Patent ID: 12203361

DETAILED DESCRIPTION

Referring now to the drawings, wherein like reference numbers are used herein to designate like elements throughout, the various views and embodiments of a system and method for surface steerable drilling are illustrated and described, and other possible embodiments are described. The figures are not necessarily drawn to scale, and in some instances the drawings have been exaggerated and/or simplified in places for illustrative purposes only. One of ordinary skill in the art will appreciate the many possible applications and variations based on the following examples of possible embodiments.

Referring toFIG.1A, one embodiment of an environment100is illustrated with multiple wells102,104,106,108, and a drilling rig110. In the present example, the wells102and104are located in a region112, the well106is located in a region114, the well108is located in a region116, and the drilling rig110is located in a region118. Each region112,114,116, and118may represent a geographic area having similar geological formation characteristics. For example, region112may include particular formation characteristics identified by rock type, porosity, thickness, and other geological information. These formation characteristics affect drilling of the wells102and104. Region114may have formation characteristics that are different enough to be classified as a different region for drilling purposes, and the different formation characteristics affect the drilling of the well106. Likewise, formation characteristics in the regions116and118affect the well108and drilling rig110, respectively.

It is understood the regions112,114,116, and118may vary in size and shape depending on the characteristics by which they are identified. Furthermore, the regions112,114,116, and118may be sub-regions of a larger region. Accordingly, the criteria by which the regions112,114,116, and118are identified is less important for purposes of the present disclosure than the understanding that each region112,114,116, and118includes geological characteristics that can be used to distinguish each region from the other regions from a drilling perspective. Such characteristics may be relatively major (e.g., the presence or absence of an entire rock layer in a given region) or may be relatively minor (e.g., variations in the thickness of a rock layer that extends through multiple regions).

Accordingly, drilling a well located in the same region as other wells, such as drilling a new well in the region112with already existing wells102and104, means the drilling process is likely to face similar drilling issues as those faced when drilling the existing wells in the same region. For similar reasons, a drilling process performed in one region is likely to face issues different from a drilling process performed in another region. However, even the drilling processes that created the wells102and104may face different issues during actual drilling as variations in the formation are likely to occur even in a single region.

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 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 driller directly responsible for the drilling may have drilled other boreholes in the same region and so may have some similar experience, but it is impossible for a human to mentally track all the possible inputs and factor those inputs into a decision. This can result in expensive mistakes, as errors in drilling can add hundreds of thousands or even millions of dollars to the drilling cost and, in some cases, drilling errors may permanently lower the output of a well, resulting in substantial long term losses.

In the present example, to aid in the drilling process, each well102,104,106, and108has corresponding collected data120,122,124, and126, respectively. The collected data may include the geological characteristics of a particular formation in which the corresponding well was formed, the attributes of a particular drilling rig, including the bottom hole assembly (BHA), and drilling information such as weight-on-bit (WOB), drilling speed, and/or other information pertinent to the formation of that particular borehole. The drilling information may be associated with a particular depth or other identifiable marker so that, for example, it is recorded that drilling of the well102from 1000 feet to 1200 feet occurred at a first ROP through a first rock layer with a first WOB, while drilling from 1200 feet to 1500 feet occurred at a second ROP through a second rock layer with a second WOB. The collected data may be used to recreate the drilling process used to create the corresponding well102,104,106, or108in the particular formation. It is understood that the accuracy with which the drilling process can be recreated depends on the level of detail and accuracy of the collected data.

The collected data120,122,124, and126may be stored in a centralized database128as indicated by lines130,132,134, and136, respectively, which may represent any wired and/or wireless communication channel(s). The database128may be located at a drilling hub (not shown) or elsewhere. Alternatively, the data may be stored on a removable storage medium that is later coupled to the database128in order to store the data. The collected data120,122,124, and126may be stored in the database128as formation data138, equipment data140, and drilling data142for example. Formation data138may include any formation information, such as rock type, layer thickness, layer location (e.g., depth), porosity, gamma readings, etc. Equipment data140may include any equipment information, such as drilling rig configuration (e.g., rotary table or top drive), bit type, mud composition, etc. Drilling data142may include any drilling information, such as drilling speed, WOB, differential pressure, toolface orientation, etc. The collected data may also be identified by well, region, and other criteria, and may be sortable to enable the data to be searched and analyzed. It is understood that many different storage mechanisms may be used to store the collected data in the database128.

With additional reference toFIG.1B, an environment160(not to scale) illustrates a more detailed embodiment of a portion of the region118with the drilling rig110located at the surface162. A drilling plan has been formulated to drill a borehole164extending into the ground to a true vertical depth (TVD)166. The borehole164extends through strata layers168and170, stopping in layer172, and not reaching underlying layers174and176. The borehole164may be directed to a target area180positioned in the layer172. The target180may be a subsurface point or points defined by coordinates or other markers that indicate where the borehole164is to end or may simply define a depth range within which the borehole164is to remain (e.g., the layer172itself). It is understood that the target180may be any shape and size, and may be defined in any way. Accordingly, the target180may represent an endpoint of the borehole164or may extend as far as can be realistically drilled. For example, if the drilling includes a horizontal component and the goal is to follow the layer172as far as possible, the target may simply be the layer172itself and drilling may continue until a limit is reached, such as a property boundary or a physical limitation to the length of the drillstring. A fault178has shifted a portion of each layer downwards. Accordingly, the borehole164is located in non-shifted layer portions168A-176A, while portions168B-176B represent the shifted layer portions.

Current drilling techniques frequently involve directional drilling to reach a target, such as the target180. The use of directional drilling generally increases the amount of reserves that can be obtained and also increases production rate, sometimes significantly. For example, the directional drilling used to provide the horizontal portion shown inFIG.1Bincreases the length of the borehole in the layer172, which is the target layer in the present example. Directional drilling may also be used alter the angle of the borehole to address faults, such as the fault178that has shifted the layer portion172B. Other uses for directional drilling include sidetracking off of an existing well to reach a different target area or a missed target area, drilling around abandoned drilling equipment, drilling into otherwise inaccessible or difficult to reach locations (e.g., under populated areas or bodies of water), providing a relief well for an existing well, and increasing the capacity of a well by branching off and having multiple boreholes extending in different directions or at different vertical positions for the same well. Directional drilling is often not confined to a straight horizontal borehole, but may involve staying within a rock layer that varies in depth and thickness as illustrated by the layer172. As such, directional drilling may involve multiple vertical adjustments that complicate the path of the borehole.

With additional reference toFIG.1C, which illustrates one embodiment of a portion of the borehole164ofFIG.1B, the drilling of horizontal wells clearly introduces significant challenges to drilling that do not exist in vertical wells. For example, a substantially horizontal portion192of the well may be started off of a vertical borehole190and one drilling consideration is the transition from the vertical portion of the well to the horizontal portion. This transition is generally a curve that defines a build up section194beginning at the vertical portion (called the kick off point and represented by line196) and ending at the horizontal portion (represented by line198). The change in inclination per measured length drilled is typically referred to as the build rate and is often defined in degrees per one hundred feet drilled. For example, the build rate may be 6°/100 ft, indicating that there is a six degree change in inclination for every one hundred feet drilled. The build rate for a particular build up section may remain relatively constant or may vary.

The build rate depends on factors such as the formation through which the borehole164is to be drilled, the trajectory of the borehole164, 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 required horizontal displacement, stabilization, and inclination. 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 needed tasks in the borehole164. Depending on the severity of the mistake, the borehole164may require enlarging or the bit may need to be backed out and a new passage formed. Such mistakes cost time and money. However, if the built rate is too cautious, significant additional time may be added to the drilling process as it is generally slower to drill a curve than to drill straight. Furthermore, drilling a curve is more complicated and the possibility of drilling errors increases (e.g., overshoot and undershoot that may occur trying to keep the bit on the planned path).

Two modes of drilling, known as rotating and sliding, are commonly used to form the borehole164. Rotating, also called rotary drilling, uses a topdrive or rotary table to rotate the drillstring. Rotating is used when drilling is to occur along a straight path. Sliding, also called steering, uses a downhole mud motor with an adjustable bent housing and does not rotate the drillstring. Instead, sliding uses hydraulic power to drive the downhole motor and bit. Sliding is used in order to control well direction.

To accomplish a slide, the rotation of the drill string is stopped. Based on feedback from measuring equipment such as a MWD tool, adjustments are made to the drill string. These adjustments continue until the downhole toolface that indicates the direction of the bend of the motor is oriented to the direction of the desired deviation of the borehole. Once the desired orientation is accomplished, pressure is applied to the drill bit, which causes the drill bit to move in the direction of deviation. Once sufficient distance and angle have been built, a transition back to rotating mode is accomplished by rotating the drill string. This rotation of the drill string neutralizes the directional deviation caused by the bend in the motor as it continuously rotates around the centerline of the borehole.

Referring again toFIG.1A, the formulation of a drilling plan for the drilling rig110may include processing and analyzing the collected data in the database128to create a more effective drilling plan. Furthermore, once the drilling has begun, the collected data may be used in conjunction with current data from the drilling rig110to improve drilling decisions. Accordingly, an on-site controller144is coupled to the drilling rig110and may also be coupled to the database128via one or more wired and/or wireless communication channel(s)146. Other inputs148may also be provided to the on-site controller144. In some embodiments, the on-site controller144may operate as a stand-alone device with the drilling rig110. For example, the on-site controller144may not be communicatively coupled to the database128. Although shown as being positioned near or at the drilling rig110in the present example, it is understood that some or all components of the on-site controller144may be distributed and located elsewhere in other embodiments.

The on-site controller144may form all or part of a surface steerable system. The database128may also form part of the surface steerable system. As will be described in greater detail below, the surface steerable system may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. The surface steerable system may be used to perform such operations as receiving drilling data representing a drill path and 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 rig110, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and/or calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Referring toFIG.2A, a diagram200illustrates one embodiment of information flow for a surface steerable system201from the perspective of the on-site controller144ofFIG.1A. In the present example, the drilling rig110ofFIG.1Aincludes drilling equipment216used to perform the drilling of a borehole, such as top drive or rotary drive equipment that couples to the drill string and BHA and is configured to rotate the drill string and apply pressure to the drill bit. The drilling rig110may include control systems such as a WOB/differential pressure control system208, a positional/rotary control system210, and a fluid circulation control system212. The control systems208,210, and212may be used to monitor and change drilling rig settings, such as the WOB and/or differential pressure to alter the ROP or the radial orientation of the toolface, change the flow rate of drilling mud, and perform other operations.

The drilling rig110may also include a sensor system214for obtaining sensor data about the drilling operation and the drilling rig110, including the downhole equipment. For example, the sensor system214may include measuring while drilling (MWD) and/or logging while drilling (LWD) components for obtaining information, such as toolface and/or formation logging information, that may be saved for later retrieval, transmitted with a delay or in real time using any of various communication means (e.g., wireless, wireline, or mud pulse telemetry), or otherwise transferred to the on-site controller144. Such information may include information related to hole depth, bit depth, inclination, azimuth, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary rotations per minute (RPM), bit speed, ROP, WOB, and/or other information. It is understood that all or part of the sensor system214may be incorporated into one or more of the control systems208,210, and212, and/or in the drilling equipment216. As the drilling rig110may be configured in many different ways, it is understood that these control systems may be different in some embodiments, and may be combined or further divided into various subsystems.

The on-site controller144receives input information202. The input information202may include information that is pre-loaded, received, and/or updated in real time. The input information202may include a well plan, regional formation history, one or more drilling engineer parameters, MWD tool face/inclination information, LWD gamma/resistivity information, economic parameters, reliability parameters, and/or other decision guiding parameters. Some of the inputs, such as the regional formation history, may be available from a drilling hub216, which may include the database128ofFIG.1Aand one or more processors (not shown), while other inputs may be accessed or uploaded from other sources. For example, a web interface may be used to interact directly with the on-site controller144to upload the well plan and/or drilling engineer parameters. The input information202feeds into the on-site controller144and, after processing by the on-site controller144, results in control information204that is output to the drilling rig110(e.g., to the control systems208,210, and212). The drilling rig110(e.g., via the systems208,210,212, and214) provides feedback information206to the on-site controller144. The feedback information206then serves as input to the on-site controller144, enabling the on-site controller144to verify that the current control information is producing the desired results or to produce new control information for the drilling rig110.

The on-site controller144also provides output information203. As will be described later in greater detail, the output information203may be stored in the on-site controller144and/or sent offsite (e.g., to the database128). The output information203may be used to provide updates to the database128, as well as provide alerts, request decisions, and convey other data related to the drilling process.

Referring toFIG.2B, one embodiment of a display250that may be provided by the on-site controller144is illustrated. The display250provides many different types of information in an easily accessible format. For example, the display250may be a viewing screen (e.g., a monitor) that is coupled to or forms part of the on-site controller144.

The display250provides visual indicators such as a hole depth indicator252, a bit depth indicator254, a GAMMA indicator256, an inclination indicator258, an azimuth indicator260, and a TVD indicator262. Other indicators may also be provided, including a ROP indicator264, a mechanical specific energy (MSE) indicator266, a differential pressure indicator268, a standpipe pressure indicator270, a flow rate indicator272, a rotary RPM indicator274, a bit speed indicator276, and a WOB indicator278.

Some or all of the indicators264,266,268,270,272,274,276, and/or278may include a marker representing a target value. For purposes of example, markers are set as the following values, but it is understood that any desired target value may be representing. For example, the ROP indicator264may include a marker265indicating that the target value is fifty ft/hr. The MSE indicator266may include a marker267indicating that the target value is thirty-seven ksi. The differential pressure indicator268may include a marker269indicating that the target value is two hundred psi. The ROP indicator264may include a marker265indicating that the target value is fifty ft/hr. The standpipe pressure indicator270may have no marker in the present example. The flow rate indicator272may include a marker273indicating that the target value is five hundred gpm. The rotary RPM indicator274may include a marker275indicating that the target value is zero RPM (due to sliding). The bit speed indicator276may include a marker277indicating that the target value is one hundred and fifty RPM. The WOB indicator278may include a marker279indicating that the target value is ten klbs. Although only labeled with respect to the indicator264, each indicator may include a colored band263or another marking to indicate, for example, whether the respective gauge value is within a safe range (e.g., indicated by a green color), within a caution range (e.g., indicated by a yellow color), or within a danger range (e.g., indicated by a red color). Although not shown, in some embodiments, multiple markers may be present on a single indicator. The markers may vary in color and/or size.

A log chart280may visually indicate depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, the log chart280may have a y-axis representing depth and an x-axis representing a measurement such as GAMMA count281(as shown), ROP283(e.g., empirical ROP and normalized ROP), or resistivity. An autopilot button282and an oscillate button284may be used to control activity. For example, the autopilot button282may be used to engage or disengage an autopilot, while the oscillate button284may be used to directly control oscillation of the drill string or engage/disengage an external hardware device or controller via software and/or hardware.

A circular chart286may provide current and historical toolface orientation information (e.g., which way the bend is pointed). For purposes of illustration, the circular chart286represents three hundred and sixty degrees. A series of circles within the circular chart286may represent a timeline of toolface orientations, with the sizes of the circles indicating the temporal position of each circle. For example, larger circles may be more recent than smaller circles, so the largest circle288may be the newest reading and the smallest circle289may be the oldest reading. In other embodiments, the circles may represent the energy and/or progress made via size, color, shape, a number within a circle, etc. For example, the size of a particular circle may represent an accumulation of orientation and progress for the period of time represented by the circle. In other embodiments, concentric circles representing time (e.g., with the outside of the circular chart286being the most recent time and the center point being the oldest time) may be used to indicate the energy and/or progress (e.g., via color and/or patterning such as dashes or dots rather than a solid line).

The circular chart286may also be color coded, with the color coding existing in a band290around the circular chart286or 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 toolface orientation with little deviation. For purposes of illustration, the color blue extends from approximately 22-337 degrees, the color green extends from approximately 15-22 degrees and 337-345 degrees, the color yellow extends a few degrees around the 13 and 345 degree marks, and the color red extends 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 and/or a light blue marking the transition between blue and green.

This color coding enables the display250to 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, the display250may clearly show that the target is at ninety degrees but the center of energy is at forty-five degrees.

Other indicators may be present, such as a slide indicator292to indicate how much time remains until a slide occurs and/or how much time remains for a current slide. For example, the slide indicator may represent a time, a percentage (e.g., current slide is fifty-six percent complete), a distance completed, and/or a distance remaining. The slide indicator292may graphically display information using, for example, a colored bar293that increases or decreases with the slide's progress. In some embodiments, the slide indicator may be built into the circular chart286(e.g., around the outer edge with an increasing/decreasing band), while in other embodiments the slide indicator may be a separate indicator such as a meter, a bar, a gauge, or another indicator type.

An error indicator294may be present to indicate a magnitude and/or a direction of error. For example, the error indicator294may indicate that the estimated drill bit position is a certain distance from the planned path, with a location of the error indicator294around the circular chart286representing the heading. For example,FIG.2Billustrates an error magnitude of fifteen feet and an error direction of fifteen degrees. The error indicator294may be any color but is red for purposes of example. It is understood that the error indicator294may present a zero if there is no error and/or may represent that the bit is on the path in other ways, such as being a green color. Transition colors, such as yellow, may be used to indicate varying amounts of error. In some embodiments, the error indicator294may not appear unless there is an error in magnitude and/or direction. A marker296may indicate an ideal slide direction. Although not shown, other indicators may be present, such as a bit life indicator to indicate an estimated lifetime for the current bit based on a value such as time and/or distance.

It is understood that the display250may 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) if 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 ft/hr). For example, the ROP indicator264may have a green bar to indicate a normal level of operation (e.g., from 10-300 ft/hr), a yellow bar to indicate a warning level of operation (e.g., from 300-360 ft/hr), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 ft/hr). The ROP indicator264may also display a marker at 100 ft/hr 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, the display250may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, the surface steerable system201may enable a user to customize the display250as desired, although certain features (e.g., standpipe pressure) may be locked to prevent removal. This locking may prevent a user from intentionally or accidentally removing important drilling information from the display. Other features may be set by preference. Accordingly, the level of customization and the information shown by the display250may be controlled based on who is viewing the display and their role in the drilling process.

Referring again toFIG.2A, it is understood that the level of integration between the on-site controller144and the drilling rig110may depend on such factors as the configuration of the drilling rig110and whether the on-site controller144is able to fully support that configuration. One or more of the control systems208,210, and212may be part of the on-site controller144, may be third-party systems, and/or may be part of the drilling rig110. For example, an older drilling rig110may have relatively few interfaces with which the on-site controller144is able to interact. For purposes of illustration, if a knob must be physically turned to adjust the WOB on the drilling rig110, the on-site controller144will not be able to directly manipulate the knob without a mechanical actuator. If such an actuator is not present, the on-site controller144may output the setting for the knob to a screen, and an operator may then turn the knob based on the setting. Alternatively, the on-site controller144may be directly coupled to the knob's electrical wiring.

However, a newer or more sophisticated drilling rig110, such as a rig that has electronic control systems, may have interfaces with which the on-site controller144can interact for direct control. For example, an electronic control system may have a defined interface and the on-site controller144may be configured to interact with that defined interface. It is understood that, in some embodiments, direct control may not be allowed even if possible. For example, the on-site controller144may be configured to display the setting on a screen for approval, and may then send the setting to the appropriate control system only when the setting has been approved.

Referring toFIG.3, one embodiment of an environment300illustrates multiple communication channels (indicated by arrows) that are commonly used in existing directional drilling operations that do not have the benefit of the surface steerable system201ofFIG.2A. The communication channels couple various individuals involved in the drilling process. The communication channels may support telephone calls, emails, text messages, faxes, data transfers (e.g., file transfers over networks), and other types of communications.

The individuals involved in the drilling process may include a drilling engineer302, a geologist304, a directional driller306, a tool pusher308, a driller310, and a rig floor crew312. One or more company representatives (e.g., company men)314may also be involved. The individuals may be employed by different organizations, which can further complicate the communication process. For example, the drilling engineer302, geologist304, and company man314may work for an operator, the directional driller306may work for a directional drilling service provider, and the tool pusher308, driller310, and rig floor crew312may work for a rig service provider.

The drilling engineer302and geologist304are often located at a location remote from the drilling rig (e.g., in a home office/drilling hub). The drilling engineer302may develop a well plan318and may make drilling decisions based on drilling rig information. The geologist304may perform such tasks as formation analysis based on seismic, gamma, and other data. The directional driller306is generally located at the drilling rig and provides instructions to the driller310based on the current well plan and feedback from the drilling engineer302. The driller310handles the actual drilling operations and may rely on the rig floor crew312for certain tasks. The tool pusher308may be in charge of managing the entire drilling rig and its operation.

The following is one possible example of a communication process within the environment300, although it is understood that many communication processes may be used. The use of a particular communication process may depend on such factors as the level of control maintained by various groups within the process, how strictly communication channels are enforced, and similar factors. In the present example, the directional driller306uses the well plan318to provide drilling instructions to the driller310. The driller310controls the drilling using control systems such as the control systems208,210, and212ofFIG.2A. During drilling, information from sensor equipment such as downhole MWD equipment316and/or rig sensors320may indicate that a formation layer has been reached twenty feet higher than expected by the geologist304. This information is passed back to the drilling engineer302and/or geologist304through the company man314, and may pass through the directional driller306before reaching the company man314.

The drilling engineer302/well planner (not shown), either alone or in conjunction with the geologist306, may modify the well plan318or make other decisions based on the received information. The modified well plan and/or other decisions may or may not be passed through the company man314to the directional driller306, who then tells the driller310how to drill. The driller310may modify equipment settings (e.g., toolface orientation) and, if needed, pass orders on to the rig floor crew312. For example, a change in WOB may be performed by the driller310changing a setting, while a bit trip may require the involvement of the rig floor crew312. Accordingly, the level of involvement of different individuals may vary depending on the nature of the decision to be made and the task to be performed. The proceeding example may be more complex than described. Multiple intermediate individuals may be involved and, depending on the communication chain, some instructions may be passed through the tool pusher308.

The environment300presents many opportunities for communication breakdowns as information is passed through the various communication channels, particularly given the varying types of communication that may be used. For example, verbal communications via phone may be misunderstood and, unless recorded, provide no record of what was said. Furthermore, accountability may be difficult or impossible to enforce as someone may provide an authorization but deny it or claim that they meant something else. Without a record of the information passing through the various channels and the authorizations used to approve changes in the drilling process, communication breakdowns can be difficult to trace and address. As many of the communication channels illustrated inFIG.3pass information through an individual to other individuals (e.g., an individual may serve as an information conduit between two or more other individuals), the risk of breakdown increases due to the possibility that errors may be introduced in the information.

Even if everyone involved does their part, drilling mistakes may be amplified while waiting for an answer. For example, a message may be sent to the geologist306that a formation layer seems to be higher than expected, but the geologist306may be asleep. Drilling may continue while waiting for the geologist306and the continued drilling may amplify the error. Such errors can cost hundreds of thousands or millions of dollars. However, the environment300provides no way to determine if the geologist304has received the message and no way to easily notify the geologist304or to contact someone else when there is no response within a defined period of time. Even if alternate contacts are available, such communications may be cumbersome and there may be difficulty in providing all the information that the alternate would need for a decision.

Referring toFIG.4, one embodiment of an environment400illustrates communication channels that may exist in a directional drilling operation having the benefit of the surface steerable system201ofFIG.2A. In the present example, the surface steerable system201includes the drilling hub216, which includes the regional database128ofFIG.1Aand processing unit(s)404(e.g., computers). The drilling hub216also includes communication interfaces (e.g., web portals)406that may be accessed by computing devices capable of wireless and/or wireline communications, including desktop computers, laptops, tablets, smart phones, and personal digital assistants (PDAs). The on-site controller144includes one or more local databases410(where “local” is from the perspective of the on-site controller144) and processing unit(s)412.

The drilling hub216is remote from the on-site controller144, and various individuals associated with the drilling operation interact either through the drilling hub216or through the on-site controller144. In some embodiments, an individual may access the drilling project through both the drilling hub216and on-site controller144. For example, the directional driller306may use the drilling hub216when not at the drilling site and may use the on-site controller144when at the drilling site.

The drilling engineer302and geologist304may access the surface steerable system201remotely via the portal406and set various parameters such as rig limit controls. Other actions may also be supported, such as granting approval to a request by the directional driller306to deviate from the well plan and evaluating the performance of the drilling operation. The directional driller306may be located either at the drilling rig110or off-site. Being off-site (e.g., at the drilling hub216or elsewhere) enables a single directional driller to monitor multiple drilling rigs. When off-site, the directional driller306may access the surface steerable system201via the portal406. When on-site, the directional driller306may access the surface steerable system via the on-site controller144.

The driller310may get instructions via the on-site controller144, thereby lessening the possibly of miscommunication and ensuring that the instructions were received. Although the tool pusher308, rig floor crew312, and company man314are shown communicating via the driller310, it is understood that they may also have access to the on-site controller144. Other individuals, such as a MWD hand408, may access the surface steerable system201via the drilling hub216, the on-site controller144, and/or an individual such as the driller310.

As illustrated inFIG.4, many of the individuals involved in a drilling operation may interact through the surface steerable system201. This enables information to be tracked as it is handled by the various individuals involved in a particular decision. For example, the surface steerable system201may track which individual submitted information (or whether information was submitted automatically), who viewed the information, who made decisions, when such events occurred, and similar information-based issues. This provides a complete record of how particular information propagated through the surface steerable system201and resulted in a particular drilling decision. This also provides revision tracking as changes in the well plan occur, which in turn enables entire decision chains to be reviewed. Such reviews may lead to improved decision making processes and more efficient responses to problems as they occur.

In some embodiments, documentation produced using the surface steerable system201may be synchronized and/or merged with other documentation, such as that produced by third party systems such as the WellView product produced by Peloton Computer Enterprises Ltd. of Calgary, Canada. In such embodiments, the documents, database files, and other information produced by the surface steerable system201is synchronized to avoid such issues as redundancy, mismatched file versions, and other complications that may occur in projects where large numbers of documents are produced, edited, and transmitted by a relatively large number of people.

The surface steerable system201may also impose mandatory information formats and other constraints to ensure that predefined criteria are met. For example, an electronic form provided by the surface steerable system201in response to a request for authorization may require that some fields are filled out prior to submission. This ensures that the decision maker has the relevant information prior to making the decision. If the information for a required field is not available, the surface steerable system201may require an explanation to be entered for why the information is not available (e.g., sensor failure). Accordingly, a level of uniformity may be imposed by the surface steerable system201, while exceptions may be defined to enable the surface steerable system201to handle various scenarios.

The surface steerable system201may also send alerts (e.g., email or text alerts) to notify one or more individuals of a particular problem, and the recipient list may be customized based on the problem. Furthermore, contact information may be time-based, so the surface steerable system201may know when a particular individual is available. In such situations, the surface steerable system201may automatically attempt to communicate with an available contact rather than waiting for a response from a contact that is likely not available.

As described previously, the surface steerable system201may present a customizable display of various drilling processes and information for a particular individual involved in the drilling process. For example, the drilling engineer302may see a display that presents information relevant to the drilling engineer's tasks, and the geologist304may see a different display that includes additional and/or more detailed formation information. This customization enables each individual to receive information needed for their particular role in the drilling process while minimizing or eliminating unnecessary information.

Referring toFIG.5, one embodiment of an environment500illustrates data flow that may be supported by the surface steerable system201ofFIG.2A. The data flow500begins at block502and may move through two branches, although some blocks in a branch may not occur before other blocks in the other branch. One branch involves the drilling hub216and the other branch involves the on-site controller144at the drilling rig110.

In block504, a geological survey is performed. The survey results are reviewed by the geologist304and a formation report506is produced. The formation report506details formation layers, rock type, layer thickness, layer depth, and similar information that may be used to develop a well plan. In block508, a well plan is developed by a well planner524and/or the drilling engineer302based on the formation report and information from the regional database128at the drilling hub216. Block508may include selection of a BHA and the setting of control limits. The well plan is stored in the database128. The drilling engineer302may also set drilling operation parameters in step510that are also stored in the database128.

In the other branch, the drilling rig110is constructed in block512. At this point, as illustrated by block526, the well plan, BHA information, control limits, historical drilling data, and control commands may be sent from the database128to the local database410. Using the receiving information, the directional driller306inputs actual BHA parameters in block514. The company man314and/or the directional driller306may verify performance control limits in block516, and the control limits are stored in the local database410of the on-site controller144. The performance control limits may include multiple levels such as a warning level and a critical level corresponding to no action taken within feet/minutes.

Once drilling begins, a diagnostic logger (described later in greater detail)520that is part of the on-site controller144logs information related to the drilling such as sensor information and maneuvers and stores the information in the local database410in block526. The information is sent to the database128. Alerts are also sent from the on-site controller144to the drilling hub216. When an alert is received by the drilling hub216, an alert notification522is sent to defined individuals, such as the drilling engineer302, geologist304, and company man314. The actual recipient may vary based on the content of the alert message or other criteria. The alert notification522may result in the well plan and the BHA information and control limits being modified in block508and parameters being modified in block510. These modifications are saved to the database128and transferred to the local database410. The BHA may be modified by the directional driller306in block518, and the changes propagated through blocks514and516with possible updated control limits. Accordingly, the surface steerable system201may provide a more controlled flow of information than may occur in an environment without such a system.

The flow charts described herein illustrate various exemplary functions and operations that may occur within various environments. Accordingly, these flow charts are not exhaustive and that various steps may be excluded to clarify the aspect being described. For example, it is understood that some actions, such as network authentication processes, notifications, and handshakes, may have been performed prior to the first step of a flow chart. Such actions may depend on the particular type and configuration of communications engaged in by the on-site controller144and/or drilling hub216. Furthermore, other communication actions may occur between illustrated steps or simultaneously with illustrated steps.

The surface steerable system201includes large amounts of data specifically related to various drilling operations as stored in databases such as the databases128and410. As described with respect toFIG.1A, this data may include data collected from many different locations and may correspond to many different drilling operations. The data stored in the database128and other databases may be used for a variety of purposes, including data mining and analytics, which may aid in such processes as equipment comparisons, drilling plan formulation, convergence planning, recalibration forecasting, and self-tuning (e.g., drilling performance optimization). Some processes, such as equipment comparisons, may not be performed in real time using incoming data, while others, such as self-tuning, may be performed in real time or near real time. Accordingly, some processes may be executed at the drilling hub216, other processes may be executed at the on-site controller144, and still other processes may be executed by both the drilling hub216and the on-site controller144with communications occurring before, during, and/or after the processes are executed. As described below in various examples, some processes may be triggered by events (e.g., recalibration forecasting) while others may be ongoing (e.g., self-tuning).

For example, in equipment comparison, data from different drilling operations (e.g., from drilling the wells102,104,106, and108) may be normalized and used to compare equipment wear, performance, and similar factors. For example, the same bit may have been used to drill the wells102and106, but the drilling may have been accomplished using different parameters (e.g., rotation speed and WOB). By normalizing the data, the two bits can be compared more effectively. The normalized data may be further processed to improve drilling efficiency by identifying which bits are most effective for particular rock layers, which drilling parameters resulted in the best ROP for a particular formation, ROP versus reliability tradeoffs for various bits in various rock layers, and similar factors. Such comparisons may be used to select a bit for another drilling operation based on formation characteristics or other criteria. Accordingly, by mining and analyzing the data available via the surface steerable system201, an optimal equipment profile may be developed for different drilling operations. The equipment profile may then be used when planning future wells or to increase the efficiency of a well currently being drilled. This type of drilling optimization may become increasingly accurate as more data is compiled and analyzed.

In drilling plan formulation, the data available via the surface steerable system201may be used to identify likely formation characteristics and to select an appropriate equipment profile. For example, the geologist304may use local data obtained from the planned location of the drilling rig110in conjunction with regional data from the database128to identify likely locations of the layers168A-176A (FIG.1B). Based on that information, the drilling engineer302can create a well plan that will include the build curve ofFIG.1C.

Referring toFIG.6, a method600illustrates one embodiment of an event-based process that may be executed by the on-site controller144ofFIG.2A. For example, software instructions needed to execute the method600may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144.

In step602, the on-site controller144receives inputs, such as a planned path for a borehole, formation information for the borehole, equipment information for the drilling rig, and a set of cost parameters. The cost parameters may be used to guide decisions made by the on-site controller144as will be explained in greater detail below. The inputs may be received in many different ways, including receiving document (e.g., spreadsheet) uploads, accessing a database (e.g., the database128ofFIG.1A), and/or receiving manually entered data.

In step604, the planned path, the formation information, the equipment information, and the set of cost parameters are processed to produce control parameters (e.g., the control information204ofFIG.2A) for the drilling rig110. The control parameters may define the settings for various drilling operations that are to be executed by the drilling rig110to form the borehole, such as WOB, flow rate of mud, toolface orientation, and similar settings. In some embodiments, the control parameters may also define particular equipment selections, such as a particular bit. In the present example, step604is directed to defining initial control parameters for the drilling rig110prior to the beginning of drilling, but it is understood that step604may be used to define control parameters for the drilling rig110even after drilling has begun. For example, the on-site controller144may be put in place prior to drilling or may be put in place after drilling has commenced, in which case the method600may also receive current borehole information in step602.

In step606, the control parameters are output for use by the drilling rig110. In embodiments where the on-site controller144is directly coupled to the drilling rig110, outputting the control parameters may include sending the control parameters directly to one or more of the control systems of the drilling rig110(e.g., the control systems210,212, and214). In other embodiments, outputting the control parameters may include displaying the control parameters on a screen, printing the control parameters, and/or copying them to a storage medium (e.g., a Universal Serial Bus (USB) drive) to be transferred manually.

In step608, feedback information received from the drilling rig110(e.g., from one or more of the control systems210,212, and214and/or sensor system216) is processed. The feedback information may provide the on-site controller144with the current state of the borehole (e.g., depth and inclination), the drilling rig equipment, and the drilling process, including an estimated position of the bit in the borehole. The processing may include extracting desired data from the feedback information, normalizing the data, comparing the data to desired or ideal parameters, determining whether the data is within a defined margin of error, and/or any other processing steps needed to make use of the feedback information.

In step610, the on-site controller144may take action based on the occurrence of one or more defined events. For example, an event may trigger a decision on how to proceed with drilling in the most cost effective manner. Events may be triggered by equipment malfunctions, path differences between the measured borehole and the planned borehole, upcoming maintenance periods, unexpected geological readings, and any other activity or non-activity that may affect drilling the borehole. It is understood that events may also be defined for occurrences that have a less direct impact on drilling, such as actual or predicted labor shortages, actual or potential licensing issues for mineral rights, actual or predicted political issues that may impact drilling, and similar actual or predicted occurrences. Step610may also result in no action being taken if, for example, drilling is occurring without any issues and the current control parameters are satisfactory.

An event may be defined in the received inputs of step602or defined later. Events may also be defined on site using the on-site controller144. For example, if the drilling rig110has a particular mechanical issue, one or more events may be defined to monitor that issue in more detail than might ordinarily occur. In some embodiments, an event chain may be implemented where the occurrence of one event triggers the monitoring of another related event. For example, a first event may trigger a notification about a potential problem with a piece of equipment and may also activate monitoring of a second event. In addition to activating the monitoring of the second event, the triggering of the first event may result in the activation of additional oversight that involves, for example, checking the piece of equipment more frequently or at a higher level of detail. If the second event occurs, the equipment may be shut down and an alarm sounded, or other actions may be taken. This enables different levels of monitoring and different levels of responses to be assigned independently if needed.

Referring toFIG.7A, a method700illustrates a more detailed embodiment of the method600ofFIG.6, particularly of step610. As steps702,704,706, and708are similar or identical to steps602,604,606, and608, respectively, ofFIG.6, they are not described in detail in the present embodiment. In the present example, the action of step610ofFIG.6is based on whether an event has occurred and the action needed if the event has occurred.

Accordingly, in step710, a determination is made as to whether an event has occurred based on the inputs of steps702and708. If no event has occurred, the method700returns to step708. If an event has occurred, the method700moves to step712, where calculations are performed based on the information relating to the event and at least one cost parameter. It is understood that additional information may be obtained and/or processed prior to or as part of step712if needed. For example, certain information may be used to determine whether an event has occurred, and additional information may then be retrieved and processed to determine the particulars of the event.

In step714, new control parameters may be produced based on the calculations of step712. In step716, a determination may be made as to whether changes are needed in the current control parameters. For example, the calculations of step712may result in a decision that the current control parameters are satisfactory (e.g., the event may not affect the control parameters). If no changes are needed, the method700returns to step708. If changes are needed, the on-site controller144outputs the new parameters in step718. The method700may then return to step708. In some embodiments, the determination of step716may occur before step714. In such embodiments, step714may not be executed if the current control parameters are satisfactory.

In a more detailed example of the method700, assume that the on-site controller144is involved in drilling a borehole and that approximately six hundred feet remain to be drilled. An event has been defined that warns the on-site controller144when the drill bit is predicted to reach a minimum level of efficiency due to wear and this event is triggered in step710at the six hundred foot mark. The event may be triggered because the drill bit is within a certain number of revolutions before reaching the minimum level of efficiency, within a certain distance remaining (based on strata type, thickness, etc.) that can be drilled before reaching the minimum level of efficiency, or may be based on some other factor or factors. Although the event of the current example is triggered prior to the predicted minimum level of efficiency being reached in order to proactively schedule drilling changes if needed, it is understood that the event may be triggered when the minimum level is actually reached.

The on-site controller144may perform calculations in step712that account for various factors that may be analyzed to determine how the last six hundred feet is drilled. These factors may include the rock type and thickness of the remaining six hundred feet, the predicted wear of the drill bit based on similar drilling conditions, location of the bit (e.g., depth), how long it will take to change the bit, and a cost versus time analysis. Generally, faster drilling is more cost effective, but there are many tradeoffs. For example, increasing the WOB or differential pressure to increase the rate of penetration may reduce the time it takes to finish the borehole, but may also wear out the drill bit faster, which will decrease the drilling effectiveness and slow the drilling down. If this slowdown occurs too early, it may be less efficient than drilling more slowly. Therefore, there is a tradeoff that must be calculated. Too much WOB or differential pressure may also cause other problems, such as damaging downhole tools. Should one of these problems occur, taking the time to trip the bit or drill a sidetrack may result in more total time to finish the borehole than simply drilling more slowly, so faster may not be better. The tradeoffs may be relatively complex, with many factors to be considered.

In step714, the on-site controller144produces new control parameters based on the solution calculated in step712. In step716, a determination is made as to whether the current parameters should be replaced by the new parameters. For example, the new parameters may be compared to the current parameters. If the two sets of parameters are substantially similar (e.g., as calculated based on a percentage change or margin of error of the current path with a path that would be created using the new control parameters) or identical to the current parameters, no changes would be needed. However, if the new control parameters call for changes greater than the tolerated percentage change or outside of the margin of error, they are output in step718. For example, the new control parameters may increase the WOB and also include the rate of mud flow significantly enough to override the previous control parameters. In other embodiments, the new control parameters may be output regardless of any differences, in which case step716may be omitted. In still other embodiments, the current path and the predicted path may be compared before the new parameters are produced, in which case step714may occur after step716.

Referring toFIG.7Band with additional reference toFIG.7C, a method720(FIG.7B) and diagram740(FIG.7C) illustrate a more detailed embodiment of the method600ofFIG.6, particularly of step610. As steps722,724,726, and728are similar or identical to steps602,604,606, and608, respectively, ofFIG.6, they are not described in detail in the present embodiment. In the present example, the action of step610ofFIG.6is based on whether the drilling has deviated from the planned path.

In step730, a comparison may be made to compare the estimated bit position and trajectory with a desired point (e.g., a desired bit position) along the planned path. The estimated bit position may be calculated based on information such as a survey reference point and/or represented as an output calculated by a borehole estimator (as will be described later) and may include a bit projection path and/or point that represents a predicted position of the bit if it continues its current trajectory from the estimated bit position. Such information may be included in the inputs of step722and feedback information of step728or may be obtained in other ways. It is understood that the estimated bit position and trajectory may not be calculated exactly, but may represent an estimate the current location of the drill bit based on the feedback information. As illustrated inFIG.7C, the estimated bit position is indicated by arrow743relative to the desired bit position741along the planned path742.

In step732, a determination may be made as to whether the estimated bit position743is within a defined margin of error of the desired bit position. If the estimated bit position is within the margin of error, the method720returns to step728. If the estimated bit position is not within the margin of error, the on-site controller144calculates a convergence plan in step734. With reference toFIG.7C, for purposes of the present example, the estimated bit position743is outside of the margin of error.

In some embodiments, a projected bit position (not shown) may also be used. For example, the estimated bit position743may be extended via calculations to determine where the bit is projected to be after a certain amount of drilling (e.g., time and/or distance). This information may be used in several ways. If the estimated bit position743is outside the margin of error, the projected bit position743may indicate that the current bit path will bring the bit within the margin of error without any action being taken. In such a scenario, action may be taken only if it will take too long to reach the projected bit position when a more optimal path is available. If the estimated bit position is inside the margin of error, the projected bit position may be used to determine if the current path is directing the bit away from the planned path. In other words, the projected bit position may be used to proactively detect that the bit is off course before the margin of error is reached. In such a scenario, action may be taken to correct the current path before the margin of error is reached.

The convergence plan identifies a plan by which the bit can be moved from the estimated bit position743to the planned path742. It is noted that the convergence plan may bypass the desired bit position741entirely, as the objective is to get the actual drilling path back to the planned path742in the most optimal manner. The most optimal manner may be defined by cost, which may represent a financial value, a reliability value, a time value, and/or other values that may be defined for a convergence path.

As illustrated inFIG.7C, an infinite number of paths may be selected to return the bit to the planned path742. The paths may begin at the estimated bit position743or may begin at other points along a projected path752that may be determined by calculating future bit positions based on the current trajectory of the bit from the estimated bit position752. In the present example, a first path744results in locating the bit at a position745(e.g., a convergence point). The convergence point745is outside of a lower limit753defined by a most aggressive possible correction (e.g., a lower limit on a window of correction). This correction represents the most aggressive possible convergence path, which may be limited by such factors as a maximum directional change possible in the convergence path, where any greater directional change creates a dogleg that makes it difficult or impossible to run casing or perform other needed tasks. A second path746results in a convergence point747, which is right at the lower limit753. A third path748results in a convergence point749, which represents a mid-range convergence point. A third path750results in a convergence point751, which occurs at an upper limit754defined by a maximum convergence delay (e.g., an upper limit on the window of correction).

A fourth path756may begin at a projected point or bit position755that lies along the projected path752and result in a convergence point757, which represents a mid-range convergence point. The path756may be used by, for example, delaying a trajectory change until the bit reaches the position755. Many additional convergence options may be opened up by using projected points for the basis of convergence plans as well as the estimated bit position.

A fifth path758may begin at a projected point or bit position760that lies along the projected path750and result in a convergence point759. In such an embodiment, different convergence paths may include similar or identical path segments, such as the similar or identical path shared by the convergence points751and759to the point760. For example, the point760may mark a position on the path750where a slide segment begins (or continues from a previous slide segment) for the path758and a straight line path segment begins (or continues) for the path750. The surface steerable system144may calculate the paths750and758as two entirely separate paths or may calculate one of the paths as deviating from (e.g., being a child of) the other path. Accordingly, any path may have multiple paths deviating from that path based on, for example, different slide points and slide times.

Each of these paths744,746,748,750,756, and758may present advantages and disadvantages from a drilling standpoint. For example, one path may be longer and may require more sliding in a relatively soft rock layer, while another path may be shorter but may require more sliding through a much harder rock layer. Accordingly, tradeoffs may be evaluated when selecting one of the convergence plans rather than simply selecting the most direct path for convergence. The tradeoffs may, for example, consider a balance between ROP, total cost, dogleg severity, and reliability. While the number of convergence plans may vary, there may be hundreds or thousands of convergence plans in some embodiments and the tradeoffs may be used to select one of those hundreds or thousands for implementation. The convergence plans from which the final convergence plan is selected may include plans calculated from the estimated bit position743as well as plans calculated from one or more projected points along the projected path.

In some embodiments, straight line projections of the convergence point vectors, after correction to the well plan742, may be evaluated to predict the time and/or distance to the next correction requirement. This evaluation may be used when selecting the lowest total cost option by avoiding multiple corrections where a single more forward thinking option might be optimal. As an example, one of the solutions provided by the convergence planning may result in the most cost effective path to return to the well plan742, but may result in an almost immediate need for a second correction due to a pending deviation within the well plan. Accordingly, a convergence path that merges the pending deviation with the correction by selecting a convergence point beyond the pending deviation might be selected when considering total well costs.

It is understood that the diagram740ofFIG.7Cis a two dimensional representation of a three dimensional environment. Accordingly, the illustrated convergence paths in the diagram740ofFIG.7Cmay be three dimensional. In addition, although the illustrated convergence paths all converge with the planned path742, is it understood that some convergence paths may be calculated that move away from the planned path742(although such paths may be rejected). Still other convergence paths may overshoot the actual path742and then converge (e.g., if there isn't enough room to build the curve otherwise). Accordingly, many different convergence path structures may be calculated.

Referring again toFIG.7B, in step736, the on-site controller144produces revised control parameters based on the convergence plan calculated in step734. In step738, the revised control parameters may be output. It is understood that the revised control parameters may be provided to get the drill bit back to the planned path742and the original control parameters may then be used from that point on (starting at the convergence point). For example, if the convergence plan selected the path748, the revised control parameters may be used until the bit reaches position749. Once the bit reaches the position749, the original control parameters may be used for further drilling. Alternatively, the revised control parameters may incorporate the original control parameters starting at the position749or may re-calculate control parameters for the planned path even beyond the point749. Accordingly, the convergence plan may result in control parameters from the bit position743to the position749, and further control parameters may be reused or calculated depending on the particular implementation of the on-site controller144.

Referring toFIG.8A, a method800illustrates a more detailed embodiment of step734ofFIG.7B. It is understood that the convergence plan of step734may be calculated in many different ways, and that800method provides one possible approach to such a calculation when the goal is to find the lowest cost solution vector. In the present example, cost may include both the financial cost of a solution and the reliability cost of a solution. Other costs, such as time costs, may also be included. For purposes of example, the diagram740ofFIG.7Cis used.

In step802, multiple solution vectors are calculated from the current position743to the planned path742. These solution vectors may include the paths744,746,748, and750. Additional paths (not shown inFIG.7C) may also be calculated. The number of solution vectors that are calculated may vary depending on various factors. For example, the distance available to build a needed curve to get back to the planned path742may vary depending on the current bit location and orientation relative to the planned path. A greater number of solution vectors may be available when there is a greater distance in which to build a curve than for a smaller distance since the smaller distance may require a much more aggressive build rate that excludes lesser build rates that may be used for the greater distance. In other words, the earlier an error is caught, the more possible solution vectors there will generally be due to the greater distance over which the error can be corrected. While the number of solution vectors that are calculated in this step may vary, there may be hundreds or thousands of solution vectors calculated in some embodiments.

In step804, any solution vectors that fall outside of defined limits are rejected, such as solution vectors that fall outside the lower limit753and the upper limit754. For example, the path744would be rejected because the convergence point745falls outside of the lower limit753. It is understood that the path744may be rejected for an engineering reason (e.g., the path would require a dogleg of greater than allowed severity) prior to cost considerations, or the engineering reason may be considered a cost.

In step806, a cost is calculated for each remaining solution vector. As illustrated inFIG.7C, the costs may be represented as a cost matrix (that may or may not be weighted) with each solution vector having corresponding costs in the cost matrix. In step808, a minimum of the solution vectors may be taken to identify the lowest cost solution vector. It is understood that the minimum cost is one way of selecting the desired solution vector, and that other ways may be used. Accordingly, step808is concerned with selecting an optimal solution vector based on a set of target parameters, which may include one or more of a financial cost, a time cost, a reliability cost, and/or any other factors, such as an engineering cost like dogleg severity, that may be used to narrow the set of solution vectors to the optimal solution vector.

By weighting the costs, the cost matrix can be customized to handle many different cost scenarios and desired results. For example, if time is of primary importance, a time cost may be weighted over financial and reliability costs to ensure that a solution vector that is faster will be selected over other solution vectors that are substantially the same but somewhat slower, even though the other solution vectors may be more beneficial in terms of financial cost and reliability cost. In some embodiments, step804may be combined with step808and solution vectors falling outside of the limits may be given a cost that ensures they will not be selected. In step810, the solution vector corresponding to the minimum cost is selected.

Referring toFIG.8B, a method820illustrates one embodiment of an event-based process that may be executed by the on-site controller144ofFIG.2A. It is understood that an event may represent many different scenarios in the surface steerable system201. In the present example, in step822, an event may occur that indicates that a prediction is not correct based on what has actually occurred. For example, a formation layer is not where it is expected (e.g., too high or low), a selected bit did not drill as expected, or a selected mud motor did not build curve as expected. The prediction error may be identified by comparing expected results with actual results or by using other detection methods.

In step824, a reason for the error may be determined as the surface steerable system201and its data may provide an environment in which the prediction error can be evaluated. For example, if a bit did not drill as expected, the method820may examine many different factors, such as whether the rock formation was different than expected, whether the drilling parameters were correct, whether the drilling parameters were correctly entered by the driller, whether another error and/or failure occurred that caused the bit to drill poorly, and whether the bit simply failed to perform. By accessing and analyzing the available data, the reason for the failure may be determined.

In step826, a solution may be determined for the error. For example, if the rock formation was different than expected, the database128may be updated with the correct rock information and new drilling parameters may be obtained for the drilling rig110. Alternatively, the current bit may be tripped and replaced with another bit more suitable for the rock. In step828, the current drilling predictions (e.g., well plan, build rate, slide estimates) may be updated based on the solution and the solution may be stored in the database128for use in future predictions. Accordingly, the method820may result in benefits for future wells as well as improving current well predictions.

Referring toFIG.8C, a method830illustrates one embodiment of an event-based process that may be executed by the on-site controller144ofFIG.2A. The method830is directed to recalibration forecasting that may be triggered by an event, such as an event detected in step610ofFIG.6. It is understood that the recalibration described in this embodiment may not be the same as calculating a convergence plan, although calculating a convergence plan may be part of the recalibration. As an example of a recalibration triggering event, a shift in ROP and/or GAMMA readings may indicate that a formation layer (e.g., the layer170A ofFIG.1B) is actually twenty feet higher than planned. This will likely impact the well plan, as build rate predictions and other drilling parameters may need to be changed. Accordingly, in step832, this event is identified.

In step834, a forecast may be made as to the impact of the event. For example, the surface steerable system201may determine whether the projected build rate needed to land the curve can be met based on the twenty foot difference. This determination may include examining the current location of the bit, the projected path, and similar information.

In step836, modifications may be made based on the forecast. For example, if the projected build rate can be met, then modifications may be made to the drilling parameters to address the formation depth difference, but the modifications may be relatively minor. However, if the projected build rate cannot be met, the surface steerable system201may determine how to address the situation by, for example, planning a bit trip to replace the current BHA with a BHA capable of making a new and more aggressive curve.

Such decisions may be automated or may require input or approval by the drilling engineer302, geologist304, or other individuals. For example, depending on the distance to the kick off point, the surface steerable system201may first stop drilling and then send an alert to an authorized individual, such as the drilling engineer302and/or geologist304. The drilling engineer302and geologist304may then become involved in planning a solution or may approve of a solution proposed by the surface steerable system201. In some embodiments, the surface steerable system201may automatically implement its calculated solution. Parameters may be set for such automatic implementation measures to ensure that drastic deviations from the original well plan do not occur automatically while allowing the automatic implementation of more minor measures.

It is understood that such recalibration forecasts may be performed based on many different factors and may be triggered by many different events. The forecasting portion of the process is directed to anticipating what changes may be needed due to the recalibration and calculating how such changes may be implemented. Such forecasting provides cost advantages because more options may be available when a problem is detected earlier rather than later. Using the previous example, the earlier the difference in the depth of the layer is identified, the more likely it is that the build rate can be met without changing the BHA.

Referring toFIG.8D, a method840illustrates one embodiment of an event-based process that may be executed by the on-site controller144ofFIG.2A. The method840is directed to self-tuning that may be performed by the on-site controller144based on factors such as ROP, total cost, and reliability. By self-tuning, the on-site controller144may execute a learning process that enables it to optimize the drilling performance of the drilling rig110. Furthermore, the self-tuning process enables a balance to be reached that provides reliability while also lowering costs. Reliability in drilling operations is often tied to vibration and the problems that vibration can cause, such as stick-slip and whirling. Such vibration issues can damage or destroy equipment and can also result in a very uneven surface in the borehole that can cause other problems such as friction loading of future drilling operations as pipe/casing passes through that area of the borehole. Accordingly, it is desirable to minimize vibration while optimizing performance, since over-correcting for vibration may result in slower drilling than necessary. It is understood that the present optimization may involve a change in any drilling parameter and is not limited to a particular piece of equipment or control system. In other words, parameters across the entire drilling rig110and BHA may be changed during the self-tuning process. Furthermore, the optimization process may be applied to production by optimizing well smoothness and other factors affecting production. For example, by minimizing dogleg severity, production may be increased for the lifetime of the well.

Accordingly, in step842, one or more target parameters are identified. For example, the target parameter may be an MSE of 50 ksi or an ROP of 100 ft/hr that the on-site controller144is to establish and maintain. In step844, a plurality of control parameters are identified for use with the drilling operation. The control parameters are selected to meet the target MSE of 50 ksi or ROP of 100 ft/hr. The drilling operation is started with the control parameters, which may be used until the target MSE or ROP is reached. In step846, feedback information is received from the drilling operation when the control parameters are being used, so the feedback represents the performance of the drilling operation as controlled by the control parameters. Historical information may also be used in step846. In step848, an operational baseline is established based on the feedback information.

In step850, at least one of the control parameters is changed to modify the drilling operation, although the target MSE or ROP should be maintained. For example, some or all of the control parameters may be associated with a range of values and the value of one or more of the control parameters may be changed. In step852, more feedback information is received, but this time the feedback reflects the performance of the drilling operation with the changed control parameter. In step854, a performance impact of the change is determined with respect to the operational baseline. The performance impact may occur in various ways, such as a change in MSE or ROP and/or a change in vibration. In step856, a determination is made as to whether the control parameters are optimized. If the control parameters are not optimized, the method840returns to step850. If the control parameters are optimized, the method840moves to step858. In step858, the optimized control parameters are used for the current drilling operation with the target MSE or ROP and stored (e.g., in the database128) for use in later drilling operations and operational analyses. This may include linking formation information to the control parameters in the regional database128.

Referring toFIG.9, one embodiment of a system architecture900is illustrated that may be used for the on-site controller144ofFIG.1A. The system architecture900includes interfaces configured to interact with external components and internal modules configured to process information. The interfaces may include an input driver902, a remote synchronization interface904, and an output interface918, which may include at least one of a graphical user interface (GUI)906and an output driver908. The internal modules may include a database query and update engine/diagnostic logger910, a local database912(which may be similar or identical to the database410ofFIG.4), a guidance control loop (GCL) module914, and an autonomous control loop (ACL) module916. It is understood that the system architecture900is merely one example of a system architecture that may be used for the on-site controller144and the functionality may be provided for the on-site controller144using many different architectures. Accordingly, the functionality described herein with respect to particular modules and architecture components may be combined, further separated, and organized in many different ways.

It is understood that the computer steerable system144may perform certain computations to prevent errors or inaccuracies from accumulating and throwing off calculations. For example, as will be described later, the input driver902may receive Wellsite Information Transfer Specification (WITS) input representing absolute pressure, while the surface steerable system144needs differential pressure and needs an accurate zero point for the differential pressure. Generally, the driller will zero out the differential pressure when the drillstring is positioned with the bit off bottom and full pump flow is occurring. However, this may be a relatively sporadic event. Accordingly, the surface steerable system144may recognize when the bit is off bottom and target flow rate has been achieved and zero out the differential pressure.

Another computation may involve block height, which needs to be calibrated properly. For example, block height may oscillate over a wide range, including distances that may not even be possible for a particular drilling rig. Accordingly, if the reported range is sixty feet to one hundred and fifty feet and there should only be one hundred feet, the surface steerable system144may assign a zero value to the reported sixty feet and a one hundred foot value to the reported one hundred and fifty feet. Furthermore, during drilling, error gradually accumulates as the cable is shifted and other events occur. The surface steerable system144may compute its own block height to predict when the next connection occurs and other related events, and may also take into account any error that may be introduced by cable issues.

Referring specifically toFIG.9, the input driver902provides output to the GUI906, the database query and update engine/diagnostic logger910, the GCL914, and the ACL916. The input driver902is configured to receive input for the on-site controller144. It is understood that the input driver902may include the functionality needed to receive various file types, formats, and data streams. The input driver902may also be configured to convert formats if needed. Accordingly, the input driver902may be configured to provide flexibility to the on-site controller144by handling incoming data without the need to change the internal modules. In some embodiments, for purposes of abstraction, the protocol of the data stream can be arbitrary with an input event defined as a single change (e.g., a real time sensor change) of any of the given inputs.

The input driver902may receive various types of input, including rig sensor input (e.g., from the sensor system214ofFIG.2A), well plan data, and control data (e.g., engineering control parameters). For example, rig sensor input may include hole depth, bit depth, toolface, inclination, azimuth, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary RPMs, bit speed, ROP, and WOB. The well plan data may include information such as projected starting and ending locations of various geologic layers at vertical depth points along the well plan path, and a planned path of the borehole presented in a three dimensional space. The control data may be used to define maximum operating parameters and other limitations to control drilling speed, limit the amount of deviation permitted from the planned path, define levels of authority (e.g., can an on-site operator make a particular decision or should it be made by an off-site engineer), and similar limitations. The input driver902may also handle manual input, such as input entered via a keyboard, a mouse, or a touch screen. In some embodiments, the input driver902may also handle wireless signal input, such as from a cell phone, a smart phone, a PDA, a tablet, a laptop, or any other device capable of wirelessly communicating with the on-site controller144through a network locally and/or offsite.

The database query and update engine/diagnostic logger910receives input from the input driver902, the GCL914, and ACL916, and provides output to the local database912and GUI906. The database query and update engine/diagnostic logger910is configured to manage the archiving of data to the local database912. The database query and update engine/diagnostic logger910may also manage some functional requirements of a remote synchronization server (RSS) via the remote synchronization interface904for archiving data that will be uploaded and synchronized with a remote database, such as the database128ofFIG.1A. The database query and update engine/diagnostic logger910may also be configured to serve as a diagnostic tool for evaluating algorithm behavior and performance against raw rig data and sensor feedback data.

The local database912receives input from the database query and update engine/diagnostic logger910and the remote synchronization interface904, and provides output to the GCL914, the ACL916, and the remote synchronization interface904. It is understood that the local database912may be configured in many different ways. As described in previous embodiments, the local database912may store both current and historic information representing both the current drilling operation with which the on-site controller144is engaged as well as regional information from the database128.

The GCL914receives input from the input driver902and the local database912, and provides output to the database query and update engine/diagnostic logger910, the GUI906, and the ACL916. Although not shown, in some embodiments, the GCL906may provide output to the output driver908, which enables the GCL914to directly control third party systems and/or interface with the drilling rig alone or with the ACL916. An embodiment of the GCL914is discussed below with respect toFIG.11.

The ACL916receives input from the input driver902, the local database912, and the GCL914, and provides output to the database query and update engine/diagnostic logger910and output driver908. An embodiment of the ACL916is discussed below with respect toFIG.12.

The output interface918receives input from the input driver902, the GCL914, and the ACL916. In the present example, the GUI906receives input from the input driver902and the GCL914. The GUI906may display output on a monitor or other visual indicator. The output driver908receives input from the ACL916and is configured to provide an interface between the on-site controller144and external control systems, such as the control systems208,210, and212ofFIG.2A.

It is understood that the system architecture900ofFIG.9may be configured in many different ways. For example, various interfaces and modules may be combined or further separated. Accordingly, the system architecture900provides one example of how functionality may be structured to provide the on-site controller144, but the on-site controller144is not limited to the illustrated structure ofFIG.9.

Referring toFIG.10, one embodiment of the input driver902of the system architecture900ofFIG.9is illustrated in greater detail. In the present example, the input driver902may be configured to receive input via different input interfaces, such as a serial input driver1002and a Transmission Control Protocol (TCP) driver1004. Both the serial input driver1002and the TCP input driver1004may feed into a parser1006.

The parser1006in the present example may be configured in accordance with a specification such as WITS and/or using a standard such as Wellsite Information Transfer Standard Markup Language (WITSML). WITS is a specification for the transfer of drilling rig-related data and uses a binary file format. WITS may be replaced or supplemented in some embodiments by WITSML, which relies on eXtensible Markup Language (XML) for transferring such information. The parser1006may feed into the database query and update engine/diagnostic logger910, and also to the GCL914and GUI906as illustrated by the example parameters of block1010. The input driver902may also include a non-WITS input driver1008that provides input to the ACL916as illustrated by block1012.

Referring toFIG.11, one embodiment of the GCL914ofFIG.9is illustrated in greater detail. In the present example, the GCL914may include various functional modules, including a build rate predictor1102, a geo modified well planner1104, a borehole estimator1106, a slide estimator1108, an error vector calculator1110, a geological drift estimator1112, a slide planner1114, a convergence planner1116, and a tactical solution planner1118. In the following description of the GCL914, the term external input refers to input received from outside the GCL914(e.g., from the input driver902ofFIG.9), while internal input refers to input received by a GCL module from another GCL module.

The build rate predictor1102receives external input representing BHA and geological information, receives internal input from the borehole estimator1106, and provides output to the geo modified well planner1104, slide estimator1108, slide planner1114, and convergence planner1116. The build rate predictor1102is configured to use the BHA and geological information to predict the drilling build rates of current and future sections of a well. For example, the build rate predictor1102may determine how aggressively the curve will be built for a given formation with given BHA and other equipment parameters.

The build rate predictor1102may use the orientation of the BHA to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if there is a layer of rock with a layer of sand above it, there is a formation transition from the sand layer to the rock layer. Approaching the rock layer at a ninety degree angle may provide a good face and a clean drill entry, while approaching the rock layer at a forty-five degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause the bit to skip off the upper surface of the rock layer. Accordingly, the build rate predictor1102may calculate BHA orientation to account for formation transitions. Within a single layer, the build rate predictor1102may use BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a layer.

The BHA information may include bit characteristics, mud motor bend setting, stabilization and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information enables a calculation-based prediction of the build rates and ROP that may be compared to both real time results (e.g., obtained while drilling the well) and regional historical results (e.g., from the database128) to improve the accuracy of predictions as the drilling progresses. Future formation build rate predictions may be used to plan convergence adjustments and confirm that targets can be achieved with current variables in advance.

The geo modified well planner1104receives external input representing a well plan, internal input from the build rate predictor1102and the geo drift estimator1112, and provides output to the slide planner1114and the error vector calculator1110. The geo modified well planner1104uses the input to determine whether there is a more optimal path than that provided by the external well plan while staying within the original well plan error limits. More specifically, the geo modified well planner1104takes geological information (e.g., drift) and calculates whether another solution to the target may be more efficient in terms of cost and/or reliability. The outputs of the geo modified well planner1104to the slide planner1114and the error vector calculator1110may be used to calculate an error vector based on the current vector to the newly calculated path and to modify slide predictions.

In some embodiments, the geo modified well planner1104(or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, the geologist304may provide the surface steerable system144with a target inclination that the surface steerable system144is to attempt to hold. For example, the geologist304may provide a target to the directional driller306of 90.5-91 degrees of inclination for a section of the well. The geologist304may enter this information into the surface steerable system144and the directional driller306may retrieve the information from the surface steerable system144. The geo modified well planner1104may then treat the target as a vector target, for example, either by processing the information provided by the geologist304to create the vector target or by using a vector target entered by the geologist304. The geo modified well planner1104may accomplish this while remaining within the error limits of the original well plan.

In some embodiments, the geo modified well planner1104may be an optional module that is not used unless the well plan is to be modified. For example, if the well plan is marked in the surface steerable system201as non-modifiable, the geo modified well planner1104may be bypassed altogether or the geo modified well planner1104may be configured to pass the well plan through without any changes.

The borehole estimator1106receives external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and provides outputs to the build rate predictor1102, the error vector calculator1110, and the convergence planner1116. The borehole estimator1106is configured to provide a real time or near real time estimate of the actual borehole and drill bit position and trajectory angle. This estimate may use both straight line projections and projections that incorporate sliding. The borehole estimator1106may be used to compensate for the fact that a sensor is usually physically located some distance behind the bit (e.g., fifty feet), which makes sensor readings lag the actual bit location by fifty feet. The borehole estimator1106may also be used to compensate for the fact that sensor measurements may not be continuous (e.g., a sensor measurement may occur every one hundred feet).

The borehole estimator1106may use two techniques to accomplish this. First, the borehole estimator1106may provide the most accurate estimate from the surface to the last survey location based on the collection of all survey measurements. Second, the borehole estimator1106may take the slide estimate from the slide estimator1108(described below) and extend this estimation from the last survey point to the real time drill bit location. Using the combination of these two estimates, the borehole estimator1106may provide the on-site controller144with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process. For example, the borehole estimator1106may calculate the current bit position and trajectory743inFIG.7C.

The slide estimator1108receives external inputs representing measured depth and differential pressure information, receives internal input from the build rate predictor1102, and provides output to the borehole estimator1106and the geo modified well planner1104. The slide estimator1108, which may operate in real time or near real time, is configured to sample toolface orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantify/estimate a deviation vector and progress while sliding.

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 MWD survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by the distance of the sensor point from the drill bit tip (e.g., approximately fifty feet). This lag introduces inefficiencies in the slide cycles due to over/under correction of the actual path relative to the planned path.

With the slide estimator1108, each toolface update is algorithmically merged with the average differential pressure of the period between the previous and current toolfaces, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during that period. As an example, the periodic rate may be between ten and sixty seconds per cycle depending on the tool face update rate of the MWD tool. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of the slide estimator1108is periodically provided to the borehole estimator1106for accumulation of well deviation information, as well to the geo modified well planner1104. Some or all of the output of the slide estimator1108may be output via a display such as the display250ofFIG.2B.

The error vector calculator1110receives internal input from the geo modified well planner1104and the borehole estimator1106. The error vector calculator1110is configured to compare the planned well path to the actual borehole path and drill bit position estimate. The error vector calculator1110may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the plan. For example, the error vector calculator1110may calculate the error between the current position743ofFIG.7Cto the planned path742and the desired bit position741. The error vector calculator1110may also calculate a projected bit position/projected path representing the future result of a current error as described previously with respect toFIG.7B.

The geological drift estimator1112receives external input representing geological information and provides outputs to the geo modified well planner1104, slide planner1114, and tactical solution planner1118. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of drilling rate and BHA. The geological drift estimator1112is configured to provide a drift estimate as a vector. This vector can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.

The slide planner1114receives internal input from the build rate predictor1102, the geo modified well planner1104, the error vector calculator1110, and the geological drift estimator1112, and provides output to the convergence planner1116as well as an estimated time to the next slide. The slide planner1114is configured to evaluate a slide/drill ahead cost equation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the well plan path. During drill ahead, the slide planner1114may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., beads) are needed for the next slide and pumping the lubricants into the drill string needs to begin thirty minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants.

Functionality for a loss circulation material (LCM) planner may be provided as part of the slide planner1114or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives need to be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.

The slide planner1114may also look at the current position relative to the next connection. A connection may happen every ninety to one hundred feet (or some other distance or distance range based on the particulars of the drilling operation) and the slide planner1114may avoid planning a slide when close to a connection and/or when the slide would carry through the connection. For example, if the slide planner1114is planning a fifty foot slide but only twenty feet remain until the next connection, the slide planner1114may calculate the slide starting after the next connection and make any changes to the slide parameters that may be needed to accommodate waiting to slide until after the next connection. This avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the toolface before finishing the slide. During slides, the slide planner1114may provide some feedback as to the progress of achieving the desired goal of the current slide.

In some embodiments, the slide planner1114may account for reactive torque in the drillstring. More specifically, when rotating is occurring, there is a reactional torque wind up in the drillstring. When the rotating is stopped, the drillstring unwinds, which changes toolface orientation and other parameters. When rotating is started again, the drillstring starts to wind back up. The slide planner1114may account for this reactional torque so that toolface references are maintained rather than stopping rotation and then trying to adjust to an optimal tool face orientation. While not all MWD tools may provide toolface orientation when rotating, using one that does supply such information for the GCL914may significantly reduce the transition time from rotating to sliding.

The convergence planner1116receives internal inputs from the build rate predictor1102, the borehole estimator1106, and the slide planner1114, and provides output to the tactical solution planner1118. The convergence planner1116is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well path. The convergence plan represents a path from the current drill bit position to an achievable and optimal convergence target point along the planned path. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by the slide planner1114. The convergence planner1116may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to the build rate predictor1102. The solution provided by the convergence planner1116defines a new trajectory solution for the current position of the drill bit. The solution may be real time, near real time, or future (e.g., planned for implementation at a future time). For example, the convergence planner1116may calculate a convergence plan as described previously with respect toFIGS.7C and8.

The tactical solution planner1118receives internal inputs from the geological drift estimator1112and the convergence planner1116, and provides external outputs representing information such as toolface orientation, differential pressure, and mud flow rate. The tactical solution planner1118is configured to take the trajectory solution provided by the convergence planner1116and translate the solution into control parameters that can be used to control the drilling rig110. For example, the tactical solution planner1118may take the solution and convert the solution into settings for the control systems208,210, and212to accomplish the actual drilling based on the solution. The tactical solution planner1118may also perform performance optimization as described previously. The performance optimization may apply to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by the GCL914in 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 toolface. Accordingly, the GCL914may receive information corresponding to the rotational position of the drill pipe on the surface. The GCL914may use this surface positional information to calculate current and desired toolface orientations. These calculations may then be used to define control parameters for adjusting the top drive or Kelly drive to accomplish adjustments to the downhole toolface in order to steer the well.

For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with the GCL914and/or other components of the on-site controller144. In the present embodiment, a drilling model class is defined to capture and define the drilling state throughout the drilling process. The class may include real time information. This 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 class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of the GCL914.

The drill bit model may represent the current position and state of the drill bit. This model includes a three dimensional position, a drill bit trajectory, BHA information, bit speed, and toolface (e.g., orientation information). The three dimensional 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 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. This model includes 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 the current drilling job. The borehole diameters represent the diameters of the borehole as drilled over the current drill job.

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 drawworks 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 RPMs to the defined level. The control output solution represents the control parameters for the drilling rig110.

The main processing loop can be handled in many different ways. For example, the main processing loop can run as a single thread in a fixed time loop to handle rig sensor event changes and time propagation. If no rig sensor updates occur between fixed time intervals, a time only propagation may occur. In other embodiments, the main processing loop may be multi-threaded.

Each functional module of the GCL914may have its behavior encapsulated within its own respective class definition. During its processing window, the individual units may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the modules may be in the sequence of geo modified well planner1104, build rate predictor1102, slide estimator1108, borehole estimator1106, error vector calculator1110, slide planner1114, convergence planner1116, geological drift estimator1112, and tactical solution planner1118. It is understood that other sequences may be used.

In the present embodiment, the GCL914may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. While the on-site controller144may rely purely on timer and date calls driven by the programming environment (e.g., java), this would limit timing to be exclusively driven by system time. In situations where it may be advantageous to manipulate the clock (e.g., for evaluation and/or testing), the programmable timer module may be used to alter the time. For example, the programmable timer module may enable a default time set to the system time and a time scale of 1.0, may enable the system time of the on-site controller144to be manually set, may enable the time scale relative to the system time to be modified, and/or may enable periodic event time requests scaled to the time scale to be requested.

Referring toFIG.12, one embodiment of the ACL916provides different functions to the on-site controller144. The ACL916may be considered a second feedback control loop that operates in conjunction with a first feedback control loop provided by the GCL914. The ACL916may also provide actual instructions to the drilling rig110, either directly to the drilling equipment216or via the control systems208,210, and212. The ACL916may include a positional/rotary control logic block1202, WOB/differential pressure control logic block1204, fluid circulation control logic block1206, and a pattern recognition/error detection block1208.

One function of the ACL916is to establish and maintain a target parameter (e.g., an ROP of a defined value of ft/hr) based on input from the GCL914. This may be accomplished via control loops using the positional/rotary control logic block1202, WOB/differential pressure control logic block1204, and fluid circulation control logic block1206. The positional/rotary control logic block1202may receive sensor feedback information from the input driver902and set point information from the GCL914(e.g., from the tactical solution planner1118). The differential pressure control logic block1204may receive sensor feedback information from the input driver902and set point information from the GCL914(e.g., from the tactical solution planner1118). The fluid circulation control logic block1206may receive sensor feedback information from the input driver902and set point information from the GCL914(e.g., from the tactical solution planner1118).

The ACL916may use the sensor feedback information and the set points from the GCL914to attempt to maintain the established target parameter. More specifically, the ACL916may have control over various parameters via the positional/rotary control logic block1202, WOB/differential pressure control logic block1204, and fluid circulation control logic block1206, and may modulate the various parameters to achieve the target parameter. The ACL916may also modulate the parameters in light of cost-driven and reliability-driven drilling goals, which may include parameters such as a trajectory goal, a cost goal, and/or a performance goal. It is understood that the parameters may be limited (e.g., by control limits set by the drilling engineer306) and the ACL916may vary the parameters to achieve the target parameter without exceeding the defined limits. If this is not possible, the ACL916may notify the on-site controller144or otherwise indicate that the target parameter is currently unachievable.

In some embodiments, the ACL916may continue to modify the parameters to identify an optimal set of parameters with which to achieve the target parameter for the particular combination of drilling equipment and formation characteristics. In such embodiments, the on-site controller144may export the optimal set of parameters to the database128for use in formulating drilling plans for other drilling projects.

Another function of the ACL916is error detection. Error detection is directed to identifying problems in the current drilling process and may monitor for sudden failures and gradual failures. In this capacity, the pattern recognition/error detection block1208receives input from the input driver902. The input may include the sensor feedback received by the positional/rotary control logic block1202, WOB/differential pressure control logic block1204, and fluid circulation control logic block1206. The pattern recognition/error detection block1208monitors the input information for indications that a failure has occurred or for sudden changes that are illogical.

For example, a failure may be indicated by an ROP shift, a radical change in build rate, or any other significant changes. As an illustration, assume the drilling is occurring with an expected ROP of 100 ft/hr. If the ROP suddenly drops to 50 ft/hr with no change in parameters and remains there for some defined amount of time, an equipment failure, formation shift, or another event has occurred. Another error may be indicated when MWD sensor feedback has been steadily indicating that drilling has been heading north for hours and the sensor feedback suddenly indicates that drilling has reversed in a few feet and is heading south. This change clearly indicates that a failure has occurred. The changes may be defined and/or the pattern recognition/error detection block1208may be configured to watch for deviations of a certain magnitude. The pattern recognition/error detection block1208may also be configured to detect deviations that occur over a period of time in order to catch more gradual failures or safety concerns.

When an error is identified based on a significant shift in input values, the on-site controller201may send an alert. This enables an individual to review the error and determine whether action needs to be taken. For example, if an error indicates that there is a significant loss of ROP and an intermittent change/rise in pressure, the individual may determine that mud motor chunking has likely occurred with rubber tearing off and plugging the bit. In this case, the BHA may be tripped and the damage repaired before more serious damage is done. Accordingly, the error detection may be used to identify potential issues that are occurring before they become more serious and more costly to repair.

Another function of the ACL916is pattern recognition. Pattern recognition is directed to identifying safety concerns for rig workers and to provide warnings (e.g., if a large increase in pressure is identified, personnel safety may be compromised) and also to identifying problems that are not necessarily related to the current drilling process, but may impact the drilling process if ignored. In this capacity, the pattern recognition/error detection block1208receives input from the input driver902. The input may include the sensor feedback received by the positional/rotary control logic block1202, WOB/differential pressure control logic block1204, and fluid circulation control logic block1206. The pattern recognition/error detection block1208monitors the input information for specific defined conditions. A condition may be relatively common (e.g., may occur multiple times in a single borehole) or may be relatively rare (e.g., may occur once every two years). Differential pressure, standpipe pressure, and any other desired conditions may be monitored. If a condition indicates a particular recognized pattern, the ACL916may determine how the condition is to be addressed. For example, if a pressure spike is detected, the ACL916may determine that the drilling needs to be stopped in a specific manner to enable a safe exit. Accordingly, while error detection may simply indicate that a problem has occurred, pattern recognition is directed to identifying future problems and attempting to provide a solution to the problem before the problem occurs or becomes more serious.

Referring toFIG.13, one embodiment of a computer system1300is illustrated. The computer system1300is one possible example of a system component or device such as the on-site controller144ofFIG.1A. In scenarios where the computer system1300is on-site, such as at the location of the drilling rig110ofFIG.1A, the computer system may be contained in a relatively rugged, shock-resistant case that is hardened for industrial applications and harsh environments.

The computer system1300may include a central processing unit (“CPU”)1302, a memory unit1304, an input/output (“I/O”) device1306, and a network interface1308. The components1302,1304,1306, and1308are interconnected by a transport system (e.g., a bus)1310. A power supply (PS)1312may provide power to components of the computer system1300, such as the CPU1302and memory unit1304. It is understood that the computer system1300may be differently configured and that each of the listed components may actually represent several different components. For example, the CPU1302may actually represent a multi-processor or a distributed processing system; the memory unit1304may include different levels of cache memory, main memory, hard disks, and remote storage locations; the I/O device1306may include monitors, keyboards, and the like; and the network interface1308may include one or more network cards providing one or more wired and/or wireless connections to a network1314. Therefore, a wide range of flexibility is anticipated in the configuration of the computer system1300.

The computer system1300may use any operating system (or multiple operating systems), including various versions of operating systems provided by Microsoft (such as WINDOWS), Apple (such as Mac OS X), UNIX, and LINUX, and may include operating systems specifically developed for handheld devices, personal computers, and servers depending on the use of the computer system1300. The operating system, as well as other instructions (e.g., software instructions for performing the functionality described in previous embodiments) may be stored in the memory unit1304and executed by the processor1302. For example, if the computer system1300is the on-site controller144, the memory unit1304may include instructions for performing methods such as the methods600ofFIG.6,700ofFIG.7A,720ofFIG.7B,800ofFIG.8A,820ofFIG.8B,830ofFIG.8C, and840ofFIG.8D.

Referring toFIGS.14A-14D, embodiments of sections of the borehole164ofFIG.1Bare illustrated.FIG.14Aillustrates an embodiment of the borehole164where the slide occurs in the middle of the section. The slide is planned to begin at a point marked by line1402and end at a point marked by line1404. Sequential survey points1406and1408mark locations where measured surveys occur. Being sequential, there is no survey point between the two survey points1406and1408.FIG.14Billustrates an embodiment of the borehole164awhere the slide occurs at the beginning of the section (e.g., right after the survey point1406).FIG.14Cillustrates an embodiment of the borehole164bwhere the slide occurs at the end of the section (e.g., leading up to the survey point1408).FIG.14Dillustrates an embodiment of the borehole164cwhere the slide occurs for the entire distance between the survey points1406and1408.FIG.14Eillustrates the boreholes164a-164c(not to scale) overlaid on one another.

Referring specifically toFIG.14A, in the present example, two possible paths1410and1412are illustrated between the survey points1406and1408. The two paths1410and1412are used herein to illustrate what may happen in the borehole164between the two survey points1406and1408. As described previously, surveys may occur at defined intervals, such as every thirty, forty-five, or ninety feet. For example, a survey may occur each time a new section of pipe (e.g., a joint) is added to the drill string. If the sections are approximately thirty feet long and a survey is taken every three sections (e.g., a stand), the surveys may occur approximately every ninety feet. Constant surveying is generally not practical as performing a survey may take a relatively substantial amount of time (e.g., from five to twenty minutes) and, in addition, control of the reactional torque neutral point may be lost. Between surveys, the state of the drilling (e.g., orientation of the bit and distance drilled) is not generally known. Accordingly, the path between the survey points1406and1408is unknown. This lack of knowledge may affect various aspects of drilling the borehole164, as well as the final efficiency of the well.

For example, assume that the planned borehole164includes a fifty foot slide (from point1402to point1404) and the slide occurs between the survey points1406and1408. One possible path1410for the slide occurs when the drilling is held almost perfectly on course, which would result in a slide of approximately fifty feet (assuming other factors are ideal). However, another possible path1412occurs when the drilling does not stay on course. In the present example, the path1412is not even on course prior to the line1402that represents the beginning of the slide. As the shortest distance between the points1406and1408is a straight line (or an arc at the maximum build rate), the path1410is more efficient than the path1412in making progress toward the target. Furthermore, not only is the path1412less efficient in reaching the target, it also forms a less ideal borehole in terms of tortuosity as described in greater detail below.

It is understood, as described previously, that there may be a survey point offset where the survey point is actually located some distance behind the bit and so the survey location may not represent the actual bit location. Because of this offset distance, a survey is accurate only to a certain distance (e.g., fifty feet behind the bit) and there is usually some uncertainty in the path ahead of the survey point to where the bit is actually located. Accordingly, knowing the actual path past a survey point may also be beneficial as illustrated by path segment1413extending from survey point1408.

In addition to providing information about drilling efficiency, knowing what occurs between the survey points1406and1408may enable the effective build rate of the BHA to be assessed more objectively because the build rate orientation stability can be taken into account. If the build rate orientation stability is not taken into account, the second path1412that lacks orientation stability may be included in the assessment, which would make the BHA seem less efficient than it actually was. In turn, the more accurate assessment of the actual path of the BHA aids in the accuracy of later drilling predictions (e.g., build rate predictions).

Knowledge of what occurs between survey points may also aid in addressing drilling problems such as tortuosity in the borehole that may impact whether casing can be run, increase friction in the drill string, affect lubrication planning for slides, and other issues. For example, dogleg severity is often viewed as the change of angle between two sequential survey points. However, this view provides no information as to whether a dogleg exists between the survey points and, if one does exist, how severe it is. Furthermore, the orientation of the doglegs may create even more severe problems. For example, a dogleg created by a left arc that is immediately followed by a dogleg created by a right arc may be more problematic than if the following dogleg is also a left arc. In other words, sequential doglegs that arc in generally the same direction may be preferable to sequential doglegs that arc in opposite directions. Accordingly, the survey points may show a dogleg characterized by a five degree per hundred foot severity (5°/100′), while the actual path may include a dogleg of 10°/100′ at one point, 5°/100′ at another point, et cetera, between the survey points, and these doglegs may have different orientations.

Knowing what is happening between the survey points and accumulating such information over the course of the well enables problems to be addressed by implementing one or more solutions before drilling continues, during later drilling, and even after drilling. For example, the ability to measure tortuosity in real time or near real time may enable determinations to be made during drilling such as whether lubrication is needed, how and when to apply the lubrication, and whether back reaming a particular section of the borehole is needed. Such information may also be used to determine whether a planned well should be stopped early. After the well is completed, the use of path information that is higher resolution than the information provided by the survey points may be used to improve the well, such as in a determination on where to focus reaming activity (e.g., at a problem area at ten thousand feet).

It is understood that information about what is occurring between survey points may also be useful even when not sliding. For example, drift caused by formation characteristics may affect the path even when drilling straight ahead. Accordingly, current location estimates may be useful regardless of the type of drilling (e.g., rotating or sliding).

Referring toFIG.15, one embodiment of a three-dimensional borehole space1500is illustrated with two measured survey points1502(also labeled as “A”) and1504(also labeled as “C”). A borehole path (not shown) extends between the two survey points1502and1504, but the actual path is unknown. Current borehole projection methods frequently use a minimum curvature technique for estimating the borehole projection between the two survey points1502and1504. Assuming the initial borehole position is known as well as its initial survey trajectory, there may be only a subsequent measure of additional borehole length and a new survey trajectory that can be measured from surface and downhole instruments that are available.

InFIG.15, the borehole space is presented in Cartesian space with a North-South (N) axis1508, an East-West (E) axis1510, an Up-Down Vertical (V) axis1512, and a borehole trajectory where an inclination angle represents the vertical component and a compass style azimuth angle represents the horizontal component. The initial survey point1502has an inclination and azimuth trajectory of α1 and ε1, respectively, and the second survey point1504has an inclination and azimuth trajectory of α2 and ε2, respectively.

With only new survey trajectory and path length information available, an assumption must be made about the shape of the borehole between the survey points1502and1504. The minimum curvature method works off the assumption that the borehole moves along the smoothest possible arc between two survey points. This arc is represented by arc1514. The change in trajectory angle from survey point1502to survey point1504(β) is often referred to as a dogleg in the context of surveying. The path ABC (where B is also labeled as point1506) represents the balanced tangential method path, whereby a borehole projection is estimated by two line segments which intersect at the point where the curvature angle, β, is evenly bisected. This bisection point is point1506in the present example. This is a useful case, as the minimum curvature method represents a special case of the balanced tangential method where the two line segments are substituted with a circular arc curve (e.g., the arc1514) that also passes through points1502and1504with tangents at those points aligned with their respective trajectories. The equations for the curve AB are the same as the balanced tangential method for calculating path ABC except for the application of the ratio factor (RF):

Δ⁢V=Δ⁢M⁢D2[cos⁢α⁢1+cos⁢α⁢2]×RF(Equation⁢1)Δ⁢N=Δ⁢M⁢D2[sin⁢α⁢1×cos⁢ε⁢1+sin⁢α⁢2×cos⁢ε⁢2]×RF(Equation⁢2)Δ⁢E⁢Δλ⁢MD2[sin⁢α⁢1×sin⁢ε⁢1+sin⁢α⁢2×sin⁢ε⁢2]×RF(Equation⁢3)

When using Equations 1-3 for estimating borehole positions between measured survey points, ΔMD represents an increase in measured depth progress between two survey trajectory measurements.

The ratio factor (RF) is used to account for the path length difference between the length of ABC and the length of the minimum curvature arc which crosses through AC. RF is given by the equation:

R⁢F=2β⁢tan⁢β2(Equation⁢4)

The minimum curvature method may result in significant inaccuracy as shown in the following examples. There are two basic assumptions in these examples. The first is that the example starts from a ninety degree inclination. The second is that all sliding is two-dimensional in the vertical plane.

Table 1, shown below, illustrates a scenario where a slide has occurred.

TABLE 1DescriptionValueUnitsTotal MD Increment100ftBetween SurveysSlide/Build Duration15ftInstantaneous Build Rate12Degrees/100 ftInclination Change1.8Degrees

For purposes of illustration, the distance between surveys is equal to one hundred feet and is used as a surface measurement of the total measured depth increment. Accordingly, the total measured depth increment between surveys in Table 1 is one hundred feet. The slide lasted for fifteen feet and had an instantaneous build rate of twelve degrees per one hundred feet, so the inclination change over the twelve foot slide was 1.8 degrees.

Table 2, shown below, illustrates two scenarios where a slide has occurred. The first column contains two rows, with each row indicating whether the slide occurred at the beginning of the one hundred foot distance (one embodiment of which is illustrated inFIG.14B) or at the end (one embodiment of which is illustrated inFIG.14C).

TABLE 2TraditionalInterpretedCurveFormation DipFitInterpretedError OverMDTVDTVDTVDSurvey PeriodchangechangechangeerrorDue to TVD(ft)(ft)(ft)(ft)Error (degrees)Slide before1002.9061.5711.3350.765RotateRotate1000.2361.571−1.335−0.765before Slide

In the first row where sliding occurred before rotation, the TVD change is 2.906 feet. Using the previously presented equations for curve fitting, the curve fit TVD change is 1.571 feet. This results in an interpreted TVD error of 1.335 feet and an interpreted formation dip error of 0.765 degrees. In the second row where sliding occurred after rotation, the TVD change is 0.236 feet. Using the previously presented equations for curve fitting, the curve fit TVD change is 1.571 feet. In other words, the curve fit TVD change is the same as in row one. The curve fit TVD change of 1.571 results in an interpreted TVD error of −1.335 feet and an interpreted formation dip error of −0.765 degrees.

Although the errors may cancel each other out relative to the entire well (e.g., an error in one direction may be canceled by an equal error in the opposite direction), the errors in a given direction accumulate and there is more accumulation the longer that a slide occurs in a particular direction.

As illustrated in Table 2, the curve fit TVD change for a particular set of slide/build duration and instantaneous build rate values remains constant regardless of whether sliding occurs before or after rotation even though the TVD change is different based on whether sliding occurs before or after rotation. This difference between the curve fit TVD change and the total TVD change occurs for different values of slide/build duration and instantaneous build rate in Table 1. The curve fit TVD change and the total TVD change may only match in two scenarios. The first is when the slide occurs for the full one hundred feet (e.g., slide/build duration is set to 100 in Table 1), as the borehole shape may be estimated as an arc between the two survey points (one embodiment of which is illustrated inFIG.14D). The second is when the slide is symmetrically centered on the midpoint between survey points. As illustrated inFIG.14E, the boreholes164a-164cofFIGS.14B-14Dmay vary significantly for the same curve fit TVD change.

Accordingly, using only information from two measured survey points to estimate the state of the drilling (e.g., orientation of the bit and distance drilled) between the two survey points may result in significant inaccuracies. These inaccuracies may negatively impact drilling efficiency, the ability to objectively identify well plan corrections, the ability to characterize formation position and dip angles, and/or similar issues. Furthermore, problems such as tortuosity may be more difficult to identify and address. Inaccurate TVD information may result in difficulties in following the target layer (e.g., the layer172A ofFIG.1B), as even seemingly minor variations in inclination (e.g., one half of one degree) may cause the drill bit to exit the target layer.

Referring toFIG.16, a method1600illustrates one embodiment of a process that may be executed by the on-site controller144ofFIG.2Aand/or another part of the surface steerable system201. For example, software instructions needed to execute the method1600may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144.

In the present example, the method1600may be used to estimate the position of the drill bit between survey points during straight drilling and/or during a sliding operation. The method1600may provide more accurate information on the state of the drilling (e.g., orientation of the bit and distance drilled) than that provided by the minimum curvature method described above.

In step1602, toolface and other non-survey sensor information is received. The toolface information may be relayed from the toolface periodically, such as at set intervals of between ten and thirty seconds. The non-survey sensor information may include any type of data, such as differential pressure and may be continuous or non-continuous. As the toolface information may be obtained at set intervals and the other non-survey sensor information may be continuous, non-survey sensor information may be obtained between orientation updates. The non-survey sensor information may be averaged (symmetrically or otherwise) to relate the sensor information to the toolface information.

In step1604, calculations are performed on the non-survey sensor information to estimate the amount of progress made by the drill bit since the last estimate. For example, the differential pressure may be used to estimate the force on the bit, which may be used with formation information to determine the distance that the bit should have drilled in the current formation layer.

One difficulty in measuring drilling information between survey points is that measurements made at the top of the drill string may not accurately reflect events at the BHA. For example, a ten thousand foot drill string may be viewed as a big spring, and when motion is stopped at the surface, the spring force may continue to increase the length of the drill string and the BHA may make progress in a certain direction. In another example, if a foot of pipe is moved into the hole, the drill string may compress and/or buckle and the bit may move little, if at all.

Accordingly, predictions about the current orientation and progress of the drill bit may vary in accuracy depending on the information on which the predictions are based. For example, rather than exclusively using surface deviation, energy produced by the bit and a combination of differential pressure, MSE, and/or other measurements may be used. In some embodiments, more sensors may be placed downhole to provide more accurate information. Depending on the particular embodiment, calculations may be performed based on sensors at various levels of the drillstring to predict actual progress between surveys. For example, calculations may be used to approximate the fluid pressure to how much force is on the bit. Other calculations may be made to account for drill string compression, tension, and/or buckling.

It is understood that the calculations may differ based on the configuration of the drilling equipment and/or the BHA. For example, if an autodrilling system is used, the drilling rig may have a fixed value for ROP, WOB, DP, and/or other characteristics. Such fixed values may affect the particular calculations used. For example, if DP is fixed, the calculations may not rely on changes in DP as the autodrilling system may attempt to maintain the fixed DP value. In another example, if ROP is fixed, measurements of DP may have a wide range due to the attempt to maintain the fixed ROP value. If an autodrilling system is not used to control drilling functions, more flexibility may be available in the calculations that are used.

In step1606, calculations may be performed to obtain an estimate of the BHA's location using the toolface information and the calculated amount of progress. This calculation may be performed in a variety of ways, including the calculation of a vector as a three-dimensional estimate of the drill bit's current location and orientation. The vector progress (e.g., degrees/100 feet) may come from the build rate predictor1102ofFIG.11, and may also include the use of formation information.

In step1608, a determination may be made as to whether survey data has been received. If not, the method1600may return to step1602and calculate another location estimate (e.g., another vector) of the BHA's incremental progression. As these estimates are calculated, an estimated path of the BHA between the two survey points is developed. If survey data has been received, the method1600moves to step1610, where the survey data is used to update the estimated location. The method1600may then return to step1602and calculate another location estimate using the new survey data as the baseline for the current estimate.

Accordingly, the survey data may serve as truth data against which the estimates can be measured. This enables the calculations used for the estimates to be refined in conjunction with formation information as more survey point data is received. For example, if the estimates use a particular drilling speed through the current formation layer and the survey data indicates that the drilling speed is incorrect, future estimates may be calculated based on the revised drilling speed to provide a higher level of accuracy. Furthermore, although not shown inFIG.16, it is understood that the survey data may also be used to check the estimated build rate and, if needed, recalibrate the build rate (e.g., the build rate predictor1102ofFIG.11) to correspond to the survey data.

Referring toFIG.17, a method1700illustrates one embodiment of a process that may be executed by the on-site controller144ofFIG.2Aand/or another part of the surface steerable system201. For example, software instructions needed to execute the method1700may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144. In the present example, the method1700illustrates a more detailed example of steps1602-1606ofFIG.16.

In step1702, the average differential pressure is determined for a toolface update period (e.g., the length of time between toolface updates). The differential pressure may be acquired or calculated. The toolface update period may vary based on factors such as the speed at which the MWD component is set to run, the priority given to the toolface information in the MWD component, the overall bandwidth available to the MWD component, and/or other factors.

In step1704, the average ROP is determined. For example, the differential pressure determined in step1702may be used to assist in a database lookup. More specifically, the average ROP for the current formation using the current BHA at the average differential pressure may be acquired from the database.

In step1706, the average ROP is applied over the toolface update period to determine the borehole distance increase since the last iteration. For example, if the ROP retrieved from the database indicates that the ROP is fifty feet per hour and the toolface update period is thirty seconds, then the distance increase should be approximately five inches.

In steps1708and1710, the new toolface sample is used to derive a plane of arc to use in a curvature projection. In the current example, applying observations from the previously described minimum curvature method may be useful when developing a method for estimating borehole position and trajectory from toolface measurements between survey measurements. Certain parameters used in the minimum curvature method may be estimated instead of directly measured.

With additional reference toFIG.18, one embodiment of a two-dimensional borehole space1800illustrates the minimum curvature path1801in the plane of the curvature arc. The space1800is illustrated with two measured survey points1802(also labeled as “A”) and1804(also labeled as “C”).

As illustrated inFIG.18, the angle θ can be seen intuitively as the arc angle along which the minimum curvature path is made and the change in trajectory between the two path points. Angle β would normally be calculated from survey trajectory angles using an additional formula. In the context of directional well steering where the angle β is deliberately controlled, it can also be considered an angle of desired or target build. In the case of projecting build in real time, an instantaneous β estimate may be needed. The complexity of such an estimate may vary. For example, a relatively simple approach may use a geometric formula of BHA dimensions. In other examples, more detailed approaches may account for factors from previous and instantaneous rig sensor data, formation data, etc., in order to provide an improved prediction of an instantaneous build rate while drilling. The build rate predictor1102ofFIG.11may provide a functional component used to perform this task within the surface steerable system201.

In the minimum curvature method, ΔMD may be directly obtained from the surface measurement of the difference in drill string lengths between surveys. When accounting for the position of the bit, this method of using surface changes in drill string lengths may be used in a relatively simple approach for an estimate. However, accounting for drill string tension, compression, buckling, and other factors that impact drill string length may provide a better estimate of the current drill bit position as it is drilling new borehole.

In the case of updating borehole trajectory over a given change in borehole depth, survey measurements may be used when available. In such cases, one goal of slide estimation may be to estimate trajectory along the bit path by using toolface history along the intervals ahead of where survey data is available to allow a real time or near real time estimate of bit location.

With additional reference toFIG.19, one embodiment of a two-dimensional borehole space1900illustrates slide estimation by integration of a single toolface measurement using the minimum curvature path1801ofFIG.18. More specifically, the present example addresses the application of a toolface vector1902that is a direct linear projection of an individual toolface. This projection is overlaid against the minimum curvature path1801for purposes of illustration. It is understood that while the present example uses a gravity toolface frame of reference, magnetic references can also be used with variations in some formulas described below to account for the use of magnetic references.

In this case, the borehole is assumed to be moving in a straight path along the trajectory AB until encountering a measured toolface. Upon encountering the toolface at point1806(B), the toolface is applied directly to the trajectory BC as follows:
α2=α1+cosTF×β(Equation 5)
ε2=ε1+sinTF×β(Equation 6)
where TF is the toolface vector angle presented relative to the gravity “up” vector. The position estimates for the path between AC may be given by:
ΔV=ΔBD×cos α1  (Equation 7)
ΔN=ΔBD×[sin α1×cos ε1]  (Equation 8)
ΔE=ΔBD×[sin α1×sin ε1]  (Equation 9)

The equations 7-9 represent the simple projection of the straight line AB in Cartesian space since the toolface would not be applied until point B. When overlaid on the curvature model, it is evident that this estimate is analogous to the balanced tangential method where the starting and finishing points A and C and the path ABC lie apart from the overlying smooth circular arc.

With additional reference toFIG.20, one embodiment of the two-dimensional borehole space1900ofFIG.19is illustrated using the minimum curvature concept to yield a better estimate of actual borehole displacement by modeling the borehole as an arc rather than bending line segments. When framed as a single arc curve displacement2002, the projection of the single toolface may appear as illustrated inFIG.20.

In this case, the toolface influence on trajectory may be modeled to yield the same tangent trajectory from the toolface build vector1902as follows:
α2=α1+cosTF×β(Equation 10)
ε2=ε1+sinTF×β(Equation 11)

After deriving trajectory changes, the minimum curvature method equations are again applicable for determining the positional displacements over the interval as follows:

Δ⁢V=Δ⁢B⁢D2[cos⁢α⁢1+cos⁢α⁢2]×RF(Equation⁢12)Δ⁢N=Δ⁢B⁢D2[sin⁢α⁢1×cos⁢ε⁢1+sin⁢α⁢2×cos⁢ε⁢2]×RF(Equation⁢13)Δ⁢E=Δ⁢B⁢D2[sin⁢α⁢1×sin⁢ε⁢1+sin⁢a⁢2×sin⁢ε⁢2]×RF(Equation⁢14)

In this case, the line path to arc relationship works out to be the same as the minimum curvature RF:

R⁢F=2β⁢tan⁢β2(Equation⁢15)

While the preceding example illustrates slide estimation by integration of a single toolface measurement, it is understood that a range of toolface measurements may be used. As described above, the integration of individual toolface projections may provide a useful method of slide and borehole estimation on a near real time basis. However, like the use of minimum curvature on a smaller scale, this process may be subject to cumulative errors over longer intervals. Accordingly, a range of toolfaces may be used over an interval to address this issue. For example, the range of toolfaces may be used to provide a net effective toolface direction and a net effective β build rate angle may also be estimated. In both cases, the benefit of larger data sets (e.g., toolface histories) may enable the application of more sophisticated statistical methods and filtering techniques. For example, over a path interval, a target toolface may be desired and attempted to be maintained. In practice, the ability to control the toolface over these intervals can be evaluated in statistical metrics, like a circular distribution. These metrics can then be used to refine the effective build rate and toolface direction over the evaluation interval.

Referring again specifically toFIG.17, in step1712, an updated spatial estimate of the borehole position may be estimated based on the preceding steps. The estimated spatial estimate may be provided to the display250ofFIG.2B(e.g., for display to the driller310ofFIG.3), provided as feedback to the convergence planner1116ofFIG.11, and/or otherwise used.

Referring toFIG.21, a method2100illustrates one embodiment of a process that may be executed by the on-site controller144ofFIG.2Aand/or another part of the surface steerable system201. For example, software instructions needed to execute the method2100may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144. In the present example, the method2100may provide a more detailed example of steps1602-1606ofFIG.16.

In step2102, the increase in measured depth is determined for the toolface update period. The increase may be acquired or calculated. For example, the measured depth may be acquired based on a surface measurement of the length of pipe inserted into the borehole between the last toolface update period and the current toolface update period. In other examples, the measured depth may be calculated based on measurements received from downhole sensors.

In step2104, the method2100may account for deviations in the overall drillstring length due to issues such as compression, tension, and/or buckling. In some embodiments, step2104may be omitted and the measured depth determined in step2102may be used with accounting for such deviations. Steps2106,2108, and2110may similar or identical to steps1708,1710, and1712, respectively, with the estimate using the information from steps2102and2104.

Referring toFIG.22, a method2200illustrates one embodiment of a process that may be executed by the on-site controller144ofFIG.2Aand/or another part of the surface steerable system201. For example, software instructions needed to execute the method2200may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144. In the present example, the method2200may provide a more detailed example of step2104ofFIG.21, although it is understood that the method2200may be used with the other methods described herein.

In step2202, a hookload measurement is acquired and compared to the static weight of the drill string vertical section excluding the mass of the surface equipment. The static weight of the drill string vertical section excluding the mass of the surface equipment may be determined, for example, from information available from the local database912ofFIG.9and/or regional database128ofFIG.1A.

In step2204, the tensile elastic deformation of the drill string components in the vertical section is determined. This determination may use, for example, average cross-section and mechanical properties of the drill string components in the vertical section. The average cross-section and mechanical properties may be determined, for example, from information available from the local database912ofFIG.9and/or regional database128ofFIG.1A.

In step2206, a real time or near real time WOB value is determined. For example, the WOB value may be obtained using a downhole sensor. In another example, the WOB value may be approximated using differential pressure and mud motor properties.

In step2208, the compressive elastic deformation of the drill string components in the horizontal section of the borehole (if any) is determined. This determination may use, for example, average cross-section and mechanical properties of the drill string components in the vertical section. The average cross-section and mechanical properties may be determined, for example, from information available from the local database912ofFIG.9and/or regional database128ofFIG.1A.

In step2210, the total drill string length dynamic offset from the measured depth is determined. This total length dynamic offset accounts for variations between the measured depth and the actual drillstring length due to issues such as compression, tension, and/or buckling in the drillstring.

Referring toFIG.23and with additional reference toFIGS.24and25, a method2300illustrates one embodiment of a process that may be executed by the on-site controller144ofFIG.2Aand/or another part of the surface steerable system201. For example, software instructions needed to execute the method2300may be stored on a computer readable storage medium of the on-site controller144and then executed by the processor412that is coupled to the storage medium and is also part of the on-site controller144.

In step2302, information is received by the surface steerable system201. The information may be any type of information displayed by the display250. For purposes of example, the information may include the orientation and progress estimate fromFIG.16.

In step2304, the GUI (e.g., the circular chart286) may be updated with the information representing the orientation and progress of the drill bit. Referring specifically toFIG.24, an embodiment of the circular chart286of the display250(FIG.2B) is illustrated with differently positioned circles than those shown inFIG.2Band may be used to show the orientation and/or mechanical progress of the drill bit at survey points and/or between surveys. More specifically,FIG.2Billustrates a particular positioning of the circles ranging from the largest circle288to the smallest circle289.FIG.24illustrates a different positioning of circles labeled2402(the smallest circle),2404,2406,2408,2410,2412,2414, and2416(the largest circle). As described with respect toFIG.2B, the series of circles may represent a timeline of toolface orientations, with the sizes of the circles indicating the temporal position of each circle. In the present example, the largest circle2416is the newest orientation and the smallest circle2402is the oldest orientation. The circular chart286may provide insight into what is happening in the borehole between surveys (e.g., using variations in size, color, shape, and/or other indicators). As described previously, the lack of knowledge about orientation and progress between surveys may affect various aspects of drilling, as well as the final efficiency of the well.

With additional reference toFIG.25, a three-dimensional chart2500illustrates vectors2502,2504,2506,2508,2510,2512,2514, and2516corresponding to circles2402,2404,2406,2408,2410,2412,2414, and2416, respectively. The vectors2502,2504,2506,2508,2510,2512,2514, and2516are plotted against a TVD axis2518and compass directions indicated by an axis2520representing east-west and an axis2522representing north-south.

Each vector2502,2504,2506,2508,2510,2512,2514, and2516provides a three dimensional representation of the orientation of the tool face, as well as an amplitude that may be used to represent the mechanical progress (e.g., distance traveled) of the bit and/or one or more other indicators. The amplitude may represent a measurement such as MSE or WOB. In some embodiments, the amplitude may be a combination of measurements and/or may represent the results of calculations based on such measurements. Accordingly, the circular chart286may provide a graphical illustration of the vectors2502,2504,2506,2508,2510,2512,2514, and2516. Although not shown, each estimate ofFIG.16may result in one of the vectors2502,2504,2506,2508,2510,2512,2514, and2516, which may be combined to provide an estimated path.

Referring again specifically to step2304ofFIG.23, for example, the circle2416may represent the latest toolface orientation information that is used to calculate the vector2516ofFIG.25when the information used to calculate the previous vector2514was represented on the circular chart286by the circle2414. In addition, the slide indicator292and/or colored bar293may be updated to provide a visual indication of the current status of an ongoing slide.

In step2306, a determination may be made as to whether a correction is needed according to the information. For example, if the heading is off by five degrees, the surface steerable system201may identify this error. In step2308, the GUI may be updated to reflect this error. For example, the error indicator294may be updated. In some embodiments, the surface steerable system201may correct the heading automatically, while in other embodiments the target toolface pointer296may change to indicate an updated correct heading. For example, as the actual toolface veers off course, the GUI may be repeatedly updated to indicate an offsetting correction that should be made in cases where the GUI is used to notify an individual for manual correction of the toolface. Although continuous or near continuous error calculations may be provided to the driller310, the steerable system201may plan a solution that uses periodic corrections, rather than instantaneous corrections. Accordingly, the display250may provide the recommended corrections to the driller310so that controlled, gradual, incremental step changes are made. In cases where the solution has a helical or otherwise continuous correction path, instantaneous or periodic corrections may be displayed to the driller310. For example, the incremental step correction may be a function of the tortuosity of the well, amount of friction, and/or the overall depth of the BHA. In another example, in cases where the toolface is automatically controlled (e.g., via Top Drive), the method2300may make the correction via instructions to the Top Drive controller, via another controller, or directly.

It will be appreciated by those skilled in the art having the benefit of this disclosure that this system and method for surface steerable drilling provides a way to plan a drilling process and to correct the drilling process when either the process deviates from the plan or the plan is modified. It should be understood that the drawings and detailed description herein are to be regarded in an illustrative rather than a restrictive manner, and are not intended to be limiting to the particular forms and examples disclosed. On the contrary, included are any further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments apparent to those of ordinary skill in the art, without departing from the spirit and scope hereof, as defined by the following claims. Thus, it is intended that the following claims be interpreted to embrace all such further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments.