EA039961B1 - WELL MONITORING METHOD - Google Patents

Description

The invention relates to a downhole monitoring method, in particular, but not exclusively, during plugging and abandonment or conservation operations.

A conventional well design comprises a wellbore having at least one tubular casing cemented in place relative to the subsurface.

When the well is no longer required, the well is known to be plugged and abandoned by plugging it with cement or an alternative to cement. For this purpose, a barrier may be added to control the well and the milled section of casing (and any adjacent cement) above it. A section of the formation can also be cut with a reamer. Fresh cement is then poured into this area to create a cement seal throughout the wellbore, connecting it to the subsurface.

In an alternative plugging process, the well may be perforated with a downhole perforator, any old cement in the annulus between the casing and the formation is flushed out, and new cement is delivered through the entire wellbore and circulated through the perforations into the annulus to connect to the formation.

In either case, a cement plug or barrier is formed which, among other things, is intended to prevent fluids from flowing out of the well after abandonment.

Similar methods can be used for well conservation.

While this is generally adequate, the present inventors have noted that it is difficult to assess the integrity of such a cement plug.

According to a first aspect of the present invention, a downhole monitoring method is provided, comprising:

installation of at least one barrier in a cased wellbore, the at least one barrier comprising a column of fluid sealing material, such as cement, having a height of at least 2 m, so as to counteract hydrodynamic coupling and fluid communication throughout the wellbore wells, thereby dividing the wellbore into a lower section under at least one barrier and an upper section above at least one barrier;

connecting said column of fluid sealing material to a portion of the formation that defines a portion of the wellbore;

wherein at least a portion of the lower section is cased with a casing, thereby defining an annulus between the surrounding formation and the casing;

at the same time, a node containing a perforating device is provided in the lower section;

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

pressure meter;

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

after installing at least one barrier, activating the perforating device to create at least one perforation through the casing;

after activating the perforating device:

(i) typically monitoring the pressure in the lower section under at least one barrier using a pressure sensor; and (ii) generally sending a wireless data signal containing pressure data from the area below the at least one barrier to the area above the at least one barrier using at least one of electromagnetic coupling and acoustic coupling.

By activating the perforating device to create a perforation in the casing, a path can be created from the interior of the casing to the formation.

By creating at least one perforation between the wellbore and the casing, a fluid flow path is opened in any pre-existing cement, the pre-existing cement being located between the casing and the formation. Thus, any additional leakage path in the annulus between the formation and the casing, and in particular any damage to the connection/seal of at least one barrier to the surrounding formation, can be determined using the various pressure tests described herein.

After step (ii), the method may include (iii) evaluating whether the lower section is isolated or to what extent it is isolated.

Step (iii) may include evaluating whether the lower section is isolated or to what extent it is isolated from the upper section over at least one barrier. Whereas setting the barrier to

- 1 039961 location in the well opposes hydrodynamic communication and fluid communication and is usually designed to seal or isolate the entire barrier, it is usually necessary to evaluate whether the seal has actually been made and whether the upper and lower sections are properly isolated.

The method may include monitoring the pressure for some time to assess whether the lower section is isolated or to what extent it is isolated. The time may be, for example, more than 15 minutes (for example, for pressure testing), more than 4 hours, or much longer, for example, more than one day, more than a month, more than a year, or more than five years (for example, for long-term monitoring of barrier integrity).

Prior to activating the perforating device to create perforations, a prior pressure test may be performed.

The pressure sensor may be located at a distance from the remainder of the assembly. In one embodiment, the perforating device is located at a distance from the combination of cordless tool and pressure transducer, although various other combinations are possible since the assembly may not be provided assembled. Despite this, the node can be called a device.

The method may include the step of monitoring pressure above and below said at least one barrier before, during or after perforation.

The method may include cleaning a portion of the formation, thereby removing at least a portion of any pre-existing cement or other debris, such as mud or filter cake, to at least partially clean the formation and therefore improve bonding with the seal fluid.

This can be done through one (or more) of milling, perforating, melting, acidizing, or dissolving, or creating an explosion. Then at least one barrier is installed at least partially in the specified area. Pre-existing cement is generally placed between the casing and the wellbore prior to removal/perforation/melting, etc. of the casing.

In particular, the step of cleaning said area may include removing, for example, milling, a portion of the casing and at least a portion of any pre-existing cement in contact with the formation in said area.

In certain embodiments, the step of cleaning said area includes a prior step of perforating a portion of the casing in said area and flushing out at least a portion of any pre-existing cement in contact with the surrounding formation.

Optionally, an upper perforating device is provided, wherein the upper perforating device is provided in the upper portion above the at least one barrier, and the method includes creating at least one perforation between the wellbore and the casing above the at least one barrier.

The top and bottom portions may be adjacent to the top and bottom zones, respectively.

The portion of the formation to which the fluid column is connected is typically the impermeable portion, i.e. there is no fluid flow path through it, and is often referred to as overburden. The perforations may also be adjacent to a similar impermeable portion of the formation.

The method can be used for the conservation and abandonment of a section or adjacent zone of the wellbore/well or the entire well/the entire wellbore.

The at least one barrier containing a column of flowable sealing material (often cement) may also contain other components such as a sealing or non-sealing hanger, bridge plug, or packer. A pressure transducer may be provided between the fluid sealing material portion and other components, such as a bridge plug, and in the pressure tests described herein, this can help confirm whether or not it is a pressurized fluid sealing material barrier. .

The fluid sealing material may include cement, or an alternative to, or a substitute for, cement. The fluid sealing material is fluid, at least during delivery, and may or may not set/solidify.

References to setting a barrier should be considered as placing the barrier, not curing/hardening the barrier.

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

Hereinafter, the flowable sealing material is often referred to as cement.

An additional option for a fluid sealant/alternative to cement/substitute for plugging and abandonment is to melt (or more broadly create an oxidizing reaction) the tubulars and/or part of the surrounding formation. For example, for this

- 2 039961 whether thermite can be used. Thermite may be a mixture of fuel from a metal powder and an oxide, such as iron oxide.

Whereas 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 before the wireless control signal is sent to the wireless communication device, so that 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 / around / around the barrier.

The punching device can be activated immediately after, or more than a week, or more than a month after the installation of the barrier / preservation / 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 a lower section/lower zone, not necessarily the entire wellbore/entire well, so that operations such as well testing or development of another zone may continue in another section/zone. Alternatively, the entire wellbore/entire well may be mothballed or abandoned.

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

Therefore, preferably the barrier is generally a permanent or semi-permanent barrier, since it remains in place for a period of at least one month, optionally more than three months or more than six months. Of course, the barrier may remain in place for much longer, such as more than a year or more than five years. Accordingly, during such periods, flowing to the surface will not occur.

A wellbore/well abandonment is a situation in which no recurrence of the wellbore/well flowing fluids to the surface is expected or exists. Therefore, the barrier is typically a permanent barrier, as it remains in place indefinitely.

double barrier

Two or more such barriers and optionally two or more such assemblies may be provided in the well. Therefore, at least one barrier may be the primary barrier and at least one secondary barrier, which may comprise a column of fluid sealing material, may be positioned below the assembly such that the at least one secondary barrier resists fluid communication and communication. fluid throughout the wellbore, thereby isolating the section of the wellbore between the primary and secondary barriers from the section of the wellbore below the secondary barrier.

For such embodiments, the secondary barrier will typically be installed first.

The pressure sensor may be a primary pressure sensor and the wellbore may include an auxiliary pressure sensor under at least one secondary barrier.

For such embodiments, optionally, the node is the main node, the punching device is the main punching device, the control mechanism is the main control mechanism, and the wireless communication device is the main wireless communication device, and the auxiliary node can be provided under at least one auxiliary a barrier, and the auxiliary node contains an auxiliary pressure sensor, an auxiliary perforating device;

an auxiliary control mechanism for controlling the punching device and comprising an auxiliary wireless communication device configured to receive a wireless control signal for activating the punching device;

wherein the method may include:

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

after installing at least one secondary barrier, activating the secondary perforating device to create at least one perforation between the wellbore and the casing;

pressure monitoring in the area under the auxiliary barrier using an auxiliary pressure sensor; And

- 3 039961 sending a wireless data signal containing pressure data from the area under the auxiliary barrier to the area above the auxiliary barrier using at least one of electromagnetic coupling, acoustic coupling and inductively coupled tubular elements.

The barrier may comprise or be made of a column of flowable sealing material (e.g. cement) such as a column 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 zonal isolation, while longer cement barriers are typically used for wellbore/well isolation.

The knot can be suspended from the main barrier.

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

In addition to the casing, in certain embodiments, especially those in which acoustic communications are present, the tubular may extend from the primary barrier and/or secondary barrier to the wellbore/well surface. In other embodiments, such as those that use EM communication, this may not be required.

The monitoring step may be performed before and/or after the secondary barrier is installed, optionally placing a cement column in place above the primary barrier.

Therefore, the node / main node components described herein can optionally be duplicated and included in the auxiliary node.

Collector monitoring

The method may also include monitoring the reservoir after the installation of at least one barrier by using an additional node in the wellbore under at least one barrier. Reservoir monitoring typically occurs via a communication path between the wellbore and the permeable portion of the formation, and wireless communications, as described herein, can be used to relay signals and derive data.

The additional assembly may contain an additional pressure sensor.

The method may include providing an additional node adjacent to the manifold, in the lower section, and the additional node contains an additional perforating device;

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

after installing at least one barrier, activating an additional perforating device to create at least one perforation between the well and the surrounding reservoir;

after activating the optional punching device:

(i) monitoring the pressure in the lower section under at least one barrier using the specified or any additional pressure sensor; and (ii) sending a wireless data signal containing pressure data from the area below the at least one barrier to the area above the at least one barrier using at least one of electromagnetic coupling, acoustic coupling, and inductively coupled tubulars.

The additional node may include an additional control mechanism for controlling an additional perforating device.

For such embodiments, the perforating device may be adjacent to the open hole to improve connectivity, particularly where pores in the formation may be at least partially blocked by a filter cake.

Capacity

The assembly or apparatus in certain embodiments of the present invention comprises a container, and the method includes propelling a fluid through an opening between the interior and exterior of the container. The movement of the fluid is preferably directed from the inside of the container to the outside of the container, although it can also be provided in the opposite direction.

The container may be located in various parts of the well or wellbore, typically under the primary(s) (or secondary(s)) barrier(s), optionally between the primary and secondary barrier(s).

The container may be particularly useful for carrying out pressure operations for pressure testing the barrier. It can also be used to restore pressure after a pressure drop.

The occurrence of fluid movement between the interior and exterior of the container may be provided before, during and/or after activation of the perforating device. Co.

- 4 039961 Certainly, it can be delayed for more than an hour, more than a week, more than one month, optionally more than one year or more than five years after activation of the perforating device. For example, it may be activated when work is being carried out in an adjacent wellbore/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 wellbore/well, typically the container may have a volume of at least 5 liters (L) or at least 50 L, optionally at least 100 L. The container may have a volume of not more than 3000 liters, as a rule, not more than 1500 liters, optionally not more than 500 liters.

Thus, the apparatus may comprise a pipe/tubular element (or a sub in the pipe/tubular element part) containing a container and other components, or, in this regard, the container can be made of tubular elements, such as tubing or drill pipe. pipe connected together.

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 cm2, optionally at least 0.25 ^cm2 or at least 1 ^cm2 . 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 opening is created by activating said (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 outer space of the container as a whole is the surrounding part of the wellbore/well. The wellbore/wellbore environment is the part of the wellbore/wellbore that surrounds the apparatus, especially outside of the opening immediately prior to movement of the control device in response to a control signal or opening created by said or any perforating device.

Entering or exiting a container is called fluid movement.

In certain embodiments, a container is positioned adjacent to, above, or below the perforations to clean the perforations. A plurality of containers may be used and provided together or separately in different parts of the wellbore or well.

Control device

The control device may include a mechanical valve assembly, a pump, and/or a latch assembly. The control device typically responds to wireless signals through the specified or any separate wireless device. The control device may or may not be located in the opening. In embodiments with a control device and a pre-existing orifice, 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 adapted 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 again be moved to counteract 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 optionally may 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 it has equalized.

- 5 039961 bone and outer space of the container. The remaining pressure difference can optionally be used later. Thus, the procedure for moving the control device to move the fluid or counteract the 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 its central part. One or more devices may be located in different positions.

The control mechanism may be configured to move the control device to selectively move the fluid or resist the movement of the fluid to/from at least a portion of the container under a certain condition, such as when a certain pressure is reached, such as 2000 psi, or after time delay. Thus, the control signal causing the control device to respond may depend on certain parameters, and different control signals may be sent depending on the appropriate parameters for the specific wellbore/well conditions.

Valve

The control device may include a mechanical valve assembly having a locking member adapted to move to selectively allow or resist fluid flow 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 locking element is directly actuated by the control mechanism, although typically a separate second control mechanism is provided to operate the locking element. It can be controlled electro-mechanically or electro-hydraulically by moving. In other embodiments, the valve is controlled indirectly, such as by moving a piston causing the valve to move.

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 driven by at least one of (i) a motor and 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 a container and/or a pump.

Prior to moving the fluid, the pressure inside the container and outside the container may be different. This pressure difference is greater than the instantaneous one, typically at least one minute and usually longer.

Thus, after a hole is created or a control device is activated to communicate through an already existing hole, fluid moves from a region of higher pressure to a region of lower pressure.

For example, a positive differential pressure vessel (having a pressure that is higher than the pressure outside the vessel/surrounding the wellbore) can pressurize an isolated section of the wellbore.

A negative differential pressure vessel (having a pressure that is lower than the pressure outside the vessel/surrounding the wellbore) is an alternative. 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). It can also be used to perform a pressure test, or when used to assist reservoir monitoring, it can repair damage to the formation, i.e., at least partially unblock any blocked portions and/or free portions of the wellbore and/or surrounding formation; this is often sufficient to improve the pressurized connection between the wellbore and the formation.

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, the fluid may be compacted into 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 wellbore (which has a higher downhole pressure). Thus, the pressure in said portion of the container, which is lower than the pressure outside the container, prior to fluid movement, may be in the range of 14 to 25 psi, which is normal atmospheric pressure, which sometimes rises at higher temperatures.

- 6 039961 tours in the wellbore. Alternatively, the vessel can effectively be evacuated, ie pressurized below 14 psi, optionally below 10 psi.

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

Pump actuation

Alternatively or in addition, the control device may comprise an electric pump for driving fluid through an 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 operated to pump fluid from the reservoir into the surrounding wellbore. Often this amount is at least one liter or more than five liters of fluid that was added to the vessel at the surface prior to lowering the tool into the wellbore. This fluid can be used to create a pressure change to pressure test at least one barrier or to treat the wellbore/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; especially 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 cm ³ /s to 20 cm ³ /s.

The pumping operation or rate may be controlled in response to the receipt of an additional control signal by said or any individual wireless communication device (or it may be an instruction 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. wellbore pressure) and is released/moves in response to an instruction from the controller to provide movement of fluid through the orifice.

The orifice may include a check valve that may resist movement of fluid through it.

The device may contain a fitting.

The fitting may be integral with the control device, or it may be in the flow path containing the opening and the control device.

Said cross-sectional area may contain a filter.

The locking element may function as a choke, an optionally 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

A floating piston may be located in the container, for example, 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 a gas at a higher pressure than the surrounding wellbore to displace the fluid when the control device is in fluid communication. environment between the reservoir and the surrounding wellbore.

In certain embodiments, there is a container and said floating piston without additional chambers. The vessel can be pressurized and then held until the surrounding wellbore/well is at a different pressure. In certain other embodiments, the container may comprise two sections separated by a control device, with one chamber being a fluid chamber and the second chamber being a reduced pressure chamber or transfer chamber. If there is a pressure difference between the interior and exterior of the container, the second chamber is typically the portion of the container having that pressure difference.

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

The floating piston can further separate two sections in the fluid chamber, with

- 7 039961 than one section is in fluid communication with the orifice and another section on the opposite side of the floating piston is in communication with the second chamber.

Thus, one side of the floating piston can be exposed to wellbore 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 lower than the pressure in the surrounding wellbore while the control device includes a valve, thereby indirectly drawing fluids into or counteracting fluids from being drawn into the fluid chamber portion of the container.

Alternatively, the second chamber may be a transfer chamber having a pressure that is higher than the pressure in the surrounding portion of the wellbore. In this case, the control device, which optionally includes a valve, may cause fluids to be expelled or counteract 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.

Thus, in response to a control signal, the control device can move fluid between the container (fluid chamber portion) and the outside of the container, such as a wellbore, 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 tanks

In addition to the container (which is sometimes referred to as the main container hereinafter), one or more auxiliary containers can be provided, optionally each of them contains appropriate control devices that control 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 wellbore/well or another part of the apparatus or formation.

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 send a control signal to a plurality of control devices.

The containers may have an internal pressure different from the pressure outside the container, such as in the surrounding wellbore or formation. If the pressure is lower than outside the container, as described herein in a broader sense, such containers are called negative differential pressure tanks, and if the pressure is higher 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 orifices and controls may be provided, each of the auxiliary vessels preferably having a volume of at least five liters, and in use, has a pumping speed and/or pressure that is lower/higher than outside the container, typically for at least one minute before optional activation of the control device 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 vessel prior to delivering the acidizing agent to the perforations, particularly when combined with reservoir monitoring, using

- 8 039961 using a container controlled by a pump.

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 tapping/pushing.

The auxiliary port may include a check valve that may resist the release of fluid from the container.

Other device options

In addition to the wireless signal, the device may contain pre-programmed sequences of actions, such as opening and reclosing a valve or changing the position of a locking element, based on parameters such as time, detection or non-detection of pressure, or detection of a specific fluid or gas. For example, under certain conditions, the machine will 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.

Reduced pressure in the well

Before the barrier is installed, lighter fluids may circulate in the wellbore, for example, as part of a flow test or for other reasons. This reduces the pressure in the wellbore due to the reduced hydrostatic head of the lighter fluids. In certain embodiments, the barrier may be installed while the wellbore pressure is similarly reduced to a pressure that is below the reservoir pressure. Therefore, the wellbore 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 improve connectivity between the wellbore and the surrounding reservoir.

Often, a heavy fluid is injected into the wellbore to aid in wellbore control.

This heavy fluid can result in poor pressurized connectivity through the perforations between the reservoir and the wellbore. In embodiments of the present invention, a barrier is provided, thereby allowing the reservoir to be perforated in a zone free of such heavy fluid, thus eliminating 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 can be adapted to provide a signal or parameter that is registered by including suitable transmitters and mechanisms. The sensors may also determine the status of other parts of the apparatus or other equipment in the wellbore, 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 apparatus. Thus, they may be located below the barrier, or above the barrier, or even outside the casing. Therefore, preferably they are under the barrier.

These temperature sensors may be located in a small diameter tubing (eg '/ 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 spaced so that the group of temperature sensors located in the tubing line can be aligned throughout the formation, for example, all perforations; or, for example, in general in parallel

- 9 039961 borehole, 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.

Therefore, in this case, an additional group of temperature sensors can provide data from the range(s) of 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 activation of the perforating device, and before, during, or after allowing fluid to flow between the interior and exterior of the container.

Extracting data means extracting data to the surface. The output data may be real time/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 an instruction to transmit.

Memory device

The apparatus, especially the sensor(s), may include a storage device that can 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 storage device and sensors may be connected to each other in any suitable manner, optionally wirelessly, or physically connected to each other using a wire. Inductive coupling is also one option. Short range wireless connections can be improved with EM communications in the VLF band.

The apparatus may be configured to monitor pressure or other parameters below the barrier for periods of time in excess of 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 optionally 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 via coded pressure pulses, and references herein to the term wireless refer to these forms unless otherwise indicated.

The signals may be data signals 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 signals 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 using appropriate control signals.

Coded pressure pulses

Coded pressure pulses can be used to activate the perforating device. The firing head of the perforating device may be above the barrier.

The pressure pulses provide methods for transmitting a message out of or into the well/wellbore, from at least one of the additional locations in or into the well/wellbore, and from the surface of the well/wellbore using positive and/or negative pressure changes, and /or changes in fluid flow in the tubular element and/or the 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. Therefore, pressure pulses used with downhole/wellbore electronic interfaces are defined in this document as coded

- 10 039961 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 to code control signals, such as pressure change or pressure change rate, amplitude shift keying (AMn), pulse phase modulation (PPM), pulse width modulation (PWM), frequency shift keying (FMSK), phase shift keying (PSK), amplitude code keying (AMSK), 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 multiphase fluids, and may be static control fluids and/or fluids produced from or injected into a wellbore.

Signals: general information

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

The EM/acoustic signals and coded pressure pulses use a well, wellbore, or formation as the transmission medium. The EM/acoustic or pressure signal may be sent from the wellbore or from the surface. The EM/acoustic signal may be transmitted through the barrier, although 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 generally higher compared to coded pressure pulses, which especially for borehole data.

Therefore, the wireless communication device may include an acoustic communication device and the wireless control signal includes an acoustic control signal, and/or the wireless communication device may include an electromagnetic communication device and the wireless control signal includes 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 using inductively coupled tubulars, typically at least ten, typically many more, individual sections of inductively coupled tubulars are provided that are joined together in operation to form 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, EM/acoustic wireless signals or wireless pressure signals can be transmitted over a relatively long distance as wireless signals, sent at least 200m, optionally more than 400m or further, which is a clear advantage over other signals. short range. In embodiments incorporating 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 wellbore.

The control signal and optionally other signals may be sent wirelessly from the area above the barrier to the area below the barrier. Similarly, signals can be sent from the area below 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, electrical or fiber optic lines. In one embodiment, the signals may be transmitted over a cable over a first distance, such as over 400

- 11 039961 m, and then transmitted via acoustic or EM links over a shorter distance, such as 200 m. In another embodiment, they are transmitted over a distance of 500 m using coded pressure pulses, and then over 1000 m using a hydraulic line.

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

In the same wellbore, different wireless signals may be used for messages from the wellbore to the surface and for messages from the surface to the wellbore.

Thus, the wireless signal can be sent directly or indirectly to the communication device, for example using repeaters in the wellbore above and/or below the barrier. The wireless signal can be sent from the surface or from a wireline/coiled tubing (or hoist) probe from anywhere in the wellbore 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 vibration transmission of the wellbore structure, which includes tubular members, casing, liner, drill pipe, drill collars, tubing, coiled tubing, pump rod, downhole tools; transmission by fluid (also by gas), including transmission through fluids in open-hole sections of the wellbore, along tubular elements and in 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 infrasonic (<20 Hz), sonic (20 Hz to 20 kHz), and ultrasonic (20 kHz to 2 MHz) frequencies. Preferably the acoustic transmission is audio (20 Hz to 20 kHz).

Acoustic signals and messages may include modulation techniques in the form of frequency shift keying (FSK) and/or phase shift keying (PSK) and/or more advanced versions of these methods, such as quadrature phase shift keying (QPSK) or quadrature amplitude modulation (QAM), and preferably include spread spectrum techniques. Typically, they are adapted to automatically adjust frequencies and acoustic signaling modes to suit wellbore conditions.

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

EM signals

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

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

ELF from 3 to 30 Hz;

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

ULF (ultra-low frequency) from 300 to 3 kHz; And

VLF (very low frequency) from 3 to 30 kHz.

An exception to the frequencies listed above is EM communication, which uses a pipe as a waveguide, in particular, but not exclusively, in cases where the pipe is filled with gas, in which case, as a rule, frequencies from 30 kHz to 30 GHz can be used in 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 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 wellbore to the surface (eg, over 100 m), sub-ELF and/or ELF 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).

EM communications may involve the transmission of a message via one or more of the following:

- 12 039961 giving a modulated current to an elongated element and using the earth as a return path; transferring current to one tubular element and providing a return path to the second tubular element; using the second wellbore as part of the current path; transmissions in the near field or far field; creating a current loop in the part of the metal structure of the wellbore to create a potential difference between the metal structure and the ground; using spaced contacts to create an electrical dipole transmitter; use of a toroidal transformer to supply current to the metal structure of the wellbore; 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; transmissions within the wellbore casing; using an elongated element and earth as a coaxial transmission line; using the tubular element as a waveguide; transmission outside the wellbore 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 part of the metal structure of the wellbore to create a potential difference between the metal structure and the ground; using spaced contacts to create an electrical dipole transmitter; and using a toroidal transformer to supply current to the wellbore metal 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 wellbore; selection of fluids or cements to control wellbores within and outside the tubular elements to provide electrical conductivity or isolation of the tubular elements; using 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; use of a tubular element as a circular waveguide using the microwave (3 to 30 GHz) and UHF (300 MHz to 3 GHz) frequency bands.

Suitable means for receiving the transmitted signal are also 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; use of sections of the metal structure of the wellbore as part of the dipole antenna. The phrase elongated element, used in the context of EM transmission, can also mean any elongated electrical conductor, including a shank; casing pipe; tubing or tubular element; flexible pipe; pump rod; wire rope; drill pipe; wire rope or flexible rod.

Means of transmitting signals within a wellbore using an electrically conductive casing is disclosed in US 5,394,141 by Soulier and US 5,576,703 by 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 form 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 either by the second pair of spaced contacts and the amplifier in the second section due to the resultant current flowing into the casing, or alternatively 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 or 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 wellbore. One or more repeaters may be configured to transmit over 300 m or over 400 m.

More than five or more than ten repeaters may be provided for acoustic communication, depending on the depth of the wellbore and the location of the device.

EM links generally require fewer repeaters. For example, only one relay may be provided. Therefore, optionally, the EM repeater (and transceivers or transmitters associated with the vehicle or located on the surface) can be configured to transmit over a distance of more than 500 m or more than 1000 m.

In some areas of the wellbore, 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 wellbore.

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 wellbore, the repeaters can therefore be spaced appropriately in the wellbore.

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 a high temperature battery, a lithium battery, a lithium oxyhalide battery, a lithium thionyl chloride battery, a lithium sulfuryl chloride battery, a lithium fluorocarbon battery, a lithium manganese dioxide battery, a lithium ion battery, a lithium alloy battery, a sodium batteries and sodium alloy batteries. High temperature batteries are designed to operate at temperatures greater than 85°C, sometimes greater than 100°C. The battery system may include a first battery and additional backup batteries that are activated after a long period in the wellbore. 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 voltage or usage threshold.

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

The apparatus, in particular 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 the shutdown of most electronic systems, and a low frequency oscillator such as a 10-100 kHz, such as 32 kHz, oscillator used to maintain temporary system settings and wake-up functions. Synchronized short range wireless communication techniques (e.g. VLF EM communication) can be used between different system components to minimize the time that individual components need to be awake 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 after running into the wellbore for up to more than 24 hours, optionally more than 7 days, more than 1 month, or more than 1 year, or up to 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 caused by production, pumping, perforating, dry testing, or other downhole testing in the first wellbore. 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 the observation wellbore.

Typically, the wellbore described herein is an observation wellbore that is being monitored/surveilled by a pressure transducer.

Delivery

The tool can be delivered with the barrier by being placed on the same string as the barrier and delivered to the wellbore with it. It can be retrofitted in the wellbore 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 can be a bridge plug, a wireline-fixed tubular/drill pipe barrier, a closure tool, or a locking device such as a cementing lantern. The plug may be a temporary or permanent plug.

- 14 039961

Also, the apparatus may be provided in the wellbore, and then the barrier is delivered and installed 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 wellbore rather than into an already existing annulus in the wellbore. An annulus may be defined between the apparatus and an already existing tubular in the wellbore.

The container, if present, may be compacted at the surface and then delivered to the wellbore. Thus, the apparatus is moved from the surface and placed under the sealed container barrier until the control device is activated.

The container opening may be provided within 100 m of the perforation between the wellbore and the reservoir, optionally within 50 or 30 m. If more than one perforation is present, the nearest perforation is used to determine the distance from the apparatus opening. Therefore, optionally, the opening in the container may be located at a distance below the perforations in the wellbore. This can assist in removing perforated debris from the perforation(s) to assist in their cleaning.

The plurality of apparatuses and optional barriers described herein may be run on the same string, eg spaced apart and placed adjacent to the same zone or separate zones. Thus, the tool can be run into a wellbore with many different zones. In such a 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 on such a zone.

Additional Information

The wellbore may be a subsea wellbore. Wireless communications can be particularly useful in subsea wellbores, since the routing of cables into subsea wellbores is more difficult than in continental wellbores. The wellbore may be a deviated or horizontal wellbore, and embodiments of the present invention may be particularly suitable for such wellbores because they avoid the passage of wire rope, cables, or coiled tubing, which may be difficult or impossible to use in such wellbores. . For example, the wellbore may be a lateral portion of a wellbore, such as a multilateral wellbore.

References herein to a perforating device include downhole perforators, punches, or drills, all of which are used to create a perforation between the casing and the wellbore.

The volume of a container is its fluid capacity.

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

Unless otherwise noted, any references herein to the terms locked or unlocked include partial lock and partial unlock.

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

The wellbore is often an at least partially vertical wellbore. However, it may be a deviated or horizontal wellbore. References to terms such as over and under when applied to deviated or horizontal wellbores should be considered equivalent in wellbores with some vertical orientation. For example, the term above means closer to the surface of the wellbore.

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

The well surface is the top of the uppermost well casing. This surface is above the well surface.

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.

Embodiments of the present invention will be described below by way of example only.

- 15 039961 and with reference to the accompanying drawings, in which in FIG. 1 is a schematic sectional view of a portion of a wellbore and a first embodiment of the present invention that monitors pressure tightness of a cement barrier; and in FIG. 2 is a schematic sectional view of a section of a wellbore and an assembly formed in a manner different from that of FIG. 1, which monitors two cement barriers; and in FIG. 3a-3c are schematic views of various apparatuses with different capacities used in certain embodiments.

In FIG. 1 shows a section of a wellbore and a first embodiment of the present invention for monitoring pressure tightness of a cement barrier connected to the formation.

In FIG. 1 shows a section of an abandoned wellbore 114 comprising an upper section of a casing string 112 and a lower section of a casing string 118 separated by a cement barrier 120. An assembly/tool 150 is provided below the cement barrier with a downhole perforator 154, a monitoring mechanism 151 comprising a pressure sensor 131, wireless transceiver 164 and battery 133.

The well further includes a cap 113 on the top of the wellbore 114 and a cable 115 and junction box 119 for forming a spaced contact on the top of the wellbore 114 for detecting and transmitting electromagnetic signals. These signals may be received from/sent to a variety of downhole communication devices, including the wireless transceiver 164 of the tool 150 and/or the gun controller, which devices are described in more detail below. Junction box 119 is used as an interface to a system for collecting and/or managing local and remote data.

Pressure tightness monitoring of the cement barrier 120 is performed in an isolated section 190B within the casing string 118 between the bridge plug 122a and the cement barrier 120. The pressure information determined by the mechanism 151 may be transmitted to the surface (not shown) of the wellbore 114 via signals transmitted from the wireless transceiver 164 of the apparatus 150. In this embodiment, the apparatus 150 is connected to the casing 118 via an EM coupler 153 that allows transmission of EM signals from the isolated portion 190B to the surface.

The cement barrier 120 is located directly above the additional bridge plug or anchor 122b. The cement barrier 120 may be formed using a conventional method that includes adding a primary barrier (plug 122a) to control the wellbore and milling a section of casing (and any adjacent cement) above it. A section of the formation may also be cut using a reamer. The plug or anchor 122b is set to provide a base for fresh cement, which is then placed in this area to create a cement barrier 120 that seals throughout the wellbore 114 and connects to the surrounding subterranean formation 168. Thus, the wellbore 114 is sealed with cement barrier 120 , thus eliminating the portion of the wellbore 114a below it.

Downhole perforator 154 is installed in the string 118 casing. In use, a gun controller (not shown) receives an EM control signal to activate the downhole gun 154, which then creates radially and vertically spaced perforations 156 in the casing 118 and pre-existing cement 167 in the annulus 191 between the casing string 118 and the formation. 168. This provides hydrodynamic communication between the annular space 191 and the isolated section 190B.

The already existing cement 167 in the annulus 191 (which may have been there for decades) may provide a leak path through which fluids may pass. Therefore, the cement barrier 120 must be sealed against the formation. The creation of the perforations 156 means that the cement barrier 120 is tested for its integrity, as described below, not only in the central region of the wellbore, but also at its junction with the formation 168, to ensure that any leaks that may be present in and below the already existing cement 167 could not extend into the area between the cement barrier 120 and formation 168. Therefore, full sealing of the cement barrier is experienced.

A pressure difference is then created between the isolated section 190B and the wellbore 114b above the cement barrier 120. This can be achieved, for example, by applying a higher pressure from the surface to the upper side of the cement barrier 120 and/or by creating a pressure increase or decrease in the isolated section 190B. Such pressure changes can be created by using a pump or vessel with a suitable positive/reduced pressure in the isolated section 190B, for example, as shown in FIG. 3a-3c described below. An alternative way is to use the pressure drop that occurs when the perforators are fired. After the shaped charges are detonated and holes 155 are created, the fluid is ejected into the downhole lane.

- 16 039961 gun 154 (and optional associated container, for example, shown in Fig. 3a), thus creating a negative differential pressure in the isolated area 190B.

Therefore, if a leak path is present in the so-called isolated area 190B, this will typically result in a pressure change being monitored that is different from any pressure change that is expected, for example, when a perforating device is fired. It should be noted that due to the presence of the perforations 156, if there is any damage to the connection between the cement barrier 120 and the formation (and by leakage in the annulus 191 below), then this can also be observed by monitoring the pressure in the isolated section 190B.

A change in pressure under these circumstances is usually indicative of some damage to the cement barrier 120, although in addition or alternatively it may indicate a leak in the liner hanger 129 or other parts of the so-called isolated section 190B, for example, in the already existing cement in the annulus 191 below the perforations. 156. When in doubt, both of the pressure tests described above can be performed to determine which portion of containment 190B is leaking.

The downhole gun 154 can be improved to create perforations in the casing 118 and the adjacent cement in the annulus 191 that do not extend into the formation 168 to the same extent necessary to provide flow paths for fluid communication from the reservoir, such as perforations 177. While the perforations 156 may extend to a certain depth into the formation, the formation is generally impermeable in that area (if not, it is impermeable around the cement barrier), and hence in the formation between the top and bottom areas there is no leakage path.

The present inventors have noted that the use of a pressure transducer below the barrier provides information on the integrity of the barrier seal, which improves the known method of monitoring pressure above the barrier seal, where the volume of the wellbore 114b above the cement barrier 120 may be larger, hence small leaks will create a subtle change in pressure. , which is difficult to immediately detect and recognize.

Moreover, providing a pressure sensor 131 below the barrier 120 can also provide confirmation that any lower barrier, such as the liner hanger 129, is also sealed, while pressure monitoring from the top does not provide this information. An additional pressure transducer (not shown) may be provided between the bridge plug/anchor 122b and the cement barrier 120 above, which may assist in confirming, through the tests described below, that this cement barrier is long term and under pressure.

An additional benefit is that the positive pressure test under the barrier tests the barrier in the direction in which the barrier is supposed to seal, thereby providing a more accurate pressure test. Similarly, the barrier negative pressure test tests any lower barrier, such as the liner hanger 129, in the direction in which the lower barrier would seal.

For certain embodiments, pressure testing may be performed before as well as after activation of the perforating device 154 to create perforations 156 in the casing 118 and cement. This may provide a baseline for testing the cement barrier 120 in the central region prior to testing the remaining cement plug, and in particular its connection to formation 168, as described above. For example, the various containers shown in FIG. 3a-3c can be used to create a change in pressure in the lower region prior to creating the perforations.

The cement for the cement plug can be placed in a variety of ways, including circulation, punching, and/or slurry discharge. In alternative embodiments, cement substitutes such as Sandaband™ can be used, or even thermite or other smelting process used in place of cement.

In modified embodiments, an additional perforating device may be provided above the cement plug and activated to provide a flow path through the adjacent casing. This provides an additional assessment of the integrity of the cement plug and its connection to the formation.

In FIG. 2 shows a further refinement of the embodiment of FIG. 1 with similar features, illustrating two cement plugs. Parts similar to those of the embodiment of FIG. 1 are not described in detail, but they are preceded by a 2 rather than a 1. In this embodiment, a pressure leak test of a plurality of cement barriers is performed versus a single cement barrier as described in the embodiment of FIG. 1.

In FIG. 2 shows a wellbore 214 comprising top and bottom cement barriers 220b and 220a, assemblies/tools 250b and 250a, and downhole guns 254b and 254a, respectively. As in the embodiment described in FIG. 1, the apparatus of FIG. 2, as a rule, is located adjacent to the

- 17 039961 permeable to the fluid layer 268 of the overburden.

Also, as in the embodiment of FIG. 1, in the embodiment of FIG. 2, a cap (not shown) and a cable (not shown) and a junction box (not shown) are provided at the top of the wellbore 214 to form a spaced contact for sensing and transmitting electromagnetic signals. These signals may be received from/sent to various objects within the wellbore 214, including perforators 254b and/or 254a, and/or received from monitoring mechanisms 251b and/or 251a, which are described in more detail below.

Carry out pressure tightness monitoring of the isolated section defined within each section of the casing string, and the isolated section 290B is defined between the bridge plug 222a and the cement barrier 220a; and moreover, an isolated area 290B' is defined between the cement barriers 220a and 220b.

The cement barriers 220a and 220b are formed using a method different from the method described with respect to the embodiment of FIG. 1, including perforating the wellbore with downhole perforators (not shown) and flushing out at least a portion of any cement and other debris in the annulus 291 between the casing 212c, 212f and the formation 268. A buffer fluid is then pumped into the annulus 291 before the cement is placed. The cement is placed inside the casing 212c, 212f and passes through the perforations 256a and 256b into the annulus 291.

Downhole perforators 254b and 254a can be activated independently, optionally through the use of wireless signals, creating perforations 256b' and 256a', respectively. Perforations, as in the embodiment of FIG. 1 provide a test of the integrity of each cement barrier 220a, 220b, not only in the central region of the wellbore 214, but across its entire width and at its junction with the casing 212c, 212f and formation 268.

Then between the isolated areas 290B' and 290B create a pressure difference. Any pressure changes in the isolated areas 290B' and 290B are detected using the monitoring mechanisms 251b and/or 251a, thereby allowing the integrity of the upper and lower cement barriers 220a, 220b in the wellbore 214 to be tested and monitored. The received data is then output wirelessly, for example, via EM communication.

An advantage of the embodiment of FIG. 2 is that it confirms that there are two separate seals in the wellbore. In certain embodiments of FIG. 2, each of the two cement seals may have a shorter length (eg, 25 meters each), and together their length is the length used in the embodiment of FIG. 1 with one cement seal (eg 50m).

The two cement barriers illustrated in FIG. 2 are preferred for longer term monitoring because the connection between the top cement barriers 220b and the formation 268 can be confirmed (typically using a pressure transducer between the cement barriers) even if in the area below the cement barriers, such as under the perforations 256a, leaks exist. In contrast, for single cement barrier embodiments, it is more difficult/impossible to confirm the connection between the cement barrier and the formation if additional leaks exist in the area below the cement barrier, such as perforations 256, as in FIG. 1.

Optionally, additional monitoring of, for example, a manifold may be accomplished through additional perforations 256c in the manifold using the appropriate apparatus described herein.

For other embodiments, the apparatus may be positioned in the wellbore by a number of means, for example, by hanging non-compacting components such as a cement scraper; or on top of a liner hanger or bridge plug.

Thus, a number of different perforating steps may occur: perforating below the formed cement barrier to facilitate its testing, perforating above the cement barrier also to facilitate its testing, perforating to ensure the site is cleared prior to placing the cement barrier, and perforating to access reservoir monitoring.

Other perforating devices may be used instead of a multi-charge downhole perforator, such as a downhole punch that can release one charge and form a single perforation, especially for perforating between the formed cement barriers.

Therefore, for certain embodiments, two cement barriers may be provided, as shown in FIG. 2 as an example. In other embodiments, a second cement barrier may be added after one cement barrier has been installed and tested (eg, in FIG. 1).

In alternative embodiments, the second apparatus 250b is optional, even

- 18 039961 if two cement barriers are provided.

The two methods of cement plug formation described with respect to FIG. 1 and 2, respectively, can be used in either single (FIG. 1) or dual (FIG. 2) barrier embodiments.

Moreover, although an EM communication system is illustrated, acoustic or other wireless communication systems may be used. For example, the wellbore 114/214 can be run from a surface installation, such as a drilling rig, to the top region of the cement barrier 120/220, for example, approximately 10 meters away from the top region.

The act of creating a double cement barrier can be accomplished by running a pipe into the wellbore once. For example, as indicated in the embodiment of FIG. 2, two sets of perforations 256a, 256b may be created, and the perforations are optionally lowered into the wellbore and the perforations flushed. The lower apparatus 250a can be released from the pipe and secured by means of an anchor 222b. The lower cement barrier 220a may then be placed prior to the installation of the upper apparatus 250b by means of an anchor 222c and the placement of the upper cement barrier 220b. The control and release of the apparatus 250a/250b and the operation of the perforating guns 256a and 256b can be performed wirelessly or by traditional ball/rod release or pivot mechanisms.

While reference is made above to pre-existing cement, casing strings often have a section where they are not connected to the formation by cement. Therefore, in certain embodiments, there is no pre-existing cement in the annulus between the casing string and the formation where perforations such as 256a', 256b' of FIG. 2, or a new cement seal such as 256a, 256b.

As noted above, the apparatus 250a in the isolated area 290B' may contain a container to reduce (or increase, if necessary) the pressure in it for pressure testing in relation to the isolated area, in particular, the cement barrier 220a. The apparatus according to Fig. 3a includes a container 357, an opening 355, a valve 362, and a control mechanism with a multifunction control device 366 and a wireless receiver (or transceiver) 364. The valve 362 is located in the device opening 355, and the opening leads to a fluid chamber 371 within the container 357. Others apparatus components such as the downhole gun and the monitoring mechanism are not shown in FIG. 3a-3c.

The valve 362 is configured to seal the reservoir 357 from the wellbore environment in the closed position and provide fluid communication and fluid communication between the fluid chamber 357 and the wellbore environment through the opening 355 in the open position.

In some embodiments, the fluid chamber 371 is filled with a gas, such as air, initially at atmospheric pressure. In such embodiments, the gas is sealed in a vessel at the surface prior to being run into the well to create a negative differential pressure between the vessel and the isolated area (which is above atmospheric pressure at the surface).

In other embodiments, the fluid chamber 371 may be filled with a gas or fluid at a higher pressure than the isolated portion, thereby creating a positive differential pressure therein.

In addition to or instead of the valve 362, a pump may be provided to move fluids between the fluid chamber 371 and the well environment, regardless of the relative pressures between the fluid chamber 371 and the well environment.

For example, as shown in FIG. 3b, an electrically driven pump 363 is located within opening 355 of container 357. Fluid chamber 371 is filled with liquid 390 and gas 392.

The pump 362 pumps fluids from the reservoir 357 into the wellbore environment/injects them into the reservoir from the wellbore environment (outside the apparatus), thus providing selective fluid communication between the reservoir portion 357 and the isolated area. Gas 392 may be suitably compressed to facilitate pumping, or provided for pump 362 to stop being drawn in to avoid a vacuum.

An optional floating piston, equivalent to piston 375 of FIG. 3c can separate the gas 392 and liquid 390 phases as shown in FIG. 3b.

In an alternative embodiment, the container apparatus shown in FIG. 3b is the assembly or apparatus of FIG. 3c. The apparatus according to Fig. 3c contains hole 355; valve 362; fitting 376; a control mechanism with a multifunction control device 366 and a wireless receiver (or transceiver) 364; and container 357. The valve 362 and fitting 376 are located in the central part of the device in the hole 379 between two sections of the container 357: the chamber 371 for the fluid and the chamber 381 reduced pressure.

- 19 039961

In some embodiments, the reduced pressure chamber 381 is filled with a gas, such as air, initially at atmospheric pressure. In such embodiments, the gas is sealed in reservoir 357 at the surface prior to being lowered into the well. This contributes to the creation of a negative differential pressure, for example, from 1000 psi to 10,000 psi, between the reservoir 357 and the surrounding part of the well (which has a pressure above atmospheric pressure at the surface).

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 flow of fluid in the well into the fluid chamber 371 through the opening 355 is opposed 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 controller 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.

An advantage of the embodiment of FIG. 3c is that the floating piston and choke can help control the rate of passage of well fluids from the wellbore environment into the reservoir, which can provide more accurate data and more accurate well and reservoir analysis.

As shown in FIG. 3c, the apparatus can be reconfigured to push fluid out of fluid chamber 371 into the surrounding wellbore. In such an embodiment, chamber 381 is a transfer chamber containing gas at a higher pressure than the surrounding wellbore, and when valve 362 is opened, the higher positive differential pressure from transfer chamber 381 drives floating piston 375 to rise from the bottom of the well. fluid chamber 371 to opening 355. As the working volume of fluid chamber 371 decreases, stored fluid is pushed out of fluid chamber 371 through opening 355 and into the surrounding wellbore.

Valve 362 may be provided where indicated between transfer chamber 381 and fluid chamber 371, or located in opening 355 instead.

As an alternative, a pump is used in place of the 362 valve.

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.

In certain embodiments, the valve may be opened immediately upon activation of the perforators. In other embodiments, the opening of the valve may be delayed some time after the perforator is fired. Similarly, activation of the perforators may be delayed after the barrier has been installed. 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.

Tanks 357 may have a capacity of, for example, 1000 liters.

The embodiments described herein may be combined. For example, the methods described with respect to any of FIGS. 1-2 may be used for a single wellbore with the reservoirs described with respect to FIGS. 3a-3c.

Claims (23)

CLAIM 1. A method for downhole monitoring of a barrier condition, comprising placing at least one barrier in a cased wellbore, wherein at least one barrier contains a column of flowable sealing material, such as cement, having a height of at least 2 m, so as to resist hydrodynamic communication and communication along the flow throughout the wellbore, thereby dividing the wellbore into a lower section under at least one barrier and an upper section above at least one barrier; connecting said column fluid sealing material to a portion of the formation that defines a portion of the wellbore; wherein at least a portion of the lower portion is cased with a casing, thereby defining an annular space between the surrounding formation and the casing; at the same time, a downhole device containing a perforating device is placed in the lower section; a control mechanism for controlling the perforating device and comprising a wireless communication device configured to receive a wireless control signal for activating the perforating device; pressure meter; sending at an arbitrary point in time a wireless control signal to the wireless communication device to activate the perforating device, wherein the wireless control signal is transmitted in at least one of the following forms: electromagnetic, acoustic, via inductively coupled tubular elements, and via coded pressure pulses; after placement of at least one barrier, activating the perforating device to create at least one perforation through the casing; after activating the perforating device: (i) monitoring the pressure in the lower section of at least one barrier using a pressure sensor; and (ii) sending a wireless data signal containing pressure data from the area below the at least one barrier to the area above the at least one barrier using at least one of electromagnetic communication and acoustic communication; and after step (ii)(iii) judging whether the lower section is isolated from the upper section or to what extent it is isolated from it, based on pressure monitoring data over time. 2. The method according to claim 1, characterized in that by activating the perforating device, a path is created from the interior of the casing to the formation. 3. The method according to claim 1 or 2, characterized in that the part of the formation to which the fluid column material is connected is an impermeable part. 4. The method according to claim 3, characterized in that the perforations are created adjacent to the impermeable part of the formation. 5. A method according to any one of the preceding claims, characterized in that it comprises the step of monitoring the pressure above and below said at least one barrier. 6. A method according to any of the preceding claims, characterized in that it includes cleaning a section of the formation, thereby removing at least a portion of any already existing cement in contact with the formation, then placing at least one barrier at least partially in said plot. 7. The method of claim 6, wherein the step of cleaning said area includes removing a portion of the casing and at least a portion of any pre-existing cement in contact with the formation in said area. 8. The method of claim 6, wherein the step of cleaning said area includes a prior step of perforating a portion of the casing in said area and flushing out at least a portion of any pre-existing cement in contact with the formation. 9. The method according to any one of the preceding claims, characterized in that an upper perforating device is provided, wherein the upper perforating device is provided in the upper section of at least one barrier, and the method includes creating at least one perforation hole between the wellbore and the casing at least one barrier. 10. The method according to any one of the preceding claims, characterized in that at least one barrier is placed prior to sending the wireless control signal to the wireless communication device, so that the wireless control signal is sent from a region above at least one barrier to the wireless communication device at least under one barrier to activate the perforating device. 11. The method according to any one of the preceding claims, characterized in that it includes monitoring the reservoir after the placement of at least one barrier by using additional dates - 21 039961 pressure gauge in the wellbore at least under one barrier. 12. The method according to any of the preceding claims, characterized in that at least one barrier is left in place for a period of at least 1 month, at least 3 months, at least 6 months, at least 1 year or more 5 years. 13. The method according to any of the preceding claims, characterized in that the downhole device is configured to monitor pressure or other parameters under at least one barrier for periods of time greater than one week, one month, one year, or more than five years. 14. The method according to any one of the preceding claims, characterized in that at least one barrier is a main barrier and at least one secondary barrier, which contains a column of fluid sealing material, is placed under the downhole device, so that due to at least at least one secondary barrier provides resistance to hydrodynamic communication and communication throughout the wellbore, thus isolating the section of the wellbore between the main and auxiliary barriers from the section of the wellbore under the auxiliary barrier. 15. The method of claim 14, wherein the pressure sensor is a primary pressure sensor and the wellbore comprises an auxiliary pressure sensor below at least one secondary barrier. 16. The method of claim 15, wherein the downhole device is the main downhole device, the perforating device is the main perforating device, the control mechanism is the main control mechanism, and the wireless communication device is the main wireless communication device, and the auxiliary downhole the device is placed under at least one auxiliary barrier, and the auxiliary downhole device contains an auxiliary pressure sensor; auxiliary punching device; an auxiliary control mechanism for controlling the punching device and comprising an auxiliary wireless communication device configured to receive a wireless control signal for activating the punching device; wherein the method includes sending at an arbitrary point in time a wireless control signal to an auxiliary wireless communication device to activate the auxiliary perforating device, wherein the wireless control signal is transmitted in at least one of the following forms: electromagnetic, acoustic, via inductively coupled tubular elements, and via coded pressure pulses ; after placing at least one secondary barrier, activating the secondary perforating device to create at least one perforation between the wellbore and the casing; pressure monitoring in the area under the auxiliary barrier using an auxiliary pressure sensor; and sending a wireless data signal containing pressure data from the region below the secondary barrier to the region above the secondary barrier using at least one of electromagnetic coupling, acoustic coupling, and inductively coupled tubular members. 17. The method according to any of the preceding claims, characterized in that the downhole device contains a container, and the method includes setting the fluid in motion through an opening between the interior and exterior of the container, while the container has a volume of at least 5 liters or at least 50 l, optionally at least 100 l; and optionally, the container has a volume of not more than 3000 liters, optionally not more than 1500 liters and optionally not more than 500 liters. 18. The method according to claim 17, 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 lower or at least 500 psi higher than the pressure outside of the container. 19. Method according to any one of claims 17-18, characterized in that the movement of the fluid medium is directed from the interior of the container to the exterior of the container. 20. The method according to any one of claims 17-19, characterized in that the container is compacted at the surface and then delivered to the wellbore, so that the downhole tool is moved from the surface to the wellbore with the compacted container. 21. The method according to any of the preceding claims, characterized in that the lower section is preserved or liquidated, and optionally the entire wellbore is preserved or liquidated. 22. The method according to any one of the preceding claims, characterized in that the wireless control signal is transmitted in the form of at least one of electromagnetic signals and acoustic - 22 039961 signals. 23. The method of claim 22, wherein at least one of the wireless data signal and the wireless control signal includes an electromagnetic signal in the sub-ELF or ELF frequency bands.