WO2020005357A1

WO2020005357A1 - Method and system for heave compensation for surface backpressure

Info

Publication number: WO2020005357A1
Application number: PCT/US2019/025264
Authority: WO
Inventors: Helio Santos; Konstantin PUSKARSKIJ
Original assignee: Safekick Americas Llc; Maersk Drilling A/S
Priority date: 2018-06-26
Filing date: 2019-04-02
Publication date: 2020-01-02

Abstract

A method of heave compensation for surface backpressure includes drilling a wellbore into a subterranean surface with a floating drilling rig, acquiring data including data corresponding to heave of the rig, using the acquired data as an input for the heave prediction modeler, calculating a heave compensation factor by heave prediction modeler, calibrating heave prediction modeler base on the acquired data, calculating a surface backpressure set point to manage pressure in the wellbore, where the surface backpressure set point includes the heave compensation factor, and changing surface backpressure to the surface backpressure set point. The floating drilling rig includes a rotating or non-rotating control device disposed above or below or across the rig tension ring and a smart choke manifold.

Description

METHOD AND SYSTEM FOR REAVE COMPENSATION

FOR SURFACE BACKPRESSURE

BACKGROUND OF THE INVENTION

[0001] In deepwater and ultra-deepwater operations, a closed-loop drilling system is typically used when drilling in locations with a narrowly constrained mud weight window, typically bounded by the pore pressure and the facture pressure. During drilling operations, the driller must precisely manage wellbore pressure within this narrow window and quickly and accurately detect wellbore problems, such as kicks, losses, and wellbore instability as they occur. Once a problem has been identified, the closed-loop drilling system must quickly control the problem by manipulating the pressure inside the wellbore in a very precise manner.

[0002] To achieve closed-loop drilling in the deepwater and ultra-deepwater fleet, the common practice today is to retrofit existing rigs with a rotating control device (“RCD”), located below the rig’s tension ring, that seals the annulus surrounding the drill string. However, retrofitting a deepwater or ultra-deepwater rig requires expensive equipment such as, for example, an integrated riser joint, which is difficult and time-consuming to install. Once installed, maintenance and repair operations are also complicated. Replacing RCD bearing assemblies is time consuming resulting in substantial non-productive time and, if anything goes wrong with the RCD or the integrated riser joint components, the blowout preventer (“BOP”) must be disconnected from the wellhead, which is an extremely costly operation at depth that results in even more non-productive time. The complicated and expensive nature of retrofitting has hindered the conversion and operation of existing deepwater and ultra- deepwater rigs fro using a closed-loop drilling system. However, the deepwater and ultra-deepwater fleet are pursuing challenging wells that require closed-loop drilling for safety and environmental reasons.

BRIEF SUMMARY OF THE INVENTION

[0003] According to one aspect of one or more embodiments of the present invention, a method of heave compensation for surface backpressure includes drilling a wellbore into a subterranean surface with a floating drilling rig, acquiring data including data corresponding to heave of the rig, calculating a heave compensation factor based on the acquired data, calculating a surface backpressure set point to manage pressure in the wellbore, where the surface backpressure set point includes the heave compensation factor, and changing surface backpressure to the surface backpressure set point.

[0004] According to one aspect of one or more embodiments of the present invention, a floating drilling rig for heave compensation for surface backpressure includes a choke manifold that controls a surface backpressure applied to a wellbore, a drill string that extends into the wellbore, a rotating or non-rotating control device disposed around the drill string on top of a telescopic joint, wherein the rotating or non-rotating control device seals an annulus between the drill string and the telescopic joint, a riser tension ring disposed around an outer barrel of the telescopic joint, a marine riser fluidly connected to a bottom of the telescopic joint, a data acquisition unit configured to acquire data including data corresponding to heave of the rig, a hydraulic modeler configured to calculate a surface backpressure set point to manage pressure in the wellbore, wherein the surface backpressure set point includes a heave compensation factor calculated based on the acquired heave data, and a control system configured to change surface backpressure to the surface backpressure set point.

[0005] Other aspects of the present invention will be apparent from the following description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0006] Figure 1 shows a conventional floating drilling rig used to drill a wellbore into a subterranean surface

[0007] Figure 2 shows a conventional above-tension-ring rotating control device configuration as part of a floating drilling rig.

[0008] Figure 3 shows a conventional below-tension-ring rotating control device configuration as part of a fl oating drilling rig.

[0009] Figure 4 shows a conventional across-tensi on-ring rotating control device configuration as part of a floating drilling rig.

[0010] Figure 5 show's a plot of heave as a function of time in accordance with one or more embodiments of the present invention.

[0011] Figure 6 shows a plot of acquired heave and predicted future heave in accordance with one or more embodiments of the present invention. [0012] Figure 7 shows an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint as part of a floating drilling rig with smart choke manifold in accordance with one or more embodiments of the present invention.

[0013] Figure 8A show's a floating drilling rig with an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint with a smart choke manifold with the telescopic joint stroked out in accordance with one or more embodiments of the present invention.

[0014] Figure 8B shows the floating drilling rig with the above-tension-ring rotating or non-rotating control device disposed above the telescopic joint with the smart choke manifold with the telescopic joint stroked in in accordance with one or more embodiments of the present invention.

[0015] Figure 9 shows a method of heave compensation for surface backpressure in accordance with one or more embodiments of the present invention.

[0016] Figure 10 show's a block diagram of a system for heave compensation for surface backpressure in accordance with one or more embodiments of the present invention.

[0017] Figure 11 show a block diagram of a control system of a floating drilling rig for heave compensation for surface backpressure in accordance with one or more embodiments of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

[0018] One or more embodiments of the present invention are described in detail with reference to the accompanying figures. For consistency, like elements in the various figures are denoted by like reference numerals. In the following detailed description of the present invention, specific details are set forth in order to provide a thorough understanding of the present invention. In other instances, well-known features to one of ordinary skill in the art are not described to avoid obscuring the description of the present invention.

[0019] Figure 1 shows a conventional floating drilling rig 100 used to drill a wellbore into a subterranean surface. Floating drilling rig 100 is disposed in a large body of water, such as, for example, a lake, sea, or ocean 105. In the semi-submersible rig 100 depicted, a plurality of columns 110 and pontoons 115 may buoyantly support a platform 120 situated above the waterline 105 and on which various drilling equipment may be disposed. Platform 120 typically includes a moon pool area (not independently illustrated) that provides access to water 105 and a riser stack. The riser stack typically includes a flow diverter 125 disposed on top of, and in fluid communication with, a top distal end of a ball joint 130, a bottom distal end of ball joint 130 in fluid communication with a top distal end of an inner barrel 135 of a telescopic joint 155, and a bottom distal end of inner barrel 135 of the telescopic joint 155 in fluid communication with an outer barrel 137 of the telescopic joint 155. Inner barrel 135 may move axially within outer barrel 137 of telescopic joint 155 as floating drilling rig 100 heaves. Heave means the substantially periodic and sinusoidal motion of the body of water 105, having a period that is typically on the order of magnitude of tens of seconds, which causes the waterline 105 to rise and fail.

[0020] In the above-tension-ring configuration depicted, RCD 140 connects a bottom distal end of outer barrel 137 of telescopic joint 155 to a top distal end of riser 160. RCD 140 controllably seals the annulus (not shown) between the drill string (not shown) disposed there through and an inner diameter (not shown) of RCD 140, One or more bearing assemblies (not shown) disposed within RCD 140 rotate with the drill string (not shown) while maintaining a pressure tight seal to contain returning fluids in the annulus below the RCD. One or more umbilical and/or fluid flow lines 143 may connect RCD 140 to platform 120 for control and fluid communication. A riser tension ring 150 may be disposed about the top distal end of riser 160 and supported by a plurality of riser tensioners 145 that provide upward force on riser 160 independent of the movement of platform 120 due to heave. A bottom distal end of riser 160 is connected to a lower marine riser package (not shown) and subsea BOP 165 disposed on the subterranean surface 170 and connected to the wellhead (not independently illustrated), or top of, wellbore 175. In ultra-deepwater drilling operations, the wellhead may be disposed at a water depth in excess of 5,000 feet.

[0021] While a semi-submersible rig 100 is depicted, one of ordinary skill in the art will recognize that conventional floating drilling rig 100 may be a drillship, a drill barge, a semi-submersible, or any other type or kind of floating drilling rig or platform that is buoyant and is subjected to the heave of the body of water in which it is situated.

[0022] Figure 2 shows a conventional above-tension-ring rotating control device configuration 200 as part of a floating drilling rig 100. In an above-tension-ring configuration, a riser stack includes a flow⁷ diverter 125 in fluid communication with a top distal end of a ball joint 130. A bottom distal end of ball joint 130 is in fluid communication with a top distal end of inner barrel 135 of a telescopic joint 155. A bottom distal end of inner barrel 135 of telescopic joint 155 is in fluid communication with an outer barrel 137 of telescopic joint 155 An RCD 140 connects a bottom distal end of outer barrel 137 of telescopic joint 155 to a top distal end of riser 160 and controllably seals the annulus (not shown) between the drill string (not shown) disposed there through and the inner diameter of RCD 140. One or more hearing assemblies (not shown) of RCD 140 rotates with the drill siring (not shown) while maintaining a pressure tight seal to contain returning fluids in the annulus. One or more umbilical and/or fluid flow lines 143 may connect RCD 140 to platform 120 for control and fluid communication A riser tension ring 150 may be disposed about the top distal end of riser 160 and supported by a plurality of riser tensioners 145 that provide upward force on riser 160 independent of the movement of platform 120 due to heave. As the body of rvater 105 heaves, inner barrel 135 of telescopic joint 155 strokes in and out with the rise and fall of the heave.

[0023] Figure 3 shows a conventional b el ow-ten si on-ring rotating control device configuration 300 as part of a floating drilling rig 100, which is the most popular configuration in use today. In the below-tension-ring configuration, a riser stack includes a flow diverter 125 in fluid communication with a top distal end of a ball joint 130 A bottom distal end of bail joint 130 is in fluid communication with a top distal end of inner barrel 135 of a telescopic joint 155 A bottom distal end of inner barrel 135 of telescopic joint 155 is in fluid communication with an outer barrel 137 of telescopic joint 155. An RCD 140 connects a bottom distal end of outer barrel 137 of telescopic joint 155 to a top distal end of riser 160 and controllably seals the annulus (not shown) between the drill string (not shown) disposed there through and the inner diameter of RCD 140. One or more bearing assemblies (not shown) of RCD 140 rotate with the drill string (not shown) while maintaining a pressure tight seal to contain returning fluids in the annulus. One or more umbilical and/or fluid flow' lines 143 may connect RCD 140 to platform 120 for control and fluid communication. A riser tension ring 150 may be disposed about the top distal end of outer barrel 137 of telescopic joint 155 and supported by a plurality of riser tensioners 145 that are configured to provide upward force on riser 160 independent of movement of platform 120 due to heave. Riser 160 may include an annular isolation device (“AID”) 310 disposed below RCD 140 that controllably seals the annulus surrounding the drill string or the wellbore itself while, for example, the bearing assemblies (not shown) of RCD 140 are being installed, removed, or serviced, the drill string is tripped in or out, or other work performed on the riser stack that requires the maintenance of wellbore pressure. As the body of water 105 heaves, inner barrel 135 of telescopic joint 155 strokes in and out with the rise and fall of the heave.

[0024] Figure 4 shows a conventional across-tensi on-ring rotating control device configuration 400 as part of a floating drilling rig 100. In an across-tension-ring configuration, a riser stack includes a flow diverter 125 in fluid communication with a top distal end of a ball joint 130. A bottom distal end of ball joint 130 is in fluid communication with a top distal end of inner barrel 135 of a telescopic joint 155. A bottom distal end of inner barrel 135 of telescopic joint 155 is in fluid communication with an outer barrel 137 of telescopic joint 155. An RCD 140 connects a bottom distal end of outer barrel 137 of telescopic joint 155 to a top distal end of riser 160 and controliably seals the annulus (not shown) between the drill string (not shown) disposed there through and the inner diameter of RCD 140, One or more bearing assemblies (not shown) of RCD 140 rotate with the drill string (not shown) while maintaining a pressure tight seal to contain returning fluids in the annulus. A riser tension ring 150 may be disposed about riser 160, but below RCD 140, supported by a plurality of riser tensioners 145 that provide upward force on riser 160 independent of the movement of platform 120 due to heave. Riser 160 may include a AID 310 disposed below RCD 140 that controliably seals the annulus surrounding the drill string or the wellbore itself while, for example, the bearing assemblies (not shown ) of RCD 140 are being installed, removed, or serviced, the drill string is tripped in or out, or other work performed on the riser stack that requires the maintenance of wellbore pressure.. One or more umbilical and/or fluid lines 143 disposed below riser tension ring 150 may control RCD 140 and provide fluid communication between RCD 140 and platform 120. As the body of water 105 heaves, inner barrel 135 of telescopic joint 155 strokes in and out with the rise and fall of the heave

[0025] Each of the above-tension-ring (Figure 2), below-tensi on-ring (Figure 3), and across-tension-ring (Figure 4) configurations, represent conventional configurations to retrofit a floating drilling rig for closed-loop drilling. While pressure is controlled at the top of the marine riser, independent of the amount of displacement of the telescopic joint due to heave, such retrofitting requires expensive equipment, such as, for example, an integrated riser joint, that is difficult and time-consuming to install. Once installed, maintenance and repair operations are also complicated. Replacing RCD bearing assemblies is time consuming and, if anything goes wrong with the RCD or the integrated riser joint components, the BOP must be disconnected from the wellhead, which is an extremely costly operation at depth. The complicated and expensive nature of retrofitting has hindered the conversion and operation of deepwater rigs using a closed-loop drilling system. However, more and more deepwater rigs are operating in areas where closed-loop drilling is necessary because of the safety and environmental consequences of losing hydrostatic control. As such, there is a long-felt, but unsolved, need in the industry for a more economical solution.

[0026] Accordingly, in one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure allows existing deepwater rigs to be converted, operated, and maintained as closed-loop drilling systems while more closely managing pressure in a manner that is substantially less expensive than existing closed-loop rig designs and retrofitted rig designs. A floating drilling rig may include an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint of the existing integrated riser joint such that the rotating or non-rotating control device may be affected by the telescopic joint displacement due to heave. Because the rotating or non-rotating control device is situated above the telescopic joint, displacement of the telescopic joint due to heave will impact hydrostatic pressure. As the telescopic joint strokes out, wellbore pressure may decrease. Similarly, as the telescopic joint strokes in, wellbore pressure may increase. In closed-loop drilling in narrow mud weight window's, this change in wellbore pressure, due to the configuration and the displacement of the telescopic joint, may result in kicks, losses, and well instability.

[0027] Accordingly, in one or more embodiments of the present invention, a heave compensation factor may be used to compensate for heave of the rig when applying surface backpressure via a smart choke manifold as part of managing pressure in the wellbore. Because the rotating or non-rotating control device only supports the weight of the inner barrel of the telescopic joint, a substantially less robust control device may be used that is smaller in size and load rating, with substantially shorter and less expensive umbilical and fluid flow' lines. Moreover, such a configuration is less complicated and less expensive to install, maintain, and repair. While conventional configurations require the BOP to be disconnected from the wellhead in an expensive and time consuming operation, the location of the rotating or non rotating control device above the telescopic joint improves accessibility such that installation, maintenance, and repair is substantially easier and less expensive, allowing for the control device to be repaired or replaced without disconnecting the BOP from the wellhead.

[0028] Figure 5 show's a plot of heave as a function of time 500 in accordance with one or more embodiments of the present invention. Heave 510 is the substantially periodic and sinusoidal motion of a body of water, having a period that is typically on the order of magnitude of tens of seconds. One of ordinary skill in the art will recognize that while the periodicity of heave varies, it is typically in a range between 10 seconds and 30 seconds. Heave is traditionally associated with the short term fluctuation of a body of water. Heave is distinguishable from tide which corresponds to the rise and fall of a body of water caused by the combined effects of the gravitational forces exerted by the Moon and the Sun and the rotation of the Earth. While heave has a periodicity on the order of magnitude of tens of seconds, tide has a periodicity' of approximately eight hours and in some cases approximately twelve hours. The amplitude of heave and tide may vary based on the body of water, nearby shoreline, bathymetry, and other factors. However, heave is the shorter ter fluctuation of the body of water that is typically associated with the rise and fall of body of water.

[0029] Figure 6 shows a plot of acquired heave 615 and predicted future heave 620 in accordance with one or more embodiments of the present invention. Acquired heave data 615 may include one or more of sensed heave data and historical heave data. Sensed heave data may be data from one or more sensors configure to sense, in substantially real time, the heave of the floating rig (e.g., 100 of Figure 1). The sensed heave data may correspond to a direct measurement of heave from, for example, a marine intelligence unit, an inferred measurement of heave from, for example, a telescopic joint proximity sensor or displacement sensor, or any other type or kind of sensor capable of sensing heave. Historical heave data may include sensed or otherwise measured heave data previously recorded for the body of water in which the floating rig (e.g. , 100 of Figure 1) is disposed. While heave may vary' in amplitude and periodicity over long periods of time, such as many minutes, hours, and days, from crest to crest, the amplitude of heave typically varies in relatively small amounts. As such, a hydraulic modeler of a floating drilling rig for heave compensation for surface backpressure may input the acquired heave data 615 and calculate a predicted future heave 620. The predicted future heave 620 may, in a simplistic case, be predicted to be the same value in the period prior. In more complicated cases, the predicted future heave 620 may be calculated on the prior period, an average of prior periods, any other type or kind of factor that may contribute to heave such as wind and tidal change, or combinations thereof. One of ordinary skill in the art will recognize that any method of predicting heave from the acquired heave may be used in accordance with one or more embodiments of the present invention.

[0030] In a floating rig with a rotating or non-rotating control device disposed above the telescopic joint, when the telescopic joint is displaced due to heave, there is a pressure difference caused by the displacement. The pressure change causes a pressure wave that travels down to the bottom of the wellbore. The effect of the pressure difference caused by heave may take anywhere from seconds to tens of seconds to reach the bottom of the wellbore, depending on the depth of the wellbore. As such, when a floating drilling rig heaves, the change of pressure caused by the displacement of the telescopic joint, takes a finite number of seconds to change the pressure at the bottom of the wellbore. So long as the hydraulic modeler calculates a heave compensation factor for surface backpressure and the control system manipulates the smart choke manifold on the order of magnitude of single digit seconds, the change in surface backpressure caused by manipulation of the smart choke manifold may travel at substantially the same time as the pressure wave caused by the heave, with mere seconds of lag, thus adequately compensating for heave and managing pressure within a narrow mud weigh window

[0031] However, in certain embodiments, there may be a lag between sensing heave, calculating a heave compensation factor, calculating a surface backpressure that includes the heave compensation factor, and manipulating a smart choke manifold to achieve the surface backpressure. The lag may be on the order of magnitude of single digit seconds to ten seconds or more. In certain embodiments, where the mud weight window is extremely narrow, a hydraulic modeler or control system of a floating drilling rig for heave compensation for surface backpressure may calculate a predicted future heave 620 based on the acquired heave 615 in order to proactively predict a heave compensation factor. For example, acquired heave 615 to present time to, may be used to calculate predicted heave 620 through time to+x, where x is on the order of magnitude of single digit to ten seconds or more A hydraulic modeler, which may be part of the same control system or another separate computing system, may then calculate a forward looking value of surface backpressure necessary to manage wellbore pressure in view of the predicted heave. As such, a control system that is calibrated for the above-noted systemic lag, may predict future heave 620 a sufficient amount of time, x, in advance to allow the control system to manipulate the surface backpressure through the choke manifold in a manner that aligns with the actual heave, thus adequately compensating for heave. One of ordinary skill in the art will recognize that the amount of time x for systemic lag may vary in accordance with one or more embodiments of the present inventi on.

[0032] Figure 7 shows an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint as part of a floating drilling rig with smart choke manifold 700 in accordance with one or more embodiments of the present invention. In an above-tension-ring configuration, a riser stack may include a flow diverter 125 in fluid communication with a top distal end of a ball joint 130 A bottom distal end of ball joint 130 may be in fluid communication with a top distal end of a rotating or non-rotating control device 740. Rotating or non-rotating control device 740 may be any type or kind of annular closing such as a rotating control device, a non-rotating control device, a drill string an annular isolation device, an annular isolation device, or any other active management device or system that controllably seals the annulus around the drill string (not shown). Rotating or non-rotating control device 740 may controllably seal the annulus (not shown) between the drill string (not shown) disposed there through and the inner diameter of the rotating or non-rotating control device 740. One or more bearing assemblies (not shown) of a rotating control device 740 rotates with the drill string (not shown), whereas a non-rotating control device 740 allows the drill string (not shown) to rotate without bearing assemblies, while maintaining a pressure tight seal to contain returning fluids in the annulus as the drill string (not shown) passes through and rotates within rotating or non-rotating control device 740

[0033] A bottom distal end of rotating or non-rotating control device 740 may be in fluid communication with a top distal end of inner barrel 135 of a telescopic joint 155. A bottom distal end of inner barrel 135 of telescopic joint 155 may be in fluid communication with an outer barrel 137 of telescopic joint 155 A riser tension ring 150 may be disposed about the outer barrel 137 of telescopic joint 155, supported by a plurality of riser tensioners 145 that provide upward force on riser 160 independent of the movement of platform 120 due to heave. Riser 160 may include a riser gas handler (“RGH”) or AID 710 that controllably seals the annulus surrounding the drill string or the wellbore itself while, for example, the bearing assemblies (not shown) of a rotating-type control device 740 are being installed, removed, or serviced, the drill string is tripped in or out, or other work performed on the riser stack that requires the maintenance of wellbore pressure. When the RGH or AID 710 is closed, the booster line (not shown) may be used to apply backpressure or augment the surface backpressure provided by the smart choke manifold (not shown). When the smart choke manifold (not shown) is to be fully closed as per modeler prediction, but still insufficient to compensate for the reduced volume, the booster line (not shown) flow rate may proactively be increased to compensate for the reduced volume when stroking out telescopic joint 155 due to heave. One or more umbilical and fluid flow lines 143 may control rotating or non-rotating control device 740 and provide fluid communication between rotating or non-rotating control device 740 and platform 120. As the body of water 105 heaves, inner barrel 135 of telescopic joint 155 strokes in and out with the rise and fall of the heave.

Figure 8A shows a floating drilling rig with an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint with a smart choke manifold with the telescopic joint stroked out 800 in accordance with one or more embodiments of the present invention. It is important to note that, because the rotating or non-rotating control device is disposed above the inner barrel 135 of the telescopic joint, displacement of the telescopic joint will cause a pressure difference. For example, when the telescopic joint is stroked out, the pressure difference caused by the extra volume of the displaced inner barrel 135 of the telescopic joint will cause the pressure to decrease. Continuing, Figure 8B shows the floating drilling system with the above-tension-ring rotating or non-rotating control device disposed above the telescopic joint with the smart choke manifold with the telescopic joint stroked in 800 in accordance with one or more embodiments of the present invention. When the telescopic joint is stroked in, the pressure difference caused by the compression of the inner barrel 135 into outer barrel 137 of the telescopic joint will cause the pressure to increase. As such, in one or more embodiments of the present invention, a method of heave compensation for surface backpressure seeks to calculate a heave compensation factor that is included in a calculated surface backpressure set point to compensate for heave of the floating drilling rig by manipulation of a smart choke manifold used to apply surface backpressure. [0035] Figure 9 shows a method of heave compensation for surface backpressure 900 in accordance with one or more embodiments of the present invention. The method 900 may be performed, in whole or in part, by one or more computing systems (e.g, 1000 of Figures 10 and 11) and a floating drilling rig (e.g., 800 of Figure 8) having a rotating or non-rotating control device (e.g, 740 of Figure 7) disposed above a telescopic joint (e.g., 135 of Figure 7). In step 910, a floating drilling rig may drill a wellbore into a subterranean surface. In step 920, a computing syste (e.g., 1000 of Figures 10 and 11), performing a hydraulic modeler or control system function, may acquire data including data corresponding to heave of the rig. The acquired data may include one or more of a displacement range of a telescopic joint, an inner diameter of an inner barrel of the telescopic joint, a length of the inner barrel of the telescopic joint, an inner diameter of an outer barrel of the telescopic joint, a length of the outer barrel of the telescopic joint, a density of fluids in the telescopic joint, and any other data that may be used to calibrate and calculate a heave compensation factor

[0036] The data corresponding to the heave of the rig may include one or more of sensed heave data, hi storical heave data, and predicted heave data. In step 930, the computing system may optionally predict future heave based on the acquired heave data. In step 940, the computing system may calculate a heave compensation factor based on the acquired data. The heave compensation factor may be a pressure difference caused by displacement of the telescopic joint of the rig based on the heave of the rig. In certain embodiments, the pressure difference may be calculated by multiplying a length of displacement of the telescopic joint by a density of fluids in the displacement. In step 940, the computing system may calculate a surface backpressure set point. In certain embodiments, the surface backpressure set point may be calculated by modeling a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure that includes the heave compensation factor. The safe pressure window may be a pressure window bounded by the pore pressure and the fracture pressure or the collapse pressure and the fracture pressure. In other embodiments, the surface backpressure may be calculated by summing a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure based on one or more actions taken by a driller and the heave compensation factor. The one or more actions taken by the driller, that impact wellbore pressure, include adjustment to one or more of rotation rate, fiow^? rate, block position, and block speed. In step 960, the computing system, performing the control system function, may change surface backpressure to the surface backpressure set point. The computing system may output a signal or signals corresponding to a position of one or more chokes of a smart choke manifold. The smart choke manifold may input the signal or signals and change a position of one or more chokes to achieve the surface backpressure set point. This process may be performed on an ongoing basis to more precisely manage pressure in the wellbore.

[0037] Figure 10 shows a block diagram of a system 1000 for heave compensation for surface backpressure in accordance with one or more embodiments of the present invention. One or more computing systems 1100 may be used to perform, in whole or in part., the method of heave compensation for surface backpressure as part of a floating drilling rig (not shown) having a rotating or non-rotating control device (not shown) disposed above the telescopic joint (not shown). Heave data 1010 may be input into computing system 1100. Heave data 1010 may be sensed heave data, historical heave data, or any other type or kind of data relevant to heave. A hydraulic modeler 1020, which may be a software application configured to execute on computing system 1100, may input heave data 1010 and other data used to generate a heave compensation factor or a hydraulic model of wellbore pressure, collectively referred to as input data 1030. Hydraulic modeler 1020 may calculate a heave compensation factor, or wellbore pressure set point that includes the heave compensation factor, 1040 that compensates for the pressure difference caused by displacement of the telescopic joint (not shown) due to heave, and computing system 1100 may adjust the surface backpressure 1050 set point of a smart choke manifold 1060 by at least the heave compensation factor 1040 to allow for the more precise management of pressure in the wellbore.

[0038] Hydraulic modeler 1020 may continuously generate a real-time model of wellbore pressure, or equivalent circulating density, 1040 based on input data 1030 including, but not limited to, one or more of water depth, well depth, casing diameter, internal diameter, inclination angle, riser diameter, drill string configuration, geothermal gradient, hydrothermal gradient, data provided by one or more surface- based sensors including, but not limited to, sensed rotation rate, sensed flow rate, and sensed block position or speed, and data provided by one or more optional downhole sensors including, but not limited to, downhole sensed flow rate, downhole sensed temperature, and downhole sensed mud density. Using one or more of input data 1030, hydraulic modeler 1020 may calculate and output wellbore pressure, or equivalent circulating density, 1040 for a given wellbore in real-time. The output surface backpressure set point 1050 may include the heave compensation factor, or wellbore pressure set point that includes the heave compensation factor, 1040 In closed-loop drilling systems, hydraulic modeler 1020 allows the driller to manage pressure by control of one or more smart choke manifolds 1060. Hydraulic modeler 1020 may output a surface backpressure set point (not shown) to computing system 1100 or computing system 1100 may calculate the surface backpressure set point based on the heave compensation factor, or wellbore pressure set point that incudes the heave compensation factor, 1040 The surface backpressure set point 1050 may be a position of one or more chokes (not shown) of smart choke manifold 1060 that achieves a desired surface backpressure based on the hydraulic model 1020. Computing system 1000 may output a signal or signals configured to manipulate a position of one or more chokes (not shown) of smart choke manifold 1060 to achieve the desired surface backpressure set point 1050.

[0039] Figure 11 show a block diagram of a computing system 1100 of a floating drilling rig for heave compensation for surface backpressure in accordance with one or more embodiments of the present invention. Computing system 1100 may be configured to execute, in whole or in part, a method of heave compensation for surface backpressure (e.g, 900 of Figure 9). Computing system 1100 may output signals (not shown) that are input into smart choke manifold (not shown) that control the position of one or more chokes (not shown) of the smart choke manifold (not shown) electronically. In certain embodiments, computing system 1100 may also implement the hydraulic modeler function (not shown). In other embodiments, the hydraulic modeler (not shown) may be implemented in a separate computing system that is in communication with computing system 1100 One of ordinary skill in the art will recognize that the various functions of the hydraulic modeler (not shown) and computing system 1100 may be distributed across multiple computing systems 1100 or integrated as part of the same computing system 1100.

[0040] Computing system 1100 may include one or more central processing units

(singular“CPU” or plural“CPUs”) 1105, host bridge 1110, input/output (“10”) bridge 1115, graphics processing units (singular“GPU” or plural“GPUs”) 1125, and/or application-specific integrated circuits (singular“ASIC or plural“ASICs”) (not shown) disposed on one or more printed circuit boards (not shown) that are configured to perform computational operations. Each of the one or more CPUs 1105, GPUs 1125, or ASICs (not shown) may be a single-core (not independently illustrated) device or a multi-core (not independently illustrated) device. Multi-core devices typically include a plurality of cores (not shown) disposed on the same physical die (not shown) or a plurality of cores (not shown) disposed on multiple die (not shown) that are collectively disposed within the same mechanical package (not shown).

[0041] CPU 1105 may be a general purpose computational device typically configured to execute software instructions. CPU 1105 may include an interface 1108 to host bridge 1110, an interface 1118 to system memory 1120, and an interface 1123 to one or more IO devices, such as, for example, one or more GPUs 1125. GPU 1125 may serve as a specialized computational device typically configured to perform graphics functions related to frame buffer manipulation. However, one of ordinary skill in the art will recognize that GPU 1125 may be used to perform non -graphics related functions that are computationally intensive. In certain embodiments, GPU 1125 may interface 1123 directly with CPU 1125 (and interface 1118 with system memory 1120 through CPU 1105). In other embodiments, GPU 1125 may interface 1121 with host bridge 1110 (and interface 1116 or 1118 with system memory 1120 through host bridge 1110 or CPU 1105 depending on the application or design). In still other embodiments, GPU 1125 may interface 1133 with IO bridge 1115 (and interface 1116 or 1118 with system memory 1120 through host bridge 1110 or CPU 1105 depending on the application or design). The functionality of GPU 1125 may be integrated, in whole or in part, with CPU 1105 or host bridge 1110.

[0042] Host bridge 1110 may be an interface device configured to interface between the one or more computational devices and IO bridge 1115 and, in some embodiments, system memory 1120. Host bridge 1110 may include an interface 1108 to CPU 1105, an interface 1113 to IO bridge 1115, for embodiments where CPU 1105 does not include an interface 1118 to system memory 1120, an interface 1116 to system memory 1120, and for embodiments where CPU 1105 does not include an integrated GPU 1125 or an interface 1123 to GPU 1125, an interface 1121 to GPU 1125. The functionality of host bridge 1110 may be integrated, in whole or in part, with CPU 1105. IO bridge 1115 may be an interface device configured to interface between the one or more computational devices and various IO devices (e.g, 1140, 1145) and IO expansion, or add-on, devices (not independently illustrated). IO bridge 1115 may include an interface 1113 to host bridge 1110, one or more interfaces 1133 to one or more 10 expansion devices 1135, an interface 1138 to keyboard 1140, an interface 1143 to mouse 1145, an interface 1148 to one or more local storage devices 1150, and an interface 1153 to one or more network interface devices 1155. The functionality of IO bridge 1115 may be integrated, in whole or in part, with CPU 1105 or host bridge 1110. Each local storage device 1150, if any, may be a non-transitory solid-state memo!}' device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network interface device 1155 may provide one or more network interfaces including any network protocol suitable to facilitate networked communications.

[0043] Computing system 1100 may include one or more network-attached storage devices 1160 in addition to, or instead of, one or more local storage devices 1150. Each network-attached storage device 1160, if any, may be a non-transitory solid- state memoiy device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network- attached storage device 1160 may or may not be collocated with computing system 1100 and may be accessible to computing system 1100 via one or more network interfaces provided by one or more network interface devices 1155.

[0044] One of ordinary' skill in the art will recognize that CPU 1105, host bridge 1110,

IO bridge 1115, GPU 1125, or ASIC (not shown) or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, in whole or in part., based on an application, design, or form factor in accordance with one or more embodiments of the present invention. Thus, the description of computing system 1100 is merely exemplary and not intended to limit the type, kind, or configuration of component devices that constitute a computing system 1100 suitable for performing computing operations in accordance with one or more embodiments of the present invention. Additionally, one of ordinary skill in the art will recognize that computing system 1100 may be a stand alone, laptop, desktop, server, blade, rack mountable, or cloud-based system and may vary based on an application or design in accordance with one or more embodiments of the present invention.

[0045] One of ordinary' skill in the art will recognize that computing system 1100 may be a cloud-based server, a server, a workstation, a desktop, a laptop, a netbook, a tablet, a smartphone, a mobile device, and/or any other type of computing system in accordance with one or more embodiments of the present invention. Moreover, one of ordinary skill in the art will recognize that computing system 1100 may be any other type or kind of system based on programmable logic controllers (“PLC”), programmable logic devices (“PLD”), or any other type or kind of system, including combinations thereof, capable of inputting data, performing calculations, and outputting control signals that manipulate a smart choke manifold (not shown).

[0046] Advantages of one or more embodiments of the present invention may include one or more of the following:

[0047] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure allows existing deepwater rigs to be converted, operated, and maintained as closed-loop drilling systems while more closely managing pressure in a manner that is substantially less expensive than existing closed-loop rig designs and retrofited rig designs.

[0048] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure uses an above-tension-ring rotating or non-rotating control device disposed above a telescopic joint and a smart choke manifold to compensate for heave of a floating drilling rig when applying surface backpressure to manage pressure in the wellbore.

[0049] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure uses a control device disposed above the waterline and substantially nearer to the rig floor Because the control device only supports the weight of the inner barrel of the telescopic joint, a substantially less robust control device may be used that is smaller in size and load rating, with substantially shorter and less expensive umbilical and fluid lines.

[0050] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure is substantially less expensive to install, maintain, and repair because of the disposition of the control device. In conventional closed-loop drilling systems, if the control device or bearing assembly needs to be repaired or replaced, the BOP must be disconnected from the wellhead in an expensive and time consuming operation. Advantageously, the location of the control device of the claimed invention provides improved accessibility, such that installation, maintenance, and repair is substantially easier and less expensive, allowing for the control device to be repaired or replaced without disconnecting the BOP from the wellhead.

[0051] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure substantially reduces operating expenditures by elimination of a subsea joint, subsea hoses, reels, umbilicals, and storm loops.

[0052] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure substantially reduces capital expenditures by allowing for removal of the rotating or non-rotating control device without BOP disconnection from the wellhead.

[0053] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure allows for the use of a surface rotating or non-rotating control device which has required connections and a bearing assembly outer diameter that allow for a drift through the upper flex joint bore.

[0054] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure is easier and less expensive to install than conventional closed-loop systems.

[0055] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure is easier and less expensive to maintain than conventional closed-loop systems.

[0056] In one or more embodiments of the present invention, a method and system for heave compensation for surface backpressure is easier and less expensive to repair than conventional closed-loop systems.

[0057] While the present invention has been described with respect to the above-noted embodiments, those skilled in the art, having the benefit of this disclosure, will recognize that other embodiments may be devised that are within the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the appended claims.

Claims

What is claimed is:

1. A method of heave compensation for surface backpressure comprising;

drilling a wellbore into a subterranean surface with a floating drilling rig;

acquiring data including data correspondi ng to heave of the rig;

calculating a heave compensation factor based on the acquired data;

cal culating a surface backpressure set point to manage pressure in the wellbore, wherein the surface backpressure set point includes the heave compensation factor; and changing surface backpressure to the surface backpressure set point.

2. The method of claim 1, wherein the data corresponding to the heave of the rig comprises one or more of sensed heave data, historical heave data, and predicted heave data.

3 The method of claim 1, wherein the heave compensation factor comprises a pressure difference caused by displacement of a telescopic joint of the rig based on the heave of the rig.

4. The method of claim 3, wherein the pressure difference is calculated by multiplying a length of displacement of the telescopic joint by a density of fluids in the displacement.

5. The method of claim 2, wherein the heave compensation factor comprises a pressure difference caused by displacement of a telescopic joint of the rig based on predicted heave of the rig.

6. The method of claim 1, wherein the acquired data comprises one or more of a displacement range of a telescopic joint, an inner diameter of an inner barrel of the telescopic joint, a length of the inner barrel of the telescopic joint, an inner diameter of an outer barrel of the telescopic joint, a length of the outer barrel of the telescopic joint, and a density of fluids in the telescopic joint.

7. The method of claim 1, wherein the surface backpressure set point is calculated by modeling a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure that includes the heave compensation factor.

8. The method of claim 1, wherein the surface backpressure set point is calculated by summing a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure based on one or more actions taken by a driller and the heave compensation factor.

9. The method of claim 8, wherein the one or more actions taken by the driller include an adjustment to one or more of a rotation rate, a flow rate, a block position, and a block speed.

10. The method of claim 1, wherein changing the surface backpressure to the surface backpressure set point comprises changing a position of one or more chokes of a choke manifold to achieve the surface backpressure set point.

11. The method of claim 1, wherein the floating drilling rig comprises an above-tension ring rotating or non-rotating control device disposed above a telescopic joint.

12. A floating drilling rig for heave compensation for surface backpressure comprising:

a smart choke manifold that controls a surface backpressure applied to a wellbore; a drill string that extends into the wellbore;

a rotating or non-rotating control device disposed around the drill string on top of a telescopic joint, wherein the rotating or non-rotating control device seals an annulus between the drill string and the telescopic joint,

a riser tension ring disposed around an outer barrel of the telescopic joint;

a marine riser fluidly connected to a bottom of the telescopic joint;

a data acquisition unit configured to acquire data including data corresponding to heave of the rig;

a hydraulic modeler configured to calculate a surface backpressure set point to manage pressure in the wellbore, wherein the surface backpressure set point includes a heave compensation factor calculated based on the acquired heave data; and a control system configured to change surface backpressure to the surface backpressure set point.

13. The floating drilling rig of claim 12, wherein the data corresponding to the heave of the rig comprises one or more of sensed heave data, historical heave data, and predicted heave data.

14. The floating drilling rig of claim 12, wherein the heave compensation factor comprises a pressure difference caused by displacement of the telescopic joint of the rig based on the heave of the rig.

15. The floating drilling rig of claim 14, wherein the pressure difference is calculated by multiplying a length of displacement of the telescopic joint by a density of fluids in the displacement.

16. The floating drilling rig of claim 13, wherein the heave compensation factor comprises a pressure difference caused by displacement of the telescopic joint of the rig based on predicted heave of the rig.

17. The floating drilling rig of claim 12, wherein the acquired data comprises one or more of a displacement range of the telescopic joint, an inner diameter of an inner barrel of the telescopic joint, a length of the inner barrel of the telescopic joint, an inner diameter of an outer barrel of the telescopic joint, a length of the outer barrel of the telescopic joint, and a density of fluids in the telescopic joint.

18. The floating drilling rig of claim 12, wherein the surface backpressure set point is calculated by modeling a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure that includes the heave compensation factor.

19. The floating drilling rig of claim 12, wherein the surface backpressure set point is calculated by summing a surface backpressure required to manage pressure within a safe pressure window or predetermined pressure based on one or more actions taken by a driller and the heave compensation factor.

20. The floating drilling rig of claim 19, wherein the one or more actions taken by the driller include an adjustment to one or more of a rotation rate, a flow rate, a block position, and a block speed.

21. The floating drilling rig of claim 12, wherein changing the surface backpressure to the surface backpressure set point comprises changing a position of one or more chokes of a choke manifold to achieve the surface backpressure set point.

22. The method of claim 1, wlierein the heave compensation factor comprises a pressure difference caused by displacement of a drill string inside the wellbore based on the heave of the rig.