FIELD OF THE INVENTION

The present invention relates to a downhole measurement apparatus, and in particular to a downhole measurement apparatus configured to determine a flow condition at a flow control device, such as an inflow control device, within a wellbore.

BACKGROUND TO THE INVENTION

In the oil and gas industry wellbores are drilled into the earth to intercept subterranean formations, which typically include a combination of oil, gas and water. These formation components are normally stratified into relatively well defined layers, with a lower layer of water, an intermediate layer of oil, and an upper layer, or cap, of gas. It is highly desirable to minimise the production of water, and in some cases gas, from a formation, and as such wellbores are normally established which follow or track through the oil layer, ensuring that the production zones are maintained within this favoured layer. In many cases this results in the creation of wellbores or multilateral wellbores which have both vertical and non-vertical sections.

Production is achieved by flow of the oil from the formation into the wellbore, and then into a tubing string, typically called a production tubing string, which provides a flow path from the production zone or zones to surface. Over time the relative levels of oil, gas and water will vary, and it is possible that the water layer will eventually encroach into one or more production zones, requiring remedial attention, which may necessitate a temporary termination in production, which is extremely undesirable. In some cases the onset of water production may result in abandoning the well.

Typically, a production tubing string will be arranged to permit inflow of oil at a number of locations along its length in order to maximise production rates from the formation. In most cases a variation in the ambient conditions, such as formation pressure, exists between different inflow regions which creates a corresponding variation in production rates across the formation. This variation may result in an imbalance in the extraction rates from the formation, and may lead to the onset of water production, for example by water coning, at one or more inflow regions before others. As noted above, producing water is highly undesirable.

In order to address or minimise the effect of imbalanced production across a formation or wellbore it is known in the art to install inflow control devices (ICDs) within the production tubing string. Each ICD is configured to provide a level of fluid resistance, for example by use of orifices, nozzles or the like to provide a degree of control of inflow. Appropriately configured ICDs are distributed axially along the length of a production string to seek to balance the rate of production from the formation. In this respect the individual ICDs may be configured in accordance with experience in the art, prior knowledge, logging measurements, estimations or the like of the ambient formation conditions. For example, it is known in the art that in horizontal wells water production is most likely to initially occur at the heel of the well, and as such an ICD at the heel of a horizontal well may be configured to provide a greater flow resistance than an ICD at the toe of the well.

Nevertheless, it is still possible that ICDs will be selected and configured poorly, for example due to inaccurate data on geological conditions, and also that the ambient conditions may vary quite significantly over time, such that the configuration may eventually become unsuitable. In this respect it is difficult for operators to determine the effectiveness of an ICD configuration, and to monitor this over time.

SUMMARY OF THE INVENTION

According to a first aspect of the present invention there is provided a downhole measurement apparatus comprising: a downhole flow control device comprising a tubular body having an internal flow path and at least one fluid port for permitting flow of a fluid between the internal flow path and an external location; and

a sensor assembly comprising a tubular body and a sensor arrangement configured for use in determining a fluid pressure externally of the flow control device and a fluid pressure within the internal flow path of the flow control device.

The apparatus may be adapted to be located within a wellbore. In use, the apparatus may define an annular region between an outer surface thereof and an inner surface of the wellbore. The at least one fluid port of the flow control device may permit communication between the annulus and the internal flow path of the flow control device. The sensor arrangement may be configured for use in determining a fluid pressure within the annulus and within the internal flow path of the flow control device.

The flow control device may define an inflow control device for permitting flow of a fluid into the flow path from an external location. This arrangement may permit the flow control device to receive fluid from an external location. For example, the flow control device may be configured to receive a formation fluid, such as oil, water or the like. The flow control device, and the apparatus, may be configured for use in production applications.

The flow control device may define an outflow control device for permitting flow of a fluid from the flow path to an external location. This arrangement may permit the flow control device to deliver a fluid to a downhole location externally of the apparatus. For example, the flow control device may be configured to permit a fluid, such as water, fracing fluid, proppant or the like, to be injected into a subterranean formation. The flow control device, and the apparatus, may be configured for use in, for example, injection applications. The flow control device may be configured for use in water injection, for example for production enhancement, matrix support or the like. The flow control device may be configured for use in fracturing applications.

The flow control device may define both an inflow control device and an outflow control device. For example, at least one fluid port may permit inflow, and at least one fluid port may permit outflow.

The flow control device may be configured to control the rate of flow of fluid to and/or from an external location. For example, the flow control device may be configured to restrict the rate of flow. In embodiments where the flow control device defines an inflow control device, this arrangement may permit a degree of control of a production rate from a downhole region of a subterranean formation. In embodiments where the flow control device defines an outflow control device , this arrangement may permit a degree of control of a fluid injection rate, fracturing rate and/or extent.

At least one fluid port may comprise a flow restriction. At least one fluid port may comprise an orifice, nozzle or the like. At least one port inlet may be arranged to generate an energy loss in a fluid flowing therethrough. For example, at least one fluid port may be configured to generate fluid friction. At least one fluid port may define a tortuous flow path or the like.

The determined fluid pressures internally and externally of the flow control device may be used to determine, estimate, evaluate or the like a flow condition associated with the flow control device. In one embodiment the determined internal and external fluid pressures may be used to evaluate a rate of flow associated with the flow control device. This arrangement may, for example, permit the effectiveness of the flow control device to be established and/or monitored.

At least one fluid port may be configured to establish a pressure change in fluid flowing therethrough. At least one fluid port may be configured to establish a back pressure to establish a pressure change. This pressure change may be determined, evaluated or the like by the sensor assembly. In one embodiment a flow condition or the like of the fluid may be evaluated in accordance with the determined internal and external pressures and one or more properties of at least one fluid port, such as dimensional properties. For example, at least one fluid port may define a predetermined inlet area and a predetermined outlet area, wherein a flow condition may be determined as a function of the internal and external fluid pressures and the inlet and outlet areas of at least one fluid port. This arrangement may permit a flow rate to be established.

The sensor assembly may be configured to determine a pressure differential between internal and external locations of the flow control device. The sensor assembly may be configured to indirectly determine a pressure differential, for example by first determining the value of the internal and external pressures and then determining the differential between these. The sensor assembly may alternatively, or additionally, be configured to directly determine a pressure differential

The flow control device may be configured to be coupled to a tubing string, such that the flow control device may provide fluid communication between the tubing string and an external location via the at least one fluid port. The tubular body of the flow control device may be configured to be arranged coaxially with the tubing string. The flow control device may be configured to define an integral part of the tubing string. The tubing string may be arranged to deliver a fluid received from the flow control device to a remote location, such as a surface location. The tubing string may define a production tubing string. The tubing string may be arranged to deliver a fluid to the flow control device. The flow control device may be configured to be deployed into a wellbore on the tubing string.

The sensor assembly may be configured to be coupled to a tubing string.

The sensor assembly and flow control device may be configured to be coupled to a common tubing string. The flow control device and sensor assembly may comprise separate tubular bodies. The separate tubular bodies may be configured to be coupled together, for example via a threaded connection or the like. In this arrangement the flow control device may comprise a first or flow control device tubular body, and the sensor assembly may comprise a second or sensor assembly tubular body. This arrangement may permit a modular arrangement to be provided, which may provide improvements in handling, storage, deployment, maintenance and the like. The first or flow control device tubular body and the second or sensor assembly tubular body may be configured to be coaxially aligned, in end-to-end relation.

In an alternative arrangement the flow control device and sensor assembly may comprise a common tubular body.

An outer diameter of the flow control device may be substantially equal to an outer diameter of the sensor assembly. This may eliminate or minimise variations on flow properties externally of the apparatus, for example by minimising variations in an annulus area defined between the apparatus and a wall of a wellbore, when in use. Minimising such variations in the flow properties externally of the apparatus may permit the sensor assembly to accurately determine the internal and external pressures associated with the flow control device.

The sensor assembly may comprise a gauge mandrel.

At least a portion of the sensor arrangement may be located externally of the sensor assembly tubular body. In one arrangement at least a portion of the sensor arrangement may be located on an external surface of the sensor assembly tubular body. Alternatively, or additionally, the sensor assembly tubular body may define a recess in an external surface thereof, and at least a portion of the sensor arrangement may be located within the recess.

The sensor assembly may define a port permitting communicating between an internal region thereof and an externally located sensor arrangement. This arrangement may permit an externally located sensor arrangement to be exposed to a fluid pressure internally of the sensor assembly in order to determine a pressure differential.

At least a portion of the sensor arrangement may be located internally of the sensor assembly tubular body. The sensor assembly may define a port permitting communicating between an external region thereof and an internally located sensor arrangement.

A portion of the sensor arrangement may be located internally of the tubular body of the sensor assembly, and a portion of the sensor arrangement may be located externally of the tubular body of the sensor assembly.

The sensor arrangement may comprise at least one pressure sensor configured to be exposed to fluid pressure from both internally and externally of the apparatus. In this configuration the sensor arrangement may comprise at least one differential pressure sensor.

The sensor arrangement may comprise at least one sensor configured to be exposed to fluid pressure from internally of the apparatus, and at least one further pressure sensor configured to be exposed to fluid pressure from externally of the apparatus.

The sensor arrangement may comprise a diaphragm type pressure sensor, transducer type pressure sensor, distributed pressure sensor, such as a fibre optic distributed pressure sensor, or the like, or any suitable combination thereof.

The apparatus may be configured to accommodate a cable associated with the sensor arrangement. The cable may be configured to communicate signals to and/or from the sensor arrangement. The cable may comprise an electrical conductor, optical conductor, hydraulic conduit or the like.

The sensor arrangement may be configured to communicated with a remote location via a cable, optical wire, hydraulic conduit or the like. The sensor arrangement may be configured to wirelessly communicate with a remote location, for example using acoustic signals, pressure pulses, EM radiation, such as radio waves, microwaves, or the like.

The apparatus may be configured to determine at least one downhole property. The sensor assembly of the apparatus may be configured to determine at least one downhole property. The at least one downhole property may comprise temperature, chemical composition, conductivity, water saturation, interface properties, such as properties of an oil/water interface, carbon composition, oxygen composition, salinity, acoustic properties or the like.

The apparatus may be configured to determine at least one downhole property using a signal, such as an acoustic signal, electromagnetic signal or the like. The signal may be used to determine a flow condition, phase condition or the like of a downhole fluid.

The apparatus may be configured to determine a phase property of a downhole fluid. The sensor assembly may be configured to determine a phase property of a downhole fluid. The apparatus may be configured to permit a differentiation to be made between at least gas and liquid phases of a downhole fluid. The apparatus may be configured to permit a differentiation to be made between different liquid components of a liquid phase, such as oil and water.

The apparatus may comprise a multiphase flow meter.

The apparatus may comprise one or more sensors, such as temperature sensors or the like. The apparatus may comprise one or more distributed sensors, such as fibre optic distributed sensors, for example distributed temperature sensors.

The apparatus may comprise a sensor configured to function by communicating radioactivity through towards a downhole region. Such a sensor may be configured for operation by gamma ray spectroscopy, such as in a carbon/oxygen sensor. The apparatus may comprise a sand control assembly, such as a sand screen assembly. The sand control assembly may be configured to at least partially cover at least one fluid inlet.

At least one fluid port may be adjustable, for example to adjust the rate of flow therethrough. At least one fluid port may be adjustable in accordance with a determined fluid pressure. At least one fluid port may be adjustable in accordance with a determined downhole property, such as a phase property of a downhole fluid. At least one fluid port may be configured to be isolated. For example, at least one fluid port may be isolated to prevent the inflow of water from an external location.

The apparatus may be configured for use with one or more sealing assemblies, such as packer assemblies, for example swellable packer assemblies, mechanical packer assemblies, inflatable packer assemblies or the like, or any suitable combination thereof. The apparatus may be configured to be positioned between a pair of axially separated sealing assemblies.

The packer assemblies may be configured to accommodate one or more cables to pass therethrough, such as cables associated with the apparatus, for example cables configured to permit communication with the sensor assembly.

The apparatus may comprise one or more sealing assemblies.

The apparatus may be used singly, or may be used in combination with similar or identical apparatus within a single wellbore.

The present invention may permit monitoring of the flow control device. Such monitoring may permit advanced knowledge of, for example, the flow conditions, which may allow the requirement for any remedial action, such as intervention or workover action to be recognised in advance, and also may assist in selection of the most appropriate form remedial action which will provide the most benefit with minimal impact on well operations.

According to a second aspect of the present invention there is provided a downhole measurement apparatus comprising: a downhole flow control device comprising a tubular body having and internal flow path and at least one fluid port for permitting flow of a fluid between the internal flow path and an external location; and

a sensor assembly comprising a tubular body and a sensor arrangement configured for use in determining a fluid pressure differential between external and internal locations of the flow control device.

According to a third aspect of the present invention there is provided a method of downhole measurement, comprising:

providing a flow control device comprising a tubular body in combination with a sensor assembly comprising a tubular body;

permitting a downhole fluid to flow through at least one fluid port within the flow control device; and

determining a fluid pressure externally of the flow control device, and a fluid pressure internally of the flow control device.

According to a fourth aspect of the present invention there is provided a method of downhole measurement, comprising:

providing a flow control device comprising a tubular body in combination with a sensor assembly comprising a tubular body;

permitting a downhole fluid to flow through at least one fluid port within the flow control device; and

determining a fluid pressure differential between external and internal locations of the inflow control device.

The method according to the third and/or fourth aspect may comprise steps associated with the use of the apparatus according to the first and/or second aspect, and features and uses of the apparatus defined above are applicable to the method according to one or more aspects of the invention. According to a fifth aspect of the present invention there is provided a production tubing string comprising at least one downhole measurement apparatus according to the first and/or second aspect.

The tubing string may comprise a plurality of downhole measurement apparatus axially arranged along the length of the tubing string.

Each downhole measurement apparatus may be configured to communicate with an isolated downhole region. An isolated downhole region may be established by one or more sealing assemblies, such as packer assemblies. The tubing string may comprise one or more sealing assemblies.

According to a sixth aspect of the present invention there is provided a completion assembly comprising at least one downhole measurement apparatus according to the first and/or second aspect.

According to a seventh aspect of the present invention there is provided a downhole measurement apparatus comprising:

a downhole flow control device comprising at least one fluid port for permitting flow of a fluid between external and internal locations of the flow control device; and a sensor assembly coupled to the flow control device and comprising a sensor arrangement configured for use in determining a fluid pressure differential between external and internal locations of the flow control device.

The sensor assembly may be configured to be releasably coupled to the flow control device.

The sensor assembly may comprise a gauge mandrel.

According to an eighth aspect of the present invention there is provided a downhole measurement apparatus comprising:

a downhole flow control device comprising a tubular body having and internal flow path and at least one fluid port for permitting flow of a fluid between the internal flow path and an external location; and a sensor assembly comprising a tubular body and a sensor arrangement configured for use in determining at least one downhole property.

The at least one downhole property may comprise pressure, temperature, chemical composition, conductivity, water saturation, interface properties, such as properties of an oil/water interface, carbon composition, oxygen composition, salinity, acoustic properties or the like.

The apparatus may be configured to determine a phase property of a downhole fluid. The sensor assembly may be configured to determine a phase property of a downhole fluid. The apparatus may be configured to permit a differentiation to be made between at least gas and liquid phases of a downhole fluid. The apparatus may be configured to permit a differentiation to be made between different liquid components of a liquid phase, such as oil and water.

The apparatus may comprise one or more sensors, such as pressure, temperature sensors or the like. The apparatus may comprise one or more distributed sensors, such as fibre optic distributed sensors, for example distributed temperature sensors.

The apparatus may comprise a sensor configured to function by communicating radioactivity through towards a downhole region. Such a sensor may be configured for operation by gamma ray spectroscopy, such as in a carbon/oxygen sensor.

The apparatus may comprise a multiphase flow meter.

Features presented above in relation to the first to seventh aspects may also apply to the eighth aspect. However, for the purposes of brevity these features have not been repeated.

According to a ninth aspect of the present invention there is provided a downhole measurement apparatus comprising:

an inflow control device comprising a tubular body and at least one fluid inlet for permitting flow of a fluid into the tubular body from an external location; and a sensor assembly comprising a tubular body and a sensor arrangement configured for use in determining a fluid pressure externally of the inflow control device and a fluid pressure internally of the flow control device.

According to a tenth aspect of the present invention there is provided a downhole measurement apparatus comprising:

an outflow control device comprising a tubular body and at least one fluid outlet for permitting flow of a fluid from the tubular body to an external location; and a sensor assembly comprising a tubular body and a sensor arrangement configured for use in determining a fluid pressure externally of the outflow control device and a fluid pressure internally of the outflow control device.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 is a diagrammatic representation of a downhole measurement apparatus according to an embodiment of the present invention, shown in use within a wellbore; and

Figure 2 is a cross sectional view of the downhole measurement apparatus shown in Figure 1.

DETAILED DESCRIPTION OF THE DRAWINGS

A downhole measurement apparatus in accordance with an embodiment of the present invention is shown in Figure 1. The apparatus, generally identified by reference numeral 10, is shown in use deployed within a wellbore 12 which intercepts a subterranean formation 14 which contains hydrocarbons. The apparatus 10 is coupled to and forms part of a production tubing string 15 which is configured to communicate fluids, such as oil, produced from the formation 14 to surface. The tubing string 15 comprises a pair of packers 16 which are located on axially opposing sides of the apparatus 10 and function to establish an isolated annular production zone 18 within which the apparatus 10 is located. In the embodiment shown the packers 16 are shown located adjacent the apparatus 10. It should be understood, however, that this is for clarity of the drawings and that the packers may be located at any appropriate distance from the apparatus, thus extending, or reducing, the axial length of the annular zone 18. The packers 16 may be of any suitable form, but in the embodiment shown are swellable packers. The packers 16 prevent the migration of formation fluids along the annulus region formed between the tubing string and the wellbore 12.

The tubing string 15 may comprise additional packers along its length, as represented by reference numeral 20, in order to provide a number of isolated regions.

The apparatus 10 comprises a flow control device, which in the embodiment shown is an inflow control device (ICD) 22 which includes a plurality of fluid inlets 24 which permit formation fluids which have entered the isolated annulus region 18 from the formation 14 to flow into the ICD 22 and be communicated along the tubing string 15. The ICD is configured to control the rate of inflow of fluid from the annulus 18 to permit a degree of control of the production rate from the formation 14.

The apparatus 10 further comprises a sensor assembly 26 which is coupled to the ICD 22 via a threaded connection 28 and includes a sensor arrangement 30 for use in determining at least one downhole property. In the embodiment shown the sensor arrangement 28 is mounted externally of the sensor assembly 26 and is configured for use in determining a the pressure of the fluid within the isolated annulus region 18 and the pressure of the fluid which has flowed into the ICD 22 via the inlets 24.

A cable 32 extends along the length of the tubing string 15 and functions to communicate with the sensor arrangement 30. In the embodiment shown the cable 32 is a fibre optic cable. The cable 32 may be configured to form part of a distributed temperature sensor arrangement which is known in the art. As shown, the cable 32 may extend below the apparatus 10, for example to communicate with other apparatus, or to permit a temperature distribution below the apparatus 10 to be determined.

The apparatus further comprises a sand screen 34, represented in broken outline, for minimising the inflow of sand and other particulate matter associated with the formation 14.

Reference is now additionally made to Figure 2 in which a longitudinal cross- sectional view of the apparatus 10 is shown. As shown, both the ICD 22 and sensor assembly 26 are separate components, both tubular in form, and coupled together via a threaded connection 28. The ICD 22 and the sensor assembly 26 each describe a common external diameter which minimises variations in fluid conditions, such as pressure, within the annular region 18 (Figure 1 ). Otherwise, any variations in fluid conditions within the annulus may provide inaccurate pressure results.

The inlets 24 of the ICD are configured in the form of nozzles and are dimensionally constructed, for example in terms of flow area, to establish a pressure difference, for example by creating a back pressure, between the pressure Pa within the annulus 18, and the pressure Pts within the tubing string 15. This pressure difference is measured by the sensor arrangement 30 of the sensor assembly 26. In the embodiment shown the sensor arrangement 30 comprises a first pressure sensor 30a which senses the fluid pressure Pa within the annulus, and a second pressure sensor 30b which senses the fluid pressure Pts within the tubing string 15. The sensor assembly 26 defines a fluid port 36 which permits the second pressure sensor 30b to be exposed to the internal tubing string pressure Pts.

The determined pressures may be used in combination with the dimensional properties of the fluid inlets 24 in order to evaluate or determine the flow rate of fluid being produced from the formation. This information may advantageously permit the effectiveness of the ICD 22 to be monitored, and to allow any requirement for remedial action to be identified. For example, where a greater than expected flow rate is identified this may permit a user to recognise that an early onset of water production may be expected.

Although not shown, a number of apparatus 10, or a combination of one or more apparatus 10 with individual ICDs 22 may be distributed along the length of the tubing string 15 in order to provide control of production over a length of tubing string 5. For example, an ICD with a greater flow restriction may be positioned at a heel region of a deviated wellbore, and an ICD with a lower flow restriction may be positioned at a toe region, such that a balance in production rates across the wellbore may be achieved.

It should be understood that ^' the embodiment described herein is merely exemplary and that various modifications may be made thereto without departing from the scope of the invention. For example, in other embodiments the sensor assembly may alternatively, or additionally, be configured to measure some other downhole property, such as temperature, chemical composition, conductivity, water saturation, interface properties, such as properties of an oil/water interface, carbon composition, oxygen composition, salinity, acoustic properties or the like. The sensor assembly may be configured to determine a phase property of a downhole fluid, such as to permit a differentiation to be made between at least gas and liquid phases of a downhole fluid, and/or a differentiation to be made between different liquid components of a liquid phase, such as oil and water. This may be beneficial in recognising the onset of water production, permitting remedial action to be taken when appropriate. The apparatus may comprise a multiphase flow meter. Additionally, the inlets to the ICD may be adjustable. In this arrangement adjustment may be made in accordance with any determined property, such as pressure. Furthermore, although two separate pressure sensors 30a, 30b are shown, a single differential pressure sensor may be utilised. Also, the sensor arrangement 30 may be located internally of the sensor assembly.

Additionally, in the embodiment shown the apparatus includes an inflow control device. However, in other embodiments the apparatus may alternatively, or additionally, comprise an outflow control device for permitting outflow of a fluid from the apparatus into the annulus region, and optionally into the formation. Such an arrangement may have application in fracturing operations, injection operations or the like.