GB2524810A

GB2524810A - Method of analysing a drill core sample

Info

Publication number: GB2524810A
Application number: GB1406039.6A
Authority: GB
Inventors: Brett Louis Clark; John Alexander Cumming Maitland; Ian Thomas Maurice Patey
Original assignee: Corex UK Ltd
Current assignee: Corex UK Ltd
Priority date: 2014-04-03
Filing date: 2014-04-03
Publication date: 2015-10-07
Anticipated expiration: 2034-04-03
Also published as: US20170108483A1; GB201406039D0; WO2015150825A1; GB2524810B; EP3126828A1; US10620181B2

Abstract

A method of analysing a subterranean drilled core sample comprises; providing a drill core sample taken from a formation; producing high-resolution data of at least a section of the sample; mimic wellbore operations using reservoir conditions core floods; producing high-resolution data of at least a section of the drill core sample; identifying and/or segregating one or more formation damage mechanisms; dividing the core sample into two or more sub-sampling sections; producing very high resolution data of one or more sub sampling sections;obtaining elemental analysis/chemical characterisation of a selected area of interest of at least two sub-sampling sections; and determining the effect of said formation damage mechanism on a characteristic of said drill core sample.

Description

METHOD OF ANALYSING A DRILL CORE SAMPLE

The present invention relates to a method of analysing a drill core sample, in particular, to a method of analysing a subterranean drilled core sample.

The invention also relates to a method of quantification of formation damage mechanisms in a subterranean drilled core sample and the effect of the formation damage mechanisms on a characteristic [e.g. the permeability) of the core sample.

In oil and gas weils, valuable hydrocarbons locked in an underground reservoir are recovered to surface by drilling a weilbore into the formation and flowing the production fluids containing the valuable hydrocarbons to the surface through production tubing. "Production fluids" is a term used to refer to all fluids flowing from a production zone in the formation, and while production fluids flowing into the wellbore from the formation will normally contain a high proportion of usable hydrocarbons, they will usually also contain less useful components, such as particulate material comprising fine particles of sand, rock and fines etc, which may be suspended in the production fluids.

The efficient recovery of hydrocarbons relies on an accurate prediction of the transport parameters of reservoir rocks, in particular permeability.

Permeability impairment caused by damaging mechanisms in the reservoir, for example during well operations, can have a significant impact upon productivity, in particular, hydrocarbon recovery. Operational decisions are often influenced by the results of reservoir conditions tests, for example coreflooding tests, which can be used to try and evaluate formation damage.

Formation damage testing is commonly used to gather information and aid in risk-reduction when making operational decisions. This is because the majority of damaging mechanisms can be simulated and replicated by performing reservoir conditions coreflooding tests.

Formation damage laboratory testing is widely used to help understand the potential impact on productivity or injectivity of wellbore operations.

Understanding what laboratory test results could mean in a field context is a key to reducing risk.

Interpretation of results has historically been dominated by taking permeability or pressure measurements at face value. The nature of laboratory testing means that it is a higher risk to rely on permeability and pressure measurements alone, so various geological techniques (including scanning electron microscopy and thin section) are used to gather additional information and aid interpretation. These geological techniques help reduce the inherent risk associated with upscaling from short core samples (including the potential for multiple mechanisms to be masking the potential for productivity impairment in the reservoir).

Examples of such techniques are disclosed in W02013/058672, W02013/169137, SPE 152640-PA: Permeability Upscaling for Carbonates From the Pore Scale by Use of Multiscale X-ray-CT Images', and SPE 165110-MS: Use of Micro-CT Scanning Visualisations To Improve Interpretation Of Formation Damage Laboratory Tests Including a Case Study From The South Morecambe Field'.

While the current techniques provide excellent high-resolution data, they are limited in terms of capturing the change throughout an entire core sample, particularly being able to capture the alterations and their distribution within samples.

Furthermore, permeability impairment is generally a result of a combination of formation damage mechanisms occurring during well operations. Current techniques are not able to segregate these formation damage mechanisms in order to measure permeability or determine their individual effects on the permeability.

Currently, there is no quantitative approach for estimating formation damage by making value-based measurements of damaging mechanisms. All known approaches are qualitative.

There is therefore a need for an improved method of analysing core samples that decreases risk in operational decision-making.

According to a first aspect, the present invention there is provided a method of analysing a subterranean drilled core sample, comprising the steps of a] providing a drill core sample taken from a subterranean formation; b] producing high resolution data of at least a section of the drill core samples c) mimic wellbore operations using reservoir conditions core floods; d) producing high-resolution data of at least a section of the drill core sample; e] identifying and/or segregating one or more formation damage mechanisms; and 0 determining the effect of said formation damage mechanism(s) on a characteristic of said drill core sample.

The present invention provides an innovative quantitative technique to identil' and segregate formation damaging mechanisms measuring permeability and/or further characteristics e.g. wettability or porosity of each core sample to allow the effects of any single or combination of formation damage mechanisms to be clearly understood.

The present invention also provides an improved analysis technique which overcomes the inability to separate and quantify the observed damaging mechanisms) as well as providing a novel value-based technique for improving hydrocarbon recovery and reduced risk decision-making for field operations.

The method in accordance with the invention uniquely utilises a combination of laboratory data with tools thus allowing visualisation of both the distribution and nature of damaging mechanisms. As a result, laboratory data is made more valuable and therefore decreases risk in operational decision-making Preferably, step b) and/or step d) comprises producing high resolution data of the entire drill core sample.

Preferably, step f) comprises determining the effect of said formation damage mechanism(s) on the permeability of the drill core sample.

The determining step I) may further comprise calculating a volume change in said drill core sample caused by each of the one or more formation damage mechanisms.

In exemplary embodiments, the determining step fl further comprises calculating a volume change in said drill core sample caused by a combination of different formation damage mechanisms.

Preferably, the method further comprises the step of segmenting said one or more formation damage mechanisms. The method may further comprise generating individual or combinations of 3D skeletons representing formation damage mechanism(s), grain(s) and pore space(s) by segmentation.

In exemplary embodiments, the determining step f) comprises calculating the percentage volume of each formation damage mechanism.

The formation damage mechanism may include fines accumulation and/or drilling solid retention.

In exemplary embodiments, the determining step 0 further comprises:-i) dividing the core sample into two or more sub-sampling sections, ii) producing very high resolution, and more preferably, at a higher resolution than the said high resolution utilised in either or both of steps b) and/or d), data of one or more sub-sampling sections, and Hi) obtaining elemental analysis/chemical characterization of a selected area of interest of each sub-sampling section.

Preferably, the core sample is divided into a plurality (such as 12-16) of sub-sampling sections.

Preferably, the high resolution data of step b) and/or step d) and the higher resolution data of step fl is produced by a suitable 3D dataset acquisition method for example but not limited to nano CT scanning, XRM, FIB, micro CT scanning or synchnotron analysis.

The elemental analysis/chemical characterization of step f) Hi) maybe obtained by a Focussed Ion Beam Scanning Electron Microscope [FIB-SEM] used in combination with an Energy-dispersive X-ray Spectroscopy device (EDS). This allows a user such as a consultant to acquire a chemical element map of an area of interest selected and therefore identifr the formation damage mechanisms present.

Preferably, features of the sub-sampling sections in the very high resolution data of step 0 ii] and features of the sub-sampling section obtained from data derived from the elemental analysis/chemical characterization of step fJ Hi) are matched via registration or point matching.

In exemplary embodiments, the method further comprising the step of extrapolating the formation damaging mechanisms captured in the FIB-SEM/EDS selected area of interest to have similar occurrences rendered elsewhere throughout the core sample dataset Preferably, step cJ comprises mimicking (e.g. attempting to simulate) reservoir conditions by means of a test conducted on the core sample, for example a coreflooding test In embodiments wherein step c) comprises a reservoir conditions test, high resolution data of the entire drill core sample is produced (prior to the reservoir conditions test of step c]) at step b] in order to produce before test data sets and/or scans.

One or more high resolution after test data sets and/or scans of the entire drill core sample may be produced at step d) (after the reservoir conditions test of step c)J and may be further additionally produced during various further stages of the test sequence depending on objectives in order to produce one or more after test data sets and/or scans as part of step e).

Preferably, change maps are generated to facilitate the identification and/or segregation of one or more formation damage mechanisms in step e).

Preferably the process of generating the change maps comprises the following steps: -overlaying and aligning the before and after test data sets; -pointwise intensity subtraction of the after test data sets from the before test data sets; -change map image processing to produce a change map; and -quantification of the data and change map.

Preferably the change map image processing step comprises processing change intensity data obtained from the pointwise intensity subtraction step to produce the change map. Optionally, positive and negative change intensi can be separated in the change map.

Preferably, the quantification of the data and change map comprises the creation of a new data set using a binerization function. The binerization function conveniently attributes a value of 1 to both high and low intensity changes and attributes a value of 0 for no change. In this way, all change within the sample will be accounted for.

According to a second aspect, there is provided a method of quantification of formation damage mechanisms in a subterranean drilled core sample and the effect of the formation damage mechanisms on the characteristics (e.g. permeability) of the core sample comprising the steps of ana'ysing a subterranean drilled core sample in accordance with the first aspect.

According to a third aspect, there is provided a database on formation damage mechanisms comprising a list of formation damage mechanisms and their effect on an analysed subterranean drilled core sample populated by data obtained by the method according to the first aspect.

In exemplary embodiments, the database further comprises a list of at least one compound characteristic(s) (e.g. permeability) impairment mechanism and the effect of the at least one compound characteristic(s) (e.g. permeability) impairment mechanism on an analysed subterranean drilled core sample, wherein the at least one compound characteristic(s) (e.g. permeability) mechanism comprises at least two different formation damage mechanisms and the list is populated by data obtained by the method according to the first aspect.

The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one aspect can typically be combined alone or together with other features in different aspects of the invention.

Various aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary aspects and imp'ementations. The invention is also capable of other and different examples and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention. Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope.

Language such as "including" "comprising," "having," "containing" or "involving" and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes.

Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the fieki relevant to the present invention.

In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitional phrases "consisting essentially of", "consisting", "selected from the group of consisting or, "including", or "is" preceding the recitation of the composition) element or group of elements and vice versa.

All numerica' values in this disclosure are understood as being modified by "about".

All singular forms of elements, or any other components described herein are understood to include plural forms thereof and vice versa. References to directional and positional descriptions such as upper and lower and directions e.g. "Up", "down" etc. are to be interpreted by a skilled reader in the context of the examples described and are not to be interpreted as necessarily limiting the invention to the literal interpretation of the term, but instead shoukl be as understood by the skilled addressee.

The following definitions will be followed in the specification. As used herein, the term "weilbore" refers to a weilbore or borehole being provided or drilled in a manner known to those skilled in the art The wellbore may be open hole' or cased', being lined with a tubular string. Reference to up or down will be made for purposes of description with the terms "above", "up", "upward", "upper", or upstream" meaning away from the bottom of the wellbore along the longitudinal axis of a work string and "below", "down", "downward", "lower", or "downstream" meaning toward the bottom of the wellbore along the longitudinal axis of the work string. Similarly work string' refers to any tubular arrangement for conveying fluids and/or tools from a surface into a wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

A detailed description of certain examples of the present invention follows, with reference to the attached drawings, wherein: Figures 1 schematically illustrates where a test core sample may be plugged (obtained) from a reservoir interval; Figure 2 schematically illustrates the alignment of the before and after test data after registration; Figure 3 schematically illustrates an example of corresponding features of a core sample in before and after test data sets produced by e.g. XRM or nano CT or FIB or micro CT or synchnotron analysis; Figure 4 schematically illustrates the registration of before and after test nano-CT data sets; Figure 5 schematically illustrates an example of a nano-CT scan data set where an area has been sub-selected for more detailed analysis; Figure 6 schematically illustrates a nano-CT change map; Figure 7 schematically illustrates a positive change representative graph of the change map of figure 6; Figure 8 schematically illustrates a negative change representative graph of the change map of figure 6; Figure 9 schematically illustrates a volumetric representation of the new data set created for positive change (e.g. pore restricting flow reducing formation damaging mechanisms]; Figure 10 schematically illustrates the marking of a core sample into an appropriate number of sub-selected samples; Figure 11 schematically illustrates an example of a nano-CT scan image depicting detrital grains (8km voxel size]; Figure 12 schematically illustrates an example of high resolution 500x magnification SEM image region and registered region of nano-CT 3D image; Figure 13 schematically illustrates an example of filtering and boundary interfacing via watershedding'; Figure 14 shows a schematic diagram that illustrates the result of watershed segmentation'; Figure 15 schematically illustrates an example of fluid flow through a porous medium depicting the technique used to measure the characteristics (e.g. permeability] of a porous medium; Figure 16 schematically illustrates the effects on characteristics (e.g. permeability] by the presence of formation damaging mechanisms; Figure 17(a) schematically illustrates a 3D representation of the positive change produced during stage 2.3; and Figure 17(b) schematically illustrates a 3D representation of the negative change produced during stage 2.3.

DETAILED DESCRIPTION

A method of analysing a subterranean drilled core sample 10 (hereinafter referred to as the core sample'] for the quantification of formation damage mechanisms 12 in the core sample 10 and the effect of the formation damage mechanisms 12 on the characteristics (e.g. permeability] of the core sample 10 in accordance with the invention will be described with reference to the figures.

Prior to following the method in accordance with the present invention, a core sample 10 is obtained from a subterranean formation 2.

The exemplary method in accordance with the present invention comprises the primary steps of: a) providing a core sample 10 taken from a subterranean formation 2; b) producing high res&ution data of at least a section of the core samp'e 10, and preferably the whole core sample 10 (to provide a before test data set); c) mimic wellbore operation using reservoir conditions core flooding or other

suitable test;

d) producing high-resolution data of at least a section of the core sample 10, and preferably the whole core sample 10 (to produce an after test data set); e) identifying and/or segregating one or more formation damage mechanisms 12; and 0 determining the effect of said formation damage mechanism(s) 12 on a characteristic of said core sample 12.

The characteristic of the core sample 12 is for example one or more characteristic(s) (e.g. permeability) of the core sample 12 but may be another characteristic of the core sample 12 such as wettability or porosity but not limited to those.

The core sample 10 will be obtained from a subterranean formation 2 in the form of a section of the reservoir rock (usually the hydrocarbon recovery interval/zone or hydrocarbon bearing zone). The core sample 10 is a cylinder which is normally in the region of 1 inch (2.54 cm) or 1.5 inches (3.81 cm) in diameter and up to 4 cm in length but other sizes of core samples 10 can be obtained and used. Figure 1 shows an example of where a test core sample 10 may be plugged (obtained) from a reservoir interval 2.

The method of obtaining of a test core sample from a subterranean formation is typically achieved by using a conventional core barrel tool (not shown) at the lower end of a drill string run from the surface of a well using known techniques and is therefore generally known to the skilled person and as such will not be described in any further detail.

It would be understood that the core sample 10 may be of a different size, shape or dimension to that described above.

Extra geological analyses material is taken from the same depth as the core sample for petrographic characterisation when the core sample obtained. The petrographic characterisation consists of X-ray diffraction (XRD] and/or scanning electron microscopy (SEM) analysis and/or other suitable petrographic or biological characterising analysis techniques. The petrographic or biological characterisation may be performed prior to (for example with a handheld to5l or downhole tool included in the string with the core barrel and operated as the core sample 10 is taken or cut from the reservoir or just after) or during (e.g. in the laboratory) one of the main stages of investigating the effect of the formation damage mechanisms 12 on the characteristics (e.g. permeability) of the core sample 10 in the method in accordance with the invention.

The XRD and SEM analysis will allow a consultant (who maybe for example, but not limited to, a geologist or micro-biologist or chemist) making the investigation to assess the minerals and clays present in the core sample 10.

The main stages of investigating the effect of the formation damage mechanisms 12 on the characteristics (e.g. permeability) of the core sample 10 in the method in accordance with the invention will now be described.

Stage 1 -Core preparation and reservoir conditions tests (in accordance with steps a to dfl Once the core sample 10 has been obtained [in accordance with step a)], the first stage of the investigation begins with preparing the core sample 10 for testing.

The core sample 10 is cleaned and re-prepared to a base line saturation profile using brine, oil or gas phase that is representative of the reservoir.

The core sample 10 is then stored at an appropriation temperature depending on the test phases, ageing may be undertaking to improve the conditioning of the core sample 10 to initial wellbore saturation.

The bulk test core sample 10 is then scanned by a suitable 3D dataset acquisition technique such as for example, but not limited to, nano-CT scanning, XRM, FIB, micro CT scanning or synchnotron analysis, before testing begins in order to produce before test 3D data set acquisition technique scans [B) [in accordance with step b)). Bulk volume scans will vary in resolution depending on core sample size but will usually be able to discern particle sizes down to a range between 18-26Rm [with e.g. nano CT although it should be noted that XRM can with present day [i.e.

calendar year 2014) technolo discern particle sizes down to a range of 2.5 to 26 m and it is likely that future technolow advancements will discern even lower particle sizes and therefore perform higher resolution scans) and therefore provides a high resolution scan.

The laboratory reservoir conditions test can now begin [in accordance with step c]).

Testing of core samples 10 will mimic well operations e.g. fluid sequence applications and clean up) as well as any production and/or injection stages. The performance of the laboratory reservoir conditions test may be in accordance with any of the currently known methods) a common conditions test being for example a coreflooding test.

The core sample 10 can be offloaded at specific stages during the mimicking of well operations to be scanned by a suitable 3D dataset acquisition technique to thereby provide one or more after test scans [A) (in accordance with step d]]. This can be done multiple times during various stages of the test sequence depending on the objectives. These after test 3D dataset acquisition technique scans [A) alongside the before test 3D dataset acquisition technique scans (B) made prior to simulating weilbore operations are processed using 3D imaging/image processing software capable of data visualization and analysis. The 3D imaging/image processing software maybe an off the shelf software package available to the skilled person for example an Avizo ® software package or a specially developed and suitable software package.

Stage 2 -Chance Mapping with 3D dataset acquisition techniuue bulk sample scans (in accordance with steo eli The 3D dataset acquisition technique data sets 14 obtained from the before test (B) and from each after test [A] 3D dataset acquisition technique scan conducted during stage 1 as outlined above are uploaded into the 3D image processing software and orthoslices can be used to view each data set. Figure 2 depicts an example of a before test (B) scan slice 14B with an intersecting after test [A] scan slice 14A (this includes the well operations deposited cake 22 and body at the top of the sample 10).

Change maps (C) are generated by taking the after test (A) 3D dataset acquisition technique scans and subtracting the before test (B) 3D dataset acquisition technique scans (i.e. A-B=C).

The process of generating the change maps are outlined in more detail by the four stages listed below: 2.1 -Registration (overlaying and aligning the before and after test data sets) 2.2 -Arithmetic (Pointwise intensity subtraction) [A-Bj 2.3 -Change map image processing [Cj 2.4 -Quantification 2.1 Registration stage:-Both the before (B) and after (A) test 3D dataset acquisition technique data sets 14 have to be aligned together, such that the after test (A) 3D dataset acquisition technique data set 14A moves along the X, Y and Z axis into alignment with the before test (B) 3D dataset acquisition technique data set 14B. All grains 20, clays and cements are aligned together, between both 3D dataset acquisition technique data sets 14. See figure 3 for an example of corresponding features that are misaligned, which need to be corrected; this is done by registration.

The registration function is accomplished by having the after test (A) 3D dataset acquisition technique data set 14A registered to the before test (B) data set 14B. In simple terms the before test (B) 3D dataset acquisition technique data set 14B remains still and the after test (A) 3D dataset acquisition technique data set 14A moves, and as such the after test (A) data set 14A is aligned to the before test data (B) data set 14B.

An illustration is depicted in figure 4 to show how registration works; black blobs represent high intensity grains/minerals 20 in the before test (B) data set 14B and white blobs represent high intensity grains/minera's 20 in the after test (A) data set 14A. The picture to the right shows grains/minerals are now aligned.

Registration is a very important stage in the process of generating the change maps as it ensures when the arithmetic (pointwise intensity subtraction) is calculated, the result will only show the change that has occurred because of the well operations and not due to grain/mineral misalignment.

2.2 Arithmetic stage:-The concept is A-B=C, in simple terms After minus Before equals Change.

This arithmetic function identifies all the changes from formation damaging mechanisms 12 caused during the above mentioned tests (for example the coreflooding tests). Density alterations are made apparent by the difference between the A and B data sets 14A,14B. Density alterations are typically caused by welibore operations solids or weilbore operations filtrate retention. These formation damage mechanisms 12 can alter the pore network volume and this is indicated by density alterations (e.g. between the positive and negative changes).

The output created as part of the arithmetic function is a new data set which can be used to show change intensity. Change intensity is based on density alteration.

Small alterations in density mean low change intensity and large alterations in density mean high change intensity.

2.3 Change map image processing:-This stage involves processing the change intensity data to display a 3D volume representation of all the change that has occurred. Positive and negative change intensity can be separated as seen in the change map 24 shown in figure 6 (which includes examples of potential formation damage mechanisms that could cause the positive and negative change depicted).

Positive change which occurs as a result of pore restricting/flow reducing mechanism(s) could be due to solids and/or operational fluid invasion, clay fines deposition or precipitation due to a fluid incompatibility. Negative change which occurs as a result of pore enlarging/flow enhancing mechanism(s) could be due to clay fines removal and/or dissolution of native reservoir rock.

The change maps created are used to find specific areas of change that are of particular interest to the consultant at the up-scaling stage later on in the investigation (see Stage 3 for more detail).

Positive change can be displayed by adjusting the threshold value (e.g. 36-130 along the X axis in the graph shown in Figure 7) allowing a 3D representation to be produced as shown in Figure 17(a). Threshold ranges vary from sample to sample because of the different density ranges e.g. some samples are denser than others.

Negative change can be obtained by inverting the change intensity spectrum allowing the consultant to adjust the threshold (e.g. 367-187 along the X axis in the graph shown in Figure 8) aflowing a 3D representation to be produced (as shown in Figure 17(b)).

The change maps 24 created can then be quantified once the consultant is happy with the threshold values when further quality checks are made.

2.4 Quantification:-This final stage involves calculating the total percentage of change regardless of intensity within a selected sub sample 101 to 116 and/or whole sample 10.

To allow the software to measure the change as a volume against the total volume of the selected sub sample and/or whole sample, a new data set is created using the binerization function.

The change map 24 can be binerized to create a new data set from the threshold values above. When the change intensity data sets (positive change and negative change) are binerized both high and low intensity changes are attributed with a value of 1 and for no change attributed with a value of 0, meaning all change within the sample is accounted for. Figure 9 shows a binerized data set for positive change (e.g. pore restricting flow reducing formation damaging mechanisms 12).

Once the new (binerized) data sets are created (positive change volume and negative change volume), the volume change percentage can be calculated. This is done using a function included with the imaging software which provides a volume for the change along with a whole volume. This means two separate change percentages can be created for positive and negative along with a total change percentage.

The positive and negative change volumes obtained at this point can be revisited at a later stage by the consultant at the up-scaling stage of the investigation. This will involve sub-dividing the positive and negative change volumes into individual formation damage volumes (see Stage 3 for more detail), which can then be quantified as a percentage in order to determine the effect of the individual formation damage mechanisms 12.

Stage 3 -Determining the effect of formation damaging mechanisms by quantification of formation damage mechanisms and their effect on the characteristics leg. permeability) of a core sample The procedure for quantification of formation damage mechanism 12 and their effect on the characteristics (e.g. permeability) of the core sample 10 are outlined in more detail by the four stages listed below: 3.1 -Sub-sampling selected sub-samples from core sample 3.2 -Very high resolution 3D dataset acquisition technique scanning of sub-samples and elemental analysis/chemical characterization of selected areas of interest 3.3 -Registration of datasets 3.4 -Generating a metrics database of the formation damaging mechanisms 3.1 Sub-sampling selected sub-samples from core sample for high resolution 3D dataset acquisition technique scanning Following creation of the 3D change map, the consultant selects an appropriate number of sub-selected samples from within the core sample (from this point forward the sub-selected samples are described as cubes' although it is important to note that they need not be cube shaped but could be any suitable size and/or shape), and records the co-ordinates of the sub-selected cubes' that will be used to obtain even higher resolution datasets as will be subsequently described at stage 3.2.

Conveniently, 12-16 cubes' are allocated from the core sample 10 to be sub-sampled and sixteen are provided in the embodiment as shown in Figure 10 as cubes 101 to 116 (cubes 106 to 108 and cubes 114 to 116 being hidden from view).

It would be understood that the number of cubes' allocated is dependent on the size of the core sample 10.

The cubes' 101 to 116 are then either:-a) physically cut from the core sample 10 using a core cutting tool into the allocated number of cubes' 101 to 116 from the exact locations co-ordinated (see figure 10) if for example a nano CT scan is conducted; or b) selected as a zone of interest within the core sample 10 with the exact location being recorded if for example an XRM scan is conducted (in other words no physical cube need be cut but the scanning tool can zoom or zone in on the cube 101 to 116) whilst it is still an integral part of the core sample 10.

3.2 Very high resolution 3D dataset acquisition technique scanning of sub-sampled cubes' and elemental analysis/chemical characterization of selected areas of interest Very high resolution 3D dataset acquisition technique scan datasets of each cube' are then obtained using a 3D dataset acquisition technique scanner, the very high resolution being an even higher resolution than that used in Stage 1 as described above.

The newly acquired datasets are then uploaded into a super-computer (not shown) and using a 3D image processing software, each very high resolution dataset (down to -8i.tm voxel size and preferably in the range of 0.SRm to brim voxel size for nano CT and between 0.lrim to Srim for an XRM scan depending on the size of the zone of interest chosen is reviewed in order to carefully select an area of the respective cube' for elemental analysis/chemical characterization. Figure 5 depicts an example of a 3D dataset acquisition technique scan data set 14 where an area 16 has been sub-selected for more detailed analysis.

The elemental analysis/chemical characterization may for example be performed by means of a Focus Ion Beam [FIB) device, a Scanning Electron Microscope (SEM) and/or an Energy-dispersive X-ray Spectroscopy (EDS) device. Preferably a Focussed Ion Beam Scanning Electron Microscope (FIB-SEM) is used in combination with an EDS device.

One area of interest is selected from each cube' 101 to 116 throughout the core sample (12-16 areas of interest in total). The co-ordinates of each area of interest is recorded at this stage to allow the consultant to register the FIB-SEM dataset with the corresponding cube' very high resolution 3D dataset acquisition technique scan dataset.

The selected areas of interest will then be analysed under the FIB-SEM/EDS instruments to allow even higher [i.e. ultra high) resolution imagery such as 0.001km to 0.5km (and preferably around 0.06km but further technical improvements in scanning techniques in future could allow even higher resolution than that) of a small stack of images and allow identification of the formation damaging mechanisms 12 (in accordance with step e)) that have occurred within the core sample 10 as a result of the well operations test sequence (for example the coreflooding tests hereinbefore described during stage 1 and which were in accordance with step c)).

The FIB-SEM/EDS technique enables the consultant to acquire a chemical element map of the area of interest selected therefore identifying the formation damage mechanisms present.

This stage can generate individual or combinations of 3D skeletons representing formation damage mechanism(s), grain(s) and pore space(s) by segmentation (watershedding).

3.3 Registration of FIB-SEM/EDS and 3D dataset acquisition technique scan datasets Following acquisition of the FIB-SEM/EDS chemical element maps from each area of interest, these high resolution datasets are uploaded to the 3D image processing software along with the corresponding dataset of the very high resolution cube' 3D dataset acquisition technique scan.

The software needs to be capable of reading any binary volume of data. The software will register the two datasets before further processing is performed. This involves fine tuning functions for filtering and boundary interfacing via watershedding'.

A materials structure imaging tool within the software or a 3D visualization and analysis software for exploring core sample 10 and digital rock data sets, for example Avizo ® Fire, will be used for upscaling to extrapolate the formation damaging mechanisms 12 captured in the FIB-SEM/EDS small area of interest to have similar occurrences rendered elsewhere throughout the remainder of the corresponding 3D cube' dataset.

Figure 12a illustrates an example of an ultra high resolution SOOx magnification SEM image region and Figure 12b illustrates a registered region of a 3D scanned image.

Figure 13 illustrates an example of filtering and boundary interfacing via watershedding' which allows for upscaling to extrapolate the formation damaging mechanisms 12 captured in the FIB-SEM/EDS small area of interest (Figure 13a -before watershedding'; figure 13b -after watershedding').

3.4 Generating a metrics database of the formation damaging mechanisms for the core sample Once the formation damage mechanisms 12 have been rendered throughout each cubed' dataset (watershedding' complete), the consultant can use the software to calculate the percentage volume of each formation damage mechanism 12, for example fines accumulation, drilling solid retention.

For each cube' 101 to 116, a table can be populated that lists the formation damage mechanisms 12 and the percentage volume change. This generates a database for all the cubes' 101 to 116. From this database any query can be executed e.g. grouping the percentage volume of clay fines migration from each cube' 101 to 116.

Figure 14 shows a schematic diagram that illustrates the result of watershed segmentation' which allows for quantification of the separate phases.

Further value to the database on formation damage mechanisms 12 may be added by generating additional characteristics (e.g. permeability) metrics as described below.

Using a software package capable of performing numerical simulations from calculated characteristics [e.g. permeability] of a porous media from a scanned core sample 10, for example Avizo ® XLab Hydro extension, the consultant can generate characteristics (e.g. permeability) metrics on each cube' 101 to 116. Figure 15 shows an example of fluid flow through a porous medium depicting the technique used to measure the characteristics (e.g. permeability) of a porous medium.

The algorithm used in the software should be Darcy's Law which is the industry standard algorithm for measuring permeability. This initial permeability metric is generated with all formation damaging mechanisms 12 present in the first cube' 101. For each cube' 101 to 116 the consultant or software user will then mask/threshold out some of the formation damaging mechanisms 12 so that the permeability can be measured with only individual or combinations of formation damaging mechanisms 12 present. All permeability metrics can then be added to the metrics database on formation damage mechanisms 12 which presents the option of performing queries to group selected formation damage mechanisms 12 or permeabilities.

Figure 16 shows the simuktion of characteristics (e.g. permeability) measurements of individual damaging mechanisms 12 with (a) no damaging mechanisms present, (bJ clay fines migration only, and [cJ fluid retention only.

Following construction of a database and use of subsequent queries, a consultant may choose to rank variables e.g., fluid products or fluid sequence applications based on either the total v&ume of formation damage mechanisms 12 and/or characteristics (e.g. permeability). The consultant can then use this database to see how much of an influence each formation damage mechanism 12 has on the characteristics [e.g. permeability) (in accordance with step fl). For example; the effect on the characteristics (e.g. permeability) of pore restricting clay fines migration or separately pore enlarging clay fines migration could be reviewed. The following decisions could thus be made based on the query findings: a) Use new welibore operations; b) Modi!wellbore operations; c] Not perform wellbore operations (terminating]; d) Take no action and continue as planned.

Below is an example (non-exclusive) list of formation damage mechanisms 12 that may be recorded in the database: i) Fines migration [e.g. clays, precipitates, plankton debris, microbes, polymers); ii) Dissolution of minera' matrix and cavitations/collapse of formation or pore volume compaction; Hi] Wellbore Operation Fluids invasion with subsequent retention (i.e., solids entrapment and/or filtrate retention); iv) Phase entrapment (i.e., polymer adsorption onto the skeletal grains reducing pore volume); v] Precipitates (organic and/or inorganic from either fluid/fluid and/or fluid/fluid/rock interactions -Porefluids and Injected fluids); vi] Emulsions; vii) Asphaltenes deposition; viii) Wax deposition; ix] Bacterial fouling and cell growth; etc..

It is apparent that embodiments of the present the invention, as described above, also advantageously provide a method of quantification of formation damage mechanisms in a subterranean drilled core sample and the effect of the formation damage mechanisms on the characteristics (e.g. permeability] of the core sample 10.

It has been found that the most significant gains in terms of risk-reduction come when an "integrated approach" is taken, i.e.: - -design tests that are an accurate simubtion of the operations or conditions under consideration; -perform the testing, gathering data which pica11y consists of characteristics (e.g. permeability] measurements, pressure measurements, and sample images; and -understand laboratory test results through quantitative interpretative analysis that allows alterations in the samples to be put in context and

conclusions/recommendations made.

Modifications and improvements may be made to the embodiments hereinbefore described without departing from the scope of protection.

Claims

CLAIMS1. A method of analysing a subterranean drilled core sample, comprising the steps of a) providing a drill core sample taken from a subterranean formation; b] producing high-resolution data of at least a section of the drill core sample; c) mimic welibore operations using reservoir conditions core floods; d] producing high-resolution data of at least a section of the drill core sample; e] identil'ing and/or segregating one or more formation damage mechanisms; and I) determining the effect of said formation damage mechanism(s) on a characteristic of said drill core sample.
2. A method according to claim 1, wherein step b) and/or step d)comprises 15 producing high resolution data of the entire drill core sample.
3. A method according to claim 1 or claim 2, wherein step I] comprises determining the effect of said formation damage mechanism(s) on the effective permeability of the drill core sample.
4. A method according to claim 3, wherein said determining step fl further comprises calculating a volume change in said drill core sample caused by each of the one or more formation damage mechanisms.
5. A method according to claims 3 or 4, wherein said determining step I) further comprises calculating a volume change in said drill core sample caused by a combination of different formation damage mechanisms.
6. A method according to any one of the preceding claims, further comprising the step of segmenting said one or more formation damage mechanisms.
7. A method according to claim 6, further comprising generating individual or combinations of 3D skeletons representing formation damage mechanism(s), grain(s) and pore space(s) by segmentation.
8. A method according to any one of the preceding steps, wherein said determining step fl further comprises calculating the percentage volume of each formation damage mechanism.
9. A method according to claim 8, wherein the formation damage mechanism includes fines accumulation and/or drilling solid retention.
10. A method according to any one of the preceding claims, wherein said determining step fl further comprises:-fl dividing the core sample into two or more sub-sampling sections, 15 H) producing very high resolution data resolution of one or more sub-sampling sections, and Hi) obtaining elemental analysis/chemical characterization of a selected area of interest of each sub-sampling section.
11. A method according to claim 10, wherein the very high resolution data comprises a higher resolution than said high-resolution utilised in either or both of stepsb] and/ord].
12. A method according to claim 10 or claim 11, wherein the core sample is divided into 12-16 sub-sampling sections.
13. A method according to any one of the preceding claims, wherein the high resolution data of step b) and/or step d) is produced by a suitable 3D dataset acquisition method.
14. A method according to claim 11 or any claim directly or indirectly dependent on claim 11, wherein the higher resolution data of step fl is produced by a suitable 3D dataset acquisition method.
15. A method according to claim 13 or claim 14, wherein the 3D dataset acquisition method comprises nano CT scanning XRM, FIB, micro CT scanning or synchnotron analysis.
16. A method according to claim 10 or any claim directly or indirectly dependent on claim 10, wherein the elemental analysis/chemical characterization of step I] iii) is obtained by a Focussed Ion Beam Scanning Electron Microscope (FIB-SEM) used in combination with an Energy-dispersive X-ray Spectroscopy device (EDS).
17. A method according to claim 10 or any claim directly or indirectly dependent "f 15 on claim 10, wherein features of the sub-sampling sections in the very high resolution data of step I') ii) and features of the sub-sampling section obtained from data derived from the elemental analysis/chemical characterization of step I) Hi) are matched via registration or point matching.
18. A method according to claim 16 or any claim directly or indirectly dependent on claim 16, further comprising the step of extrapolating the formation damaging mechanisms captured in the FIB-SEM/EDS selected area of interest to have similar occurrences rendered elsewhere throughout the core sample dataset.
19. A method according to any one of the preceding claims) wherein step c) comprises mimicking reservoir conditions by means of a test conducted on the core sample.
20. A method according to claim 19, wherein the test conducted on the core sample is a coreflooding test.
21. A method according to claim 19 or claim 20, wherein high resolution data of the entire drill core sample is produced prior to the reservoir conditions test of step cJ at step bJ in order to produce before test data sets and/or scans.
22. A method according to any one of claims 19 to 21, wherein one or more high resolution after test data sets and/or scans of the entire drill core sample are produced at step d) after the reservoir conditions test of step c).
23. A method according to claim 22, wherein after high resolution after test data sets and/or scans are further additionally produced during various further stages of the test sequence depending on objectives in order to produce one or more after test data sets and/or scans as part of step e].
24. A method according to claim 22 or claim 23, wherein change maps are 15 generated to facilitate the identification and/or segregation of one or more formation damage mechanisms in step e).

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25. A method according to claim 24, wherein the process of generating the change maps comprises the following steps: -overlaying and aligning the before and after test data sets; -pointwise intensity subtraction of the after test data sets from the before test data sets; -change map image processing to produce a change map; and -quantification of the data and change map.
26. A method according to claim 25, wherein the change map image processing step comprises processing change intensity data obtained from the pointwise intensity subtraction step to produce the change map.
27. A method according to claim 27, wherein positive and negative change intensity are separated in the change map.
28. A method according to any one of claims 25 to 27, wherein the quantification of the data and change map comprises the creation of a new data set using a binerization function.
29. A method of quantification of formation damage mechanisms in a subterranean drilled core sample and the effect of the formation damage mechanisms on the characteristics of the core sample comprising the steps of analysing a subterranean drilled core sample in accordance with any one of claims 1 to 28.
30. A method according to claim 29, wherein the characteristics of the core sample includes the permeability of the core sample.
31. A database on formation damage mechanisms comprising a list of formation 15 damage mechanisms and their effect on an analysed subterranean drilled core sample populated by data obtained by the method according to any one of claims 1 to 28.
32. A database according to claim 31, further comprising a list of at least one compound characteristic(s) impairment mechanism and the effect of the at least one compound characteristic(s) impairment mechanism on an analysed subterranean drilled core sample, wherein the at least one compound characteristic(s) mechanism comprises at least two different formation damage mechanisms and the list is populated by data obtained by the method according to any one of claims 1 to 28.
33. A database according to claim 32, wherein the at least one compound characteristic(s) impairment mechanism includes a compound permeability impairment mechanism.Amendments to the claims have been made as follows:CLAIMS1. A method of analysing a subterranean drilled core sample, comprising the steps of a) providing a drill core sample taken from a subterranean formation; b) producing high-resolution data of at least a section of the drill core sample; c] mimic wellbore operations using reservoir conditions core floods; d) producing high-resolution data of at least a section of the drill core sample; e) identifying and/or segregating one or more formation damage mechanisms; and f) i) dividing the core sample into two or more sub-sampling sections, ii) producing very high resolution data of one or more sub-sampling 15 sections, and Hi) obtaining elemental analysis/chemical characterization of a selected r area of interest of at least two of the sub-sampling sections, and iv) determining the effect of said formation damage mechanism(s) on a characteristic of said drill core sample.2. A method according to claim 1, wherein step b) and/or step d)comprises producing high resolution data of the entire drill core samp'e.3. A method according to claim 1 or claim 2, wherein step f) comprises determining the effect of said formation damage mechanism(s) on the effective permeability of the drill core sample.4. A method according to claim 3, wherein said determining step f) further comprises calculating a volume change in said drill core sample caused by each of the one or more formation damage mechanisms.5. A method according to claims 3 or 4, wherein said determining step fl further comprises calculating a volume change in said drill core samp'e caused by a combination of different formation damage mechanisms.6. A method according to any one of the preceding claims, further comprising the step of segmenting said one or more formation damage mechanisms.7. A method according to claim 6, further comprising generating individual or combinations of 3D skeletons representing formation damage mechanism(s), grain(s) and pore space(s) by segmentation.8. A method according to any one of the preceding steps, wherein said determining step 1') further comprises calculating the percentage volume of each formation damage mechanism.9. A method according to claim 8, wherein the formation damage mechanism r includes fines accumulation and/or drilling solid retention. rZt 10. A method according to any preceding claim, wherein the very high resolution data comprises a higher resolution than said high-resolution utilised in either or both of steps b) and/or d).11. A method according to any preceding claim, wherein the core sample is divided into 12-16 sub-sampling sections.12. A method according to any one of the preceding claims) wherein the high resolution data of step b) and/or step dJ is produced by a suitable 3D dataset acquisition method.13. A method according to claim 10 or any claim directly or indirectly dependent on claim 10, wherein the higher resolution data of step fJ is produced by a suitable 3D dataset acquisition method.14. A method according to claim 12 or claim 13, wherein the 3D dataset acquisition method comprises nano CT scanning, XRM, FIB, micro CT scanning or synchnotron analysis.15. A method according to any preceding claim, wherein the elemental analysis/chemical characterization of step I] iii) is obtained by a Focussed Ion Beam Scanning Electron Microscope (FIB-SEM) used in combination with an Energy-dispersive X-ray Spectroscopy device (ED 5).16. A method according to any preceding claim, wherein features of the sub-sampling sections in the very high resolution data of step flH) and features of the sub-sampling section obtained from data derived from the elemental analysis/chemical characterization of step f) iii) are matched via registration or f 15 point matching.r 17. A method according to claim 15 or claim 16, further comprising the step of extrapolating the formation damaging mechanisms captured in the FIB-SEM/EDS selected area of interest to have similar occurrences rendered elsewhere throughout the core sample dataset.18. A method according to any one of the preceding claims, wherein step c) comprises mimicking reservoir conditions by means of a test conducted on the core sample.19. A method according to claim 18, wherein the test conducted on the core sample is a coreflooding test.20. A method according to claim 18 or claim 19, wherein high resolution data of the entire drill core sample is produced prior to the reservoir conditions test of step c] at step b) in order to produce before test data sets and/or scans.21. A method according to any one of claims 18 to 20, wherein one or more high resolution after test data sets and/or scans of the entire drill core sample are produced at step d] after the reservoir conditions test of step c].22. A method according to claim 21, wherein after high resolution after test data sets and/or scans are further additionally produced during various further stages of the test sequence depending on objectives in order to produce one or more after test data sets and/or scans as part of step e).23. A method according to daim 21 or claim 22, wherein change maps are generated to facilitate the identification and/or segregation of one or more formation damage mechanisms in step e].24. A method according to claim 23, wherein the process of generating the cf 15 change maps comprises the following steps: -overlaying and aligning the before and after test data sets; r -pointwise intensity subtraction of the after test data sets from the before test data sets; -change map image processing to produce a change map; and r -quantification of the data and change map.25. A method according to claim 24, wherein the change map image processing step comprises processing change intensity data obtained from the pointwise intensity subtraction step to produce the change map.26. A method according to claim 25, wherein positive and negative change intensity are separated in the change map.27. A method according to any one of claims 24 to 26, wherein the quantification of the data and change map comprises the creation of a new data set using a binerization function.28. A method of quantification of formation damage mechanisms in a subterranean drilled core sample and the effect of the formation damage mechanisms on the characteristics of the core sample comprising the steps of analysing a subterranean drilled core sample in accordance with any one of claims 1 to27.29. A method according to claim 28, wherein the characteristics of the core sample includes the permeability of the core sample.30. A database on formation damage mechanisms comprising a list of formation damage mechanisms and their effect on an analysed subterranean drilled core sample populated by data obtained by the method according to any one of claims 1 to 27.c.f 15 31. A database according to claim 30, further comprising a list of at least one compound characteristic(s) impairment mechanism and the effect of the at least one r compound characteristic(s) impairment mechanism on an analysed subterranean drilled core sample, wherein the at least one compound characteristic(s) mechanism comprises at least two different formation damage mechanisms and the list is populated by data obtained by the method according to any one of claims 1 to 27.32. A database according to claim 31, wherein the at least one compound characteristic(s) impairment mechanism includes a compound permeability impairment mechanism.