EP2564016B1

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Info

Publication number: EP2564016B1
Application number: EP10850856.5A
Authority: EP
Inventors: James R. Lovorn; Emad Barki; Jay K. Turner; Ryan G. Ezell
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2010-04-27
Filing date: 2010-04-27
Publication date: 2016-06-08
Anticipated expiration: 2030-04-27
Also published as: CA2795910C; BR112012026845B1; WO2011136761A1; AU2010352027B2; EP2564016A1; MX2012012385A; SG184922A1; BR112012026845A2; EP2564016A4; AU2010352027A1; CA2795910A1

Description

TECHNICAL FIELD

The present disclosure relates generally to equipment and fluids utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides for wellbore pressure control with segregated fluid columns.

BACKGROUND

In underbalanced and managed pressure drilling and completion operations, it is beneficial to be able to maintain precise control over pressures and fluids exposed to drilled-through formations and zones. In the past, specialized equipment (such as downhole deployment valves, snubbing units, etc.) have been utilized to provide for pressure control in certain situations (such as, when tripping pipe, running casing or liner, wireline logging, installing completions, etc.)
However, this specialized equipment (like most forms of equipment) is subject to failure, can be time-consuming and expensive to install and operate, and may not be effective in certain operations. For example, downhole deployment valves have been known to leak and snubbing units are ineffective to seal about slotted liners.
Therefore, it will be appreciated that improvements are needed in the art of wellbore pressure control. These improvements could be used in conjunction with conventional equipment (such as downhole deployment valves, snubbing units, etc.), or they could be substituted for such conventional equipment. The improvements could be used in underbalanced and managed pressure drilling and completion operations, and/or in other types of well operations.
DocumentUS 2006/272860 A1 discloses methods for improving the pressure containment integrity of subterranean well bores.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic partially cross-sectional view of a well system and associated method which can embody principles of the present disclosure.
FIG. 2 is a schematic view of a pressure and flow control system which may be used with the well system and method ofFIG. 1.
FIG.3 is a schematic cross-sectional view of the well system in which initial steps of the method have been performed.
FIG. 4 is a schematic cross-sectional view of the well system in which further steps of the method have been performed.
FIG. 5 is a schematic view of a flowchart for the method.

DETAILED DESCRIPTION

Representatively and schematically illustrated inFIG. 1 is awell system 10 and associated method which can embody principles of the present disclosure. In thesystem 10, awellbore 12 is drilled by rotating adrill bit 14 on an end of atubular string 16.
Drillingfluid 18, commonly known as mud, is circulated downward through thetubular string 16, out thedrill bit 14 and upward through anannulus 20 formed between the tubular string and thewellbore 12, in order to cool the drill bit, lubricate the tubular string, remove cuttings and provide a measure of bottom hole pressure control. A non-return valve 21 (typically a flapper-type check valve) prevents flow of thedrilling fluid 18 upward through the tubular string 16 (e.g., when connections are being made in the tubular string).
Control of bottom hole pressure is very important in managed pressure and underbalanced drilling, and in other types of well operations. Preferably, the bottom hole pressure is accurately controlled to prevent excessive loss of fluid into anearth formation 64 surrounding thewellbore 12, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc.
In typical managed pressure drilling, it is desired to maintain the bottom hole pressure just greater than a pore pressure of theformation 64, without exceeding a fracture pressure of the formation. In typical underbalanced drilling, it is desired to maintain the bottom hole pressure somewhat less than the pore pressure, thereby obtaining a controlled influx of fluid from theformation 64.
Nitrogen or another gas, or another lighter weight fluid, may be added to thedrilling fluid 18 for pressure control. This technique is especially useful, for example, in underbalanced drilling operations.
In thesystem 10, additional control over the bottom hole pressure is obtained by closing off the annulus 20 (e.g., isolating it from communication with the atmosphere and enabling the annulus to be pressurized at or near the surface) using a rotating control device 22 (RCD). The RCD 22 seals about thetubular string 16 above awellhead 24. Although not shown inFIG. 1, thetubular string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), astandpipe line 26, kelley (not shown), a top drive and/or other conventional drilling equipment.
Thedrilling fluid 18 exits thewellhead 24 via awing valve 28 in communication with theannulus 20 below the RCD 22. Thefluid 18 then flows throughfluid return line 30 to achoke manifold 32, which includesredundant chokes 34. Backpressure is applied to theannulus 20 by variably restricting flow of thefluid 18 through the operative choke(s) 34.
The greater the restriction to flow through thechoke 34, the greater the backpressure applied to theannulus 20. Thus, bottom hole pressure can be conveniently regulated by varying the backpressure applied to theannulus 20. A hydraulics model can be used, as described more fully below, to determine a pressure applied to theannulus 20 at or near the surface which will result in a desired bottom hole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired bottom hole pressure.
Pressure applied to theannulus 20 can be measured at or near the surface via a variety ofpressure sensors 36, 38, 40, each of which is in communication with the annulus.Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP)stack 42.Pressure sensor 38 senses pressure in the wellhead below theBOP stack 42.Pressure sensor 40 senses pressure in thefluid return line 30 upstream of thechoke manifold 32.
Anotherpressure sensor 44 senses pressure in thestandpipe line 26. Yet anotherpressure sensor 46 senses pressure downstream of thechoke manifold 32, but upstream of aseparator 48,shaker 50 andmud pit 52. Additional sensors includetemperature sensors 54, 56, Coriolisflowmeter 58, andflowmeters 62, 66.
Not all of these sensors are necessary. For example, thesystem 10 could include only one of theflowmeters 62, 66. However, input from the sensors is useful to the hydraulics model in determining what the pressure applied to theannulus 20 should be during the drilling operation.
In addition, thetubular string 16 may include itsown sensors 60, for example, to directly measure bottom hole pressure.Such sensors 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD) sensor systems. These tubular string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of tubular string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements. Various forms of telemetry (acoustic, pressure pulse, electromagnetic, optical, wired, etc.) may be used to transmit the downhole sensor measurements to the surface.
Additional sensors could be included in thesystem 10, if desired. For example,another flowmeter 67 could be used to measure the rate of flow of thefluid 18 exiting thewellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of arig mud pump 68, etc.
Fewer sensors could be included in thesystem 10, if desired. For example, the output of therig mud pump 68 could be determined by counting pump strokes, instead of by usingflowmeter 62 or any other flowmeters.
Note that theseparator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, theseparator 48 is not necessarily used in thesystem 10.
Thedrilling fluid 18 is pumped through thestandpipe line 26 and into the interior of thetubular string 16 by therig mud pump 68. Thepump 68 receives thefluid 18 from themud pit 52 and flows it via a standpipe manifold (not shown) to thestandpipe line 26, the fluid then circulates downward through thetubular string 16, upward through theannulus 20, through themud return line 30, through thechoke manifold 32, and then via theseparator 48 and shaker 50 to themud pit 52 for conditioning and recirculation.
Note that, in thesystem 10 as so far described above, thechoke 34 cannot be used to control backpressure applied to theannulus 20 for control of the bottom hole pressure, unless thefluid 18 is flowing through the choke. In conventional overbalanced drilling operations, a lack of circulation can occur whenever a connection is made in the tubular string 16 (e.g., to add another length of drill pipe to the tubular string as thewellbore 12 is drilled deeper), and the lack of circulation will require that bottom hole pressure be regulated solely by the density of thefluid 18.
In thesystem 10, however, flow of thefluid 18 through thechoke 34 can be maintained, even though the fluid does not circulate through thetubular string 16 andannulus 20. Thus, pressure can still be applied to theannulus 20 by restricting flow of thefluid 18 through thechoke 34.
In thesystem 10 as depicted inFIG. 1, abackpressure pump 70 can be used to supply a flow of fluid to thereturn line 30 upstream of thechoke manifold 32 by pumping fluid into theannulus 20 when needed. Alternatively, or in addition, fluid could be diverted from the standpipe manifold to thereturn line 30 when needed, as described inInternational Application Serial No. PCT/US08/87686, and inUS Application Serial No. 12/638,012. Restriction by thechoke 34 of such fluid flow from therig pump 68 and/or thebackpressure pump 70 will thereby cause pressure to be applied to theannulus 20.
Although the example ofFIG. 1 is depicted as if a drilling operation is being performed, it should be clearly understood that the principles of this disclosure may be utilized in a variety of other well operations. For example, such other well operations could include completion operations, logging operations, casing operations, etc.
Thus, it is not necessary for thetubular string 16 to be a drill string, or for the fluid 18 to be a drilling fluid. For example, the fluid 18 could instead be a completion fluid or any other type of fluid.
Accordingly, it will be appreciated that the principles of this disclosure are not limited to drilling operations and, indeed, are not limited at all to any of the details of thesystem 10 described herein and/or illustrated in the accompanying drawings.
A pressure and flowcontrol system 90 which may be used in conjunction with thesystem 10 and method ofFIG. 1 is representatively illustrated inFIG. 2. Thecontrol system 90 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.
Thecontrol system 90 includes ahydraulics model 92, a data acquisition andcontrol interface 94 and a controller 96 (such as, a programmable logic controller or PLC, a suitably programmed computer, etc.). Although theseelements 92, 94, 96 are depicted separately inFIG. 2, any or all of them could be combined into a single element, or the functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided, etc.
Thehydraulics model 92 is used in thecontrol system 90 to determine the desired annulus pressure at or near the surface to achieve the desired bottom hole pressure. Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by thehydraulics model 92 in making this determination, as well as real-time sensor data acquired by the data acquisition andcontrol interface 94.
Thus, there is a continual two-way transfer of data and information between thehydraulics model 92 and the data acquisition andcontrol interface 94. Preferably, the data acquisition andcontrol interface 94 operates to maintain a substantially continuous flow of real-time data from thesensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 to thehydraulics model 92, so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure. Thehydraulics model 92 operates to supply the data acquisition andcontrol interface 94 substantially continuously with a value for the desired annulus pressure.
A greater or lesser number of sensors may provide data to theinterface 94, in keeping with the principles of this disclosure. For example, flow rate data from aflowmeter 72 which measures an output of thebackpressure pump 70 may be input to theinterface 94 for use in thehydraulics model 92.
A suitable hydraulics model for use as thehydraulics model 92 in thecontrol system 90 is REAL TIME HYDRAULICS (TM) provided by Halliburton Energy Services, Inc. of Houston, Texas USA. Another suitable hydraulics model is provided under the trade name IRIS (TM), and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in thecontrol system 90 in keeping with the principles of this disclosure.
A suitable data acquisition and control interface for use as the data acquisition andcontrol interface 94 in thecontrol system 90 are SENTRY (TM) and INSITE (TM) provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in thecontrol system 90 in keeping with the principles of this disclosure.
Thecontroller 96 operates to maintain a desired setpoint annulus pressure by controlling operation of thefluid return choke 34 and/or thebackpressure pump 70. When an updated desired annulus pressure is transmitted from the data acquisition andcontrol interface 94 to thecontroller 96, the controller uses the desired annulus pressure as a setpoint and controls operation of thechoke 34 in a manner (e.g., increasing or decreasing flow through the choke as needed) to maintain the setpoint pressure in theannulus 20.
This is accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of thesensors 36, 38, 40), and increasing flow through thechoke 34 if the measured pressure is greater than the setpoint pressure, and decreasing flow through the choke if the measured pressure is less than the setpoint pressure. Of course, if the setpoint and measured pressures are the same, then no adjustment of thechoke 34 is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used if desired.
Thecontroller 96 may also be used to control operation of thebackpressure pump 70. Thecontroller 96 can, thus, be used to automate the process of supplying fluid flow to thereturn line 30 when needed. Again, no human intervention may be required for this process.
Referring additionally now toFIG. 3, a somewhat enlarged scale view of a portion of thewell system 10 is representatively illustrated apart from the remainder of the system depicted inFIG. 1. In theFIG. 3 illustration, both cased 12a and uncased 12b portions of thewellbore 12 are visible.
In the example ofFIG. 3, it is desired to trip thetubular string 16 out of thewellbore 12, for example, to change thebit 14, install additional casing, install a completion assembly, perform a logging operation, etc. However, it is also desired to prevent excessively increased pressure from being applied to theuncased portion 12b of the wellbore exposed to the formation 64 (which could result in skin damage to the formation, fracturing of the formation, etc.), to prevent excessively reduced pressure from being exposed to the uncased portion of the wellbore (which could result in an undesired influx of fluid into the wellbore, instability of the wellbore, etc.), to prevent any gas in the fluid 18 from migrating upwardly through the wellbore, and to prevent other fluids (such as higher density fluids) from contacting the exposed formation.
In one unique feature of the example depicted inFIG. 3, thetubular string 16 is partially withdrawn from the wellbore 12 (e.g., raised in the vertical wellbore shown inFIG. 3) and abarrier substance 74 is placed in the wellbore. Thebarrier substance 74 may be flowed into thewellbore 12 by circulating it through thetubular string 16 and into theannulus 20, or the barrier substance could be placed in the wellbore by other means (such as, via another tubular string installed in the wellbore, by circulating the barrier substance downward through the annulus, etc.).
As illustrated inFIG. 3, thebarrier substance 74 is placed in thewellbore 12 so that it traverses the junction between thecased portion 12a anduncased portion 12b of the wellbore (i.e., at a casing shoe 76). However, in other examples, thebarrier substance 74 could be placed entirely in the casedportion 12a or entirely in theuncased portion 12b of thewellbore 12.
Thebarrier substance 74 is preferably of a type which can isolate the fluid 18 exposed to theformation 64 from other fluids in thewellbore 12. However, thebarrier substance 74 also preferably transmits pressure, so that control over pressure in the fluid 18 exposed to theformation 64 can be accomplished using thecontrol system 90.
To isolate the fluid 18 exposed to theformation 64 from other fluids in thewellbore 12, thebarrier substance 74 is preferably a highly viscous fluid, a highly thixotropic gel or a high strength gel which sets in the wellbore. However, thebarrier substance 74 could be (or comprise) other types of materials in keeping with the principles of this disclosure.
One suitable highly thixotropic gel for use as thebarrier substance 74 is N-SOLATE (TM) provided by Halliburton Energy Services, Inc. A suitable preparation is as follows:

N-SOLATE(TM)Base A base fluid (glycerol) - 1.9971 kg/m³ (0.70 lb/bbl)
Water (freshwater) - 0.8559 kg/m³ (0.30 lb/bbl)
N-SOLATE (TM)600 Vis viscosifier - 28.53 kg/m³ (10.0 lb/bbl)

One suitable high strength gel for use as thebarrier substance 74 may be prepared as follows:

N-SOLATE (TM) Base A base fluid (glycerol) - 2.08269 kg/m³ (0.73 lb/bbl)
N-SOLATE (TM)275 Vis viscosifier - 0.42795 kg/m³ (0.15 lb/bbl)
N-SOLATE (TM)275 x-link cross linker - 0.11412 kg/m³ (0.04 lb/bbl)
Water (freshwater) - 0.22824 kg/m³ (0.08 lb/bbl)

Of course, a wide variety of different formulations may be used for thebarrier substance 74. The above are only two such formulations, and it should be clearly understood that the principles of this disclosure are not limited at all to these formulations.
Referring additionally now toFIG. 4, thesystem 10 is representatively illustrated after thebarrier substance 74 has been placed in thewellbore 12 and thetubular string 16 has been further partially withdrawn from the wellbore. Another fluid 78 is then flowed into thewellbore 12 on an opposite side of thebarrier substance 74 from the fluid 18.
The fluid 78 preferably has a density greater than a density of the fluid 18. By flowing the fluid 78 into thewellbore 12 above thebarrier substance 74 and the fluid 18, a desired pressure can be maintained in the fluid 18 exposed to theformation 64, as thetubular string 16 is tripped out of and back into the wellbore, as a completion assembly is installed, as a logging operation is performed, as casing is installed, etc.
The density of the fluid 78 is selected so that, after it is flowed into the wellbore 12 (e.g., filling the wellbore from thebarrier substance 74 to the surface), an appropriate hydrostatic pressure will be thereby applied to the fluid 18 exposed to theformation 64. Preferably, at any selected location along theuncased portion 12b of thewellbore 12, the pressure in the fluid 18 will be equal to, or only marginally greater than (e.g., no more than approximately 689475 N/m² (100 psi) greater than), pore pressure in theformation 64. However, other pressures in the fluid 18 may be used in other examples.
While thebarrier substance 74 is being placed in thewellbore 12, and while the fluid 78 is being flowed into the wellbore, thecontrol system 90 preferably maintains the pressure in the fluid 18 exposed to theformation 64 substantially constant (e.g., varying no more than a few psi). Thecontrol system 90 can achieve this result by automatically adjusting thechoke 34 as fluid exits theannulus 20 at the surface, as described above, so that an appropriate backpressure is applied to the annulus at the surface to maintain a desired pressure in the fluid 18 exposed to theformation 64.
Note that, since different density substances (e.g.,barrier substance 74 and fluid 78) are being introduced into thewellbore 12, the annulus pressure setpoint will vary as the substances are introduced into the wellbore. Preferably, the density of the fluid 78 is selected so that, upon completion of the step of flowing the fluid 78 into thewellbore 12, no pressure will need to be applied to theannulus 20 at the surface in order to maintain the desired pressure in the fluid 18 exposed to theformation 64.
In this manner, a snubbing unit will not be necessary for subsequent well operations (such as, running casing, installing a completion assembly, wireline or coiled tubing logging, etc.). However, a snubbing unit may be used, if desired.
Preferably, thebarrier fluid 74 will prevent mixing of thefluids 18, 78, will isolate the fluids from each other, will prevent migration ofgas 80 upward through thewellbore 12, and will transmit pressure between the fluids. Consequently, excessively increased pressure in theuncased portion 12b of the wellbore exposed to the formation 64 (which could otherwise result from opening a downhole deployment valve, etc.) can be prevented, excessively reduced pressure can be prevented from being exposed to the uncased portion of the wellbore, gas in the fluid 18 can be prevented from migrating upwardly through the wellbore to the surface, and fluids (such as higher density fluids) other than the fluid 18 can be prevented from contacting the exposed formation.
Referring additionally now toFIG. 5, a flowchart for one example of amethod 100 of controlling pressure in thewellbore 12 is representatively illustrated. Themethod 100 may be used in conjunction with thewell system 10 described above, or the method may be used with other well systems.
In aninitial step 102 of themethod 100, a first fluid (such as the fluid 18) is present in thewellbore 12. As in thesystem 10, the fluid 18 could be a drilling fluid which is specially formulated to exert a desired hydrostatic pressure, prevent fluid loss to theformation 64, lubricate thebit 14, enhance wellbore stability, etc. In other examples, the fluid 18 could be a completion fluid or another type of fluids.
The fluid 18 may be circulated through thewellbore 12 during drilling or other operations. Various means (e.g.,tubular string 16, a coiled tubing string, etc.) may be used to introduce the fluid 18 into the wellbore, in keeping with the principles of this disclosure.
In asubsequent step 104 of themethod 100, pressure in the fluid 18 exposed to theformation 64 is adjusted, if desired. For example, if prior to beginning the procedure depicted inFIG. 5, an underbalanced drilling operation was being performed, then it may be desirable to increase the pressure in the fluid 18 exposed to theformation 64, so that the pressure in the fluid is equal to, or marginally greater than, pore pressure in the formation.
In this manner, an influx of fluid from theformation 64 into thewellbore 12 can be avoided during the remainder of themethod 100. Of course, if the pressure in the fluid 18 exposed to theformation 64 is already at a desired level, then thisstep 104 is not necessary.
Instep 106 of themethod 100, thetubular string 16 is partially withdrawn from thewellbore 12. This places a lower end of thetubular string 16 at a desired lower extent of thebarrier substance 74, as depicted inFIG. 3.
If the lower end of the tubular string 16 (or another tubular string used to place the barrier substance 74) was not previously below the desired lower extent of the barrier substance, then "partially withdrawing" the tubular string can be taken to mean, "placing the lower end of the tubular string at a desired lower extent of thebarrier substance 74." For example, a coiled tubing string could be installed in thewellbore 12 for the purpose of placing thebarrier substance 74 above the fluid 18 exposed to theformation 64, in which case the coiled tubing string could be considered "partially withdrawn" from the wellbore, in that its lower end would be positioned at a desired lower extent of the barrier substance.
Instep 108 of themethod 100, thebarrier substance 74 is placed in thewellbore 12. As described above, the barrier substance could be flowed through thetubular string 16, flowed through theannulus 20 or placed in the wellbore by any other means.
Instep 110 of themethod 100, thetubular string 16 is again partially withdrawn from thewellbore 12. This time, the lower end of thetubular string 16 is positioned at a desired lower extent of the fluid 78. In thisstep 110, "partially withdrawing" can be taken to mean, "positioning a lower end of the tubular string at a desired lower extent of the fluid 78."
Instep 112 of themethod 100, thesecond fluid 78 is flowed into thewellbore 12. As described above, the fluid 78 has a selected density, so that a desired pressure is applied to the fluid 18 by the column of the fluid 78 thereabove. It is envisioned that, in most circumstances of underbalanced and managed pressure drilling, the density of the fluid 78 will be greater than the density of the fluid 18 (so that the pressure in the fluid 18 is equal to or marginally greater than the pressure in the formation 64), but in other examples the density of the fluid 78 could be equal to, or less than, the density of the fluid 18.
Instep 114 of themethod 100, a well operation is performed at the conclusion of the procedure depicted inFIG. 5. The well operation could be any type, number and/or combination of well operation(s) including, but not limited to, drilling operation(s), completion operation(s), logging operation(s), installation of casing, etc. Preferably, due to the unique features of the system and method described herein, such operation(s) can be performed without use of a downhole deployment valve or a surface snubbing unit, but those types of equipment may be used, if desired, in keeping with the principles of this disclosure.
Throughout themethod 100, and as indicated bysteps 116 and 118 inFIG. 5, thehydraulics model 92 produces a desired surface annulus pressure setpoint as needed to maintain a desired pressure in the fluid 18 exposed to theformation 64, and thecontroller 96 automatically adjusts thechoke 34 as needed to achieve the surface annulus pressure setpoint. The surface annulus pressure setpoint can change during themethod 100.
For example, if the fluid 78 has a greater density than the fluid 18 instep 112, then the surface annulus pressure setpoint may decrease as the fluid 78 is flowed into thewellbore 12. As another example, instep 104, the surface annulus pressure setpoint may be increased if thewellbore 12 was previously being drilled underbalanced, and it is now desired to increase the pressure in the fluid 18 exposed to theformation 64, so that it is equal to or marginally greater than pressure in the formation.
Note that, although in the above description only thefluids 18, 78 are indicated as being segregated by thebarrier substance 74, in other examples more than one fluid could be exposed to theformation 64 below the barrier substance and/or more than one fluid may be positioned between the barrier substance and the surface. In addition, more than onebarrier substance 74 and/or barrier substance location could be used in thewellbore 12 to thereby segregate any number of fluids.
It may now be fully appreciated that the above description of the various examples of thewell system 10 andmethod 100 provides several advancements to the art of wellbore pressure control. Pressure applied to a formation by fluid in a wellbore intersecting the formation can be precisely controlled and the fluid exposed to the formation during various well operations can be optimized, thereby preventing damage to the formation, loss of fluids to the formation, undesired influx of fluids from the formation, etc.
The above disclosure describes amethod 100 of controlling pressure in awellbore 12. Themethod 100 can include placing abarrier substance 74 in thewellbore 12 while afirst fluid 18 is present in the wellbore, and flowing asecond fluid 78 into thewellbore 12 while thefirst fluid 18 and thebarrier substance 74 are in the wellbore. The first andsecond fluids 18, 78 may have different densities.
Thebarrier substance 74 may isolate the first fluid 18 from thesecond fluid 78, may prevent upward migration ofgas 80 in the wellbore and/or may prevent migration ofgas 80 from thefirst fluid 18 to thesecond fluid 78.
Thebarrier substance 74 may comprises a thixotropic gel and/or a gel which sets in thewellbore 12. Thebarrier substance 74 may have a viscosity greater than viscosities of the first andsecond fluids 18, 78.
Placing thebarrier substance 74 in thewellbore 12 can include automatically controlling afluid return choke 34, whereby pressure in thefirst fluid 18 is maintained substantially constant. Similarly, flowing thesecond fluid 78 into thewellbore 12 can include automatically controlling thefluid return choke 34, whereby pressure in thefirst fluid 18 is maintained substantially constant.
Thesecond fluid 78 density may be greater than thefirst fluid 18 density. Pressure in thefirst fluid 18 may remain substantially constant while the greater densitysecond fluid 78 is flowed into thewellbore 12.
Also described by the above disclosure is amethod 100 of controlling pressure in awellbore 12, with the method including: circulating afirst fluid 18 through atubular string 16 and anannulus 20 formed between thetubular string 16 and thewellbore 12; then partially withdrawing thetubular string 16 from thewellbore 12; then placing abarrier substance 74 in thewellbore 12; then further partially withdrawing thetubular string 16 from thewellbore 12; and then flowing asecond fluid 78 into thewellbore 12.
Pressure in thefirst fluid 18 may be maintained substantially constant during placing thebarrier substance 74 in thewellbore 12 and/or during flowing thesecond fluid 78 into the wellbore.
Themethod 100 can include, prior to placing thebarrier substance 74 in thewellbore 12, adjusting a pressure in thefirst fluid 18 exposed to aformation 64 intersected by thewellbore 12, whereby the pressure in thefirst fluid 18 at a selected location is approximately the same as, or marginally greater than, a pore pressure of theformation 64 at the selected location.
The above disclosure also provides to the art awell system 10. Thewell system 10 can include first andsecond fluids 18, 78 in awellbore 12, the first and second fluids having different densities, and abarrier substance 74 separating the first and second fluids.
It is to be understood that the various embodiments of the present disclosure described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
In the above description of the representative embodiments of the disclosure, directional terms, such as "above," "below," "upper," "lower," etc., are used for convenience in referring to the accompanying drawings. In general, "above," "upper," "upward" and similar terms refer to a direction toward the earth's surface along a wellbore, and "below," "lower," "downward" and similar terms refer to a direction away from the earth's surface along the wellbore.
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of the present disclosure.

Claims

A method of controlling pressure in a wellbore (12), the method comprising:
placing a barrier substance (74) in the wellbore (12) while a first fluid (18) is present in the wellbore; and
flowing a second fluid (78) into the wellbore (12) while the first fluid (18) and the barrier substance (74) are in the wellbore (12),characterized in that the second fluid (78) fills the wellbore from the barrier substance (74) to the surface, wherein the barrier substance (74) isolates the first fluid (18) from the second fluid (78) after the barrier substance (74) sets in the wellbore (12), and wherein the barrier substance transmits pressure between the first and second fluids after the barrier substance (74) sets in the wellbore (12), and wherein the first and second fluids have different densities.
A method according to claim 1, wherein the barrier substance (74) prevents upward migration of gas in the wellbore (12).
A method according to claim 1, wherein the barrier substance (74) prevents migration of gas from the first fluid (18) to the second fluid (78).
A method according to claim 1, wherein the barrier substance (74) comprises:
(a) a thixotropic gel; or
(b) a gel which sets in the wellbore (12).
A method according to claim 1, wherein the barrier substance (74) has a viscosity greater than viscosities of the first and second fluids.
A method according to claim 1, wherein the second fluid density is greater than the first fluid density, preferably wherein pressure in the first fluid (18) remains substantially constant while the greater density second fluid (78) is flowed into the wellbore (12).
A well system, comprising:
first and second fluids in a wellbore (12), and a barrier substance (74) separating the first and second fluids,characterised in that the second fluid (78) fills the wellbore from the barrier substance (74) to the surface, wherein the barrier substance (74) isolates the first fluid (18) from the second fluid (78) after the barrier substance (74) sets in the wellbore (12), and wherein the barrier substance transmits pressure between the first and second fluids after the barrier substance (74) sets in the wellbore (12), and wherein the first and second fluids have different densities.
A well system according to claim 7, wherein the barrier substance (74) prevents upward migration of gas in the wellbore (12).
A well system according to claim 7, wherein the barrier substance (74) prevents migration of gas from the first fluid (18) to the second fluid (78).
A well system according to claim 7, wherein the barrier substance (74) comprises:
(a) a thixotropic gel; or
(b) a gel which sets in the wellbore (12).
A well system according to claim 7, wherein the barrier substance (74) has a viscosity greater than viscosities of the first and second fluids.