ROTARY STEERING METHOD AND SYSTEM FOR DRILLING BOREHOLE

Description

FIELD OF INVENTION

The present disclosure relates in general to systems, apparatus and methods for directional drilling, particularly for oil and gas wells.

BACKGROUND

There are two main categories of RSS: “point-the-bit” and “push-the-bit” drilling systems.

In the “point-the-bit” drilling systems, the orientation of the drill bit is varied relative to centerline of the drill string to achieve a desired wellbore deviation. Such system requires complex and expensive design of bottom hole assembly and drill bit configuration.

In the push-the-bit system, a lateral side force is applied by using a few pads to the formation wellbore surface resulting in drill string movements, thereby deflecting steering tool from the axis of the wellbore to achieve a desired deviation. The drill bit is required to cut sideways in order to generate a curved well trajectory.

One prime difference between types of push-the-bit rotary steerable system is based on whether the tool applies dynamic side force from a rotating housing, or a static side force from a non-rotating housing on the rotary steerable tool. Another primary differences in such systems include the type of fluid used to actuate the steering pads.

A few companies are using for operation a self-contained hydraulic oil system. One example of such system is the Sure-Steer-RSS-475 from APS Technology [www.aps-tech.com]. The oil is pressurized, flow to each pad is driven by a positive displacement vane pump, and delivered to each steering pad via electrically stimulated solenoid valves which are individually opened and closed by the control system. The system produces a fix pushing force and has a retraction mechanism to bring steering pad after full extension to its original close positions, but the tool requires a turbine alternator, three pumps and has reliability issues due to complexity of its design.

The majority of commercial push-the-bit RSS utilize the flow of drilling fluid in the bore of drillstring to open the steering blades evenly spaced around the perimeter of the tool.

The more common design is positioning of the steering pads on a rotating housing, such as Power Drive and Orbit from Schlumberger [www.slb.com], Magnus from Weatherford [www.weatherford.com], Halliburton i Cruise [www.halliburton.com], D-Tech RST [www.d-techdrilling.com], or the like.

These systems generally divert upward a small portion of mud flow through an open portion of essentially stationary valve into openings in a lower rotational part of the tool. High pressure drilling fluid is directed to each openings of flow distribution channels resulting successive extension of each steering pad. The extending force which open the steering pad is proportional to the differential pressure between the pressure inside drill string bore and the annulus.

The gap between upper valve which rotates in opposite direction of the collar rotation and lower part of the tool which rotates with collar rotation speed is relatively small, preferably equal to zero. The size of the gap is responsible for crosslinking mud flow into all openings even when they are in “closed” positions, in other words when there are no overlap between open portion of the upper valve and open channel to the steering pad. The leaking pressure or back pressure significantly reducing differential pressure, but also preventing steering pads to go back into original position inside the pad retainer assembly, or at least ensure that pad breaks off the borehole wall during time when the pad should not communicate with borehole surface. In addition, the crosslinking reducing the impact on the borehole surface by activated pad resulting in decrease of dog leg severity (DLS).

The vast majority of push-the-bit conventional RSS use drilling fluid to create differential pressure have complex design with orifices and sealing systems resulting in frequent and labor intensive maintenance.

For the foregoing reasons, there is a need for rotary steerable push-the-bit RSS that can deflect the drill bit to a desired extent applying lower differential pressure than convention push-the-bit systems in order to achieve requested side forces. There is also a need for rotary steerable push-the-bit system and apparatus that have simple robust design with fast and not labor intensive maintenance.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1A is a diagrammatic view of a drilling rig with bottom hole assembly for directional drilling with a push-the-bit rotary steerable system (RSS).

FIG. 1b is an enlarged diagrammatic view of the push-the-bit RSS shown on FIG. 1a.

FIG. 2 is a flow chart illustrating a method for an exemplary system shown on FIGS. 1A and 1B.

FIG. 3 is a perspective view of the steering head.

FIG. 4 is a detail cross-sectional view of the steering head in longitudinal direction.

FIG. 5 is an isometric partial section of the flow metering assembly.

FIG. 6A is a side view of the flow metering assembly with a gap between rotational valve disk and the top surfaces of the inserts into flow channels.

FIG. 6B is an alternative design of the flow metering assembly shown on FIG. 6A with zero gap value.

FIG. 6C is a transverse cross-section of the flow metering assembly for line A-A′ (see FIG. 6A).

FIG. 6D is a transverse cross-section of the flow metering assembly for line B-B′ (see FIG. 6A).

FIG. 7a is an illustrative transverse cross-section view in downward direction through the junction between rotational valve flat plane and the top surfaces of the inserts into flow channels in a position when two flow distribution channels are closed.

FIG. 7B is an illustrative transverse cross-section view in FIG. 7A with one flow distribution channel is closed.

FIG. 8 is a prospective view of the manifold block.

FIG. 9 is a longitudinal cross-section view of the manifold block.

FIG. 10A is a transverse cross section of the manifold block in direction A-A′ shown on FIG. 9.

FIG. 10B is a transverse cross-section of the manifold block in direction B-B′ shown on FIG. 9.

FIG. 10C is a transverse cross-section of the manifold block in direction C-C′ shown on FIG. 9.

FIG. 11 is 3D transparent side view of a chamber for pad assembly.

FIG. 12 shows 3D side view of the pad assembly.

FIG. 13 is a longitudinal cross-section through the center of the pad assembly.

FIG. 14 shows a 3D view of the guide device 320 for transversely fixing an upward portion of the manifold block 310 in the area adjacent to drill bit 8.

FIG. 15 is a cross-section of guide device 320 with 4 blades.

FIG. 16 is a flow chart and block diagram illustrating steps for planning and preparation stage 210 (shown in FIG. 2).

FIG. 17 shows the dependence of the pressure drop of drilling fluid 32 passing through drill bit 8 for different flow rates for steering head 60 with diameter 4.75 inches.

FIG. 18 shows azimuth coordinate system is used for directional drilling based on reverses gravity and or magnetically defined Tool Face.

FIG. 19 shows projections of the reactive forces on the selected Tool face direction and on the perpendicular direction on the azimuth coordinate system shown on FIG. 18.

FIG. 20A is a schematic illustration showing an angular position of the rotational valve opening which coincides with one of three flow distribution channels according a typical prior art system.

FIG. 20B shows graphs of steering forces during 360 degrees of drill collar rotation for a typical commercial system shown on FIG. 20A.

FIG. 21A is a schematic illustration showing an angular position of rotational valve 360 opening 362 when drilling fluid 32 is going simultaneously through two flow channels 311 according to one or more embodiments of the present invention.

FIG. 21B shows graphs of steering forces during 360 degrees of drill collar 6 rotation for the steering head 60 with rotational valve 360 opening 362 equal to 120 degrees as shown on FIG. 21A.

FIG. 22A is a schematic illustration showing an angular position of the rotational valve opening coincides with one of four flow distribution channels according a typical prior art system.

FIG. 22B shows graphs of steering forces during 360 degrees of drill collar rotation for the system shown on FIG. 22A.

FIG. 23A is a schematic illustration showing an angular position of rotational value 360 opening 362 when drilling fluid 32 is going simultaneously through two flow channels 311 for steering head 60 with four fluid channels 311.

FIG. 23B shows graphs of steering forces during 360 degrees of drill collar 6 rotation for the steering head 60 with rotational valve opening 362 equal to 135 degrees as shown on FIG. 23A.

FIG. 24 shows graphs of leakage of drilling flow 32 (in percentages of the total drilling flow 32 through steering head 60) into closed fluid channels 311 depending on size of gaps 62 for pad assembly 61 for different diameters of flow channels 311.

FIG. 25 shows the dependence of differential pressure loss from diameters of flow channels 311 for several gap 62 sizes.

FIG. 26 shows graphs of pad assembly 61 displacement from wellbore wall versus time for different strength of the set of springs 343 for closed fluid channels 311 for valve gap 369 between flat surface of valve disk 367 and the top surface of the inserts 313 for the gap 369 equal to zero.

FIG. 27 shows the amount of an additional pressure in chamber 330 depending on the drilling fluid inflow into closed flow channels 311 as percentage of the total volume drilling fluid 32 passing through steering head 60 for different sizes of valve gap 369.

FIG. 28 shows a workflow of directional drilling by using apparatus and method in according to embodiments of the present invention.

DETAILED DESCRIPTION

FIG. 1A is a diagrammatic view of a drilling rig 1 for implementation of an exemplary system for directional drilling using push-the-bit rotary steerable system (RSS) and method. The drilling rig 1 can be engaged in drilling operation by using RSS with simultaneous logging-while-drilling (LWD) acquisitions and downlinking for communication between the surface and the bottom borehole assembly (BHA). LWD operation typically include measurement-while drilling (MWD) operation, as well as additional measurements. During operation, a wellbore hole 2 is drilled into ground 3 through formation 5 by using the rotary drilling rig 1.

Drilling operation generally include the circulation of drilling fluid 32 (e.g. drilling mud) by pump 34 located at the surface through a mud line 36, into and through a drill string 6 down to the drill bit 8, and back to the surface through the annulus 15 between the drill string 6 and the borehole wall 17. The drilling fluid 32 exits the wellbore 2 via a return conduit 39, which routes the drilling fluid 32 back to one or more mud pits 30.

Downlinking is an important part of managing RSS parameters. It may be achieved by either periodically varying the flow rate of the drilling mud in the system or/and by periodically varying the rotation rate of drilling. One downlinking and method is described in, e.g., U.S. Pat. No. 11,840,925 to Pogrebinsky, the contents of which are fully incorporated herein by reference in their entirety. As described in the '925 patent, a modulator 51 having a rotational flap for generating harmonic pressure signals in flowing drilling fluid by rotating a flap clockwise and counterclockwise inside fluid mud line 36 is used. The transducer 52 is used by the system to estimate an initial amplitude of the harmonic pressure waves in the drilling fluid 32 generated by modulator 51.

The BHA 22 at or near the distal end of the drill string 6 includes RSS 10, one or more centralizers 9, one or more other sensor modules 12. In some embodiments, sensor modules 12 of the BHA 22 can include one or more flow sensors 11, one more directional sensors, one or more formation evaluation sensors, combinations thereof, or the like. The BHA 22 includes at least one transducer 13, one or more sources of energy 14 (e.g., batteries or/and generators), and downhole electronics (including a controller 16) in communication with the sensors 12 (including flow sensor 11, transducer 13, and a pulser assembly 21). The pulser assembly 21 can include a modulator 20, and a motor control and electronic power board 18 (e.g. printed circuit board (PCB)). It should be understood that at least some (if not all) of the components of the downhole assembly can be communicatively connected to each other to allow for signals generated or received by the system to be collectively used for adjusting operation of the system. During operation in the uplink mode, the pressure fluctuations 50 propagate to the surface through the mudflow and are detected at the surface by one or more transducers 38 which are connected to the fluid flow line 36. The analog/digital device 40 transmits a digital form of the pressure signals to a processing device or unit 42 (e.g., a computer or some other type of a data processing device). Processing device 42 operates in accordance with software programmed into the system to process and decode the signals received from the analog/digital device 40. The resulting LWD data can be further analyzed and processed to generate a display of various useful information. For example, the system can include a graphical user interface (GUI) capable of displaying data acquired and/or processed, can assist with visually confirming proper operation of the system and/or adjusting operation of the system as needed based on operation requirements.

A request for downlinking command is a comprehensive process which is based on data from surface sensors (e.g., stand pipe gauge for pressure 55, hook load sensor 56, depth tracking sensor 57, combinations thereof, and the like) along with the well planning trajectory, 3D geological model, mud log information, and others data. All of the above information can be reviewed in real-time (or substantially real-time) by different experts on site or at remote location center 54 in order to make a decision for controlling the drilling process and/or optimizing data acquisition. Based on the comprehensive analysis of the above information, the downlinking command can be selected and then transmitted in real-time to the downhole BHA 22. In instances of a high level of noise or the need to switch to lower frequencies (due to an increase of borehole depth), the duration of the transmitted signal to the BHA 22 can be increased by up to several minutes, resulting in delay of the adjustment of the drilling process.

FIG. 1B represents the RSS 10 of the BHA 22 in FIG. 1A. The RSS 10 includes a rotary steering head 60 with three or more pads assemblies 61, gap 62 to annular space 15, control Unit 67, which includes flow metering system 63 with distribution rotational valve, motor to drove a shaft of the distribution rational valve, controller for the motor, main controller and processor 64, directional sensors 65 and power source 66. The BHA 22 also includes at least one stabilizer 9, located above or/and bellow RSS 10.

The present invention is used with drill bit 8 as a single source for a generation of differential pressure necessary to extend pads outside the steering head to apply force to the well bore surface in order to deviate steering head in opposite direction from the point of the pads contacts with wellbore surface.

The ability of the system and method disclosed in the present invention carry out directional drilling only due to the creation of differential pressure through mud flow moving into the drill bit nozzles allows to radically simplify the design of steering head 60 and eliminate any of orifices or/and internal flow restrictors.

The directional sensors 65, preferably, are sets of accelerometers and magnetometers. The accelerometers are used to determine the inclination of the steering head 60 relative to the earth's gravitational field, while the magnetometers are used to determine the direction of the steering head 60 relative to the earth's magnetic fields.

It is understood that various so-called «direction and inclination» sensors are known in the RSS industry. The present invention is not limited to any particular arrangement of directional and inclination sensors.

In the industry are known various design of the control unit 67. One of a suitable design is where control unit 67 components and power batteries 66, are housed in a probe-like tube with standard MWD dimensions.

FIG. 2 provides a flow chart of the method of constructive forces interference based on disclosed design of Push-The-Bit RSS 10 with use of only the Drill Bit 8 for achieving differential pressure difference between the pressure inside drill collars and the annuals pressure. Existing RSS are capable, in some cases, control directional drilling by using the pressure drop that occurs when drilling fluid passes through nozzles of the drill bit. In order to apply existing systems in a wide range of geological conditions, the vast majority of RSS have in their design orifices and others type of the flow restrictors resulting in complex design and unnecessary loss of drilling flow energy.

The planning and preparation stage 210 includes various steps:

• • Gathering geological and drilling information;
  • Determining the steering head 60 parameters to compensate for the lack of orifices;
  • Selection of rotational distribution valve and pad assembly 61 gaps and calculations of compressions springs strength for separation of pads top cover from the borehole surface during period of time when a distribution flow channel is closed;
  • The compensation for the absence of orifices are based by increasing the area of pads foundation, choosing appropriate number of pads, using the constructive interference effect, proposed in the present invention, due to simultaneous extension of two or more pads.

Drilling stage 220 includes utilization of RSS in accordance with present invention in a borehole and drilling commences. The rotational valve is deployed at calculated Tool Face position according the drilling plan. The maximum dog leg severity (DLS) is assumed based on BHA flexibility, for example, as equal to 15 degrees per 100 feet. At any particular point of time a requested by trajectory design DLS might be different from the assumed maximum of DLS. The method provides the possibility of calculating actual DLSmax for a geological formation. In order to make a smooth wellbore trajectory the present invention applied a proportional steering ratio concept by using shorter time cycles compare to the industry typical realizations. The cycle time is in a range of 10-30 seconds. Such short period of cycling resulting in drilling smooth borehole trajectory.

To steer (i.e. change the direction of drilling) two or more of pads assembly 61 are extended simultaneously. At each moment of time a reactive force of two or more pads have a useful reactive force component that coincides with the direction opposite to the given Tool Face. In the case of RSS with 3 pads, one of the distribution flow channel remains closed, i.e. mud flow is not coming to the pad chamber. Almost instantly, at the moment of closing the channel, the pressure in the chamber becomes equal to the pressure in the annulus. The present invention is disclosed relationships between the gap value 62 around pads sides surfaces and the inner surfaces of the retained chambers and the strength of compression springs which provide full or partial return of the pad assembly 61 toward the initial position. The absence of interaction between the pad and the borehole wall during 50% time of the directional drilling reduces wear on the outer surface of the pad top cover 342 and increases its service life. After drilling of the current pipe or drill stand is finished, the stationary survey is performed and survey data is uplink to the surface, planed and actual wellbore trajectories are compared and correction of Tool Face is downlinked (if necessary).

Based on the difference of planned and actual trajectories of wellbore, an adjustment of DLSmax assumed to DSLmax actual is performed. The new value of DSLmax actual for a particular formation is used for calculation of steering ratio. While drilling process continues, after each survey the DSLmax actual is recalculated.

When a drilling of a next formation is started, an initial difference between expected value of DSLmax and an actual its value might be quite significant, but after obtaining a few measurements, it should be reduced to an acceptable level allowing drilling to continue without a need to send a downlinking command after processing measurements of the stationary survey.

FIGS. 3-15 illustrate components of the steering head 60 and flow metering system 63 in accordance with embodiments of the present invention. FIG. 3 provides a three dimensional view of the steering head 60, which is a part of rotary steerable system 10. It has a drill collar 6 connected with threated connections to the drill bit 8 in the downward direction, and to the upper portion of rotary steerable system 10 in the upward direction. Steering head 60 has several pads assembly 61 which under selective fluid flow are actuated and temporarily are extended in the opposite direction to a desired wellbore deviation, thereby deflecting the drill bit away from the borehole centerline.

The pad 61 has a rectangular or elongated shape with a ratio of length along the wellbore axis to the width of the pad in the transverse direction of no less than 2:1 and up to 6:1. In an example which is used in the present invention the length of the pad is 16 centimeters and width is 3 centimeters. The area of external side of the pad is 48 cm². The form of the pad proposed in the invention allows to increase its area three or more times compared with typical RSS. The area of inner side of the pad is almost equal to the area of outside side of the pad. Thus, only a selection of the pad dimensions allows to reduce the typical differential pressure which is used for most RSS by three or more times. Most used RSS require the creation of large differential pressure values limiting hydraulic capabilities in a well due to increased pumping horsepower necessary for circulating drilling fluid through the RSS apparatus.

In FIG. 3 the steering head 60 is shown in it starting position when all pads assembly 61 are in the closed positions. Pads are located inside retained chamber 330, between them there are gaps 62 for the exit of drilling fluid into the annulus space 15 (shown on FIG. 1A). The outer surface of the pads has carbide inserts 352 and holes for tightening bolts 351, attaching the top cover of the pad 342 to base plate 347 (shown on FIG. 12). The flow-metered assembly 365 (See FIG. 5) in the demonstrated example of design is located inside the steering head 60, position 364 shows shaft of rotational valve 360 (not shown on FIG. 3).

FIG. 4 shows a cross-section along longitudinal axis of steering head 60 allowing to demonstrate its internal design.

The central place of the steering head 60 is occupied by manifold block 310. The upward portion of the manifold block is a part of the flow metered assembly 365. The rotational valve 360 during directional drilling must be in the so-called “geostationary position” while the steering head 60 rotates at speed of typically from 60 up to 350 revolutions per minute. The manifold block 310 as part of steering head 60 is also rotating with the same speed allowing drilling fluid 32 alternately flow through flow distribution channels 311, through holes 333 in the bottom of the chamber 330 resulting pad assemblies 61 temporal extension toward wellbore surface.

The manifold block 310 allows the pad assemblies 61 to be firmly attached to its body without connecting them to the drill collar body 6 of the steering head 60. This is ensured by a recess in the body of the manifold block 310 which forms a flat area 312 allowing the bottom of the chamber 330 to fit snugly against the manifold block 310 body. The disclosed arrangement prevents the manifold block 310 moving along longitudinal axis of the steering head 60.

Such design also prevents chambers 330 and pad assembles 61 from becoming loose or coming apart during extreme downhole vibrations and others impacts on the drill string 6. All chambers 330 are coupled to the manifold block in a triangular configuration (in case of 3 pad assembles design).

The bottom of chambers 330 are bolted to the manifold block 310 by bolts 336.

This is different from the standard RSS design where pad assemblies are directly bolted to the drill collars.

The downward portion of the manifold block 310 is inserted into the hole in the non-threaded guide device 320 which prevents any movement in transverse direction. During assembly of the steering head 60 the hole in the guide device 320 serves as a guide allowing quick and correct connection of pad assemblies 61 to the manifold block 310.

The pad assembly 61 design has compression springs 343 designed for separating the pad assemblies top cover 342 from wellbore surface 17 during the period of closure of corresponding flow distribution channel 311. This is achieved by displacing the drilling fluid from the cavity 353 into the annulus 15. Steering head 60 is connected by thread 301 and 302 to flow metering system 63 and drill bit 8 respectively. The design features of the pad assemblies 61 are discussed in more details below in FIGS. 11 and 12.

FIG. 5 shows an isometric partial section of flow-metered assembly 365 disposed inside steering head 60. Rotational valve 360 is configured to direct a portion of a drilling fluid flow 32 into flow distribution channels 311 to activate pads assembly 61 in the radially outward direction. The distribution flow channels 311 are contained within upper portion of manifold block 310, each flow channel extend to a corresponding chamber 330 (shown on FIG. 4).

Rotational valve 360 has a shaft 364 and opening 362. The base of rotational valve 360 is positioned tightly or with a small gap adjacent to the distribution channels inserts 313. The inserts extend beyond the upper flat portion of the manifold block 310, allowing to achieve the balance between mud fluid pressure above and below rotational valve 360.

FIG. 6A is a side view of the flow metering assembly 365. A cylindrical pin 363 is inserted into a recess, located centrally at the bottom of the distribution rotational valve 360 flat surface of the disk 367 (See FIG. 6C). Cylindrical pin 363 extended in downhole direction and contacts upward portion of the manifold block 310. The size of the protruding part of the pin is slightly longer than the height of the protruding part of inserts 313. The possible excess of the length of cylindrical pin 363 over the protruding parts of inserts 313 is the value of gap valve 361 between distribution rotational valve 360 and upward surface of the inserts 313. One of the goals of the present invention is to ensure guaranteed detachment of pads from the downhole surface during the period of the flow distribution channels 311 closure. Determination of the maximum permissible gap value can be performed by using multifactor numerical modeling, which takes into account the geometry of steering head 60, drilling fluid flow rate, the size of the gap between pad assemblies 61 and chamber 330, springs force and other factors. The methodology of numerical modeling and its results are discussed below. In one embodiment the size of valve gap 361 is selected between 0 and maximum of calculated permissible gap value. For the flow-metered assembly 365 design shown in FIG. 6A, the value gap 361 has a constant preselected value. In such configuration output shaft 364 has a connection with gearbox (not shown) which is not allowing its movement on the longitudinal axis direction.

FIG. 6B shows an alternative design of the flow-metered assembly 365, where a gap value 361 varies in the range from 0 to a certain value which is less than the maximum permissible value. This is possible due to some freedom movement in longitudinal axis direction. The presence of play simplifies the requirements for the manufacturing, while as shown below, during drilling this gap is equal to zero due to the proposed method for the selection of the ratio of diameters of shaft 364 and flow distribution channels 311. The absence of the free play during the distribution rotational valve 360 rotation is ensured by rigid fixation of the shaft 364 by engaging grooves 366 with corresponding guides at the base of a socket (non-shown). The rounded support 368 on the shaft 364 ensures low friction in the presence of axial vibration.

FIG. 6C shows a transverse cross-section of the flow metering assembly 65 shown on FIG. 6A through section A-A′. The flat surface of the disk 367 has a radial opening 362, the angle of the opening 362 is an important parameter for the embodiments of the present invention. The selection of an angle of the opening 362 is described below. A diameter of cylindrical pin 363 is in a range of a few millimeters. The cylindrical pin 363 with minimum diameter should withstands vibration during drilling operations, the maximum diameter should fits into the space 314 (see FIG. 6D) between flow distribution channels insert 313. A significant flow area between collars 6 and flow-metered assembly 365 and manifold block 310 ensures the passage of main drilling fluid through the steering head 60. FIG. 6D shows a transverse cross-section of the flow-metered assembly 365 shown on FIG. 6A through section B-B′ (See FIG. 6A). The upward portion of manifold block 310 has 3 distribution flow channels 311 (in case of 4 or 6 pads it should have 4 or 6 channels respectively). The entrances to the distribution channels 311 are protected by inserts 313 made of high-strength material that is not subject to quick erosion due to the presence of abrasive particles in the drilling fluid 32. In the case of using distribution rotational valve 360 with a cylindrical pin 363, the area 314 in the center of the flat top surface 316 of manifold block 310 where the cylindrical pin 363 touches the manifold block 310 is subjected to additional strengthening and grinding.

FIGS. 7A and 7B show the relative positions of the rotational valve 360 and opening 362 with respect to positions of flow channels 311. In the case shown on FIG. 7A two channels 311 are closed. FIG. 7B illustrates situation with one closed channel 311. The proposed designs shown on FIGS. 6A and 6B provide space between rotational valve 360 flat surface 316 of disk 367 and the top surface 316 of manifold block 310 due to the presence of inserts 313. The presence of such gap ensures close values of fluid pressure above and below disk resulting in reducing friction in the sliding contact between the flat surface of the disk 367 and the top surface of the inserts 313 or between cylindrical pin 363 and the center 314 of the upper flat surface of the manifold block 310. Since the proposed design provides the movement of the shaft 364 in longitudinal direction, it is necessary that pressure of the drilling fluid 32 above rotational valve 360 disk exceed the fluid pressure bellow the disk. Fulfillment of this condition is achieved by an appropriate selection of total area of flow channels 311 and the cross-sectional area of the rotational valve 360 shaft 364.

For steering head 60 with three pads assembly 61 according to one or more embodiments of the present invention, during 360 degrees of rotational valve 360 disk close one as shown on FIG. 7A or two flow channels 311 as shown on FIG. 7B.

The drilling fluid pressure 32 above the rotary valve 360 disk does not depend on the number of closed channels, while the pressure bellow the disk in case of two closed channels is less than for time when only one channel is closed.

Therefore, satisfying the requirement of the equal drilling fluid 32 pressure above and below the rotational valve 360 disk for one close channel 311 will result in excess of the drilling fluid 32 pressure above the disk relative to the pressure bellow the disk when two fluid channels 311 are closed. Therefore, the calculation of equal drilling fluid pressure above and below disk for the case of one closed fluid channel 311 allows to determine cross-sectional area of the shaft 364 by using Equation 1:

S shaft = S channel ( 1 - Pa P ) ( 1 )

• • where S_shaft—cross-sectional area of shaft 364; S_channel—area of distribution flow channels 311, P—is drilling fluid 32 pressure at inlet of steering head 60; Pa—drilling fluid annual pressure.

In the case of one closed channel 311, zero clearance of gap 361 is achieved due to the kinetic energy of the drilling fluid 32 flow.

FIG. 8 shows a prospective view of the manifold block 310 with flow distribution channels 311 extending downward from the upper end of the manifold block 310 to the junction with an openings 315 into the chamber 330. The manifold block 310 has a flat cut surfaces 312 designed to tightly connect the chamber 330 to the manifold block 310 by bolts 336 that are attached to threaded holes 317 in the body of the manifold block 310.

FIG. 9 shows a longitudinal cross-section passes through one of the flow distribution channel 311, crosses the area of openings 315 into the chamber 330, then goes through threaded holes 317. FIG. 9 also shows the position of three sections through flow distribution channels 311 in the direction perpendicular to longitudinal axis of the manifold block 310 (see FIGS. 10A, 10B and 10C).

FIG. 10A shows a cross-section of the manifold block 310 in the direction perpendicular to its longitudinal axis along line A-A′ (see FIG. 9), through inserts 313 which are made of a material that can withstand the abrasive effects of drilling mud flow. In the center of the cross-section there is an intersection 318 with cylindrical pin 363, which may be present in some embodiments of the disposed invention.

FIG. 10B shows a section of the manifold block 310 along line B-B′ (see FIG. 9) The amount of distribution channels 311 can be 3, 4 or more depending on the drilling objectives and geometric dimensions of the steering head 60.

FIG. 10C shows a section of the manifold block 310 along line C-C′ (see FIG. 9). This section crosses the area of the junction of the flow distribution 311 exit and the entrance 315 to the chamber 330 the pad assembly 61. FIG. 11 shows 3D transparent side view of a chamber 330 for the pad assembly 61. The chamber 330 is a hollow parallelepiped with no top cover. The upper part of the narrow side faces has rounding's with a radius equal to the radius of the outer surface of the tool collar 6. Each narrow side face has a hole 332 for a fuse (not shown) that limits the pad extension in case the upper surface of the pad does not reach a contact with wellbore surface at the maximum allowed pad extension value.

The fuse is a threaded cylindrical pin that is screwed into this tool collar 6. The other side of the fuse goes into a slotted oblong hole in the narrow side surface of the pad 348 (shown on FIG. 12). The bottom of the chamber 330 has a hole 333 designed to inject drilling fluid 32 into the chamber 330. The holes 334 are designed to attach the bottom of the chamber 330 with bolts 336 to the flat surface 312 of the manifold block 310. The holes 335 are designed to attach retraction springs 343 (see FIGS. 12 and 13) to the bottom of the chamber 330. The chamber 330 has significant free space 331 sufficient to accommodate the design proposed in one or more embodiments for pad assembly 61.

FIG. 12 shows 3D side view of the pad assembly 61, which it is placed inside the chamber 330, with gap 61 between the inner surface of the chamber 330 and the outer surface of the pad walls. The main components of the pad assembly 61 are: the top cover 342, the lower connecting plate 347, mounting angles 346 and spring assembly consisting from springs 343, the plate 345 for mounting spring to the lower connecting plate and the plates 344 to mount springs 343 to the bottom of the chamber 330 by using holes 355. The springs assembly provides the pad retraction movement during the period of closed flow distribution channel 311.

The side face of the mounting angles 346 has an elongate slot 348 that limits the movement of the pad when it is pushed out by pressurized drilling fluid if a diameter of the well in a given location exceeds the nominal diameter of the well. At the maximum permissible amplitude of the pad extension in the direction of the borehole well, the edge of elongated slots 348 rest against fuses (not shown), which are screwed into a tool collar 6.

Top cover 342 has through holes that match the through holes in the mounting angles 346 and with the shallow threaded holes in the lower connecting plate 347. These three elements are connected by bolts 351.

During the directional drilling process according the embodiments of the present intention, the top cover 342 has interaction with the wellbore wall only half time due to the guarantee surface detachment from the wellbore surface, this ensures, doubling the service life of top cover 342 compared to the vast majority of known commercial rotary steerable systems. However, to reduce wear, the top cover surface 342 has carbide inserts.

FIG. 13 is a longitudinal section through the middle of the pad assembly 61. The outer bolts 351 tighten three elements positions 342, 347 and 346). The central bolts 351 tighten two elements (positions 342 and 347). Springs 343 in the starting position provide attraction of the pad assembly 61 to the manifold block 310 with force ensuring the displacement of drilling fluids 32 to the annulus 15 in situations when drilling fluid 32 entering into closed flow channel 311. The springs 343 are attached to the plate 347 with bolts 353 and to the base of chamber 330 by bolts 354.

FIG. 14 shows 3D side view of the guide device 320 for the manifold block 310. The guide device 320 has a through hole 321 with a diameter several micrometers larger than the outer diameter of manifold block 310, it has two or more support blades 322, which rest with their rounded ends against the inner walls of the tool collar 6. The proposed geometry of the guide device 320 ensures alignment of the manifold block 310 along the steering hear 60. The position of the blades 322 relative to any mark, for example, high side of bottom hole assembly, does not matter for the stability of the guide device 320 in the direction perpendicular to the steering head 60. The proposed design provides the ability to rotate guide device 320 around its own axis to prevent erosion of the inner surface of tool collar 6 in case of permanent blades positions.

To prevent the guide device 320 from moving toward the drill bit under the influence of drilling fluid 32 a locking device (not shown) is installed between the guide 320 and drill bit 8. For this purpose, a variety of simple devices such as pin fasters, bolts and nuts can be used.

FIG. 15 shows cross-section of guide device 320 with 4 blades. It is possible to use only 3 or even 2 blades.

FIG. 1A-15 demonstrate the design and functionality of the system and apparatus of push-the-bit rotary steerable tool that is used with embodiments of the present invention. It is shown that steering head 60 differs from existing commercial systems in its simplicity of design and the small number of component required for it exploitation. It completely lacks of any seals, which eliminates one of the main causes of failures associated with violation of their integrity in known commercial systems.

A distinctive feature of the design is that the impact area of pressurized drilling mud is almost equal to the area of the outer surface of the pad cover 342 resulting 2, 3 or more times increase of the impact area compared to commercial system. In combination with the proposed effect of constructive interference (illustrated bellow on FIG. 19 and FIG. 21), the present invention allows to apply the force to the wellbore surface greater than that of known commercial systems. This design eliminates the need for complex solutions with various flow restrictors utilized in most commercial systems to generate significant differential pressure to achieve the required impact on the wellbore surface.

The proposed design of steering head 60 provides various exploitation and maintenance or repaired locally on the rig site resulting significant positive impact on the tool utilization, which is one of the key driver for cost-effectiveness in directional drilling using rotary steerable systems.

After completion of drilling the well, the steering head 60 is disassembled at the drilling site to replace the springs set, in order to expedite preparation to the next job, the entire pad assemblies 61 are replaced. Also it is possible to replace the inserts 313 to the distribution flow channels 311. The conditions of manifold block 310 and rotational valve 360 are assessed, and if necessary, they could be replaced. It should be noted that the disassembly/assembly the steering head 60 takes significantly less time than a similar procedures for the vast majority of commercial systems.

As disclosed in one or more embodiments, the steering head 60 is disposed adjacent to the drill bit 8 with steering forces (pad assembly 61) applied as close to the bit 8 as possible resulting increase the built rate capability in the curve section, as well as a tight trajectory control in long laterals. For majority of commercial RSS the distance between drill bit and pads are 1-2 feet. The disclosed steering head 60 design allows to reduce such distance compare with majority of commercial RSS. Also, the steering head 60 according the disclosed embodiments, may have very short distance between the bases of the upward and downward threaded connection. Such distance in the case of drilling well with DSL of 15-20 degrees or more, may exceed the pad cover 342 length by only 2-3 inches. For example, with a pad cover 342 length of 4 inches, the distance between the threads might be 6-7 inches. Such compact dimensions of the steering head 60 along the well axis significantly reduces bending stress and the fatigue failure risk of the steering head 60 during directional drilling in the high build up sections.

All wells generally differ in purpose, design, well trajectory, measured depth, or the like. Therefore, the planning stage is considered essential. The exemplary system for directional drilling using push-the-bit rotary steerable tool and method discussed herein provides the ability to select the design and parameters of steering head 60 that corresponds to the complexity of well trajectory and the assigned tasks. The planning stage (210 in FIG. 2) is illustrated in greater details, in FIG. 16.

FIG. 16 is a flow chart and block diagram illustrating steps for the planning and initialization stages. Step 81 includes obtaining information regarding drilling parameters and equipment for a proposed well and analysis of wells with a similar trajectory that were drilled in the same region by using other commercial rotary steerable systems. It is necessary to find out the previously used differential pressure for pads extension and the total area of the pad/pistons to which mud flow or internal oil pressure were applied.

Step 82 includes calculation of pressure drop by using only drill bit for a proposed well. It is obvious that the sum of pressure losses using combination of restrictors and drill bit is greater than the differential pressure caused only by the passage of drilling fluid through the nozzles of the drill bit.

FIG. 17 shows the dependence of the pressure drop of drilling fluid 32 through the bit 8 nozzles from flow rates for 4.75 inches diameter of the steering head 60. For the modeling of steering head 60 various parameters, the flow rate is used equal to 255 gpm, resulting in pressure loss 350 psi.

The differential pressure calculates at step 82 (for example, equal to 350 psi) should be reduced due to pressure losses caused by the size of the flow channels 311 diameter and the presence of the gap 62 connecting the cavity 331 inside the pad assembly with the annular space 15. The maximum total loss due to these factor is selected at step 82 and should not exceed 50-100 psi in most cases. Steps 83-95 show the logic behind selection of steering head 60 parameters according method disposed in the present invention. The selection is based on required impact on wellbore surface. The possibility of increasing the impact on the wellbore surface to match or exceed the impact of previously used commercial system is achieved by increasing the area of pad assemblies 61 and if this is not enough, then the interference constructive effect of the simultaneous use of two or more pad assemblies is additionally applied.

Let's evaluate the possibility of the force impact on the wellbore surface by using elongated shape of the pad assemblies 61.

Let denote as P_{diff orifice} the differential pressure created by orifices in most commercial systems using drilling fluid for pads extension. The differential pressure caused by passage of drilling fluid 32 through the bit 8 as P_{diff bit}. The areas affected by pressurized mud flow in a commercial system and on the pad base in proposed design will be denoted accordingly as S_com and S_enlarged.

As a first approximation, size of the area S_enlarged should ensure at least the following inequality in Equation 2:

P diff ⁢ bit * S enlarged ≥ ( P diff ⁢ orifice + P diff ⁢ bit ) * Scom ( 2 )

In order to take into account the pressure losses, let's introduce the dimensionless coefficient L in Equation 3, which takes into account the loss of pressure in the drilling flow 32 under the base of pads assembly 61 due to the diameter of flow channels 311 (P_loss Ø) and the gap 62 between the side surface of the pads assembly 61 and the interior surface of the chamber 330 (P_{loss gap}).

The coefficient L is equal to:

L = Pdiff ⁢ bit - Ploss ⁢ ∅ - Ploss ⁢ gap Pdiff ⁢ bit ( 3 )

For example, for the total loss is equal to 50 psi and P_{diff bid} equal to 250 psi, L=0.8. Inequality (2) is supplemented by coefficient L will have the form of Equation 4:

P diff ⁢ bit * S enlarged ≥ ( P diff ⁢ orifice + P diff ⁢ bit ) * S com ( 4 )

The design of pad assembly 61 proposed in the present invention allows to satisfy condition (4) by increasing the S_enlarged factor. However, the ratio of S_enlarged to S_com due to practical geometric considerations, might not exceed a value of 2.5-3.0. The ratio of K=P_{diff orifice}/P_{diff bit} is usually in range from 1 to 4. For example, If S_enlarged=3 S_com, then inequality (4) is satisfied with K≤3L−1. For L, for example, equal 0.8, value of K might not exceed 1.4. Such effect, which is, based on drilling fluid flow 32 goes simultaneously into two or more flow channels 311. An illustration of this effect is demonstrated on FIG. 19 and FIG. 21. In case of using steering head 60 with 3 pads assemblies 61, the maximum value of construction interference (K_int) impact is equal to 1.8, which allows to compensate lack of complex design with orifices when value of coefficient K is equal or less than 2.52.

In some cases, to obtain the required impact on the wall surface by steering head 60 with 3 pads, it may be sufficient to use a K_int value less than equal to maximum value of 1.8.

Depending on drilling requirements and tasks for drilling a well with a particular trajectory, the value of K_int can be selected in the range greater than 1.0 and less or equal to 1.8.

Orbitally, the range of K_int for steering head with 3 pad assembly 61 can be divided into 4 categories: from 1.0-1.2—very low effect; from 1.2-1.4—low effect, from 1.4-1.6—medium effect and from 1.6-18—strong effect.

After step 82, depends on the answer in step 83, planning sequence is going to step 84 or step 87. If the previously used commercial systems allowed drilling well with similar trajectory, next step is 84. In such case, as shown above, there is confidence that the task can be accomplished using steering head 60 with 3 pads design. If the trajectory of proposed well would require, for example, to increase DLS by 20-50 percent or more, then proceeding to step 87 and 88. It is still possible that 3 pads design capable to satisfied additional requirements, but if not, then moving to step 90 to evaluate the maximum capabilities of the 4 pads design. The maximum of the constructive interference coefficient K_int for the 4 pads is equal to 2.6. In inequality (4) should be supplemented by a coefficient K_int (ratio of the average force impact on the wellbore wall due to the simultaneous openings of two or more pad assemblies 61 to the average force impact for a typical commercial system). Then, inequality (4) can be written using coefficient K in the following form of Equation 5:

L * S enlarged * K int ≥ ( K + 1 ) ⁢ S com ( 5 )

Let's consider the extreme case when K=4. For S_enlarged=3 S_com and, for example, L=0.8, we get, that K_int≥2.08.

Let's evaluate the possibility of providing an equal or greater force impact on the wellbore walls for the proposed method and apparatus in relation to a typical system for K=4, S_enlarged=3 S_com and L=0.8. Substituting these values into inequality (5), we find that the equal impact is achieved at K_int=2.08. In the K_int range 2.09-2.4, it is possible to have higher impact compare to a typical system.

Thus, in accordance with the block diagram in FIG. 16, by the time to go to step 96, the number of pad assembles 61, area of pad assembles 61 base (S_enlarged) and value of K_int have been selected. Calculation of K_int for designs with 3 and 4 pad assemblies is illustrated below in FIGS. 19-23.

Step 96 is designed to calculate the gaps between the side surface of the pads assembly 61 and inner surface of chamber 330, as well as the gap between flat base of rotational valve 360 and the top surfaces of inserts 313. At step 96, a diameter of flow channels 311 is assessed. One of the procedure important reducing wear and tear of top surface of the pads assembly 61 is a selection of springs force 343 sufficient to tearing the top cover of pad 342 from wellbore surface during the time when flow channel 311 is closed.

Preparation stage 210 ends with step 97—planning and preparation. To illustrate the benefits of constructive interference effect aimed to increase total impact of steering head 60, the azimuth coordinate system for tool face is used as a reference in FIG. 18. The method of steering a well in a desirable direction with respect to gravity or magnetic north is based on ability of rotational valve assembly 360 opening “geostationary” position when an angle between middle of the rotational valve assembly 360 opening 362 and angle of gravity (GTF) magnetic North (MTF) corresponds with direction opposite by 180 degrees to the desirable well direction. An instantaneous GTF of zero degrees corresponds to the point when a reference mark on the tool, known as a “scribe line”, is oriented towards the top of borehole, GTF of 180 degrees corresponds to the point when the scribe line is oriented towards the bottom of the bore hole.

FIG. 19 illustrates an example of directional drilling where the desired drilling direction coincides with the X axis. In this case, as noted earlier, the distribution rotational valve assembly 360 is in a geostationary position along the X axis. The tool face at given geostationary position denote as 402. The projection of reactive force on the steering head 60 in the desired direction is represented by Equation 6:

F x = F max * cos ⁡ ( φ ) ( 6 )

where F_max is reactive force at φ=0 (point 401 on FIG. 19).

For the perpendicular direction (axis y on FIG. 19) projection of reactive force on the steering head 60 is given by Equation 7:

F y = F max ( sin ⁢ φ ) ( 7 )

where φ is the angle between axis X and line connecting the point of the interaction between pad assembly 61 with formation with the athimutal coordinate center at intersection of X and Y axes.

Let's consider the projections of reactive forces 403 (equal to F_max) to on X and Y axes at two points 404 and 405 located symmetrically with respect to the X axis. Projections 406 are equal to each other and directed in the desired drilled direction, this follows from the properties of cosine function as shown in Equation 8:

cos ⁢ ( φ ) = cos ⁢ ( - φ ) ( 8 )

The projections onto the Y axis 407 and 408 are equal and directed in opposite directions, this follows from the asymmetrical property of sinus function of Equation 9:

sin ⁢ ( φ ) = - sin ⁢ ( - φ ) ( 9 )

Based on the Equations 6-9, it follows that in the range of angles φ from 90 to minus 90 degrees there are useful components of the reactive force in the desired drilling direction on axis X. At the same time, the total effect of the reactive force components on Y axis in the same range of angles is equal to zero and does not affect the well trajectory.

The present invention uses the principles described above, which makes it possible to provide simultaneous impacts on the borehole wall with two or more pads, fulfilling the condition that the impacts are in the range of 180 degrees or less.

The ability to enhance the impact of steering head 60 compare to tradition commercial systems due to the simultaneous contribution of two or more pads provides increase of total impact. Such effect in the present invention is named as constructive interference. FIGS. 20-23 allow to illustrate such effect in more details.

FIG. 20A shows a cross-section of a spider distribution unit for a typical commercial rotary steerable system with 3 pads. Radial angle for rotational valve notch 432 and angle between two tangent to flow distribution channels 430 are equal to 60 degrees.

FIG. 20B shows by graphs 481 and 482 of the impact force of the pads on the wellbore surface depending on the collar angle position during one 360° rotation. The graph 482 is corrected for cosine of angle φ. In this example, the geostationary position of rotational valve corresponds to a value of 60 degrees (the desired directional drilling direction corresponds to tool face of 240 degrees). The maximum impacts on the well wall F_max correspond to drill collar angles equal to 60, 180 and 300 degrees, when the positions of the center of channel 1, 2 and 3 coincide with the center of rotational valve opening 362. The dotted line shows the same dependence taking into account the correction for the cosine of the angle φ.

Based on the graph 482 presented by the dotted line, it is calculated that the average value of the reactive force on the typical commercial steering tool is equal to half the value of F_max.

Efficiency of a typical RSS with 3 extended pads with inlet flow channels and rotational valve opening equal 60 degrees is relatively low. The presence of a hinged cover in most systems leads to additional decrease in efficiency due to the leverage effect.

The possibility of increasing efficiency of push-the-bit RSS according to principals of the present invention is lustrated in FIGS. 21A and 21B. FIG. 21A shows one of the possible arrangement of flow distribution channels 311 and rotational valve opening 362. Rotational valve 360 is at geostationary position and pointed to the point 401 at the wellbore surface. The opening 362 angle 430 is equal to 120 degrees. The flow distribution channels 311 have angle 432 equal to 60 degrees. The selected angles values ensure the achievement of the maximum value of the constructive interference coefficient K_{int max}, when sum of these angles is equal to 180 degrees.

Distribution flow channels 311 (numbers 1 and 2 or numbers 2 and 3) are located symmetrically relative to X axis and the corresponding pads assembly 61 provide an equal contribution to the total impact by two pads on borehole surface, and, accordingly, equality of reactive forces and their projections on the axis X. FIG. 21B illustrates that, such positions of flow channels 311 to the rotational valve 360 opening 362 corresponds to the intersection points of the graphs 481 and 482 with correction for cosine of angle φ at collar angles of 120 or 240 degrees. The total reactive force on bias unit 60 projected into X axis is presented by graph 483 which is sum of graphs 482. The behavior of graph 483 shows that the result of constructive interference effect on steering head 60 during drill collar rotation is almost uniform. The average total impact value is equal to 0.92 of the maximum impact value 1.0 (in relative units). The ability to use constructive interference effect according the disposed in the present invention method and apparatus allows to increase efficiency of 3 pads RSS by up to 1.8 times.

Further increase of RSS efficiency may be achieved by increasing the number of pads assembly 61 to 4 or more pads.

FIGS. 22A-23B illustrate the effectiveness of a traditional commercial system designs on FIG. 22A and new design on FIG. 23A for 4 extended elements. FIG. 22A shows an example of four flow channels 430 and rotational valve opening 432 when their value are equal to 45 degrees. FIG. 22B shows graphs 481 and 482 of the impact force of the pads assembly 61 on the wellbore surface depending on the collar angle position during one 360 degrees rotation.

The efficiency of 4 pads typical commercial system is the same as typical 3 pads commercial system and is equal to 50 percent. If hinged cover is used as intermediate element to transfer force from the pistons to the wellbore surface, then the efficiency of it is further reduced due to the lever effect).

FIG. 23A shows one of the possible arrangement of flow distribution channels 311 and distributor rotational valve notch 362. The center point of the notch 362 is at point 401. The angle 432 is equal 45 degrees and notch angle 430 is equal 135 degrees.

The sum of angles 432 and 430 is equal 180 degrees that ensure the achievement of the maximum value of the constructive interference coefficient K_{int max}. When flow distribution channels 311 in pairs (1 and 2 or 2 and 3 or 3 and 4) are located symmetrically relatively the X axis both corresponding flow distribution channels 311 are fully opened and the maximum impact value on wellbore surface is achieved.

FIG. 23B shows graphs 481 and 482 (corrected for cosine angle of φ) force impact on the wellbore surface from each flow channels 311. The total reactive force on steering head 60 projected onto X axis is presented by graph 483. The behavior of graph 483 shows that a total constructive interference effect on steering head 60 during drill collar rotation has a quasi-periodic behavior. The minimum values of this function correspond to the positions of the flow distribution channels 311 when their centers coincide with the midpoint of opening 362 and corresponded the function 483 values are equal to 1.0.

The maximum values of this function correspond to channel positions symmetrical to the X Axis (see FIG. 23A) and have values equal to 1.41. The average total impact value of function 485 is equal to 1.2 of the maximum impact value 1.0 (in relative units). Considering that the efficiency coefficient for a typical commercial system with equal angles values for flow channels and rotational valve opening equal 0.5 and can reach value of 1.2 for the method and apparatus disposed in the present invention, then the efficiency due to constructive interference increases by 2.4 times. The calculation of some parameters of the apparatus disposed in the present invention and conditions for effective application of the method is carried out by using numerical modeling methods and appropriate software.

Computational Fluid Dynamics (CFD) software was utilized to produce simulation results shown in FIGS. 24-27. CFD software leverages mathematical modeling and numerical techniques to solve the governing equations of fluid flow. The software takes into account the conservation equations for mass, momentum, and energy. [Reference: Anderson, J. D. Jr., “Computational Fluid Dynamics: The Basics with Applications,” 1st Edition, McGraw-Hill Education, 1995.]. Through a combination of algorithms and numerical methods, CFD software discretizes the computational domain and solves these equations to obtain detailed insights into the behavior of fluids and their impact on the surrounding environment. [Reference: Versteeg, H. K., and Malalasekera, W., “An Introduction to Computational Fluid Dynamics: The Finite Volume Method,” 2nd Edition, Pearson Education Limited, 2007.]

The 3D model of the steering head 60 is placed within a model of annular space, meaning that the steering head 60 itself is located inside another pipe. The inlet for the fluid is the main channel of the steering head 60 (non-shown) from the side of the valve output shaft 364, and the inlet boundary condition defines a fluid flow of 10 liter per second under a pressure of 2000 psi. The outlet for the fluid is the area between the outer surface of steering head 60 and the wellbore. The results of the flow simulation calculations include the distribution of fluid pressure on surfaces (pad top/bottom, etc.), volumes (chamber, pipe, etc.), total forces acting on the solid body surface from the fluid, and flow of the fluid through specified cross-sections (through branches or gaps).

The modeling was performed for various geometries of the components of steering head 60. For example, varying the thickness of the chamber wall allows to adjust the pad gap 61 within the required range.

Fluid-Structure Interaction (FSI) software was utilized to simulate the process of fluid displacement from the chamber when the pad is returning into “in-chamber” position under force of springs 343. Fluid-Structure Interaction (FSI) software is a specialized computational tool simulating the behavior of fluid flow interacting with deformable structures. It combines Computational Fluid Dynamics (CFD) methods and Structural Mechanics (SM) methods to model and predict the complex fluid-structure interaction of systems where fluid dynamics and structural response are tightly coupled. Interface conditions are defined to transfer forces, displacements, velocities, and pressures between fluid and solid domains. [Reference: Hurek, S., et al., “Fluid-Structure Interaction: Models, Software, and Applications,” Springer, 2017.]; [Reference: Farhat, C., and Geuzaine, P., “Advances in Computational Fluid-Structure Interaction and Flow Simulation: New Methods and Challenging Computations,” Wiley, 2016.]

The next step 96 has the following objectives:

• • a) select a gap 62 between side surface of the pad assembly 61 and internal surface of the chamber 330;
  • b) select a gap 369 between distribution rotational valve 360 flat surface 367 and the top of the inserts 313 into the flow channels 311;
  • c) determine compression spring sets 343 force necessary to return the pad assembly 61 to its initial state or to detach it from the wellbore surface during the period of closing the corresponding flow channel 311.

The gap 62 selection process is illustrated in FIGS. 24 and 25. FIG. 24 shows the dependence of the percentage of the drilling fluid flow 32 through the gap 62 from the total value of flow the drilling fluid 32 through steering head 60 for different diameters of the flow channels 311.

Graph 451 corresponds to flow distribution channels 311 diameters of 6 millimeters, 452 to 8 mm, 453 to 10 mm and 454 to 12 mm. A detailed study of these graphs shows that in the range of gap 62 from 0.01 mm to 0.05 mm all graphs completely coincide with each other. At gap 62 value of 0.05 mm the part of the flow through it is equal to 1.49% of the total fluid flow through steering head 60.

For the gap size equal to 0.1 mm the amount of drilling through gap 62 is increased to 4.0-4.2% (depending on flow channels 311 diameters). A further increase of the gap 62 value, for example, to 0.15 mm for a flow channel 311 diameter of 8 mm, leads to the amount of drilling fluid through gap 62 is reached 7%, which corresponds to the maximum level accept in the industry. Considering that in the disposed in present invention method and apparatus, the drilling flow 32 simultaneously pass through two or more flow channels 311, the gap value 61 for the steering head 60 geometry under consideration should be in the middle part of the range 0.05-0.1 mm.

At the same time, another condition for the effective use of the present invention method and system should also be met—to prevent a decrease of the differential pressure (created by the mud flow 32 passage through drill bit 8) by an amount exceeding the calculated value, or predefine value. Pressure losses in the area of interaction with pressurized flow under the pad depend on both the size of gap 62 and the diameter of the flow channels 311. These losses may significantly reduce the differential pressure created on the bit 8.

FIG. 25 shows graphs of the dependence of differential pressure loss from the diameter of flow channels 311 for several gaps 62 values. Graphs 491, 492, 493 and 494 correspond to values equal 0.01 mm, 0.05 mm, 0.1 mm and 0.15 mm respectively.

In the example shown on FIG. 25, the differential pressure created by the drilling flow 32 passing through the drill bit 8 is 380 psi. Let's consider two cases of the maximum permitted differential pressure (shown as dotted lines) losses equal to 50 psi and 100 psi respectfully.

In the case of the maximum pressure loss is 50 psi, for the gap 62 equal to 0.1 mm, the diameter of flow of flow 311 should be at least 7 mm (see graph 493) in order to have differential pressure above 330 psi. For gap 62 equal 0.05 mm (position 492) the condition of the pressure stays above 330 psi is satisfied at diameter to 5.2 mm by interpolating between graphs 492 and 493, the appropriate parameters for the steering head 60 geometry could be selected for gap 62 as 0.075 mm and for diameter of flow channels 311 equal to 5.8 mm. If maximum pressure loss is equal to 100 psi, the condition of differential pressure above 280 psi is met with a gap 62 equal to 0.15 mm and flow distribution channels 311 diameter is equal to 7.4 mm (see graph 494). However, with gap 62 equal to 0.15 mm, the volume of fluid flow through the gap 62 is increased to 7.0 percent (see FIG. 24, graph 452).

Block 96 is also designed to select a gap 369 between rotational valve 360 flat surface disk 367, and the top surface of the inserts 313.

In the preferred embodiments the gap 369 is equal to zero. In such case there are no leakage of drilling fluid 32 into flow channels 311 when they are closed. Based on numerical modeling for set of springs 343 with different initial strengths, the graphs of separation of pad top cover 342 from wellbore wall from time are obtained. FIG. 26 show graphs 501,502, 503 and 504 for the set of springs 343 with initial strengths equal to 20, 40, 80 and 160 kg respectfully. The time of movement of the pad top cover 342 in the direction to the initial position is equal, according to one or more embodiments, to half the time of one revolution of the drill collar 6. For example, for drill collar 6 rotations per minute (RPM) equal to 240, one revolution time is 250 milliseconds, the closing time of channel 311 is 125 milliseconds. For the set of springs 343 with initial strengths equal to 80 kg (graph 503) the distance from wellbore wall is reached 6 mm (position 505). For RPM 120, the separation from the wall is doubled to 12 mm (position 506).

Note that the use of the set of springs 343 with initial strength of 20 kg (graph 501) provides a separation sufficient for most cases to extend the service life of the pad top cover 342.

In case when gap 369 is not equal zero, it is necessary to take into account the rate of drilling flow 32 into the closed flow channels 311, which leads to an increase in fluid pressure in the chamber 330 relative to the annulus pressure. The graph 496 in FIG. 27 shows the amount of additional pressure in chamber 330 depending on the drilling fluid 32 inflow into closed flow channels 311 as percentage of the total volume if drilling fluid 32 passing through the steering head 60 (upper horizontal scale) and on the value of gap 369 (lower horizontal scale). For the gap 369 equal, for example, 0.06 mm, the pressure of drilling fluid 32 inside the chamber 330 is increased by 2.35 psi. A set of springs 343 with equal to 2.45 psi position 497 for area under the pad assembly 61 equal to 48 cm square in the used model for disposed example.

This level of pressure ensures the displacement of the incoming drilling fluid 32 into the chamber 330, but to displace the drilling fluid located in the chamber 330, it is necessary increase the force of the set of springs 343 by the value that can be selected using graphs 501-504 shown in FIG. 26.

For example, for RPM 240 and the detachment equal to 6 mm the initial strength of the set of springs 343 is equal to 80 kg (see position 505). Thus, for preventing leakage into flow channels for gap 369 equal to 0.06 mm additional 80 kg strength is necessary add to the selected (position 505) initial strength 80 kg resulting initial strength equal to 160 kg. If the detachment value is reduced to 3 mm, then the initial strength of the set of springs 343 is only 20 kg resulting an initial strength equal to 100 kg.

The completion of the preparation stage 210 (shown in detail in FIG. 16) is carried out at initialization stage 97 (shown in FIG. 16).

The final stage 97 of a preparation for the start of the directional drilling is programming of firmware of controller and processor unit 64 of control unit 67, which includes:

• • set of downlinking commands;
  • set of uplinking commands and formats of data transmissions;
  • proportional steering initial parameters;
  • tops of geological formation.

FIG. 28 shows example of workflow for performing directional drilling in according to embodiments of the present invention.

After completion of the implementation stage 210, the drilling starts (Block 573). In Block 573 the starting value of tool face and parameters for the proportional steering are selected and downlinking.

Based on the selected design of the steering head 60 the initial estimation a the maximum DLS is made. Depending on the value of the current DLS_i value, the percentage X of the directional drilling time to the duty cycle time T is calculated by Equation 10 as:

X = DLSi DLS ⁢ max ( 10 )

For example, the DLS_max is equal to 20 degrees for 100 feet, and the DLS_i=8 degrees for 100 feet, then X=8°/20°=40%. Respectfully, the drilling of 60% of the duty cycle T, drilling should be similar to drilling the so-called tangential section of the well trajectory when inclination and azimuth parameters do not change. In prior art practice duty cycle is usually equal to 1-2 minutes, is divided into directional and tangential drilling intervals. This causes unwanted trajectory patterns during high drilling speeds. For example, at drilling speed 300 feet's/hour and duty cycle 120 sec, DLS_max equal 12 degrees per 100 feet's and current DLS equal to 6 degrees per 100 feet's, directional drilling period is equal to 60 sec. During 60 sec 5 feet's are drilled resulting in developing undesirable curvature on the well trajectory. Another challenge for most commercial RSS is drilling the tangential portion of a duty cycle. One of a popular method is based on changing toll face orientation of rotational valve according to the law of random numbers.

In the present invention, the duty cycle T is divided into 2 or more sub-cycles, the entire 360 degrees range of tool face values is divided into 12 or more equal sizes sectors to ensure a smooth well trajectory.

Block 574 is responsible to drill a distance of the length equal to one drilling string by using parameters for proportional steering and/or Tool face value received from block 210 at a start of drilling and from Block 579 after the start of drilling.

In Block 574, during the drilling operation, the control unit 67, which is responsible to provide proportional steering by using parameters of duty cycle received from block 579 according to the following procedures:

• • the entire range of tool faces value is divided into a number of sectors in a such way that the middle of the first sector coincides with the value of the desired current tool face value;
  • the drilling time of a straight section is calculated as the difference between the duration time T and the time of drilling a curvature section of the well trajectory;
  • calculate the drilling time for straight Ts and curved sections Tc for sub-cycles;
  • ensure the “geostationary position” of the rotational valve 360 opening 362 is located inside each sector during the appropriate time.
  • Determination of the position of the rotational valve 360 is based on real-time processing of directional sensors measurements with a frequency of 125-1500 measurements per second. The average value of tool faces for a given sector is determined. If this value is within the boundaries of a sector, then a value equal to one is added to a counter. In case the average value is outside of the sector boundaries, then the value equal one is added to the counter of the corresponding sector. By the time the drilling cycle is completed, the counter values for all sectors should be equal to the number of sub-cycles. The time which is allocated to curvature portion during sub-cycle is calculated by using Equation 11:

T dir . sub = T * X M ( 11 )

• • where M—amount of sub-cycles.

It should be noted that the relationship between the force applied to the wellbore walls and DLS is difficult to establish by using various methods including comprehensive modeling. This dependence is influenced by a number of poorly predictable factors such as local anisotropy and heterogeneity of rocks, the presence of vibration and shocks of drilling tool, the presence of the stick-slip effect, etc.

The proposed method uses as initial value of DLS the DLS_maxj drilling cycle T for each new j geological formation. In the assumed to value of DLS_maxj differs from it's the actual value, then correction is carried out when drilling the next drill pipe or during drilling several drill pipes.

The sequence of actions in Block 576 based on instruction received from Block 575 is illustrated by the following example.

Let duty cycle T be equal 100 seconds. The number of sub-cycles is 4; the number of sectors G=20, time Tc for directional drilling is 40% from T. Number of directional sensors measurements-1000 per second.

Based on these data, the following parameters are calculated:

Directional ⁢ drilling ⁢ time ⁢ ⁢ Tc = 40 ⁢ sec

Tangential drilling time Ts=60 sec respectively, for sub-cycles these values are:

tc = 10 ⁢ sec ; ts = 15 ⁢ sec ;

The size of each of 20 sectors is equal to 18°.

During each sub-cycle the time t₅ when the rotational valve 360 opening 362 is located in geostationary position within the boundaries of each sector is ts/G=15/20=0.75 sec.

During period of 0.75 sec 750 measurement to tool face values and average value are calculated. In accordance with the procedure described above counter value increases by one for the sector within which the average value of the tool faces is located. By the end of duty cycle T, the counter values for each sectors are equal to the number of sub-cycles (equal to 4 in this example).

Directional drilling time in each sub-cycle to equal to 10 seconds and a total directional drilling time Tc equal to 40 seconds or 40% of drilling cycle T.

After completion of drilling the first drilling cycle, the counter values for all sectors reset to zeros, and the procedure are repeated to the second and subsequent cycles until the drilling pipe or stand is drilled, which means the end of activity of block 574 and transition to block 577.

Block 575 is used to obtain data on the spatial position of the BHA 24 during stationary mode, as well as obtain LWD data on the physical properties of rocks. This data is used to compare actual data with planed well trajectory in block 577 after uplinking this information in block 576.

In block 577 the planed DLS value is compared with actual value which is based on directional measurements obtained in block 575.

In block 578, if planned and actual trajectories coincide, next step is going to block 581, which tracks the moment of achieving the target depth and in the goal is achieved, the block 582 stops the drilling operation, otherwise control passes to block 574 and drilling of the next pipe stand continues.

In case of a difference exceeding the threshold value set in block 579, the ratio of directional drilling time Tc to drilling cycle time T is adjusted. The adjustment of the planed trajectory and the actual trajectory is performed in such way that a match occurs after drilling the next pipe stand or after drilling dulling two or more pipe stands (to maintain a smooth trajectory).

In case of drilling tangential portion of the well trajectory or drilling lateral according to the proposed method, a drilling cycle time T and amount of sub-cycle are increased in order to achieve smooth trajectory and have ability to drill with zero or small value of DLS.

In these situation, in order to reduce the error in predicting the value of DLS for the next stand, data from two or more drilled stands are used.

Block 580 is responsible for downlinking adjusted steering parameters to block 581 and further to block 574 to continue drilling next pipe stand.

The RSS designs of the present invention have the advantage of containing fewer parts, lack of orifices and sealing in the steering head 60, while is inexpensive to produce and maintain. The steering head 60 length is short and located close to the Drill Bit 8 resulting in high DLS values.

The present invention designs allow multiplication of applied forces on the wellbore walls due to the simultaneous impact of two or more pads and increasing the area of hydraulic contacts of drilling fluid on the base of the pads assembly 61.

The present invention have a number of other advantages such as guaranteed full of partial closure of pads during time when flow channels 311 are closed, drilling smooth wellbore trajectory and a number of others benefits described in the text of the present invention. The describe system and method are scalable for various borehole sizes. While it will apparent that the mentions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and changes without departing from the spirit thereof.

It will be readily appreciated by those skilled in the art that various modification of embodiments taught by the present disclosure may be devised without departing from the teaching and scope of the present disclosure. It is especially to be understood that the present disclosure is not invented to be limited to any described or illustrated embodiment, and that the substitution of a variant of a claimed element or feature without any substantial resultant change in operation, will not constitute a departure from the scope of the present disclosure.

Some provisions and components of present invention may benefit various application of commercial rotary steerable systems used for directional drilling.

A system with 3 extended members that use a system with hydraulic oil and has a mechanism to independently activate extended members (example RSS developed by APS Technology) or a system that use drilling fluid to activate extended members having 3 rotational valves that capable independently regulate the flow of drilling fluid into the flow channels (example, Magnus RSS by Weatherford) are using dwell angles equal to or less 120 degrees while the extended members are activated sequentially. Based on the teaching of the present invention, both group may increase the average force of extended members on the wellbore surface by using dwell angles in the range from 120 degrees to 180° degrees resulting in increase the efficiency of such systems up to 80%, and in case of having 4 extended members the efficiency may go up to 130%.

Commercial systems with pressurized drilling fluids as means for activating extended members may increase their efficiency by 2-3 or more times by enlarging an area of drilling fluid contacts with the extended members design revealed in the present invention.

Utilization of another aspect of the present invention may double service life of extended members by using a set of springs according to present invention teaching by tearing of the outer surface of the extended members from borehole surface.

Another opportunity to improve the performance of systems with rotational valve or valves is a reduction of the friction between the downward surface of rotational valve disk and the upward surface of a device with flow channels. The paradox of this situation based on the need to simultaneously satisfy seemingly mutually exclusive conditions: the first condition is required a gap between these parts to minimize friction, and the second condition, on the contrary, requires significantly reducing the gap to prevent leaking of drilling fluid into the flow channel during its closure. The present invention proposes two solutions to this apparent contradiction based on the use of inserts on the inlet of the flow channels.

The first solutions is based on having a portion of the inserts extending beyond the flat upward surface of a device with flow channels by an amount of at least 0.3-0.4 mm or more ensuring the gap sufficient to balance of fluid pressure above and below the rotational valve disk, while condition of zero gap between disk plate and the top of the inserts is achieved by pressing the disk by energy of drilling fluid flow.

The second solution involves also using inserts by also adding a pin between the downward surface of the disk and the upward surface of the device with flow channels. The pin size is equal or up to 0.05-0.1 mm longer than the protruding part of the inserts.

Thus, the design options disposed in the present invention allow simultaneously achieve a low friction and minimize drilling fluid leakage closed flow channels.

The system discussed herein provides several operational advantages, a non-limiting list of which is provided below:

• • Elongated shape of pad assemblies allows an increase in area of communication with pressurized drilling flow by few times resulting on increasing force impact on the wellbore surface. In existing commercial systems are used piston or balls in order to transmit fluid pressure to wellbore walls. Also, design of pad assembly has various novel elements including fastening spring set.
  • Central element of steering head-manifold block allows to fastened bottom of pad assemblies chamber to flat surface of the manifold block resulting in a rigid structure. Such design allows to avoid attaching pad assemblies to drill collar.
  • A presence of the gap between the flat surface of the rotary valve disk and the upward surface of the manifold block ensures equal pressure of drilling fluid above and below disk resulting in eliminating strong friction between rotational valve and flow distribution channels in typical commercial systems. This gap is ensured by presence of inserts into flow distribution channels. At the same time, the limited friction sliding contact between disk and inserts blocking the flow distribution channels allowing to reduce rotational force necessary to rotate disk.
  • A rule has been proposed for the ratio of angular values for flow distribution channels and openings in the disk to create construction interference effect when drilling fluid simultaneously enter into two or more (in case 6 flow channels) see claim 2. Those relations are also important part of the proposed method.
  • All known RSS which utilized differential pressure (difference between pressure inside steering tool/head and pressure in annular space between drill pipe and well bore wall). The pressure difference in a typical RSS (using drilling mud as a source of pressurized fluid) is created by the pressure loss going through orifices/restrictor and through the nozzles of the drill bit. In the proposed method the only source for creation of the differential pressure is drill bit. By using a conventional RSS in some condition it might be possible to use also only drill bit, but in most cases the combination of orifice and drill bit is required. The proposed method allows to use only differential pressure created on drill bit since there are two opportunity to increase force impact on wellbore surface from differential pressure of the bit by increasing area of an actuated member (pad internal area in the contact with pressurized drilling mud) or/and use amplification due to effect of simultaneous contact with wellbore wall two or more pad assembly. The method and system allows to exceed average force impact on the wellbore wall generated by commercial systems with orifices.

REFERENCE NUMBER LISTING

• • 1—rig
  • 2—borehole
  • 3—earth
  • 5—formation
  • 6—drill string
  • 8—drill bit
  • 9—centralizer(s)
  • 10—RSS
  • 11—flow sensor
  • 12—sensor module
  • 13—downhole transducer
  • 14—source of energy
  • 15—annulus space
  • 16—controller
  • 17—borehole wall
  • 18—motor control
  • 20—modulator
  • 21—pulser assembly
  • 22—BHA
  • 30—mud pit
  • 32—drilling fluid
  • 34—pump
  • 36—fluid mud line
  • 38—transducers
  • 40—analog/digital device
  • 42—processing device
  • 50—pressure fluctuation
  • 51—modulator
  • 52—transducer
  • 54—remote location center
  • 55—stand pipe gauge for pressure
  • 56—hook load sensor
  • 57—depth tracking sensor
  • 60—rotary steering head
  • 61—pad assembly
  • 62—gap to annulus
  • 63—flow metering system
  • 64—main controller and processor
  • 65—directional sensors
  • 66—power source
  • 67—control unit
  • 301—thread on the surface side
  • 302—thread on bit side
  • 310—manifold block
  • 311—flow distribution channel
  • 312—flat surface of the manifold block 310 to attach chamber 330
  • 313—flow distribution channel inserts
  • 314—space between flow distribution channels inserts 313
  • 315—opening into the chamber 330
  • 316—top flat surface of manifold block 310
  • 317—threaded holes for bolts 336
  • 318—central part of top surface 316
  • 320—guide device
  • 321—guide device 320 mounting hole
  • 322—guide device blades
  • 330—chamber
  • 331—space for pads
  • 332—hole for fuse
  • 333—hole in the bottom of chamber 330 to enter fluid 32
  • 334—holes to attach the bottom of 330 to 310
  • 335—holes to attach springs 343 to bottom of 330
  • 336—bolts
  • 342—top cover of the pad
  • 343—compression springs
  • 344—mounting plates for springs (lower ends)
  • 345—mounting plates for springs (upper ends)
  • 346—mounting angles
  • 347—base plate of lower connecting plate
  • 348—elongated slots
  • 351—tightening bolts
  • 352—carbide inserts
  • 353—space for drilling fluid
  • 354—tightening bolts
  • 360—rotational valve
  • 361—gap between rotational valve disk and inserts 313 (valve gap)
  • 362—openings
  • 363—cylindrical pin
  • 364—shaft of rotational valve 360
  • 365—flow-metered assembly
  • 366—recesses on shaft 364
  • 367—flat plane of the disk
  • 369—valve gap between 367 and 313
  • 368—rounded support on shaft 364
  • 369—valve gap between 367 and top surface of the manifold
  • 430—angle α
  • 432—angle β