Method for Evaluating Voids in a Subterranean Formation

Abstract

Voids adjacent a wellbore wall and in a region surrounding a wellbore wall can be detected by monitoring gamma rays scattered from the fractures. Gamma rays are strategically directed from a tool disposed within the wellbore and to the wall and/or the region. Some of the gamma rays scatter from the voids and are detected with detectors set a designated axial distance from the gamma ray source. In addition to identifying the presence of the voids, the location and size of the fractures/perforations is also estimated. Time lapsed imaging of the wellbore wall can yield changes in the voids that in turn can affect permeability of the well. Examples of the voids include fractures and/or perforations.

Description

BACKGROUND

1. Field of Invention

The invention relates generally to assessing fractures in a subterranean wellbore. More specifically, the present invention relates to a device and method that uses a radiation source in conjunction with a radiation detector for a time lapsed evaluation of fractures in a formation intersected by the wellbore.

2. Description of Prior Art

Subterranean wellbores used for producing hydrocarbons typically are lined with a casing string that is cemented to the formation intersected by the wellbore. The casing and the surrounding formation are then perforated to provide fluid communication between the formation and interior of the casing. Fluid produced from the well flows through the perforations, to within the casing, and to the surface within production tubing that is inserted inside the inner casing string.

Some hydrocarbon bearing formations can have low permeability due to the presence of shale, or very tight formation rock (such as in limestone formations); which in turn can limit hydrocarbon production. However, natural or man-made fractures in these formations can increase formation permeability thereby increasing hydrocarbon production. Identifying the location and size of these fractures are of considerable importance in determining which part of the borehole to perforate and produce. Often, a layer of shale is on top of a formation that contains hydrocarbons. Generally, it is more stable to drill in the layer of shale than the hydrocarbon bearing formation. In these situations, a wellbore is drilled through the shale with the hopes of intersecting a fracture in the shale that extends into the reservoir having the hydrocarbons, as fractures increase permeability of a subterranean formation.

Wellbores often include portions that are lined with a gravel pack, which is made up of particles of a designated size that are retained between a perforated tubular in the wellbore and the wellbore wall. The gravel pack, which is typically one or more of sand, gravel, or proppant, provides support for unconsolidated zones in the subterranean formation surrounding the wellbore. Without gravel pack, unrestrained particulate matter in the formation could become dislodged as produced fluid flows from the formation, which could possibly damage tubulars, valves, and other fluid production hardware. The gravel pack is also sometimes forced into the subterranean fractures to not only prevent unwanted particulate matter in the formation from entering the produced fluid, but also to support the fractures and prevent them from collapsing. In spite of injecting proppants into the fractures, they can still compress over time due to applied formation stresses. Drilling procedures have changed in response to environmental concerns so that fluids and cuttings are injected into hydraulically generated fractures of depleted reservoirs. Although the cuttings may be ground in specially modified centrifugal pumps, a risk remains that the ground cuttings can plug or otherwise degrade the fractures in the subterranean formation.

As with re-injection wells, conventional wells in producing fields can change their productivity because fracture permeability can change during oil and gas production. For example, erosion or breakdown of proppant materials (for example, resin-coated proppant sands or open-channel proppant deterioration) typically results in loss of production (see E. d'Huteau, Oilfield Review Vol 23, No. 3, Autumn 2011).

SUMMARY OF THE INVENTION

Disclosed herein is a method of imaging a wellbore which includes directing radiation from a source to a formation surrounding the wellbore, detecting radiation scattered from the formation, estimating a rate and energy of the detected radiation, and estimating information about a change of a void in the formation based on the rate and energy of the detected radiation. The void can be a fracture or a perforation. The steps of directing radiation, detecting scattered radiation, and estimating a rate and energy can take place over time in order to perform time lapsed imaging. The source can be a gamma ray source and which is directed in a substantially conical pattern from the source and wherein the energy of the detected radiation is dependent upon an angle of scatter of the radiation. Optionally, the information about a change of the void can be a change in thickness of the void, a change of permeability in the void, a change in flowability through the void, or a change of density of material in the void. The method can optionally further include estimating a location of the void. The void can be a fracture that intersects a wall of the wellbore, or a a perforation that intersects a wall of the wellbore. In an example, the wellbore is an injection well, or can be a production well.

Also disclosed is a method of imaging a wellbore which includes providing a logging instrument having a radiation source and a radiation detector; disposing the logging instrument into the wellbore and within casing that lines the wellbore, directing radiation from the source to a formation surrounding the wellbore and along a path, so that at least some of the radiation scatters in a direction back from the formation towards the radiation detector, detecting radiation scattered from the formation with the radiation detector, and identifying a change in a void in the formation based on a change of rate of the radiation detected. The void can be an opening in the formation which is a perforation or a fracture. The steps of the method are repeated over time so that the change of rate of the radiation detected comprises a time lapsed measurement. The radiation can be directed fully from the outer circumference of the logging instrument so that the radiation scatters from an entire circumference of a wall of the wellbore. The method can be repeated while moving the logging instrument to different depths in the wellbore.

An example of a method of imaging a wellbore is disclosed herein that includes directing radiation from a source to a formation surrounding the wellbore, detecting radiation scattered from the formation, estimating a rate and energy of the detected radiation, repeating the steps of directing radiation, detecting scattered radiation, and estimating a rate and energy of the detected radiation at a later time to perform a time lapsed measurement, and estimating information about a change of a void in the formation based on the time lapsed measurement. Estimating information about a change of a void in the formation can be based on a rate and energy of the detected radiation. Optionally, a location of the void can be estimated. The void can be a space in the formation such as a fracture or a perforation.

BRIEF DESCRIPTION OF DRAWINGS

Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which:

FIG. 1 a schematic of an example embodiment of a downhole imaging tool having a radiation source and detectors disposed in a wellbore in accordance with the present invention.

FIG. 2 is a perspective view of one embodiment of the tool of FIG. 1 in accordance with the present invention.

FIGS. 3A and 3B are sectional views of an example embodiment of the tool of FIG. 2 in accordance with the present invention.

FIG. 4 is a side sectional view of an example method of an imaging tool in a wellbore that emits gamma rays to a surrounding formation in accordance with the present invention.

FIG. 5 is a side sectional view of an example of perforating the wellbore of FIG. 4 and in accordance with an embodiment of the present invention.

FIG. 6 is a side sectional view of an example method of time lapsed imaging of the wellbore with perforations of FIG. 4 and in accordance with the present invention.

While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION OF INVENTION

The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude.

It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation.

Referring now to FIG. 1 a downhole imaging tool 100 is shown positioned in a section of casing or inner steel housing 110 of a wellbore. It is recognized that a tool housing 130, such as that surrounding the region of the source and detector array, may be constructed of any light metal wherein the term, “light metal,” as used herein, refers to any metal having an atomic number less than 23. Downhole imaging tool 100 includes at a minimum a housing or pipe 130 carrying a radiation source 120 and plurality of detectors 140. In one example embodiment, gamma radiation source 120 is centrally located in housing 130. Optionally, detectors 140 are symmetrically spaced apart azimuthally at a constant radius, within housing 130. Radiation source 120 emits radiation, in this case, gamma rays 124 into formation 150 surrounding the casing 110. Cement 151 is between the casing 110 and formation 150.

The formation 150 of FIG. 1 includes fractures 153, 155 that could be fluid-filled or not. For example, fracture 153 contains completion fluids or production fluids, whereas fracture 155 is partially or fully sand filled. Of course, those skilled in the art, with the benefit of this disclosure, will appreciate that these are for illustrative purposes only and that fractures 153, 155 could take any shape and any position.

In the example of FIG. 1, gamma rays 124 propagating into formation 150 are Compton scattered with a loss of some energy back towards detectors 140 located within downhole imaging tool 100. The reduced-energy gamma rays 126 are detected by detectors 140. The count-rate intensity of Compton scattered. gamma rays 126 depends on, among other factors, the size of the fracture and the density of the material inside the fracture. Hence, higher count rates represent higher density material in the formation, whereas lower count-rates represent lower density as a result of fewer gamma rays being back-scattered towards the detectors.

In an example, radiation source 120 includes a cesium, or some other radiation source, or combinations thereof. Because the detectors are located close to the source, energy detected from scattered gamma rays originates only from a short distance into the formation immediately adjacent the casing. For these same reasons, in one example detectors 140 are positioned in housing 130 proximate to radiation source 120. In one example embodiment, radiation source 120 and detectors 140 are within about 3 to about 3.5 inches apart along the length of tool 100.

Shielding 156 may be applied around radiation source 120 to collimate or otherwise limit the emission of radiation from radiation source 120 to a restricted longitudinal segment of formation 150. In an embodiment, such shielding is a heavy metal shield, such as sintered-tungsten, which collimates the pathway for the emitted gamma rays into the fractures. Likewise, as described in more detail below, similar shielding may be used around each detector to limit the detector viewing aperture to only those gamma rays that are primarily singly-scattered back to the detector from a restricted azimuthal section of the formation.

Further, the energy levels of the emitted gamma rays 124 may be selected to assess fracture characteristics at varying depths or distances from downhole imaging tool 100. As one example, the radiation from a gamma ray source, such as a ¹³³Ba source, may be used to emit several energy levels. Alternatively, a gamma ray radiation source with a single energy gamma ray, such as ¹³⁷Cs, may be used.

To produce an accurately oriented map of the fracture locations, the azimuthal angle of the logging tool relative to the high side of the borehole is determined. This orientation can be determined using any orientation device known in the art. Orientation devices may contain one or more attitude sensors used to determine orientation of the logging tool with respect to a reference vector. Examples of suitable orientation devices include, but are not limited to, those orientation devices produced by MicroTesla of Houston, Tex. Each set of gamma ray measurements may be associated with such an orientation so that a 2D profile map of the formation can be accurately generated in terms of the actual azimuthal location of the fracture.

FIG. 2 illustrates a perspective view of one embodiment of a gravel pack imaging tool. As shown, downhole imaging tool 200 includes a housing 230 which carries radiation source 220, source collimator 225, and a plurality of radiation detectors 240 in an array. The array of detectors 240 may be positioned at a fixed distance from radiation source 220. In certain embodiments, detector arrays may be positioned at differing distances from radiation source 220. Additionally, detector arrays on either side of radiation source 220 are also envisioned in certain embodiments. Electronics 260 may also be located in housing 230 or wherever convenient.

Radiation source 220 may be one or more radiation sources, which may include any suitable low-energy gamma ray source capable of emitting gamma ray radiation from about 250 keV to about 700 keV. Gamma ray sources suitable for use with embodiments of the present invention may include any suitable radioactive isotope including, but not limited to, radioactive isotopes of barium, cesium, a LINAC, high energy X-rays (e.g. about 200+ keV), or any combination thereof. Radiation from radiation source 220 may be continuous, intermittent, or pulsed.

In one example embodiment shown in FIG. 2, a radiation source 220 is centrally located in housing 230. In the illustrated embodiment, source 220 is positioned along the axis of housing 230.

Gamma-Ray collimator 225, which is optional in certain embodiments, may be-configured adjacent to the source 220 in order to directionally constrain radiation from the radiation source 220 to an azimuthal radiation segment of the formation. For example, collimator 225 may include fins or walls 226, 228 adjacent source 220 to direct gamma ray propagation. By directing, focusing, or otherwise orienting the radiation from radiation source 220, radiation may be guided to a more specific region of the formation. Additionally, the radiation energy may be selected, by choosing different isotopic sources, so as to provide some lithological or spatial depth discrimination.

In the illustrated embodiment, collimator 225 constrains radiation from source 220. In this embodiment, collimator 225 is also conically shaped as at 228, in the direction of detectors 240 to collimate the gamma rays from source 220. Of course, those skilled in the art will appreciate that collimator 225 may be configured in any geometry suitable for directing, focusing, guiding, or otherwise orienting radiation from radiation source 220 to a more specific region of the formation.

In one non-limiting example, the radiation transmitted from source 220 into a formation (such as formation 150 of FIG. 1) is Compton scattered back from the formation to tool 200 where the back-scattered radiation may be measured by radiation detectors 240. Radiation detectors 240 can be any plurality of sensors suitable for detecting radiation, including gamma ray detectors. In the illustrated embodiment, four detectors are depicted, although any number of detectors can be utilized. In another example embodiment, three detectors or six detectors are utilized; where optionally, each detector is disposed to “view” a different segment of the formation. Employing multiple detectors, the tool can image the entire circumference of the casing 110 in separately identifiable segments. The resolution of the image of the overall circumference can depend on the number of detectors, the energy of the gamma rays and the degree of shielding provided around each detector.

In certain embodiments, gamma ray detectors may include a scintillator crystal that emits light proportional to the energy deposited in the crystal by each gamma ray. A photomultiplier tube may be coupled to the crystal to convert the light from the scintillation crystal to measurable electron current or voltage pulse, which is then used to quantify the energy of each detected gamma ray. In other words, the gamma rays' energies are quantified, counted, and used to estimate the density of material in a fracture. Photomultiplier tubes may be replaced with high-temperature charge-coupled devices (CCD) or micro-channel photo-amplifiers. Examples of suitable scintillator crystals that may be used include, but are not limited to, NaI(Tl) crystals, BGO, and Lanthanum-bromide, or any combination thereof. In this way, count-rates may be measured from returned radiation, in this case, returned gamma rays. The intensity of the Compton scattered gamma rays depends on, among other factors, the density of the formation material. Hence, lower density represents gaps in the formation, such as may be caused by the formation being fractured and lower count-rates represent lower density as a result of fewer gamma rays being back-scattered towards the detectors.

Still referring to FIG. 2, in an example embodiment detectors 240 are mounted inside a housing at a radius smaller than the radius of housing 230 inset from the surface of housing 230. Likewise, while they need not be evenly spaced, in the illustrated embodiment, detectors 240 are evenly spaced on the selected radius. Although the illustrated example shows four detectors 240 spaced apart 90 degrees from one another, those skilled in the art will appreciate that any number of multiple detectors can be utilized in the invention. Further, while the embodiment illustrates all of the detectors 240 positioned at the same distance from source 220, they need not be evenly spaced. Thus, for example, one detector (or a multi-detector array) might be spaced apart 12 centimeters from the source, while another detector (or a detector array) is spaced apart 20 centimeters from the source or any other distance within the tool.

Similarly, in another embodiment, detectors 240 can be positioned both above and below source 220. In such a case, collimator 225 would be appropriately shaped to guide gamma rays in the direction of the desired detectors. In such embodiments with multiple detectors disposed on both sides of the radiation source, additional shielding may be provided between the collimators to prevent radiation scattering (i.e. cross-contamination of the radiation) from different segments of the formation.

Each detector 240 may be mounted so as be shielded from the other detectors 240. While any type of shielding configuration may be utilized for the detectors 240, in the illustrated embodiment, collimator 248 is provided with a plurality of openings or slots 245 spaced apart around the perimeter of collimator 248. Although openings 245 could have any shape, such as round, oval, square or any other shape, in one example embodiment openings 245 are shaped as elongated slots and will be referred to as such herein.

A detector 240 is mounted in each slot 245, so as to encase detector 240 in the shield. The width and depth of the slot 245 can be adjusted as desired to achieve the desired azimuthal range. In certain embodiments the length of slots 245 can be as long as the sensitive region of the gamma-ray detector (e.g. the crystal height). It will be appreciated that since a detector is disposed within the slot, the detector is not on the surface of the collimator where it might otherwise detect gamma rays from a larger azimuthal range. In an example embodiment, slot 245 is 360/(number of detectors) degrees wide and the detector face to inner diameter of the pressure housing is a few millimeters deep (e.g. from about 2 to about 5 mm). However, tighter collimation is possible. Optionally, the azimuthal range of each slot is limited to 360/(number of detectors) degrees. In this way, the view of each radiation detector 240 may be more focused on a particular region of the formation. Additionally, such shielding eliminates or at least mitigates radiation scattered from one detector to another detector. As can be seen, each detector is separated from one another by radiation absorbent material. By eliminating detector-to-detector radiation scattering, more precise azimuthal readings are achieved.

While source collimator 225 is shown as a single, integrally formed body and conical surface 228, it need not be and could be formed of separate structural components, such as a source collimator combined with a detector collimator 248, so long as the shielding as described herein is achieved.

In the illustrated embodiment, the region of housing 230 around the opening in source collimator and detectors 240 may be fabricated of beryllium, aluminum, titanium, or other low atomic number metal or material, the purpose of which is to allow more of the gamma rays to enter detectors 240. This design is especially important for lower energy gamma rays, which are preferentially absorbed by any dense metal in the pressure housing.

Alternatively, or in addition to detector shielding or detector collimator 248, an anti-coincidence algorithm may be implemented in electronics 260 to compensate for detector-to-detector radiation scattering. In this way, a processor can mitigate the effects of multiply-detected gamma rays via an anti-coincidence algorithm. In certain embodiments, electronics 260, 262, and 264 are located above detectors 240 or below source 220.

Electronics 260 may include processor 262, memory 263, and power supply 264 for supplying power to gravel pack imaging tool 200. Power supply 264 may be a battery or may receive power from an external source such as a wireline (not shown). Processor 262 is adapted to receive measured data from radiation detectors 240. The measured data, which in certain embodiments includes count rates, may then be stored in memory 263 or further processed before being stored in memory 263. Processor 262 may also control the gain of the photomultiplier or other device for converting scintillations into electrical pulses. Electronics 260 may be located below source 220 and above detectors 240 or removed therefrom.

In one embodiment, the tool further includes an accelerometer, a 3 axis inclinometer or attitude sensor to unambiguously determine the position of an azimuthal segment. In certain embodiments, a compass device may be incorporated to further determine the orientation of the tool.

Fracture detection tool 200 may be constructed out of any material suitable for the downhole environment to which it is expected to be exposed, taking into account in particular, the expected temperatures, pressures, forces, and chemicals to which the tool will be exposed. In certain embodiments, suitable materials of construction for source collimator 225 and detector collimator 248 include, but are not limited to, sintered tungsten (known as heavy-met), lead, dense and very-high atomic number (Z) materials, or a combination thereof.

Further, while a 1 11/16 inch diameter configuration tool is illustrated in FIG. 1, the tool 100 can be sized as desired for a particular application. Those skilled in the art will appreciate that a larger diameter tool would allow more detectors and shielding to provide further segmentation of the view of the formation.

This tool may be deployed to detect fractures and to estimate their size. A person of ordinary skill in the art with the benefit of this disclosure will appreciate how to relate the log results of count rates and inferred densities of formation material to the structure of the formation and to reason from the results to the condition of the properties of the detected fractures.

As a further illustration of an exemplary geometry of the embodiment illustrated in FIG. 2, FIGS. 3A and 3B show cross-sectional views of another embodiment of the tool disposed in base pipe or production tubing 330, which is further disposed in casing 310. An annulus 350 is defined between the casing 310 and the tubing 330, where FIG. 3A shows a cross-section taken from the X-Y plane, which is perpendicular to the tool longitudinal axis, and where FIG. 3B shows a cross-section taken from the X-Z plane, along the tool longitudinal axis. As shown in the illustrated embodiment, upper and lower source collimators 328, 329 are each conical shaped in the X-Z plane or Y-Z plane. More specifically, upper collimator 328 has a surface that defines an emission angle θ₁ with respect to the tool longitudinal axis A_X, and lower collimator 329 has a surface that defines an emission angle θ₂ with respect to axis A_X. Detector 340 is shown in FIG. 3A in openings or slots 345, whereas radiation source 320 is shown depicted in FIG. 3B. As shown in FIG. 3A, detector collimators 348 are fan-shaped in the X-Y plane and rectangular in the X-Z or Y-Z planes. In certain embodiments, upper and lower conical source collimators 328, 329 reduce multiple scattering events in unwanted regions surrounding the tool and creating un-necessary background. More specifically, strategic placement and configuration of the conical upper and lower source collimators 328, 329 causes radiation from the source to be directed from the source 320 and single scatter from the wellbore wall (or gravel pack) to the detectors 340. The shape of the upper and lower source collimators 328, 329 and selective positioning of the detectors 340 from the source 320, vastly increases the number of counts detected by the detectors 340 of radiation that have single scattered (rather than undergone multiple scatters) so that resolution of the gathered data can be increased, thereby providing data that better represents the downhole formation. In an example, the angles θ₁,θ₂ are chosen so that the tool 10 can be put in different sized wellbores; where the spacing between the source 320 and detectors 340 is adjusted to ensure single scattering is detected in the varying diameter wellbores.

In addition to the energy levels of the radiation source, other factors that may be adjusted to discriminate segmented views of the formation include, but are not limited to the angle of the collimators and the source to detector spacing. Examples of suitable values of the emission angles θ₁, θ₂ range from about 15° to about 85°, and all values between 15° to about 85°, and wherein the lower value of the range of emission angles θ₁, θ₂ can be 15° to about 85° (and all values in between), and wherein the upper value of the range of emission angles θ₁, θ₂ can be 15° to about 85° (and all values in between). Examples of suitable source to detector spacing include, but are not limited to, from about 1 inch to about 12 inches, and all values between 1 to 12 inches.

Moreover, it is recognized that the downhole tool is capable of measuring count rates while being lowered or raised in the wellbore. In certain embodiments, the downhole tool may perform measurements while the tool is stationary in the wellbore. Exemplary raising and lowering rates include displacement rates of up to about 1800 feet/hour.

FIG. 4 illustrates in a partial side sectional view, an example of an imaging tool 400 inserted within a tubular 402. Embodiments exist wherein the tool 400 can be the same or substantially the same as the tools 100, 200 respectively of FIGS. 1, 2, and 3 and described above. In the example of FIG. 4, the tubular 402 is inserted into a wellbore 404 that is shown intersecting a subterranean formation 406. Casing 408 is optionally provided in the wellbore 404 for lining the sidewalls of the wellbore 404. Thus in this example, the tubular 402 is production tubing. Alternate examples of use exist wherein the tool 400 is inserted within casing 408 having no production tubing within. The tool 400 is deployed in the wellbore 404 on a line 410, where the line 410 can be a wireline, slickline, cable, or coiled tubing. The line 410 is shown inserted through a wellhead assembly 412 that is mounted on surface above an opening to the wellbore 404. Fluid 413 is illustrated in the tubular 402 and surrounding the space between the tool 400 and walls of the tubular 402.

Further illustrated in the embodiment of FIG. 4 are fractures 414 in the formation 406 surrounding the wellbore 404. In an example, fractures 414 define a discontinuity in the formation 406 that may occur where adjacent portions of rock or other subterranean strata shear from one another. In the example of FIG. 4, lengths of the fractures 414 can range from less than a foot, to in excess of many feet. In an example, the presence of the fractures 414 can be detected with the tool 400. In an example, included with the embodiment of the tool 400 of FIG. 4 is a radiation source 416, which can be substantially the same as sources 220, 320 respectively of FIGS. 2 and 3B and described above. Further in the example of FIG. 4, a sensor 418 is included with the tool 400, wherein the sensor 418 includes detectors 140, 240 respectively of FIGS. 1 and 3 and discussed above. Radiation emitted from the source 416 can travel along a path represented by arrows A, which initially diverges from the axis A_X. Some of the radiation undergoes scattering and is redirected to converge with the axis A_X at a location axially away from the source 416. As shown, the redirected radiation contacts sensor 418 where a count and associated energy of the radiation is detected.

Still referring to the example embodiment of FIG. 4, the radiation is directed in a conical pattern away from the source 416 and generally about a line intersecting the source 416 and sensor 418. As such, the radiation Compton scatters from the fluid 413 in the tubular 402, an area proximate the sidewall of the tubular 402, and the formation 406. At least some of the radiation scatters from materials in the fractures 414. It should be pointed out that paths the radiation follows from the source 416 to the sensor 418 are not limited to the select number of arrows A that are illustrated for clarity.

As is known, the energy of the radiation detected by the sensor 418 is affected by the Compton single-scatter angle of the radiation (i.e. the angle of the directional change of the radiation). Generally, the energy decreases with increasing scattering angles; thus the radiation flowing from the source 416 to the sensor 418 which undergoes only minimal scattering will have a greater detected energy than the radiation single scattered over a large angle from adjacent the tubular 402 the formation 406. The radiation single scattered from adjacent the tubular 402 will have a greater detected energy than the radiation single scattered from the formation 406 because the average angles are shallower. In an example, radiation counts detected by sensor 418 are binned based on an energy level of each count. It is within the capabilities of those skilled in the art to identify the substances from which the radiation scatters based on the counts and corresponding energy of the created spectrum. Moreover, those skilled in the art are capable of identifying a spatial location of the identified substances.

In an example, source 416 and sensor 418 are set apart a designated distance so that the gamma rays from the source 416 scatter from a region 420 at the wall of the wellbore 408. Optionally, the range of the region 420 from which the gamma rays from the source 416 scatter extends radially outward past the wall of the wellbore 408 and to within the formation 406. Region 420 can be an annular space circumscribing the wellbore 404 and having a radial thickness ranging from a few inches to several feet. Detecting the actual number of Compton scattered gamma rays per unit time provides an indication of the density of material from which the gamma rays have scattered. Moreover, material filling a fracture 414 generally has a density different from the surrounding formation 406. Thus, a change in rate of gamma rays detected by sensor 418 can indicate that a fracture 414 is at the wall of the wellbore 404 or in the region 420.

In one non-limiting example of use of the tool 400 of FIG. 4, the tool 400 is raised within the wellbore 404 on wireline 410 while gamma rays emitted from the source 416 Compton scatter from the wall of the wellbore 404 and/or from within the region 420 around the wellbore 404. As discussed above, the location of scatter can depend on the relative locations of the source 416 and sensor 418. Also noted above, a fracture 414 at the wall of the wellbore 404, or in the region 420, can be identified by a change in the rate of gamma rays detected by sensor 418. Moreover, by correlating the depth of the tool 400 in the wellbore 404 with any changes in gamma ray detection rate, a height or width of a fracture 414 can be estimated. Advantages of using the method and tool 400 described herein include that fractures are identifiable with gamma ray detection that are outside the size range detectable by known acoustic means.

An additional advantage of utilizing Compton scattering of gamma rays to identify fractures 414 in the formation 406 surrounding the wellbore 404, is that their vertical and azimuthal locations can be identified with precision, as well as their size. As illustrated in FIG. 5, strategically placed perforations 422 can be formed in the formation 406 based on precise spatial information of the fractures 414 derived from use of the tool 400 described above. An example embodiment of a perforating string 424 is shown disposed in the wellbore 404 for forming the perforations 422. The string 424 includes a series of perforating guns 426 with shaped charges 428. In the example of FIG. 5, the shaped charges 428 are disposed at a depth in the wellbore 404 and oriented so that when they are detonated, an ensuing metal jet (not shown) creates perforations 422 across the wall of the wellbore 404 and into the formation 406 to intersect with the fractures 414. In the example of FIG. 5, the tubular 402 lining the wellbore 404 is wellbore casing, and cement 430 is disposed in the annular space between the casing and wall of the wellbore 404. Thus the perforation 422 also extends through the casing and the cement 430. The intersection between the perforations 422 and fractures 414 create fluid communication between fractures 414 and the wellbore 404. Embodiments exist wherein the formation 406 is a shale formation adjacent a formation (not shown) having a hydrocarbon bearing reservoir; and wherein a fracture 414 extends into the adjacent formation and into communication with hydrocarbons therein. Thus intersecting fracture 414 that extends into the adjacent formation with a perforation 422 necessarily communicates the wellbore 404 with the hydrocarbon bearing reservoir.

Referring now to FIG. 6, an example of the imaging tool 400 is illustrated disposed in wellbore 404 and imaging the formation 406 around the wellbore 404; where the steps of imaging the formation 406 can be the same or similar to that described above and illustrated in FIG. 4. Further as described above, the tool 400 is moved within the wellbore 404 during imaging so that data from the formation 406 can be gathered at multiple wellbore depths. Analyzing the gathered data can provide information about the material within perforations 422 and/or fractures 414 in the formation 406. In an example, the information about the material includes the density of the material. Changes in the density of the material in the perforations 422 and fractures 414, which can be caused by the buildup of sand plugging or reactive changes (scale or dissolution), or fracture re-closure, can be estimated with time lapsed imaging in the wellbore 404 with the tool 400. In an embodiment, time lapsed imaging includes performing a baseline measurement made at an initial time with the tool 400, and then conducting subsequent measurements with the tool 400; any changes between imaged data obtained at different times can be used to estimate density changes.

Examples exist wherein the initial time of imaging takes place prior to introducing proppant into the wellbore 404, or after introducing proppant into the wellbore 404. As permeability of the perforations 422 and fractures 414 can be affected by the density of the material in the perforations 422 and fractures 414, monitoring changes in density of this material can therefore yield information about changes in permeability of the perforations 422 and fractures 414. Accordingly, imaging the formation 406 with the tool 400 can be used to determine which the perforations 422 and fractures 414 have undergone deterioration by using a time-lapse differential profile logging technique. Information about deterioration, or lack of deterioration, can enable well operators to plan remedial operations. In addition to monitoring density changes of material in the perforations 422 and fractures 414, any changes in size of the perforations 422 and fractures 414 can be monitored. Size changes of the perforations 422 and fractures 414 can include one or more of thickness, width, length, and combinations thereof. In an example, the perforations 422 and fractures 414 define voids in the formation 406.

One advantage of understanding the dynamics of fracture-evolution/development (i.e. injection, storage, and dissipative bleed off) during repeated cycles of cuttings re-injection in critical to maintain the integrity of any well, including a disposal well. Optionally, a differential log profile is generated that depicts the difference between a base-line logging measurement done early in the life of the well, and subsequent measurements made after the well has been used for some time. Differences in the fracture density profiles can indicate changes in the fractures caused by re-injection processes.

The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.

Claims

1. A method of imaging a wellbore comprising: a. directing radiation from a source to a formation surrounding the wellbore;b. detecting radiation scattered from the formation;c. estimating a rate and energy of the detected radiation; andd. estimating information about a change of a void in the formation based on the rate and energy of the detected radiation.

2. The method of claim 1, wherein the void is selected from the group consisting of a fracture and a perforation.

3. The method of claim 1, wherein steps (a)-(c) include time lapsed imaging.

4. The method of claim 1, wherein the source comprises a gamma ray source and which is directed in a substantially conical pattern from the source and wherein the energy of the detected radiation is dependent upon an angle of scatter of the radiation.

5. The method of claim 1, wherein the information about a change of the void is selected from the group consisting of a change in thickness of the void, a change of permeability in the void, a change in flowability through the void, and a change of density of material in the void.

6. The method of claim 1, further comprising estimating a location of the void.

7. The method of claim 1, wherein the void comprises a fracture that intersects a wall of the wellbore.

8. The method of claim 1, wherein the void comprises a perforation that intersects a wall of the wellbore.

9. The method of claim 1, wherein the wellbore comprises a well selected from the group consisting of an injection well and a production well.

10. A method of imaging a wellbore comprising: a. providing a logging instrument having a radiation source and a radiation detector;b. disposing the logging instrument into the wellbore and within casing that lines the wellbore;c. directing radiation from the source to a formation surrounding the wellbore and along a path, so that at least some of the radiation scatters in a direction back from the formation towards the radiation detector,d. detecting radiation scattered from the formation with the radiation detector; ande. identifying a change in a void in the formation based on a change of rate of the radiation detected.

11. The method of claim 10, wherein the void comprises an opening in the formation selected from the group consisting of a perforation and a fracture.

12. The method of claim 10, wherein steps (a)-(d) are repeated over time so that the change of rate of the radiation detected comprises a time lapsed measurement.

13. The method of claim 10, wherein the radiation is directed fully in a fan-shaped beam from the outer circumference of the logging instrument so that the radiation can scatter from an entire circumference of a wall of the wellbore.

14. The method of claim 10, further comprising repeating steps (b)-(e) while moving the logging instrument to different depths in the wellbore.

15. A method of imaging a wellbore comprising: a. directing radiation from a source to a formation surrounding the wellbore;b. detecting radiation scattered from the formation;c. estimating a rate and energy of the detected radiation;d. repeating steps (a)-(c) at a later time to perform a time lapsed measurement; ande. estimating information about a change of a void in the formation based on the time lapsed measurement.

16. The method of claim 15, wherein step (e) is based on a rate and energy of the detected radiation.

17. The method of claim 15, further comprising estimating a location of the void.

18. The method of claim 15, wherein the void comprises a space in the formation selected from the group consisting of a fracture and a perforation.