GB2572811A

GB2572811A - Evaluation of a formation outside of a pipe and evaluation of formation creep outside of a pipe

Info

Publication number: GB2572811A
Application number: GB1806054.1A
Authority: GB
Inventors: Merciu Alexandru
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2018-04-12
Filing date: 2018-04-12
Publication date: 2019-10-16
Also published as: GB201806054D0; WO2019199175A1

Abstract

A method of evaluating a formation 2 outside of a pipe 3 in a wellbore, wherein ultrasonic data gathered from within the pipe is provided and used to evaluate characteristics of the formation such as stratigraphic information, dip information, strike information and/or an evaluation of creep. Creep may be evaluated by taking repeat ultrasound measurements using ultrasound logging tool 8 at different times and comparing the evaluated data to evaluate formation creep. The collected data may be an impedance map that may be displayed on a monitor. Differences in impedance give information about the material outside of the pipe.

Description

EVALUATION OF A FORMATION OUTSIDE OF A PIPE AND EVALUATION OF FORMATION CREEP OUTSIDE OF A PIPE

The invention relates to a method of evaluation of a formation outside of a pipe in a wellbore, and a method of evaluating creep of a formation outside of a pipe in a wellbore.

Evaluating a formation behind a pipe in a wellbore is of great importance in understanding the structure and integrity of the well. This information may be of use during the life span of the well from construction, through to production, through to closure of the well.

However, evaluating the formation outside of a pipe in a wellbore is difficult for many reasons.

One reason is that any logging equipment for gathering data must necessarily be introduced into the pipe. Hence, the pipe (which is a sturdy metallic structure) is in between the logging equipment and the formation, which in turn means the logging equipment, and the associated physics and data processing method, cannot directly evaluate the media on the outside of the pipe.

Another reason is that the wellbore may be very deep (in some cases more than 10km deep). This leads to a hostile environment in the well, which in turn means that any logging equipment must be very robust.

One particularly useful evaluation of a formation outside of a pipe is to evaluate the creep of the formation. As shown in Figure 1a, a wellbore 1 may have been drilled through a formation 2. Through the wellbore 1 there may be pipe 3 placed inside the wellbore 1. To seal the wellbore 1, cement 4 may be introduced into the annulus 5 between the formation 2 and the pipe 3. While the cement 4 is not intended to fill the annulus 5, at certain points 6, the cement 4 may touch the pipe 3. The annulus 5 typically contains a fluid, which may include water, gas and/or mud.

Figure 1b shows the same wellbore 1 but at a later time in comparison to Figure 1a. Due to pressure, forces, characteristic mineralogy, and electrochemical interaction between annuli fluids and the formation 2, the formation 2 may have creeped over time such that the formation 2 touches the pipe 3 at certain points 7. The formation 2 at points 7 will have properties that are desirable to be evaluated. These properties may include stratigraphic information and dip/strike information which can be further linked to prior information about the mineralogy, petrography or stress information for a given formation and field. Further, it is desirable to be able to monitor the points 7 over time to see how the creep evolves. Typically, over time there is a tendency for the formation 2 to creep inwards to close the annulus 5.

-2As is known in the art, the acoustic resonance (and hence impedance) of a pipe varies depending on the material/medium on the outside surface of the pipe. As an analogy, when a bell is surrounded by air, it can resonate for a long time. However, if the bell is touched or gripped by a human hand, the resonance only occurs for a short time (particularly for the higher frequencies).

Thus, by examining the acoustic impedance using tools within the pipe in the wellbore, one can attempt to draw conclusions about the media outside of the pipe. Currently, there are two main types of logging to examine acoustic impedance. These technologies are both referred to as active acoustic logging. Generally, they use an active acoustic source and an array of acoustic receivers, which are lowered inside a pipe inside a borehole and data is collected against depth. This technology takes advantage of the acoustic impedance contrast between the various radiallydistributed layers in the borehole (e.g. the acoustic impedance contrasts between mud, pipe, cement, formation, etc.). The most commonly used logging tools are wireline tools. Based on the frequency range of the acoustic source the tools can be classified in two main groups: sonic tools and ultrasonic tools. These are discussed below in more depth.

Sonic tools are typically characterized by a source frequency bandwidth of about 700 Hz to 80 kHz. Most commonly used sonic tools are equipped with monopole sources with a central frequency of about 20 to 30 kHz and a distributed array of receivers. There are typically two receivers at different distances from the source (typically one is at 3ft (0.9m) and one is at 5ft (1.5m)). The standard answer product provided by the service is called CBL - VDL (cement bond log - variable density log). The recorded waveforms are analyzed in terms of attenuation of the signal strength recorded on the first peak amplitude of the waveforms at the 3ft receiver (CBL). A full waveform amplitude display at the 5ft receiver (VDL) is displayed along with the CBL curve. The source impulse sets a guided extensional acoustic mode (SO first order symmetric mode) inside the body of the pipe which propagates at the speed of sound in the material of the pipe (i.e. the speed of sound in steel). The attenuation of signal strength along the propagation path is influenced by the acoustic contact quality inside and outside the pipe. Furthermore the low frequency mode “leaks” planar wave fronts inside the hole which are recorded as pressure variation at receivers. Because the monopole source does not excite directivity on the initial wave front impulse, the CBL-VDL answers does not present azimuthal information, but rather presents a convolution effect of all the media investigated. CBL-VDL interpretation reference flowcharts exist and they are actively used to provide robust interpretations of the media outside of the pipe. For simplicity

- 3one can picture the CBL-VDL conclusions as a bell ringing: if it is high-pitch then there is no solid media (e.g. cement or formation) in contact with the pipe; if it is lowpitch then there is solid media in contact with the pipe.

Ultrasonic tools are typically characterized by a source frequency bandwidth of about 100 kHz to 2 MHz. Because of the high frequency bandwidth of the source the ultrasonic tools are characterized by high directivity characteristics as opposed sonic tools. This permits azimuthal information to be found. As an analogy, one can picture the ultrasonic tools as being similar to medical ultrasound echometers. In general the measurements are performed over ultrasound waveforms recorded by a transducer (the transducer may simultaneously be the ultrasonic source and the receiver) or an array of ultrasound transmitter receivers. Based on the angle of incidence between the ultrasonic wave front and the target (i.e. the inner surface of the pipe) one can split the measurements in vertical incidence and oblique incidence. Thus, modern ultrasonic logging technologies permit simultaneous vertical and oblique data recording and hence contact impedance on the outer surface of the pipe can be found as a function of azimuthal angle and longitudinal position of the pipe.

In order to draw conclusions on well integrity from these active acoustic logging techniques, the human interpreter of the data must combine the impedance information gathered from the acoustic logs with other information (such as cement jobs, well history, etc.). This requirement is clearly described in the current regulatory frame work.

As is known, the results of data processing applied to raw acoustic data are displayed in logging maps. When the data is gathered, numerical values of impedance can be found as a function of longitudinal position (e.g. depth) and azimuthal angle of the pipe. These numerical impedance values can be transformed into a map by using a colour scheme to show different impedances with different colours. Thus, a map is a representation of the numerical values resulting from acoustic data in two dimensions: longitudinal position on one axis and azimuthal angle on the other axis. An example of such a map is shown in Figures 2a-2c.

An analogy can be made between these maps and topographical geographical maps. In a topographical geographical map, altitude of a landmass as a function of latitude and longitude may be displayed using a colour scheme, where the colours of the colour scheme change with altitude. With the maps derived from the acoustic data, impedance of a material outside of the pipe can be displayed as a function of depth and azimuth.

As further background to the present invention, the wellbore is first drilled during an exploration phase. During the exploration phase, there is no pipe or casing

-4introduced into the wellbore. Rather, the sides of the formation through which the wellbore is drilled are left open. Such a wellbore is described as “openhole” in the art.

If hydrocarbons are found to be present, then the wellbore is converted into a production wellbore. One of the steps performed here is that a pipe (or casing) is introduced into the wellbore. The pipe is for moving materials (such as hydrocarbons and mud) between the hydrocarbon reservoir and the Earth’s surface. The pipe is typically a long (typically several kilometres long) cylindrical pipe, and may contain other pipes within it. Such a wellbore is described as “cased hole” in the art.

In the case of openhole, it is known to evaluate a formation using ultrasonic data. An example of such a method is taught in US 5162994, where properties (such as dip and strike) of the formation are found. However, because this is in the openhole scenario, there is no pipe present between the ultrasonic logging tool and the formation, and hence this method does not suffer from the complications associated with attempting to evaluate a formation behind a pipe.

However, as will be clear from the description below, the present invention does not relate to openhole scenarios. Rather, the present invention is concerned with the casedhole scenario (i.e. evaluating the formation outside of a pipe).

With regard to prior art examples in a casedhole scenario, US 8336620 shows a method of identifying where a formation contacts a pipe in a wellbore. This is achieved by comparing ultrasonic data with CBL-VDL data (essentially as has been discussed above).

Further, in the casedhole scenario, Hayman A.J., Hutin R. and Wright P.V., 2 April 1991, High-Resolution Cementation and Corrosion Imaging by Ultrasound, SPWLA 32^nd Annual Logging Symposium, 16-19 June 1991, (Hayman) teaches a method of evaluating the cement outside of a pipe using ultrasonic data and impedance maps.

Thus, whilst it is known to be able to estimate the location of where a formation and cement touches a pipe, and it is known to evaluate a formation in an openhole scenario, prior to the present invention there is no way of evaluating a formation in a casedhole scenario. The present inventor has devised a way of doing so using the standard ultrasonic data gathering techniques discussed above.

In a first aspect, the invention provides a method of evaluation of a formation outside of a pipe in a wellbore, wherein ultrasonic data gathered from within the pipe is provided, the method comprising using the ultrasonic data to evaluate the formation behind the pipe.

- 5As mentioned above, evaluating the formation behind the pipe in a cased borehole is of great importance. Evaluating the formation behind the pipe can allow for the overburden (particularly the creeping and flowing of the overburden) to be evaluated and monitored, can provide calibration references for mechanical stress and strain estimations in the overburden, can provide references for geophysical (e.g. seismic) reservoir monitoring, can enhance the evaluation of the well integrity, can evaluate formation creep, can confirm with a high degree of confidence whether the formation is providing a hydraulic sealing around the pipe, and can help in deciding how and when to permanently close a well.

The present invention allows for such an evaluation of the formation behind a pipe to be obtained using ultrasonic data. As mentioned above, in the past, ultrasonic data has been gathered within the pipe in a wellbore. However, until the present invention, it has not been possible to use ultrasonic data to evaluate the formation behind a pipe in a cased wellbore.

By ultrasonic data, it is meant ultrasonic data that has been gathered using a known ultrasonic logging tool (such as the tool described above with one or more ultrasonic transducers capable of longitudinal and azimuthal data gathering). The frequency of the ultrasound used may be approximately 100 kHz to 2 MHz. This frequency may be the central frequency value of the signal, since in practice it is not typically possible to produce a perfect spike (Dirac function) signal.

Thus, the present invention allows for information about the formation behind a pipe of a wellbore to be found using an existing data-gathering technique that is already used in a cased well (ultrasonic data-gathering). No additional logging tools or well operations are therefore required. The present invention is therefore an efficient method for evaluating the formation behind the pipe.

Evaluating the formation may mean obtaining physical information about the formation. For instance, evaluating the formation may be deducing the physical properties of the formation. This may include where the formation touches the pipe (as has been achieved in the prior art discussed above), but also goes beyond this. For instance, the evaluation of the formation behind the pipe may comprise obtaining stratigraphic information, dip information, strike information and/or creep evaluation. Stratigraphic information may be any information to do with the structure (e.g. layers/strata) of the formation. Such information may include the type of material present, for example sand shale, rock, and/or salt, etc., and information (such as depth, order and angle) of the layers.

The formation may be any structure beneath the Earth’s surface through which a borehole passes. It may comprise rock, sand, shale, rock, and/or salt. The

-6structure may comprise the reservoir to which the borehole reaches and/or may comprise the overburden of a reservoir. The term formation is intended to mean the structures that are naturally present beneath the Earth’s surface; it is not intended to cover man-made materials or components that may be present in or around the borehole (such as cement or pipe materials).

As mentioned above, the pipe is in the borehole. The pipe may also be called a casing, or a tube, or a tubular. As is known in the art, a pipe is used during production of hydrocarbons through the borehole. The pipe may transport mud and/or hydrocarbons between the reservoir and the Earth’s surface. As is known, there may be multiple concentric pipes used during hydrocarbon production. The pipe referred to in this specification is the outermost pipe (i.e. the pipe that is exposed to the formation/cement of the borehole), and not any other pipe within the outermost pipe.

By saying the formation is outside of the pipe, it may be that the formation is radially outward of the pipe or behind the pipe, preferably in contact with the pipe (i.e. having no other medium in between the outer surface of the pipe and the formation). As mentioned above, generally speaking in a cased borehole, the formation will not touch the outer surface of the pipe. Rather, the outer surface of the pipe will be in contact with fluids in an annulus that is formed between the inner surface of the borehole and the outer surface of the pipe, or with cement that has been used to seal the borehole. However, it is possible (for example due to formation creep or due to movement of the pipe) that the outer surface of the pipe may be in contact with the formation itself. Thus, the present method may evaluate the formation outside of the pipe at the location(s) at which the formation is in contact with the pipe.

The ultrasonic data used may be of a standard, known type. The ultrasonic data may provide, amongst other information, data concerning the impedance of media outside of the pipe. The data may comprise impedance as a function of azimuthal angle of the pipe and as a function of longitudinal position of the pipe (e.g. depth). The ultrasonic data may be gathered by a known tool. For example, it may be a rotating tool with ultrasonic transducers that is lowered and raised through the pipe.

The outer surface of the pipe may be in contact with one or more media. The ultrasonic data may give impedance data for the one or more media over the outer surface locations of the pipe.

The one or more media may comprise the formation, at certain location(s) on the pipe. As mentioned in more detail below, the media may also comprise one or

- 7more other media, such as fluid and/or cement. By “cement”, it is meant any material used in the art to seal the face of a wellbore.

The ultrasonic data may comprise an impedance map showing the various impedance values of said one or more media at respective locations within the borehole. Thus, raw gathered ultrasonic data may be (or may have been) processed to produce the impedance map. This processing is a known technique and is not discussed herein. The impedance map may be a continuous map showing respective impedance values at their respective positions (e.g. impedance values plotted at their respective azimuthal angles and of longitudinal positions). The density of the impedance values found may be high such that the map appears continuous. The impedance map may be of a similar form to a topographical geographical map, where altitude (instead of impedance) is plotted as a function of latitude and longitude (instead of azimuth and longitude). The specific impedance values found outside of the pipe may be the impedance value as experienced on the outer surface of the pipe.

The impedance map may comprise a colour scheme for showing said various impedance values. The colour scheme may be such that the colour associated with one impedance value is different to another impedance value. The colour scheme may be continuous with respect to varying impedances (i.e. it may be a spectrum from a minimum impedance (e.g. 0 MRayl) to a maximum impedance (e.g. 10 MRayl).

The method may comprise using a colour scheme such that the impedance associated with the formation is distinguishable from the impedance associated with the other one or more media. The method may comprise choosing (or determining or formulating or producing) such a colour scheme.

In the prior art, when ultrasonic data and impedance maps have been used to look at wells (such as in Hayman), no such intelligently, deliberately chosen colour scheme is used. Rather, in Hayman, a relatively arbitrary colour scheme is used that does not aid the user/reader to see important information in the impedance map concerning the formation. In the present method, using an intelligently, deliberately chosen colour scheme allows the impedance of the formation to be distinguishable from the impedance(s) of the other media is an advantageous step that the present inventor has found. It is advantageous since it allows the formation to be evaluated using ultrasonic data.

The present inventor discovered that it was possible to produce a colour scheme such that the impedances associated with the formation are distinguishable from the impedances associated with the other media present. The inventor did this

- 8by testing (in a laboratory environment) the impedances of several different media that may be present outside of (e.g. in contact with the outer surface of) the pipe in a borehole.

The inventor found that fluids have a low impedance (e.g. approximately 0-4 MRayl (for instance, gas may have an impedance of approximately 0-0.3 MRayl, water may have an impedance of approximately 0.3-2.0 MRayl, and mud may have an impedance of approximately 2.0-4.0 MRayl)). This is because the ultrasonic energy loses energy to fluids through only compressional energy coupling.

Further, the inventor found that cement may have an intermediate impedance (e.g. approximately 3-7 MRayl (for instance, light cement may have an impedance of approximately 3-5 MRayl and heavy cement may have an impedance of approximately 4-7 MRayl)). This is larger than for fluids because the ultrasonic energy loses energy to the formation through both compressional and shear energy coupling (because the cement is solid).

Further, the inventor found that the formation may have a high impedance (e.g. approximately 6-250 MRayl). The formation may have the highest impedance of all media present. This is larger than for fluids because the ultrasonic energy loses energy to the formation through both compressional and shear energy coupling (because the cement is solid). Further, it is larger than for cement, as cement is typically more homogenous than formation rock.

Thus, the inventor found that of all the likely media present outside of the pipe, the formation may have the highest impedance, and there may not be a significant overlap in impedance values between the formation and the medium with the next lowest impedance value (e.g. cement).

From this discovery, the inventor was able to conclude that it may be possible to choose/use a colour scheme on the impedance map that distinguishes the impedance values associated with the formation contacting the pipe, with the impedance values associated with the other media contacting the pipe.

By “distinguishes”, it is meant that the colour(s) that indicate the impedances associated with the formation are different to the colour(s) that indicate the other impedances that are present in the impedance map. This difference may be clear to the human eye/brain.

For instance, the colour scheme may be such that a disproportionately large colour change occurs around a selected impedance value. By “disproportionately large”, it is meant that there is a larger colour shift than would be expected if a random, unintelligently-chosen colour scheme was used (e.g. a colour scheme that changed uniformly between maximum and minimum values). For instance, a

- 9disproportionately large colour change may be one that a user (i.e. the human eye and brain) can clearly detect, and can detect more clearly than other colour shifts at other positions on the colour scheme. A disproportionately large colour change may be one where the colour changes faster (with respect to impedance) at a certain impedance range in comparison to other impedance ranges. A disproportionately large colour change may be a sudden/instantaneous colour change between two quite different colours (e.g. grey to blue) at a particular impedance value.

The selected impedance value may also be referred to as a threshold value, a particular value or a specific value. It may be selected based on observations of the impedances of the various media outside of the pipe (e.g. the laboratory measurements mentioned above).

The disproportionately large colour change may occur over a certain range of impedance values. This range may be centred around the selected impedance value. The range may be small, so the colour changes quickly. For instance, the range may be less than 1 MRayl, or less than 0.5 MRayl, or less than 0.1 MRayl or even approximately 0 MRayl.

The selected impedance value may be between the impedance value of the formation and the impedance value of the medium that has the next highest impedance value. As mentioned above, the impedance values of the formation and the other medium/media may be known or expected values, e.g. from knowing what media are likely behind a particular pipe and from laboratory measurement.

The medium that has the next highest impedance value (i.e. next to the formation impedance value) may have an impedance lower than the impedance of the formation but higher than the impedance of any other medium that may be present outside of the pipe.

The medium that has the next highest impedance value may be cement.

The formation may have the highest impedance value of all the media present behind the pipe.

The selected value may be approximately between 5 to 8 MRayl, preferably approximately between 5.5 to 7 MRayl, preferably about 6-6.5 MRayl, and preferably approximately 6 MRayl. This value may be optimal since, as mentioned above, the inventor found during the laboratory experiments that the impedance of cement is about 4-7 MRayl and the impedance of the formation is about 6-250 MRayl.

There may be a plurality of selected impedance values around which there is a disproportionately large colour change. The selected values may be located approximately at impedance values where an expected impedance value of one medium changes to an expected impedance value of another medium (such as

- 10around 3-5MRayl, preferably around 4MRayl, for fluid (e.g. water or mud) to solid (e.g. cement); around 0.3MRayl for gas to water; around 2 MRayl for water to mud; around 5 MRayl for light cement to heavy cement; and/or around 6-7 MRayl for cement to formation).

The method may comprise using a colour scheme for the impedance map such that there is a disproportionately small colour change below a chosen impedance value. By “disproportionately small”, it is meant that the colour change is less than would be expected than if a random, unintelligently-chosen colour scheme was used (e.g. a colour scheme that changed uniformly between maximum and minimum values). For instance, a disproportionately small colour change may be one that a user (i.e. the human eye and brain) cannot clearly detect, and can detect less clearly than other colour shifts at other positions on the colour scheme. A disproportionately small colour change may be one where the colour changes slower (with respect to impedance) over a certain impedance range in comparison to other impedance ranges.

The disproportionately small colour change may take the form of a substantially uniform colour over a range of impedance values. This range may be between 0 MRayl and the chosen value.

The chosen impedance value is preferably different to the selected impedance value discussed above. The chosen impedance value is preferably lower than the selected impedance value discussed above.

The chosen impedance value may also be referred to as a threshold value, a particular value or a specific value. It may be selected based on observations of the impedances of the various media outside of the pipe (e.g. the laboratory measurements mentioned above).

The reasons for having a disproportionately small colour change below a chosen value, and why this is advantageous, are given below.

During the laboratory experiments discussed above, the present inventor discovered that below a certain impedance (for example, below around 4 MRayl), the media at the outside of the pipe is likely to be fluid (either gas, water or mud), or to behave as a fluid with respect to ultrasonic energy (e.g. some solid cement may behave as a fluid with respect to ultrasonic energy if there are large amounts of trapped gases or rubber-like particles in the cement slurry)..

The inventor concluded that none of the impedances on the ultrasonic data impedance map with values less than 4 MRayl may be of importance when looking to evaluate the formation. From the laboratory experiments, as mentioned above, the formation is expected to have a much higher impedance (e.g. 6 to 250 MRayl).

- 11 Because the inventor discovered that none of the impedance values in the impedance map below a certain value (which may be around 4 MRayl) may be due to the presence of the formation, the inventor realised that there may be no need to use many colours to show the impedance variation between zero MRayl and the chosen impedance value. Since there is a finite spectrum of colours, the inventor chose to use only very small (or no) changes in colour below the chosen impedance value, thus allowing more of the colour spectrum to be used for important impedance changes around the expected formation impedance values. Further, since unnecessary changes in colour can distract the human eye/brain thus misleading the reader of the map, the inventor chose to use only very small (or no) changes in colour below the chosen impedance value so that the user would not be misled.

Alternatively, it may be possible to simply remove all data from the impedance map with impedance values below the chosen value.

The chosen impedance value is approximately between 3 to 5 MRayl, preferably approximately between 3.5 to 4.5 MRayl, preferably approximately 4 MRayl. From the laboratory experiments mentioned above, the inventor has found that below approximately 4 MRayl, the losses are due primarily to compressional coupling only, whereas above 4 MRayl the losses are due to a combination of shear and compressional coupling.

The disproportionately small colour change may occur over the range of 0 MRayl to the chosen impedance value.

The chosen impedance value may be approximately between the impedance value of at least one solid medium and at least one fluid medium. These impedance values may be the impedance values of media that are expected to be outside of the pipe, and they may be measured in a laboratory as mentioned above. The at least one solid medium may be the solid medium with the lowest impedance. The at least one fluid medium may the fluid medium with the highest impedance.

The method may comprise choosing (or determining or formulating or producing) the colour scheme to be used.

Doing so may comprise choosing the selected value, and/or choosing how the colour scheme will change disproportionately quickly around the selected value (e.g. between what colours in the spectrum will the colour change, over what impedance range (e.g. how quickly) will the colour change around the selected value, etc.).

Doing so may comprise choosing the chosen value, and/or choosing how the colour scheme will change disproportionately slowly below the chosen value.

- 12The choosing of the colour scheme may be done with knowledge of the particular wellbore (e.g. knowledge of what media are likely to be in the wellbore) and/or knowledge of the impedances of the media likely/expected to be outside of the pipe (e.g. from the laboratory experiments mentioned above).

The impedance map may be normalised such that the colour scheme of impedance map has an increased contrast. This normalisation may be any suitable normalisation technique, but is preferably static normalisation. This normalisation preferably occurs on the chosen colour scheme discussed above (i.e. the colour scheme that has been chosen/modified with knowledge of the expected impedances of the expected media outside of the pipe).

The colour scheme of the impedance map may be converted to black and white. This may preferably occur after the colour scheme is chosen (as discussed above), and preferably after the contrast of the colour scheme has been increased (as discussed above).

The inventor has found that converting the colour impedance map to a black and white image, particularly after having used an intelligently-chosen colour scheme and normalising the data (as discussed above), improves the clarity of the map and allows the user to see patterns more clearly.

The method may comprise evaluating the formation by extracting information from patterns in the impedance map. This may be performed in any known way by skilled readers of impedance maps. The impedance map may be read and interpreted by a human eye/brain. However, borehole imaging software can also be used. The skilled reader (just like the reader of a topographical geographical map) may be able to read the impedance map to deduce information about where the formation is in contact with the pipe, and the formation properties in such a location. For instance, stratigraphic information may be deduced. Further, patterns (such as sinusoidal patterns) may be identified in the impedance map, from which dip and strike information can be deduced in a standard way.

The method may comprise using the ultrasonic data in combination with one or more other data sets to evaluate the formation. The other data sets may comprise other well log(s) (such as gamma logs and/or acoustic logs (which can be used for VDL CBL analysis)), knowledge of the well’s construction (e.g. knowledge of the cement application or pipe construction or borehole drilling), previous knowledge of cement, seismic data and/or electromagnetic measurements). The other data sets may be able to guide the reader of the impedance map as to what conclusions concerning the formation are possible or probable, or to corroborate the reader’s conclusions.

- 13For instance, in the case of other well log(s), the other well log(s) may be taken from the same well, possibly at a similar time to ultrasonic data.

A gamma log may be used since the different media outside of the pipe may have different gamma activities. For instance, shale (which may be part of the formation) has a high gamma value. Additionally/alternatively, an acoustic log may be used. Using an acoustic log (for example an acoustic log that has been processed using the VDL CBL method described in US 8336620), the depth location(s) of the pipe at which high impedances are present can be found. These high impedances may be indicative of the formation touching the pipe, and hence the depth location(s) of the high impedances can be used to help identify depth location(s) on the ultrasonic data impedance map to look at in more depth, or simply to corroborate the depth location(s) of the ultrasonic data impedance map where the reader of the map believes the formation is touching the pipe.

In a second aspect, the invention provides a method of evaluating formation creep outside of a pipe in a wellbore, comprising performing any of the steps discussed above in relation to the first aspect of the invention.

The method of evaluating creep may comprise performing any of the methods of the first aspect at a first time to obtain a first evaluation of the formation; performing any of the methods of the first aspect at a second later time to obtain a second evaluation of the formation; and comparing the first and second evaluations of the formation to evaluate formation creep outside of the pipe. The comparison may be made by the reader of the impedance maps. The impedance map produced at the first time and the impedance may produced at the second time may be used in a time-lapse video to show the progression of formation creep over time. The reader may be able to evaluate creep from such a time-lapse. An example of a time-lapse view of a well is shown in Merciu IA, RD628032_Time Lapse well integrity, Research disclosure database number 628032, 13 July 2016.

Of course, there may be more than two evaluations at different respective times. There may be three, four, five, six or more. There may be any number of evaluations at different respective times. These may all be used in a time-lapse video.

Any of the methods of the first and second aspects may comprise gathering the ultrasonic data. As mentioned above, this may be performed using a known ultrasonic tool. The tool is specifically designed to be able to withstand the extreme environments deep inside the well. The tool is able to collect ultrasonic data as a function of azimuthal angle and longitudinal position (e.g. depth) of the pipe. For

- 14example, it may be a rotating tool with ultrasonic transducers that is lowered and raised through the pipe.

In a third aspect, the invention provides a computer program product comprising instructions that, when executed, will configure a computer apparatus to implement any of the methods of the first two aspects and to display the impedance map on a monitor of the computer apparatus.

The computer program product may comprise instructions that, when executed, will configure a computer apparatus to process raw ultrasonic data gathered from an ultrasonic tool into an impedance map. This may be performed in a known way.

The computer program product may allow a user to adjust the colour scheme and/or contrast of the colour scheme as desired by the user (and as described in the first aspect).

In a fourth aspect, the invention provides a system for evaluation of a formation outside of a pipe in a wellbore comprising an ultrasonic logging tool for deployment within the pipe in order to obtain ultrasonic data; a processor arranged to perform any of the methods of the first two aspects; and a monitor for displaying the impedance map to a user of the system for evaluation of the formation.

The processor and the monitor may be arranged such that the monitor displays the impedance map along with any other data the user wishes to compare the ultrasonic data to (such as other well logs, previous knowledge of the well, etc. as discussed above in the first aspect).

The well discussed herein is preferably a production well for producing hydrocarbons. The well, the borehole and the pipe may extend from a hydrocarbons reservoir to the Earth’s surface.

The term “media” used herein may mean the materials outside of the pipe.

Certain preferred embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings in which:

Figure 1a shows a cased wellbore at a first time;

Figure 1b shows the cased wellbore of Figure 1a at a later time;

Figure 2a shows a prior art example of an impedance map produced using ultrasonic data taken from within a cased wellbore;

Figure 2b shows an impedance map produced using the same ultrasonic data as the impedance map of Figure 2a but with a deliberately, intelligently chosen colour scheme, in accordance with an embodiment of the present method;

Figure 2c shows an impedance map produced using the same ultrasonic data as the impedance map of Figure 2a and with the same deliberately, intelligently

- 15chosen colour scheme of Figure 2b, but with an increased contrast, in accordance with an embodiment of the present method; and

Figure 3 shows a comparison of an impedance map that has not had its contrast increased with an impedance map made using the same data that has had its contrast increased.

As has been discussed briefly above, Figure 1a shows a schematic view of a cased wellbore. The wellbore 1 has been drilled through a formation 2. A pipe 3 is placed inside the wellbore 1. To seal the wellbore 1, cement 4 has been introduced into the annulus 5 between the formation 2 and the outside of the pipe 3. While the cement 4 is not intended to necessarily fill the annulus 5, at certain points 6, the cement 4 may touch the pipe 3. The annulus 5 is typically filled with a fluid, which may include water, gas and/or mud.

It will be understood that when solids (such as cement or the formation) touch the pipe 3, the acoustic resonance of the pipe 3 will be altered. Hence, by investigating the acoustic impedance of the pipe 3, it is possible to estimate what materials are present outside of the pipe 3.

In order to investigate the acoustic impedance of the pipe 3, a wire-line ultrasonic logging tool 8 is used. This tool 8 is of a known type comprising rotating ultrasonic transducers capable of collecting data around the azimuth of a pipe. As the tool 8 is moved up and down the wellbore 1, it is therefore capable of collecting ultrasonic data in both the azimuthal and longitudinal directions of the pipe.

This ultrasonic data is processed in any known way to produce an impedance map, said impedance map having a longitudinal dimension of the pipe on one axis and the azimuthal direction of the pipe on the other axis. An example of such a typical impedance map is shown in Figure 2a.

Figure 1b shows the same wellbore 1 but at a later time in comparison to Figure 1a. Due to pressures and forces present in the formation 2, the formation 2 has creeped over time such that the formation 2 touches the pipe 3 at certain points 7. The formation 2 at points 7 will have properties that are desirable to be evaluated. These properties include stratigraphic information and dip/strike information.

The tool 8 is used again to gather a second set of ultrasonic data, which in turn is processed to produce a second impedance map.

The process of acquiring ultrasonic data can be repeated at multiple other times to monitor the creep of the formation 2.

The present method is one that takes the gathered ultrasonic data (in the form of the impedance map), and processes said data such that a skilled reader of the impedance map can evaluate the formation and assess formation creep.

- 16With regard to Figure 2a, this shows an impedance map 10 produced using a prior art method (such as the method of Hayman). The impedance map 10 is produced using known processing techniques from ultrasonic data gathered by the tool 8. On the y-axis is the depth of the pipe 3. On the x-axis is the azimuthal angle of the pipe 3 (i.e. angle from 0-360°).

At this point, it should be noted that although this impedance map has been displayed in black-and-white (simply to meet the rules and regulations of patent offices), the skilled person will be aware that in reality this impedance map is a coloured map. Different colours in the map represent different impedances. This variation in colour with respect to impedance is referred to as the colour scheme of the map. There is a legend 11 describing the colour scheme that the reader of the map may use to understand the map.

With regard to Figure 2a, due to the colour scheme chosen, the impedance map does not clearly show (at least in comparison to Figures 2b and 2c) many of the features of the media behind the pipe 3. Thus, due to the colour scheme chosen, the reader of the map is unable to estimate, determine or evaluate the formation behind the pipe 3, or creep of the formation behind the pipe 3.

Prior to the present method, ultrasonic data has not been used to evaluate formation properties in a casedhole scenario. The present inventor realised that there may be relevant information in ultrasonic data impedance maps that, due to the typical colour schemes chosen, is not visible to the reader of the impedance maps.

The present inventor has developed a new colour scheme that, for the same ultrasonic data, can provide the reader of the impedance map with more information on formation properties behind the pipe 3.

The inventor developed the new colour scheme by performing laboratory experiments to find expected impedances of media that are expected to possibly be in contact with the outer surface of the pipe 3. Such media include gas, water, mud, light cement, cement and formation materials (such as shale, sand, salt, rock, etc.).

The inventor found that gas has an impedance of approximately 0-0.3 MRayl, water has an impedance of approximately 0.3-2.0 MRayl, mud has an impedance of approximately 2.0-4.0 MRayl, light cement has an impedance of approximately 3-5 MRayl, heavy cement has an impedance of approximately 4-7 MRayl, and the formation has an impedance of approximately 6-250 MRayl.

From these experimentally-found expected values of the expected materials that may be present behind the pipe 3, the inventor made a new colour scheme. The new colour scheme has stark colour changes at impedance values which would indicate a material change. For instance, a large colour change was introduced to

- 17the colour scheme at around 6 MRayl (since, below 6MRayl, impedances are likely to be due to cement and, above 6MRayl, impedances are likely to be due to the formation). Further, a large colour change was introduced to the colour scheme at around 4 MRayl (since, below 4MRayl, impedances are likely to be due to fluids and, above 4MRayl, impedances are likely to be due to cement).

Other colour changes may be introduced at other impedances that may indicate expected media changes. For instance, there may be large colour change around 0.3MRayl for gas to water; around 2 MRayl for water to mud; and around 5 MRayl for light cement to heavy cement.

Such a colour scheme is used in Figure 2b. Figure 2b shows an impedance map 20 produced using the same ultrasonic data as the impedance map of Figure 2a. However, because the colour scheme in Figure 2b has been intelligently chosen (as described above) to deliberately highlight certain expected media changes, much more detail of where different media are located outside the pipe 3 can be seen. The colour scheme is shown in legend 21.

(It should be noted that although this impedance map has been displayed in black-and-white (simply to meet the rules and regulations of patent offices), the skilled person would be aware that the impedance map is a coloured map.)

To further increase the amount of information the skilled user of the map can extract concerning the properties of the formation outside of the pipe, the inventor increased the contrast of the colour scheme of Figure 2b to produce the colour scheme shown in the legend 31 of Figure 2c. Figure 2c shows the impedance map 20 of Figure 2b (on the left of Figure 2c) next to a new impedance map 30 where the contrast of the colour scheme has been increased (on the right of Figure 2c). Due to the increase in contrast, patterns in the impedance map 30 are clearer. This contrast increase is performed using a static normalisation. The impedance map 30 uses this colour scheme, and even more details of the media behind the pipe can be seen.

Figure 3 shows another comparison of two impedance maps 40, 50 that is similar to the comparison shown in Figure 2c, but where the impedance maps 40, 50 have been made using different ultrasonic data in comparison to Figure 2c. The left hand impedance map 40 shows an impedance map with a selected colour scheme. The right hand impedance map 50 shows an impedance map made from the same data and same general colour scheme as map 40, but where the contrast has been increased. Similarly to Figure 2c, the patterns in the impedance map 50 where the contrast has been increased are clearer for the skilled map reader to interpret.

- 18As can be appreciated, due to the processing techniques developed by the present inventor, the impedance maps 30, 50 show many more details than the impedance map 10 of Figure 2a.

The skilled user of the improved impedance map (map 20, 40 or preferably 30, 50) can use the greater level of detail to make evaluations of the formation 2.

This may be achieved by converting the improved impedance map to a blackand-white format (which will look like the black-and-white pictures shown in map 30, 50).

When using the improved impedance map (either in colour or in black-andwhite), the skilled user may identify a depth interval which contains high colour contrasts above around 6MRayl. This depth interval is likely to be a location 7 where the formation 2 is touching the pipe 3. This depth interval can be corroborated using other logging data. For instance, a CBL-VDL method can be used to check if the depth interval is a likely location where the formation 2 is in contact with the pipe 3.

In order to evaluate properties (such as dip and strike) of the formation 2 at the location 7 it touches the pipe 3, patterns (such as sinusoids) may be identified in the impedance map (particularly in the depth interval of interest). Patterns can be identified by the skilled user’s eye/brain and/or any borehole image software. The patterns can be interpreted using known techniques to give formation properties.

Further, in order to evaluate properties, the impedance map 20, 30, 40, 50 (particularly after it has been converted to black and white, and possibly after a depth interval of interest has been selected), can be used in combination with other information concerning the well (such as gamma logs, well construction knowledge, previous ultrasonic data, known/estimated cement information, seismic data, electromagnetic data, etc.). For instance, gamma logs can give indications of what materials are present outside of the pipe. Well construction knowledge and known/estimated cement information can give the skilled user of the impedance map some guidance as to where certain features of the impedance map originate.

Once formation properties have been evaluated at one time, they can be compared with formation properties evaluated at other times to evaluate formation creep. This comparison may be shown in a time-lapse series of images.

Claims

1. A method of evaluation of a formation outside of a pipe in a wellbore, wherein ultrasonic data gathered from within the pipe is provided, the method comprising using the ultrasonic data to evaluate the formation behind the pipe.

2. A method as claimed in claim 1, wherein the evaluation of the formation behind the pipe comprises obtaining stratigraphic information, dip information, strike information and/or creep evaluation.

3. A method as claimed in claim 1 or 2, wherein the outer surface of the pipe is in contact with one or more media, wherein the one or more media comprise the formation, wherein the ultrasonic data comprises an impedance map showing the various impedance values of said one or more media at respective locations within the borehole, wherein the impedance map comprises a colour scheme for showing said various impedance values, and wherein the method comprises using a colour scheme such that the impedance associated with the formation is distinguishable from the impedance associated with the other one or more media.

4. A method as claimed in claim 3, wherein the step of using a colour scheme such that the impedance associated with the formation is distinguishable from the impedance associated with the other one or more media comprises using a colour scheme such that a disproportionately large colour change occurs around a selected impedance value.

5. A method as claimed in claim 4, wherein the one or more media further comprises at least one other medium, wherein the at least one other medium comprises a medium that has an impedance lower than the impedance of the formation but higher than the impedance of any other medium that may be present, and wherein the selected impedance value is between the impedance value of the formation and the impedance value of the medium that has an impedance lower than the impedance of the formation but higher than the impedance of any other medium that may be present.

6. A method as claimed in claim 4 or 5, wherein the selected value is approximately between 5 to 7 MRayl, preferably approximately between 5.5 to 6.5 MRayl, preferably approximately 6 MRayl.

7. A method as claimed in any of claims 3 to 6, comprising using a colour scheme such that there is a disproportionately small colour change below a chosen impedance value, or removing the data from the map for impedance values below the chosen impedance value..

8. A method as claimed in claim 7, wherein the chosen impedance value is approximately between 3 to 5 MRayl, preferably approximately between 3.5 to 4.5 MRayl, preferably approximately 4 MRayl.

9. A method as claimed in claim 7 or 8, wherein the one or more media comprises at least one solid medium and at least one fluid medium, and wherein the chosen impedance value is approximately between the impedance value of the at least one solid medium and the at least one fluid medium.

10. A method as claimed in any of claims 3 to 9, wherein the impedance map is normalised such that the colour scheme of impedance map has an increased contrast.

11. A method as claimed in any of claims 3 to 10, wherein the colour scheme of the impedance map is converted to black and white.

12. A method as claimed in any of claims 3 to 11, comprising evaluating the formation by extracting information from patterns in the impedance map.

13. A method as claimed in any preceding claim, comprising using the ultrasonic data in combination with one or more other data sets to evaluate the formation.

14. A method of evaluating formation creep outside of a pipe in a wellbore, comprising performing any of the steps in any of claims 1 to 13.

15. A method as claimed in claim 14, comprising performing any of the methods of any of claims 1 to 13 at a first time to obtain a first evaluation of the formation; performing any of the methods of any of claims 1 to 13 at a second later time to obtain a second evaluation of the formation; and comparing the

-21 first and second evaluations of the formation to evaluate formation creep outside of the pipe.

16. A method as claimed in any preceding claim, comprising gathering the

5 ultrasonic data.

17. A computer program product comprising instructions that, when executed, will configure a computer apparatus to implement any of the methods of claims 1 to 15 and to display the impedance map on a monitor of the computer

10 apparatus.

18. A system for evaluation of a formation outside of a pipe in a wellbore comprising an ultrasonic logging tool for deployment within the pipe in order to

15 obtain ultrasonic data;

a processor arranged to perform any of the methods of claims 1 to 15; and a monitor for displaying the impedance map to a user of the system for evaluation of the formation.