PRESSURE AND FLOW CONTROL IN CONTINUOUS FLOW DRILLING OPERATIONS

TECHNICAL FIELD

This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for pressure and flow control in continuous flow drilling operations.

BACKGROUND

It can be beneficial to continuously circulate fluid through a drill string, in part because ceasing and then restarting flow (such as, to allow a section to be added to or removed from the drill string) can cause detrimental pressure fluctuations in a wellbore being drilled. Therefore, it will be appreciated that improvements are continually needed in the arts of constructing and operating well systems which provide for continuous flow during drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of a system and a method for providing substantially continuous circulation through a drill string and an annulus formed between the drill string and a wellbore, which system and method can embody principles of this disclosure.

FIGS. 2-12 are representative schematic views of various steps of an example of the method.

FIG. 13 is a representative block diagram of a hydraulic control system that may be used with the system and method.

FIGS. 14 & 15 are representative schematic views of steps of another example of the method.

DETAILED DESCRIPTION

FIG. 1 is a representative partially cross-sectional view of a system 10 and a method for providing substantially continuous circulation through a drill string 12 and an annulus 14 formed between the drill string and a wellbore 16, which system and method can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method described herein and/or depicted in the drawings.

A land-based well is illustrated in FIG. 1, but it should be clearly understood that the principles of this disclosure can be readily applied to subsea or other water-based wells, for example, using floating, fixed or jack-up rigs. Thus, the scope of this disclosure is not limited to any particular details of the well depicted in the drawings or described herein.

In the FIG. 1 example, a section 12a of the drill string 12 protrudes upwardly from an annular seal device 18 connected above a blowout preventer stack 20. The blowout preventer stack 20 depicted in FIG. 1 includes an annular preventer 20a, a variable ram 20b, a blind ram 20c, a flow spool 20d and a pipe ram 20e connected above a wellhead 22. In other examples, other or different equipment could be used in or substituted for the annular seal device 18, the blowout preventer stack 20 and/or the wellhead 22.

The drill string 12 is used to drill the wellbore 16. For this purpose, a drill bit 24 is connected at a distal end of the drill string 12. The drill bit 24 could, for example, be a rotary cone, fixed cutter, impact or other type of drill bit.

In some examples, the drill bit 24 may be rotated by rotating the drill string 12 at or near the earth's surface, such as, by use of a rotary table (not shown) or a top drive (not shown). In some examples, the drill bit 24 may be rotated by use of a drilling motor 26 connected in the drill string 12. In other examples, the drill bit 24 may not be rotated.

Thus, the scope of this disclosure is not limited to any particular technique for causing the drill bit 24 to drill the wellbore 16. Indeed, it is not necessary for the drill bit 24 to be used at all. For example, a jet drill (which drills by means of a fluid jet) could be used instead of, or in addition to, the drill bit 24.

While the wellbore 16 is being drilled, a fluid 28 is pumped through the drill string 12 into the wellbore 16. The fluid 28 exits the drill bit 24 and flows back to the surface via the annulus 14. A non-return valve (unnumbered in FIG. 1) can be used in the drill string to prevent reverse flow of the fluid 28 through the drill string 12.

The fluid 28 can serve many purposes, such as, to cool and lubricate the drill bit 24, to stabilize the wellbore 16, to transport cuttings to the surface, to maintain a desired pressure in the wellbore, etc. The fluid 28 can be combined with a variety of additives, for example, to increase or decrease the fluid's density, to provide a protective layer or “cake” lining in the wellbore 16, etc. The fluid 28 can be known to those skilled in the art as drilling “mud” although it could in some examples be merely brine water. Nitrogen or another gas, or another lighter weight fluid, may be added to the fluid 28 for pressure control. This technique is useful, for example, in underbalanced drilling operations. Thus, the scope of this disclosure is not limited to use of any particular fluid in the system 10.

The annular seal device 18 seals off the annulus 14 at or near the surface using, for example, an annular seal (not shown) that encircles the drill string 12. The annular seal may or may not rotate with the drill string 12 when or if the drill string rotates.

The device 18 may be of the type known to those skilled in the art as a rotating control device, rotating control head, rotary diverter, rotating blowout preventer, etc. In that case, the device 18 may include bearings (not shown) which allow the annular seal to rotate with the drill string 12 while sealing off the annulus 14 from atmosphere at or near the surface. However, it should be clearly understood that the scope of this disclosure is not limited to use of any particular type of annular seal device in the system 10.

The fluid 28 exits the annulus 14 via an outlet line 44 connected to the device 18 (for example, below the annular seal). Since the annulus 14 is sealed off at or near the surface with the device 18, a choke manifold 46 (not shown in FIG. 1, see FIGS. 2-12) can be used to variably restrict the flow of the fluid 28 from the annulus and thereby control pressure in the wellbore 16.

For example, by increasingly restricting the flow of the fluid 28 from the annulus 14, an increased backpressure can be applied to the annulus and, hence, to the wellbore 16. If, however, restriction to flow of the fluid 28 from the annulus 14 is decreased, the backpressure is also decreased, thereby decreasing pressure in the wellbore 16.

Control of wellbore pressure is very important in managed pressure drilling, and in other types of drilling operations. Preferably, the wellbore pressure is accurately controlled to prevent excessive loss of fluid into an earth formation surrounding the wellbore 16, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc. In typical managed pressure drilling, it is desired to maintain the wellbore pressure just greater than a pore pressure of the formation, without exceeding a fracture pressure of the formation. In typical underbalanced drilling, it is desired to maintain the wellbore pressure somewhat less than the pore pressure, thereby obtaining a controlled influx of fluid from the formation.

Operation of the choke manifold 46 (see FIGS. 2-12) can be automated, so that a desired pressure is maintained in the wellbore 16 at all, or substantially all, times. Suitable automated wellbore pressure control systems are described in U.S. Publication No. 2013/0133948, and in International Application No. PCT/US12/39586, filed on 25 May 2012. Such automated wellbore pressure control systems can be used to automatically control operation of the choke manifold 46, as well as other pressure and flow equipment (such as, a standpipe manifold 48, not shown in FIG. 1, see FIGS. 2-12), including but not limited to flow control devices (such as, valves and chokes) and pumps, etc. However, the scope of this disclosure is not limited to use of any particular automated wellbore pressure control system.

While the wellbore 16 is being drilled, the fluid 28 can be supplied to an uppermost connector 30 of the drill string 12 via a kelly (not shown) and a standpipe line 32 (see FIGS. 2-12). However, when it is desired to add another section 12b to, or to remove the section 12a from, the drill string 12, the connector 30 is disconnected from the kelly and standpipe line 32, and so these are not available for supplying the fluid 28 to the drill string.

In the FIG. 1 example, in order to provide an alternate means for supplying the fluid 28 to the drill string 12, each section of the drill string is equipped with a continuous circulation device 34. The device 34 includes flow control devices 36, 38 (such as valves or closable chokes) for providing fluid communication between a longitudinal flow passage 40 of the drill string 12, and the connector 30 and/or an inlet 42.

The inlet 42 provides for sealed fluid communication through a sidewall of the device 34 to the flow passage 40. The connector 30 provides for sealed fluid communication through the flow passage 40 between sections 12a,b of the drill string 12.

The flow control device 36 selectively permits and prevents fluid communication between the connector 30 and the flow passage 40. The flow control device 38 selectively permits and prevents fluid communication between the inlet 42 and the flow passage 40.

Although separate flow control devices 36, 38 are depicted in FIG. 1, any number of flow control devices could be used in other examples. For example, a single three-way valve could be used in place of the separate flow control devices 36, 38 if desired.

Suitable continuous circulation devices are described in U.S. Pat. No. 7,845,433, and in International Application No. PCT/US13/62730, filed on 30 Sep. 2013. Such continuous circulation devices may be automated (for example, so that operation of the flow control devices 36, 38 is automatically controlled), or manually operated. However, the scope of this disclosure is not limited to use of any particular type of continuous circulation device.

In the International Application No. PCT/US13/62730 mentioned above, the continuous circulation device includes connection sensors that can detect when connections are properly made (for example, at the uppermost connection 30 and at the inlet 42), so that the valves 36, 38 can be operated in response. The valves 36, 38 can also be operated synchronously. In the system 10 described herein, the valves 36, 38 can be operated automatically based, at least in part, on an output of a hydraulics model 122 (see FIG. 13).

The sections 12a,b of the drill string 12 depicted in FIG. 1 may be stands of drill pipe, drill collars or other equipment (such as, the drilling motor 26, pressure-, measurement- or logging-while-drilling (PWD, MWD or LWD) sensors 50, centralizers, stabilizers, reamers, etc.). The continuous circulation device 34 may be separate from, or integrated as part of, each section added to or removed from the drill string 12 in the drilling operation. For example, each of the sections 12a,b of the drill string 12 illustrated in FIG. 1 can include the continuous circulation device 34.

As depicted in FIG. 1, the section 12b is being added to or removed from the drill string 12. Thus, the flow control device 36 is closed and the flow control device 38 is open, thereby enabling flow of the fluid 28 via the inlet 42 into the flow passage 40 and preventing upward flow out of the flow passage via the connector 30.

In this example, pressure in the wellbore 16 is maintained relatively constant (e.g., with only minor fluctuations occurring) at a desired pressure while the section 12b is added to or removed from the drill string 12. Since continuous circulation of the fluid 28 is provided in the system 10, the choke manifold 46 (see FIGS. 2-14) can be operated to maintain a desired pressure in the wellbore 16 while the section 12b is added to or removed from the drill string 12.

So that the choke manifold 46 does not have to compensate for large variations in flow while the flow control devices 36, 38 are operated, the flow of the fluid 28 through the flow passage 40 (and, hence, through the drill string 12 and annulus 14) can be maintained substantially constant (e.g., with only minor fluctuations occurring) while those flow control devices are operated. For example, instead of opening one of the flow control devices 36, 38 and then closing the other one, the flow control devices can be gradually opened and closed, so that a total amount of flow through the flow control devices remains substantially constant. Suitable flow sensors (such as, the sensors 50 and flowmeters 52, 54, not shown in FIG. 1, see FIGS. 2-12) and the automated wellbore pressure control systems mentioned above can be used to automatically operate the flow control devices 36, 38, so that the flow of the fluid 28 through the drill string 12 and annulus 14 remains substantially constant while the flow control devices are operated.

FIGS. 2-12 are representative schematic views of various steps of one example of the method. In the FIGS. 2-12 example, a section is added to the drill string 12. However, it will be readily appreciated by those skilled in the art that similar steps can be used in removing a section from the drill string 12.

Not all of the steps depicted in FIGS. 2-12 are necessary for performance of the method. For example, FIGS. 14 & 15 depict alternative steps that can be used with the method in certain circumstances. Thus, it should be clearly understood that the scope of this disclosure is not limited to any particular number, sequence, function or type of steps in the method of providing continuous circulation of the fluid 28 through the drill string 12 and the annulus 14.

The method steps depicted in FIGS. 2-12 are performed with the system 10 of FIG. 1 (including additional equipment described more fully below). However, the method can be performed with other systems, in keeping with the principles of this disclosure.

Turning now specifically to FIG. 2, the system 10 is representatively illustrated while the wellbore 16 (see FIG. 1) is being drilled with the drill string 12, a situation known to those skilled in the art as “drilling ahead” or “making hole.” In this relatively steady state situation, the fluid 28 is pumped through the drill string 12, into the annulus 14 (see FIG. 1), and returns to the surface.

In the further description below, the flow of the fluid 28 through the system 10 will be described, beginning at a reservoir 56 (or “mud pit”) and returning to the reservoir. However, it should be clearly understood that a variety of different alternatives exist for flow of the fluid 28, and so the scope of this disclosure is not limited to any particular flow path traversed by the fluid.

Beginning at the reservoir 56, the fluid 28 is pumped by a pump 58 (such as, a rig mud pump) to the standpipe manifold 48. The fluid 28 passes through a debris strainer 60 and a valve 62 in the standpipe manifold 48. The fluid 28 then flows to the standpipe line 32.

In this example, a kelly (not shown, but kelly valves 64a,b are depicted in FIG. 2) can be connected between the standpipe line 32 and the section 12a of drill string 12. The kelly provides a rotary fluid connection, so that the drill string 12 can rotate relative to the standpipe line 32 while maintaining fluid communication between them. However, in other examples, such a rotary fluid connection could be provided as part of a top drive, or a rotary fluid connection may not be used.

The fluid 28 flows from the standpipe line 32 into the flow passage 40 of the drill string 12 via the flow control device 36, which is open at this time. The other flow control device 38 of the continuous circulation device 34 is closed at this time.

The fluid 28 flows through the passage 40 to the drill bit 24 (see FIG. 1). The fluid 28 then exits the drill bit 24 (such as, via nozzles of the drill bit, not shown) and returns via the annulus 14 (see FIG. 1). The fluid 28 is shown in dashed lines flowing downwardly and upwardly through the blowout preventer stack 20 in FIG. 2, thereby indicating the flow of the fluid into the wellbore 16 (see FIG. 1) via the passage 40, and return of the fluid from the wellbore via the annulus 14.

At or near the surface, the fluid 28 exits the annular seal device 18 and flows into the outlet line 44. The fluid 28 then flows through the choke manifold 46, which variably restricts the fluid flow to thereby maintain a desired pressure in the wellbore 16. In the FIG. 2 example, the fluid 28 flows through only one of multiple redundant chokes 66 of the manifold 46. One or more of the chokes 66 can be automatically operated using the wellbore pressure control systems mentioned above, in order to automatically maintain the desired wellbore pressure.

The fluid 28 then flows through a flowmeter 68. The flowmeter 68 can be capable of relatively precise flow rate measurements (for example, the flowmeter may be a Coriolis flowmeter), which can assist in the automated operation of the choke manifold 46 and the flow control devices 36, 38, 62, 74, 82, 86 (see FIGS. 3-15).

In addition, by comparing the flows into the wellbore 16 (measured, for example, by flowmeters 52, 54 and/or sensors 50) to the flow out of the wellbore (measured, for example, by the flowmeter 68), diagnostic techniques can detect certain circumstances (such as, influx of formation fluid into the wellbore, loss of fluid 28 from the wellbore, etc.), and certain formation properties (such as, fracture pressure, pore pressure, etc.) can be measured. Suitable diagnostic and measurement techniques are described in International Application No. PCT/US12/59079, filed on 5 Oct. 2012, and in U.S. Publication No. 2013/0133948.

The fluid 28 then flows through a gas separator 70 and a shaker 72 before returning to the reservoir 56. The separator 70 removes any gas that might be entrained in the fluid 28, and the shaker 72 removes cuttings or other debris from the fluid. However, other or additional fluid conditioning equipment may be used, in keeping with the principles of this disclosure.

Note that the separator 70 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a “poor boy degasser”). However, the separator 70 is not necessarily used in the system 10.

Referring specifically now to FIG. 3, the system 10 is representatively illustrated after a flow control device 74 (such as, a choke) has been opened in the standpipe manifold 48. Note that the fluid 28 flows both through the valve 62 and the flow control device 74 at this time.

In addition, a bypass line 80 is now connected to the inlet 42 of the continuous circulation device 34. In steps described more fully below, the flow of the fluid 28 is gradually diverted from the standpipe line 32 to the bypass line 80, so that the fluid flows into the passage 40 via the flow control device 38 instead of via the flow control device 36.

Referring specifically now to FIG. 4, the system 10 is representatively illustrated after the valve 62 has been closed. The fluid 28 now flows through the flow control device 74, but not the valve 62, thereby enabling the flow control device 74 to be used to precisely vary the flow of the fluid 28 as needed.

Referring specifically now to FIG. 5, the system 10 is representatively illustrated after a valve 76 has been opened in preparation for regulating flow of the fluid 28 to the inlet 42 of the continuous circulation device 34. However, at this time, the fluid 28 does not yet flow to the inlet 42.

Another flow control device 78, which controls flow through the bypass line 80, may be opened at this time. Alternatively, the flow control device 78 could be opened in response to proper connecting of the bypass line 80 to the inlet 42 (e.g., as described in the International Application No. PCT/US13/62730 mentioned above).

Referring specifically now to FIG. 6, the system 10 is representatively illustrated after another flow control device 82 (such as, a choke) has been opened, thereby allowing flow of the fluid 28 from the standpipe manifold 48 to the inlet 42 of the continuous circulation device 34. The flow control device 82 can variably regulate this flow, so that a total flow of the fluid 28 into the drill string 12 remains substantially constant (although it is not necessary for such flow to remain constant, since the choke manifold 46 can be operated to compensate for flow variations), and so that large pressure fluctuations are avoided.

The flow control device 74 is depicted in the drawings as being part of the standpipe manifold 48, whereas the flow control device 82 is depicted as being separate from the standpipe manifold. However, it is not necessary for any particular flow control device to be a part of, or separate from, the standpipe manifold 48.

The flow control device 38 can be gradually opened while the flow control device 36 is gradually closed, so that fluid communication between the passage 40 and the uppermost connector 30 (see FIG. 1) is gradually prevented and fluid communication between the passage and the inlet 42 is gradually permitted. In addition, the flow control devices 74, 82 can be automatically operated, so that progressively more flow of the fluid 28 is diverted from the standpipe line 32 to the bypass line 80.

Automation of this process can be in response to detection of appropriate connection of the bypass line 80 to the inlet 42. A suitable connection sensor is described in the International Application No. PCT/US13/62730 mentioned above.

Referring specifically now to FIG. 7, the system 10 is representatively illustrated after the flow control device 36 has been fully closed. All of the flow of the fluid 28 from the standpipe manifold 48 now goes to the inlet 42, and thence into the flow passage 40. The flow control device 74 may also be fully closed at this time. Flow into the inlet 42 can now be automatically controlled using the flow control devices 78, 82.

Referring specifically now to FIG. 8, the system 10 is representatively illustrated after a valve 84 in the standpipe manifold 48 has been closed, thereby completely isolating the standpipe line 32 from the flow of the fluid 28 from the pump 58. The fluid 28 continues to flow to the bypass line 80 and into the flow passage 40.

After the valve 84 has been closed, the standpipe line 32 can be bled off (e.g., via a flow control device 86). Once pressure in the standpipe line 32 is reduced to atmospheric pressure, the standpipe line (and the kelly, not shown) can be disconnected from the drill string 12.

This leaves the uppermost connector 30 available for connecting the next drill string section 12b (see FIGS. 1 & 9). Note that FIG. 8 depicts the system 10 in a same condition as is depicted in FIG. 1.

Referring specifically now to FIG. 9, the system 10 is representatively illustrated after the section 12b has been connected to the section 12a. The standpipe line 32 has also been connected to the section 12b (for example, via an uppermost connector 30 of the section 12b). However, the fluid 28 continues to flow into the passage 40 exclusively via the bypass line 80, inlet 42 and flow control device 38.

Referring specifically now to FIG. 10, the system 10 is representatively illustrated after the valve 84 has been opened, allowing the flow control device 74 to variably regulate flow of the fluid 28 from the standpipe manifold 48 to the standpipe line 32 (which is now connected to the section 12b, not shown in FIG. 10).

The flow control device 36 can now be gradually opened to admit fluid 28 from the standpipe line 32 to the flow passage 40. The flow control device 38 can be gradually closed, so that the fluid 28 eventually flows into the passage 40 exclusively via the standpipe line 32 and the flow control device 36. In addition, the flow control devices 74, 82 can be automatically operated, so that progressively more flow of the fluid 28 is diverted from the bypass line 80 to the standpipe line 32.

Automation of this process can be in response to detection of appropriate connection of the drill string section 12b to the connector 30 of the drill string section 12a. A suitable connection senor is described in the International Application No. PCT/US13/62730 mentioned above.

Referring specifically now to FIG. 11, the system 10 is representatively illustrated after the flow control device 78 has been closed, thereby preventing flow of the fluid 28 via the bypass line 80 to the inlet 42. A bleed valve (not shown) can be incorporated into the inlet 42, or in conjunction with the flow control device 78, in order to bleed the bypass line 80 between the inlet 42 and the flow control device 78.

Note that the flow of the fluid 28 into the drill string 12 at this point is exclusively via the standpipe line 32. The flow control device 74 can be used to variably regulate this flow as needed.

Referring specifically now to FIG. 12, the system 10 is representatively illustrated after the bypass line 80 has been disconnected from the inlet 42. In addition, the valve 62 has been opened and the valve 84 has been closed, so that the flow control device 74 is no longer used to variably regulate the flow of the fluid 28 through the standpipe manifold 48.

The system 10 is now returned to its condition as depicted in FIG. 2, except that the section 12b (not shown in FIG. 12, but connected above the section 12a) is now part of the drill string 12. Drilling of the wellbore 16 (see FIG. 1) can now resume.

Note that, at any point in the method described above, the flow of the fluid 28 from the annulus 14 (see FIG. 1) can be diverted to a well control choke manifold 88 (for example, by opening a valve 90 and closing a valve 92). Flow may be diverted to the well control choke manifold 88 for well control operations (for example, to circulate out an otherwise uncontrolled influx of gas into the wellbore 16). Alternatively, or in addition, the choke manifold 46 could be used for such well control operations.

The hydraulics model 122 (see FIG. 13) can be used, as described more fully below, to determine a pressure applied to the annulus 14 at or near the surface which will result in a desired wellbore pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired wellbore pressure. The hydraulics model 122 can also be used to control various flow control devices (such as, flow control devices 74, 82, 86 and valves 36, 38, 62, 76, 78, 84) to maintain continuous circulation through the drill string 12.

Pressure applied to the annulus 14 can be measured at or near the surface via a variety of pressure sensors 100, 102, 104, each of which is in communication with the annulus. Pressure sensor 100 senses pressure below the annular seal device 18, but above the blowout preventer stack 20. Pressure sensor 102 senses pressure in the wellhead 22 below the blowout preventer stack 20. Pressure sensor 104 senses pressure in the outlet line 44 upstream of the choke manifold 46.

Another pressure sensor 106 senses pressure in the standpipe line 32. Yet another pressure sensor 108 senses pressure downstream of the choke manifold 46. Additional sensors include temperature sensors 110, 112, Coriolis flowmeter 68, and flowmeters 52, 54, 114, 116, 118.

Not all of these sensors are necessary. For example, the system 10 could include only two of the three flowmeters 52, 54, 114. However, input from the sensors is useful to the hydraulics model 122 in determining what the pressure applied to the annulus 14 should be during the drilling operation, and how to operate the various flow control devices in order to maintain a desired wellbore pressure.

In addition, the drill string 12 includes its own sensors 50, for example, to directly measure wellbore pressure. Such sensors 50 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD). These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements. Various forms of telemetry (acoustic, pressure pulse, electromagnetic, etc.) may be used to transmit the downhole sensor measurements to the surface.

Additional sensors could be included in the system 10, if desired. For example, another flowmeter could be used to measure the rate of flow of the fluid 28 exiting the wellhead 22, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of the rig mud pump 58, etc.

Fewer sensors could be included in the system 10, if desired. For example, the output of the rig mud pump 58 could be determined by counting pump strokes, instead of by using flowmeter 114 or any other flowmeters. Thus, the scope of this disclosure is not limited to use of any particular number, type or arrangement of sensors in the system 10.

FIG. 13 is a representative block diagram of a pressure and flow control system 120 that may be used with the system 10 and method. The control system 120 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.

The control system 120 includes the hydraulics model 122, a data acquisition and control interface 124 and a controller 126 (such as a programmable logic controller or PLC, a suitably programmed computer, etc.). Although these elements 122, 124, 126 are depicted separately in FIG. 13, any or all of them could be combined into a single element, or the functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided, etc.

The hydraulics model 122 is used in the control system 120 to determine the desired annulus pressure at or near the surface to achieve the desired wellbore pressure. Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by the hydraulics model 122 in making this determination, as well as real-time sensor data acquired by the data acquisition and control interface 124.

Thus, there is a continual two-way transfer of data and information between the hydraulics model 122 and the data acquisition and control interface 124. For the purposes of this disclosure, it is important to appreciate that the data acquisition and control interface 124 operates to maintain a substantially continuous flow of real-time data from the sensors 50, 52, 54, 100, 102, 104, 106, 108, 110, 112, 114, 116, 118 to the hydraulics model 122, so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure, and the hydraulics model operates to supply the data acquisition and control interface substantially continuously with a value for the desired annulus pressure.

A suitable hydraulics model for use as the hydraulics model 122 in the control system 120 is REAL TIME HYDRAULICS™ provided by Halliburton Energy Services, Inc. of Houston, Tex. USA. Another suitable hydraulics model is provided under the trade name IRIS™, and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in the control system 120 in keeping with the principles of this disclosure.

A suitable data acquisition and control interface for use as the data acquisition and control interface 124 in the control system 120 are SENTRY™ and INSITE™ provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in the control system 120 in keeping with the principles of this disclosure.

The controller 126 operates to maintain a desired setpoint annulus pressure by controlling operation of the mud return choke 66 while drilling. When an updated desired annulus pressure is transmitted from the data acquisition and control interface 124 to the controller 126, the controller uses the desired annulus pressure as a setpoint and controls operation of the choke 66 in a manner (e.g., increasing or decreasing flow through the choke as needed) to maintain the setpoint pressure in the annulus 14.

This is accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of the sensors 100, 102, 104), and increasing flow through the choke 66 if the measured pressure is greater than the setpoint pressure, and decreasing flow through the choke if the measured pressure is less than the setpoint pressure. Of course, if the setpoint and measured pressures are the same, then no adjustment of the choke 66 is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used if desired.

The controller 126 may also be used to control operation of the various standpipe, bypass and continuous circulation flow control devices and valves 36, 38, 62, 74, 76, 80, 82, 84, 86. The controller 126 can, thus, be used to automate the processes of appropriately opening and closing the continuous circulation flow control devices 36, 38 (for example, when the bypass line 80 is properly connected to the inlet 42, etc.), and of diverting flow of the fluid 28 from the standpipe line 32 to the bypass line 80 prior to making a connection in the drill string 12, then diverting flow from the bypass line to the standpipe line after the connection is made, and then resuming normal circulation of the fluid 28 for drilling. Again, no human intervention may be required in these automated processes, other than to initiate each process in turn.

Referring additionally now to FIG. 14, a step in another example of the method is representatively illustrated. In this step, the fluid 28 is not continuously circulated through the drill string 12, but is instead diverted from the bypass line 80 to the outlet line 44.

Note that FIG. 14 is similar in most respects to FIG. 8, except that a flow control device 94 is opened, thereby allowing the fluid 28 to flow from the standpipe manifold 48 via the flow control device 82 to the outlet line 44. The flow control device 78 is closed, so that the fluid 28 does not flow to the inlet 42 (and may not enter the bypass line 80 at all).

Backpressure can still be applied to the annulus 14 by variably regulating flow of the fluid 28 through the choke manifold 46 (and through the flow control device 82 and various other flow control devices), because the valve 92 remains open. Thus, pressure in the wellbore 16 can be maintained at a desired level, even though the fluid 28 does not circulate through the drill string 12 and annulus 14.

Although the flow control devices 78, 94 are depicted in FIGS. 2-14 as being separate elements of the system 10, they can be combined, if desired. In FIG. 15, an alternative configuration of the system 10 is representatively illustrated, in which a single three-way flow control device 96 is used in place of the separate flow control devices 78, 94.

Similarly, the flow control devices 74, 82 that variably regulate flow of the fluid 28 from the standpipe manifold 48 to the standpipe line 32 and the bypass line 80, respectively, could be combined into a single three-way flow control device. Thus, it will be appreciated that the scope of this disclosure is not limited to any particular number, arrangement or configuration of elements in the system 10, or to any particular manner of operating those elements in the method.

It can now be fully appreciated that the above disclosure provides significant advancements to the art of providing continuous circulation of fluid through a drill string and annulus in drilling operations. The system 10 and method examples described above provide for maintaining flow of the fluid 28 through the drill string 12 and annulus 14, even when connections are made or broken in the drill string, or when circulation might otherwise be ceased. The flow control devices 74, 82 can provide for gradual automated diversion of the fluid 28 between the standpipe line 32 and the bypass line 80, so that fluctuations in flow and/or pressure can be avoided.

More specifically, a method of providing continuous circulation of fluid 28 through a drill string 12 and an annulus 14 between the drill string 12 and a wellbore 16 is provided to the art by the above disclosure. In one example, the method comprises: sealing off the annulus 14 from atmosphere; regulating flow of the fluid 28 from the annulus 14 while the annulus is sealed off from the atmosphere, thereby controlling pressure in the wellbore 16; and diverting flow of the fluid 28 from a pump 58 to: a) an uppermost connector 30 of the drill string 12, and b) an inlet 42 extending in a sidewall of the drill string 12. Each of the uppermost connector 30 and the inlet 42 is communicable with a flow passage 40 extending longitudinally through the drill string 12, and the regulating step and the diverting step are performed concurrently.

The diverting step can include gradually decreasing the flow of the fluid 28 from the pump 58 to the uppermost connector 30 while gradually increasing the flow of the fluid 28 from the pump 58 to the inlet 42.

The diverting step can include gradually increasing the flow of the fluid 28 from the pump 58 to the uppermost connector 30 while gradually decreasing the flow of the fluid 28 from the pump 58 to the inlet 42.

The pressure in the wellbore 16 may be maintained substantially constant throughout the diverting step.

The diverting step can include automatically operating at least one flow control device 74, 82 which controls flow to the uppermost connector 30, and which controls flow to the inlet 42.

A substantially constant flow of the fluid 28 through the drill string 12 and the annulus 14 may be maintained throughout the diverting step.

The diverting step may include diverting the flow of the fluid 28 from the pump 58 to an outlet line 44 via which the fluid 28 flows from the annulus 14.

Also provided to the art by the above disclosure is a pressure and flow control system 10 for providing continuous circulation of fluid 28 from a pump 58 through a drill string 12 and an annulus 14 between the drill string 12 and a wellbore 16. In one example, the system 10 can include at least one flow control device 74, 82 which diverts flow from the pump 58 to: a) a first valve (e.g., flow control device 36) which selectively permits and prevents communication between an uppermost connector 30 of the drill string 12 and a flow passage 40 extending longitudinally through the drill string 12, and b) a second valve (e.g., flow control device 38) which selectively permits and prevents communication between the flow passage 40 and an inlet 42 extending in a sidewall of the drill string 12; and an annular seal device 18 which seals off the annulus 14 while the one or more flow control devices 74, 82 divert flow between the first and second valves 36, 38.

The first and second valves 36, 38 can be operated in response to sensor inputs to a hydraulics model 122.

The one or more flow control devices may comprise first and second chokes 74, 82. The first choke 74 can variably regulate flow from the pump 58 to the first valve 36, and the second choke 82 can variably regulate flow from the pump 58 to the second valve 38.

Flow may be permitted through the first and second chokes 74, 82 simultaneously. The first and second chokes 74, 82 may be operated in response to sensor 50, 52, 54, 100, 102, 104, 106, 108, 110, 112, 114, 116, 118 inputs to a hydraulics model 122. The first and second chokes 74, 82 may be operated simultaneously, whereby flow is gradually diverted between the first and second valves 36, 38.

The system 10 can include a choke 66 which variably regulates flow of the fluid 28 from the annular seal device 18 and maintains a substantially constant pressure in the wellbore 16 while the one or more flow control devices 74, 82 divert flow between the first and second valves 36, 38.

The one or more flow control devices 74, 82 can be automatically operated and maintain a substantially constant flow of the fluid 28 through the drill string 12 and the annulus 14 while flow is diverted between the first and second valves 36, 38.

In the FIGS. 13 & 14 examples, the one or more flow control devices 74, 82 can divert the flow of the fluid 28 from the pump 58 to an outlet line 44 via which the fluid 28 flows from the annular seal device 18.

Another method of providing continuous circulation of fluid 28 through a drill string 12 and an annulus 14 between the drill string 12 and a wellbore 16 can comprise: sealing off the annulus 14 from atmosphere; regulating flow of the fluid 28 from the annulus 14 while the annulus is sealed off from the atmosphere, thereby controlling pressure in the wellbore 16; and operating at least one flow control device 74, 82, thereby diverting flow of the fluid 28 from a pump 58 to: a) a first valve (e.g., flow control device 36) which selectively permits and prevents communication between an uppermost connector 30 of the drill string 12 and a flow passage 40 extending longitudinally through the drill string 12, and b) a second valve (e.g., flow control device 38) which selectively permits and prevents communication between the flow passage 40 and an inlet 42 extending in a sidewall of the drill string 12. The regulating step and the operating step may be performed concurrently.

Another method of providing substantially continuous circulation of fluid 28 through a drill string 12 and an annulus 14 between the drill string 12 and a wellbore 16 can comprise: operating a hydraulics model 122; and in response to an output from the hydraulics model 122, diverting flow of the fluid 28 from a pump 58 to: a) an uppermost connector 30 of the drill string 12, and b) an inlet 42 extending in a sidewall of the drill string 12. Each of the uppermost connector 30 and the inlet 42 is communicable with a flow passage 40 extending longitudinally through the drill string 12.

Another method of providing substantially continuous circulation of fluid 28 through a drill string 12 and an annulus 14 between the drill string 12 and a wellbore 16 can comprise: inputting sensor measurements to a hydraulics model 122; and in response to an output of the hydraulics model 122, automatically operating at least one flow control device 74, 82, thereby diverting flow of the fluid 28 from a pump 58 to: a) a first valve 36 which selectively permits and prevents communication between an uppermost connector 30 of the drill string 12 and a flow passage 40 extending longitudinally through the drill string 12, and b) a second valve 38 which selectively permits and prevents communication between the flow passage 40 and an inlet 42 extending in a sidewall of the drill string 12.

Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

PRESSURE AND FLOW CONTROL IN CONTINUOUS FLOW DRILLING OPERATIONS

Information

Publication Number

Date Filed

Date Published

Inventors

Original Assignees

CPC

International Classifications

Abstract

Description

Claims

PCT Information