EA042605B1 - MANIFOLD PRESSURE MONITORING METHOD - Google Patents

Description

The invention relates to a method for monitoring reservoir pressure.

Reservoir characteristics can be determined by the first well, and with more information about the reservoir, corresponding performance in the second well can be determined or improved.

Testing reservoirs in this way and evaluating connectivity in the reservoir between wells is known as a connectivity test, such as an interference test or interference test.

Interference testing is a study in which a pressure pulse is applied to the formation near one well/isolated section of the well and recorded in another observation well or a separate isolated section of the same well, and data on whether the pressure wave was recorded in the observation well or isolated section and to what extent, are important in relation to reservoir pressure connectivity between wells/isolated areas. Such information can be useful for a number of reasons, such as determining the best strategy for extracting fluids from a reservoir.

Interference testing is similar to interference testing, however, it examines the long-term effects on the observation well/isolated area after production (or injection) in a single well or isolated area. One example is US Pat. No. 3,285,064, which describes changing flow in a first wellbore and monitoring pressure in a second wellbore.

It is also useful to know as much as possible about the well and reservoir and track them. In this way, useful information about the reservoir can be obtained, which in the future may facilitate subsequent production from adjacent wells.

The authors of the present invention have developed a new way to provide further understanding of the reservoir.

According to a first aspect of the present invention, there is provided a method for monitoring reservoir pressure, comprising:

in the case of a cross-sectional well, placing at least one barrier in the well such that the well is divided into a lower pressure-isolated portion below the at least one barrier and an upper portion above the at least one barrier;

at the same time, in the lower pressure-isolated section, an apparatus is located, containing: a perforating device;

a control mechanism for controlling the perforating device, comprising a wireless communication device configured to receive a wireless control signal for activating the perforating device;

pressure meter;

sending at any time a wireless control signal to the wireless communication device to activate the punching device, wherein the wireless control signal is transmitted in at least one of the following forms: electromagnetic, acoustic, via inductively coupled tubular elements and coded pressure pulses;

activating, after installation, at least one barrier of the perforating device to create at least one perforation between the well and the surrounding reservoir;

conservation or elimination during or after the installation of at least one barrier of at least a zone adjacent to the specified lower pressure-isolated area;

after activation of the perforating device and after conservation or liquidation of the specified area:

(i) monitoring the pressure in the lower pressure-isolated portion under the at least one barrier using a pressure sensor; and (ii) sending a wireless data signal containing pressure data from a region below the at least one barrier to a region above the at least one barrier using at least one of electromagnetic coupling, acoustic coupling, and inductively coupled tubulars.

Thus, in contrast to conventional procedures for activating a perforating device to bring fluid to the surface, the present inventors place a barrier in the well prior to activating the perforating device so that no flow can escape to the surface. Thus, as a rule, from the specified lower pressure-isolated section does not flow to the surface after the installation of the barrier, at least until the stages of tracking and wireless sending of data.

It has been determined that this method can extract useful information about the properties of the reservoir surrounding the well. Pressure and/or other parameters may also be monitored prior to activation of the perforating device and prior to conservation/decommissioning of the zone.

The term at least one barrier in this document is abbreviated to the term barrier.

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In this case, the wireless signal can be sent before the barrier is set and the perforating device is activated on a time delay basis (so that they are activated after the barrier is set); typically, the barrier is set up before the wireless control signal is sent to the wireless communication device, thus the wireless control signal is sent from the area above the barrier to the wireless communication device below the barrier to activate the perforating device. Accordingly, in such embodiments, the implementation of the wireless signal passes through/along/around the barrier.

The perforating device can be activated immediately after or more than a week, or more than a month after the installation of the barrier or conservation/liquidation of the zone. Of course, the perforating device may be activated more than six months, more than a year, or more than five years thereafter.

The barrier may shut down or abandon the lower pressure-isolated section, not necessarily the entire well, so that operations such as well testing or another zone development may continue in another section. Alternatively, the entire well may be mothballed or abandoned.

Conservation of a zone is bringing the zone to a state where there is no flowing to the surface and where it is necessary to isolate with a barrier for at least one month, optionally more than three months or more than six months. Of course, the well may be mothballed for a longer period, such as more than a year or more than five years.

Thus, preferably the barrier is generally a permanent or semi-permanent barrier, as long as it remains in place for at least one month, optionally more than three months or more than six months. Of course, the barrier may remain in place for a longer period, such as more than a year or more than five years.

Accordingly, during these periods, flowing to the surface will not occur.

A well abandonment is a situation in which no recurrence of the well's flow of fluids to the surface is expected or exists. Thus, the barrier is typically a permanent barrier, as it remains in place indefinitely.

Barrier.

In certain embodiments, the barrier may comprise a bridge plug or packer plug. The barrier can be made up of a number of different parts that can be spaced apart from each other, for example, more than 1 m, more than 10 m, usually less than 500 m, 200 m or less than 50 m. For example, the plug can be located in the central the pipe and the packer in the annulus, each respectively blocking a portion of the well such that the entire cross section of the well prevents fluid communication and fluid communication, effectively preventing pressure communication between the well surface and the perforating device. Any pipe between such a packer and the plug may also form part of the barrier. If the barrier is made up of a central portion (eg a plug) and an annulus portion (eg a packer), preferably the central portion is in or below the annulus portion.

The barrier may comprise or be made of a pillar of cement, such as a pillar having a height of at least 2 m or at least 10 m, at least 50 m, 200-500 m and possibly up to 1000 m or even more. A short cement barrier may be preferred for reservoir isolation, while longer cement barriers are typically used for well isolation.

The outer part of the barrier may come into contact with the inner surface of the casing string or the wellbore in the well.

The barrier is typically at least 100 m or 300 m below the well surface.

The device can be hung on a barrier.

The barrier may include a valve in a closed position. In certain embodiments, the zone is preserved or eliminated by closing the barrier valve, the perforating device is activated, and a plug and/or cement column can later be added to the barrier.

Once a barrier is installed, whether it be a valve or a plug, for example, it is typically fixed in position in the well and not moved relative to the outer casing or wellbore.

Second barrier.

The barrier may be a first barrier, and a second barrier may also be located above the perforating device such that the second barrier inhibits fluid communication and fluid communication along the entire cross section of the well, thereby isolating the section of the well underneath.

Like the first barrier, the second barrier may include a bridge plug or packer plug. In certain embodiments, it may comprise or be made of a cement pillar, such as a pillar having a height of at least 2m, 10m, 50m, 200-500m and possibly up to 1000m or even

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The optional features described above with respect to the first barrier are independent, and the optional features with respect to the second barrier are not repeated further for the sake of brevity.

However, the second barrier is less likely to be a valve and more likely to be a fixed barrier such as a bridge plug or locking device.

The second barrier may be above the first barrier or below it, as a rule, it is above the first barrier.

Often, conservation or abandonment of wells is required in order to have two or more independent barriers in place. In certain embodiments, the perforating device may be activated prior to the placement of the second barrier. Time can also be reduced as the perforating operation can take place simultaneously with other well operations such as testing another area/zone. In other embodiments, the implementation of the perforating device is activated after placing the second barrier in place.

In addition to the casing, in certain embodiments, especially those in which acoustic communications are present, the tubular may extend from the first and/or second barrier to the surface of the well. In other embodiments, such as using electromagnetic coupling, this may not be required.

The second barrier may contain a column of cement.

The tracking step may be performed before and/or after the installation of the second barrier, optionally with the placement of a column of cement in place above the first barrier.

Capacity.

The apparatus in preferred embodiments of the present invention comprises a container, and the method includes driving a fluid through an opening between the interior and exterior of the container. The direction of movement of the fluid is preferably from the outer space of the container to the inner space of the container, although it can be provided in the opposite direction.

Movement of fluid between the interior and exterior of the container may occur before, during and/or after activation of the perforating device. Of course, it may be delayed for more than an hour, more than a week, more than a month, optionally more than a year or more than five years after the perforating device has been activated. For example, it may be activated when work is being done on an adjacent well.

The apparatus may be oblong. It may be in the form of a tube. As a rule, it has a cylindrical shape.

While the size of the container may vary depending on the properties of the well, typically the container may have a volume of at least 5 liters (l) or at least 50 liters, optionally at least 100 liters. The container may have a volume of not more than 3000 liters, usually not more than 1500 liters, optionally not more than 500 liters.

Thus, the apparatus may comprise a tubular/tubular element (or a sub in the tubular/tubular element part) containing a container and other components, or, in this regard, the container may be made of tubular elements, such as tubing or drill pipe. pipe connected together. The tubular elements may comprise sections each 3 m to 14 m long, 8 m to 12 m in total, and have a nominal outside diameter of 2 3/8 inches (or 2 7/8 inches) to 7 inches.

The opening allowing fluid to flow between the interior and exterior of the container may be a pre-existing opening or channel, or may be created in situ, such as by a perforating device.

The orifice provides a cross-sectional area for fluid communication and fluid communication. Said area may be less than 0.1 cm ² , optionally at least 0.25 cm ² or at least 1 cm ² . The cross-sectional area may be at most 150 cm ² , or at most 25 cm ² , or at most 5 cm ² , optionally at most 2 cm ² .

In the first case, the control device controls the opening. Alternatively, the container contains a housing for the perforating device, and the hole is created by activating this (or other) perforating device. Often the perforating device contains at least one shaped charge.

Less than ten openings or less than five openings may be provided.

The outside of the vessel is typically the surrounding area of the well. The wellbore environment is the part of the wellbore that surrounds the tool, in particular the outer part of the hole, immediately before the control device moves in response to a control signal, or the hole is created by this or any other perforating device.

Entry into or exit from a container is referred to herein as fluid movement.

Control device.

The control device may include a mechanical valve assembly, a pump, and/or a latch assembly.

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The control device typically responds to wireless signals via this or a separate wireless communication device. The control device may or may not be located in the hole. In embodiments with a control device and an already existing opening, the control device may be moved in response to a control signal at least 2 minutes before and/or at least 2 minutes after any activation of the perforating device. This period may be at least 10 minutes before and/or after any activation of the perforating device. Through their independent control, it is possible to extract useful information between the activation of the perforating device and the activation of the control device.

The control device may be configured to close the hole in the first position and open the hole in the second position. Thus, typically in a first position, the control device seals said interior space of the container relative to said external space of the container, and typically, in a second position, the control device allows fluid to flow into/out of the container. Thus, in the second position, fluid communication and fluid communication can be provided between said interior of the container and said outer space of the container.

The control device can be moved back to the position it was originally in, or to the next position, which may be more open or more closed, or partially open/closed. This usually occurs in response to receiving an additional control signal.

Therefore, optionally, the control device can be moved again to prevent the movement of fluid between the container and the outer space of the container. For example, the flow may be stopped, or resumed or changed, and may optionally be partially controlled according to a parameter or time delay. As a rule, the control device in the open second position remains attached to the apparatus.

The control device can be closed until any pressure difference between the container and the outer space of the container is equalized. The remaining pressure difference may optionally be used later. Thus, the procedure for moving the control device to allow or prevent movement of the fluid can be repeated at a later time.

The control device may be located at one end of the apparatus. However, it can be located in the central part of the apparatus. One or more devices may be located in different positions.

The control mechanism may be configured to move the control device to selectively provide or prevent the flow of fluid to/from at least a portion of the container when a certain condition is met, for example, when a certain pressure is reached, for example, 2000 psi. inch, or after a time delay. Thus, the control signal causing the response to move the control device may depend on certain parameters, and different control signals may be sent depending on the appropriate parameters for specific downhole conditions.

Valve.

Thus, the control device may comprise a mechanical valve assembly having a locking member movable to selectively allow or prevent fluid from moving between at least a portion of the container and the exterior of the container through the opening.

The locking element can be controlled directly or indirectly. In certain embodiments, the implementation of the locking element is controlled directly by the control mechanism, although, as a rule, a separate second control mechanism is provided to control the locking element. It can be controlled electro-mechanically or electro-hydraulically by moving. In other embodiments, the implementation of the valve is controlled indirectly, for example, by moving the piston causing movement of the valve.

The mechanical valve assembly may include a solid locking element. A mechanical valve assembly typically has an inlet, a valve seat, and a sealing mechanism. The seat and sealing mechanism may comprise a single component (eg a pinch valve or a mechanical bursting disc).

Piston, needle and spool valve assemblies are preferred.

The locking element may be actuated by at least one of (i) a motor and an actuator, (ii) a spring, (iii) a differential pressure, (iv) an electromagnet, and (v) a screw spindle.

Operated by differential pressure

A variety of different driving forces can cause fluid to move through the opening, such as a pressure difference between the interior and exterior of the container and/or a pump.

Prior to the movement of the fluid, the pressure inside the container and outside the container may be different, in particular lower inside the container compared to the outside of the container. This pressure difference

- 4 042605 is greater than instantaneous, typically at least one minute and usually longer.

Thus, once a hole is created or a control device is activated to communicate through a pre-existing hole, fluid moves from a region of higher pressure to a region of lower pressure.

A negative differential pressure vessel (having less pressure than outside the vessel/surrounding the well) is particularly preferred. Typically, at least 5 liters of fluid is drawn into the container, optionally at least 50 liters or at least 100 liters (other containers, such as positive differential pressure containers, may have the same amount of fluid movement through the orifice). This may eliminate damage to the formation, ie, at least partially unblock any blocked portions and/or free portions of the well and/or surrounding formation; this is often sufficient to improve pressure communication between the well and the reservoir. The present inventors recognize that test performance and/or other downhole operations may be compromised due to blockage of pores or other areas, and a method to effectively unblock these areas would be beneficial. These blockages can be caused by kill fluid, wellbore debris, filter cake after kill fluid flushing, lost circulation material, or debris after perforation. Thus, the term debris may include perforation debris and/or formation damage such as a filter cake.

The container typically contains a gas, for example at least 85% by volume of a gas such as nitrogen, carbon dioxide or air. In one embodiment, fluid may be sealed in at least a portion (eg, greater than 50% by volume) of the vessel at atmospheric pressure prior to delivery, and then the tool is delivered to the well (which has a higher well pressure). Thus, the pressure in said portion of the container, which is less than the pressure outside the container, prior to fluid movement, may be in the range of 14 to 25 psi. inch, which is normal atmospheric pressure, which sometimes increases with higher downhole temperatures. Alternatively, the vessel can be effectively evacuated, ie less than 14 psig. inch, optionally less than 10 psi. inch.

The pressure difference between the interior of the reduced pressure vessel and said exterior of the vessel before fluid movement can be at least 100 psi. inch or at least 500 psi. inch, preferably at least 1000 psi. inch.

Pump actuation.

Alternatively or in addition, the control device may include an electric pump for causing the fluid to move through the opening between the interior and exterior of the container. The pump may be located in the hole. Optionally, the pump is configured to pump fluid from the outside of the container to the inside of the container.

Alternatively, the pump is configured to pump fluid from the reservoir into the surrounding wellbore. Typically, this amount is at least one liter or more than five liters of fluid that was added to the vessel at the surface before the tool was lowered into the well. This fluid may be used to treat the well/reservoir.

The electric pump is preferably a positive displacement pump such as a piston pump, a gear pump, a screw pump, a diaphragm pump, a lobe pump; in particular a piston or gear pump. Alternatively, the pump may be a high speed pump such as a centrifugal pump.

The pump may be configured to pump fluids at a rate of 0.01 cc/s to 20 cc/s.

The pumping operation or rate may be controlled in response to receiving an additional control signal from this or a separate wireless communication device (or it may be a command in the original signal).

Other control devices.

The control device may include a latch assembly which in turn controls the floating piston: it can hold the floating piston in place against other forces (e.g. downhole pressure) while releasing/moving in response to a command from the controller to ensuring the movement of fluid through the hole.

The orifice may include a check valve that may prevent fluid from flowing through it.

Union.

The device may contain a fitting.

The choke may be integral with the control device or may be in a flow path containing an opening and a control device.

Said cross-sectional area may contain a filter.

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The locking element may function as a choke, optionally an adjustable choke that can be changed in the field, or it may be a non-adjustable choke.

Thus, the size of the cross-sectional area for fluid movement can be sufficiently small, for example 0.1-0.25 cm ² , whereby fluid movement is effectively blocked.

Floating piston.

The floating piston may be positioned in the vessel to separate one fluid from another. For example, one side of the floating piston may be provided with fluid to release, and the other side may be provided with gas at a higher pressure than the surrounding well to displace the fluid when the control device is in fluid communication. between the reservoir and the surrounding well.

In certain embodiments, there is a container and said floating piston without additional chambers. However, in other embodiments, a portion of the vessel may be pressure equalized (optionally selectively) with the surrounding portion of the well. A pump can here be used to draw fluid into or out of a pressure equalized container; or the pressure is built up and then held until the surrounding part of the well has a different pressure. In certain other embodiments, the container may comprise two sections separated by a control device, with one being a fluid chamber and the other being a reduced pressure chamber, transfer chamber, or pressure equalization chamber. If there is a pressure difference between the inside and outside of the container, the second chamber is typically the part of the container having a similar pressure difference.

The control device may control the movement of fluid between the fluid chamber and the second chamber.

The floating piston may further separate two sections in the fluid chamber, with one section in fluid communication with the orifice and another section on the opposite side of the floating piston in communication with the second chamber.

Thus, one side of the floating piston can be exposed to well pressure through the orifice. Fluid, such as oil, may be provided in the fluid chamber on the side of the second chamber of the floating piston.

In embodiments, a plurality of embodiments may be presented with respect to the second chamber. The second chamber may be a reduced pressure chamber at a pressure that is less than the pressure in the surrounding wellbore, while the control device includes a valve, thereby indirectly allowing or preventing fluids from being drawn into the fluid chamber portion of the container.

Alternatively, the second chamber may be a transfer chamber having a pressure greater than that of the surrounding wellbore. In this case, the control device, which optionally includes a valve, may cause or prevent fluids from being expelled from the fluid chamber portion of the container.

In both cases, in these embodiments, since the control device is located between the fluid chamber and the second chamber, it indirectly controls the movement of the fluid through the opening in the fluid chamber.

Alternatively, the second chamber may be a pressure equalization chamber and a control device comprising a pump that draws in fluid or withdraws fluid from a portion of the fluid chamber via a pressure equalization port in the pressure equalization chamber.

Thus, in response to a control signal, the control device may cause fluid to move between the container (fluid chamber portion) and the outer space of the container, such as a well, to draw fluids into or expel fluids therefrom.

A check valve may be provided in the opening.

The volume of the second chamber may be at least 90% of the volume of the fluid chamber, although in certain embodiments, the volume of the second chamber is larger than the volume of the fluid chamber in order to avoid or limit pressurization in the second chamber and therefore achieve greater uniform flow rate in the fluid chamber.

As a rule, the floating piston has a dynamic seal against the interior of the container.

Auxiliary containers.

In addition to the container (hereinafter, sometimes referred to as the main container), one or more auxiliary containers can be provided, optionally each of them contains corresponding control devices controlling the communication in a fluid medium between the interior of the corresponding auxiliary container and the external space of this container. It may be, for example, the surrounding part of the well, or another part of the apparatus or

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Thus, one, two, three or more than three auxiliary tanks can be provided. Additional control devices for auxiliary vessels may or may not move in response to a control signal, but instead they may respond to a parameter or time delay. Each control device for the respective auxiliary vessel can operate independently. A common communication device may be used to transmit a control signal to a plurality of control devices.

The containers may have an internal pressure different from the pressure outside the container, for example, in the surrounding part of the well or formation. If the pressure is less than outside the container, as described herein in a broader sense, such containers are called negative differential pressure tanks, and if the pressure is greater than outside the container, they are called positive differential pressure tanks.

Thus, a plurality of main and/or auxiliary vessels or apparatuses can be provided, each having a different function, wherein one or more vessels may have a negative differential pressure, one or more vessels may have a positive differential pressure, or one or more vessels may be controlled pump.

Negative differential pressure, positive differential pressure, and/or pump-driven and associated auxiliary orifices and controls may be provided, with each of the auxiliary vessels preferably having a volume of at least at least five liters and, in use, has a pumping rate and/or pressure that is lower/higher than outside the container, typically for at least one minute before the control device is optionally activated in response to a control signal. Thus, the fluids surrounding the auxiliary vessel can be drawn in (for negative differential pressure vessels), quickly if necessary, or expelled (for positive differential pressure vessels).

This can be useful, for example, for partially cleaning the filter cake using a negative differential pressure tank prior to delivering the acidizing agent to the perforations using a pump-driven tank.

Alternatively, when operating in a short interval, the surface barrier can be removed from the interval by acid delivered from the positive differential pressure vessel, and then the apparatus with the negative differential pressure vessel is used to draw fluid from the interval.

The fluid from the first chamber in the vessel may pass to another for mixing prior to discharge/removal.

The auxiliary port may include a check valve that may prevent fluid from being released from the container.

Other properties of the apparatus.

In addition to the wireless signal, the device may contain a programmed sequence of actions, such as opening and reclosing a valve or changing the position of a locking element, based on parameters such as time, pressure detection or non-detection, or detection of a specific fluid or gas. For example, under certain conditions, the machine can perform certain steps sequentially: each subsequent step is performed automatically. This can be advantageous in cases where the delay in waiting for a signal to proceed can reduce the efficiency of the process.

Typically, the hole is provided on the side surface of the apparatus, although in certain embodiments, the hole may be provided in the end surface.

More than one apparatus may be provided. Short Interval The orifice may be located between two packer element parts (or two packer elements) and the control device is activated in response to a control signal to release pressure from the reservoir into an adjacent well/reservoir for a short interval procedure. In such embodiments, the perforation is formed between the well and the reservoir in a short interval by any or a particular perforating device.

Typically, these two parts are two separate packer elements that are spaced apart to define a short interval. However, a single packer element may be used, with the hole and perforation located between two parts of the same packer element, such as a single circular packer element.

The barrier according to the first aspect of the present invention may comprise one of said parts of the packer elements forming a short interval. Alternatively, the two parts of the packer element may be separated by said barrier.

Preferably, fluid is drawn from the outside of the container into the container. Thus, such a procedure is preferably performed using an apparatus having less pressure inside the container than outside the container, such as a manifold near a perforation or with a pump that can direct fluid in both directions.

Therefore, the method described herein can be used to perform injectivity, permeability, well/reservoir treatment, hydraulic fracturing, mini fracturing or similar tests/procedures that may require application of pressure between two packer elements. In preferred embodiments, the vessel is depressurized gradually over several seconds (eg, 5-10 seconds) or longer (eg, 2 minutes to 6 hours) or very slowly (eg, 1-7 days). Thus, the functionality of the choke is extremely practical.

The packer elements are typically part of the whole packer(s) that can be controlled wirelessly. Thus, it can be stretchable and/or compressible via wireless signals. The entire packer may be an inflatable packer.

A short interval, such as the distance between two parts of the packer elements, may be less than 30 m, optionally less than 10 m, optionally less than 5 m or less than 2 m, less than 1 m or less than 0.5 m. These distances are measured from the lowest point of the upper packer element of the (first) packer element to the highest point of the lower packer element of the second packer element. Thus, it can limit the volume and hence the apparatus becomes more efficient when the opening is opened into a limited volume.

In certain embodiments, such a test may provide an early indication of the reservoir's response to the injection/fracturing operation and may reduce the requirements for a larger injection/fracturing operation.

The method described herein can be applied to an interval test, a drawdown test, an inflow test, a pressure recovery curve test, or a pressure test.

The apparatus may further comprise an outlet in fluid communication with the container, the outlet being located below the second annulus seal or above the first annular seal. A pump may be provided to direct fluid through the outlet port.

Reduced pressure in the well.

Before the barrier is installed, lighter fluids may circulate in the well, for example, as part of a flow test or for other reasons. This reduces the pressure in the well due to the reduced hydrostatic head of the lighter fluids. In certain embodiments, the barrier may be installed while the well pressure is similarly reduced to a pressure that is below the reservoir pressure. Thus, the well may have a negative differential pressure relative to the reservoir during perforation.

An advantage of such embodiments is that when the perforating device is activated, the reduced pressure assists in extracting more debris from the perforation(s) to increase communication between the well and the surrounding reservoir.

Often, a heavy fluid is injected into the well to help control it.

This heavy fluid can conduct low pressure communication through the perforations between the reservoir and the wellbore. In embodiments of the present invention, a barrier is provided, thereby perforating the manifold in a zone free of such heavy fluid, and therefore avoiding contact between the heavy fluid and the perforations.

Sensors.

The apparatus may contain sensors for fluid analysis, including optical analysis of the fluid, density, water cut, and other parameters to determine the gas factor (GOR).

Any other sensors are preferably provided below the barrier, and for pressure sensors, data is output as described herein. Preferably, a temperature sensor is also provided. Various other sensors may be provided, including sensors for acceleration, vibration, torque, motion, displacement, radiation, noise, magnetism, corrosion detection, chemical or radioactive tracer detection, fluid such as hydrate, paraffin and sand entrainment , and to determine fluid properties such as (but not limited to) flow rate, density, water cut, such as capacitance and conductivity, acidity, and viscosity. Additionally, the sensors may be configured to provide a signal or parameter that is sensed by including suitable transmitters and mechanisms. The sensors may also determine the status of other parts of the tool or other equipment in the well, such as the status of a control device such as the position of a locking element.

A group of discrete temperature sensors or a distributed temperature sensor may be provided (eg, deflated) with the vehicle. Thus, they may be located below the barrier or above the barrier, or even outside the casing. However, they are preferably under a barrier.

These temperature sensors may be located in a small diameter tubing (eg _1/4 inch) and may be connected to a transmitter or transceiver. If necessary, any number of ropes containing additional groups of temperature sensors can be provided. This group of temperature sensors and the complex system can be located at a distance so that the group of temperature sensors located in the tubing line can be aligned along the formation, for example, perforations; either, for example, predominantly parallel to the well, or in the form of a spiral.

A group of discrete temperature sensors may be part of the apparatus or may be separate from it.

The temperature sensors can be electronic sensors or fiber optic cable.

Thus, in this case, an additional group of temperature sensors can provide data from the region(s) of the perforations and signal if, for example, the perforations are blocked/clogged. An array of temperature sensors in the tubing can also provide a clear indication of fluid flow, in particular when the apparatus is activated. In this way, for example, more information about the response of the perforations can be obtained: the top region of the perforations can be opened while the other region remains blocked, and this can be determined from the local temperature along a series of temperature sensors.

Data can be output from the pressure sensor(s) before, during and/or after the activation of the perforating device and before, during or after the movement of fluid between the interior and exterior of the container.

Extracting data means extracting data to the surface.

The output data may be real-time data/current data and/or statistical data.

The data is preferably sent via acoustic and/or electromagnetic signals.

Data can be output in a variety of ways. For example, they may be transmitted wirelessly in real time or later, optionally in response to a transmission command.

Memory device.

The apparatus, in particular the sensor(s), may comprise a storage device which may store data for recall at a later time. The storage device, in some circumstances, can also be removed and the data can be output after removal.

The storage device may be part of the sensor(s). If they are not integral, the memory and sensors may be connected to each other in any suitable manner, optionally wirelessly, or physically connected to each other via a wire. Inductive coupling is also one option. Short range wireless connections can be enhanced by electromagnetic coupling in the VLF band.

The apparatus may be configured to monitor pressure or other parameters below the barrier for more than one week, one month, one year, or more than five years.

The storage device may be configured to store information for at least one minute, optionally at least one hour, more preferably at least one week, preferably at least one month, more preferably at least one year or more than five years. .

Signals.

The wireless control signal is transmitted in at least one of the following forms: electromagnetic, acoustic, via inductively coupled tubular elements and coded pressure pulses; throughout this document, references to the term wireless include those forms unless the context dictates otherwise.

The signals may be data or command signals, which need not be in the same wireless form. Accordingly, the options set forth herein for different types of wireless signals apply independently to data and command signals. The control signals may control downhole devices, including sensors. Data from the sensors may be transmitted in response to a control signal. Moreover, data acquisition and/or transmission parameters, such as acquisition and/or transmission rate or resolution, can be changed by using appropriate control signals.

Coded pressure pulses.

If coded pressure pulses are used to activate the perforating device, the firing head of the perforating device may be above or below the barrier.

Pressure pulses provide methods of transmitting a message out of or into the well/wellbore, from at least one of additional locations in or into the well/wellbore, and from the surface of the well/wellbore by using positive and/or negative pressure and/or changes in fluid flow in the tubular

- 9 042605 element and/or annulus.

Encoded pressure pulses are those pressure pulses that use a modulation scheme to encode commands in pressure or flow fluctuations, where a transducer is used in the well/wellbore to detect and/or generate the fluctuations, and/or an electronic system is used in the well/wellbore for encoding and/or decoding commands. Thus, pressure pulses used with downhole/wellbore interface electronics are referred to herein as coded pressure pulses. An advantage of coded pressure pulses as defined herein is the fact that they can be sent to electronic interfaces and can provide higher data rates and/or higher bandwidth than pressure pulses sent to mechanical interfaces.

When coded pressure pulses are used to transmit control signals, various modulation schemes can be used, such as pressure change or pressure change rate, amplitude shift keying (AMn), pulse phase modulation (PPM), pulse width modulation (PWM), frequency shift keying (FSK), phase shift keying (PSK), amplitude code keying (ACM), combinations of modulation schemes, for example, AMn-PPM-PWM, can also be used. Data rates in modulation schemes for coded pressure pulses are generally low, typically less than 10 bps and may be less than 0.1 bps.

Coded pressure pulses may be generated in stationary or moving fluids and may be recorded by direct or indirect measurement of pressure and/or flow changes. Fluids include liquids, gases, and multi-phase fluids, and may be static control fluids and/or fluids produced from or injected into a well.

Signals: general information.

Preferably, the wireless signals are signals capable of passing through a barrier, such as a traffic jam, when they are fixed in place. Thus, preferably, wireless signals are transmitted in at least one of the following forms: electromagnetic, acoustic, and via inductively coupled tubular elements.

Electromagnetic/acoustic signals and coded pressure pulses use a well, wellbore, or formation as the transmission medium. An electromagnetic/acoustic or pressure signal can be sent from the well or from the surface. The electromagnetic/acoustic signal may be transmitted from the barrier, however, in certain embodiments, it may travel indirectly, such as around the barrier.

Electromagnetic and acoustic signals are particularly preferred because they can pass through/through the annular barrier without the use of a special system of inductively coupled tubular elements, and in data transmission the amount of information that can be transmitted is usually greater compared to coded pressure pulses, in in particular when obtaining data from a well.

Therefore, the communication device may be an acoustic communication device and the wireless control signal is an acoustic control signal, and/or the communication device may be an electromagnetic communication device and the wireless control signal is an electromagnetic control signal.

Likewise, the transmitters and receivers used correspond to the type of wireless signals used. For example, when using acoustic signals, an acoustic transmitter and receiver are used.

When inductively coupled tubulars are used, at least ten, typically many more, individual sections of inductively coupled tubulars are typically provided that are connected to each other in operation, for example, to create a column of inductively coupled tubulars. They have a single wiring and may be formed by tubular elements such as tubing, drill pipe or casing. There is an inductive coupling on each connection between adjacent sections.

Suitable inductively coupled tubular elements are available from N O V under the name Intellipipe®.

Thus, electromagnetic/acoustic or pressure signals can be transmitted over relatively long distances as wireless signals, sent at least 200m, optionally more than 400m or further, which is a clear advantage over other short range signals. actions. In embodiments involving inductively coupled tubulars, this advantage/effect is provided by a combination of single wiring and inductive couplings. The distance traveled can be significantly greater depending on the length of the well.

The control signal, and optionally other signals, may be sent wirelessly from the area above the barrier to the area below the barrier. Similar signals can be sent from the area

- 10 042605 under the barrier to the area above the barrier in wireless form.

The data and commands contained in the signal may be relayed or transmitted by other means. Thus, wireless signals can be converted to other types of wireless or wired signals, and optionally retransmitted, by similar or other means such as hydraulic, cable or fiber optic lines. In one embodiment, the signals may be transmitted via cable over a first distance, such as over 400 m, and then transmitted via acoustic or electromagnetic links over a shorter distance, such as 200 m. In another embodiment, they are transmitted over a distance of 500 m by using coded pressure pulses and then 1000 m using a hydraulic line.

Thus, although wired means may be used in addition to wireless means for signal transmission, preferred configurations predominantly use wireless communication. Thus, although the distance traveled by the signal depends on the depth of the well, often the wireless signal, including repeaters, but not including any wired transmission, travels more than 1000 m or more than 2000 m. In preferred embodiments, there are also signals transmitted by wireless signals (including repeaters, but not including wired facilities), at least half the distance from the surface of the well to the device.

In the same well, different wireless signals may be used for downhole-to-surface messages and surface-to-well messages.

Thus, the wireless signal can be sent directly or indirectly to the communication device, for example, through the use of downhole repeaters above and/or below any barrier.

The wireless signal can be sent from the surface or from a wireline/coiled tubing probe (or hoist) anywhere in the well above the barrier. In certain embodiments, the probe may be located relatively close to the barrier, such as less than 30 m from it or less than 15 m.

acoustic signal.

Acoustic signals and communication may include transmission through vibrations of the well structure, which includes tubular elements, casing string, liner string, drill pipe, drill collars, tubing, coiled tubing, sucker rod, downhole tools; transmission by fluid (also by gas), including transmission through fluids in open-hole sections, tubulars, and annulus; transmission through stationary or mobile fluids; mechanical transmission through a wire rope, cable rope or flexible rod; ground transmission; transmission through wellhead equipment. Structural and/or fluid communication is preferred.

Acoustic transmission can occur at subsonic (<20 Hz), sonic (20 Hz - 20 kHz), and ultrasonic (20 kHz - 2 MHz) frequencies. Preferably the acoustic transmission is audio (20 Hz-20 kHz).

Acoustic signals and messages may include frequency shift keying (FSK) and/or phase shift keying (PSK), and/or improved versions of these methods, such as quadrature phase shift keying (QPSK) or quadrature amplitude modulation (QAM), and preferably include spreading techniques spectrum. Typically, they are adapted to automatically adjust frequencies and acoustic transmission modes to suit downhole conditions.

Acoustic signals and messages can be unidirectional or bidirectional. A moving coil piezoelectric transducer or magnetostrictive transducers can be used to send and/or receive a signal.

electromagnetic signals.

Electromagnetic (EM) (sometimes also referred to as quasi-static (QS)) wireless communications typically operate in the following frequency bands (selected based on transmission characteristics):

sub-ELF (extremely low frequency) <3 Hz (typically above 0.01 Hz);

ELF from 3 Hz to 30 Hz;

VLF (extra low frequency) from 30 Hz to 300 Hz;

ULF (ultra-low frequency) from 300 Hz to 3 kHz; and VLF (very low frequency) from 3 kHz to 30 kHz.

An exception to the frequencies listed above is EM communications using a tube as a wave path, especially but not exclusively where the tube is filled with gas, in which case frequencies from 30 kHz to 30 GHz can generally be used, the frequency is selected depending on the size of the pipe, the fluid in the pipe and the communication distance. The fluid contained in the pipe is preferably non-conductive. US Pat. No. 5,831,549 describes a telemetry system that transmits in the gigahertz range over a gas-filled tubular waveguide.

For transmission of messages from the well to the surface, sub-ELF and/or ELF (eg over 100 m) are preferred. For more local links, eg less than 10 m, VLF is preferred. The nomenclature used for these bands is defined by the International Telecommunication Union (ITU).

Electromagnetic communications may include the transmission of messages through one or more of the following: applying a modulated current to an elongated element and using the ground as a return path; transferring current to one tubular element and providing a return path to the second tubular element; using the second well as part of the current path; transmission in the near field or far field; creation of a current loop in the metal structure of the well to create a potential difference between the metal structure and the ground; use of spaced contacts to create an electric dipole emitter; use of a toroidal transformer to supply current to the metal structure of the well; use of an insulating sub; using a loop antenna to create a time-varying magnetic field modulated for local transmission or transmission through the formation; transmission within the well casing; using an elongated element and earth as a coaxial transmission line; the use of a tubular element as a waveguide; transmission outside the well casing.

Particularly suitable is the supply of modulated current to the elongated element and the use of earth as a return path; creation of a current loop in the metal structure of the well to create a potential difference between the metal structure and the ground; use of spaced contacts to create an electric dipole emitter; and using a toroidal transformer to supply current to the well structure.

A number of different methods can be used to effectively control the current and orient its direction. For example, it may be one or more of the following: the use of an insulating coating or spacers on the tubular elements of the well; selection of fluids or cements to control within and outside the tubular elements to provide electrical conductivity or isolation of the tubular elements, use of a toroidal core with high magnetic permeability to create inductance and hence impedance; the use of an insulated wire, cable or insulated elongated conductor in part of the transmission path or antenna; the use of a tubular element as a circular waveguide; use of the microwave frequency bands (from 3 GHz to 30 GHz) and UHF (from 300 MHz to 3 GHz).

Additionally, suitable means for receiving the transmitted signal are provided, which may include detecting the passage of current; potential difference detection; use of a dipole antenna; use of a loop antenna; use of a toroidal transformer; use of a Hall or similar magnetic field detector; using sections of the metal structure of the well as a dipole antenna. The phrase elongated element, used in the context of electromagnetic transmission, can also mean any elongated electrical conductor, including a hidden column; casing string; tubing or tubular element; flexible pipe; pump rod; wire rope; drill pipe; wire rope or flexible rod.

A means of transmitting signals within a well with an electrically conductive casing is disclosed in US Pat. No. 5,394,141 to Soulier and US Pat. No. 5,576,703 to MacLeod et al., both of which are incorporated herein by reference in their entirety. The transmitter, containing the generator and power amplifier, is connected to spaced contacts at the first section inside the casing with finite resistivity to create an electric dipole due to the potential difference created by the current flowing between the contacts, as the main load on the power amplifier. This potential difference creates an electric field outside the dipole, which can be detected by the second pair of spaced contacts and the amplifier in the second area due to the resultant current flowing into the casing or at the surface between the wellhead and the ground reference electrode.

Repeater.

The repeater contains a transceiver (or receiver) that can receive a signal, and an amplifier that can amplify the signal for the transceiver (or transmitter) in order to transmit it further.

At least one relay may be present. At least one repeater (and transceivers and transmitters associated with the tool or located on the surface) can be configured to transmit a signal at a distance of at least 200 m through the well. One or more repeaters may be configured to transmit over 300 m or over 400 m.

For acoustic communication, more than five or more than ten repeaters can be provided depending on the depth of the well and the location of the apparatus.

Electromagnetic links require fewer repeaters. For example, only one relay may be provided. Thus, optionally, the electromagnetic repeater (and transceivers or transmitters associated with the vehicle or located on the surface) can be configured to transmit over 500 m or over 1000 m.

- 12 042605

In some areas of the well, transfer may be more difficult, such as when transferring through a packer. In this case, the relayed signal can travel a shorter distance. However, if a plurality of acoustic repeaters are provided, preferably at least three of them are configured to transmit a signal at least 200 m downhole.

Inductively coupled tubular elements can also be equipped with a repeater, for example, for every 300-500 m of the well.

The repeaters may retain at least a portion of the data for later retrieval into suitable storage media.

Taking into account these factors, as well as the properties of the well, the repeaters can be spaced appropriately in the well.

The control signals may substantially cause immediate activation, or may be configured to activate the apparatus after a time delay and/or other conditions such as a certain change in pressure.

Electronic devices.

The apparatus may include at least one battery, optionally a rechargeable battery. The battery may be at least one of the following: high temperature battery, lithium battery, lithium oxyhalide battery, lithium thionyl chloride battery, lithium sulfuryl chloride battery, lithium fluorocarbon battery, lithium manganese dioxide battery, lithium ion battery, lithium alloy battery , sodium battery and sodium alloy battery. High temperature batteries are designed to operate at temperatures above 85°C, sometimes over 100°C. The battery system may include a first battery and additional backup batteries that are activated after a long period in the well. Backup batteries may comprise a battery in which the electrolyte is held in a reservoir and interacts with the anode and/or cathode when the active battery reaches a threshold voltage or usage level.

The control mechanism is typically an electronic control mechanism. The communication device is typically an electronic communication device.

The apparatus, especially the control mechanism, preferably comprises a microprocessor. The electronic devices in the apparatus required to power the various components such as the microprocessor, the control and communication systems and optionally the valve are preferably low power electronic devices. Low power electronic devices may include features such as low voltage microcontrollers and the use of standby modes during shutdown of most electronic systems, and a low frequency oscillator such as 10-100 kHz, such as a 32 kHz oscillator used to maintain system timing and wake up functions. Synchronized short range wireless communication techniques (e.g. VLF electromagnetic communication) can be used between different system components to minimize the time that individual components need to be operational and therefore maximize standby time. and energy savings.

Electronic devices with low power consumption contribute to the long-term use of the various components of the machine. The control mechanism may be configured to control the control signal more than 24 hours after running into the well, optionally more than 7 days, more than 1 month, more than 1 year, or more than five years. It may be configured to be in sleep mode before and/or after activation.

Tests.

The method described herein can be used to conduct a test and/or an interference test.

Pressure changes may be induced by production, pumping, perforating, dry testing, or other well testing in the first well. As a rule, they are caused by short-term or long-term operation. The pressure changes they cause may or may not be observed in an observation well.

Typically, the well described in the present invention is an observation well that is monitored/monitored by a pressure sensor.

Delivery.

The tool can be delivered with the barrier by being placed on the same string as the barrier and delivered to the well with it. It can be retrofitted downhole and passed through the annulus. It is generally connected to a plug or hanger, the plug or hanger in turn being connected directly or indirectly, for example by tubular members, to the O-ring. The plug may be a bridge plug, a wireline-fixed tubular/drill pipe barrier, a closure tool, or a stop plug such as a cementing plug. The plug may be a temporary or permanent plug.

Also, a tool can be provided in the well, then the barrier is delivered and placed on top of it, and then, after the barrier is lowered, the method described herein is performed.

In some embodiments, the apparatus may be delivered into the center channel of an already existing tubular in the well rather than into the already existing well annulus. The annulus may be formed between the tool and the tubular element already in the well.

The container, if present, can be sealed at the surface and then delivered to the well. The term at the surface in the context of this document generally refers to the outer part of the well, although it may be sealed while shallow in the well, for example, no more than 30 meters from the surface of the well, which is the top of the uppermost casing of the well. Thus, the apparatus is moved from the surface and placed under the barrier with the container sealed until the control device is activated.

The container opening may be provided within 100 m of the perforations between the well and the reservoir, optionally within 50 m or 30 m. If more than one perforation is present, the nearest perforation is used to determine the distance from the apparatus opening. Thus, optionally, the opening in the container may be located at a distance below the perforations in the well. This may assist in the removal of post-perforation debris from the perforation(s) to facilitate cleaning.

The plurality of apparatuses and optional barriers described herein may be run on the same string and, for example, spaced apart and placed adjacent to the same site or isolated sites. Thus, the tool can be lowered into the well with a plurality of isolated areas adjacent to different zones. In this case, there may be no direct access from the area under the perforating devices to the lower zone(s). Thus, when running such a string, embodiments of the present invention provide a means of operating in such a zone.

Additional Information.

The well may be a subsea well. Wireless communications can be especially useful for subsea wells, since running cables into subsea wells can be more difficult compared to underground wells. The wellbore may be a deviated or horizontal wellbore, and embodiments of the present invention may be particularly suitable for such wells because they avoid wire rope, cables, or coiled tubing, which may be difficult or impossible to use in such wells.

The well typically includes a casing, and even if the barriers are installed in the casing or liner, the perforating device may be located adjacent to the open hole to increase connectivity, particularly where pores in the formation may be at least least partially blocked by the filter cake. Therefore, the barriers may be located on the casing string, the liner string, or (less often) against the wellbore. In certain embodiments, the lower of the first and second barriers is located on the liner and the upper of the first and second barriers is located on the casing.

If the barriers are installed in a casing or liner, the wellbore cross section is determined by the cross section of the casing or liner where the barrier is installed. (In any case, cement is usually present between the casing/liner and the wellbore). If the barriers are installed in an open hole section, the wellbore cross section is formed by the wellbore. If the barrier is spaced apart by two or more parts, the borehole cross section is formed by the outside diameter of the part of the borehole with the outermost part of the barrier; the important feature is that the barrier isolates the area below it.

Reference herein to a perforating device includes downhole perforators, punches or drills, all of which are used to create a perforation within the reservoir into the well.

The volume of a container is its fluid capacity.

Transceivers that have transmit and receive functionality may be used in place of the transmitters and receivers described herein.

Unless otherwise noted, any references herein to the terms locked or unlocked may refer to partial locks and partial unlocks.

All pressures in this document are absolute pressures unless otherwise noted.

The well is often at least partially vertical well. However, it may be a deviated or horizontal well. References to such terms

- 14 042605 both above and below when applied to deviated or horizontal wells should be considered as their equivalents in vertically oriented wells. For example, the term above means closer to the well surface through the well.

The term zone is defined herein as the formation adjacent to or below the lowest barrier, or the portion of the formation adjacent to the well that is partially isolated between the barriers and that has, or will have, at least one communication channel (e.g., a perforating hole) between the well and the surrounding formation between the barriers. Thus, each additional barrier installed in the well forms a separate zone, except for the areas between the two barriers (eg, double barrier), in which communication channels to the surrounding formation are not and will not be formed.

The term killing fluid means any fluid, sometimes also referred to as weighted killing fluid, that is used to provide a hydrostatic head, typically sufficient to overcome reservoir pressure.

References to cement in this document include a cement substitute. The hardening cement substitute may include epoxies and resins, or a non-hardening cement substitute such as from Sandaband™.

Embodiments of the present invention will be described in the following, by way of example only, with reference to the accompanying drawings, in which:

in fig. 1 shows a schematic sectional view of a first embodiment of a well and a downhole tool that can be used in the method of the present invention through the use of acoustic signals;

in fig. 2 shows a schematic sectional view of a second embodiment of a well and a downhole tool that can be used in accordance with the method of the present invention through the use of electromagnetic signals;

in fig. 3 is a schematic cross-sectional view of a third embodiment of a well and a downhole tool used to perform a short interval test according to the method of the present invention; and in FIG. 4 is a schematic view of a floating piston container used in certain embodiments.

In FIG. 1 shows a downhole tool 10 comprising a abandoned well 14, a liner 12a, and a casing 12b. Within each of the liner 12a and the casing 12b is an annulus 90A and 90C, respectively, and between the bridge plugs 22a and 22b is an annulus 90B. Downhole apparatus 10 additionally contains a hanger 29 of the secret column. The secret column hanger 29 is a part of the secret column suspension assembly from which the secret column 12a can be hung.

The string is located in well 14 and is divided into a lower tubular 16a, an intermediate tubular 16b, and an upper tubular 16c. Bridge plugs 22a and 22b form barriers, each of which is located along the entire cross section of the well and is installed in the liner 12a and casing 12b, respectively, extending along the well 14 and dividing the well 14 into three sections. Upper tubular 16c, intermediate tubular 16b, and lower tubular 16a provide a continuous physical connection downhole to improve acoustic communication. Since there are many different options, the intermediate tubular element 16b is more likely to be engaged in or attached to the barrier 22a; while the tubular members 16a and 16b may be continuous and the barrier/bridge plug 22b may be formed from a packer member and a center plug.

Two holders 40 and 46 of the device are located on the upper tubular element 16c. Each of the holders 40 and 46 of the device contains an acoustic repeater 44, 49, respectively. Additional device holder 30 is located on an intermediate tubular element 16b between bridge plugs 22a, 22b and contains a pressure sensor 32 connected to an acoustic repeater 31. Repeaters 44, 49 contain transceivers that can receive control signals from the surface 11 and send them to the area under the bridge plug 22a to a wireless transceiver (not shown) of the tool 50, optionally via an acoustic repeater 31. Similarly, repeaters 44, 49 can receive data from the area below the bridge plugs 22a and 22b and send it further, for example, to the surface 11 of the well.

The well surface 11 includes a cap 13 that covers the well 14. The cap 13 includes a transceiver 17 combined with a cable 15. The transceiver 17 is configured to convert wired signals into acoustic signals to be sent to the well 14 to the acoustic repeaters 31, 44 and 49 or vice versa.

In this embodiment, well 14 contains a plurality of sections. The first top portion includes the top tubular 16c, instrument holders 40 and 46, and bridge plug 22b. The second middle section contains an intermediate tubular element 16b, a tool holder 30 and a countersunk column hanger 29. The third lower section contains the lower tubular element 16a, the lower

- 15 042605 bridge plug 22a and apparatus 50.

The apparatus 50 is located below the lower tubular member 16a and includes a tracking mechanism 51 having a pressure sensor (not shown), a control mechanism comprising a gun controller 52 and a wireless transceiver (not shown), and a battery 63. The apparatus 50 also includes a downhole gun 54 surrounded by outer casing 60, and a hollow container 57 extending collinearly from the downhole perforator 54.

The control mechanism components (wireless transceiver and gun controller 52) are typically located adjacent or closer to each other, but may be spaced apart.

In use, before the tool 50 is lowered into the well 14, the inside of the downhole gun 54 and the hollow container 57 are in fluid communication with each other and sealed at atmospheric pressure at the surface so that when the tool 50 is lowered into place in the well 14, they have a reduced pressure, ie, they have a negative differential pressure with respect to well 14. The shaped charges are provided to the downhole gun 54. In the first case, the body 60 of the downhole gun 54 is intact.

The apparatus 50 is lowered into the well 14 and a barrier is placed above it.

The downhole perforator 54 is controlled by the perforator controller 52. The wireless transceiver of the control mechanism is configured to receive an acoustic control signal from the transceiver 17 of the cap 13, optionally via repeaters 31, 44 and 49. The operator sends a control signal to activate the downhole perforator 54 via cable 15 to the transceiver 17, from where it is then sent acoustically to the well 14 to the wireless transceiver in the control mechanism.

The gun controller 52 then activates the downhole gun 54 in response to the control signal, which causes the shaped charges to detonate and pierce the liner 12a, thereby creating perforations 56 in the liner 12a. In use, shaped charge detonation creates openings 55 in the body 60 of the downhole gun 54. These holes 55 provide fluid communication between the inside of the downhole gun 54/attached container 57 and its outside. Thus, in this embodiment, a pressure differential occurs between the interior of the perforator 54/reservoir 57 and the surrounding portion of the well 14. Creation of the holes 55 causes fluid to be released into the perforator 54/reservoir 57 due to the pressure differential, which removes any debris in the tool 50 or around it, in particular the perforations 56. (The term debris here and throughout the text includes perforation debris, filter cake, kill fluid, drilling mud, and loss control material.)

A tracking mechanism 51 containing a pressure sensor tracks the well 14, which can be used to evaluate the nature of the reservoir. Moreover, well operations in offset wells can be monitored from the well of FIG. 1, which can also be used to infer the characteristics of a collector so that, for example, it can be used more appropriately.

The data from the tracking mechanism 51 may be sent acoustically, either continuously, or optionally periodically, to the area uphole 11 and then to the operator via wire cable 15, or alternatively, in the case of a subsea well, via an underwater acoustic modem.

Thus, in contrast to the known use of perforating guns to create flow paths for production, in the present embodiment they are used during or after the shutdown or abandonment of a well under a barrier to provide similar tracking functionality.

An advantage of embodiments of the present invention is that the removal of debris from perforations or the surrounding formation allows data to be collected and sent to the surface that is more indicative of reservoir conditions.

In alternative embodiments, the downhole gun may be activated during the abandonment operation, that is, after the installation of the first barrier and before the installation of the second barrier.

Tank 57 provides more volume for a stronger ejection effect. However, in alternative embodiments of the present invention, a container is not required, but a negative differential pressure effect can be relied upon using the interior of the perforating device. In an alternative variation of the embodiment of FIG. 1, the vessel can be removed, shortened, or stretched by removing or adding additional sections of tubing to create a smaller or larger pressure drop when the shaped charges are fired.

In certain embodiments, the vessel may have an additional opening independent of the downhole gun that may be sealed by a valve, for example, such a valve may be controlled to open to create an auxiliary release from the vessel at a later time than the initial release provided by the inside of the downhole perforator.

- 16 042605 radiator.

In alternative embodiments, only the lower tubular and the intermediate tubular are included, but not the upper tubular, hence the tubular is not above the bridge plug 22b. In such embodiments, one possibility is to attach repeaters to the interior or exterior of the casing.

In FIG. 2 shows an embodiment of apparatus 150 in which activation of a negative differential pressure vessel is dependent on downhole perforators. Parts similar to those of the embodiment of FIG. 1 are not described in detail, however, they are preceded by the number 1. In FIG. 2 shows a abandoned well 114 including a packer 122a, two bridge plugs 122b, 122c, a cement seal 120, and a cap 113 on top of the well 111. Compared to FIG. 1, fig. 2 is based on electromagnetic coupling and therefore contains only the lower tubular element 116a. A packer 122a seals the annulus at the top of the lower tubular 116a, and a bridge plug 122c seals the wellbore near the top of the lower tubular 116a. Bridge plug 122b seals the entire cross section of the well, as does the combination of bridge plug 122c and packer 122a. Between the bridge plugs 122b and 122c and directly below the bridge plug 122b is an electromagnetic tool holder 121 containing a transceiver 123.

The communication device 119 provides a contact located at a distance from the abandoned or abandoned well 114 for transmitting and receiving electromagnetic signals. The communication device 119 is also capable of storing data for later retrieval.

Just as in the embodiment of FIG. 1, apparatus 150 includes a downhole gun 154, a battery 163, a tracking mechanism 151 with a pressure sensor (not shown). It also contains control mechanisms, albeit for a valve, as well as a separate control mechanism for the downhole gun, with each control mechanism containing a wireless transceiver (not shown) and a valve control device 166, as well as a gun controller 152, respectively.

The shaped charges are located in the downhole gun 154 and when activated they create holes 158.

However, unlike FIG. 1, a container 159 is located at a distance below the downhole gun 154 at the end of the lower tubular 116a. The container 159 has an opening 155 and a valve 162 controlling the opening 155. Compared to FIG. 1, the second control mechanism includes a valve control 166 that is provided to control the valve 162, along with an additional wireless receiver (or transceiver) (not shown). The container 159 may have a capacity of, for example, 1000 liters.

Regardless of the operation of the downhole perforator 154, the valve 162 is configured to block and isolate the opening 155 to seal the container 159 from the surrounding part of the well 114 in the closed position and provide hydrodynamic communication and fluid communication between the part of the container 159 and the surrounding part of the well 114 through the opening 155 in open position. In use, valve 162 is moved from a closed position to an open position in response to a wireless control signal.

In some embodiments, container 159 is filled with a gas, such as air, initially at atmospheric pressure. In such embodiments, the gas is sealed in reservoir 159 at the surface prior to being lowered into well 114. This helps create a pressure drop of, for example, 1000 psi. inch to 10,000 psi inch, between the container 159 and the surrounding part of the well 114 (the pressure in which is higher than atmospheric pressure at the surface).

After operation of the downhole gun 154, as described above with respect to FIG. 1, container 159 may be used to pressurize container 159 to clear debris in and around perforations/formation prior to tracking well 114 or an adjacent reservoir.

In use, valve 162 is initially in the closed position. An electromagnetic signal is sent to a wireless transceiver (not shown) by the operator, optionally via transceiver 123. The gun controller 152 then activates the gun 154 in response to the control signal so that the shaped charges detonate and pierce the body 160 of the gun 154 as well as the liner 112a, creating perforations 156 in the countersunk column 112a. An electromagnetic signal is then sent, optionally earlier or much later, to an additional transceiver which instructs valve control 166 to open valve 162 controlling port 155. The differential pressure in container 159 causes fluid to be expelled into container 159 through port 155.

Once the debris has been relatively removed from well 114, the tracking mechanism 151 may then more effectively track the reservoir, or optionally track the impact on the reservoir of well interventions in other wells connected to the reservoir, and may transmit data electromagnetically to the area uphole 111. Cable 115 and connecting the connection box 119 form a spaced contact for detecting and transmitting electromagnetic signals, while the connection junction box 119 is used as an interface for the receiving system

- 17 042605 local and remote data and management.

In some embodiments, the vessel may have a positive differential pressure, or have a positive differential pressure portion such that the area of increased pressure is compared to the surrounding portion of the well. In such embodiments, upon opening of the valve, fluid is released from the reservoir into the surrounding wellbore. The apparatus is particularly suitable in this case for delivering acid for acid treatment. The container may be filled with hydrochloric acid or other acids or chemicals used for such so-called acid treatments. Acid cleaning typically treats the surface of the wellbore, or may treat scale in the wellbore, or may be performed to help reduce debris from perforations or other surface damage. Acids can be directed to specific areas, for example using holes in a pipe. The opening may comprise a pipe extending along the wellbore with a plurality of openings. The acidizing agent then travels along the pipe and exits the well at the proper location. A positive differential pressure vessel may be used instead of a negative differential pressure vessel. Alternatively, a pressure equalized vessel containing a pump may be used to deliver the acidizing agent in place of a positive differential pressure vessel. Optionally, an array of discrete temperature sensors (not shown) may be used along the perforator to monitor the acid treatment and the reservoir.

In some embodiments, the valve may also be opened prior to activation of the perforating device. Optionally, the same container is used to clean debris from the wellbore both before and after activation of the perforating devices, but in some embodiments, more than one container or more than one chamber in the container may be provided. For example, one container/chamber can be used to clean the well prior to activation of the perforating device, and the second can be used after.

In certain embodiments, the valve may be opened immediately upon activation of the perforators. In other embodiments, the valve opening may be delayed for some time after the operation of the downhole perforator. Similarly, activation of downhole guns may be delayed after the barrier has been installed. They can be activated, for example, immediately prior to testing in an adjacent well. Activation of downhole perforators may also occur after the rig attached to the well is retrieved.

In some alternative embodiments, one or a first set of shaped charges located in a downhole gun may be detonated to a second or second set of shaped charges.

In further embodiments, a plurality of perforators may be present, with each perforator being separated by a barrier such as a bridge plug or packer.

In FIG. 3 shows a further embodiment of apparatus 250. Parts similar to those of the embodiment of FIG. 2 are not described in detail, but they are preceded by the number 2. In FIG. 3 shows a abandoned wellbore 214 including two bridge plugs 222a and 222b and two packer elements 270a and 270b between the lower tubular element 216a and the liner 212a. The two packer elements 270a, 270b are spaced apart along the well 214 and form a short interval. Like the embodiment of FIG. 2, fig. 3 is based on electromagnetic coupling.

Apparatus 250 of FIG. 3 contains a valve 262, a fitting 276, an opening 255, a control mechanism with a wireless receiver or transceiver (not shown) and a multifunctional control device 266, a battery 263, a tracking mechanism 265 with a pressure sensor, and a container 259, the capacity of which may be, for example, 100 liters. . Between the container 259 and the surrounding part of the well 214 there is a pressure drop in a short interval between the elements 270a and 270b of the packer.

The battery 263 powers the components of the apparatus 250, such as the multifunction controller 266, the tracking mechanism 265, and the transceiver. Often a separate battery is provided for each powered component. In alternative embodiments, a downhole power generation plant may be used, for example, through the production of thermoelectricity.

Nozzle 276 is located adjacent valve 262, optionally located at a distance from the valve, in bypass 261 between opening 255 and reservoir 259. The rate at which fluid enters reservoir 259 is controlled by the cross-sectional area of nozzle 276. In alternative embodiments, implementation the positions of the fitting 276 and the valve 262 may be in the reverse order of that shown, or they may be combined into one component.

Compared to the embodiments of FIG. 1 and FIG. 2, the embodiment of FIG. 3 includes a single hole puncher 254 258 which, when used, creates a single punch hole 256 in the countersunk column 212a. Unlike FIG. 2, 254 puncher and valve

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262 of FIG. 3 are controlled by one multifunction controller 266 and one wireless transceiver.

The opening 255 of the container 259 is located in a short interval between the elements 270a and 270b of the packer. The gun 254 is also located within a short interval such that, in use, the gun 254 is activated and creates a perforation 256 in a short interval to provide fluid communication between the reservoir (not shown) and the surrounding wellbore 214 in a short interval.

The well may be operated upon, such as an inflow test, whereby flow from the reservoir is formed in a specified short interval and passed through the apparatus. In use, the packer elements 270a and 270b are initially installed in the liner 212a to define a short interval for testing. The multifunction control device 266 then receives an electromagnetic control signal to activate the punch 254, which creates a perforation 256 in the liner 212a or adjacent formation (not shown) to provide fluid communication between the formation and the surrounding wellbore 214 in a short interval.

The multifunction control device 266 then receives an additional control signal to open the valve 262. The container 259, which has a negative differential pressure, can then receive flow in a controlled manner from the perforated interval between the two packer elements 270a and 270b.

Debris in or around the perforation 256 is also drawn into the container 259 due to this pressure drop, which helps clean up the surrounding well 214 in a short interval. The negative differential pressure effect is concentrated in a short interval, which increases the radius of the reservoir it affects. This can improve well flow and provide more accurate data from the flow test.

The pressure is monitored by the tracking mechanism 265 both prior to the opening of valve 262 and during the entry of flow into vessel 259 at a rate controlled by fitting 276.

Valve 262 is closed prior to a significant pressurization of vessel 259. Therefore, a relatively limited inflow test can be performed in the short interval between packer elements 270a and 270b. Data from the tracking mechanism 265 or other sensors in close communication, such as between two packer members 270a, 270b, or under the lower packer member 270a in bypass 261 adjacent choke 276, can provide useful flow test information. Reservoir response to flow test and buildup curve test can provide useful information about reservoir performance.

An advantage of certain embodiments of the present invention is that short interval flow tests can be performed with barrier(s), such as bridge plugs and packers, in place, as this can improve well safety. The barrier(s) may also allow short interval testing at the same time as other well operations and operations that are performed over the barrier(s). This can save time.

In some embodiments, after the liner has been perforated, the well may be observed for a short period of time, for example, flow from the well into the vessel may occur at a low rate for no more than 24 hours. In some embodiments, the well may be monitored while the well above the barrier is abandoned.

Many alternatives are available for such a short interval inflow test. Two or more such inflow tests may be carried out. In one embodiment, valve 262 may be opened again and additional fluid may enter reservoir 259. This open/close sequence may be repeated as long as reservoir 259 is full. Alternatively or in addition, additional negative differential pressure tanks may be provided for additional inflow test(s).

As an additional option, a second negative differential pressure vessel is provided that can be used for a short interval purge prior to using apparatus 250 to perform a short interval inflow test as described above.

In some embodiments, reservoir 259 or additional reservoirs may be pressurized with respect to the surrounding wellbore 214 in a short interval. In such embodiments, the apparatus may be used to perform an interval injectivity test/procedure, permeability, well/reservoir treatment, hydraulic fracturing, mini-fracturing, or similar test/procedure that may require application of pressure between two annulus sealing devices, for example, between two packer elements 270a and 270b forming a short interval. A similar effect can be achieved with a pump instead of a sealed container. In any case, the effect is concentrated in the short

- 19 042605 interval and, therefore, more penetrates into the reservoir.

In alternative embodiments, a short barreled perforator may be used instead of a press perforator.

A particularly suitable apparatus for use in FIG. 3 is shown in FIG. 4. The apparatus of FIG. 4 contains an opening 355, a valve 362, a fitting 376 and a control mechanism with a multifunctional control device 366 and a wireless receiver (or transceiver) (not shown), as well as a container 357. The valve 362 and fitting 376 are located in the central part of the apparatus in the opening 379 between two sections of the container 357: the chamber 371 for the fluid and the chamber 381 reduced pressure.

The floating piston 375 is housed in the fluid chamber 371. The fluid chamber 371 is initially filled with oil below the floating piston 375 through a fill port (not shown). If the floating piston 375 is located on top of the fluid chamber 371, it isolates/closes the fluid chamber 371 from the surrounding wellbore, and if the floating piston 375 moves down the fluid chamber 371, the opening 355 allows fluid to pass into the chamber 371 for fluid through the opening 359 to flow from the outside of the container, typically the surrounding portion of the well. The position of the floating piston 375 is controlled indirectly by the flow of fluid through the valve 362, which, in turn, is controlled through signals sent to the multifunction control device 366.

In use, the sequence begins with the valve 362 in the closed position and the floating piston 375 located near the top of the fluid chamber 371. The passage of fluid in the well into the fluid chamber 371 through the opening 355 is prevented by the floating piston 375 and the oil below it while the valve 362 is in the closed position. A signal is then sent to the multifunction control device 366 which instructs the valve 362 to open. When valve 362 is opened, oil from fluid chamber 371 is directed into reduced pressure chamber 381 by well pressure acting on floating piston 375, and fluids from the surrounding wellbore are drawn into fluid chamber 371. The rate at which the oil in the fluid chamber 371 is pushed into the reduced pressure chamber 381, and therefore the rate at which wellbore fluids can be drawn into the reservoir 357, is controlled by the cross section of the choke 376.

Alternatively, a pump may be used in place of the negative differential pressure in the vessel to draw fluids into the vessel.

An advantage of the embodiment of FIG. 4 is that the floating piston and choke can help control the rate of passage of wellbore fluids and debris from the surrounding wellbore into the reservoir, which can provide more accurate data and hence more accurate well and reservoir analysis.

Changes and improvements may be made without departing from the scope of the present invention. For example, the features in Fig. 1 and FIG. 2 can be combined so that the apparatus can contain more than one negative differential pressure vessel, and control signals can be transmitted acoustically and/or electromagnetically. Similarly, the embodiment of FIG. 3 may be based on acoustic coupling instead of or in addition to electromagnetic coupling.

Moreover, the figures show the well in a state of conservation. Prior to the step shown in the figures, the drilling rig may be attached to a well that is not capped. The first barrier may be placed and then the perforating device may be activated while the rig is still present prior to the second barrier being placed. After these steps, a second barrier will be installed and, subsequently, the connection to the rig will be broken and the hood will return to its place.

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Claims (23)

CLAIM 1. The method of studying the reservoir between the first well and the second well, including: in the case of a first well with a cross section, installing at least one barrier in the first well such that the first well is divided into a lower pressure-isolated section under the at least one barrier and an upper section above the at least one barrier; at the same time, in the lower pressure-isolated section, an apparatus is located, containing: a perforating device; a control mechanism for controlling the perforating device, comprising a wireless communication device configured to receive a wireless control signal for activating the perforating device; pressure meter; sending at any time a wireless control signal to the wireless communication device to activate the punching device, wherein the wireless control signal is transmitted in at least one of the following forms: electromagnetic, acoustic, via inductively coupled tubular elements and coded pressure pulses; activating, after installation, at least one barrier of the perforating device to create at least one perforation between the first well and the surrounding reservoir; conservation or elimination during or after the installation of at least one barrier of at least a zone adjacent to the specified lower pressure-isolated area; after activation of the perforating device and after conservation or liquidation of the specified area: (i) monitoring the pressure in the lower pressure-isolated portion under the at least one barrier using a pressure sensor; and (ii) sending a wireless data signal containing pressure data from a region below the at least one barrier to a region above the at least one barrier using at least one of electromagnetic coupling, acoustic coupling, and inductively coupled tubulars. 2. The method according to claim 1, characterized in that it includes monitoring pressure changes caused by activities in the additional well. 3. The method according to claim 1 or 2, characterized in that at least one barrier is installed prior to sending the wireless control signal to the wireless communication device, thus the wireless control signal is sent from the area above the at least one barrier to the wireless communication device to the area under at least one barrier to activate the perforating device. 4. The method according to any of the preceding claims, characterized in that the perforating device is activated less than a week after the installation of at least one barrier. 5. The method according to claim 2 or 3, characterized in that the perforating device is activated more than one month after the installation of at least one barrier. 6. A method according to any one of the preceding claims, characterized in that at least one barrier comprises a bridge plug or packer plug. 7. A method according to any one of the preceding claims, characterized in that at least one barrier is formed from a central portion and a portion of the annulus, the central portion being in or below the portion of the annulus. 8. Method according to any one of the preceding claims, characterized in that at least one barrier comprises a column of cement or cement-like material having a height of at least 2 m. 9. Method according to any of the preceding claims, characterized in that at least one barrier remains in place for at least 1 month, at least 3 months, or at least 6 months, and optionally for at least 1 year or more than 5 years. 10. The method according to any of the previous paragraphs, characterized in that the entire first well is mothballed or liquidated. 11. The method according to any of the preceding claims, characterized in that at least one barrier is a first barrier, and at least one second barrier is installed above the apparatus in such a way that at least one second barrier prevents hydrodynamic communication and fluid communication environment along the entire cross section of the first well, thereby isolating a section of the first well underneath, optionally, the perforating device is activated after the installation of at least one second barrier. 12. The method according to any one of the preceding claims, characterized in that the apparatus comprises a container, and the method includes driving a fluid through an opening between the interior and exterior of the container. - 21 042605 13. The method according to claim 12, characterized in that immediately prior to the movement of the fluid through the hole, the pressure inside at least a portion of the container is at least 500 psi. inch below or at least 500 psi. inch higher than the pressure outside the container. 14. A method according to any of claims 12 or 13, wherein the opening is a pre-existing opening in the container and the wirelessly controlled control device enables or prevents fluid from flowing between the interior and exterior of the container through the opening. 15. Method according to any one of claims 12 to 14, characterized in that the container has a volume of at least 5 liters or at least 50 liters, optionally at least 100 liters. 16. The method according to any one of claims 12-15, characterized in that the container is sealed on the surface and then delivered to the first well, thus the apparatus is moved from the surface to the first well with the sealed container. 17. The method according to any one of claims 12-16, characterized in that the hole is located between the first part of the packer element and the second part of the packer element, and the perforation is created between the reservoir and the first well, and also between the two parts of the packer element(s) , while performing a test in a short interval. 18. The method according to claim 17, characterized in that the parts of the packer element are separated by less than 10 m, optionally less than 5 m, or less than 2 m, or less than 1 m, or less than 0.5 m. 19. A method according to any one of the preceding claims, wherein the lighter fluids are circulated in the first well to reduce the hydrostatic head in the first well, optionally to a pressure that is less than the pressure in the reservoir, and at least one barrier is installed at the time when the hydrostatic head in the first well is reduced. 20. The method according to any one of the preceding claims, characterized in that the apparatus is configured to monitor pressure or other parameters under at least one barrier for more than one week, one month, one year, or more than five years. 21. The method according to any one of the preceding claims, further comprising the use of an apparatus for carrying out a level-down test, an inflow test, a pressure build-up curve test, a connectivity test such as a interference test or an interference test, an injectivity test in the interval or pressure test. 22. The method according to any one of the preceding claims, characterized in that a group of discrete temperature sensors or a distributed temperature sensor are placed under at least one barrier. 23. A method according to any one of the preceding claims, characterized in that at least one of the wireless data signal and the wireless control signal is transmitted as at least one of electromagnetic signals and acoustic signals. -