The present disclosure relates to well control fluids in wellbore testing operations, and more particularly to treating a fractured wellbore with a well control fluid.
Well control fluid, such as kill weight fluid, can be used in wellbore testing operations to reduce permeability of an accidentally fractured formation, for example, by plugging fractures in the wellbore to restrict fluid loss out of the wellbore. Sometimes, the well control fluid is a dense, thick-gel solution that is pumped through a testing string of a well system to a downhole location proximate the formation fractures to slow fluid flow through the formation fractures. Well control fluids often vary in viscosity, and are selected based on their viscosity and on pressure data collected during well testing operations.
Like reference symbols in the various drawings indicate like elements.
A well string 22 is shown as having been lowered from the surface 16 into the wellbore 12. In some instances, the well string 22 is a series of jointed lengths of tubing coupled together end-to-end and/or a continuous (i.e., not jointed) coiled tubing. The well string 22 can include a well testing string with one or more well tools, including a downhole testing assembly 24. The downhole testing assembly 24 can include, for example, a wellbore testing tool. Testing fluid, well control fluid, and/or other types of fluid can be communicated to the downhole testing assembly 24 from a testing fluid source 26 at a surface location of the well. The testing fluid source 26 is fluidly coupled to the downhole testing assembly 24, for example, via the well string 22. In the example well system 10, the wellbore 12 is completing a drill stem test (DST), where the wellbore 12 has been accidentally fractured and is experiencing fluid ingress from the formation into the wellbore 12.
The well control fluid 118 has a particular rheological property (e.g., specified viscosity) adjustable by the electric field, magnetic field, and/or other potential applied by the electrodes 112 of in the upper housing 106. For example, the well control fluid 118 can include a ferrofluid, a ferrofluid additive, a chemical sealant, a gel, and/or another type of fluid that, for example, becomes more viscous (or less viscous) based at least in part on a magnitude of an applied electric field, magnetic field, and/or other potential on the well control fluid 118. In some instances, the well control fluid 118 is pumped through the well string 110 to the wellbore testing tool 100 at a first viscosity (e.g., a low viscosity), and introduced to an electric field, magnetic field, or other potential via the electrodes 112 in the upper housing 106 in order to retain a second, higher viscosity to restrict fluid flow (e.g., fluid ingress) through the fractures 104 in the wellbore 102. In certain instances, the well control fluid 118 at the second, higher viscosity maintains a pressure in the wellbore 102 below a fluid ejection threshold. The fluid ejection threshold, for example, is a pressure threshold that retains fluid in the wellbore 102 from ejecting the wellbore 102 at a surface of the well. In other words, the well control fluid 118 at the second, higher viscosity can help balance a fluidic pressure in the wellbore 102 such that fluid ingress through the fractures 104 does not increase wellbore pressure greater than a hydrostatic head of the wellbore 102 can maintain. In some examples, the well control fluid 118 at the second, higher viscosity is denser than fluid entering the wellbore during fluid ingress, for example, such that the well control fluid 118 restricts the fluid from entering the wellbore through a formation fracture. In certain instances, pumping the well control fluid 118 at the first viscosity through the well string 110 is easier than pumping the well control fluid 118 at the second, higher viscosity through the well string 110.
In some instances, a magnitude of the electric field, magnetic field, and/or other potential applied by the electrodes 112 can be adjusted (e.g., in real time) to effect a third viscosity of the well control fluid 118. For example, a magnitude of the electric field, magnetic field, and/or other potential can be increased to effect a third viscosity of the well control fluid 118 that is greater than the second viscosity. Increasing the viscosity of the well control fluid 118 can, in some instances, more effectively slow or stop fluid loss and/or fluid ingress though the fractures 104 of the wellbore 102. For example, when the electric field, magnetic field, and/or other potential causes the well control fluid 118 to take on the second viscosity but there is still significant fluid loss or fluid ingress through the fractures 104 in the wellbore 102, the magnitude of the electric field, magnetic field, and/or other potential may be increased to effect the increased third viscosity of the well control fluid 118. In some examples, the magnitude of the electric field, magnetic field, and/or other potential can be decreased from the second viscosity to an intermediate viscosity that is between the first viscosity and the second, higher viscosity. For example, when the well control fluid 118 takes on the second viscosity, the well control fluid 118 may cause new fractures and/or expand the existing fractures 104 in the wellbore 102. Therefore, the magnitude of the electric field, magnetic field, and/or other potential can, in some instances, be reduced to decrease the viscosity of the control fluid to the intermediate viscosity, for example, to avoid additional or expanded wellbore formation fractures.
Activation of the electrodes 112 to apply the electric field, magnetic field, and/or other potential on the well control fluid 118 can vary. In some instances, activation of the electrodes 112 is like an on-off switch. For example, the electrodes 112 can be activated by communicating power to the electrodes from the power source 114 based on well operator commands (e.g., via telemetry, wired, wireless, and/or other communication), a rupture disk or other pressure-sensitive device responsive to a specified downhole pressure, an in-well hydrocarbon detection sensor responsive to hydrocarbon presence in the wellbore, and/or other. In certain instances, a well operator can control the magnitude of the electric field, magnetic field, and/or other potential via commands from a well control station at a surface of the well communicated via telemetric communications link, wired connection, wireless connection, a combination of these, and/or other.
In view of the discussion above, certain aspects encompass a method including introducing a well control fluid at a first viscosity into a downhole portion of a wellbore, where the well control fluid includes an electrorheological or magnetorheological fluid. In response to a wellbore inflow condition, the method includes activating the well control fluid to change the viscosity of the well control fluid to a second, higher viscosity.
Certain aspects encompass a method including introducing a well control fluid with an adjustable rheological property into a downhole portion of a wellbore, where the well control fluid has a first rheological characteristic. In response to fluid entering the wellbore through a formation fracture in the wellbore, the method includes activating the well control fluid to adjust the adjustable rheological property of the well control fluid to retain a second, different rheological characteristic, and where the well control fluid with the second rheological characteristic is denser than the fluid entering the wellbore through the formation fracture.
Certain aspects encompass a method including, during testing of a wellbore, ceasing unintended fluid inflow into the wellbore by electrically or magnetically activating a well control fluid in the wellbore. In response to electrically or magnetically activating the well control fluid, the method includes monitoring a pressure in the wellbore.
The aspects above can include some, none, or all of the following features. The wellbore inflow condition includes fluid entering the wellbore through a hydraulically induced formation fracture in the wellbore. Activating the well control fluid includes activating one of an electric field or a magnetic field on the well control fluid. The method includes increasing a magnitude of the electric field or magnetic field on the well control fluid to effect a third viscosity of the well control fluid that is greater than the second viscosity. The method includes decreasing a magnitude of the electric field or magnetic field on the well control fluid to effect a third viscosity of the well control fluid, where the third viscosity is greater than the first viscosity and less than the second, higher viscosity. Introducing a well control fluid at a first viscosity into a downhole portion of a wellbore includes pumping a ferrofluid at a first viscosity into a downhole portion of a wellbore. Activating the well control fluid includes activating an in-well electric field source or magnetic field source adjacent the wellbore inflow condition. Activating an electric field source or magnetic field source comprises activating electrodes in a well testing string. Activating an electric field source or magnetic field source includes providing power to the electric field source or magnetic field source via an in-well battery. Activating an electric field source or magnetic field source includes rupturing a rupture disk in response to a specified downhole pressure to allow an electric field or magnetic field to activate the well control fluid. The method includes deactivating the well control fluid to return the viscosity of the well control fluid to the first viscosity prior to circulating the well control fluid out of the wellbore. The method includes pressurizing the wellbore to a specified well test pressure and fracturing the wellbore causing the wellbore inflow condition. The method includes maintaining a pressure in the wellbore below a fluid ejection threshold in response to the wellbore inflow condition. The adjustable rheological property of the well control fluid is viscosity of the well control fluid, the first rheological characteristic is a first viscosity, and the second, different rheological property is a second, higher viscosity. The method includes deactivating the well control fluid to return the adjustable rheological property of the well control fluid to retain the first rheological characteristic. Activating the well control fluid to adjust the adjustable rheological property of the well control fluid includes activating one of an electric field or magnetic field on the well control fluid to retain the second, different rheological characteristic. Unintended fluid inflow includes fluid entering the wellbore through a hydraulically induced formation fracture in the wellbore.
A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made. Accordingly, other embodiments are within the scope of the following claims.
Filing Document | Filing Date | Country | Kind |
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PCT/US2014/060960 | 10/16/2014 | WO | 00 |