Patent Description:
Isolating a zone in a wellbore helps prevent fluids such as water or gas in one zone from mixing with the production fluid in another zone. Zonal isolation includes a hydraulic barrier between an isolated annulus and the production fluid flowing through the production tubing. Isolating a zone can be done as a thru-tubing operation and can be permanent or semi-retrievable. Over the life of the wellbore, as the annular seal is subject to formation and pressure changes, significant pressure and temperature differentials can affect zonal isolation.

<CIT> describes an array of sensors that can be deployed within a wellbore for measuring properties of a fluid in a central flow passage of a tubular string.

In one aspect of the present disclosure there is provided a zonal isolation assessment system as in clam <NUM> and a method as in claim <NUM>. Implementations of the present disclosure include a zonal isolation assessment system that includes a receiver, production tubing, a zonal isolation assembly, and an assessment assembly. The receiver resides at or near a surface of a wellbore. The production tubing is disposed in the wellbore. The zonal isolation assembly resides downhole of and is fluidically coupled to the production tubing. The zonal isolation assembly isolates a zone of the wellbore and includes isolation tubing that flows production fluid from the wellbore to the production tubing, a first sealing element coupled to the isolation tubing, and a second sealing element coupled to the isolation tubing and disposed downhole of the first sealing element. The first sealing element and the second sealing element are set on a wall of the wellbore to fluidically isolate an internal volume of the isolation tubing from an isolated annulus defined between the isolation tubing and the wall of the wellbore. The annulus extends from the first sealing element to the second sealing element. The assessment assembly is disposed at least partially inside the isolation tubing and communicatively coupled to the receiver. The assessment assembly includes a first pressure sensor residing at the internal volume of the isolation tubing and configured to sense a first pressure value representing a fluidic pressure of the internal volume. The assessment assembly also includes a second pressure sensor residing at the annulus and configured to sense a second pressure value representing a fluidic pressure of the annulus. The assessment assembly transmits, to the receiver, the first pressure value and the second pressure value such that the first and second pressure values are usable to determine, based comparing the first pressure value with the second pressure value, a zonal isolation integrity of the zonal isolation assembly.

In some implementations, the first pressure value includes a first set of pressure values sensed by the first pressure sensor over time before and during production, and the second pressure value includes a second set of pressure values sensed by the second pressure sensor over time before and during production. The first set of pressure values and the second set of pressure values are usable to determine the zonal isolation integrity of the zonal isolation assembly by at least one of: <NUM>) comparing a rate of change over time of the second set of pressure values to a first threshold, the second set of pressure values starting at a point in time in which the first set of pressure values represent the beginning of a drawdown pressure, or <NUM>) comparing a rate of change over time between the first set of pressure values and the second set of pressure values to a second threshold. In some implementations, the first threshold represents a percentage of the drawdown pressure. The drawdown pressure represents a change in pressure at the internal volume as the wellbore enters a flowing condition. In some implementations, the first threshold represent <NUM>% or less of the drawdown pressure, and the first and second pressure values are usable to determine low isolation integrity when the rate of change over time of the second set of pressure values is equal to or larger than the threshold.

In some implementations, the assessment assembly continuously or generally continuously transmits real-time data to the receiver. The real-time data represents a first set of pressure values sensed by the first pressure sensor over time before and during production and a second set of pressure values sensed by the second pressure sensor over time before and during production. The first and second set of pressure values are usable to determine the zonal isolation integrity in or near real-time.

In some implementations, the zonal isolation assembly is configured to be permanently set on the wall of the wellbore to isolate the zone of the wellbore during production.

In some implementations, the isolation tubing is disposed at an open hole section of the wellbore. The isolated zone includes a region of the open hole section isolated by the first sealing element and the second sealing element set on a wall of the open hole section of the wellbore.

In some implementations, the receiver is communicatively coupled to a processor configured to determine, based on a rate of change of the first pressure value and the second pressure value, a third value representing a leakage percentage. The processor is configured to determine a level of isolation integrity based on comparing the leakage percentage to a leakage percentage threshold.

In some implementations, the assessment assembly is releasably coupled to and disposed inside the isolation tubing. The assessment assembly includes a fluid pathway configured to receive production fluid from the isolation tubing at the internal volume and flow the production fluid to the first pressure sensor disposed along the fluid pathway.

In some implementations, the assessment assembly can be retrieved from the assessment assembly by a retrieving tool run on wireline, slick line, or coiled tubing.

In some implementations, the assessment assembly includes a first housing that houses and protects circuitry and a battery system that powers electric components of the circuitry. The circuitry receives the first pressure value and the second pressure value and transmits the first pressure value and the second pressure value to the receiver.

In some implementations, the assessment assembly includes a second housing that houses and protects at least a portion of an electric turbine assembly and a pressure compensator. The electric turbine assembly includes a turbine axially coupled to a rotating shaft and configured to rotate under fluidic pressure of production fluid flowing through the turbine. The rotating shaft coupled to an electric generator configured to produce electricity through rotation of the shaft. The electric generator is electrically coupled to and configured to charge batteries of the battery system.

In some implementations, the assessment assembly includes a turbine housing and an engagement assembly releasably attached to the isolation tubing. The first housing and the second housing form a tubular body attached to and disposed between the turbine housing and the engagement assembly. The tubular body forming an annulus with a wall of the isolation tubing in which at least a portion of the fluid pathway is defined.

Implementations of the present disclosure include an assessment assembly that includes isolation tubing disposed in a wellbore downhole of production tubing. The isolation tubing flows production fluid from the wellbore to the production tubing. The assessment assembly also includes a first sealing element coupled to the isolation tubing and a second sealing element coupled to the isolation tubing and disposed downhole of the first sealing element. The first sealing element and the second sealing element is configured to be set on a wall of the wellbore to fluidically isolate an internal volume of the isolation tubing from an isolated annulus defined between the isolation tubing and the wall of the wellbore, the isolated annulus extends from the first sealing element to the second sealing element. The assessment assembly includes a first pressure sensor residing at the internal volume of the isolation tubing, the first pressure sensor communicatively coupled and configured to transmit first pressure information to a receiver at or near a surface of the wellbore. The assessment assembly includes a second pressure sensor residing at the annulus. The second pressure sensor is communicatively coupled and configured to transmit second pressure information to the receiver such that the first pressure information and the second pressure information is usable to determine a zonal isolation integrity of the isolation tubing.

In some implementations, the first pressure sensor and the second pressure sensor are coupled to an autonomous assessment assembly releasably coupled to the isolation tubing. The autonomous assessment assembly includes an energy harvesting system configured to harvest energy from the production fluid to power electronics electrically coupled to the first and second pressure sensor.

In some implementations, the assessment assembly is configured to continuously or generally continuously transmit real-time data to the receiver. The real-time data represents a first set of pressure values sensed by the first pressure sensor over time before and during production and a second set of pressure values sensed by the second pressure sensor over time before and during production. The first and second set of pressure values are usable to determine the zonal isolation integrity.

In some implementations, the isolation tubing is permanently set on the wall of the wellbore to permanently isolate a zone of the wellbore during production. In some implementations, the isolation tubing is disposed at an open hole section of the wellbore. The isolated annulus includes a region of the open hole section and is isolated by the first sealing element and the second sealing element set on a wall of the open hole section of the wellbore.

Implementations of the present disclosure include a method that includes receiving, by a receiver at or near a surface of a wellbore, a first pressure value and a second pressure value from a zonal isolation assembly disposed downhole of production tubing. The zonal isolation assembly includes <NUM>) isolation tubing, <NUM>) a first sealing element coupled to the isolation tubing, <NUM>) a second sealing element coupled to the isolation tubing and disposed downhole of the first sealing element, the first sealing element and the second sealing element configured to be set on a wall of the wellbore to fluidically isolate an internal volume of the isolation tubing from an isolated annulus defined between the isolation tubing and the wall of the wellbore, <NUM>) a first pressure sensor residing at the internal volume of the isolation tubing and configured to sense the first pressure value, and <NUM>) a second pressure sensor residing at the annulus and configured to sense the second pressure value. The method also includes determining, based on comparing the first pressure value to the second pressure value, a third value representing a zonal isolation integrity of the zonal isolation assembly.

In some implementations, receiving the first value includes receiving a first set of pressure values sensed by the first pressure sensor over time before and during production, and receiving the second value includes receiving a second set of pressure values sensed by the second pressure sensor over time before and during production. Determining the third value includes determining the third value based on <NUM>) comparing a rate of change over time of the second set of pressure values to a first threshold, the second set of pressure values starting at a point in time in which the first set of pressure values represent the beginning of a drawdown pressure, or <NUM>) comparing a rate of change over time between the first set of pressure values and the second set of pressure values to a second threshold.

The present disclosure describes an autonomous assessment tool fluidically coupled to production tubing and communicatively coupled to a receiver at the surface of the wellbore. The assessment tool or assembly is disposed at an isolated zone to receive hydrocarbons from an isolation assembly containing the assessment assembly. The assessment assembly has an energy harvesting system that uses the production fluid to power the components of the assessment assembly. The assessment assembly has a first pressure sensor disposed inside the assessment assembly and a second pressure sensor disposed outside the isolation assembly, at an isolated annulus. After shut-in, upon entering a flowing condition, production fluid enters the assessment assembly to flow past the first pressure sensor. The first pressure sensor continually senses the pressure of the fluid flowing through the assessment assembly. The second pressure sensor continually senses the pressure in the annulus of the isolated zone. The assessment tool transmits the pressure values to the receiver. The receiver computes a difference between the two pressures and determines, based on the difference between pressures, the integrity of the isolated zone. If pressure in the annulus dropped during drawdown, there is pressure communication between the annulus of the isolated zone and the production tubing, which thereby reduces the integrity of the isolated zone.

Particular implementations of the subject matter described in this specification can be implemented so as to realize one or more of the following advantages. For example, the assessment assembly helps determine in real-time that the isolation integrity of a wellbore zone is successfully deployed in open hole, monitor the integrity of the zonal isolation over time, and monitor the isolated pressure in the isolated zone. Additionally, the assessment tool can help detect early the water front's progressing, which can help in production strategy planning.

<FIG> shows a zonal isolation assessment system <NUM> disposed inside a wellbore <NUM>. The zonal isolation assessment system <NUM> is a wellbore assembly for isolating and assessing the integrity of a zone in a production well. The wellbore <NUM> is formed in a geologic formation <NUM> that includes a reservoir <NUM> from which production fluid (for example, hydrocarbons) can be extracted. The wellbore <NUM> can be a non-vertical wellbore, with a vertical portion and a non-vertical portion (for example, a horizontal portion). The wellbore <NUM> can include a cased section or portion <NUM> and an open hole section or portion <NUM>, from which production fluid is extracted.

The assessment system <NUM> includes a receiver <NUM>, production tubing <NUM>, a zonal isolation assembly <NUM>, and an assessment assembly <NUM>. The receiver resides at or near a surface <NUM> of the wellbore <NUM> (for example, at or near a wellhead of the wellbore). The receiver can be communicatively coupled to the assessment assembly <NUM> through a wireless connection. In some implementations, the pressure data can be stored in a local memory of the assessment assembly <NUM> and later retrieved with the assessment assembly <NUM> for analysis.

The production tubing <NUM> or production string is disposed inside the wellbore <NUM> and flows production fluid from a downhole location of the wellbore <NUM> to the surface <NUM>. For example, during production, the production tubing <NUM> flows hydrocarbons received through the zonal isolation assembly <NUM> from an upstream location of the open hole section <NUM> of the wellbore <NUM> to the surface <NUM>. The production tubing <NUM> can include an electric submersible pump (not shown) that moves the production fluid from the reservoir <NUM>, through the zonal isolation assembly <NUM>, to the production tubing <NUM>.

The zonal isolation assembly <NUM> resides downhole of and is fluidically coupled to the production tubing <NUM>. The zonal isolation assembly <NUM> can be attached to the production tubing <NUM> or can reside in the open hole section <NUM> of the wellbore <NUM> separated from the production tubing <NUM>. The zonal isolation assembly <NUM> is used for annular zonal isolation of a section of the wellbore. Specifically, the zonal isolation assembly <NUM> isolates a zone 'I' of the wellbore <NUM> during production. For example, the zonal isolation assembly <NUM> can be permanently deployed to a downhole location of the open hole section <NUM> of the wellbore <NUM> to permanently isolate the zone 'I' or section of the wellbore, and enable production fluid flowing through the zonal isolation assembly <NUM> from an upstream location of the open hole section <NUM> of the wellbore <NUM>.

In another example, the zonal isolation assembly <NUM> can be semi-permanently deployed to a downhole location of the open hole section <NUM> of the wellbore <NUM> to isolate the zone 'I' or section of the wellbore, and enable production fluid flowing through the zonal isolation assembly <NUM> from an upstream location of the open hole section <NUM> of the wellbore <NUM>. Parts of he semi retrievable or semi-permanent zonal isolation assembly <NUM> can be retrieved to the surface <NUM> (for example, for maintenance), leaving parts of the zonal isolation assembly <NUM> which facilitate larger ID, leaving a generally unrestricted flow path in the wellbore <NUM>.

One or more isolated zones 'I' can be used for compartmentalizing the wellbore <NUM> in different zones. While shown in isolated portions of wellbores <NUM> completed with open hole producing sections <NUM>, the system can be used in cased-hole applications. The isolated zone 'I' can be a zone that contains undesirable fluids or production fluid that is designated for later production.

Specifically, the zonal isolation assembly <NUM> includes isolation tubing <NUM>, a first sealing element <NUM> coupled to the isolation tubing <NUM>, and a second sealing element <NUM> coupled to the isolation tubing <NUM> downhole of the first sealing element <NUM>. The isolation tubing <NUM> includes a fluid inlet <NUM> that receives the production fluid (for example, from the hydrocarbon reservoir <NUM>) and a fluid outlet <NUM> that flows fluid from the isolation tubing <NUM> to the production tubing <NUM>. Each sealing element <NUM> and <NUM> can be a rubber ring that is part of a respective packer <NUM> and <NUM>. The packers <NUM> and <NUM> include respective anchors <NUM> and <NUM> or slips that anchor the zonal isolation assembly <NUM> to the wellbore <NUM>. The first sealing element <NUM> and the second sealing element <NUM> are set on a wall <NUM> of the wellbore <NUM> to fluidically isolate an internal volume <NUM> of the isolation tubing from an isolated annulus <NUM> defined between the isolation tubing <NUM> and the wall <NUM> of the wellbore <NUM>. The annulus <NUM> extends from the first sealing element <NUM> to the second sealing element <NUM> and is fluidically isolated from the rest of the wellbore <NUM>. Thus, the isolated zone 'I' can be a region isolated by the first sealing element <NUM> and the second sealing element <NUM> set on the wall <NUM> of the open hole section <NUM> of the wellbore <NUM>.

The assessment assembly <NUM> is disposed at least partially inside the isolation tubing <NUM> of the isolation assembly <NUM>. As further described in detail later with respect to <FIG>, the assessment assembly <NUM> transmits to the receiver <NUM> information sensed or gathered by pressure sensors coupled to the assessment assembly <NUM>.

The assessment assembly <NUM> can be releasably coupled to the isolation tubing <NUM>. For example, if the assessment assembly <NUM> needs to be retrieved, a retrieving tool can retrieve the assessment assembly <NUM> from the isolation tubing <NUM> and back to the surface <NUM>. The assessment assembly <NUM> is fluidically coupled to the isolation tubing <NUM> to flow production fluid from an inlet <NUM> of the assessment assembly <NUM> to an outlet <NUM> of the assessment assembly <NUM>.

The assessment assembly <NUM> gathers pressure information before and during production of hydrocarbons to determine zonal isolation integrity of the isolated zone `I'. Specifically, the assessment assembly <NUM> compares a fluidic pressure sensed at the internal volume <NUM> of the isolation tubing <NUM> to a fluidic pressure sensed at the isolated annulus <NUM> to determine if there is pressure interference between the annulus <NUM> and the interior volume <NUM> of the isolation tubing <NUM>. If there is pressure communication between the two, then the isolated region 'I' has low or no isolation integrity and the sealing elements <NUM> have to be readjusted (or serviced or replaced) to form an isolated zone with zonal isolation integrity. If it is determined that the zone "I" is compromised, the zone "I" can be extended to cover a larger portion or zone.

As shown in <FIG>, the receiver <NUM> can be communicatively coupled to a processor <NUM> that determines, based on the difference between the pressure at the annulus <NUM> and the pressure at the internal volume <NUM>, a third value representing a level of zonal isolation integrity. For example, the third value can be a leak rate measured in cubic centimeters per minute (cc/min) or barrels per day. The third value can also be a leakage percentage. For example, the leakage percentage can be calculated using the following equation: <MAT> in which ΔP<NUM> is the change in pressure sensed at the internal volume <NUM> and ΔP<NUM> is the change in pressure sensed at the annulus <NUM>. Thus, if ΔP<NUM> is zero, the leak percentage is <NUM>%, and if ΔP<NUM>= ΔP<NUM>, the leak percentage is <NUM>%.

In some implementations, the leak rate or leakage percentage can be used to predict other parameters such as water production rate or time of failure of the zonal isolation assembly <NUM>. The lake rate or percentage can directly affect the water production rate and have negative consequences for the oil production rate. Predictions can be made based on trends, such as sudden increments of the leak rate (or percentage), and based on assumptions to the failure mode, (e.g., assumptions as to where is the water leaking from). As further described in detail later with respect to <FIG>, the processor can compute a difference between a rate of change over time of the pressure values sensed by the pressure sensors, and use that result to determine the zonal isolation integrity. The receiver <NUM> can also include a transmitter <NUM> that transmits instructions to the zonal isolation assembly <NUM> to increase or decrease the sample rate and resolution.

Referring to <FIG>, the assessment assembly <NUM> includes a first pressure sensor <NUM> that resides at the internal volume <NUM> of the isolation tubing <NUM>. The first pressure sensor <NUM> senses a first pressure value representing a fluidic pressure of the internal volume <NUM>. The assessment assembly <NUM> also includes a second pressure sensor <NUM> that resides at the isolated annulus <NUM> and senses a second pressure value representing a fluidic pressure at the isolated annulus <NUM>.

The fluidic pressures at the internal volume <NUM> and at the annulus <NUM> are continuously or generality continuously sent to the receiver <NUM>. For example, the pressure information from each pressure sensor can be sent to the receiver <NUM> in real-time or near-real time. By "real time," it is meant that a duration between receiving an input and processing the input to provide an output can be minimal, for example, in the order of seconds, milliseconds, microseconds, or nanoseconds, sufficiently fast to detect pressure communication at an early stage.

The fluidic pressure at the internal volume <NUM> and at the annulus <NUM> is sensed before production and during production. Specifically, the pressure values are gathered during drawdown. The drawdown pressure represents a change in pressure at the internal volume <NUM> as the wellbore <NUM> enters a flowing condition. During drawdown and during production, production fluid 'F' flows through the isolation tubing <NUM> and through a fluid pathway of the assessment assembly <NUM>. The assessment assembly <NUM> defines a fluid pathway that extends from the inlet <NUM> of the assessment assembly <NUM> to the outlet <NUM> of the assessment assembly <NUM>. The fluid pathway includes an annulus <NUM> in which the production fluid 'F' forms a tubular-shaped column around a tubular body <NUM> of the assessment assembly <NUM>. The fluid pathway receives production fluid 'F' from the isolation tubing <NUM> at the internal volume <NUM> and flows the production fluid 'F' to the first pressure sensor <NUM> that is disposed along the fluid pathway. The second pressure sensor <NUM> is disposed away from the fluid pathway, outside the assessment assembly <NUM>.

As shown in <FIG>, the assessment tool <NUM> has a first housing <NUM> that protects circuitry <NUM> that includes a battery system <NUM> that powers electric components of the circuitry <NUM>. The circuitry <NUM> also includes a pressure sensor system <NUM> and a controller and memory system <NUM>. The pressure sensor system <NUM> receives a first pressure value from the first pressure sensor <NUM> and a second pressure value from the second pressure sensor <NUM>. The circuitry transmits the first pressure value and the second pressure value to the receiver at the surface of the wellbore.

The assessment tool <NUM> also includes a second housing <NUM> coupled to the first housing <NUM>. The second housing <NUM> protects at least a portion of an electric turbine assembly <NUM> and a pressure compensator <NUM>. The electric turbine assembly <NUM> converts the kinetic energy of the production fluid into electricity, similar to a hydroelectric power plant. The electric turbine assembly <NUM> includes a turbine <NUM> axially coupled to a rotating shaft <NUM>. The turbine <NUM> rotates under fluidic pressure of the production fluid 'F' flowing through the turbine <NUM>. The turbine <NUM> rotates the shaft <NUM> that is coupled to an electric generator <NUM> that produces electricity through rotation of the shaft <NUM>. The electric generator <NUM> is electrically coupled to and configured to charge batteries of the battery system <NUM>. Thus, the assessment assembly <NUM> is an autonomous assessment assembly that uses a harvesting system (the electric turbine assembly <NUM>) configured to harvest energy from the production fluid 'F' to power electronics electrically coupled to the first and second pressure sensor.

The pressure sensor system <NUM> of the assessment tool <NUM> can do some processing of the pressure values, such as averaging, determining a minimum and maximum value, and computing standard deviations. The memory system <NUM> can store the pressure data from the sensors and the pressure sensor system <NUM> can measure, pack, and transmit the sensor data to the processor <NUM> at the surface of the wellbore (see <FIG>). The surface processor <NUM> can have more computational power than the pressure sensor system <NUM> and can run prediction models by comparing large quantitative datasets and using designed algorithms. The surface processor <NUM> can further transmit data to a remote secure server or end user dashboard. The surface processor <NUM> can also facilitate threshold monitoring and can trigger alarms. The electric generator <NUM> can power the battery system <NUM> and power the sensor system <NUM>, the pressure sensors <NUM> and <NUM>, and the wireless communications system of the sensor system <NUM>.

The assessment assembly <NUM> has a turbine housing <NUM> that includes a guide vane for the turbine <NUM>. The assessment assembly also includes a sensor hub <NUM> opposite the turbine housing <NUM>. As further described in detail below with respect to <FIG>, the sensor hub <NUM> is attached to an engagement assembly that receives and engages with a retrieving tool to retrieve the assessment assembly <NUM>. The first housing <NUM> and the second housing <NUM> are attached to and disposed between the sensor hub <NUM> and the turbine housing <NUM>. The first housing <NUM> and the second housing <NUM> together form a tubular body <NUM> that is attached to the turbine housing <NUM> and to the sensor hub <NUM>. The turbine housing <NUM> is movable along the longitudinal axis of the isolation tubing <NUM> and the sensor hub <NUM> is fixed to the inner wall of the isolation tubing. The sensor hub <NUM> can be releasably attached to the inner wall of the isolation tubing <NUM> (for example, with shear pins) to allow the assessment assembly <NUM> to be retrieved. The sensor hub can include sealing rings <NUM> (for example, O-rings) to isolate the pressure sensing ports of the second pressure sensor <NUM> from the inside of the isolation tubing <NUM>.

<FIG> shows a block diagram of a zonal isolation assessment system. The system includes the first sensor <NUM> and second sensor <NUM> in communication with the pressure sensor system <NUM>. The first sensor <NUM> and the second sensor <NUM> transmit the sensed pressure data to the pressure sensor system <NUM>, which can include a processor that processes the pressure data. The pressure sensor system <NUM> transmits the pressure information to the surface receiver <NUM> which can include a user interface that indicates the isolation integrity of the isolated zone. The pressure sensor system <NUM> can continuously or generally continuously transmit real-time data to the receiver <NUM>. The real-time data can represent a first set of pressure values sensed by the first pressure sensor <NUM> over time before and during production and a second set of pressure values sensed by the second pressure sensor <NUM> over time before and during production.

The first and second set of pressure values are usable to determine the zonal isolation integrity. For example, the pressure sensor system <NUM> or the processor <NUM> at the surface determines a difference between the first pressure value and the second pressure value and determines, based on comparing that difference to a user defined threshold, the zonal isolation integrity of the zonal isolation assembly. Specifically, the first set of pressure values are compared to the second set of pressure values to determine a rate of change between the first set of pressure values and the second set of pressure values.

For a zone to have good zonal isolation integrity (for a good seal), during drawdown of the wellbore, the second set of pressure values (the pressure at the annulus <NUM>) should remain constant, and not be affected by the drawdown pressure of the wellbore (the change in pressure of the first set of pressure values). Overtime, the second set of pressure values in the isolated zone can decrease slightly as water in the reservoir shifts inside the reservoir, causing small pressure changes. The time period from when the annulus pressure (the second set of pressure values) start to change, to when the values become stabile may imply which type of leakage is happening. For example, if the annulus pressure rapidly equalizes to the tubular pressure (the pressure inside the tubing <NUM>) after drawdown, there is a high continuous leakage rate between the isolated annulus <NUM> and the tubing <NUM> (and by extension, the production zone). If the annulus pressure stabilizes at <NUM>% of drawdown pressure change, and this occurs after several hours or even days, there may be production of water from the outside of the isolated zone. In such cases, the length of the isolated zone needs to be increased.

The rate of change is compared to a threshold that represents a percentage of a drawdown pressure change. The drawdown pressure change is, for example, <NUM> Psi when the no production pressure is <NUM> Psi in the tubing <NUM> and the production pressure in the tubing <NUM> is <NUM> Psi. Thus, the user-defined threshold can represent <NUM>% of the drawdown pressure change, and the isolation integrity is determined to be compromised when the rate of change over time is equal to or larger than the threshold, and normal isolation integrity is determined when the rate of change over time is less than the threshold. In some implementations, only the pressure values from the second sensor can be used to determine zonal isolation integrity. For example, the rate of change of the second pressure value from the time the first pressure value detects the drawdown pressure can be used to detect zonal isolation integrity. Thus, the rate of change of the second set of pressure values can be used from a point in time at the beginning of a drawdown pressure.

In some implementations, the threshold can be a value that represents a difference between the first set of pressure values and the second set of pressure values, or a value that represents a rate of change between the first set of values and the second set of values. For example, another way of quantifying the isolation integrity is by using a leak rate percentage (for example, leakage percentage). In this percentage range, <NUM>% can represent a full opening between the isolated zone and the tubular section, indicating full fluid communication. Conversely, <NUM>% can indicate no fluid communication, and that the isolated zone has full sealing integrity. Thus, the monitoring or assessment system <NUM> includes continuous monitoring, and can also monitor trends over time. The system <NUM> can monitor the entire isolated zone 'I' of the wellbore <NUM>, and can permanently monitor isolated zones in the open hole section of the wellbore <NUM>.

<FIG> shows a side view of the assessment assembly <NUM> with the sensor hub <NUM> attached to an engagement assembly or snap latch <NUM>. The snap latch <NUM> can be releasably coupled to the isolation tubing <NUM>. A retrieving tool can be used to retrieve the assessment assembly <NUM> from the wellbore <NUM>. The retrieving tool has a matching profile with the internal dimensions of the snap latch <NUM>, so that when the retrieving tool is connected, a jarring mechanism on the tool string can transmit impact force to the assessment assembly <NUM> to disconnect the assessment assembly from the isolation tubing <NUM>.

<FIG> shows a flow diagram of an example method <NUM> of determining an isolation integrity of an isolated zone in a wellbore. The method <NUM> includes receiving, by a receiver at or near a surface of a wellbore, a first pressure value and a second pressure value from a zonal isolation assembly disposed downhole of production tubing, the zonal isolation assembly comprising <NUM>) isolation tubing, <NUM>) a first sealing element coupled to the isolation tubing, <NUM>) a second sealing element coupled to the isolation tubing and disposed downhole of the first sealing element, <NUM>) a first pressure sensor residing at the internal volume of the isolation tubing and configured to sense the first pressure value, and <NUM>) a second pressure sensor residing at the annulus and configured to sense the second pressure value (<NUM>). The method also includes determining, based on a difference between the first pressure value and the second pressure value, a third value representing a zonal isolation integrity of the zonal isolation assembly (<NUM>).

Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope of the disclosure. Accordingly, the exemplary implementations described in the present disclosure and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations.

Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents.

The singular forms "a", "an" and "the" include plural referents, unless the context clearly dictates otherwise.

As used in the present disclosure and in the appended claims, the words "comprise," "has," and "include" and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used in the present disclosure, terms such as "first" and "second" are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words "first" and "second" serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term "first" and "second" does not require that there be any "third" component, although that possibility is contemplated under the scope of the present disclosure.

Claim 1:
A zonal isolation assessment system (<NUM>) comprising:
a receiver (<NUM>) residing at or near a surface of a wellbore (<NUM>);
a processor (<NUM>) communicatively coupled to the receiver (<NUM>);
production tubing (<NUM>) configured to be disposed in the wellbore;
a zonal isolation assembly (<NUM>) configured to reside downhole of and fluidically coupled to the production tubing, the zonal isolation assembly configured to isolate a zone of the wellbore and comprising:
isolation tubing (<NUM>) configured to flow production fluid from the wellbore to the production tubing (<NUM>),
a first sealing element (<NUM>) coupled to the isolation tubing, and
a second sealing element (<NUM>) coupled to the isolation tubing and disposed downhole of the first sealing element,
the first sealing element and the second sealing element configured to be set on a wall (<NUM>) of the wellbore to fluidically isolate an internal volume (<NUM>) of the isolation tubing from an isolated annulus (<NUM>) defined between the isolation tubing and the wall of the wellbore, the annulus extending from the first sealing element to the second sealing element; and
an assessment assembly (<NUM>) disposed at least partially inside the isolation tubing and communicatively coupled to the receiver, the assessment assembly comprising:
a first pressure sensor (<NUM>) residing at the internal volume (<NUM>) of the isolation tubing (<NUM>) and configured to sense first pressure data representing a fluidic pressure of the internal volume over time, and
a second pressure sensor (<NUM>) residing at the annulus (<NUM>) and configured to sense second pressure data representing a fluidic pressure of the annulus over time,
the assessment assembly configured to transmit, to the receiver, the first pressure data and the second pressure data;
wherein the processor is configured to determine, based on a rate of change over time between the first pressure data and the second pressure data, a level of zonal isolation integrity of the zonal isolation assembly.