US20060065402A9 - Drilling system and method for controlling equivalent circulating density during drilling of wellbores - Google Patents
Drilling system and method for controlling equivalent circulating density during drilling of wellbores Download PDFInfo
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- US20060065402A9 US20060065402A9 US10/191,152 US19115202A US2006065402A9 US 20060065402 A9 US20060065402 A9 US 20060065402A9 US 19115202 A US19115202 A US 19115202A US 2006065402 A9 US2006065402 A9 US 2006065402A9
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- 238000005553 drilling Methods 0.000 title claims abstract description 109
- 238000000034 method Methods 0.000 title claims description 29
- 239000012530 fluid Substances 0.000 claims abstract description 190
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/12—Underwater drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/001—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor specially adapted for underwater drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
- E21B21/085—Underbalanced techniques, i.e. where borehole fluid pressure is below formation pressure
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
- E21B33/076—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/001—Survey of boreholes or wells for underwater installation
Definitions
- This invention relates generally to oilfield wellbore drilling systems and more particularly to subsea drilling systems that control bottom hole pressure or equivalent circulating density during drilling of the wellbores.
- Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string.
- the drill string includes a drilling assembly (also referred to as the “bottom hole assembly” or “BHA”) that carries the drill bit.
- BHA bottom hole assembly
- Coiled tubing or jointed tubing is utilized to convey the drilling assembly into the wellbore.
- the drilling assembly sometimes includes a drilling motor or a “mud motor” that rotates the drill bit.
- the drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters.
- a suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped from the surface down the tubing.
- the drilling fluid drives the mud motor and then it discharges at the bottom of the drill bit.
- the drilling fluid returns uphole via the annulus between the drill string and the wellbore and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
- tubing For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at the surface work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore.
- a riser which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead.
- the riser also serves as a conduit for fluid returning from the wellhead to the vessel at sea surface.
- the drilling operator attempts to carefully control the fluid density at the surface so as to prevent an overburdened condition in the wellbore.
- the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out.
- the density of the drilling fluid and the fluid flow rate largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface.
- One important downhole parameter during drilling is the bottomhole pressure, which is effectively the equivalent circulating density (“ECD”) of the fluid at the wellbore bottom.
- ECD equivalent circulating density
- ECD describes the condition that exists when the drilling mud in the well is circulated.
- ECD is the friction pressure caused by the fluid circulating through the annulus of the open hole and the casing(s) on its way back to the surface. This causes an increase in the pressure profile along this path that is different from the pressure profile when the well is in a static condition (i.e., not circulating).
- This pressure increase along the annulus of the well can negatively impact drilling operations by fracturing the formation at the shoe of the last casing. This can reduce the amount of hole that can be drilled before having to set an additional casing.
- the bottom hole ECD In order to be able to drill a well of this type to a total wellbore depth at a subsea location, the bottom hole ECD must be reduced or controlled.
- One approach to do so is to use a mud filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system).
- gas or some other low density liquid
- This so-called “dual density” approach is often referred to as drilling with compressible fluids.
- the present invention provides a wellbore system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in the returning fluid path of a riser utilizing an active differential pressure device, such as a centrifugal pump or turbine, located adjacent to the riser. The fluid is then returned into the riser above the restriction.
- the present invention also provides a dual gradient subsea drilling system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in a riser by utilizing an active differential pressure device, such as a centrifugal pump or turbine located some distance above the sea bed.
- the present systems are relatively easy to incorporate in new and existing systems.
- the present invention provides wellbore systems for performing subsea downhole wellbore operations, such as subsea drilling as described more fully hereinafter.
- drilling systems include a rig at the sea level that moves a drill string into and out of the wellbore.
- a bottom hole assembly, carrying the drill bit, is attached to the bottom end of the tubing.
- a wellhead assembly or equipment at the sea bottom receives the bottom hole assembly and the tubing.
- a drilling fluid system supplies a drilling fluid into a fluid circuit that supports wellbore operations.
- the fluid circuit includes a supply conduit and a return conduit.
- the supply conduit includes a tubing string that receives drilling fluid from the fluid system. This fluid is discharged at the drill bit and returns to the wellhead equipment carrying the drill cuttings.
- the return conduit includes a riser dispersed between the wellhead equipment and the surface that guides the drill string and provides a conduit for moving the returning fluid to the surface.
- a flow restriction device in the riser restricts the flow of the returning fluid through the riser.
- the flow restriction device moves between a substantially open bore and closed bore positions and accommodates the axial sliding and rotation movement of the drill string.
- radial bearings stabilize the drill string while a hydraulically actuated packer assembly provides selective obstruction of the riser bore and therefore selectively diverts return fluid flow into a flow diverter line provided below the flow restriction device.
- a seal such as a rotary seal is used to further restrict flow of return fluid through the flow restriction device.
- a fluid flow device such as a centrifugal pump or turbine in the flow diverter line causes a pressure differential in the returning fluid as it flows from just below the flow restriction device to above the flow restriction device.
- the pump speed is controlled, by controlling the energy input to the pump.
- One or more pressure sensors provide pressure measurement of the circulating fluid.
- a controller controls the operation of the pump to control the amount of the differential pressure across the pump and thus the equivalent circulating density.
- the controller maintains the equivalent circulating density at a predetermined level or within a predetermined range in response to programmed instructions provided to the controller.
- the pump is mounted on the outside of the riser joint, typically at a sufficient depth below the sea level to provide enough lift to offset the desired amount of ECD.
- the flow restriction device and the pump may be disposed in the return fluid path in the annulus between the wellbore and the drill string.
- the present system is equally useful as an at-balance or an underbalanced drilling system.
- a flow restriction device in the riser restricts the flow of the returning fluid through the riser.
- a flow diverter line, active pressure differential device (“APD Device”) and a separate return line provide a fluid flow path around the flow restriction device.
- dual gradient drilling with active control of wellbore pressure is achieved mid riser or at a selected point in the riser, the selected point between the surface and sea bottom.
- the active pressure differential device such as centrifugal pumps or turbines, moves the returning fluid from just below the flow restriction device to the surface via the separate return line.
- the operation of the active pressure differential device is controlled to create a differential pressure across the device, thereby reducing the bottomhole pressure.
- the pumps or turbines speeds are controlled, by controlling the energy input to the pumps or turbines.
- One or more pressure sensors provide pressure measurements of the circulating fluid.
- a controller controls the operation of the pumps or turbines to control the amount of the pressure differential and thus the equivalent circulating density.
- the controller maintains the bottom hole pressure and the equivalent circulating density at a predetermined level or within a predetermined range in response to programmed instructions provided to the controller.
- the pumps or turbines are mounted on the outside of the riser, typically between 1000 to 3000 ft. below sea level, but above the sea bed. The present system is equally useful in maintaining the bottomhole pressure at an at-balance or under-balance condition.
- FIG. 1 is a schematic elevation view of one embodiment of a wellbore system for controlling equivalent circulating density during drilling of subsea wellbores;
- FIG. 2 is a schematic elevation view of a flow restriction device and active differential pressure device made in accordance with one embodiment of the present invention
- FIGS. 3A and 3B illustrate pressure gradient curves provided by the FIG. 1 embodiment of the present invention
- FIG. 4 is a schematic elevation view of one embodiment of a wellbore system for controlling equivalent circulating density and bottomhole pressure during dual gradient drilling of subsea wellbores with the device mounted at a point in the riser between the surface and the seabed;
- FIGS. 5A and 5B illustrate pressure gradient curves provided by the FIG. 4 embodiment of the present invention.
- FIG. 1 shows a schematic elevational view of a wellbore drilling system 100 for drilling a subsea or under water wellbore 90 .
- the drilling system 100 includes a drilling platform 101 , which may be a drill ship or another suitable surface work station such as a floating platform or a semi-submersible.
- a drilling ship or a floating rig is usually preferred for drilling deep water wellbores, such as wellbores drilled under several thousand feet of water.
- wellhead equipment 125 is deployed above the wellbore 90 at the sea bed or bottom 123 .
- the wellhead equipment 125 includes a blow-outpreventer stack 126 .
- a lubricator (not shown) with its associated flow control valves may be provided over the blow-out-preventer 126 .
- the subsea wellbore 90 is drilled by a drill bit 130 carried by a drill string 120 , which includes a drilling assembly or a bottom hole assembly (“BHA”) 135 at the bottom of a suitable tubing 121 , which may be a coiled tubing or a jointed pipe.
- the tubing 121 is placed at the drilling platform 101 .
- the BHA 135 is conveyed from the vessel 101 to the wellhead equipment 125 and then inserted into the wellbore 90 .
- the tubing 121 is moved to the wellhead equipment 125 and then moved into and out of the wellbore 90 by a suitable tubing injection system.
- a drilling fluid 20 from a surface drilling fluid system or mud system 22 is directed into a fluid circuit that services the wellbore 90 .
- This fluid can be pressurized or use primarily gravity assisted flow.
- the mud system 22 includes a mud pit or supply source 26 and one or more pumps 28 in fluid communication with a supply conduit of the fluid circuit.
- the fluid is pumped down the supply conduit, which includes the tubing 121 .
- the drilling fluid 20 may operate a mud motor in the BHA 135 , which in turn rotates the drill bit 130 .
- the drill bit 130 breaks or cuts the formation (rock) into cuttings 147 .
- the drilling fluid 142 leaving the drill bit travels uphole through a return conduit of the fluid circuit.
- the return conduit includes the annulus 122 between the drill string 120 and the wellbore wall 126 carrying the drill cuttings 147 .
- the return circuit also includes a riser 160 between the wellhead 125 and the surface 101 that carries the returning fluid 142 from the wellbore 90 to the sea level.
- the returning fluid 142 discharges into a separator 24 , which separates the cuttings 147 and other solids from the returning fluid 142 and discharges the clean fluid into the mud pit 26 .
- the tubing 121 passes through the mud-filled riser 160 . As shown in FIG.
- the clean mud 20 is pumped through the tubing 121 and the mud 142 with cuttings 147 returns to the surface via the annulus 122 up to the wellhead 125 and then via the riser 160 .
- the fluid circulation system or fluid circuit includes a supply conduit (e.g., the tubing 121 ) and a return conduit (e.g., the annulus 122 and the riser 160 ).
- the riser constitutes an active part of the fluid circulation system.
- the present invention provides a drilling system for controlling wellbore pressure and controlling or reducing the ECD effect during drilling fluid circulation or drilling of subsea wellbores.
- the present invention selectively adjusts the pressure gradient of the fluid circulation system.
- One embodiment of the present invention utilizes an arrangement wherein the flow of return fluid is controlled (e.g., assisted) at a predetermined elevation along the riser 160 .
- An exemplary arrangement of such an embodiment includes a flow restriction device 164 in the drilling riser 160 and an actively controlled fluid lifting device 170 .
- an exemplary flow restriction device 164 diverts return fluid flow from the riser 160 to the fluid lifting device 170 .
- the flow restriction device 164 can move between a substantially open bore position (no flow restriction) and a substantially closed bore position (substantial flow restriction). It is also preferred that the flow restriction device 164 accommodate both the axial sliding and rotation movement of the drill string 121 when in the substantially closed position. Accordingly, in a preferred embodiment of the flow restriction device 164 , upper and lower radial bearings 164 A, 164 B are used to stabilize the drill string 121 during movement. Further, a hydraulically actuated packer assembly 164 D provides selective obstruction of the bore of the riser 160 .
- the inflatable elements of the packer assembly 164 D When energized with hydraulic fluid via a hydraulic line 164 G, the inflatable elements of the packer assembly 164 D expand to grip the drill string 121 and thereby substantially divert return fluid flow 142 into the diverter line 171 .
- Intermediate elements such as concentric tubular sleeve bearings (not shown) can be interposed between the packer assembly 164 D and the drill string 121 .
- a seal 164 C such as a rotary seal can be provide an additional barrier against the flow of return fluid 142 through the flow restriction device 164 .
- the flow restriction device 164 is positioned in a housing joint 164 F, which can be a slip joint housing. Elements such as the bearings 164 A,B and seal 164 C can be configured to reside permanently in the housing joint 164 F or mount on the drill string 121 . In one preferred arrangement, element that are subjected to relatively high wear are positioned on the drill string 121 and changed out when the drill string 121 is tripped. Furthermore, a certain controlled clearance is preferably provided between the drill string 121 and the flow restriction device 164 so that upset portion of the drill string 121 (e.g., jointed connections) can slide or pass through the flow restriction device 164 .
- upset portion of the drill string 121 e.g., jointed connections
- the flow restriction device 164 may be adjustable from a surface location via a control line 165 , which allows the control over the pressure differential through the riser.
- the depth at which the flow restriction device 164 is installed will depend upon the maximum desired reduction in the ECD. A depth of between 1000 ft to 3000 ft. is considered adequate for most subsea applications.
- the returning fluid 142 in the riser 160 is diverted about the restriction device 164 by a fluid lifting device, such as centrifugal pump 170 coupled to a flow cross line or a diverter line 171 .
- the diverter line 171 is installed from a location below the flow restriction device 164 to a location above the flow restriction device 164 .
- the lifting device 170 diverts the returning fluid in the riser from below the flow restriction device to above the flow restriction device 164 .
- the fluid lifting device 170 is mounted on the exterior of the riser 160 .
- the pump speed (RPM) is controlled.
- the energy input to (and thus the RPM of) the pump 170 is increased as the fluid flow in the circulating path is increased and/or the length of the circulating path increases with advancement of the drill bit.
- the energy input to (and thus the RPM of) the lifting device is decreased as the return flow in the well 90 ( FIG. 1 ) is decreased.
- the lifting device takes on part of the work of pushing or lifting the drilling fluid back to the surface from the restriction device location.
- the energy input into the lifting device 170 results in reducing the hydrostatic pressure of the fluid column below that point, which results in a corresponding reduction of the pressure along the return path in the annulus below the lifting device 170 and more specifically at the shoe 151 of the last casing 152 .
- Any number of devices such as centrifugal pumps, turbines, jet pumps, positive displacement pumps and the like can be suitable for providing a pressure differential and associated control of ECD.
- the terms active pressure differential device (“APD” device), active fluid flow device and active fluid lifting device are intended to encompass at least such devices, mechanisms and arrangements.
- the flow restriction device 164 and the pump 170 may be installed at a suitable location in the wellbore annulus, such as shown by arrow 175 , or at the wellhead equipment 125 .
- the present invention is equally applicable to under-balanced drilling systems since it is capable of controlling the ECD effect to a desired level.
- the wellbore system 100 further includes a controller 180 at the surface that is adapted to receive input or signals from a variety of sensors including those in remote equipment such as the BHA 135 .
- the system 100 includes one or more pressure sensors, such as P 1 and a host of other sensors S 1-7 that provide measurements relating to a variety of drilling parameters, such as fluid flow rate, temperature, weight-on bit, rate of penetration, etc., drilling assembly or BHA parameters, such as vibration, stick slip, RPM, inclination, direction, BHA location, etc. and formation or formation evaluation parameters commonly referred to as measurement-while-drilling parameters such as resistivity, acoustic, nuclear, NMR, etc.
- Drilling fluid pressure measurements may also be obtained at wellhead (P 2 ) and at the surface (P 3 ) or at any other suitable location (P n ) along the drill string 120 .
- the status and condition of equipment as well as parameters relating to ambient conditions (as well as pressure and other parameters listed above) in the system 100 can be monitored by sensors positioned throughout the system 100 : exemplary locations including at the surface (S 1 ), at the fluid lifting device (S 2 ), at the wellhead equipment 125 (S 3 ), at the fluid restriction device 164 (S 4 ), near the casing shoe 151 B (S 5 ), at bottomhole assembly (S 6 ), and near the inlet to the active fluid lifting device 170 (S 7 ).
- the data provided by these sensors are transmitted to the controller 180 by a suitable telemetry system (not shown).
- the controller 180 receives the pressure information from one or more of the sensors (P 1 -P n ) and/or information from other sensors (S 1 -S 7 ) in the system 100 .
- the controller 180 determines the ECD and adjusts the energy input to the lifting device 170 to maintain the ECD at a desired or predetermined value or within a desired or predetermined range.
- the controller 180 includes a microprocessor or a computer, peripherals 184 and programs which are capable of making online decisions regarding the control of the flow restriction device 164 and the energy input to the lifting device 170 .
- a speed sensor S 2 may be used to determine the pump speed.
- the location of the flow restriction device 164 and the pressure differential about the restriction device controls the ECD.
- the wellbore system 100 thus provides a closed loop system for controlling the ECD by controllably diverting the returning fluid about a flow restriction device in the returning fluid path in response to one or more parameters of interest during drilling of a wellbore.
- This system is relatively simple and efficient and can be incorporated into new or existing drilling systems.
- FIGS. 3A and 3B there is graphically illustrated the ECD control provided by the above-described embodiment of the present invention.
- FIG. 3A shows the fluid lifting device 164 at a depth D 1 and a representative location in the wellbore such as the casing shoe 151 at a lower depth D 2 .
- FIG. 3B provides a depth versus pressure graph having a first curve C 1 representative of a pressure gradient before operation of the system 100 and a second curve C 2 representative of a pressure gradients during operation of the system 100 .
- Curve C 3 represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings.
- the system 100 reduces the hydrostatic pressure at depth D 1 . and thus shifts the pressure gradient as shown by curve C 3 , which can provide the desired predetermined pressure at depth D 2 . This shift is roughly the pressure drop provided by the fluid lifting device 170 .
- FIG. 4 there is shown another embodiment of the present invention that is suitable for dual gradient drilling.
- the FIG. 4 embodiment includes a system 200 wherein the returning fluid 142 in the riser 160 is diverted about the restriction device 164 by an active pressure differential device 202 coupled to a flow cross line or a diverter line 204 .
- the diverter line 204 is installed at a location below the flow restriction device 164 .
- the active pressure differential device 202 diverts the returning fluid 142 in the riser 160 from below the flow restriction device 164 to the surface.
- the active pressure differential device 202 is mounted above the seabed and external to riser 160 .
- FIG. 4 further illustrates a material 208 , having a lower density than the return fluid and obtained from a suitable source at or near the surface, is maintained in the riser 160 uphole of restriction device 164 .
- the material 208 usually is seawater. However, a suitable fluid could have a density less or greater than seawater.
- the material 208 is used in providing a static pressure gradient to the wellbore that is less than the pressure gradient formed by the fluid downhole of the flow restriction device 164 . Drilling is performed in a similar manner to that described with respect to the FIG. 1 embodiment except that the active pressure differential device 202 discharges the return fluid 142 into the separate return line 206 that may be external to the riser 160 . Thereafter, the return fluid 142 is discharged into the separator 24 .
- the system 200 utilizes a flow restriction device 164 and active pressure differential device 202 in much the same manner as that described in reference to system 100 ( FIG. 1 ). That is, briefly, the active pressure differential device 202 provides lift to the return fluid, above its location reducing the hydrostatic pressure of the fluid column below that point. This results in a corresponding reduction of the pressure along the return path and more specifically at the shoe 151 of the last casing 152 . Therefore, control of the active pressure differential device allows for control of the wellbore pressure and ECD.
- FIGS. 5A and 5B there is graphically illustrated the ECD control provided by the above-described embodiment of the present invention.
- FIG. 5A shows the fluid lifting device 202 at a depth D 3 and a representative location in the wellbore such as the casing shoe 151 at a lower depth D 4 .
- FIG. 5B provides a depth versus pressure chart having a first curve C 4 representative of a pressure gradient before operation of the system 100 and a second curve C 5 representative of a pressure gradients during operation of the system 100 .
- Curve C 6 represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings.
- the pressure gradient of the non-drilling fluid material 208 (e.g., seawater) ( FIG. 3 ) in riser is shown as curve C 7 and the pressure gradient of the drilling fluid in the separate line 206 ( FIG. 3 ) is shown as curve C 8 .
- curve C 7 The pressure gradient of the non-drilling fluid material 208 (e.g., seawater) ( FIG. 3 ) in riser
- curve C 8 The pressure gradient of the drilling fluid in the separate line 206
- the system 200 includes a controller 180 that is adapted to receive input or signals from a variety of sensors including those in the BHA 135 . For brevity, the details of the several associated components will not be repeated. Further, also like system 100 , the controller 180 of system 200 receives the pressure information from one or more of the sensors (P 1 -P n ) and/or information from other sensors S 1 -S 7 in the system 100 . The controller 180 determines the bottomhole pressure and adjusts the energy input to the pressure differential device 202 to maintain the bottomhole pressure at a desired or predetermined value or within a desired or predetermined range.
- the wellbore system 200 thus provides a closed loop system for controlling the ECD by controllably diverting the returning fluid about a flow restriction device in the returning fluid path in response to one or more parameters of interest during drilling of a wellbore.
- This system is relatively simple and efficient and can be incorporated into new or existing drilling systems.
Abstract
Description
- This application takes priority from Provisional U.S. Patent Applications Serial Nos. 60/303,959 and 60/304,160, filed on Jul. 9 th, 2001 and Jul. 10 th, 2001, respectively, and Provisional U.S. Patent Application Serial No. 60/323,797, filed on Sep. 20 th, 2001. This application also takes priority from U.S. application Ser. No. 10/094,208, filed Mar. 8 th, 2002 and Ser. No. 09/353,275, filed Jul. 14 th, 1999, both of which claim priority from U.S. application Nos.: No. 60/108,601, filed Nov. 16th, 1998; No. 60/101,541, filed Sep. 23 rd, 1998; No. 60/092,908, filed Jul. 15 th, 1998; and No. 60/095,188, filed Aug. 3 rd, 1998.
- 1. Field of the Invention
- This invention relates generally to oilfield wellbore drilling systems and more particularly to subsea drilling systems that control bottom hole pressure or equivalent circulating density during drilling of the wellbores.
- 2. Background of the Art
- Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drilling assembly (also referred to as the “bottom hole assembly” or “BHA”) that carries the drill bit. The BHA is conveyed into the wellbore by a tubing. Coiled tubing or jointed tubing is utilized to convey the drilling assembly into the wellbore. The drilling assembly sometimes includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped from the surface down the tubing. The drilling fluid drives the mud motor and then it discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
- For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at the surface work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. In sub-sea riser-type drilling, a riser, which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the vessel at sea surface.
- During drilling, the drilling operator attempts to carefully control the fluid density at the surface so as to prevent an overburdened condition in the wellbore. In other words, the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out. The density of the drilling fluid and the fluid flow rate largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface. One important downhole parameter during drilling is the bottomhole pressure, which is effectively the equivalent circulating density (“ECD”) of the fluid at the wellbore bottom.
- This term, ECD, describes the condition that exists when the drilling mud in the well is circulated. ECD is the friction pressure caused by the fluid circulating through the annulus of the open hole and the casing(s) on its way back to the surface. This causes an increase in the pressure profile along this path that is different from the pressure profile when the well is in a static condition (i.e., not circulating). In addition to the increase in pressure while circulating, there is an additional increase in pressure while drilling due to the introduction of drill solids into the fluid. This pressure increase along the annulus of the well can negatively impact drilling operations by fracturing the formation at the shoe of the last casing. This can reduce the amount of hole that can be drilled before having to set an additional casing. In addition, the rate of circulation that can be achieved is also limited. Due to this circulating pressure increase, the ability to clean the hole is severely restricted. This condition is exacerbated when drilling an offshore well. In offshore wells, the difference between the fracture pressures in the shallow sections of the well and the pore pressures of the deeper sections is considerably smaller compared to on-shore wellbores. This is due to the seawater gradient versus the gradient that would exist if there were soil overburden for the same depth.
- In order to be able to drill a well of this type to a total wellbore depth at a subsea location, the bottom hole ECD must be reduced or controlled. One approach to do so is to use a mud filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system). This so-called “dual density” approach is often referred to as drilling with compressible fluids.
- Another method for changing the density gradient in a deepwater return fluid path has been proposed. This approach proposes to use a tank, such as an elastic bag, at the sea floor for receiving return fluid from the wellbore annulus and holding it at the hydrostatic pressure of the water at the sea floor. Independent of the flow in the annulus, a separate return line connected to the sea floor storage tank and a subsea lifting pump delivers the return fluid to the surface. Although this technique (which is referred to as “dual gradient” drilling) would use a single fluid, it would also require a discontinuity in the hydraulic gradient line between the sea floor storage tank and the subsea lifting pump. This requires close monitoring and control of the pressure at the subsea storage tank, subsea hydrostatic water pressure, subsea lifting pump operation and the surface pump delivering drilling fluids under pressure into the tubing for flow downhole. The level of complexity of the required subsea instrumentation and controls as well as the difficulty of deployment of the system has delayed the commercial application of the “dual gradient” system.
- Another approach is described in U.S. patent application Ser. No. 09/353,275, filed on Jul. 14, 1999 and assigned to the assignee of the present application. The U.S. patent application Ser. No. 09/353,275 is incorporated herein by reference in its entirety. One embodiment of this application describes a riserless system wherein a centrifugal pump in a separate return line controls the fluid flow to the surface and thus the equivalent circulating density.
- The present invention provides a wellbore system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in the returning fluid path of a riser utilizing an active differential pressure device, such as a centrifugal pump or turbine, located adjacent to the riser. The fluid is then returned into the riser above the restriction. The present invention also provides a dual gradient subsea drilling system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in a riser by utilizing an active differential pressure device, such as a centrifugal pump or turbine located some distance above the sea bed. The present systems are relatively easy to incorporate in new and existing systems.
- The present invention provides wellbore systems for performing subsea downhole wellbore operations, such as subsea drilling as described more fully hereinafter. Such drilling systems include a rig at the sea level that moves a drill string into and out of the wellbore. A bottom hole assembly, carrying the drill bit, is attached to the bottom end of the tubing. A wellhead assembly or equipment at the sea bottom receives the bottom hole assembly and the tubing. A drilling fluid system supplies a drilling fluid into a fluid circuit that supports wellbore operations. In one embodiment, the fluid circuit includes a supply conduit and a return conduit. The supply conduit includes a tubing string that receives drilling fluid from the fluid system. This fluid is discharged at the drill bit and returns to the wellhead equipment carrying the drill cuttings. The return conduit includes a riser dispersed between the wellhead equipment and the surface that guides the drill string and provides a conduit for moving the returning fluid to the surface.
- In one embodiment of the present invention, a flow restriction device in the riser restricts the flow of the returning fluid through the riser. Preferably, the flow restriction device moves between a substantially open bore and closed bore positions and accommodates the axial sliding and rotation movement of the drill string. In one embodiment, radial bearings stabilize the drill string while a hydraulically actuated packer assembly provides selective obstruction of the riser bore and therefore selectively diverts return fluid flow into a flow diverter line provided below the flow restriction device. Additionally, a seal such as a rotary seal is used to further restrict flow of return fluid through the flow restriction device. A fluid flow device, such as a centrifugal pump or turbine in the flow diverter line causes a pressure differential in the returning fluid as it flows from just below the flow restriction device to above the flow restriction device. The pump speed is controlled, by controlling the energy input to the pump. One or more pressure sensors provide pressure measurement of the circulating fluid. A controller controls the operation of the pump to control the amount of the differential pressure across the pump and thus the equivalent circulating density. The controller maintains the equivalent circulating density at a predetermined level or within a predetermined range in response to programmed instructions provided to the controller. The pump is mounted on the outside of the riser joint, typically at a sufficient depth below the sea level to provide enough lift to offset the desired amount of ECD. Alternatively, the flow restriction device and the pump may be disposed in the return fluid path in the annulus between the wellbore and the drill string. The present system is equally useful as an at-balance or an underbalanced drilling system.
- In another embodiment of the present invention, a flow restriction device in the riser restricts the flow of the returning fluid through the riser. A flow diverter line, active pressure differential device (“APD Device”) and a separate return line provide a fluid flow path around the flow restriction device. In this embodiment, dual gradient drilling with active control of wellbore pressure is achieved mid riser or at a selected point in the riser, the selected point between the surface and sea bottom. The active pressure differential device, such as centrifugal pumps or turbines, moves the returning fluid from just below the flow restriction device to the surface via the separate return line. The operation of the active pressure differential device is controlled to create a differential pressure across the device, thereby reducing the bottomhole pressure. The pumps or turbines speeds are controlled, by controlling the energy input to the pumps or turbines. One or more pressure sensors provide pressure measurements of the circulating fluid. A controller controls the operation of the pumps or turbines to control the amount of the pressure differential and thus the equivalent circulating density. The controller maintains the bottom hole pressure and the equivalent circulating density at a predetermined level or within a predetermined range in response to programmed instructions provided to the controller. The pumps or turbines are mounted on the outside of the riser, typically between 1000 to 3000 ft. below sea level, but above the sea bed. The present system is equally useful in maintaining the bottomhole pressure at an at-balance or under-balance condition.
- Examples of the more important features of the invention have been summarized (albeit rather broadly) in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.
- For detailed understanding of the present invention, reference should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawing:
-
FIG. 1 is a schematic elevation view of one embodiment of a wellbore system for controlling equivalent circulating density during drilling of subsea wellbores; -
FIG. 2 is a schematic elevation view of a flow restriction device and active differential pressure device made in accordance with one embodiment of the present invention; -
FIGS. 3A and 3B illustrate pressure gradient curves provided by theFIG. 1 embodiment of the present invention; -
FIG. 4 is a schematic elevation view of one embodiment of a wellbore system for controlling equivalent circulating density and bottomhole pressure during dual gradient drilling of subsea wellbores with the device mounted at a point in the riser between the surface and the seabed; and -
FIGS. 5A and 5B illustrate pressure gradient curves provided by theFIG. 4 embodiment of the present invention. -
FIG. 1 shows a schematic elevational view of awellbore drilling system 100 for drilling a subsea or underwater wellbore 90. Thedrilling system 100 includes adrilling platform 101, which may be a drill ship or another suitable surface work station such as a floating platform or a semi-submersible. A drilling ship or a floating rig is usually preferred for drilling deep water wellbores, such as wellbores drilled under several thousand feet of water. To drill awellbore 90 under water,wellhead equipment 125 is deployed above thewellbore 90 at the sea bed orbottom 123. Thewellhead equipment 125 includes a blow-outpreventer stack 126. A lubricator (not shown) with its associated flow control valves may be provided over the blow-out-preventer 126. - The
subsea wellbore 90 is drilled by adrill bit 130 carried by adrill string 120, which includes a drilling assembly or a bottom hole assembly (“BHA”) 135 at the bottom of asuitable tubing 121, which may be a coiled tubing or a jointed pipe. Thetubing 121 is placed at thedrilling platform 101. To drill thewellbore 90, theBHA 135 is conveyed from thevessel 101 to thewellhead equipment 125 and then inserted into thewellbore 90. Thetubing 121 is moved to thewellhead equipment 125 and then moved into and out of thewellbore 90 by a suitable tubing injection system. - To drill the
wellbore 90, adrilling fluid 20 from a surface drilling fluid system ormud system 22 is directed into a fluid circuit that services thewellbore 90. This fluid can be pressurized or use primarily gravity assisted flow. In one embodiment, themud system 22 includes a mud pit orsupply source 26 and one ormore pumps 28 in fluid communication with a supply conduit of the fluid circuit. The fluid is pumped down the supply conduit, which includes thetubing 121. Thedrilling fluid 20 may operate a mud motor in theBHA 135, which in turn rotates thedrill bit 130. Thedrill bit 130 breaks or cuts the formation (rock) intocuttings 147. Thedrilling fluid 142 leaving the drill bit travels uphole through a return conduit of the fluid circuit. In one embodiment, the return conduit includes theannulus 122 between thedrill string 120 and thewellbore wall 126 carrying thedrill cuttings 147. The return circuit also includes ariser 160 between thewellhead 125 and thesurface 101 that carries the returning fluid 142 from thewellbore 90 to the sea level. The returningfluid 142 discharges into aseparator 24, which separates thecuttings 147 and other solids from the returningfluid 142 and discharges the clean fluid into themud pit 26. Thetubing 121 passes through the mud-filledriser 160. As shown inFIG. 1 , theclean mud 20 is pumped through thetubing 121 and themud 142 withcuttings 147 returns to the surface via theannulus 122 up to thewellhead 125 and then via theriser 160. Thus, the fluid circulation system or fluid circuit includes a supply conduit (e.g., the tubing 121) and a return conduit (e.g., theannulus 122 and the riser 160). Thus, in one embodiment the riser constitutes an active part of the fluid circulation system. - As noted above, the present invention provides a drilling system for controlling wellbore pressure and controlling or reducing the ECD effect during drilling fluid circulation or drilling of subsea wellbores. To achieve the desired control of the ECD, the present invention selectively adjusts the pressure gradient of the fluid circulation system. One embodiment of the present invention utilizes an arrangement wherein the flow of return fluid is controlled (e.g., assisted) at a predetermined elevation along the
riser 160. An exemplary arrangement of such an embodiment includes aflow restriction device 164 in thedrilling riser 160 and an actively controlledfluid lifting device 170. - Referring now to
FIG. 2 , an exemplaryflow restriction device 164 diverts return fluid flow from theriser 160 to thefluid lifting device 170. Preferably, theflow restriction device 164 can move between a substantially open bore position (no flow restriction) and a substantially closed bore position (substantial flow restriction). It is also preferred that theflow restriction device 164 accommodate both the axial sliding and rotation movement of thedrill string 121 when in the substantially closed position. Accordingly, in a preferred embodiment of theflow restriction device 164, upper and lowerradial bearings drill string 121 during movement. Further, a hydraulically actuatedpacker assembly 164D provides selective obstruction of the bore of theriser 160. When energized with hydraulic fluid via ahydraulic line 164G, the inflatable elements of thepacker assembly 164D expand to grip thedrill string 121 and thereby substantially divertreturn fluid flow 142 into thediverter line 171. Intermediate elements such as concentric tubular sleeve bearings (not shown) can be interposed between thepacker assembly 164D and thedrill string 121. Additionally, aseal 164C such as a rotary seal can be provide an additional barrier against the flow ofreturn fluid 142 through theflow restriction device 164. When de-energized, thepacker assembly 164D disengages from thedrill string 121 and retracts toward the wall of theriser 160. This retraction reduces the obstruction of the bore of theriser 160 and thereby enables large diameter equipment (not shown) to cross theflow restriction device 164 while, for example, thedrill string 121 is tripped in and out of theriser 160. Preferably, theflow restriction device 164 is positioned in a housing joint 164F, which can be a slip joint housing. Elements such as thebearings 164A,B and seal 164C can be configured to reside permanently in the housing joint 164F or mount on thedrill string 121. In one preferred arrangement, element that are subjected to relatively high wear are positioned on thedrill string 121 and changed out when thedrill string 121 is tripped. Furthermore, a certain controlled clearance is preferably provided between thedrill string 121 and theflow restriction device 164 so that upset portion of the drill string 121 (e.g., jointed connections) can slide or pass through theflow restriction device 164. - The
flow restriction device 164 may be adjustable from a surface location via acontrol line 165, which allows the control over the pressure differential through the riser. The depth at which theflow restriction device 164 is installed will depend upon the maximum desired reduction in the ECD. A depth of between 1000 ft to 3000 ft. is considered adequate for most subsea applications. The returningfluid 142 in theriser 160 is diverted about therestriction device 164 by a fluid lifting device, such ascentrifugal pump 170 coupled to a flow cross line or adiverter line 171. Thediverter line 171 is installed from a location below theflow restriction device 164 to a location above theflow restriction device 164. Thus, thelifting device 170 diverts the returning fluid in the riser from below the flow restriction device to above theflow restriction device 164. Thefluid lifting device 170 is mounted on the exterior of theriser 160. To control the ECD at a desired value, the pump speed (RPM) is controlled. Typically, the energy input to (and thus the RPM of) thepump 170 is increased as the fluid flow in the circulating path is increased and/or the length of the circulating path increases with advancement of the drill bit. Moreover, the energy input to (and thus the RPM of) the lifting device is decreased as the return flow in the well 90 (FIG. 1 ) is decreased. In this configuration, the lifting device takes on part of the work of pushing or lifting the drilling fluid back to the surface from the restriction device location. The energy input into the lifting device 170 (i.e. the work performed by the device) results in reducing the hydrostatic pressure of the fluid column below that point, which results in a corresponding reduction of the pressure along the return path in the annulus below thelifting device 170 and more specifically at theshoe 151 of thelast casing 152. Any number of devices such as centrifugal pumps, turbines, jet pumps, positive displacement pumps and the like can be suitable for providing a pressure differential and associated control of ECD. The terms active pressure differential device (“APD” device), active fluid flow device and active fluid lifting device are intended to encompass at least such devices, mechanisms and arrangements. - Referring now to
FIG. 1 , in an alternative embodiment, theflow restriction device 164 and thepump 170 may be installed at a suitable location in the wellbore annulus, such as shown byarrow 175, or at thewellhead equipment 125. Also, the present invention is equally applicable to under-balanced drilling systems since it is capable of controlling the ECD effect to a desired level. - Referring now to
FIGS. 1 and 2 , thewellbore system 100 further includes acontroller 180 at the surface that is adapted to receive input or signals from a variety of sensors including those in remote equipment such as theBHA 135. Thesystem 100 includes one or more pressure sensors, such as P1 and a host of other sensors S1-7 that provide measurements relating to a variety of drilling parameters, such as fluid flow rate, temperature, weight-on bit, rate of penetration, etc., drilling assembly or BHA parameters, such as vibration, stick slip, RPM, inclination, direction, BHA location, etc. and formation or formation evaluation parameters commonly referred to as measurement-while-drilling parameters such as resistivity, acoustic, nuclear, NMR, etc. Drilling fluid pressure measurements may also be obtained at wellhead (P2) and at the surface (P3) or at any other suitable location (Pn) along thedrill string 120. Further, the status and condition of equipment as well as parameters relating to ambient conditions (as well as pressure and other parameters listed above) in thesystem 100 can be monitored by sensors positioned throughout the system 100: exemplary locations including at the surface (S1), at the fluid lifting device (S2), at the wellhead equipment 125 (S3), at the fluid restriction device 164 (S4), near the casing shoe 151B (S5), at bottomhole assembly (S6), and near the inlet to the active fluid lifting device 170 (S7). The data provided by these sensors are transmitted to thecontroller 180 by a suitable telemetry system (not shown). - During drilling, the
controller 180 receives the pressure information from one or more of the sensors (P1-Pn) and/or information from other sensors (S1-S7) in thesystem 100. Thecontroller 180 determines the ECD and adjusts the energy input to thelifting device 170 to maintain the ECD at a desired or predetermined value or within a desired or predetermined range. Thecontroller 180 includes a microprocessor or a computer,peripherals 184 and programs which are capable of making online decisions regarding the control of theflow restriction device 164 and the energy input to thelifting device 170. A speed sensor S2 may be used to determine the pump speed. Thus, the location of theflow restriction device 164 and the pressure differential about the restriction device controls the ECD. Thewellbore system 100 thus provides a closed loop system for controlling the ECD by controllably diverting the returning fluid about a flow restriction device in the returning fluid path in response to one or more parameters of interest during drilling of a wellbore. This system is relatively simple and efficient and can be incorporated into new or existing drilling systems. - Referring now to
FIGS. 3A and 3B , there is graphically illustrated the ECD control provided by the above-described embodiment of the present invention. For convenience,FIG. 3A shows thefluid lifting device 164 at a depth D1 and a representative location in the wellbore such as thecasing shoe 151 at a lower depth D2.FIG. 3B provides a depth versus pressure graph having a first curve C1 representative of a pressure gradient before operation of thesystem 100 and a second curve C2 representative of a pressure gradients during operation of thesystem 100. Curve C3 represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings. It will be seen that a target or selected pressure at depth D2 under curve C3 cannot be met with curve C1. Advantageously, thesystem 100 reduces the hydrostatic pressure at depth D1. and thus shifts the pressure gradient as shown by curve C3, which can provide the desired predetermined pressure at depth D2. This shift is roughly the pressure drop provided by thefluid lifting device 170. - Referring now to
FIG. 4 , there is shown another embodiment of the present invention that is suitable for dual gradient drilling. Features the same as those inFIG. 1 are, for convenience, referenced with the same numerals. TheFIG. 4 embodiment includes asystem 200 wherein the returningfluid 142 in theriser 160 is diverted about therestriction device 164 by an active pressuredifferential device 202 coupled to a flow cross line or adiverter line 204. Thediverter line 204 is installed at a location below theflow restriction device 164. Thus, the active pressuredifferential device 202 diverts the returningfluid 142 in theriser 160 from below theflow restriction device 164 to the surface. The active pressuredifferential device 202 is mounted above the seabed and external toriser 160. The operation of the active pressuredifferential device 202 creates a selected pressure differential across thedevice 202. It also moves the returning fluid 142 from just below theflow restriction device 164 and discharges the diverted fluid into aseparate return line 206, which carries the fluid to the surface by bypassing the portion of theriser 160 that is above theflow restriction device 164.FIG. 4 further illustrates amaterial 208, having a lower density than the return fluid and obtained from a suitable source at or near the surface, is maintained in theriser 160 uphole ofrestriction device 164. Thematerial 208 usually is seawater. However, a suitable fluid could have a density less or greater than seawater. Thematerial 208 is used in providing a static pressure gradient to the wellbore that is less than the pressure gradient formed by the fluid downhole of theflow restriction device 164. Drilling is performed in a similar manner to that described with respect to theFIG. 1 embodiment except that the active pressuredifferential device 202 discharges thereturn fluid 142 into theseparate return line 206 that may be external to theriser 160. Thereafter, thereturn fluid 142 is discharged into theseparator 24. - To achieve the desired reduction and/or control of the bottomhole pressure or ECD, the
system 200 utilizes aflow restriction device 164 and active pressuredifferential device 202 in much the same manner as that described in reference to system 100 (FIG. 1 ). That is, briefly, the active pressuredifferential device 202 provides lift to the return fluid, above its location reducing the hydrostatic pressure of the fluid column below that point. This results in a corresponding reduction of the pressure along the return path and more specifically at theshoe 151 of thelast casing 152. Therefore, control of the active pressure differential device allows for control of the wellbore pressure and ECD. - Referring now to
FIGS. 5A and 5B , there is graphically illustrated the ECD control provided by the above-described embodiment of the present invention. For convenience,FIG. 5A shows thefluid lifting device 202 at a depth D3 and a representative location in the wellbore such as thecasing shoe 151 at a lower depth D4.FIG. 5B provides a depth versus pressure chart having a first curve C4 representative of a pressure gradient before operation of thesystem 100 and a second curve C5 representative of a pressure gradients during operation of thesystem 100. Curve C6 represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings. The pressure gradient of the non-drilling fluid material 208 (e.g., seawater) (FIG. 3 ) in riser is shown as curve C7 and the pressure gradient of the drilling fluid in the separate line 206 (FIG. 3 ) is shown as curve C8. It will be seen that a target or selected pressure at depth D3 under curve C6 cannot be met with curve C4. Advantageously, thesystem 200 reduces the hydrostatic pressure at depth D3 and thus shifts the pressure gradient curve as shown by curve C5, which can provide the desired predetermined pressure at depth D4. This shift is roughly the pressure drop provided by thefluid lifting device 202. - Like the
wellbore system 100 ofFIG. 1 , thesystem 200 includes acontroller 180 that is adapted to receive input or signals from a variety of sensors including those in theBHA 135. For brevity, the details of the several associated components will not be repeated. Further, also likesystem 100, thecontroller 180 ofsystem 200 receives the pressure information from one or more of the sensors (P1-Pn) and/or information from other sensors S1-S7 in thesystem 100. Thecontroller 180 determines the bottomhole pressure and adjusts the energy input to the pressuredifferential device 202 to maintain the bottomhole pressure at a desired or predetermined value or within a desired or predetermined range. Thewellbore system 200 thus provides a closed loop system for controlling the ECD by controllably diverting the returning fluid about a flow restriction device in the returning fluid path in response to one or more parameters of interest during drilling of a wellbore. This system is relatively simple and efficient and can be incorporated into new or existing drilling systems. - While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.
Claims (60)
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US10/191,152 US7270185B2 (en) | 1998-07-15 | 2002-07-09 | Drilling system and method for controlling equivalent circulating density during drilling of wellbores |
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US10860198P | 1998-11-16 | 1998-11-16 | |
US09/353,275 US6415877B1 (en) | 1998-07-15 | 1999-07-14 | Subsea wellbore drilling system for reducing bottom hole pressure |
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US32379701P | 2001-09-20 | 2001-09-20 | |
US10/094,208 US6648081B2 (en) | 1998-07-15 | 2002-03-08 | Subsea wellbore drilling system for reducing bottom hole pressure |
US10/191,152 US7270185B2 (en) | 1998-07-15 | 2002-07-09 | Drilling system and method for controlling equivalent circulating density during drilling of wellbores |
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