Coiled tubing drilling advisor

Abstract

A coiled tubing drilling advisor is configured to generate coiled tubing drilling advisories that include supervisory instructions to rig personnel that provide supervisory oversight of a coiled tubing wellbore operation. The advisories include at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies. The advisories are generated based on an input coiled tubing drilling configuration, input coiled tubing drilling operational parameters, and received downhole and surface sensor measurements made during a coiled tubing wellbore operation.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] None.BACKGROUND

[0002] Coiled tubing drilling operations are commonly utilized to drill high dogleg and horizontal wellbore sections. In such coiled tubing drilling operations, the drill bit and bottom hole assembly (BHA) are conveyed into the wellbore via a continuous length of coiled tubing. A mud motor or turbine is commonly employed to rotate the drill bit since the coiled tubing is not rotated in the wellbore. In many operations, coiled tubing drilling operations employ underbalanced drilling in which the hydrostatic pressure in the wellbore is kept lower than the pressure of the formation being drilled. In such underbalanced coiled tubing drilling operations, formation fluid and / or gas generally flows into the wellbore and to the surface during the drilling operation.

[0003] Coiled tubing drilling generally requires three key systems, a coiled tubing system (e.g., a tubing injector), a returned fluids management system, and a directional bottom hole assembly (BHA). The coiled tubing system may include an injector head suitable for controlling the weight on bit (WOB) and rate of penetration (ROP) of the drilling operation, and equipment for pumping and well control. The return fluids management system may include an adjustable drilling fluid composition that enables the hydrostatic pressure in the wellbore to be controlled and enables wellbore fluids and / or gas to be returned to and separated at the surface. The fluids system may further include numerous sensors and chokes for controlling the return flow of circulating fluids in the wellbore. The directional BHA may include downhole measurement tools as well as a downhole steering tool or bent sub configured for controlling the direction or the rate of change of the direction of drilling.

[0004] In many coiled tubing drilling operations, these three systems are provided by three different service providers having distinct personnel and limited communications, and no integrated data overview. Moreover, coiled tubing drilling operations are often manually intensive, with the individual service providers following their own best practices. Unfortunately, owing to the manual nature of the operations, adherence to standard operating procedures or best practices can be deficient, thereby resulting in suboptimal operational efficiency and consistency, unnecessary service quality issues, lost production time, and increased costs. There is a need in the industry for an automated or semi-automated system or system advisor that integrates the key systems to improve coiled tubing drilling operations, particularly for underbalanced coiled tubing drilling operations.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] For a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: FIGS. 1A and 1B (collectively FIG. 1) depict an example coiled tubing drilling operation including the disclosed coiled tubing drilling supervisory control system. FIG. 2 depicts a block diagram of the supervisory control system of FIG. 1 in communication with a coiled tubing subsystem, a BHA subsystem, and an underbalanced or managed pressure subsystem. FIG. 3 depicts an example embodiment of the supervisory control system of FIG. 1. FIG. 4 depicts another example embodiment of the supervisory control system of FIG. 1. FIG. 5 depicts a flow chart of one example method for supervising a coiled tubing wellbore operation. FIG. 6 depicts a flow chart of another example method for supervising a coiled tubing wellbore operation. FIG. 7 depicts a flow chart of an example method for supervising a coiled tubing wiper trip. FIG. 8 depicts a flow chart of an example method for supervising a coiled tubing tripping operation. FIG. 9 depicts a flow chart of an example method for supervising a coiled tubing sidetracking operation. DETAILED DESCRIPTION

[0006] Methods and systems for advising a coiled tubing wellbore operation are disclosed. In one example embodiment, a method comprises inputting a coiled tubing drilling configuration into a supervisory control system and inputting coiled tubing drilling operational parameters into the supervisory control system. Downhole and surface sensor measurements made during the coiled tubing wellbore operation are received in the supervisory control system and evaluated to generate coiled tubing drilling advisories. The generated coiled tubing drilling advisories include supervisory instructions to rig personnel that provide supervisory oversight of the coiled tubing wellbore operation. The coiled tubing drilling advisories include at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies.

[0007] FIGS. 1A and 1B (collectively FIG. 1) depict an example coiled tubing drilling operation 20 including a disclosed coiled tubing drilling supervisory control system 100 (e.g., an automated drilling controller or advisor). As described in more detail below, the supervisory control system 100 may be configured to automatically provide supervisory control of a coiled tubing drilling operation (e.g., including drilling, tripping, wiper trip, and sidetrack operations) and in so doing may provide advisories for rig personnel to integrate the bottom hole assembly, the return fluids management system, and the coiled tubing system during the operation. In the depicted example embodiment, coiled tubing 30 and other equipment are delivered into a subterranean wellbore 40 of an oilfield by a truck 50 (or portable platform / rig). The truck 50 accommodates a coiled tubing reel 52 and equipment for threading the coiled tubing 30 through a gooseneck 54 and injector head 55 for advancement of the coiled tubing 30 into the wellbore 40. Other conventional equipment such as a blow-out preventor stack 57 and a master control valve 58 may be employed in directing the coiled tubing 30 out of the well 40 or preventing its uncontrollable release to the environment.

[0008] The coiled tubing drilling operation 20 may make use of a bottom hole assembly (BHA) 35, a mud motor 38, and a drill bit 32 deployed on a downhole end of the coiled tubing string 30 (in wellbore 40 in the depicted embodiment). The motor 38 may include a positive displacement motor or a turbine and may be configured to convert drilling fluid flow (hydraulic force) to rotary motion to rotate the drill bit 32 and drill the wellbore 40. The BHA 35 may include various downhole tools used in drilling the wellbore, for example, including measurement while drilling (MWD) and logging while drilling (LWD) tools that may include various sensors (not shown) for sensing downhole characteristics and environment of the wellbore and the surrounding formation, an orienting tool to change toolface angle, as well as a steering tool or bent sub to steer the direction of drilling. The disclosed embodiments are, of course, not limited to any particular BHA configuration.

[0009] Data generated by the MWD, LWD, steering tool, and / or other sensors may be transmitted (communicated) uphole to supervisory control system 100. In certain embodiments, the data may be transmitted uphole in substantially real time (e.g., while it is being detected by the downhole sensors during the drilling operation), for example, via a wireline (or wireless) telemetry link 62. Moreover, control commands may be sent from the surface to the BHA via the wireline telemetry link 62. In some embodiments, electric power may also be provided to the BHA via the wireline link 62. As is known to those of ordinary skill in the art, the wireline telemetry link may be routed along an interior of or within a wall of the coiled tubing 30.

[0010] As noted above, the coiled tubing 30 may be delivered downhole via an injector head 55. In certain embodiments, the injector head 55 may be controlled to slack off or pick up the coiled tubing 30 so as to control the amount of speed of tubing into the wellbore and, correspondingly, the weight on bit (WOB) acting on the drill bit 32 (or BHA). In this way, the rate of penetration (ROP) of the drilling operation may be controlled. Depending on the specifics of the coiled tubing operation, various types of data may be collected downhole, and transmitted to the supervisory control system 100. For example, the data may be used to fully or partially automate downhole operations, to optimize the downhole operations, and / or to provide more accurate predictions regarding components or aspects of the downhole operations as well as to integrate the control of the coiled tubing injection (and ROP), the BHA operation, and the managed pressure or underbalanced drilling.

[0011] A pump unit 80 (FIG. 1B) may be employed to pump drilling fluid downhole through the coiled tubing 30 to the drill bit 32 as depicted at 71 (FIG. 1A), for example, to cool and lubricate the drill bit and generate rotary power to the drill bit 32 (via motor 38). The drilling fluid is also intended to carry cuttings and other debris, comingled or not with formation gases and fluids, to the surface in return flow 72 in the wellbore annulus 42. The return flow rate may be controlled, for example, via a choke manifold 74 that may include a number chokes and other components / equipment used to influence a variety of parameters, including the bottom hole pressure. A mud gas separator 75 may be employed to remove nitrogen gas (and other gases) from the returning fluid. Solids control equipment, for example including a settling tank 76 or a shale shaker (not shown), may be configured to remove drill cuttings from the returning fluid. The recovered fluid may be held in active tanks 77 and / or circulated through a centrifuge 78 to remove residual fine cuttings particles.

[0012] During underbalanced drilling operations, it may be advantageous to maintain bottomhole pressure within a desired or predetermined pressure window below the reservoir pressure during all phases of the coiled tubing drilling operation (drilling, wiper tripping, sidetracking, etc.). Maintaining bottomhole pressure within a targeted window may be accomplished, for example, by coordinating the operation of mud pumps 80, the injector head 55, and the choke manifold 74 based on various surface and downhole sensor measurements. Moreover, in many underbalanced operations, nitrogen gas is used to reduce the density of the drilling fluid and create the underbalanced condition. The use of high partial fractions of nitrogen are not uncommon. As such, the coiled tubing drilling operations may optionally make use of a nitrogen cryogenic (liquid nitrogen) unit 82 to introduce nitrogen gas into the drilling fluid prior to pumping the fluid downhole.

[0013] FIG. 2 depicts a block diagram of one example embodiment of supervisory control system 100 in communication with a coiled tubing subsystem 170, a BHA subsystem 180, and an underbalanced or managed pressure subsystem 190. As depicted, the supervisory control system 100 is in communication with each of the subsystems 170, 180, 190. The supervisory control system 100 may be configured to acquire operational and equipment data from the various sensors deployed in each subsystem 170, 180, 190. The supervisory control system 100 may be further configured to evaluate the acquired data (as well as user input and system configuration information) to determine the operational state (e.g., tripping, drilling, wiper trip, etc.) and to provide actionable operational instructions (advisories) to each of the subsystems 170, 180, 190 such that the subsystem operators may adhere to (or be in compliance with) established processes, procedures, and best practices. The system 100 may further include smart alarms to alert operational personnel of pending operational issues, such as pending stuck pipe incidents, motor stall, etc. In some embodiments, the supervisory control system 100 may be still further configured to automatically or semi-automatically control or partially control the operation of one or more of the subsystems 170, 180, 190.

[0014] Turning now to FIG. 3, example embodiments of supervisory control system 100 are described in more detail. The depicted supervisory control system 100 may include one or more analysis modules 110 (e.g., a program of computer-executable instructions and associated data) that may be configured to perform various control functions of the embodiments described herein (e.g., as described in more detail below with respect to FIGS. 5-9). The supervisory control system 100 may further include one or more processors 120 and storage media 130. In example embodiments, the analysis modules 110 may be stored in the storage media 130 and may be executed by the processor(s) 120.

[0015] The processor(s) 120 may include substantially any suitable microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, digital signal processor, and / or other control or computing device. Moreover, in example embodiments, the processor(s) 120 may include machine learning and / or artificial intelligence (AI) based processors. The storage media 130 may be implemented as one or more non-transitory computer-readable or machine-readable storage media. For example, the storage media 130 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. As noted above, the computer-executable instructions and associated data of the analysis module(s) 110 may be provided on a computer-readable or machine-readable storage medium of the storage media 130, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media are considered to be part of an article (or article of manufacture), which may refer to any manufactured single component or multiple components. The storage media 130 may be located either in the machine running the machine-readable instructions, or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

[0016] With continued reference to FIG. 3, system 100 may further include a network interface 140, for example, in communication with the processor(s) 120. The network interface 140 may be in electronic communication with various downhole equipment 150 (e.g., located in the BHA) or surface equipment 160 (e.g., the choke manifold 74, the injector head 55, the pumping unit 80, etc.) and may be configured to enable the system 100 to communicate therewith. The downhole equipment 150 and surface equipment 160 may each include multiple downhole sensors 152, 162, actuators 154, 164, and / or programmable logic controllers (PLC) 156, 166. Such communication with the downhole equipment 150 and the surface equipment 160 may enable the system 100 to control the coiled tubing drilling operation as described in greater detail herein. In certain embodiments, the network interface 140 may also enable the system 100 to communicate with an external computing system 145, such as cloud storage (or other wired and / or wireless communication network), for example, to archive the data or to enable external computing systems to access the data and / or to remotely interact with the surface processing system 100.

[0017] It should be appreciated that the supervisory control system 100 shown on FIG. 3 is merely one example of a suitable supervisory control system 100, and that the system may have more or fewer components than shown, may combine additional components not depicted, and / or may have a different configuration or arrangement of the depicted components. In addition, the various components illustrated in FIG. 3 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and / or application specific integrated circuits. Furthermore, the operations of the supervisory control system 100 as described herein may be implemented by running one or more functional modules in an information processing apparatus such as application specific chips, such as application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), programmable logic devices (PLDs), systems on a chip (SOCs), or other appropriate devices. These modules, combinations of these modules, and / or their combination with hardware are all included within the scope of the embodiments described herein.

[0018] As described above, the network interface may be configured to acquire data from a plurality of downhole sensors 152 and surface sensors 162. The sensor measurements may be acquired in substantially real time via wired or wireless telemetry. Non-limiting examples of downhole sensors 152 may include sensors configured to measure, for example, weight-on-bit (WOB), torque acting on the BHA, vibrations, downhole pressures, downhole differential pressures, logging measurements such as gamma ray and resistivity measurements, survey measurements such as wellbore inclination and azimuth, and other desired downhole parameters. Non-limiting examples of surface sensors 162 may include sensors configured to measure, for example, parameters related to fluid and solid returns (e.g., wellhead pressure, return fluid flow rate, returned gas rate, choke settings, the amount of cuttings returned, and other desired surface parameters), parameters related to the injector head or tubing real such as a tubing feed rate or coiled tubing weight, or the pumping system such as pump pressure or fluid flow rate.

[0019] In some embodiments, the acquired sensor measurements may enable the system 100 to self-learn (e.g., via modeling or simulation using machine learning or artificial intelligence (AI) based processors, machine learning or AI based algorithms stored in the one or more storage media 130, or combinations thereof). For example, in certain embodiments, the acquired sensor measurements may be used to train machine learning or AI based algorithms to determine certain operating parameter adjustments that may be manually or automatically implemented to improve the coiled tubing drilling operation in substantially real time. Such adjustments may be made to the coiled tubing system, the return fluid management system (e.g., an underbalanced management system), and / or the directional BHA. Such real-time modeling by the supervisory control system 100 may enable improved coiled tubing drilling operations, either in manual or automated operations. Modeling may also be used to optimize the operation to prolong service life of the various equipment. For example, the supervisory control system 100 may predict wear on the mud motor 38 and / or the drill bit 32, adjust the operating parameters to minimize the wear, and to advise the operator regarding projecting timing of the next trip to the surface to replace the motor 38 and / or the bit 32.

[0020] The supervisory control system 100 may be configured to predict various downhole events related to the coiled tubing drilling operation. For example, downhole measurements such as WOB, pressure, differential pressure, BHA torque, and the like may be evaluated by the supervisory control system 100 to predict or advise an operator that the operational conditions may induce a mud motor stall. In such embodiments, the supervisory control system 100 may be configured to make recommendations for adjusting (either to be executed manually by the operators, or to be executed automatically without human intervention by the control system), for example, a speed of the injector head 55 and / or the pump pressures to prevent the stall, and to ensure efficient continuous operation. In addition, in certain embodiments, the data may be processed and evaluated to recommend adjustment of operational parameters to minimize fluid losses to the formation (e.g., in order to minimize damage to the formation), which may be executed manually by the operators, or to be executed automatically without human intervention by the control system.

[0021] In example embodiments, the collected data may be evaluated by the supervisory control system 100 to monitor mud motor performance. For example, motor wear may be detected by monitoring the effective torque of the downhole motor based on data obtained regarding pump rates, pressure differentials, and actual torque measurements of the BHA. Various algorithms may be used by the supervisory control system 100 to predict or guide an operator to predict, for example, how many more hours the downhole motor may be run efficiently. Such predictions may be used to make automatic decisions or to provide indications to an operator when to trip the coiled tubing string to replace the motor.

[0022] In example embodiments, the collected data may be evaluated by the supervisory control system 100 to predict a condition where the coiled tubing string 30 may become stuck. The ability to predict such events may help prevent unnecessary short trips and, thus, improve tubing longevity. In certain embodiments, downhole parameters such as weight on bit, torque, and pressure differentials in combination with surface parameters such as coiled tubing weight and speed, pump rate, and circulating pressure may be evaluated to provide predictions or warnings that the coiled tubing may become stuck. Based on such predictions and / or past experience recorded in a storage system, the supervisory control system 100 may automatically execute certain operational sequences, such as changing injector speed profile, changing pump rates, changing the toolface of the BHA, etc., to mitigate the probability of the coiled tubing becoming. Evaluating the sensor data may further enable the supervisory control system 100 to detect other undesirable events, such as bridge, coiled tubing runaway, etc. and to command relevant equipment to react automatically to prevent operational failures.

[0023] FIG. 4 depicts a block diagram of another example supervisory control system 200 (also referred herein to as a coil tubing advisor). Supervisory control system 200 may be used for advising a coiled tubing wellbore operation such as an underbalanced coiled tubing drilling operation including drilling and non-drilling activities within the operation. Example drilling activities may include drilling substantially any portion of a wellbore including build sections, horizontal sections, or a side track. Example non-drilling activities may include trips (in or out of the well), circulations, and wiper trips. As described above with respect to FIG. 3, system 200 may include a processing engine 210 (e.g., including one or more processors or computer systems as well as corresponding software applications). The processing engine 210 may be configured to receive the various inputs, for example, including inputs regarding the coiled tubing configuration 220, the coiled tubing operational parameters 230, and downhole and surface sensor measurements 250, 260.

[0024] The coiled tubing configuration inputs 220 may include, for example, the drilling fluid type (such as oil-based versus water-based fluid type as well as other specific parameters related to the fluid such as the density, the viscosity, the solids content, and the composition), the wellbore diameter, depth and survey, the presence or absence of a completion string (and the diameter and configuration of the completion string if present), the drill bit type, the mud motor configuration, the BHA and steering tool configuration, and / or the coiled tubing string diameter, weight, and grade. The coiled tubing operational parameters 230 may include the operational state of the coiled tubing string (e.g., drilling straight ahead, drilling a build or a turn, sidetracking, tripping in or out, performing a wiper trip, etc.), the ROP while drilling, weight on bit, torque on bit, coiled tubing weight, outer dimension, and ovality, pump pressure, nitrogen pump pressure, downhole and surface temperatures, downhole pressure including annular pressure, internal pressure, and differential pressure across the BHA, wellhead pressure, casing annulus pressure, injector head traction cylinder pressure, pump rate, return flow rates such as produced gas rate, produced oil rate, and produced water rate, choke positions, pressure at the separator inlet, wellbore trajectory azimuth, wellbore trajectory inclination, the nitrogen flow rate, and etc. The downhole and surface sensor measurements 250, 260 may include substantially any suitable sensor measurements, for example, including those described above with respect to FIG. 3.

[0025] With continued reference to FIG. 4, the processing engine 210 may be configured to evaluate the inputs regarding the coiled tubing configuration 220, the coiled tubing operational parameters 230, and downhole and surface sensor measurements 250, 260 and to provide operational advisories 270 (e.g., multiple advisories through the operation). For example, the processing engine 210 may be configured to model (or make use of a model to estimate) one or more parameters including the mud motor performance, hole cleaning performance, and / or the downhole pressure based on the above described inputs 220, 230, 250, 260. The processing engine may be further configured to compare the modeled parameters with corresponding thresholds or envelopes to ensure that the modeled parameters are within predetermined operational windows. The processing engine may be still further configured to detect operational anomalies and diagnose drilling problems during the coiled tubing drilling operation.

[0026] The operational advisories 270 may include operator instructions regarding the coiled tubing operational parameters 230 and may be made to one or more of the subsystems 170, 180, and / or 190 described above with respect to FIG. 2. For example, when the model parameters are within the corresponding thresholds or envelopes, the operational advisories may advise that the operational parameters remain unchanged. When the model parameters are outside the corresponding thresholds or envelopes (outside the predetermined operational window), the operational advisories may provide guidance or advice regarding desirable or necessary changes to the operational parameters of any one of the subsystems. For example, when the processing engine determines that hole cleaning is substandard (outside the predetermined operational window), the operational advisories may suggest a change in the operational state (e.g., initiating a wiper trip), a change in the drilling fluid flow rate, or a change in the drilling fluid composition. When the processing engine determines that there is an operational anomaly, such as a failed tool, the operational advisories may suggest a trip to change the tool or a procedure to remedy the anomaly.

[0027] As further indicated at 280, a separate nitrogen advisory may also optionally be issued, for example, indicating a change to the nitrogen flow rate. In another example, when the processing engine determines that the downhole pressure is out of specification, the operational advisories may suggest a change to one or more of the drilling fluid flow rate, the nitrogen flow rate, or various choke settings. In still another example, when the processing engine determines that the motor performance is out of specification, the operational advisories may suggest a change in the operational state (e.g., initiating a tripping operation to replace the motor) or a change to one or more of the drilling fluid flow rate and the nitrogen flow rate.

[0028] With continued reference to FIG. 4, it will be appreciated that in example embodiments, the operational advisories 270 may be intended to aid coiled tubing drilling operators. For example, the operational advisories 270 may be intended to maintain the coiled tubing drilling operation within compliance of standard operating procedures, processes, and best practices and to provide actionable recommendations to address various drilling contingencies, operational anomalies, and problems that may arise during the operation. The operational advisories may therefore improve operational efficiency and service quality (e.g., via a reduction in non-production time). Moreover, the system 200 may advantageously improve consistency from one operation to the next or across a fleet of coiled tubing drilling operations.

[0029] Turning now to FIG. 5, a flow chart of one example method 300 for supervising a coiled tubing wellbore (e.g., drilling) operation is depicted. The method 300 may include inputting a coiled tubing drilling configuration into a coiled tubing supervisory control system at 302 (e.g., including the coiled tubing configuration inputs 220 described above with respect to FIG. 4). Coiled tubing drilling operational parameters may be input into the supervisory control system at 304 (e.g., including the coiled tubing operational parameters 230 described above with respect to FIG. 4). Downhole and surface sensor measurements may be received by the supervisory control system at 306 during the operation. The coiled tubing drilling configuration, the coiled tubing drilling operational parameters, and the sensor data may be evaluated at 308 to generate one or more coiled tubing drilling advisories (e.g., one or more advisories to update or change coiled tubing drilling operational parameters). In example embodiments, generating the advisories at 308 may further include automatically adjusting or changing one or more of the operational parameters in response to the evaluation. It will be appreciated that method steps 304, 306, and 308 may be repeated substantially any number of times as the coiled tubing drilling operation progresses (e.g., at some time interval as updated sensor measurements are received) as depicted at 310.

[0030] In example embodiments, method 300 may be advantageously configured to provide pressure advisories at 308 for an underbalanced or managed pressure coiled tubing drilling operation. In such embodiments, the advisories are intended to guide operators in maintaining proper bottom hole pressure within the constraints of the surface system (e.g., via the choke manifold 74 and the pressure unit 80). The advisories at 308 may further guide the operators in optimal nitrogen usage. In other example embodiments, method 300 may advantageously be configured to provide a hole cleaning advisory or motor performance advisories at 308 for a slide drilling coiled tubing drilling operation. In such embodiments, the advisories are intended to guide operators in maintaining compliant hole cleaning and motor performance processes and may provide guidance (advice) related an upcoming wiper trips, drilling fluid flow rate, drilling fluid composition, and other operational parameters.

[0031] Moreover, as described in more detail below, the advisories may guide the operators to adhere to established processes and procedures (e.g., standard operating procedures) related to a desired tripping speed profile (tripping in and tripping out). The speed profile may take into account the presence or absence of a completion casing, jewelry, and tagging at the stripper. The advisories may further guide operators regarding pull test procedures, sidetracking or milled window procedures, as well as wiper trip procedures.

[0032] In still other embodiments, the advisories may be intended to alert operators about operational anomalies (such as a stuck event, a motor stall, a kick or potential kick, a bridge, or various equipment or sensor failures). The advisories may be further configured to guide operators in addressing and / or mitigating such anomalies. Such advisories may advantageously be generated automatically.

[0033] In example embodiments, the system 200 may receive a drilling plan (e.g., from a digital drilling program or from a drilling operator) and method 300 may provide detailed advisories enabling the operator to follow the drilling plan. In particular, the method 300 may provide advisories at various drilling phases enabling the operators to remain compliant with standard operating procedures. For example, the advisories may be intended to enable the operators to follow the drilling plan, such as within the build section, and to provide appropriate steering guidance, pressure maintenance guidance (to maintain underbalanced pressure conditions), hole cleaning guidance, shock and vibration guidance, and tubing injection guidance, as well as guidance related to the service life of various downhole components including the drill bit and the mud motor. Moreover, method 300 may be further configured to provide advisories related to sidetracking operations, window milling operations, shoe milling operations, and drilling off operations required to achieve the drilling plan. Method 300 may be still further configured to identify potential operational risks and advise the operators to respond appropriately.

[0034] FIG. 6 depicts a flow chart of another example method 320 for supervising a coiled tubing wellbore (e.g., drilling) operation. Method 320 is similar to method 300 in that it includes inputting the coiled tubing drilling configuration into a supervisory control system at 322, inputting operational parameters into the supervisory control system at 324, and receiving downhole and surface sensor measurements via the supervisory control system at 326. Expected values or indicators of various coiled tubing drilling parameters may be estimated (e.g., via a coiled tubing drilling model) at 328. These parameters may include, for example, a bottom hole pressure or other underbalanced drilling indicator, a solid transport / hole cleaning indicator such as a downhole drilling fluid flow rate, and / or a motor performance indicator such as a rotation rate of the drill bit or a pressure drop through the motor.

[0035] The estimated coiled tubing drilling parameters may be compared with corresponding advisory windows (threshold ranges) at 330 to ensure that the coiled drilling operation is operating within specification. When the estimated parameter(s) is / are outside of the corresponding specification ranges (windows), recommended adjustments or increments to the to the coiled tubing drilling operational parameters may be generated at 332. Processing steps 328, 330, and 332 may then be repeated until parameters estimated at 328 are within the corresponding specification ranges.

[0036] When each of the estimated parameter(s) is / are within the corresponding specification ranges, the method may evaluate whether or not the nitrogen flow rate (nitrogen usage rate) may be reduced at 334 (it will be appreciated that it is generally desirable to reduce nitrogen gas usage to correspondingly reduce the cost of the coiled tubing drilling operation). For example, the downhole pressure may be compared with the reservoir pressure. In one example embodiment, an estimated downhole pressure less than a threshold value (e.g., less than 70%, 80%, or 90% of the reservoir pressure) may be taken as an indicator that the nitrogen usage can be reduced. In another example, an increase in returned gas rate at the surface (e.g., as a result of entering a gas producing zone) may be an indicator that the nitrogen usage can be reduced. The method returns to 332 when a determination has been made that the nitrogen flow may be reduced.

[0037] When the nitrogen flow rate is determined to be appropriate (or optimum) at 334 (e.g., is not too high or should not be reduced), a coiled tubing drilling parameter advisory may be generated at 336. For example, the advisory may recommend not changing the operational parameters when the coiled drilling operation is initially within specification at 330 and the nitrogen flow rate is determined to be appropriate at 334. Otherwise, the advisory may recommend changing the operational parameters to those determined at 332. In still other example embodiments, the method 320 may further automatically adjust one or more operational parameters using computer controlled actuators (e.g., the choke position or drilling fluid flow rate may be automatically adjusted when appropriate). As indicated at 338, the method steps 326, 328, 330, 332, 334, and 336 may be repeated while drilling operation progresses. It will be appreciated that method steps 328, 330, 332, and 334 are generally processing steps executed by the supervisory control system. From the vantage point of the operator, the method 320 generates repeated operational advisories at 336 throughout the operation to supervise the operators as they control the coiled tubing drilling operation, as well as to alert the operators of any operational anomalies.

[0038] FIG. 7 depicts a flow chart of an example method 350 for supervising a coiled tubing wiper trip operation. In example embodiments, method 350 may be initiated by an operator or may be initiated automatically, for example, at 308 of method 300 (FIG. 5). Method 350 may include detecting an operational state of the coiled tubing string at 352 (e.g., confirming that the drilling apparatus is in a drilling state). The supervisory control system may receive a request to initiate a wiper trip or a pull test at 354. For example, the supervisory control system may receive the request from an operator at the surface or at 308 of method 300 when the advisory recommends changing the state of the coiled tubing apparatus from a drilling state to a wiper trip. A drill off procedure may be initiated at 356, for example, by comparing the measured WOB with a threshold. If the measured WOB is greater than the threshold the method may advise the operators to wait a predetermined time at 358 before initiating the wiper trip. The method may further advise (and / or automatically initiate) the drilling operator to start the wiper trip at 360 when the weight on bit is less than the threshold.

[0039] FIG. 8 depicts a flowchart of an example method 370 for supervising a coiled tubing tripping operation. The depicted flow chart illustrates example advisories that may be generated for an example tripping operation. As described previously, method 370 may be initiated by an operator or may be initiated automatically, for example, at 308 of method 300 (FIG. 5). Method 370 may include setting or receiving completion information at 372. The completion information may include, for example, tubing identification and size, casing identification and depth, and well jewelry (e.g., nipples, mandrels, etc.) identification and depth. A tripping goal, for example, a measured depth or total vertical depth, and a standard operating procedure for tripping, such as a tripping speed profile (coiled tubing tripping speed versus depth), pump rate, pull test, BHA functional test, and toolface orientation versus depth may be received at 374. The tripping operation may then commence at 376. Downhole and surface sensor data may be received at 378, for example, as described above at 326 with respect to FIG. 6. When the tripping operation commences, the supervisory control system monitors the depth and speed of the coiled tubing, the flow rate, the pull test and toolface angle, and advises the operator to modify these parameters such that the established operation procedure is followed during the whole tripping operation. For example, the method may evaluate the tripping speed at 380 and issue a corresponding advisory at 381, a fluid flow rate at 382 and issue a corresponding advisory at 383, pull test and BHA function tests at 384, 386 and issue corresponding advisories at 385, 387, and toolface compliance at 388 and issue a corresponding advisory at 389. The status of the tripping operation may then be evaluated with respect to the initial tripping goal at 390 and the method may continue as indicated at 392 until the tripping goal has been achieved. It will be appreciated that the disclosed embodiments are not limited to particular advisories depicted in FIG. 8.

[0040] FIG. 9 depicts a flowchart of an example method 400 for supervising a coiled tubing sidetracking operation. The supervisory control system may receive a request to initiate a sidetracking operation at 402. For example, the supervisory control system may receive the request from an operator at the surface. In another example embodiment, the supervisory control system may receive the request at 308 of method 300 (FIG. 5), for example, for example, when the measured depth equals a target depth for the sidetracking operation (e.g., during a drip in or trip out). The operator may then be advised to perform a depth correlation at 404.

[0041] The sidetracking operation may be initiated at 406 and further advisories may be optionally given to set the toolface angle, the coiled tubing speed, the weight on bit, and the drilling fluid flow rate / motor speed. Further advisories may be generated to move the coiled tubing up and down to promote sidetracking. It will be appreciated, that sidetracking drilling parameters may differ significantly from normal drilling parameters. For example, the drill bit rotation rate, the rate of penetration, and the weight on bit may be different during a sidetracking operation. Moreover, sidetracking may make use of reciprocating (up and down) motion of the coiled tubing string. Sensor data may be received and the sidetracking operation may be evaluated at 408, for example, via monitoring the direction of drilling (e.g., inclination and azimuth) and the total depth or coiled tubing advancement of the sidetrack. The measured side track parameters may be compared with standard operating procedures, operational goals, and other operational constraints at 410 and corresponding advisories may be generated to supervise the operators to maintain the sidetracking operation in compliance. The sidetracking objectives may be evaluated at 412 to determine whether or not the operation is complete. The sidetracking operation may continue at 414 until complete with continued monitoring at 408 and continued advisory generation at 410. A final sidetracking advisory may be generated at 416 when the sidetracking operation is completed and normal drilling procedures may optionally be established or advised at 418 (e.g., according to the predefined well plan).

[0042] It will be understood that the present disclosure includes numerous embodiments. These embodiments include, but are not limited to, the following embodiments.

[0043] In a first embodiment, a method for advising a coiled tubing wellbore operation comprises , inputting a coiled tubing drilling configuration into a supervisory control system; inputting coiled tubing drilling operational parameters into the supervisory control system; receiving downhole and surface sensor measurements in the supervisory control system, the sensor measurements made during the coiled tubing wellbore operation; and evaluating the sensor measurements with the supervisory control system to generate coiled tubing drilling advisories, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel that provide supervisory oversight of the coiled tubing wellbore operation, the coiled tubing drilling advisories including at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies.

[0044] A second embodiment may include the first embodiment, wherein the instructions are implemented automatically without human intervention.

[0045] A third embodiment may include any one of the first through second embodiments, wherein the coiled tubing drilling advisories comprise supervisory instructions to change at least one of the coiled tubing drilling operational parameters in response to the received downhole and surface sensor measurements.

[0046] A fourth embodiment may include any one of the first through third embodiments, wherein the supervisory instructions comprise instructions to change at least one of the coiled tubing drilling operational parameters in a coiled tubing subsystem, a bottom hole assembly subsystem, or an underbalanced or managed pressure subsystem.

[0047] A fifth embodiment may include any one of the first through fourth embodiments, wherein the supervisory instructions comprise instructions to meet operational targets including at least one of underbalanced or managed pressure drilling targets, hole cleaning targets, and drilling performance targets.

[0048] A sixth embodiment may include any one of the first through fifth embodiments, wherein the supervisory instructions comprise instructions to maintain the coiled tubing wellbore operation within standard operating procedures for at least one of a coiled tubing drilling operation, a wiper trip operation, a sidetracking operation, and a tripping operation.

[0049] A seventh embodiment may include any one of the first through sixth embodiments, wherein the supervisory instructions comprise instructions to address operational anomalies including at least one of a stuck event, a motor stall, a kick, a bridge, and a coiled tubing equipment failure.

[0050] An eighth embodiment may include any one of the first through seventh embodiments, wherein the evaluating further comprises estimating an underbalanced or managed pressure drilling indicator, a hole cleaning indicator, and a motor performance indicator based on the received downhole and surface sensor measurements; and generating the coiled tubing drilling advisory, the generated coiled tubing drilling advisory including supervisory instructions to rig personnel to change at least one of the coiled tubing drilling operational parameters to maintain the under balance drilling indicator, the hole cleaning indicator, and the motor performance indicator within corresponding predetermined operating windows.

[0051] A ninth embodiment may include any one of the first through eighth embodiments, wherein the evaluating further comprises estimating a nitrogen flow rate window for maintaining underbalanced drilling conditions based on the received downhole and surface sensor measurements; comparing a nitrogen flow rate with the estimated nitrogen flow rate window; and generating the coiled tubing drilling advisory, the generated coiled tubing drilling advisory including supervisory instructions to rig personnel to either increase or decrease the nitrogen flow rate when the nitrogen flow rate is outside of the estimated nitrogen flow rate window.

[0052] A tenth embodiment may include any one of the first through ninth embodiments, wherein the generated coiled tubing drilling advisory includes instructions to the personnel to initiate a wiper trip or a tripping operation.

[0053] In an eleventh embodiment a coiled tubing drilling supervisory control system comprises a processor in electronic communication with downhole sensors and surface sensors; the processor configured to: receive an input coiled tubing drilling configuration; receive input coiled tubing drilling operational parameters; receive sensor measurements from the downhole sensors and the surface sensors during a coiled tubing wellbore operation; and evaluate the sensor measurements to generate a coiled tubing drilling advisory, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel that provide supervisory oversight of the coiled tubing wellbore operation, the coiled tubing drilling advisories including at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies.

[0054] A twelfth embodiment may include the eleventh embodiment, wherein the supervisory control system is configured to implement the supervisory instructions automatically without human intervention.

[0055] A thirteenth embodiment may include any one of the eleventh through twelfth embodiments, wherein the supervisory instructions comprise instructions to meet operational targets including at least one of underbalanced or managed pressure drilling targets, hole cleaning targets, and drilling performance targets.

[0056] A fourteenth embodiment may include any one of the eleventh through thirteenth embodiments, wherein the supervisory instructions comprise instructions to maintain the coiled tubing wellbore operation within standard operating procedures for at least one of a coiled tubing drilling operation, a wiper trip operation, a sidetracking operation, and a tripping operation.

[0057] A fifteenth embodiments may include any one of the eleventh through fourteenth embodiments, wherein the supervisory instructions comprise instructions to address operational anomalies including at least one of a stuck event, a motor stall, a kick, a bridge, and a coiled tubing equipment failure.

[0058] In a sixteenth embodiment a method for advising a coiled tubing wellbore operation comprises inputting a coiled tubing drilling configuration into a supervisory control system; inputting coiled tubing drilling operational parameters into the supervisory control system; receiving downhole and surface sensor measurements in the supervisory control system, the downhole and surface sensor measurements received from sensors deployed in a coiled tubing subsystem, a bottom hole assembly subsystem, and an underbalanced or managed pressure subsystem; estimating an underbalanced or managed pressure drilling indicator, a hole cleaning indicator, and a motor performance indicator based on the received downhole and surface sensor measurements; and evaluating the estimated underbalanced or managed pressure drilling indicator, the estimated hole cleaning indicator, and the estimated motor performance indicator to generate coiled tubing drilling advisories, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel to change at least one of the coiled tubing drilling operational parameters in the coiled tubing subsystem, the bottom hole assembly subsystem, and the underbalanced or managed pressure subsystem to maintain the under balance drilling indicator, the hole cleaning indicator, and the motor performance indicator within corresponding predetermined operating windows.

[0059] A seventeenth embodiment may include the sixteenth embodiment, wherein the supervisory instructions further comprise instructions to maintain the coiled tubing wellbore operation within standard operating procedures for at least one of a coiled tubing drilling operation, a wiper trip operation, a sidetracking operation, and a tripping operation.

[0060] An eighteenth embodiment may include any one of the sixteenth through seventeenth embodiments, wherein the supervisory instructions further comprise instructions to address operational anomalies including at least one of a stuck event, a motor stall, a kick, a bridge, and a coiled tubing equipment failure.

[0061] A nineteenth embodiment may include any one of the sixteenth through eighteenth embodiments, further comprising estimating a nitrogen flow rate window for maintaining the underbalanced drilling conditions based on the received downhole and surface sensor measurements; comparing a nitrogen flow rate with the estimated nitrogen flow rate window; and generating a nitrogen advisory including instructions to personnel to either increase or decrease the nitrogen flow rate when the nitrogen flow rate is outside of the desired nitrogen flow rate window.

[0062] A twentieth embodiment may include the nineteenth embodiment, wherein the generated nitrogen advisory comprises supervisory instructions to rig personnel to adjust the at least one of the coiled tubing drilling operational parameters to enable the nitrogen flow rate to be reduced.

[0063] Although a coiled tubing drilling advisor and certain advantages thereof have been described in detail, it should be understood that various changes, substitutions and alterations may be made herein without departing from the spirit and scope of the disclosure.

Claims

1. A method for advising a coiled tubing wellbore operation, the method comprising: inputting a coiled tubing drilling configuration into a supervisory control system; inputting coiled tubing drilling operational parameters into the supervisory control system; receiving downhole and surface sensor measurements in the supervisory control system, the sensor measurements made during the coiled tubing wellbore operation; and evaluating the sensor measurements with the supervisory control system to generate coiled tubing drilling advisories, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel that provide supervisory oversight of the coiled tubing wellbore operation, the coiled tubing drilling advisories including at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies.

2. The method of claim 1, wherein the instructions are implemented automatically without human intervention.

3. The method of claim 1 or 2, wherein the supervisory instructions comprise instructions to change at least one of the coiled tubing drilling operational parameters in a coiled tubing subsystem, a bottom hole assembly subsystem, or an underbalanced or managed pressure subsystem.

4. The method of any one of the preceding claims, wherein the evaluating further comprises: estimating an underbalanced or managed pressure drilling indicator, a hole cleaning indicator, and a motor performance indicator based on the received downhole and surface sensor measurements; and generating the coiled tubing drilling advisory, the generated coiled tubing drilling advisory including supervisory instructions to rig personnel to change at least one of the coiled tubing drilling operational parameters to maintain the under balance drilling indicator, the hole cleaning indicator, and the motor performance indicator within corresponding predetermined operating windows.

5. A coiled tubing drilling supervisory control system comprising: a processor in electronic communication with downhole sensors and surface sensors; the processor configured to: receive an input coiled tubing drilling configuration; receive input coiled tubing drilling operational parameters; receive sensor measurements from the downhole sensors and the surface sensors during a coiled tubing wellbore operation; and evaluate the sensor measurements to generate a coiled tubing drilling advisory, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel that provide supervisory oversight of the coiled tubing wellbore operation, the coiled tubing drilling advisories including at least one of instructions to meet operational targets, instructions to maintain the coiled tubing wellbore operation within standard operating procedures, and instructions to address operational anomalies.

6. The supervisory control system of claim 5, wherein the supervisory instructions comprise instructions to meet operational targets including at least one of underbalanced or managed pressure drilling targets, hole cleaning targets, and drilling performance targets.

7. A method for advising a coiled tubing wellbore operation, the method comprising: inputting a coiled tubing drilling configuration into a supervisory control system; inputting coiled tubing drilling operational parameters into the supervisory control system; receiving downhole and surface sensor measurements in the supervisory control system, the downhole and surface sensor measurements received from sensors deployed in a coiled tubing subsystem, a bottom hole assembly subsystem, and an underbalanced or managed pressure subsystem; estimating an underbalanced or managed pressure drilling indicator, a hole cleaning indicator, and a motor performance indicator based on the received downhole and surface sensor measurements; and evaluating the estimated underbalanced or managed pressure drilling indicator, the estimated hole cleaning indicator, and the estimated motor performance indicator to generate coiled tubing drilling advisories, the generated coiled tubing drilling advisories including supervisory instructions to rig personnel to change at least one of the coiled tubing drilling operational parameters in the coiled tubing subsystem, the bottom hole assembly subsystem, and the underbalanced or managed pressure subsystem to maintain the under balance drilling indicator, the hole cleaning indicator, and the motor performance indicator within corresponding predetermined operating windows.

8. The method of claim 7, wherein the supervisory instructions further comprise instructions to initiate and maintain the coiled tubing wellbore operation within standard operating procedures for at least one of a coiled tubing drilling operation, a wiper trip operation, a sidetracking operation, and a tripping operation.

9. The method of claim 7 or 8, wherein the supervisory instructions further comprise instructions to address operational anomalies including at least one of a stuck event, a motor stall, a kick, a bridge, and a coiled tubing equipment failure.

10. The method of any one of the claims 7 - 9, further comprising: estimating a nitrogen flow rate window for maintaining the underbalanced drilling conditions based on the received downhole and surface sensor measurements; comparing a nitrogen flow rate with the estimated nitrogen flow rate window; and generating a nitrogen advisory including instructions to personnel to either increase or decrease the nitrogen flow rate when the nitrogen flow rate is outside of the desired nitrogen flow rate window, wherein the generated nitrogen advisory comprises supervisory instructions to rig personnel to adjust the at least one of the coiled tubing drilling operational parameters to enable the nitrogen flow rate to be reduced.

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