SENSOR AND ACTUATOR FOR AUTONOMOUSLY DETECTING WELLBORE FLUIDS AND CLOSING FLUID PATH

TECHNICAL FIELD

The field relates to a sensor used to detect the presence of different types of fluids in a reverse cementing operation. The sensor can be a resistivity sensor. When cement is detected by the sensor, an actuator can close a valve that closes a fluid flow path.

BRIEF DESCRIPTION OF THE FIGURES

The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.

FIG. 1 illustrates a system for preparation and delivery of a cement composition to a wellbore according to certain embodiments.

FIG. 2A illustrates surface equipment that may be used in placement of a cement composition into a wellbore.

FIG. 2B illustrates placement of a cement composition into an annulus of a wellbore for a reverse cementing operation.

FIG. 3 illustrates a reverse cementing sensor device located inside a casing string to detect different types of wellbore fluids according to certain embodiments.

FIG. 4 illustrates a resistivity measurement apparatus according to certain embodiments.

FIG. 5 is a graph of resistivity in Ω-m versus time in seconds for an oil-based drilling fluid and a synthetic-based drilling fluid.

FIG. 6 is a graph of resistivity in Ω-m versus time in seconds for 3 different water-based drilling fluids.

FIG. 7 is a graph of resistivity in Ω-m versus time in seconds for 2 different spacer fluids.

FIG. 8 is a graph of resistivity in Ω-m versus time in seconds for 3 different cement compositions.

FIG. 9 illustrates 2 different resistivity profiles for different wellbore fluids.

FIG. 10 is a graph of resistivity in Ω-m versus cement percentage.

DETAILED DESCRIPTION

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid.

As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. A homogenous fluid has only one phase; whereas a heterogeneous fluid has more than one distinct phase. A colloid is an example of a heterogeneous fluid. A heterogeneous fluid can be: a slurry, which includes a continuous liquid phase and undissolved solid particles as the dispersed phase; an emulsion, which includes a continuous liquid phase and at least one dispersed phase of immiscible liquid droplets; a foam, which includes a continuous liquid phase and a gas as the dispersed phase; or a mist, which includes a continuous gas phase and liquid droplets as the dispersed phase. As used herein, the term “base fluid” means the solvent of a solution or the continuous phase of a heterogeneous fluid and is the liquid that is in the greatest percentage by volume of a fluid.

A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a subterranean formation” means and includes into any portion of the well, including into the wellbore, into the near-wellbore region via the wellbore, or into the subterranean formation via the wellbore.

A wellbore is formed using a drill bit. A drill string can be used to aid the drill bit in drilling through the subterranean formation to form the wellbore. The drill string can include a drilling pipe. During drilling operations, a drilling fluid, sometimes referred to as a drilling mud, may be circulated downwardly through the drilling pipe, and back up the annulus between the wellbore and the outside of the drilling pipe. The drilling fluid performs various functions, such as cooling the drill bit, maintaining the desired pressure in the well, and carrying drill cuttings upwardly through the annulus between the wellbore and the drilling pipe. A drilling fluid can include a base fluid of a hydrocarbon liquid (commonly referred to as an oil-based mud), a base fluid of a synthetic oil (commonly referred to as a synthetic-based mud), or a base fluid comprising water (commonly referred to as a water-based mud).

A portion of a wellbore can be an open hole or cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing string is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include but are not limited to: the space between the wall of the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wall of the wellbore and the outside of a casing string in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

During well completion, it is common to introduce a cement composition into an annulus in a wellbore. For example, in a cased-hole wellbore, a cement composition can be placed into and allowed to set in the annulus between the wall of the wellbore and the casing in order to stabilize and secure the casing in the wellbore. By cementing the casing in the wellbore, fluids are prevented from flowing into the annulus. Consequently, oil or gas can be produced in a controlled manner by directing the flow of oil or gas through the casing and into the wellhead. Cement compositions can also be used in primary or secondary cementing operations, well-plugging, or squeeze cementing.

As used herein, a “cement composition” is a mixture of at least cement and water. A cement composition can include additives. As used herein, the term “cement” means an initially dry substance that develops compressive strength or sets in the presence of water. Some examples of cements include, but are not limited to, Portland cements, gypsum cements, high alumina content cements, slag cements, high magnesia content cements, sorel cements, and combinations thereof. A cement composition is a heterogeneous fluid including water as the continuous phase of the slurry and the cement (and any other insoluble particles) as the dispersed phase. The continuous phase of a cement composition can include dissolved substances.

A spacer fluid can be introduced into the wellbore after the drilling fluid and before the cement composition. The spacer fluid can be circulated down through a casing string or tubing string and up through the annulus or down through the annulus and up through the casing or tubing string. The spacer fluid functions to remove the drilling fluid from the wellbore, so the cement composition encounters a better bonding surface. The spacer fluid pushes the drilling fluid through the wellbore, and a cement composition is then introduced after the spacer fluid.

A cement composition should remain pumpable during introduction into a wellbore. A cement composition will ultimately set after placement into the wellbore. As used herein, the term “set,” and all grammatical variations thereof, are intended to mean the process of becoming hard or solid by curing. As used herein, the “setting time” is the difference in time between when the cement and any other ingredients are added to the water and when the composition has set at a specified temperature. It can take up to 48 hours or longer for a cement composition to set.

Reverse cementing operations were developed to overcome some of the disadvantages to traditional cement operations. For example, in traditional cementing operations, the setting time of the cement composition needs to be longer in order for the cement slurry to remain pumpable as it travels through the casing or an inner tubing string and back up into the annulus before setting. Additionally, the amount of cement slurry that is pumped is generally greater than in reverse cementing because the cement composition must travel down through the casing and then back up into the annulus to fill the annulus. In reverse cementing by contrast, the cement slurry is pumped directly from the wellhead into the annulus instead of into the annulus via the casing string or tubing string—essentially cutting the amount of cement needed in half and shortening the setting time. Accordingly, reverse cementing generally requires a lower amount of the cement slurry, can have faster setting times because it takes less time to pump the cement into the annulus, and requires lower pump pressures because gravity assists the cement slurry in being placed in the annulus.

In all cementing operations, it is desirable to place the minimum amount of cement necessary to fill the portions of the annulus to be cemented. In traditional cementing, the amount of cement needed for the cementing operation can be estimated by the well geometry, and cement is pumped down the casing string with an excess amount. A cement plug can be placed behind the cement slurry column and will bump onto the casing shoe. An operator can tell by a pressure change observed at the wellhead that is caused by the cement plug reaching the casing shoe. The operator can then cease pumping of the cement composition into the casing string or tubing string. However, in reverse cementing operations, there are no visual observations that can be made to know when the cement composition has reached the bottom of the casing or tubing string and filled the annulus. Therefore, devices can be placed near the bottom of the casing or tubing string that can detect the presence of the cement composition.

Devices used to detect the presence of a cement composition can include a sensor. Generally, the sensor is connected to equipment at the wellhead that communicates with a readout device in order for an operator to monitor the measurements. By way of example, the sensor can be connected to equipment at the wellhead via wireline. An operator can monitor the readings from the sensor and cease pumping the cement composition when the readings indicate the presence of cement. However, wireline connections can be expensive and time-consuming.

Moreover, sensors placed on the outside of a casing or tubing string can be unpredictable and unreliable. After run-in, the longitudinal axis of the casing or tubing string is rarely perfectly centered inside the wellbore wall. Accordingly, one or more areas of the annulus will have a decreased volume compared to other areas of the annulus. Fluids pumped into the annulus have a turbulent flow and will also generally take the path of least resistance, which are the areas of the annulus that have the largest volume. Therefore, if a sensor is located on the outside of a casing string that is in a lower volume area of the annulus for example, then fluid may bypass the sensor and detection of the presence of the cement composition may be missed.

Thus, there is a need for improved sensors that can predictably and reliably detect the presence of a cement composition in a reverse cementing operation and overcome the aforementioned problems. It has been discovered that a resistivity sensor can be placed on the inside of a casing or tubing string. The resistivity sensor can be pre-programmed at the wellhead that corresponds to a unique and specific resistivity profile based on the exact composition of the fluids used. The resistivity sensor uses the pre-programmed resistivity profile to autonomously close a valve located within the casing or tubing string. When the valve closes, fluid flow up the casing or tubing string ceases and a change in pressure at the wellhead can be observed—thus, alerting an operator that the cement composition has filled the annulus and pumping can be stopped.

A reverse cementing sensor device can include a resistivity sensor, wherein the resistivity sensor is located on an inside of a casing string or tubing string; an acquisition and measurement apparatus configured to be pre-programmed with a resistivity profile and to receive readings from the resistivity sensor; an actuator configured to receive instructions from the acquisition and measurement apparatus; and a valve, wherein the valve is located inside of the casing string or tubing string, wherein the acquisition and measurement apparatus is configured send instructions to the actuator to close the valve after the resistivity sensor detects a resistivity of the pre-programmed resistivity profile.

Methods of detecting the presence of a cement composition in a reverse cementing operation in a wellbore can include introducing a sensor device into the wellbore, the sensor device comprising: a resistivity sensor; an acquisition and measurement apparatus configured to receive readings from the resistivity sensor; and an actuator configured to receive instructions from the acquisition and measurement apparatus; pre-programming the acquisition and measurement apparatus with a resistivity profile; introducing a first fluid into the wellbore; introducing a cement composition into an annulus of the wellbore; allowing the resistivity sensor to measure the resistivity of the first fluid and the cement composition; and allowing the acquisition and measurement apparatus to instruct the actuator to close a valve.

It is to be understood that the discussion of any of the embodiments regarding the sensor device is intended to apply to all of the apparatus and method embodiments. Any reference to the unit “gallons” means U.S. gallons.

FIG. 1 illustrates a system that can be used in the preparation of wellbore fluids and delivery to a wellbore according to any of the embodiments. Although the discussion below is in reference to a cement composition, it is to be understood that other wellbore fluids, for example a drilling fluid or spacer fluid, can be prepared and delivered as described. As shown, the cement composition can be mixed in mixing equipment 4, such as a jet mixer, re-circulating mixer, or a batch mixer, for example, and then pumped via pumping equipment 6 to the wellbore. The mixing equipment 4 and the pumping equipment 6 can be located on one or more cement trucks. A jet mixer can be used, for example, to continuously mix the cement composition, including water, as it is being pumped to the wellbore.

An example technique and system for introducing the cement composition into a subterranean formation will now be described with reference to FIGS. 2A and 2B. FIG. 2A illustrates surface equipment 10 that can be used to introduce the cement composition. It should be noted that while FIG. 2A generally depicts a land-based operation, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. The surface equipment 10 can include a cementing unit 12, which can include one or more cement trucks, mixing equipment 4, and pumping equipment 6 (e.g., as depicted in FIG. 1). The cementing unit 12 can pump the cement composition 14 through a feed pipe 16 and to a cementing head 18, which conveys the cement composition 14 downhole.

The methods include introducing a first fluid 44 into a wellbore. The first fluid can be a drilling fluid. The drilling fluid can be used to form a wellbore in a subterranean formation via a drilling operation. The drilling fluid can be, without limitation, an oil-based drilling mud, a synthetic-based drilling mud, or a water-based drilling mud.

The methods include introducing a cement composition into an annulus of the wellbore for a reverse cementing operation. Turning now to FIG. 2B, the cement composition 14 can be introduced into an annulus 32 of the wellbore 22. The step of introducing can include pumping the cement composition into the wellbore using one or more pumps 6. The step of introducing can be for the purpose of at least one of the following: well completion; foam cementing; primary or secondary cementing operations; well-plugging; squeeze cementing; and gravel packing. The cement composition can be in a pumpable state before and during introduction into the annulus 32. The subterranean formation 20 is penetrated by the wellbore 22. The well can be, without limitation, an oil, gas, or water production well, an injection well, a geothermal well, or a high-temperature and high-pressure (HTHP) well. The wellbore 22 comprises walls 24. A surface casing 28 can be inserted into the wellbore 22. The surface casing 28 can be cemented to the walls 24 via a cement sheath 26. One or more additional conduits (e.g., intermediate casing, production casing, liners, etc.) shown here as casing 30 can also be disposed in the wellbore 22. One or more centralizers 34 can be attached to the casing 30, for example, to centralize the casing 30 in the wellbore 22 prior to and during the reverse cementing operation. The well can include an annulus 32 formed between the outside of the casing 30 and the walls 24 of the wellbore 22 and/or the surface casing 28.

With continued reference to FIG. 2B, the cement composition 14 can be pumped down the annulus 32 in the direction indicated by the arrows. The cement composition 14 can be allowed to flow down the annulus 32, through a casing shoe 42 at the bottom of the casing 30, and up inside the casing 30. As it is introduced, the cement composition 14 can displace the first fluid 44 that is present in the interior of the casing 30 and/or the annulus 32. Although not show, a second fluid can be introduced into the wellbore 22 after the first fluid. The second fluid can be, for example, a spacer fluid. The cement composition 14 can displace the first fluid and the second fluid. At least a portion of the displaced fluids can exit the casing 30 via a flow line 38 and be deposited, for example, in one or more retention pits 40 (e.g., a mud pit), as shown on FIG. 2A.

FIG. 3 is an illustration of a reverse cementing sensor device 100. The sensor device 100 can include a resistivity sensor 110. The resistivity sensor 110 is configured to measure the resistivity of a fluid. Most rock materials in a subterranean formation are essentially electrical insulators, while their enclosed fluids are electrical conductors. For fluids, the electrical charge carriers are only the ions present in fluid, for example, salt ions in brackish water. In the absence of dissolved ions, water is a very poor electrical conductor. Electrical resistivity is a fundamental property of a material that measures how strongly it resists electric current. A low resistivity indicates a material that readily allows electric current. Resistivity (p) can be measured by injecting a signal into the wellbore and measuring voltage and current through the unit length of electrodes as shown in FIG. 4 denoted by Equation 1.

ρ=E/J EQ. 1

where ρ is the electrical resistivity of the material in ohm-meter “Ω-m”, E is the magnitude of the electric field in the material in voltage per meter “V/m”, and J is the magnitude of the electric current density in the material in ampere per meter squared “A/m²”. By way of example, if a 1 cubic meter solid cube of material has sheet contacts on two opposite faces, and the resistance between these contacts is 1Ω, then the resistivity of the material is 1Ω-m.

The resistivity sensor 110 can include other components necessary to measure the resistivity of a fluid as shown in FIG. 4. According to any of the embodiments, the resistivity sensor 110 includes a source of electrical current and frequency, a voltage measurement system (e.g., a voltmeter), electrodes, and cables connecting the components to one or more electrodes.

Turning back to FIG. 3, the sensor device 100 is located on an inside of the casing string 30. The sensor device 100 can also be located on the inside of a tubing string. The annulus 32 can be located between the outside of the casing string 30 and the wall 24 of the wellbore 22 for an open-hole wellbore or located between the outside of a tubing string and the inside of a casing string (not shown) for a cased-hole wellbore. In this manner, fluids flowing inside the casing string or tubing string will more predictably and reliably make contact with the resistivity sensor 110.

Still with reference to FIG. 3, the sensor device 100 includes an acquisition and measurement apparatus 111. The acquisition and measurement apparatus 111 can be a controller board. The acquisition and measurement apparatus 111 is configured to be pre-programmed with a resistivity profile. The acquisition and measurement apparatus 111 is configured to receive readings from the resistivity sensor 110. The methods can include pre-programming the acquisition and measurement apparatus 111 with a resistivity profile.

The exact composition of the first fluid, the cement composition, and optionally a second, third, etc. fluids can differ. By way of example, an oil-based drilling mud may be used in one subterranean formation while a water-based drilling fluid may be used in a different subterranean formation. Also, the ingredients in each type of wellbore fluid can be different based on the exact subterranean formation makeup and the specific wellbore conditions. Accordingly, the resistivity can be different depending on the exact composition for a particular wellbore fluid.

By way of example and as shown in FIGS. 5-8, the resistivity of the wellbore fluids is different. Both the oil-based drilling mud and synthetic-based drilling mud shown in FIG. 5 had very similar resistivities over 1,600Ω-m; however, the water-based drilling muds shown in FIG. 6 had resistivities in the range of 1.5 to 3.5Ω-m. This shows that the exact composition and concentration of ingredients in the different types of wellbore fluids (e.g., drilling fluid, spacer fluid, and cement composition) will affect the resistivity for each particular fluid. The resistivity of the different types of fluids is relatively consistent within a range, even though the exact ingredients and concentration can differ. For example, oil-based and synthetic-based drilling muds generally have a resistivity greater than 1,600Ω-m, water-based drilling muds generally have a resistivity less than 3.5Ω-m, spacer fluids generally have a resistivity between 5-6Ω-m, and cement compositions generally have a resistivity less than 0.5Ω-m. The resistivity sensor 110 can have a higher sensitivity compared to other sensors. In this manner, the resistivity sensor 110 can detect smaller incremental units (e.g., measurement increments of 0.1Ω-m) in order to differentiate between different types of fluid having resistivities that are close to each other, such as a spacer fluid having a resistivity of 4.8 and a water-based drilling mud having a resistivity of 3.5.

As shown in FIG. 9, different fluids can be used in reverse cementing operations. A first fluid, for example a drilling mud, can be used to form a wellbore. The drilling mud will have a unique resistivity depending on the ingredients and concentrations in the drilling mud. A casing string and/or tubing string can be installed in the wellbore. A second fluid, for example a spacer fluid, can be introduced into an annulus of the wellbore. A cement composition can then be introduced into the annulus after the spacer fluid. The drilling mud and the spacer fluid can be pushed down the annulus and up into the casing or tubing string by the cement composition.

As shown in scenario-1 in FIG. 9, the column of fluids flowing upwards through the inside of the casing or tubing string can be an oil-based drilling mud, the spacer fluid, and then the cement composition. The column of fluids will have a unique resistivity profile based on the composition of the different types of fluids and the length of time each type of fluid flows past the sensor device 100. For example, an oil-based drilling mud can have a resistivity of 1,600Ω-m and can flow past the sensor device 100 for 2 hours, the spacer fluid can have a resistivity of 5Ω-m and can flow past the sensor device 100 for 1 hour, and the cement composition can have a resistivity of 0.3Ω-m and flow past the sensor device 100 for 10 minutes. According to this example, the resistivity profile will look like descending stairs. By way of another example and as shown in scenario-2, a water-based drilling mud can have a resistivity of 1.5Ω-m and can flow past the sensor device 100 for 2 hours, the spacer fluid can have a resistivity of 6Ω-m and can flow past the sensor device 100 for 1 hour, and the cement composition can have a resistivity of 0.3Ω-m and flow past the sensor device 100 for 10 minutes. According to this example, the resistivity profile will look like one step up and then back down.

However, as shown in FIG. 10, the change in resistivity between fluids is rarely instantaneously observed. This is because most commonly there is some mixing of two different fluids at the fluid interface. For example, when a spacer fluid is introduced into the annulus, some of the spacer fluid mixes with some of the drilling fluid at the top of the column. The cement composition can then mix with some of the spacer fluid at the top of the column. As can be seen in FIG. 10, as the cement composition is introduced into the annulus and begins to displace the spacer fluid, the percentage of the cement composition flowing past a particular location within the annulus gradually increases from initially being 0% (all spacer fluid is flowing past) to eventually being 100% (all cement composition is flowing past). Accordingly, the ratio of cement composition to spacer fluid in the mixed fluid gradually increases. The resistivity of the mixed fluid will change depending on the concentrations of spacer fluid and cement in the mixed fluid as the fluids are flowing through the wellbore. As can be seen, the resistivity can be approximately 1.5Ω-m at 20% cement and 80% spacer fluid. However, the resistivity can be approximately 0.5Ω-m at 80% cement and 20% spacer fluid. As shown in FIG. 9, this gradual change in resistivity is represented by the dashed lines in the resistivity profiles to depict the change in resistivity more realistically in reverse cementing operations.

The methods include pre-programming the acquisition and measurement apparatus with the resistivity profile. The methods can further include pre-determining the resistivity for each of the specific fluids used in the reverse cementing operation. The step of pre-determining the resistivity for each of the specific fluids can include preparing a test fluid wherein the test fluid is identical to the fluids used in the reverse cementing operation (i.e., the test fluid has the same ingredients and in the same concentration as the fluid used in the operation). For example, the resistivity of test fluids corresponding to the drilling fluid, spacer fluid, and cement composition to be used at a specific well site can be tested in a laboratory to determine the exact resistivity for those fluids. Laboratory testing can be performed off-site or at the well site. The test fluids can be an aliquot of the actual fluids to be used or more commonly can be a prepared sample.

Once the resistivity of each fluid used in the oil or gas operation is pre-determined, the length of time each fluid is estimated to flow past the resistivity sensor 110 can be pre-determined. For example, it may take 4 hours for the first fluid (e.g., a drilling fluid) to flow past the resistivity sensor 110 after a second fluid (e.g., a spacer fluid) in pumped into the annulus. Accordingly, the acquisition and measurement apparatus 111 can be pre-programmed with the pre-determined resistivity for the first fluid as 4 hours. It may take 2 hours for the second fluid to flow past the resistivity sensor after the cement composition is placed into the annulus. Accordingly, the acquisition and measurement apparatus 111 can be pre-programmed with the pre-determined resistivity for the second fluid as 2 hours. The resistivity after the 2 hours has elapsed should be the pre-determined resistivity of the cement composition. The resistivity profile can also include the gradual change in resistivity between the different fluids that may become intermixed at the fluid interfaces, for example, as illustrated in FIGS. 9 and 10. The time can be pre-determined based on a variety of factors, such as the length of the casing string or tubing string, the pump rate of the first fluid, the optional second fluid, and the cement composition, among other factors.

It is to be understood that unlike other sensors and methods of detecting the presence of a fluid, the specific resistivity of the fluids to be used for a specific well are pre-determined via laboratory testing, the resistivity profile is then determined based on the specific resistivities of each fluid and the length of time, and the resistivity profile is pre-programmed into the acquisition and measurement apparatus at the wellhead.

The methods can include introducing the sensor device 100 into the wellbore. The sensor device 100 can be installed on an inside and near a bottom of the casing string or tubing string prior to being run into the well. The casing string can be run into the well during drilling operations for example. The step of introducing can be running in of the casing string or tubing string. The sensor device 100 is intended to remain within the casing string or tubing string after introduction into the wellbore, that is, the sensor device 100 is not intended to be retrieved from the wellbore after use. According to any of the embodiments, the sensor device 100 can be used one time after introduction into the wellbore.

Any of the components of the sensor device 100, such as the acquisition and measurement apparatus 111, can be powered by a power source. The power source can be batteries. It is to be understood that none of the components of the sensor device 100 receive direct power from the wellhead. According to any of the embodiments, the sensor device 100 can be put in sleep mode during introduction into the wellbore. Sleep mode can preserve available power from the power source. For example, it is not uncommon for the casing string to take 24 hours or more to be run into the well. Therefore, the sensor device 100 can be pre-programmed to be in sleep mode during run in. The sensor device 100 can also be programmed to wake up from sleep mode after a desired length of time. The desired length of time can be a time before, at, or after the time to run the casing string or tubing string into the well. By way of example, if it is estimated to take 24 hours to run the casing string into the well, then the sensor device 100 can be programmed to wake up from sleep mode after 20 hours to 25 hours.

The methods can include allowing the resistivity sensor 110 to measure the resistivity of the first fluid and the cement composition. The resistivity sensor 110 can also measure the resistivity of the second fluid, third fluid, etc. if used. The resistivity sensor 110 can continually measure the resistivity of the different types of fluids as they flow past the resistivity sensor. The resistivity sensor can also be instructed by the acquisition and measurement apparatus 111 to take readings at a desired time interval, for example, every 5 minutes. The resistivity sensor can also be instructed to take readings after one or more specific times have elapsed, for example, at 2 hours and 4 hours. This embodiment can be useful in order to conserve power and can be coordinated based on the estimated time it will take for a different type of fluid to reach the resistivity sensor.

The acquisition and measurement apparatus 111 can also instruct the resistivity sensor 110 to take readings at a desired time interval after a specific time has elapsed. By way of example, if it is estimated to take 4 hours for a spacer fluid and 8 hours for the cement composition to reach the resistivity sensor, then the acquisition and measurement apparatus can instruct the resistivity sensor to begin taking readings every 4 minutes beginning after 3.5 hours have elapsed since the spacer fluid began being pumped into the well. The acquisition and measurement apparatus can then optionally instruct the resistivity sensor to cease taking readings, for example, when the resistivity measures the specific resistivity of the spacer fluid, which would indicate 100% of the fluid flowing past the resistivity sensor is spacer fluid and not a mixture of spacer fluid and drilling mud. The acquisition and measurement apparatus can then instruct the resistivity sensor to begin taking readings every 4 minutes after 7.5 hours have elapsed since the cement composition began being pumped into the annulus. Of course, shorter or longer time intervals can be used instead of the every-4-minutes example, and different elapsed times can also be used instead of 30 minutes before the estimated time example.

Turning back to FIG. 3, the sensor device 100 can further an actuator 112. The actuator 112 is configured to receive instructions from the acquisition and measurement apparatus 111. The acquisition and measurement apparatus 111 can be in wired communication with the resistivity sensor 110 and the actuator 112 in order to receive readings and send instructions. A valve 200 can be located inside the casing string 30 or a tubing string. The valve 200 can be located at or near a bottom of the casing or tubing string. The valve 200 can be located below the sensor device 100. The valve 200 can be any type of valve, for example a flapper valve or sliding sleeve, that allows fluid to flow up into the casing or tubing string when in an open position and restrict fluid flow through the casing or tubing string when in a closed position as shown. When the valve 200 is in a closed position, an operator can detect a change in pressure within the wellbore and can cease pumping the cement composition into the annulus.

The acquisition and measurement apparatus 111 is configured to send instructions to the actuator 112 to close the valve 200 after the acquisition and measurement apparatus receives a desired resistivity reading within the resistivity profile. The desired resistivity reading can be the pre-determined resistivity of the cement composition. The desired resistivity reading can be any of the pre-determined resistivities along the cement composition portion of the resistivity variation curve portion of the resistivity profile illustrated in FIG. 9. By way of a specific example with reference to FIG. 10, if the pre-determined resistivity of the cement composition is 0.4Ω-m and the pre-determined resistivity of the drilling fluid or spacer fluid is 3Ω-m, then the desired resistivity reading can be any reading in the range of 1.5 to 0.4Ω-m. Accordingly, the desired resistivity reading can correspond to a 20% cement/80% spacer fluid mixture to 100% cement composition. In this manner, an operator can ensure that the cement composition has filled the annulus and is present at the location of the resistivity sensor 110.

The acquisition and measurement apparatus 111 can instruct the actuator 112 to close the valve 200 after the desired resistivity reading is transmitted to the acquisition and measurement apparatus. According to any of the embodiments, the acquisition and measurement apparatus sends the instruction to the actuator 112 to close the valve a desired time after receiving the desired resistivity reading from the resistivity sensor 110. By way of a first example, if the desired resistivity reading corresponds to less than 100% cement composition (e.g., greater than 0.4Ω-m in example FIG. 10), then the acquisition and measurement apparatus can wait 15 minutes to send the instruction to the actuator to close the valve after receiving the desired resistivity reading. In this manner, an operator can ensure that the cement composition has been properly placed and filled the annulus. The desired time after receiving the desired resistivity reading can vary and range from 1 minute (preferably if the desired resistivity reading is the pre-determined resistivity for 100% cement) to 15 minutes. According to any of the embodiments, the instruction to close the valve is sent at the earliest possible time when proper cement placement can be ensured. This can save money by not needlessly pumping more cement into the annulus. It is to be understood that the acquisition and measurement apparatus 111 is pre-programmed at the wellhead with the specific resistivity profile and instructions and autonomously sends the instruction to the actuator based on the pre-programmed resistivity profile and instructions. For example, the acquisition and measurement apparatus can be pre-programmed to begin measuring the resistivity using the resistivity sensor after a pre-programmed time has elapsed, and/or send instructions to the actuator after the desired resistivity is detected and a pre-programmed time has elapsed since detection.

Any of the components of the sensor device 100 can be housed within a housing. The housing can protect the components from damage by wellbore fluids. The housing can ensure that the components can function properly and for the intended duration of use.

A second sensor can also be used in conjunction with the resistivity sensor device. A second sensor can be used as a back-up sensor to ensure that the valve is closed at a desired time. The second sensor can include, for example, a magnetic sensor or a capacitance sensor. The second sensor can be connected to the acquisition and measurement apparatus 111 and the actuator 112. Capacitance sensing is a technology, based on capacitive coupling, that can detect and measure anything that is conductive or has a dielectric different from air. Additional ingredients can be added to the cement composition, such as a magnetic mineral (e.g., magnetite), such that the magnetic sensor can detect the presence of the cement composition. The second sensor can be located inside the casing string or tubing string adjacent to the resistivity sensor 110. The acquisition and measurement apparatus can also be pre-programmed with a capacitance or magnetic profile of test fluids.

An embodiment of the present disclosure is a method of detecting the presence of a cement composition in a reverse cementing operation in a wellbore comprising: introducing a sensor device into the wellbore, the sensor device comprising: a resistivity sensor configured to measure the resistivity of a fluid; an acquisition and measurement apparatus configured to receive readings from the resistivity sensor; and an actuator configured to receive instructions from the acquisition and measurement apparatus; pre-programming the acquisition and measurement apparatus with a resistivity profile; introducing a first fluid into the wellbore; introducing a cement composition into an annulus of the wellbore; allowing the resistivity sensor to measure the resistivity of the first fluid and the cement composition; and allowing the acquisition and measurement apparatus to instruct the actuator to close a valve. Optionally, the method further comprises wherein the resistivity sensor comprises a source of electrical current, a voltage measurement system, electrodes, and cables. Optionally, the method further comprises wherein the acquisition and measurement apparatus is a controller board. Optionally, the method further comprises wherein the resistivity of the first fluid is different from the resistivity of the cement composition. Optionally, the method further comprises wherein the first fluid is a drilling mud or a spacer fluid. Optionally, the method further comprises introducing a second fluid into the wellbore, wherein the second fluid is introduced into the wellbore after the first fluid and before the cement composition, wherein the first fluid is a drilling mud, and wherein the second fluid is a spacer fluid. Optionally, the method further comprises pre-determining the resistivity for the first fluid and the cement composition prior to introduction of the sensor device into the wellbore. Optionally, the method further comprises wherein pre-determining the resistivity for the first fluid and the cement composition comprises: preparing a first and second test fluid, wherein the first test fluids is identical to the first fluid and the second test fluid is identical to the cement composition; and measuring the resistivity of the test fluids. Optionally, the method further comprises estimating the lengths of time that each of the first fluid and the cement composition flow past the resistivity sensor. Optionally, the method further comprises wherein the resistivity profile is determined based on the resistivity of the first test fluid and the second test fluid, and the lengths of time. Optionally, the method further comprises wherein the acquisition and measurement apparatus sends instructions to the actuator to close the valve after the acquisition and measurement apparatus receives a desired resistivity reading within the resistivity profile from the resistivity sensor. Optionally, the method further comprises wherein the desired resistivity reading corresponds to a pre-determined resistivity indicative of the cement composition in a concentration in a range from 20% to 100% by volume. Optionally, the method further comprises wherein the acquisition and measurement apparatus sends the instructions to the actuator to close the valve a desired period of time after receiving the desired resistivity reading from the resistivity sensor. Optionally, the method further comprises introducing a second sensor into the wellbore, wherein the second sensor is located near the resistivity sensor, wherein the second sensor measures a property of the first fluid, the cement composition, or the first fluid and the cement composition; pre-programming the acquisition and measurement apparatus with a profile of the property; and allowing the second sensor to measure the property of the first fluid, the cement composition, or the first fluid and the cement composition. Optionally, the method further comprises wherein the property is a change in a magnetic field or capacitance. Optionally, the method further comprises wherein the second sensor is a magnetic sensor or a capacitance sensor. Optionally, the method further comprises wherein the first fluid or the cement composition comprises a magnetic mineral, or wherein the first fluid and the cement composition comprise a magnetic mineral in different concentrations.

Another embodiment of the present disclosure is a reverse cementing sensor device comprising: a resistivity sensor, wherein the resistivity sensor is located on an inside of a casing string or tubing string; an acquisition and measurement apparatus configured to be pre-programmed with a resistivity profile and to receive readings from the resistivity sensor; and an actuator configured to receive instructions from the acquisition and measurement apparatus, wherein the acquisition and measurement apparatus is configured to send instructions to the actuator to close a valve located inside the casing string or tubing string after the acquisition and measurement apparatus receives a desired resistivity reading within the resistivity profile. Optionally, the sensor device further comprises wherein the resistivity sensor comprises a source of electrical current, a voltage measurement system, electrodes, and cables. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus is a controller board. Optionally, the sensor device further comprises wherein the resistivity profile is of a fluid. Optionally, the sensor device further comprises wherein the resistivity profile is of a drilling mud or a spacer fluid. Optionally, the sensor device further wherein the resistivity profile is of a cement composition, or the cement composition and the drilling mud or spacer fluid. Optionally, the sensor device further comprises wherein the resistivity profile of the fluid is pre-determined. Optionally, the sensor device further comprises wherein pre-determining the resistivity for the fluid comprises: preparing a first and second test fluid, wherein the first test fluids is identical to the first fluid and the second test fluid is identical to the cement composition; and measuring the resistivity of the test fluids. Optionally, the sensor device further comprises estimating the lengths of time that each of the first fluid and the cement composition flow past the resistivity sensor. Optionally, the sensor device further comprises wherein the resistivity profile is determined based on the resistivity of the first test fluid and the second test fluid, and the lengths of time. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus sends instructions to the actuator to close the valve after the acquisition and measurement apparatus receives a desired resistivity reading within the resistivity profile from the resistivity sensor. Optionally, the sensor device further comprises wherein the desired resistivity reading corresponds to a pre-determined resistivity indicative of the cement composition in a concentration in a range from 20% to 100% by volume. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus sends the instructions to the actuator to close the valve a desired period of time after receiving the desired resistivity reading from the resistivity sensor. Optionally, the sensor device further comprises introducing a second sensor into the wellbore, wherein the second sensor is located near the resistivity sensor, wherein the second sensor measures a property of the first fluid, the cement composition, or the first fluid and the cement composition; pre-programming the acquisition and measurement apparatus with a profile of the property; and allowing the second sensor to measure the property of the first fluid, the cement composition, or the first fluid and the cement composition. Optionally, the sensor device further comprises wherein the property is a change in a magnetic field or capacitance. Optionally, the sensor device further comprises wherein the second sensor is a magnetic sensor or a capacitance sensor. Optionally, the sensor device further comprises wherein the first fluid or the cement composition comprises a magnetic mineral, or wherein the first fluid and the cement composition comprise a magnetic mineral in different concentrations.

Another embodiment of the present disclosure is a reverse cementing sensor device comprising: a first sensor located on an inside of a casing string or tubing string, wherein the first sensor is a resistivity sensor; a second sensor located in the inside of the casing string or tubing string; an acquisition and measurement apparatus configured to be pre-programmed with a profile corresponding to the first sensor and the second sensor, and configured to receive readings from the first sensor and the second sensor; and an actuator configured to receive instructions from the acquisition and measurement apparatus, wherein the acquisition and measurement apparatus is configured to send instructions to the actuator to close a valve located inside the casing string or tubing string after the acquisition and measurement apparatus receives a desired reading within the profile for the first sensor, the second sensor, or the first sensor and the second sensor. Optionally, the sensor device further comprises wherein the resistivity sensor comprises a source of electrical current, a voltage measurement system, electrodes, and cables. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus is a controller board. Optionally, the sensor device further comprises wherein the resistivity profile is of a fluid. Optionally, the sensor device further comprises wherein the resistivity profile is of a drilling mud or a spacer fluid. Optionally, the sensor device further wherein the resistivity profile is of a cement composition, or the cement composition and the drilling mud or spacer fluid. Optionally, the sensor device further comprises wherein the resistivity profile of the fluid is pre-determined. Optionally, the sensor device further comprises wherein pre-determining the resistivity for the fluid comprises: preparing a first and second test fluid, wherein the first test fluids is identical to the first fluid and the second test fluid is identical to the cement composition; and measuring the resistivity of the test fluids. Optionally, the sensor device further comprises estimating the lengths of time that each of the first fluid and the cement composition flow past the resistivity sensor. Optionally, the sensor device further comprises wherein the resistivity profile is determined based on the resistivity of the first test fluid and the second test fluid, and the lengths of time. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus sends instructions to the actuator to close the valve after the acquisition and measurement apparatus receives a desired resistivity reading within the resistivity profile from the resistivity sensor. Optionally, the sensor device further comprises wherein the desired resistivity reading corresponds to a pre-determined resistivity indicative of the cement composition in a concentration in a range from 20% to 100% by volume. Optionally, the sensor device further comprises wherein the acquisition and measurement apparatus sends the instructions to the actuator to close the valve a desired period of time after receiving the desired resistivity reading from the resistivity sensor. Optionally, the sensor device further comprises introducing a second sensor into the wellbore, wherein the second sensor is located near the resistivity sensor, wherein the second sensor measures a property of the first fluid, the cement composition, or the first fluid and the cement composition; pre-programming the acquisition and measurement apparatus with a profile of the property; and allowing the second sensor to measure the property of the first fluid, the cement composition, or the first fluid and the cement composition. Optionally, the sensor device further comprises wherein the property is a change in a magnetic field or capacitance. Optionally, the sensor device further comprises wherein the second sensor is a magnetic sensor or a capacitance sensor. Optionally, the sensor device further comprises wherein the first fluid or the cement composition comprises a magnetic mineral, or wherein the first fluid and the cement composition comprise a magnetic mineral in different concentrations.

Therefore, the apparatus, methods, and systems of the present disclosure are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions, systems, and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more fluids, sensors, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc.

Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

SENSOR AND ACTUATOR FOR AUTONOMOUSLY DETECTING WELLBORE FLUIDS AND CLOSING FLUID PATH

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