US20130333879A1

US20130333879A1 - Method for Closed Loop Fracture Detection and Fracturing using Expansion and Sensing Apparatus

Info

Publication number: US20130333879A1
Application number: US13/919,428
Authority: US
Inventors: Wajid Rasheed
Original assignee: Individual
Current assignee: Smart Reamer Drilling Systems Ltd
Priority date: 2008-06-27
Filing date: 2013-06-17
Publication date: 2013-12-19
Also published as: GB0811815D0; US8235144B2; CN102137981A; GB2465504A; CN102137981B; GB2465504C; EP2327857A1; US8528668B2; GB201002533D0; US9593538B2; EP2327857A4; WO2009156552A1; US8511404B2; US9677342B2; US20140060933A1; US20140299385A1; US20130306373A1; MX2010014189A; US20130306375A1; EP2746527B1

Abstract

An expansion and sensing apparatus used to detect natural and hydraulic fractures. In a closed loop aspect of the invention a microprocessor may be incorporated to process data which identifies natural fractures and optimises the coordinates for setting an isolation device, hydraulically fracturing the formation, identifying the effectiveness of the hydraulic fracture and if required repeat the hydraulic fracture at the same co-ordinates or select further co-ordinates in order to propagate an optimised fracture pathway and maximise production. The apparatus may be used with microseismic, tiltmeters, etc.

Description

FIELD OF THE INVENTION

This invention relates to an apparatus and method capable of detecting fractures and expanding a tubular or wellbore isolation device in oil and gas wells. The expandable elements can be configured to expand to the actual wellbore diameter while sensors such as acoustic sensors or mechanical probes can detect wellbore fractures. Further measurements can be obtained after expansion and used in conjunction with fluid properties, vibration, flow, hydraulic force, pressure, temperature.
It is to be understood that the term ‘expansion’ as used herein refers to the capacity of the expandable element to expand outwardly and against the interior wall of a passage, such as a borehole, especially a wellbore, or a tubular used as a casing, and then to maintain pressure or isolate pressure from the formation. It is not always essential that the expandable element such as a bridge plug or packer be expanded, since the sensing elements can be used to detect fractures without necessarily expanding the packer.
The invention relates to an Expansion and Sensing apparatus and method for identifying natural fractures and optimising the process of man-made or hydraulic fractures in oil and gas wells. The technology is especially useful in unconventional reservoirs that hold tight gas, shale gas, coal bed methane, shale oil, etc. If critical knowledge of the fracture i.e. reservoir interconnectivty, fractures, pathways or dips can be gained both pre and post fracking this would lead to greater recovery rates due to more effective wellbore fracking by increasing the actual fracked footage in the payzone. The invention is suitable for open and cased/liner hole and hydraulic fracturing with or without perforating tubing.
The apparatus and method is capable of evaluating natural fractures to determine optimal depths and locations to set an expandable element such as packers or other wellbore isolation devices so as to optimise the fracture pathways that are naturally present once the wellbore is isolated and the man-made or hydraulic fractures can be propagated. The apparatus and method finds particular use in characterising fractures and their geo-physical and petro-physical features principally using sensors or wellbore imaging based on electrical, ultrasonic, electromagnetic or nuclear measurements to characterise the fracture and wellbore isolation devices using expandable packers, swellable packers, intelligent control valves, intelligent control devices. Alternative means can be used to identify the fracture and isolate the wellbore. Any type of fracturing method itself can be employed in the invention and this is not limited to hydraulic fracturing, as different types of reservoirs may require the use of differing methodologies or new fracturing techniques.
In a closed loop aspect of the invention a microprocessor may be incorporated to process data which identifies natural fractures and optimise the coordinates for setting an isolation device, hydraulically fracturing the formation, identifying the effectiveness of the hydraulic fracture and if required repeat the hydraulic fracture at the same co-ordinates or select further co-ordinates in order to propagate an optimised fracture pathway and maximise production.
On average, 65% of hydrocarbons are left underground this equates to a recovery rate of 35%. Unconventional reservoirs often have as many as 10 stages requiring fracturing. An optimized fracture method and apparatus would potentially help increase recovery rates. It is to be understood that the term ‘fracture’ as used herein refers to the capacity of the invention to evaluate an aperture in the formation which may vary in size from millimetres to metres, have a determined angular orientation and may connect to other fractures in the same plane or another plane within a formation that extends from the tool at a determined angle and reaches a given angular depth and a true vertical depth.
In contrast, prior art logging tools are differentiated as part of a separate function i.e. are tripped out of the hole and a fracking assembly entered into the hole. In the prior art, once a fracking assembly is located, neither a sensor nor an imaging tool capable of detecting fractures is in communication with the fracking operator due to the complex downhole configuration of fracking and the location of the fracking stages. The technology overcomes these issues by providing pre and post fracking data and can also be configured with wellbore isolation devices and may be configured so as to be retrievable through a packer to determine the effectiveness of a frack job or a frac stage. It can be run with a rotary steerable to detect fractures but it is not necessary for fracking to occur using wellbore isolation devices conveyed on drill pipe. An expandable element and fracture sensor to determine natural fractures before formations are hydraulically fractured and thereby increase hydrocarbon recovery factors by optimally setting the wellbore and the wellbore isolation device such as a packer; a method of closed loop fracture identification, fracking and identifying frack effectiveness.
In one embodiment the present apparatus and method itself overcomes these issues by providing pre and post fracking data and can also be configured with wellbore isolation devices and may be configured so as to be retrievable through a packer to determine the effectiveness of a frack job or a frac stage. In another embodiment the invention is configured with a rotary steerable to detect fractures but it is not necessary for fracking to occur using wellbore isolation devices conveyed on drill pipe.
Other aspects of the invention include a method of operating an expandable element and fracture sensor to determine natural fractures before formations are hydraulically fractured and thereby increase hydrocarbon recovery factors by optimally setting the wellbore and the wellbore isolation device such as a packer; a method of closed loop fracture identification, fracking and identifying frack effectiveness, identifying fractures, angularly, axially and vertically ahead of hydraulic fractures; a method of pre and post frac analysis using a closed loop system, creating a an optimised sensing zone. In a further aspect, the invention relates to an apparatus for controlling logging and wellbore placement in real-time. The invention may also be combined with micro-seismic, tiltmeters, frac tracers, proppant, or sensing of a frack parameters such as flow, pressure, temperature, depth, azimuth, inclination to provide insight into the fracking process.
When deciding the optimal trajectory and placement of an exploration or production well and its completion, numerous downhole activities are conducted to ensure the highest recovery of hydrocarbons and minimise the production of water over the well's life-span. Geo-physical data such as formation porosity, permeability, oil, water, gas contact zones, formation beds and dips are required to be known to steer the well to its optimal location. A variety of logging-while-drilling technology such as neutron density, gamma ray, resistivity and acoustic investigation tools are commonly used to identify formations and evaluate their features. (FIG. 1).
For unconventional wells, the present invention provides insight into natural fractures and their interplay with hydraulic fractures. Many considerations affect the fracture matrix such as organic content, porosity, permeability, brittleness, orientation, pressure but as a general rule, because hydraulic fractures propagate along the path of natural fractures, detecting natural fractures is most useful in enlarging and stabilizing the natural fracture matrix. Although, many fractures appear closed in cores, markers i.e. differing properties from the surrounding rock such as pressure, impedance, calcite lining, etc provide clues to their detection. Consequently, the invention would enable oil companies to maximise production by pin pointing natural fractures while drilling, feed these into the fracture matrix and complement micro seismic, tiltmeter, frac tracers, proppant effectiveness etc. Thus the invention embodies a truly optimised closed loop method for open hole/cased hole completions using packers or sleeves. Further embodiments may determine fracture detection on the open hole completion or stimulation string where a perforating string is involved suitable reconfiguration of the technology.
The present invention details an embodiment of a sensor to detect a fracture. As is known in the art, fractures may be derived from a variety of formation evaluation data which comprise acoustics, electro-magnetics, resistivity or conductance measurements, neutron density, alpha particle measurements, photoelectric measurements, gamma ray. In fact any type of sensor that can detect a fracture is useful in the invention. Alternatively or additionally a wellbore image may be provided.
Several types of sound based investigation sensors exist such as passive seismic that record natural seismic events, active seismic that generate and register sound waves from man-made sources and those known as acoustics (below 20,000 Hz) and those known as ultrasonic (above 20,000 Hz). It is understood that the term ‘acoustic’ covers ultrasonic, sonic and other frequencies.
Seismic tools provide wide-scale geological data, however these have poor resolution of formation detail and drilling itself is the true test of geophysical formation characteristics. Therefore, there is a need for and reliance on real-time acoustic while drilling tools. These tools use transducers or sources to create high frequency sound waves which are propagated as shear or pressure waves in solids and fluids respectively. Sound waves are further classified as those travelling within the wellbore (Stoneley waves), the near formation as (Flexural waves) and far formation as (Body waves). Through an evaluation of the echo pulse, its maxima and minima, which are received back by the sensor/receiver, and derivations thereof, calculations, can be made as to the time interval between signal transmission and recording the echo to determine the distance to an object or formation feature. Further, using algorithms various characteristics such as formation density, void spaces, fluid saturations, fluid trapping and formation direction changes such as beds or dips all have definite signature velocities that correspond to their reflective ability.
In all of these applications, the prior art suffers from two major limitations namely a lack of pre and post frack data (FIG. 2, 90, 100) and the integration thereof. Firstly, sensor and natural fracture data is not always available to set the packer in a timely manner based on fracture evaluation (100). The discontinuity (100 feet or more) between sensors and the packer leads to a trial and error approach.
Second, the effectiveness of the frack job is not determined as the prior art may not be deployed below the packer or may not be retrievable through the packer to determine the orientation and propagation of the hydraulic fractures (90). This severely limits the ability to repeat the frack job to allow for perforation, fracture propagation and proppant to be pumped through (FIG. 2). In this way, the prior art can only provide for formation evaluation subsequent to drilling. This is unsatisfactory as it prevents the optimal placement of the packer and the wellbore due to the non-existent or tardy arrival of formation data after wellbore placement has already occurred.
Measurement may involve the acquisition and communication to surface of various types of wellbore data such as resistivity, porosity, permeability, azimuth, inclination and borehole diameter or rugosity, formation dips or bedding angles. Such measurements are known in the art and in the interest of brevity therefore are shown conceptually only.
In the event of a productive hydrocarbon bearing zone having been unsuccessfully fractured (bypassed or exited or simply not fractured), there is a missing step between the data showing where the hydrocarbons are located and the subsequent production. Often, the missing step leads to uncertainty, additional cost and can be accompanied by a loss of production as hydrocarbons are bypassed or the optimal fracking stage configuration within a low permeability zone is lost. In the case of productive zones, characterization using wireline or micro-seismic occurs after fracking, once the assembly has been tripped out of the hole and the area has been traversed.
The present invention may be suitably combined with microseismic, tiltmeters etc to provide inferred or indirect or direct measurements where the invention provides the detail for the fracture pathways that are necessary for production. In the prior art this means that the payzone of the reservoir may be exited and further corrective fracking or drilling must occur to place the wellbore in the desired productive state. Such cycles of delayed post fracture data arrival and subsequent corrections can be eliminated with the present invention.

BACKGROUND OF THE INVENTION

To those versed in the art, it is known that over geological time, ancient river systems carried and deposited millions of tonnes of sediment and organic matter as they ran their courses to river outlets, deltas or gulfs. Over time, continuing deposits eventually formed numerous layers of sedimentary rock. These were pushed deeper and deeper under the seabed. Each successive layer (younger deposits) increased the pressure on earlier layers (older deposits) and tectonic plate movement deformed the layers creating folds, hills (anticlines) valleys (synclines), unconformities (eroded areas), faults and traps. Time, pressure and heat converted the decomposed marine life into elemental hydrocarbons. Within a given rock structure, the younger deposits or later layers form ‘overburden’ pressure conditions. Additionally, each layer has a given temperature profile according to the True Vertical Depth (TVD) at which it is located. These factors combine to form oil and gas deposits in certain rocks known in the art as ‘source-rock’, which can often be seen in certain oil and gas provinces in outcrops. From their origins deep within the source beds, hydrocarbon molecules are squeezed by immense pressures caused by the overlying sediments similar to water from a sponge. They migrate to water-saturated porous and permeable beds where, being lighter than water, they start to rise. As they rise, they contact other hydrocarbon molecules and coalesce into droplets that keep rising until they encounter an impermeable layer known in the art as ‘a cap rock’. There, they accumulate, forming a reservoir.
To those skilled in the art, the three rock classes—source, reservoir and cap—explain two concepts. Firstly, the sedimentary process explains why oil and gas are contained in minute rock spaces or pores (porosity) and not in caverns. This can be imagined as a dry sponge placed over water. The water is drawn in and contained within the voids of the sponge. To those skilled in the art, porosity is defined as the percentage of ‘voids’ in a volume of rock. Secondly, sedimentation shows the ability of a fluid to ‘seep’ or ‘flow’ through a given formation (permeability). Minute channels are created in the formations and, due to the pressurised nature of oil and gas and their relative lightness, there is always a tendency for the oil and gas to rise. This is illustrated by the migration of oil and gas from a source rock to a porous reservoir rock.
Such oil and gas accumulations are therefore contained in highly complex structures which are found at varying depths in different geological basins worldwide. Exploration and production of such accumulations relies on the construction of a well according to a well plan which is itself based on calculations and assumptions derived from scarce data and similar offset wells.
Various well types exist and are defined according to usage such as wildcats or those used in exploration; delineation; and production and injection. Variations in well profile exist also according to vertical, slant, directional and horizontal trajectories. Each differs according to the oil company's objectives and the challenges that a given basin presents from the surface of the earth or the ocean to the hydrocarbon reservoir at a given underground depth.
Geological mapping and geophysical surveys allow oil companies to characterise their acquired acreage and the age and sedimentation patterns of the rock formation contained therein. This process of characterisation can be reconstructed as a visual earth model that delineates the position and shape of the structure including anticlines, faults-stratigraphy, structure which helps increase production from subsequent wells and from the field as a whole. However, the earth model and the well plan have inherent uncertainties.
Geological uncertainties and challenges are related to the location of the hydrocarbons, water contacts, traps, formation stresses, movements and reservoir porosity and permeability. To overcome these challenges, a highly detailed well plan is developed which contains the well objective, coordinates, legal, geological, technical and well engineering data and calculations. To resolve the uncertainties, however, drilling is the final test.
The data is used to plot a well profile using precise bearings which is designed in consecutive telescopic sections—surface, intermediate and reservoir. To deliver the well objective and maintain the integrity of well over its lifecycle, a given wellbore trajectory with multiple sections and diameters is drilled from surface. Although there are many variants, a simple vertical well design could include a surface or top-hole diameter of 17½″ (445 mm), intermediate sections of 13⅝″ (360 mm) and 9⅝″ (245 mm) narrowing down to the bottom-hole diameter of 8½″ (216 mm) in the reservoir section.
Each consecutive section is ‘cased’ with the specified diameter and a number of metal tubes placed into the wellbore according to the length of the section. Each must be connected to each other after which they are cemented into the appropriately sized hole with a given tolerance. In this way, a well is constructed in staged sections, each section dependent on the completion of the previous section until the well is isolated from the formation along the entire distance from surface to the reservoir. Each section will also have a logging plan with minimum formation evaluation requirements. In a similar way, the reservoir section is left open hole or bare or completed using production casing, sandscreens, gravel packs etc. Production casing fully isolates the wellbore from the reservoir formations and therefore requires communication which is provided via perforations created in the casing allowing fluid commingling. Perforations are of further importance in unconventional basins as they provide the coordinates for the hydraulically induced fractures.
Scarcity of oil and gas is driving oil and gas companies to explore and develop reserves in unconventional basins such as those known as tight gas, shale gas, shale oil and coal bed methane. Unconventional reservoirs are those whose permeability is far lower than conventional oil and gas reservoirs as the oil and gas is essentially trapped due to a lack of permeability. The completion method known as fracking, fractures the reservoir liberating the hydrocarbons from their tight earthen structure. These wells are highly dependent on fracture pathways to ensure that permeability is achieved to allow hydrocarbons to flow from the reservoir.
Therefore, the well plans that are used to drill these wells may include modeling or fractures using micro seismic, tiltmeters, acoustic, resistivity or other logging devices to characterize natural fractures. In this way, modeling is an integral part of fracture construction and there is now an increased dependence on modeling for wellbore fracture placement.
Previously, the fracture detection has been restricted to natural or pre frack measurements which are often modeled only. Typically, the natural frack data means that modeled fracture data would be provided before a fracking operation and may or may not have microseismic applied. Consequently, the fracking operation may have exited a payzone and the fracking would be of limited effectiveness. A new well may have to be drilled to reach back to the optimal location or the fracking operation repeated. If critical knowledge of the fracture i.e. reservoir interconnectivity, fractures, pathways or dips can be gained both pre and post fracking this would lead to greater recovery rates due to more effective wellbore fracking by increasing the actual fracked footage in the payzone.
In other applications such as gas zone, kick detection, pore pressure analysis or fracture identification, the tolerances between the planned parameters and actual downhole parameters can be very close and variations of 0.2 ppg can lead to the failure or loss of the well. By being able to detect a kick, or establish a fracture before it is actually drilled through, remedial drilling action can be taken in advance saving time, money and providing a significant safety margin.
To those skilled in the art, it is known that the industry relies on modeled data which may not incorporate direct downhole fracture detection whether pre or post fracking.
Therefore, the prior art does not lend itself to a reliable or certain means of investigating formations before, during or immediately after drilling or fracking.
Further the prior art generates time-consuming correction cycles of changes in fracking, azimuth and inclination in an attempt to retrospectively maintain an optimal frack trajectory.
Further, the prior art contributes to an average and unsatisfactory recovery rate of 35% of hydrocarbons as reserves are not detected or produced in an optimal manner.
Further the prior art does not detect variations in fractures prior to fracking in real-time.
Further the prior art does not detect variations in fracture characteristics such as porosity or fluid content in real-time.
Further the prior art does not detect gas zones, fractures or water flows ahead of the bit or wellbore in real-time.
Further the prior art does not detect pressure or temperature variations ahead of the bit or wellbore in real-time.
Further the prior art does not automatically allow for a closed-link or automatic troubleshooting of well trajectory or fracking placement.

SUMMARY OF THE INVENTION

The present invention has for a principal object to provide an improvement on the prior art wherein the pre and post fractures are characterized so that fracture pathways and production rates can be maximised. The invention seeks to provide critical knowledge of the fracture i.e. reservoir interconnectivty, fractures, pathways or dips can be gained both pre and post fracking this would lead to greater recovery rates due to more effective wellbore fracking by increasing the actual fracked footage in the payzone.
The invention seeks to meet the need for a closed-loop real-time fracture detection to provide real time formation data of formation data and natural fractures (pre frack) while the wellbore is being fracked or before the packer is set at a give coordinate (depth, azimuth, inclination etc). This has not been forthcoming in the prior art due to missing steps inherent in the pre and post frack placement, orientation and assembly.
The present invention seeks to directly investigate pre and post fracking and offers optimal wellbore and packer placement using a novel sensor configuration which also allows for optimized fracture propagation and measurement of post frack effectiveness.
The present invention eliminates the uncertainty of trial and error by providing real-time data which allows the wellbore isolation device to be set at optimized coordinates, the frack job to conducted thereafter and the its effectiveness measured thereby providing real time data as to the effectiveness of the fracking operation and where necessary to repeat the frack job until the required recovery will be achieved.
It is thus an object of the present invention to provide closed loop fracturing means, enabling the device to give immediate evaluation of a formation to be fractured, or the characteristics of a formation once fractured and, if the apparatus detects a parameter of interest or a change in a parameter of interest such as a fracture pathway, propagation, production flow, to automatically calculate and correct for an optimal fracking, and to repeat evaluation until such an optimal well path result is achieved in real-time.
Although fracture detection is a principal route to characterizing the effectiveness of fracking, the invention is not limited to fracture detection and envisages alternative investigation means similarly integrated with fracture detection capability of the tool. These alternative means can include nuclear, electro-magnetic, optical, temperature or other such sensor as deemed required for optimal fracking or wellbore placement.
Further the invention can be used to perform hydraulic fracking with open hole or cased/liner hole applications with or without perforating assemblies. In such cases, the downhole and surface configurations would be arranged to meet the needs of the operation and the apparatus may be connected directly or indirectly in any manner or order so that the frack operation may be optimized.
Fracture sensing means may be located above, below, on the wellbore isolation means and suitably configured to enable downhole fracking operations. For example, this may involve the unrestricted ID (internal diameter) or passage for full flow or pressure or to drop ball etc to as is know in the art to create the necessary pressure for fracking. Other configurations may require additionally or alternatively the ability to retrieve the sensors or to deploy the sensors above or below the packer. Deployment may be performed via means such as collapsible supports for the sensors, fibre optics, miniaturized sensing means, fixed supports, independently rotatable, extendable supports, arms, blocks, blades, etc. Power would be provided accordingly and can be contained within the apparatus or provided from outside the apparatus. Communications would be provided using wires, wirelessly or a combination. The invention is not limited in the placement or configuration of the apparatus.
It is a further object of the present invention to provide an apparatus capable of verifying pre and post frack data through a processor arrangement that uses sensor data to detect fracking results and conducts diagnostics according to a logic circuit in order to ensure the wellbore frack plan is optimized in view of real time fracking data. The processor will automatically detect whether corrective steps are required to maintain/move the wellbore fracking in the optimal zone. Data can be collected on each stage as it is fracked and this is compared with pre frack data and differing stage data. If the tool finds a significant divergence, a signal may be sent to the rig-surface or to the location of the operating engineer so that further remedial action can be taken, such as coordinate revisions. A memory mode may store sensor information that can be downloaded at surface when the tool is retrieved, or sent to the surface by telemetry or by wireless means.
One or more sensors may be optimally spaced in the fracking apparatus in order to investigate the formation, detect fracking and provide pre and post frack data. The resolution of fracture detection may be user defined and can be pre-programmed at surface to the processor or via instruction from a surface location to the downhole location of the apparatus and processor. The method according to the invention similarly provides for pre programming or programming on the fly and communication both using wires or wirelessly.
A keyway may provide a channel for wiring from the sensors to the processor and to a transponder. The wiring can be used to transmit sensor data retrieved by the sensors, as well as positional and structural data of formation characteristics such as fractures and their relative depths, pathways, corridors, inter-connectivity etc. The keyway may be sealed and filled with a means to absorb vibration such as silicon gel or grease and to maintain wires in position. Similarly, the keyways may be left redundant and as a back-up to a wireless mode of operation.
The transponder converts formation and fracture data so that it can be transmitted and may be linked a the mud-pulser which transmits the data to surface using a series of binary codes at a given frequency using drilling fluid as means of mud pulsing. Other means of data transfer may be used such as wireless transmission short hop using radio frequency or electro-magnetic pulses or wired drill-pipe. This allows up and downlink of the tool in order to receive and transmit data and commands so as to optimize fracking.
At surface a transducer may be incorporated within a decoder housing which decodes the binary code and may link to the frac operations or driller's terminal or may be yet further transmitted by satellite or other means to a remote operations centre.
These and other objects will emerge from the following description and the appended claims.
In one aspect, the closed loop fracture apparatus (50) comprises a tool body with means for attaching the tool body (63) directly or indirectly to a support or reamer, reaming shoe, drill-bit whereby it can be rotated and moved axially along a passage (20), and is characterized by, at least one sensor (58) which can detect natural or man made fractures (FIG. 5) relative to the horizontal axis of the tool, and (57) is adapted to investigate and recognize sensor data from a fracked stage (70) or from a plurality of stages (110,120,130,140) and thereby increase hydrocarbon recovery rates by optimizing wellbore trajectory and hydraulic frack location based on formation data acquired by the sensor before, during or after a frack operation occurs with or without a drill-bit (70).
The support may typically be a perforating or production string (30) or a workstring or drillstring or extended length of coiled tubing as used in downhole operations in oil and gas fields.
In preferred embodiments of the invention, the investigation operation is based on sensor elements comprising a set of at least one sensor, receiver combination optimally configured and oriented to investigate beyond the wellbore and detect fractures. The sensor housing may comprise protective covering, which may be of similar construction to the sensors, but having outer surfaces where sensors are protected by a hardened material. Such protection may simply bear under temperature, pressure or flow acting against it from the inside of a wellbore. In an alternate embodiment, the zone surrounding the housing may be treated to actively receive data or configured with a variety of receivers rendering it a sensing zone. The sensors may be provided with a lens surface that may be convex (52 a), concave (52 b), or planar (52 c) according to requirement. The sensors and receivers may be optimally tuned and gated in terms of frequency so that emitted frequencies do not cancel out upon contact with return waves and so that reference measurements are taken to establish background noise which would be suitably excluded from operational measurement calculations. Alternatively, the same sensors may be received within an additional section of apparatus or a separate steel body or behind or ahead such section suitably prepared to provide a means of stabilization or centralization and protection for downhole applications. Further sensors may be provided with a means to reduce ‘ringing’ or ‘dampening’ of the sensors so as to always ensure the measurements are fit-for-purpose.
It is to be noted that the description herein of the structure and operation of sensors or receivers and tool design is applicable generally, irrespective of function, except to the extent that certain sensors may be provided specifically for formation evaluation purposes and replaced by other sensors such as nuclear or resistivity or acoustic or nuclear magnetic resonance sensors as required by the drilling operation.
The apparatus comprises a tool body or a plurality of tool bodies which are typically cylindrical high grade steel housings adapted to form part of a fracking assembly. It is not always necessary that the assembly be used for fracking as the sensors may be used to determine natural fractures while drilling. Thus the means for attaching the tool body to the support, whether it is a drill string or work string or coiled tubing, may comprise a screw thread provided on the tool body which is engageable with a drill collar or a connection to a production string for fracking. The attachment need not be direct, but may be indirect, as there will typically be many different functional elements to be included in the long and narrow assembly, and the arrangement of the successive elements will vary based on production, completion or drilling applications. The lower end of the assembly may be the drill bit (or a packer or casing shoe or reamer shoe) which may be directly connected to the tool and in between there may or may not be other components dependent on the operational requirement. For example, in drilling such components could be a means for directional control such as a rotary steerable system or directional motor. The tool body may be provided with a through passage for the flow of drilling fluid from the drill string. For example, in completion operations using perforating such components could be a means for wellbore isolation such as a bridge plug or packer. The tool body may be provided with a through passage for the flow of completion fluid from the string. In open hole completions perforating may not be required prior to hydraulic fracturing. Thus the invention is not limited to a single configuration of the apparatus since it is always envisaged that the necessary components are available to perform the frack job.
Such a through passage allows for full flow, pressure, drop ball or other actions above or below the tool i.e. activation, deactivation, or retrieval of equipment. The tool itself may also be provided to be retrievable so that it may be placed below a packer or take measurements below a packer or above a packer. Similarly, any completion or wellbore isolation device such as intelligent control valve, swellable packer or inflow control device can be used to isolate the wellbore and create the necessary pressure to fracture the formation.
The sensors may be protected and housed in a plurality of positions directed outwardly of a body. The sensor may be received within the profile of the tool body in a sensor recess suitably protected from abrasion, wear and damage by means of at least one protective coating or covering. The protective coating may be steel with HVOF, tungsten carbide, boron nickel or other protection according to requirements. The sensor may be provided with a dampening material or mechanism such as silicon gel or a spring.
The sensor and receiver may then be provided with means for driving the sensors and receiving the data from the far formation, near formation or wellbore so as to characterize the fractures located therein. The microprocessor control means may be suitably adapted to receive formation data from the sensors and to control the frequency in response thereto. A gating procedure may be suitably incorporated to discard a range of background noise frequencies or by means of establishing a maxima reference measurement and engaging with such a maxima or by means of establishing a measurement and engaging with such a measurement. The microprocessor also may receive information from micro-seismic, tiltmeters, frack parameters so as to optimize the frack operation and this may be done in a closed loop operation with or without user intervention. In this way, a number of differing frac jobs may be performed at a number of sites and data viewed at a central location.
Pressure compensation may be provided to handle variations in downhole pressure compared to surface atmospheric conditions for example in fracking where hydraulic flow and pressure may require pressure compensation (not shown).
The system may comprise a microprocessor means for monitoring fracture evaluation data and relative positions of frack stages where the microprocessor means may include a means of automatically anticipating any fracture or detecting a feature of a formation or detecting a change in the feature of a formation, thereby guiding the control system to ensure the optimal placement and functioning of the frack operation.
The tool normally comprises a plurality of sensor and receivers arranged symmetrically around the tool and disposed outwardly. The sensor receiver may be configured as an integral transducer or separated as a sensor to receiver array known as a ‘sensing zone’ (not shown). Two transducers would be on opposite sides of the tool, three blocks would be separated by 120 degrees, four by 90 degrees, and six by 60 degrees. Additionally or alternatively, sensor receiver arrays could be configured in a plurality of combinations including longitudinal or wellbore spacings or axial or spiral, with the object of ensuring the zone of investigation covers the pre and post fractures.
In accordance with a particularly preferred aspect of the invention, the sensor receiver array is provided with an internal keyway for directing power from a source within the tool and providing communications to and from the sensor receiver. The source of power may be a battery within the tool or within another support for the tool suitably adapted for such purpose. The communications may be a processor within the tool, or at surface or other support for the tool suitably adapted for such purpose. Alternatively or additionally, the sensor/receiver or tool body may be provided with a wireless means of communication to an internal or external processor. In each case, the two-way communications provide data transmission, operational refinement and data capture.
In order to keep the sensor/receiver clean and prevent the build-up of clogging debris from the fracking operation, the sensor housing may be provided with a specialized coating to minimize the residence or remove such material altogether from the sensing zone.
In one preferred aspect the present invention incorporates a wellbore isolation device so as to permit a frack job and sensors to permit the detection of fractures before and after a frack job.
In another aspect of the present invention housing for other types of sensors is provided. The tool may further comprise telemetry means for communicating downhole data and control signals between the tool and a surface interface, which may, among other functions, control the drill string or work string during the drilling or frack operation.
In a further aspect, the invention provides a method of operating an apparatus to investigate natural and induced fractures and to optimally guide and place a wellbore which comprises locating a wellbore fracking device according to the invention in a borehole on a support, activating the sensors/receivers to detect natural fractures and establish a set of coordinates for locating a wellbore fracking device, fracking a wellbore, and detecting the effectiveness of the fracking operation and if unsatisfactory repeating the fracking operation at the same coordinates or further coordinates until an optimal fracking operation is completed and hydrocarbon production is maximized.
The data gathered by the sensors relates to the natural and induced fractures and can be all relevant characteristics concerning the fracture matrix, such as their depth, relative distance, azimuthul orientation, pathways, interconnectivity and corridors. natural fractures and their interplay with hydraulic fractures. Many considerations affect this fracture matrix such as organic content, porosity, permeability, brittleness, orientation, pressure but as a general rule, because hydraulic fractures propagate along the path of natural fractures, detecting natural fractures is clearly most useful in enlarging and stabilizing the natural fracture matrix. Although, fractures may appear closed in cores, markers i.e. differing properties from the surrounding rock such as impedance, calcite lining, etc provide clues to their detection.
In accordance with the method of the invention, the tool may be provided with microprocessor means responsive to formation data received from the sensor/receivers. In this way, a closed loop tool which is capable of detecting fracture changes and controlling wellbore fracking may be realised. The sensor/receiver may investigate the fracture, or investigate a feature of a fracture, set a wellbore fracking device, frack a formation and may further investigate the fracture to provide data to a surface monitor to signal an opportunity for operator intervention to correct wellbore fracking if it were not able to do so automatically.
Thus, in the case of the pre and post frack detection system data from the formation are detected by sensors. These fracture data may be transmitted from the sensor to a processor which correlates the fracture data and uses this to establish the optimal location for setting a wellbore fracking device taking into consideration formation characteristics such as dips, faults, and allowing for variations in the formation. The processor uses this data to correlate whether the pre-programmed frack program will be achieved and the resulting hydraulic pressure and frack fluids that would be required to frack to an optimal level. Where the processor detects that a fracture or feature of a formation may affect the frack parameters such as hydraulic pressure, fluid types, proppants etc it can automatically recalculate an optimal value for the hydraulics as well as the physical location for the frack to occur. Or it may simply signal an opportunity for an operator to intervene.
In the case of fracking, the operator may frack using a drilling or completion or production assembly or a frack assembly. In both cases the present invention can be employed to detect pre and post fractures and thereby a novel way of maximizing the placement and effectiveness of any fracking operation. The principal objective is knowledge of the fracture i.e. reservoir interconnectivty, fractures, pathways or dips gained both in pre and post fracking which leads to greater recovery rates due to more effective wellbore fracking by increasing the actual fracked footage in the payzone.
For example, the processor may be programmed with a logic circuit which can be configured in any number of ways so as to optimize performance. An exemplary configuration may involve the circuit to first cross check the natural fracture data and then set a wellbore fracking device. The fracking operation is performed and the induced fracture data and if required corresponding flow of hydrocarbons is obtained by the sensors and transmitted to the processor. In this way, the processor can measure the effectiveness of the induced fracking directly and if it were insufficient provide for a further cycle of fracking. This distinguishes the present invention from the prior art which has neither the ability to compare natural and induced fractures nor optimize the location of fracking devices.
If it is seen that the induced fracture is insufficient in terms of production of hydrocarbons, the fracking operation can be repeated at the same coordinates with a change in fracking parameters. If the post frack data still shows insufficient gain in production of hydrocarbons, the apparatus can provide for example, a change in the depth, orientation or angle at which the fracking device is either isolated from the wellbore or the coordinates at which it fractures the formation. The apparatus may further be optimized for shale oil, shale gas or tight gas zone or coal bed methane so that apparatus can alert the user by means of telemetry to check the wellbore frack device location, azimuthal, inclination, or frack parameters as necessary or prompt this through a closed loop system. The skilled person will readily appreciate that other procedures may be implemented by the logic circuit within the processor, which can be programmed to cover other scenarios.
In another aspect, the invention provides a fracture detection method comprising locating a tool body with sensors and receivers, optionally but not limited to a housing carrying a plurality of sensors and receivers directed outwardly of the tool body, wherein the sensor or receiver is received within the tool body in a purpose built housing having an open mouth, and means for allowing sensor emissions to propagate to and from the housing and to and from the wellbore, near and far formation to detect natural and man-made fractures.
In a still further aspect, the invention provides a wellbore fracking device used in conjunction with the fracture detection capability outlined above comprising a wellbore isolation device such as a expandable packer, intelligent flow control device, intelligent control valve, confirmable sponge, swellable packer carrying at least one expandable element to conform to the wellbore and isolate a specific area in the wellbore. Additionally or alternatively further areas in the wellbore may be left open to allow free flow of hydrocarbons. In this way a plurality of wellbore flow areas may be created allowing for fluids to frack the wellbore as well as allowing the flow of hydrocarbons into the wellbore.
Additionally, sensor and receiver arrays may be configured optimally by providing longitudinal spacings between the sensors and receivers.
Additionally, the apparatus may be provided with compensation and/or calibration means for enhancing fracture detection. Typically, compensation and/or calibration occurs using look up tables for parameters affecting sensor measurements or measurements made at surface or downhole. The invention envisages all types of such calibration since they can improve the accuracy of measurements and fracture detection.
Other aspects of the invention are disclosed in the following specific description of exemplary embodiments of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention are illustrated by way of non-limiting examples in the accompanying drawings, in which:

FIG. 1 is a general diagrammatic view of an oil or gas well showing rig surface structures (10) and the underground well (20), with a tool (50) in accordance with the invention as part of a bottomhole assembly (40) drilling a well (30) and indicating formations and formation features (70) located ahead of the drill-bit (60) and a wellbore (80);

FIGS. 2,2 a,2 b, are downhole side views illustrating a a plurality of sensor distributed along the apparatus in a helical, longitudinal, spiral arrangement respectively. It is not essential the sensors are distributed on a tubular body as the may be located within collapsible arms, extendable arms, fibre optic cables, distributed within casing or liners or retrievable from below a packer. Sensors may be non rotating, rotatable, independently rotatable, toward the wellbore or internally or may be fixed in position. The invention is not limited in sensor placement or fixing.

FIG. 3 a show a and 3 b show a radial corresponding to radial sensor distribution corresponding to FIG. 2

FIG. 4 is a 3-D Earth cube from a surface (260) and downhole side (150) view, part cut away to show the fracking operation (160) according to a multi stage fracking operation (280);

FIG. 5 is a diagrammatic cross section through the apparatus in accordance with the invention similar having a wellbore isolation device (62) or other zonal isolation member (63) at the downhole end;

FIG. 6 is a diagrammatic cross section through the apparatus in accordance with the invention similar to that shown in FIG. 5, but having an additional wellbore isolation device (61) or other zonal isolation member at the trailing uphole end

FIG. 7 is an exemplary embodiment with sensing element between zonal isolation devices as would be the case with multiple stages or packers according to frack operations.

FIG. 8 is an exemplary diagnosis and troubleshooting procedure according to the invention showing fracture detection and integration with other data such as micro-seismic, tiltmeters, fracking parameters and the like.

DETAILED DESCRIPTION OF THE INVENTION

As shown in FIG. 1, an exemplary exploration or production rig comprises a surface structure (10) at the wellhead, a wellbore (20), and a string (30) in the wellbore with a downhole assembly (40) at its lower end. The downhole assembly includes an apparatus (50) in accordance with one aspect of the invention, a sensing means and a wellbore isolation device (60) and formations fractured and detected as the object of the invention.
The apparatus (50) is illustrated by way of exemplary embodiments in FIGS. 5, 6, and 7 comprises a tubular steel body (62) provided with a connection at either end to enable its direct or indirect connection to the wellbore isolation device (60) and connect it to other elements of the downhole assembly (40) and a link to a means of communication to the surface (64). Wellbore isolation device (60) may be replaceable by a drill bit where the invention is used in while drilling capacity to detect natural fractures.
The apparatus comprises a tool body (58) that carries at least one housing for at least one sensor (58) and a wellbore isolation device (60) capable of detecting natural and induced fractures. The sensor element (51) comprises a number of sensing elements (52) disposed radially around the profile of the tool body FIG. 3 a. The sensors detect fractures that extend beyond the wellbore (60) and into formations surrounding (70) and at multiple stages or locations in the wellbore (110, 120, and 130).
An exemplary configuration of the invention in accordance with its specified object is shown in FIG. 5.
FIG. 5 is a diagrammatic cross section through a lookahead tool in accordance with the invention similar to that shown in FIG. 5, but having a wellbore isolation device (62) or other wall contact member (69) at the trailing uphole end. Equally, such downhole wall contact may be an expandable device, pressure containment device;
FIG. 7 illustrates diagrammatically the aforementioned sensing elements within the tool (50), together with a wellbore isolation device (61) in a cross section view in accordance with the invention similar to that shown in FIG. 5, but having an additional wellbore isolation device (61) at the leading downhole end; wherein a plurality of such devices may be employed as is the case where multiple frack stages are required to stimulate the reservoir.
Fracking performance is verified using a micro-processor, shown in location (55), that compares data from the sensor (51) with a pre-programmed wellbore frack plan, thus detecting natural and induced fracking. Additionally or alternatively, the micro processor may be located at the surface especially when a micro seismic or tiltmeter or surface frack parameters are measured. The apparatus is programmed and automated to conduct diagnostics according to a logic circuit or diagnostic program stored in processor (55) in order to ensure the fracking is optimally performed. Once corrective steps have been taken, and if the apparatus indicates that the planned fracking (trajectory, productivity, location etc) is not optimal in light of formation data, an alert signal is sent via the mud-pulser (64) to the rig-surface 10 or to a remote operator so that control action of the assembly (40) can be taken. A memory module (not shown) associated with processor (55) may store sensor information that can be downloaded at surface when the tool is retrieved, or sent to the surface by telemetry through a transponder to a mud-pulser (64) or by other communication means. A means of powering the sensors and receivers is shown by (54).
The tool is provided with a built-in link to a communication system which may be a wired or wireless telemetry system (64) which also serves to monitor real-time formation data and features. One or more sensor receivers (51) are spaced within the tool body in order to detect fractures in a single part of the wellbore (40) or a multiple number (110,120,130). The microprocessor (55) establishes formations (110, 120, 130) and formation features (160) and fracture data through a series of calculations derived from acoustic velocity or resistivity or neutron density imaging. The invention is not limited to sensing or imaging means and compares this with preprogrammed targets. If the two measurements match given user defined tolerances the tool continues to total depth of the wellbore section. Where the formation data do not match the logic circuit dictates a series of diagnostic steps, which are further discussed in relation to FIG. 8 below.
As further shown in FIG. 5, a keyway provides a channel for wiring (56) from the sensor (51) to the processor (55), and also to a comms device (64). The wiring is used to transmit formation evaluation data retrieved by the acoustic reflection sensors (51) as well formation features (110, 120, 130, 160) from the receivers (52) to the processor (55) and transponder (64). The keyway may be sealed and filled with a means to absorb vibration and maintain wires in position such as silicon gel or grease (not shown).
The comms device (64) converts data from the microprocessor (55) so that it can be transmitted to surface (10) and may also receive data from the surface. Means of data transfer may be used such as wired, wireless, short hop using radio frequency or electro-magnetic pulses, mud-pulse etc.
FIG. 6 shows an alternative configuration with a wellbore isolation device (61) and shows a central axial through passage (59) for the free flow of fracturing fluid or drop ball through a central axial passage.
Additionally or alternatively, housing (51) may also be suitably adapted and treated for use of other types of sensor, analogue or digital, resistivity, electro-magnetic, nuclear magnetic resonance, acoustic, pressure, flow to detect a fracture.
The tool body (50) is a cylindrical high grade tube adapted to form part of a downhole fracking assembly 40. Suitable materials for the tool body are metallic, ceramic, or any other high strength material. FIGS. 5, 6 show a diagrammatic side view of the apparatus (50). At the leading downhole end there is pin connection (63) to a drill-bit, in the centre is a profiled section (58) housing sensing (51, 52) and control functions (55).
FIG. 6 shows a further section at the uphole end, (69), is connected to a fracking assembly (40). At either end a wellbore isolation device may be placed to create zonal isolation for fracking. Sensors can detect fractures pre and post fracking either downhole or at surface as per FIG. 2 above. Sensors may be constructed and housed integrally and generally designated as (51), except that a plurality of sensors may be placed to form a sensing zone as per FIGS. 2 a,2 b,2 c, 3 a and 3 b. In all embodiments there is at least one surface which is hard faced or coated with a hard abrasion-resistant material. Any suitable means for attaching the tool body to a fracking assembly is envisaged.
In this alternative configuration the tool is configured, in addition to sensing capacity, with the wellbore isolation device incorporating expandable device to isolate the wellbore and allow pressure to frack the formation. The wellbore isolation device may be directly or indirectly above or below the central sensing section and may be hard-wired or wireless accordingly so as to ensure the comms device (64) may transmit data to surface (10). The comms may be provided as wireless or wired the configuration of the apparatus may be changed to suit such an application.
As shown in FIGS. 5, 6, and 7, the illustrated example of a pre and post frack apparatus in accordance with the invention is a sensor which uses a microprocessor (55) and wellbore isolation device to determine and perform an optimal wellbore frack operation. Sensor/receiver means (51, 52) determine single or multiple frack characteristics (110, 120, 130, 160) and send corresponding signals back to the processor (55).
As required, the sensors (51) may be protected and housed (53) in a plurality of positions and/or orientations directed outwardly of a tool body (58) and at all times to detect fractures (60) and configured optimally based on formation and downhole component considerations. The sensors may be received within the tool body in a sensor housing recess (53) that is also suitably protected from abrasion, wear and damage by means of at least one protective coating or covering. The protective coating may be steel with a HVOF coating, tungsten carbide, boron nickel, titanium, epoxy, kevlar or other protection suited to requirements. The sensor may also be provided with a dampening material or mechanism such as silicon gel or a spring (not shown).
The sensor means may then be provided with drive means (54) for driving the sensors and receiving data from the multiple stages (110,120,130,160), fracture or wellbore (80). The microprocessor control means (55) may be suitably adapted to receive formation data from the sensors (51, 52) and to control the frequency in response thereto. A gating procedure may be suitably incorporated to discard a range of background noise frequencies or by means of establishing a maxima reference measurement and engaging with such a maxima. Noise in this context does not refer to solely to acoustic noise, but any electrical, sensor or other signal or circuitry interference.
Pressure compensation may be provided to handle variations in downhole pressure compared to surface atmospheric conditions where activation is opposed by a source of external pressure. This may comprise a port from a source of downhole fluid into a chamber suitably connected to the area within the area requiring pressure compensation (not shown).
The system may comprise a microprocessor means for monitoring formation evaluation data and relative positions of formation structures where the microprocessor means may include a means of automatically anticipating a fracture or detecting a fracture or detecting a change in a fracture or detecting a fracking effectiveness, thereby guiding the fracking operation to ensure the optimal wellbore production.
The apparatus normally comprises a plurality of sensing means arranged around the toolbody and disposed outwardly. The sensing means may itself may be configured as an integral transducer or separated as a plurality of sensors to receivers (array) known as a ‘sensing zone’. Sensors or transducers may be on opposite sides of the tool radially, longitudinally, axially or helically. Sensor receiver arrays could be configured in a plurality of combinations with the object of ensuring the zone of fracture detection and the zone of wellbore isolation is optimized within the sensing zone.
In accordance with a particularly preferred aspect of the invention, the transducer or sensor receiver array is provided with an internal keyway for directing power from a source within the tool and providing communications to and from the sensor receiver. The source of power may be a battery within the tool or within other support for the tool suitably adapted for such purpose. The communications may be a processor within the tool, or at surface or other support for the tool suitably adapted for such purpose. Alternatively or additionally, the sensor/receiver or tool body may be provided with a wireless means of communication to an internal or external processor. In each case, the two-way communications provide data transmission, operational refinement and data capture.
In order to keep the sensors and/or receivers clean and prevent the build-up of clogging debris from the downhole operation, the sensor housing may be provided with a specialized coating to minimize the residence or remove such material altogether from the sensing zone.
In one preferred aspect the present invention incorporates an optimal means of fracture detection which is practically applicable to natural and induced fractures and is combined with wellbore placement means such as rotary steerables.
In another aspect of the present invention the fracture detection means are provided with a plurality of wellbore isolation devices.
The apparatus may further comprise telemetry means for communicating downhole data and control signals between the tool and a surface interface, which may, among other functions, control the apparatus during the formation evaluation operation.
In a further aspect, the invention provides a method of operating a logging tool to investigate a formation or a fracture or the like to optimally guide and place a wellbore isolation device which comprises locating a device according to the invention in a borehole on a support, activating the sensors/receivers to detect fractures from the formation and establish data on fractures and features thereof, their relative distance, size from the tool in a preferred embodiment of apparatus, fracturing a formation, investigating the formation recently fractured by the sensors, and continuing the operation until an optimal wellbore production is achieved.
To those skilled in the art, it is known that the wellhead surface structure (10) includes a control and communications system having an interface for communication telemetry with downhole instrumentation including a transponder and a decoder which decodes data and may be linked directly to the user's terminal. The decoded data may be yet further transmitted by satellite or other means to a remote user or a remote operations centre by means of a telecommunication link. This surface control system allows full communication to and from the downlink and uplink to the invention.
The invention may also provide a method of automatically operating a directional tool according to a processor to optimally place a wellbore, tubular or completion.
FIG. 8 is an exemplary diagnosis and troubleshooting procedure according to the invention showing fracture detection and integration with other data such as micro-seismic, tiltmeters, fracking parameters and the like.
It is recognized that the apparatus could be programmed by the skilled person to cover many other scenarios.
Those skilled in the art will appreciate that the examples of the invention given by the specific illustrated and described embodiments show a novel fracture detection apparatus and method for formation evaluation, with numerous variations being possible. These embodiments are not intended to be limiting with respect to the scope of the invention. Substitutions, alterations and modifications not limited to the variations suggested herein may be made to the disclosed embodiments while remaining within the ambit of the invention.

Claims

1. An apparatus (50) for fracturing an oil or gas well comprising a sensing element, means for attaching the sensing element to a support whereby it can be moved in a borehole (20), characterized by, at least one sensor (58), to detect a fracture or a feature of the formation related to a fracture, at least one expandable element (52)

2. The apparatus of claim 1 wherein said sensing element detects a fracture or a feature of a formation related to a fracture in order to generate an optimal location to set the expandable element in real-time

3. The apparatus of claim 3 further comprising expanding the expandable element in response to sensor data acquired by the sensing element.

4. The apparatus of claim 1 wherein downhole sensors are used to sense said fractures or fracture features

5. The apparatus of claim 1 wherein surface sensors are used to sense said fractures or fracture features

6. The apparatus of claim 1 wherein said sensors are one of the group selected from: resistivity, neutron density, nuclear magnetic resonance, acoustic, wellbore imaging, seismic, micro-seismic, tilt-meters, pressure, flow, temperature, stress, strain

7. The apparatus of claim 1 wherein said expandable element is selected from one or more of the group of: plugs, packers, elastomers, sponges, metals, porous material, non porous material and effectively isolates or communicates with at least one zone of the formation

8. Apparatus of claim 1 wherein the expandable element expands under mechanical force, temperature, pressure, flow or other force acting against it from the inside of a wellbore or from the inside of the support.

9. Apparatus of claim 3 wherein the expandable element is expanded on command in response to sensor data.

10. Apparatus of claim 4 wherein the expandable element is expanded on command in response to sensor data.

11. Apparatus of claim 1 wherein the sensor is locatable above or below the expandable element

12. Apparatus of claim 8 wherein the sensor is retrievable and has an unrestricted internal diameter communicable to the expandable element

13. Method of claim 20 wherein a fracture is detected by sensor, the expandable element is expanded on command in response to sensor data and a fracture is induced

14. Method of claim 15 wherein the induced fracture is detected by sensor

15. Apparatus as claimed in claim 1 with sensors and expandable elements configured with a wall contact member FIG. 5 (62) wall contact member (63) at the trailing uphole or leading downhole end

16. Apparatus of claim 17 wherein such downhole wall contact member may form part of a rotary steerable, stabilizer, roller reamer, a reamer, a pressure containment device, a measurement device, a bridge plug, a packer and inflow control device.

17. Apparatus as claimed in claim 19 which is elongate and comprises at least two of said expandable elements at longitudinally separated positions along the support, (FIG. 7, 61)

18. Apparatus as claimed in claim 1 comprising microprocessor control means (55) adapted to receive data on the formation or formation features based on acoustic signature velocities recognized by receivers (52), detect a formation or formation feature and signal a tool in response to acquired data in order to set the expandable element to maximize production.

19. Apparatus as claimed in claim 1 wherein a plurality of sensing elements are directed outwardly of the tool to form a sensing zone wherein said plurality is placed helically, longitudinally, spirally, axially, radially and communicate with a user interface in real-time so as to optimize performance.

20. An automated method of operating a fracturing apparatus to optimally place a wellbore or tubular or packer or sand screen or like completion or production system or device based on acquired formation data, which comprises locating a tool as claimed in claim one in a borehole, activating the sensing element to send and receive formation data, rotating the tool and moving it axially along the borehole on the drill-bit or support, receiving data by receiver means, and continuing the formation evaluation until an optimal fracking operation is achieved using logic programming to diagnose and correct common errors or failures.

21. A method of fracturing using apparatus as claimed in claim 1 provided with a closed-loop micro-processor means for detecting a wellbore feature or detecting a natural fracture or an induced fracture, comparing this with a desired fracture and automatically alerting an operator or changing the condition of an expandable element in response thereto (62) and wherein the tool is supported on a downhole string (40) and a surface interface controls and exchanges data with the downhole string and any of its components during the formation evaluation operation according to a program to deliver a desired wellbore placement.

22. A method of completing an oil or gas well as claimed in claim 1 where the apparatus gives immediate evaluation of a formation, or the characteristics of a formation yet to be drilled and, if the tool detects a feature of a formation or a change in a feature of interest, to automatically calculate and correct for an optimal well path, and to repeat evaluation until such an optimal well path result is achieved in real-time where formations are detected as rock types, earthen formations or lithologies with a feature of interest meant to include but not limited to detecting porosity or a change in porosity, detecting permeability or a change in permeability, an oil zone, a gas zone, a water zone, a fracture, a fault, a dip, a bed, a vugular formation, an anticline, a syncline and a trap.