Patent Application
20230304359
The present disclosure provides systems and methods useful for drilling a well, such as an oil and gas well. The systems and methods can be computer-implemented using processor executable instructions for execution on a processor and can accordingly be executed with a programmed computer system.
Drilling a borehole for the extraction of minerals has become an increasingly complicated operation due to the increased depth and complexity of many boreholes, including the complexity added by directional drilling. Drilling is an expensive operation and errors in drilling add to the cost and, in some cases, drilling errors may permanently lower the output of a well for years into the future. Conventional technologies and methods may not adequately address the complicated nature of drilling and may not be capable of gathering and processing various information from downhole sensors and surface control systems in a timely manner, in order to improve drilling operations and minimize drilling errors.
In the oil and gas industry, extraction of hydrocarbon natural resources is done by physically drilling a hole to a reservoir where the hydrocarbon natural resources are trapped. The hydrocarbon natural resources can be up to 10,000 feet or more below the ground surface and be buried under various layers of geological formations. Drilling operations can be conducted by having a rotating drill bit mounted on a bottom hole assembly (BHA) that gives direction to the drill bit for cutting through geological formations and enabled steerable drilling.
In an aspect, an apparatus for drilling, can include a propellant chamber configured to store a liquid propellant for drilling; a burner nozzle connected to the propellant chamber via one or more passages to route the liquid propellant from the propellant chamber to the burner nozzle; and an ignitor configured to ignite the liquid propellant as the liquid propellant escapes the burner nozzle.
In various embodiments, the apparatus can include a connector for coupling a propellant feed hose.
In various embodiments, the burner nozzle is encased in a drill pipe to create a path for a drilling fluid that bypasses the burner nozzle and feeds fluid down an inside passage and up an outside passage of the drill pipe.
In various embodiments, the apparatus can include a diverter cage placed in a path of the inside passage to divert one or more propellant capsules from the inside passage to a capsule blade; the capsule blade configured to puncture the one or more propellant capsules; and a reservoir configured to capture the propellant from the one or more propellant capsules and route the fuel to the propellant chamber.
In various embodiments, the apparatus can include a diverter configured to route one or more pierced capsules to the outside passage of the large internal diameter drill pipe.
In various embodiments, the apparatus can include a burner nozzle monitor configured to detect a condition of the burner nozzle; and a compressed gas cylinder coupled to the drill pipe, the compressed gas cylinder configured to release the compressed gas into a chamber to cause the apparatus to float to a surface of a borehole.
In various embodiments, the diverter cage comprises a mesh size smaller than a diameter of the one or more propellant capsules.
In various embodiments, wherein the burner nozzle comprises a high temperature, high abrasion ceramic.
In an aspect of the disclosure a bottom hole assembly for drilling a borehole can include a propellant chamber configured to store a liquid propellant for drilling; a burner nozzle connected to the propellant chamber via one or more passages to route the liquid fuel from the propellant chamber to the burner nozzle; and an ignitor configured to ignite the liquid fuel as the propellant escapes the burner nozzle.
In various embodiments, the bottom hole assembly can include a connector for coupling a propellant feed house. In various embodiments, the burner nozzle is encased in a large internal diameter drill pipe to create a path for a drilling fluid that bypasses the burner nozzle and feeds fluid down an inside passage and up an outside passage of the large internal diameter drill pipe.
In various embodiments, the bottom hole assembly or other components of the drill string can include a diverter cage placed in a path of the inside passage to divert one or more propellant capsules from the inside passage to a capsule blade; the capsule blade configured to puncture the one or more propellant capsules; and a reservoir configured to capture the propellant from the one or more propellant capsules and route the fuel to the propellant chamber. In other embodiments, a diverter system may be used which directs the fuel capsules to a centrally located blade or blades which pierce or cut an outer layer of the capsule and release the fuel into the fuel feed house.
In various embodiments, the bottom hole assembly can include a diverter configured to route one or more pierced capsules to the outside passage of the large internal diameter drill pipe.
In various embodiments, the bottom hole assembly can include a burner nozzle monitor configured to detect a condition of the burner nozzle; and a compressed gas cylinder coupled to the large internal diameter pipe, the compressed gas cylinder configured to release the compressed gas into a chamber to cause the apparatus to float to a surface of a borehole.
In various embodiments, the diverter cage comprises a mesh size smaller than a diameter of the one or more propellant capsules.
In various embodiments, the burner nozzle comprises a high temperature, high abrasion ceramic.
In various aspects, a method for drilling a borehole using a bitless drill assembly can include storing a liquid propellant in a propellant chamber; routing the liquid propellant from the propellant chamber to a burner nozzle via one or more passages; igniting the liquid propellant at the burner nozzle; and drilling a formation using the liquid propellant.
In various embodiments, the method can include receiving additional liquid propellant to the propellant chamber visa a coupling for a fuel hose, which can be located within the drill string and coupled to a tool for combustion and bitless drilling that is located at least partially if not wholly within the bottom hole assembly. In some embodiments, a fuel hose can be disposed within a drill string and connected to a tool located within a bottom hole assembly.
In various embodiments, the method can include diverting one or more fuel capsules from an inside passage of a pipe encasing the bitless drill assembly; piercing the one or more fuel capsules using a capsule blade; and capturing the propellant from the one or more fuel capsules. In some embodiments, the fuel capsules may comprise an outer layer which has a first density that is lower than the density of the fuel, so that the outer layer can be carried back to or rise to the surface through the drilling fluid, while the fuel within the capsule sinks within the drilling mud and is collected for use.
In various embodiments, the method can include routing the one or more fuel capsule outer layers from the capsule blade to a surface via an outside passage of the pipe encasing the bitless drill assembly.
In still other embodiments, the systems may include the use of a sub coupled to the respective ends of pipe that are joined together with the sub, wherein each piece of the drill pipe comprises a thin tube which extends longitudinally through the pipe and into the sub, wherein the tube opens into an interior chamber of the sub which is isolated from the drilling mud by two seals, wherein the sub allows the flow of drilling mud from one drill pipe through a portion of the sub to the next drill pipe connected that are connected together by the sub.
For a more complete understanding of the present invention and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:
Like reference symbols in the various drawings indicate like elements, in accordance with certain example implementations. In addition, multiple instances of an element may be indicated by following a first number for the element with a letter or a hyphen and a second number.
In the following description, details are set forth by way of example to facilitate discussion of the disclosed subject matter. It is noted, however, that the disclosed embodiments are exemplary and not exhaustive of all possible embodiments.
Throughout this disclosure, a hyphenated form of a reference numeral refers to a specific instance of an element and the un-hyphenated form of the reference numeral refers to the element generically or collectively. Thus, as an example (not shown in the drawings), device “12-1” refers to an instance of a device class, which may be referred to collectively as devices “12” and any one of which may be referred to generically as a device “12”. In the figures and the description, like numerals are intended to represent like elements.
Drilling a well typically involves a substantial amount of human decision-making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and the available information to make decisions on how to plan the drilling operation, how to accomplish the drilling plan, and how to handle issues that arise during drilling. However, even the best geologists and drilling engineers perform some guesswork due to the unique nature of each borehole. Furthermore, a directional human driller performing the drilling may have drilled other boreholes in the same region and so may have some similar experience. However, during drilling operations, a multitude of input information and other factors may affect a drilling decision being made by a human operator or specialist, such that the amount of information may overwhelm the cognitive ability of the human to properly consider and factor into the drilling decision. Furthermore, the quality or the error involved with the drilling decision may improve with larger amounts of input data being considered, for example, such as formation data from a large number of offset wells. For these reasons, human specialists may be unable to achieve desirable drilling decisions, particularly when such drilling decisions are made under time constraints, such as during drilling operations when continuation of drilling is dependent on the drilling decision and, thus, the entire drilling rig waits idly for the next drilling decision. Furthermore, human decision-making for drilling decisions can result in expensive mistakes because drilling errors can add significant cost to drilling operations. In some cases, drilling errors may permanently lower the output of a well, resulting in substantial long term economic losses due to the lost output of the well.
Therefore, the well plan may be updated based on new stratigraphic information from the wellbore, as it is being drilled. This stratigraphic information can be gained on one hand from measurement while drilling (MWD) and logging while drilling (LWD) sensor data, but could also include other reference well data, such as drilling dynamics data or sensor data giving information, for example, on the hardness of the rock in individual strata layers being drilled through.
Referring now to the drawings, Referring to
In
A mud pump 152 may direct a fluid mixture 153 (e.g., a mud mixture) from a mud pit 154 into drill string 146. Mud pit 154 is shown schematically as a container, but it is noted that various receptacles, tanks, pits, or other containers may be used. Mud 153 may flow from mud pump 152 into a discharge line 156 that is coupled to a rotary hose 158 by a standpipe 160. Rotary hose 158 may then be coupled to top drive 140, which includes a passage for mud 153 to flow into borehole 106 via drill string 146 from where mud 153 may emerge at drill bit 148. Mud 153 may lubricate drill bit 148 during drilling and, due to the pressure supplied by mud pump 152, mud 153 may return via borehole 106 to surface 104.
In drilling system 100, drilling equipment (see also
Sensing, detection, measurement, evaluation, storage, alarm, and other functionality may be incorporated into a downhole tool 166 or BHA 149 or elsewhere along drill string 146 to provide downhole surveys of borehole 106. Accordingly, downhole tool 166 may be an MWD tool or a LWD tool or both, and may accordingly utilize connectivity to the surface 104, local storage, or both. In different implementations, gamma radiation sensors, magnetometers, accelerometers, and other types of sensors may be used for the downhole surveys. Although downhole tool 166 is shown in singular in drilling system 100, it is noted that multiple instances (not shown) of downhole tool 166 may be located at one or more locations along drill string 146.
In some embodiments, formation detection and evaluation functionality may be provided via a steering control system 168 on the surface 104. Steering control system 168 may be located in proximity to derrick 132 or may be included with drilling system 100. In other embodiments, steering control system 168 may be remote from the actual location of borehole 106 (see also
In operation, steering control system 168 may be accessible via a communication network (see also
In particular embodiments, at least a portion of steering control system 168 may be located in downhole tool 166 (not shown). In some embodiments, steering control system 168 may communicate with a separate controller (not shown) located in downhole tool 166. In particular, steering control system 168 may receive and process measurements received from downhole surveys and may perform the calculations described herein for surface steering using the downhole surveys and other information referenced herein.
In drilling system 100, to aid in the drilling process, data is collected from borehole 106, such as from sensors in BHA 149, downhole tool 166, or both. The collected data may include the geological characteristics of formation 102 in which borehole 106 was formed, the attributes of drilling system 100, including BHA 149, and drilling information such as weight-on-bit (WOB), drilling speed, and other information pertinent to the formation of borehole 106. The drilling information may be associated with a particular depth or another identifiable marker to index collected data. For example, the collected data for borehole 106 may capture drilling information indicating that drilling of the well from 1,000 feet to 1,200 feet occurred at a first rate of penetration (ROP) through a first rock layer with a first WOB, while drilling from 1,200 feet to 1,500 feet occurred at a second ROP through a second rock layer with a second WOB (see also
The collected data may be stored in a database that is accessible via a communication network for example. In some embodiments, the database storing the collected data for borehole 106 may be located locally at drilling system 100, at a drilling hub that supports a plurality of drilling systems 100 in a region, or at a database server accessible over the communication network that provides access to the database (see also
In
Steering control system 168 may further be used as a surface steerable system, along with the database, as described above. The surface steerable system may enable an operator to plan and control drilling operations while drilling is being performed. The surface steerable system may itself also be used to perform certain drilling operations, such as controlling certain control systems that, in turn, control the actual equipment in drilling system 100 (see also
Manual control may involve direct control of the drilling rig equipment, albeit with certain safety limits to prevent unsafe or undesired actions or collisions of different equipment. To enable manual-assisted control, steering control system 168 may present various information, such as using a graphical user interface (GUI) displayed on a display device (see
To implement semi-automatic control, steering control system 168 may itself propose or indicate to the user, such as via the GUI, that a certain control operation, or a sequence of control operations, should be performed at a given time. Then, steering control system 168 may enable the user to imitate the indicated control operation or sequence of control operations, such that once manually started, the indicated control operation or sequence of control operations is automatically completed. The limits and safety features mentioned above for manual control would still apply for semi-automatic control. It is noted that steering control system 168 may execute semi-automatic control using a secondary processor, such as an embedded controller that executes under a real-time operating system (RTOS), that is under the control and command of steering control system 168. To implement automatic control, the step of manual starting the indicated control operation or sequence of operations is eliminated, and steering control system 168 may proceed with a passive notification to the user of the actions taken.
In order to implement various control operations, steering control system 168 may perform (or may cause to be performed) various input operations, processing operations, and output operations. The input operations performed by steering control system 168 may result in measurements or other input information being made available for use in any subsequent operations, such as processing or output operations. The input operations may accordingly provide the input information, including feedback from the drilling process itself, to steering control system 168. The processing operations performed by steering control system 168 may be any processing operation associated with surface steering, as disclosed herein. The output operations performed by steering control system 168 may involve generating output information for use by external entities, or for output to a user, such as in the form of updated elements in the GUI, for example. The output information may include at least some of the input information, enabling steering control system 168 to distribute information among various entities and processors.
In particular, the operations performed by steering control system 168 may include operations such as receiving drilling data representing a drill path, receiving other drilling parameters, calculating a drilling solution for the drill path based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and calculating corrections for the drilling process if the drilling process is outside of the margin of error.
Accordingly, steering control system 168 may receive input information either before drilling, during drilling, or after drilling of borehole 106. The input information may comprise measurements from one or more sensors, as well as survey information collected while drilling borehole 106. The input information may also include a well plan, a regional formation history, drilling engineer parameters, downhole tool face/inclination information, downhole tool gamma/resistivity information, economic parameters, reliability parameters, among various other parameters. Some of the input information, such as the regional formation history, may be available from a drilling hub 410, which may have respective access to a regional drilling database (DB) 412 (see
As noted, the input information may be provided to steering control system 168. After processing by steering control system 168, steering control system 168 may generate control information that may be output to drilling rig 210 (e.g., to rig controls 520 that control drilling equipment 530, see also
Referring now to
In drilling environment 200, it may be assumed that a drilling plan (also referred to as a well plan) has been formulated to drill borehole 106 extending into the ground to a true vertical depth (TVD) 266 and penetrating several subterranean strata layers. Borehole 106 is shown in
Also visible in
Current drilling operations frequently include directional drilling to reach a target, such as target area 280. The use of directional drilling has been found to generally increase an overall amount of production volume per well, but also may lead to significantly higher production rates per well, which are both economically desirable. As shown in
Referring now to
The build rate used for any given build up section may depend on various factors, such as properties of the formation (i.e., strata layers) through which borehole 106 is to be drilled, the trajectory of borehole 106, the particular pipe and drill collars/BHA components used (e.g., length, diameter, flexibility, strength, mud motor bend setting, and drill bit), the mud type and flow rate, the specified horizontal displacement, stabilization, and inclination angle, among other factors. An overly aggressive built rate can cause problems such as severe doglegs (e.g., sharp changes in direction in the borehole) that may make it difficult or impossible to run casing or perform other operations in borehole 106. Depending on the severity of any mistakes made during directional drilling, borehole 106 may be enlarged or drill bit 146 may be backed out of a portion of borehole 106 and re-drilled along a different path. Such mistakes may be undesirable due to the additional time and expense involved. However, if the built rate is too cautious, additional overall time may be added to the drilling process because directional drilling generally involves a lower ROP than straight drilling. Furthermore, directional drilling for a curve is more complicated than vertical drilling and the possibility of drilling errors increases with directional drilling (e.g., overshoot and undershoot that may occur while trying to keep drill bit 148 on the planned trajectory).
Two modes of drilling, referred to herein as “rotating” and “sliding,” are commonly used to form borehole 106. Rotating, also called “rotary drilling,” uses top drive 140 or rotary table 162 to rotate drill string 146. Rotating may be used when drilling occurs along a straight trajectory, such as for vertical portion 310 of borehole 106. Sliding, also called “steering” or “directional drilling” as noted above, typically uses a mud motor located downhole at BHA 149. The mud motor may have an adjustable bent housing and is not powered by rotation of drill string 146. Instead, the mud motor uses hydraulic power derived from the pressurized drilling mud that circulates along borehole 106 to and from the surface 104 to directionally drill borehole 106 in buildup section 316.
Thus, sliding is used in order to control the direction of the well trajectory during directional drilling. A method to perform a slide may include the following operations. First, during vertical or straight drilling, the rotation of drill string 146 is stopped. Based on feedback from measuring equipment, such as from downhole tool 166, adjustments may be made to drill string 146, such as using top drive 140 to apply various combinations of torque, WOB, and vibration, among other adjustments. The adjustments may continue until a tool face is confirmed that indicates a direction of the bend of the mud motor is oriented to a direction of a desired deviation (i.e., build rate) of borehole 106. Once the desired orientation of the mud motor is attained, WOB to the drill bit is increased, which causes the drill bit to move in the desired direction of deviation. Once sufficient distance and angle have been built up in the curved trajectory, a transition back to rotating mode can be accomplished by rotating drill string 146 again. The rotation of drill string 146 after sliding may neutralize the directional deviation caused by the bend in the mud motor due to the continuous rotation around a centerline of borehole 106.
Referring now to
Specifically, in a region 402-1, a drilling hub 410-1 may serve as a remote processing resource for drilling rigs 210 located in region 402-1, which may vary in number and are not limited to the exemplary schematic illustration of
In
Also shown in
In
In some embodiments, the formulation of a drilling plan for drilling rig 210 may include processing and analyzing the collected data in regional drilling DB 412 to create a more effective drilling plan. Furthermore, once the drilling has begun, the collected data may be used in conjunction with current data from drilling rig 210 to improve drilling decisions. As noted, the functionality of steering control system 168 may be provided at drilling rig 210, or may be provided, at least in part, at a remote processing resource, such as drilling hub 410 or central command 414.
As noted, steering control system 168 may provide functionality as a surface steerable system for controlling drilling rig 210. Steering control system 168 may have access to regional drilling DB 412 and central drilling DB 416 to provide the surface steerable system functionality. As will be described in greater detail below, steering control system 168 may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. Steering control system 168 may be used to perform operations such as receiving drilling data representing a drill trajectory and other drilling parameters, calculating a drilling solution for the drill trajectory based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at drilling rig 210, monitoring the drilling process to gauge whether the drilling process is within a margin of error that is defined for the drill trajectory, or calculating corrections for the drilling process if the drilling process is outside of the margin of error.
Referring now to
Steering control system 168 represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in
In rig control systems 500 of
In rig control systems 500, autodriller 510 may represent an automated rotary drilling system and may be used for controlling rotary drilling. Accordingly, autodriller 510 may enable automate operation of rig controls 520 during rotary drilling, as indicated in the well plan. Bit guidance 512 may represent an automated control system to monitor and control performance and operation drilling bit 148.
In rig control systems 500, autoslide 514 may represent an automated slide drilling system and may be used for controlling slide drilling. Accordingly, autoslide 514 may enable automate operation of rig controls 520 during a slide and may return control to steering control system 168 for rotary drilling at an appropriate time, as indicated in the well plan. In particular implementations, autoslide 514 may be enabled to provide a user interface during slide drilling to specifically monitor and control the slide. For example, autoslide 514 may rely on bit guidance 512 for orienting a tool face and on autodriller 510 to set WOB or control rotation or vibration of drill string 146.
Steering control process 700 in
It is noted that in some implementations, at least certain portions of steering control process 700 may be automated or performed without user intervention, such as using rig control systems 700 (see
Referring to
As shown in
In
In
In
In user interface 850, circular chart 886 may also be color coded, with the color coding existing in a band 890 around circular chart 886 or positioned or represented in other ways. The color coding may use colors to indicate activity in a certain direction. For example, the color red may indicate the highest level of activity, while the color blue may indicate the lowest level of activity. Furthermore, the arc range in degrees of a color may indicate the amount of deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red with a relatively broad (e.g., three hundred degrees) arc of blue may indicate that most activity is occurring in a particular tool face orientation with little deviation. As shown in user interface 850, the color blue may extend from approximately 22-337 degrees, the color green may extend from approximately 15-22 degrees and 337-345 degrees, the color yellow may extend a few degrees around the 13 and 345 degree marks, while the color red may extend from approximately 347-10 degrees. Transition colors or shades may be used with, for example, the color orange marking the transition between red and yellow or a light blue marking the transition between blue and green. This color coding may enable user interface 850 to provide an intuitive summary of how narrow the standard deviation is and how much of the energy intensity is being expended in the proper direction. Furthermore, the center of energy may be viewed relative to the target. For example, user interface 850 may clearly show that the target is at 90 degrees, but the center of energy is at 45 degrees.
In user interface 850, other indicators, such as a slide indicator 892, may indicate how much time remains until a slide occurs or how much time remains for a current slide. For example, slide indicator 892 may represent a time, a percentage (e.g., as shown, a current slide may be 56% complete), a distance completed, or a distance remaining. Slide indicator 892 may graphically display information using, for example, a colored bar 893 that increases or decreases with slide progress. In some embodiments, slide indicator 892 may be built into circular chart 886 (e.g., around the outer edge with an increasing/decreasing band), while in other embodiments slide indicator 892 may be a separate indicator such as a meter, a bar, a gauge, or another indicator type. In various implementations, slide indicator 892 may be refreshed by autoslide 514.
In user interface 850, an error indicator 894 may indicate a magnitude and a direction of error. For example, error indicator 894 may indicate that an estimated drill bit position is a certain distance from the planned trajectory, with a location of error indicator 894 around the circular chart 886 representing the heading. For example,
It is noted that user interface 850 may be arranged in many different ways. For example, colors may be used to indicate normal operation, warnings, and problems. In such cases, the numerical indicators may display numbers in one color (e.g., green) for normal operation, may use another color (e.g., yellow) for warnings, and may use yet another color (e.g., red) when a serious problem occurs. The indicators may also flash or otherwise indicate an alert. The gauge indicators may include colors (e.g., green, yellow, and red) to indicate operational conditions and may also indicate the target value (e.g., an ROP of 100 feet/hour). For example, ROP indicator 868 may have a green bar to indicate a normal level of operation (e.g., from 10-300 feet/hour), a yellow bar to indicate a warning level of operation (e.g., from 300-360 feet/hour), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 feet/hour). ROP indicator 868 may also display a marker at 100 feet/hour to indicate the desired target ROP.
Furthermore, the use of numeric indicators, gauges, and similar visual display indicators may be varied based on factors such as the information to be conveyed and the personal preference of the viewer. Accordingly, user interface 850 may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, steering control system 168 may enable a user to customize the user interface 850 as desired, although certain features (e.g., standpipe pressure) may be locked to prevent a user from intentionally or accidentally removing important drilling information from user interface 850. Other features and attributes of user interface 850 may be set by user preference. Accordingly, the level of customization and the information shown by the user interface 850 may be controlled based on who is viewing user interface 850 and their role in the drilling process.
Referring to
In
In
In
In
In
Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the downhole survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by a distance of the sensor point from the drill bit tip (e.g., approximately 50 feet). Such a response lag may introduce inefficiencies in the slide cycles due to over/under correction of the actual trajectory relative to the planned trajectory.
In GCL 900, using slide estimator 908, each tool face update may be algorithmically merged with the average differential pressure of the period between the previous and current tool face readings, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during the period. As an example, the periodic rate may be between 10 and 60 seconds per cycle depending on the tool face update rate of downhole tool 166. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of slide estimator 908 may accordingly be periodically provided to borehole estimator 906 for accumulation of well deviation information, as well to geo modified well planner 904. Some or all of the output of the slide estimator 908 may be output to an operator, such as shown in the user interface 850 of
In
In
In
In
In
In
Other functionality may be provided by GCL 900 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole tool face. Accordingly, GCL 900 may receive information corresponding to the rotational position of the drill pipe on the surface. GCL 900 may use this surface positional information to calculate current and desired tool face orientations. These calculations may then be used to define control parameters for adjusting the top drive 140 to accomplish adjustments to the downhole tool face in order to steer the trajectory of borehole 106.
For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with GCL 900, or other functionality provided by steering control system 168. In GCL 900, a drilling model class may be defined to capture and define the drilling state throughout the drilling process. The drilling model class may include information obtained without delay. The drilling model class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a WOB/differential pressure model, a positional/rotary model, an MSE model, an active well plan, and control limits. The drilling model class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of GCL 900. The drill bit model may represent the current position and state of drill bit 148. The drill bit model may include a three dimensional (3D) position, a drill bit trajectory, BHA information, bit speed, and tool face (e.g., orientation information). The 3D position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination angle and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. The borehole model may include hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for current drilling of borehole 106. The borehole diameters may represent the diameters of borehole 106 as drilled over current drilling. The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents draw works or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active well plan represents the target borehole path and may include an external well plan and a modified well plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum rotations per minute (RPMs) to the defined level. The control output solution may represent the control parameters for drilling rig 210.
Each functional module of GCL 900 may have behavior encapsulated within a respective class definition. During a processing window, the individual functional modules may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the functional modules may be in the sequence of geo modified well planner 904, build rate predictor 902, slide estimator 908, borehole estimator 906, error vector calculator 910, slide planner 914, convergence planner 916, geological drift estimator 912, and tactical solution planner 918. It is noted that other sequences may be used in different implementations.
In
Referring now to
In the embodiment depicted in
Controller 1000, as depicted in
Controller 1000 is shown in
In
The following disclosure explains additional and improved methods and systems for drilling. In particular, the following systems and methods can be useful to drill deeper wells, especially through harder rock formations, faster and more efficiently than with conventional drilling techniques. It should be noted that the following methods may be implemented by a computer system such as any of those described above. For example, the computer system used to monitor, perform and/or control the methods described below may be a part of the steering control system 168, a part of the rig controls system 500, a part of the drilling system 100, included with the controller 1000, or may be a similar or different computer system and may be coupled to one or more of the foregoing systems. The computer system may be located at or near the rig site or may be located at a remote location from the rig site and may be configured to transmit and receive data to and from a rig site while a well is being drilled. Moreover, it should be noted that the computer system and/or the control system for controlling the flow of fuel and/or drilling mud may be located downhole in some situations.
Drilling deep underground can be expensive, often in part due to the trip time needed when a drill bit and/or its cutters wear out. Drilling in harder rock formations further increases the costs of drilling because the bit wears out more easily and more quickly when drilling through harder formations. For example, in drilling a wellbore in a typical deep, granite formation, a drill bit may last for 1,000 feet (ft) of the wellbore measured depth. The trip time typically can be around one hour per thousand feet of drill pipe. Thus, drilling through 10,000 ft of a granite formation that starts at 20,000 ft depth will likely involve 10 return trips to replace worn out bits with an average time of 50 hours for each trip. If the rate of penetration of the on-bottom time of the bit is 20 ft per hour, a drilling plan for this formation for this 10,000 ft alone would account for approximately 500 hours of drilling and 500 hours of tripping time.
The following systems and techniques can be used to reduce the time required to drill in such deep formations. In some embodiments, a drill bit need not be used to drill the wellbore or portions thereof, and instead such portions of the wellbore can be “drilled” with the use of a combustible material, such as a slow burning rocket fuel. We believe that the use of a combustible material such as rocket fuel may achieve a rate of penetration (ROP), even though harder rock formations, as much as 100 ft per hour. Because the use of such a combustible material does not require the use of a drill bit that may wear out, it is anticipated that no time will be needed for tripping out (such as to replace the bit). By drilling with the slow burn rocket fuel or other combustible material, it is believed that the rig time costs can be reduced by a factor of as much as 10 in appropriate situations. The cost of the fuel needed for such drilling should easily be overcome by the time savings achieved.
While any appropriate combustible material may be used in connection with the present disclosure, the following discussion focuses on using a slow burn rocket fuel. It is believed that such a fuel can be used to burn through materials (such as steel) that have high melting points, such as around 1500° C. It is believed that such a fuel should easily be able to burn through most rock formations encountered in most drilling situations. For example, in the presence of a fluid, granite has a melting point of around 700° C. We believe that the rocket fuel should be able to melt and burn through a granite formation with relative ease in accordance with the systems and methods of the present disclosure.
In various embodiments, the bitless drilling assembly 1100 can include a connector 1108 for coupling a propellant feed hose to the propellant tank 1102. The propellant can be fed into the drilling fluid by a single hose line which can be rapidly recovered along with the burner without tripping drill pipe out of the hole. In one approach, the propellant feed hose would be connectable in 90 ft sections and fed through each stand of drill pipe as the stands are added to the drill string before making pipe connections at a surface of the borehole.
When a hose is used to deliver the fuel to the nozzle, it may be beneficial to avoid having the hose get rolled over by drill pipe. In one embodiment, a protector sub 1200 between the pipe joints can be used to help hold the hose in place and avoid pinching or deformation from contact with the drill pipe.
In addition or alternatively, one or more hose clips 1302 at one or more locations along the length of a pipe or a stand (e.g., near the center of each pipe in the drill string) can be used to hold the hose in a fixed location relative to the pipe.
Referring now to
In yet another embodiment, such as illustrated in
In
In various embodiments, the bitless drilling assembly 1900 can include a diverter cage 1902 placed in a path of the inside passage 1802 to divert the one or more propellant capsules 1904 from the inside passage 1802 to a capsule blade 1906. The capsule blade 1906 can be configured to puncture the one or more propellant capsules 1904. The bitless drilling assembly 1900 can include a reservoir 1908 configured to capture the liquid propellant released from the one or more propellant capsules 1904 and route the liquid propellant to the propellant chamber 1102.
The one or more propellant capsules 1904 may contain fuel having a greater specific gravity (e.g., 1.4) that is held within plastic capsules with a lower specific gravity (e.g., 0.9). The one or more propellant capsules 1904 can be fed down the drill pipe and around the burner housing and can be diverted by a diverter cage 1902 with a mesh size smaller than the capsule diameter (at pressure). Once inside the burner chamber, they are punctured by a capsule blade 1902 and the released propellant drops into the fuel reservoir 1908. The spent capsules 1912 float up and out into the flow 1914 and escape through the diverter cage 1902.
In various embodiments, the bitless drilling assembly 1900 can include a diverter 1910 configured to route one or more pierced capsule fragments 1912 to the outside passage 1804 of the drill pipe 1106.
In various embodiments, the bitless drilling assembly 2000 can include a burner nozzle monitor configured to detect a condition of the burner nozzle 1104. In various embodiments, the bitless drilling assembly 2000 can include a compressed gas cylinder 2002 coupled to the drill pipe, the compressed gas cylinder 2002 can be configured to release the compressed gas into a chamber to cause the bitless drilling assembly 2000 to float to a surface of a borehole if the burner nozzle 1104 is worn.
In yet another alternative embodiment shown in
In still another option for a bitless fuel delivery system, shown in
The bitless fuel delivery system may be coupled to one or more control systems, such as any of those described above. For purposes of the following discussion, the control system for the bitless fuel delivery may be separate from or a part of the control systems described above. In one embodiment, a fuel delivery control system is coupled to one or more surface sensors, one or more downhole sensors, and/or one or more drilling control systems. The control system can receive drilling parameter information for one or more drilling parameters, such as ROP, WOB, torque, differential pressure, and/or one or more other drilling parameters noted above. The fuel delivery control system can receive such information and monitor progress and then determine whether the fuel being delivered should be increased, decreased, or maintained at its current level. For example, the control system can be coupled to one or more pumps coupled to one or more hoses to deliver the fuel and can control the one or more pumps to increase or decrease the amount of fuel being delivered downhole, as well as control the timing of any such increase or decrease so that the additional or lesser fuel arrives downhole at the nozzle at the correct time for drilling operations.
In one embodiment, the fuel delivery control system receives information indicating an amount of drilling progress, determines whether the amount of progress is within a target range, falls below or exceeds a threshold therefor, and if the amount of progress is below the target range or a threshold value, sends one or more signals to a fuel delivery system to increase the amount of fuel being delivered. The one or more control signals may also signal the amount of the increase, which may be responsive to the amount by which the amount of drilling progress falls below the target range or threshold therefor. If the fuel delivery system determines that the amount of progress is greater than desired, such as when the amount exceeds a threshold therefor or is above a target range therefor, the control system can send one or more signals to the fuel delivery system to decrease the amount of fuel being delivered, and the amount of the decrease can be determined by the amount by which the amount of progress exceeds the threshold therefor or the target range for progress. Such a control system can be used to control the amount of fuel to be delivered if the fuel is in liquid form and delivered via one or more hoses or is in capsule form and delivered to the nozzle with a drilling fluid such as with any of the fuel delivery systems described herein.
As described in co-pending patent application Ser. No. 17/823,485, filed on Aug. 30, 2022, and entitled “Systems and Methods for Drilling Geothermal Wells,” a guiding device may be used to help guide and direct the drill bit drilling a borehole towards a heat source. For example, a device such as a bottom hole assembly may include one or more portions or components that comprise one or more thermomechanical actuators. Such thermomechanical actuators may comprise thermal expansion portions or components that respond to a heat source and/or a heat differential and direct the drill bit towards the heat source. In one such approach, the drill string and/or BHA may include one or more portions or components that comprise amplified metal thermal expansion materials, such as bimetallic thermal actuators, pseudo bimorph thermal actuators, and/or may use geometric constraints to obtain the desired actuation towards a heat source. In one such an embodiment, the BHA or drill string components or portions that are heated more (e.g., are closer to a heat source) expand at a first rate responsive to their material's first thermal coefficient and due to the exposure to the heat, while other components or portions made from a second material with a different thermal coefficient expand at a different rate. The different expansion rates of the two materials of the components or portions thus can be used to direct or steer the drill bit towards the geothermal heat source. Such systems and methods may be used in addition to any or all of the sensors, control systems, and techniques described above for directional drilling of a borehole.
It should be noted that one or more portions or components of the nozzle, the BHA, and/or the drill string in a bitless drilling system and method like those described herein may comprise thermal expansion materials, such as the bimetallic thermal actuators, pseudo bimorph thermal actuators, or the like. In one embodiment, the nozzle may comprise one or more thermal actuator portions or components that bend due to the heat of the burning fuel and direct the burning fuel in a particular direction or directions. For example, a fuel delivery control system can be adapted to obtain readings regarding tool face orientation, MWD information, or LWD information during drilling and use some or all of such information to determine an orientation of the drilling. The control system can determine whether the expected orientation of the drilling conforms with the planned drilling of the wellbore (such as by comparing the expected trajectory to a well plan) and, if the expected trajectory varies from the desired well plan, the control system can increase or decrease the amount of fuel delivered to one or more ports of the nozzle, thus generating temperature one or more differential temperatures at the one or more ports. The ports may be located at one or more locations of the nozzle and use one or more thermal actuator components or portions so that the heat differential changes the orientation of the burning fuel and thus the drilling of the wellbore. For example, if the nozzle includes three or more ports, it should be possible to generate a directional bias for drilling by the nozzle in any direction. With the control system monitoring the orientation of the drilling and controlling the delivery of fuel to the ports, such as by sending more fuel to one port than received at another port, the control system can be used to automatically increase, decrease, or maintain the amount of fuel delivered to each port of the nozzle and thereby control the direction of the drilling.
In yet another embodiment, the nozzle may include a plurality of ports arranged in a way so that the burning fuel creates one or more desired effects besides melting the rock. For example, the nozzle may include one or more ports for the fuel having an angled orientation so that the burning fuel from such ports and the nozzle's movement can be used to ream out a wellbore. In addition, or alternatively, one or more ports can be orientated so that the burning fuel provides WOB or thrust. Similarly, the one or more ports can be oriented so that they cause rotation of the nozzle to scrape cuttings. In such an embodiment, the nozzle may further comprise one or more cutting surfaces such as one or more PDC bits. In addition, or in the alternative, the nozzle may comprise one or more ports which may be used to create a vortex or a Venturi effect near the bit that can help to move cuttings out of the way of the nozzle and thereby avoid recuts or reburns which would be an inefficient use of energy. Further, it should be appreciated that, by orientating the one or more ports, the thrust of the burning fuel from such ports may provide sufficient thrust to rotate the nozzle without the need for a motor, such as a mud motor in conventional drilling operations. In some embodiments, the fuel may be delivered to each of a plurality of ports, but the fluid pathways may differ in size so that one port receives more fuel than another port. In other words, the various ports may burn different amounts of fuel and thereby create different force or thrust amounts in different directions as may be desired or may burn the same amount.
In some cases, the fuel combustion generates enough heat to essentially de-nature the rock in an area that extends outwardly beyond the rock that is contacted and removed by the burning fuel. In such situations, the rock in the vicinity of the flame may soften considerably. In one embodiment, a drill bit having one or more conventional PDC cutting surfaces and one or more ignition ports or nozzles (such as in place of one of the mud nozzles in a conventional drill bit) can be included. In this system, the one or more ports or nozzles from which the burning fuel extends allows the drill bit cutting surfaces to more easily cut and remove the rock from the wellbore and uses less fuel than a purely combustion bitless drilling approach, such as described elsewhere herein. Moreover, it is believed that this approach will result in a smoother wellbore and also will result in less bit wear of the cutting surfaces.
The use of batteries for sensors and controls in the BHA or otherwise downhole will present challenges for high temperature bitless drilling applications like those described herein. Generally, such devices may be rendered inoperable or of limited use in drilling situations like those described herein. As noted, the bit or nozzle that emits the burning fuel may be oriented to provide thrust in a desired direction. Besides use of such oriented thrusters to create rotation that can be used to turn a bit or clean the hole, the rotation could also be used to generate power through a generator. The use of such a generator to provide power to sensors and control systems downhole could eliminate or at least reduce the need for batteries downhole, such as in the BHA. In one embodiment, a nozzle or bit such as described herein can include one or more ports oriented to provide thrust that rotates the nozzle or bit, and a generator which generates power that can be provided to one or more downhole sensors, control systems, or other electrically powered devices, either in addition to or in lieu of power provided by one or more batteries.
In yet another embodiment, which may be in addition to or an alternative to the use of the generator described above, it should be possible to harvest some of the extreme thermal energy proximal to the ports by using one or more thermoelectric devices to generate electrical power for the downhole system, including the sensors, control systems, and other electric devices, such as those located in the BHA. Thermoelectric devices useful for such systems and methods can include those described in co-pending U.S. Provisional Patent Application Ser. No. 63/380,448, filed on Oct. 21, 2022, and entitled “Systems and Methods for Generating and Storing Energy,” which is hereby incorporated by reference as if fully set forth herein. A number of thermoelectric devices like those described in the foregoing patent application can be placed within the BHA and/or within one or more pipes in the drill string, such as in locations proximal the nozzle or the one or more ports. It is expected that such locations are likely to present the greatest temperature differentials and therefore thermoelectric devices placed in such locations are expected to produce the most electric current. Such devices typically provide a DC current, which can be provided to the one or more sensors, control systems, or other electric components in the BHA, and/or the DC current can be transformed to an AC current, which can also be provided to such sensors, control systems and other downhole devices. The electric power from such thermoelectric devices can be used to eliminate or at least reduce the need for batteries or other power supplies for such downhole sensors, control systems, and electric devices. Such thermoelectric devices may be disposed within a pipe or BHA in a manner like those described in the foregoing co-pending application.
At block 2510, process 2500 may include storing a liquid propellant or fuel in a propellant chamber in an assembly located at the bottom or end of the wellbore. The liquid propellant can be stored in one or more reservoir. In various embodiments, a hose can refill the reservoir while the reservoir is in a wellbore.
At block 1620, process 1600 may include routing the liquid propellant from the propellant chamber to a burner nozzle via one or more passages in the assembly. The liquid propellant can be routed from the propellant chamber to the burner nozzle using a gravity feed. In various embodiments, the liquid propellant can be pressurized to provide a positive force from the propellant chamber to the burner nozzle via the one or more passages in the assembly.
At block 1630, process 1600 may include igniting the liquid propellant at the burner nozzle, with the resulting combustion adapted to melt the rock formation through which the wellbore is advanced. In various embodiments, an ignitor assembly can provide a spark or flame to ignite the liquid propellent. In various embodiments, the ignitor can be electrically powered. In various embodiments, the ignitor assembly can be configured to only operate to initially ignite the propellent. In various embodiments, the ignitor assembly can routinely provide ignition to ensure the liquid propellant continues to burn during drilling.
At block 1640, process 1600 may include drilling a formation using the liquid propellant. The burning liquid propellant can burn through the rock formation by melting the rock in the formation.
Process 1600 can include additional implementations, such as any single implementation or any combination of implementations described below and/or in connection with one or more other processes described elsewhere herein.
In various implementations, process 1600 can include receiving additional liquid propellant to the propellant chamber visa a coupling for a fuel hose.
In various implementations, process 1600 can include diverting one or more fuel capsules from an inside passage of a pipe encasing the bitless drill assembly. In various implementations, process 1600 can include piercing the one or more fuel capsules using a capsule blade. In various implementations, process 1600 can include capturing the propellant from the one or more fuel capsules.
In various implementations, process 1600 can include routing the one or more fuel capsules from the capsule blade to a surface via an outside passage of the pipe encasing the bitless drill assembly.
In various implementations, the burner nozzle may be oriented at an angle with respect to longitudinal axis of the assembly and/or the drill string. In such an approach, the combustion of the fuel will melt the rock in a desired direction, such as achieved with conventional slide drilling techniques. Alternatively, the nozzle may be oriented in a vertical position with respect to the longitudinal axis of the assembly and/or the drill string, thus advancing the wellbore in substantially the same direction as is the case with conventional rotary drilling techniques.
As used below, any reference to a series of examples is to be understood as a reference to each of those examples disjunctively (e.g., “Examples 1-4” is to be understood as “Examples 1, 2, 3, or 4”).
Example 1 is an apparatus for drilling, comprising: a propellant chamber configured to store a liquid propellant for drilling; a burner nozzle connected to the propellant chamber via one or more passages to route the liquid propellant from the propellant chamber to the burner nozzle; and an ignitor configured to ignite the liquid propellant as the liquid propellant escapes the burner nozzle.
Example 2 is the apparatus of example(s) 1, further comprising a connector for coupling a propellant feed hose.
Example 3 is the apparatus of example(s) 1, wherein the burner nozzle is encased in a drill pipe to create a path for a drilling fluid that bypasses the burner nozzle and feeds fluid down an inside passage and up an outside passage of the drill pipe.
Example 4 is the apparatus of example(s) 3, further comprising: a diverter cage placed in a path of the inside passage to divert one or more propellant capsules from the inside passage to a capsule blade; the capsule blade configured to puncture the one or more propellant capsules; and a reservoir configured to capture the propellant from the one or more propellant capsules and route the fuel to the propellant chamber.
Example 5 is the apparatus of example(s) 4, further comprising a diverter configured to route one or more pierced capsules to the outside passage of the large internal diameter drill pipe.
Example 6 is the apparatus of example(s) 4, further comprising: a burner nozzle monitor configured to detect a condition of the burner nozzle; and a compressed gas cylinder coupled to the drill pipe, the compressed gas cylinder configured to release the compressed gas into a chamber to cause the apparatus to float to a surface of a borehole.
Example 7 is the apparatus of example(s) 4, wherein the diverter cage comprises a mesh size smaller than a diameter of the one or more propellant capsules.
Example 8 is the apparatus of example(s) 1, wherein the burner nozzle comprises a high temperature, high abrasion ceramic.
Example 9 is a bottom hole assembly for drilling a borehole, comprising: a propellant chamber configured to store a liquid propellant for drilling; a burner nozzle connected to the propellant chamber via one or more passages to route the liquid fuel from the propellant chamber to the burner nozzle; and an ignitor configured to ignite the liquid fuel as the propellant escapes the burner nozzle.
Example 10 is the bottom hole assembly of example(s) 9, further comprising a connector for coupling a propellant feed house.
Example 11 is the bottom hole assembly of example(s) 9, wherein the burner nozzle is encased in a large internal diameter drill pipe to create a path for a drilling fluid that bypasses the burner nozzle and feeds fluid down an inside passage and up an outside passage of the large internal diameter drill pipe.
Example 12 is the bottom hole assembly of example(s) 11, further comprising: a diverter cage placed in a path of the inside passage to divert one or more propellant capsules from the inside passage to a capsule blade; the capsule blade configured to puncture the one or more propellant capsules; and a reservoir configured to capture the propellant from the one or more propellant capsules and route the fuel to the propellant chamber.
Example 13 is the bottom hole assembly of example(s) 12, further comprising a diverter configured to route one or more pierced capsules to the outside passage of the large internal diameter drill pipe.
Example 14 is the bottom hole assembly of example(s) 12, further comprising: a burner nozzle monitor configured to detect a condition of the burner nozzle; and a compressed gas cylinder coupled to the large internal diameter pipe, the compressed gas cylinder configured to release the compressed gas into a chamber to cause the apparatus to float to a surface of a borehole.
Example 15 is the bottom hole assembly of example(s) 12, wherein the diverter cage comprises a mesh size smaller than a diameter of the one or more propellant capsules.
Example 16 is the bottom hole assembly of example(s) 9, wherein the burner nozzle comprises a high temperature, high abrasion ceramic.
Example 17 is a method for drilling a borehole using a bitless drill assembly, comprising: storing a liquid propellant in a propellant chamber; routing the liquid propellant from the propellant chamber to a burner nozzle via one or more passages; igniting the liquid propellant at the burner nozzle; and drilling a formation using the liquid propellant.
Example 18 is the method of example(s) 17, further comprising: receiving additional liquid propellant to the propellant chamber visa a coupling for a fuel hose.
Example 19 is the method of example(s) 17, further comprising: diverting one or more fuel capsules from an inside passage of a pipe encasing the bitless drill assembly; piercing the one or more fuel capsules using a capsule blade; and capturing the propellant from the one or more fuel capsules.
Example 20 is the method of example(s) 19, further comprising: routing the one or more fuel capsules from the capsule blade to a surface via an outside passage of the pipe encasing the bitless drill assembly.
Example 21 is a system for bitless drilling, the system comprising: a fuel chamber adapted to store a liquid fuel for drilling; means for providing fuel to the fuel chamber; a burner nozzle in fluid communication with the fuel chamber; and an igniter proximal one end of the burner nozzle, wherein the igniter is adapted to ignite the fuel as it leaves the burner nozzle.
Example 22 is a system of example(s) 21, wherein the means for providing fuel to the fuel chamber comprises a tube coupled at one end to the fuel chamber, or a fluid pathway coupled to the fuel chamber, wherein the tube extends through a drill string located in a wellbore to a surface connection.
Example 23 is the system of example(s) 21, wherein the means for providing fuel to the fuel chamber comprises a diverter adapted to divert a plurality of fuel capsules to a piercing instrument that is adapted to pierce an outer layer of the plurality of fuel capsules.
Example 24 is the system of example(s) 23, wherein the diverter is adapted to divert the plurality of fuel capsules towards the center of the drill string.
Example 25 is the system of example(s) 21, wherein the means for providing fuel to the fuel chamber comprises a sub having a first end and a second end, with the first end adapted to be connected to an end of a first pipe and the second end adapted to be connected to the end of a second pipe, wherein a first tube is located in the first pipe and a second tube is located within the second pipe, and wherein the first tube and the second tube extend at least partially into the sub, wherein each of the first tube and the second tube are adapted to provide fluid communication with an interior chamber in the sub, and wherein the interior chamber in the sub is sealed against the flow of a drilling fluid thereinto from the first pipe and the second pipe.
Example 26 is the system of example(s) 23, wherein each of the plurality of capsules comprises an outer layer having a first density and fuel therein, wherein the fuel has a second density which is greater than the first density.
Example 27 is the system of example(s) 26, wherein the drilling fluid has a third density that is greater than the first density and less than the second density.
Example 28 is a system for drilling a well, the system comprising: a processor coupled to a memory, wherein the memory comprises instructions for: receiving rate of penetration (ROP) data; determining if the ROP is within a target range therefor, or exceeds a threshold therefore or falls below a threshold therefor; and sending one or more control signals to a control system to adjust the flow of a fuel being delivered to a nozzle that is adapted to burn the fuel proximal to a formation being drilled if the ROP falls outside the target range therefor, exceeds a threshold therefor, or falls below a threshold therefor.
Example 29 is a system for drilling a well, the system comprising: a bottom hole assembly (BHA) comprising a burner having one or more ports through which ignited fuel is ejected, wherein at least a first port of the one or more ports is oriented to direct the ignited fuel ejected therefrom in a predetermined direction during drilling of a wellbore.
Example 30 is the system according to claim 29, wherein the BHA further comprises one or more mechanical bits or cutting surfaces.
Example 31 is the system according to claim 30, wherein the first port is oriented so that the ignited fuel ejected therefrom generates a rotational movement of the BHA.
Example 32 is the system according to either claim 28 or 29, further comprising one or more thermoelectric devices located proximal the nozzle or the one or more ports and adapted to generate an electric current.
Example 33 is the system according to claim 32 wherein the one or more thermoelectric devices are coupled to one or more downhole sensors, one or more processors, one or more control systems, or one or more electrical components and provide electric power to the same.
Example 34 is the system according to claim 31, further comprising one or more generators adapted to generate electricity using the rotational movement of the BHA.
Example 35 is the system according to claim 34, wherein the one or more generators are coupled to one or more downhole sensors, one or more processors, one or more control systems, or one or more electrical components and provide electric power to the same.
It is to be noted that the foregoing description is not intended to limit the scope of the claims. For example, it is noted that the disclosed methods and systems include additional features and can use additional drilling parameters and relationships beyond the examples provided. The examples and illustrations provided in the present disclosure are for explanatory purposes and should not be considered as limiting the scope of the invention, which is defined only by the following claims.
This application claims the benefit of priority of U.S. Provisional Patent Application No. 63/269,846, entitled “METHODS AND APPARATUS FOR BITLESS DRILLING,” filed Mar. 24, 2022, and claims the benefit of priority of U.S. Provisional Patent Application No. 63/387,910, entitled “METHODS AND APPARATUS FOR BITLESS DRILLING,” filed Dec. 16, 2022, both of which are hereby incorporated by reference in their entirety and for all purposes. This application is related to U.S. Provisional Patent Application Ser. No. 63/260,797, entitled “Systems and Method for Drilling Geothermal Wells” filed on Aug. 31, 2021, to U.S. Provisional Patent Application Ser. No. 63/269,846, entitled “Methods and Apparatus for Bitless Drilling” filed on Mar. 24, 2022, to U.S. Non-provisional patent application Ser. No. 17/823,485 filed on Aug. 30, 2022, entitled “Systems and Methods for Drilling Geothermal Wells” filed on Aug. 30, 2022, and to U.S. Provisional Patent Application Ser. No. 63/380,448, entitled “Systems and Methods for Generating and Storing Energy” filed on Oct. 21, 2022, each of which is incorporated herein by reference in their entirety and for all purposes.
| Number | Date | Country | |
|---|---|---|---|
| 63269846 | Mar 2022 | US | |
| 63387910 | Dec 2022 | US |
