits. The method may include as step 630 adjusting the weight applied to the drill string and the rotation of the downhole cutting device based on the comparison (relative differential values) and input of data from other sensors connected to the rig, drill string, downhole cutting device, and wellbore. The method may include as step 635 repeating the steps of collecting data, comparing the data against preset limits, and modifying the drilling process as the wellbore plugs are drilled sequentially.

In another embodiment, a method to drill through a wellbore plug in a cased wellbore may include the step of connecting a downhole motor to a downhole cutting device. The method may include the step of connecting the downhole motor to a tubing string. The method may include the step of connecting the tubing string to a rig. The method may include the step of pumping wellbore fluid through the tubing string to power the downhole motor and rotate the downhole cutting device while simultaneously applying weight on the downhole cutting device as the downhole cutting device contacts one of a plurality of wellbore plugs. The method may include the step of drilling through the wellbore plug in the cased wellbore while controlling differential pressure of the downhole motor in the cased wellbore. The method may include the step of transmitting tubing pressure sensor data from the tubing string to a processor. The method may include the step of transmitting casing pressure sensor data from the annulus of the cased wellbore to the processor. The method may include the step of comparing the tubing pressure sensor data to the casing pressure sensor data to produce a measured differential pressure for the downhole motor as the downhole motor rotates the downhole cutting device through the wellbore plug. The method may include the step of comparing the measured differential pressure for the downhole motor to the differential pressure set point limits of the downhole motor. The method may include the step of transmitting a message when the measured differential pressure for the downhole motor is either (i) less than the differential pressure set point limit for the downhole motor or (ii) equal to or greater than the differential pressure set point limit for the downhole motor, the message is transmitted to at least one of: an autodriller on the rig to advance the tubing string by operating a drawworks on the rig or stopping operation of the drawworks; and a display connected to the processor enabling an operator to manually advance the tubing string by operating the drawworks or stopping operation of the drawworks.

In embodiments, the plurality of wellbore plugs can be an obstruction, an exploded well perforating gun, a deformed tubular, a rock, drilling cuttings, a bridging in the wellbore, a similar obstruction or object, or combinations thereof. In embodiments, the rig can be a drilling rig or a coiled tubing unit connected to the tubing string. In embodiments, the downhole cutting device can be a mill, a fixed face bit, or a roller cone bit. In embodiments, the downhole cutting device can be configured to be rotated by the downhole motor at a rotation up to 1000 rotations per minute (rpm). In embodiments, the wellbore fluid pump can be configured to pump the wellbore fluid at a rate proportional to the inner diameter of casing in the cased wellbore, and wherein the weight applied to the downhole cutting device is up to 15000 pounds.

While these embodiments have been described with emphasis on the embodiments, it should be understood that within the scope of the appended claims, the embodiments might be practiced other than as specifically described herein.

Claims

1. A system for controlling load on a downhole tool of a well drilling equipment of an oil or gas rig, comprising:

a downhole drilling tool, including a drill bit, connected in operable communication with a drill string extending within a wellbore, the drill string being adapted to permit a drilling fluid to flow to the downhole drilling tool, wherein the drilling fluid flows into an annular space from the downhole drilling tool or a distal end outlet of the drill string, the annular space being formed between the drill string and the wellbore wall;

a pump for pumping the drilling fluid from a drilling fluid tank through the drill string into the annular space;

a fluid back pressure system comprising a variable flow restriction device for applying flow restriction in the annular space to restrict fluid flow therein;

at least one first sensor disposed in operable communication with the drill string for measuring a drilling fluid pressure within the drill string;

at least one second sensor disposed in operable communication with the annular space for measuring an annular space fluid pressure therein; and

a processor adapted to monitor the drilling fluid pressure and the annular space fluid pressure during a drilling operation, to adjust a mechanical load on the downhole drilling tool based on a difference pressure value between the drilling fluid pressure and the annular space fluid pressure.

2. The system of claim 1, wherein the wellbore is a cased wellbore.

3. The system of claim 2, wherein the drilling operation includes a well bore plug drilling operation for drilling wellbore plugs within a cased wellbore.

4. The system of claim 3, wherein the processor is further adapted to adjust the load in response to a change in the difference pressure value by at least one of an increase and a decrease beyond a selected pressure threshold.

5. The system of claim 3, wherein the mechanical load is the weight of the drill string on the drill bit.

6. A method of controlling load on a downhole tool of a well drilling equipment of an oil or gas rig, comprising:

disposing a downhole drilling tool, including a drill bit, connected in operable communication with a drill string extending within a wellbore, the drill string being adapted to permit a drilling fluid to flow to the downhole drilling tool, wherein the drilling fluid flows into an annular space from the downhole drilling tool or a distal end outlet of the drill string, the annular space being formed between the drill string and the wellbore wall;

pumping the drilling fluid from a drilling fluid tank through the drill string into the annular space;

applying flow restriction in the annular space to restrict fluid flow therein using a fluid back pressure system comprising a variable flow restriction device;

disposing at least one first sensor in operable communication with the drill string for measuring a drilling fluid pressure within the drill string;

disposing at least one second sensor in operable communication with the annular space for measuring an annular space fluid pressure therein;

monitoring the drilling fluid pressure and the annular space fluid pressure by a processor during a drilling operation; and

advancing the drill string to add mechanical load on the downhole drilling tool based on a difference pressure value between the drilling fluid pressure and the annular space fluid pressure.

7. The method of claim 6, wherein the step of advancing the drill string adds mechanical load on a wellbore plug within the wellbore.

8. The method of claim 7 further comprising drilling the wellbore plug within the wellbore.

9. The method of claim 8 further comprising adjusting the mechanical load in response to a change in the difference pressure value by at least one of an increase and a decrease beyond a selected pressure threshold.

10. The method of claim 8, wherein the mechanical load is the weight of the drill string on the drill bit.

11. A system to drill through at least one wellbore plug in a cased wellbore, the system comprising:

a downhole motor connected to a tubing string;

a downhole cutting device hydraulically connected to the downhole motor;

a wellbore fluid pump for pumping a wellbore fluid through the tubing string, the wellbore fluid pump connected to the downhole motor for rotating the downhole cutting device while weight is simultaneously applied on the downhole cutting device, thereby enabling the downhole cutting device to contact and cut through the at least one wellbore plug in the cased wellbore;

a tubing pressure sensor connected to the tubing string for producing tubing pressure sensor data;

at least one casing pressure sensor installed in communication with the cased wellbore producing a casing pressure sensor data;

a processor connected to the tubing pressure sensor and the at least one casing pressure sensor; and

a data storage connected to the processor, the data storage comprising: computer instructions to instruct the processor to receive and store the tubing pressure sensor data and the casing pressure sensor data; at least one differential pressure set point limit for the downhole motor; computer instructions to instruct the processor to compare the tubing pressure sensor data to the casing pressure sensor data to calculate a measured differential pressure for the downhole motor; computer instructions to instruct the processor to compare the measured differential pressure for the downhole motor to the at least one differential pressure set point limit of the downhole motor; and computer instructions to instruct the processor to selectively transmit a message when the measured differential pressure for the downhole motor is either: (i) less than the at least one differential pressure set point limit for the downhole motor, (ii) equal to the at least one differential pressure set point limit for the downhole motor, or (iii) greater the at least one differential pressure set point limit for the downhole motor, wherein the message is transmitted to an autodriller to advance the tubing string by operating a drawworks.

12. The system of claim 11, further comprising a torque sensor in communication with the tubing string for transmitting torque sensor data to the processor and the data storage, the data storage further comprising: at least one torque limit and computer instructions for comparing torque sensor data to the at least one torque limit; and transmitting a torque message to start or stop rotation of the tubing string or change speed of rotation of the tubing string.

13. The system of claim 11, further comprising:

a hook load sensor positioned on a hook, the hook suspending the tubing string, the hook load sensor transmitting hook load data to the processor for storage in the data storage;

and wherein the data storage further comprising: at least one hook load limit; and

computer instructions for comparing hook load data to the at least one hook load limit, and selectively providing a hook load command transmitted to the autodriller to advance the tubing string by operating the drawworks.

14. The system of claim 11, further comprising:

a pump stroke counter in communication with the wellbore fluid pump to transmit pump stroke data to the processor for storage in the data storage; the data storage further comprising:

computer instructions to instruct the processor to store and receive the pump stroke data and to calculate flow rates of the wellbore fluid pump using the pump stroke data; and computer instructions to instruct the processor to transmit calculated flow rates using the pump stroke data.

15. The system of claim 11, wherein the data storage further comprises:

at least one casing pressure limit; and

computer instructions to instruct the processor to compare casing pressure sensor data to the at least one casing pressure limit and transmit a command to a casing choke valve to open, close, or partially close.

16. The system of claim 11, wherein the data storage further comprises computer instructions to instruct the processor to log sensor data for post operational analysis.

17. The system of claim 11, wherein the data storage further comprises computer instructions providing an operator dashboard and an administrative dashboard simultaneously for on-location and off-location monitoring and control of the system to drill sequentially through a plurality of wellbore plugs.

18. The system of claim 11, wherein the data storage further comprises computer instructions providing an administrative dashboard configured to simultaneously monitor and control multiple systems to drill through multiple cased wellbores, each having a plurality of wellbore plugs.

19. The system of claim 11, further comprising a video capture device connected to the processor for visually monitoring the tubing string.

20. The system of claim 11, wherein the downhole cutting device is at least one of: a mill, a fixed face bit, and a roller cone bit.

21. The system of claim 11, further comprising an additional casing pressure sensor.

22. The system of claim 11, further comprising a network connected to the processor and the at least one client device connected to the network, wherein the message is also transmitted to the at least one client device.

23. The system of claim 11, wherein the system drills through a plurality of wellbore plugs in a cased well.

24. A method to drill through at least one wellbore plug in a cased wellbore including the steps of:

connecting a downhole motor to a downhole cutting device;

connecting the downhole motor to a tubing string;

connecting the tubing string to a rig;

pumping wellbore fluid through the tubing string to power the downhole motor and rotate the downhole cutting device while simultaneously applying weight on the downhole cutting device as the downhole cutting device contacts the at least one wellbore plug;

drill through the at least one wellbore plug in the cased wellbore while controlling differential pressure of the downhole motor in the cased wellbore;

transmitting tubing pressure sensor data to a processor;

transmitting casing pressure sensor data to the processor;

comparing the tubing pressure sensor data to the casing pressure sensor data to calculate a measured differential pressure;

comparing the measured differential pressure for the downhole motor to at least one differential pressure set point limit of the downhole motor; and

selectively transmitting a message when the measured differential pressure for the downhole motor is either: (i) less than the at least one differential pressure set point limit for the downhole motor, (ii) equal to the at least one differential pressure set point limit for the downhole motor, or (iii) greater the at least one differential pressure set point limit for the downhole motor,

wherein the message is transmitted to at least one of:

an autodriller to advance the tubing string by operating a drawworks;

a display connected to the processor enabling an operator to manually advance the tubing string by operating the drawworks; and

at least one client device.