SAMPLE

DESCRIPTION

The invention relates to a method for analyzing a porous material from a core sample thereof. The method comprises the steps of making a three-dimensional tomographic image of the sample of the material. The image is segmented into voxels (volume elements) each representing core space or rock grain. The porosity of the sample is determined from the image.

Estimating material properties such as fluid transport properties of porous media has substantial economic significance. Methods known in the art for identifying the existence of subsurface reservoirs of gas and/or oil need to be supplemented with reliable methods for estimating how fluids dispose in the pore spaces of the reservoir rock formations will flow over time in order to characterize the economic value of such reservoir rock formations.

Recently, devices for generating computer tomographic (CT) images of samples such as drill cuttings have become available. Such CT image generating devices (CT scanners) typically produce three-dimensional grey scale images of the samples analyzed in the scanner. Using images of samples of rock formations it is possible to obtain estimates of petrophysical parameters of the imaged rock sample, for example, porosity, permeability, shear and bulk moduli and formation resistivity factor.

The transport properties of certain rock types are substantially affected by thin fractures (or cracks) that connect otherwise disconnected pore space. The spacing between these fractures may be large and, as a result, these fractures may not be captured in selected rock fragments subject to imaging using conventional imaging techniques, including CT scan images. Petro physical properties of such formations may be incorrectly determined or estimated if the estimates are based on such images.

US 2010/0128933 Al provides a method that uses images such as the foregoing described CT images to estimate petrophysical properties of fractured rock formations. The image is segmented into pixels each representing pore space or rock grain. The porosity of the sample is determined from the segmented image. An image of at least one fracture is introduced into the segmented image to generate a fractured image. The porosity of the fractured image is determined. At least one petrophysical parameter related to the pore-space geometry is estimated from the fractured image.

This approach is limited such that a solution of the CT image has to be smaller than the pore size in order for the pores to be resolved. Since the resolution of tomography is proportional to the size of the sample this constraint directly affects the maximum size of the core sample to be measured. Additionally, no direct determination is possible if the pores are interconnected and therefore permeable for petroleum or gas. Only with a large enough pore size the interconnectivity between pores can be calculated from the CT image.

It is an object of the present invention to provide a method for analyzing a porous material from a core sample thereof, which allows a direct determination of the porosity of the core sample.

This object is solved by a method according to the features of claim 1. Preferred embodiments are set out in the dependent claims.

A method for analyzing a porous material from a core sample thereof comprises making a three-dimensional tomographic image of the sample of the material. The image is segmented into voxels, each representing core space or rock grain. The porosity of the sample is determined from the image. According to the invention, a first image of the sample is made wherein core spaces of the core sample are filled with air. A first contrast value for each of the voxels is determined. A second image of the sample is made wherein the material of the sample is filled with a contrast agent with known absorption properties. A second contrast value for each of the voxels is determined. The porosity of the sample is determined from the first and the second contrast values.

The method for analyzing the porous material from a core sample is based on two measurements made in succession. The first measurement is made to a core sample in which no contrast agent is filled. The second measurement is made from the same core sample filled with the contrast agent. During each measurement the contrast values for each of the voxels are determined. From these different contrast values the porosity can be determined.

By applying a contrast agent within the core sample the porosity of the core sample can be measured even if the pore size is smaller than the resolution of a CT scanner (CT image generating device) which makes the three-dimensional tomographic image. Filling the core sample with the contrast agent furthermore helps to solve the problem of lack of contrast between solid mineral and empty space of pores network. Isolated empty space from the well connected to pore network can be distinguished because the contrast agent will go a similar way as the reservoir fluid (petroleum or gas) would go.

According to a preferred embodiment, the change between the first and the second contrast value of each voxel is determined. By calculating the change between the first and the second contrast value of each voxel, a change in absorption of the voxel between the two measurements can be determined. The change in absorption can be directly converted into the porosity of the voxels and thus into the porosity of the core sample.

According to a further preferred embodiment, the difference of the first contrast value to the second contrast value related to a maximum absorption change value is used as a means for porosity. Within this step, a comparison of a maximum change in absorption of a voxel without any rock material (only air before and only contrast agent after filling in the contrast agent) to the change of the absorption of other voxels having a mixture of rock grain and pore space allows the calculation of the porosity directly. According to that in a further preferred embodiment the changed absorption value is determined for a voxel from the first contrast value resulting from only air and the second contrast value resulting from only contrast agent. As mentioned, the calculation of the porosity is thereby independent from the resolution of the CT image.

According to a further preferred embodiment, the contrast agent consists of elements that do not occur in the material of the core sample. Therefore, as a contrast agent any substance can be used which penetrates the rock sample and ensures that a high contrast ratio from the contrast agent to the material of the core sample is provided.

According to a further preferred embodiment, the contrast agent is adapted to highly absorb rays as a measure for making the tomographic image. In order to achieve high contrast ratios from the contrast agent to the rock material any highly absorbing elements can be used, such as, but not limited to, Gadolinium which is available in liquid form as a contrast agent for medical purposes.

According to a further improved embodiment, by varying viscosity of the contrast agent and/or a pressure of the contrast agent and/or a temperature of the contrast agent the flow of petroleum can be simulated at different conditions by adjusting the physical properties of the liquid.

According to a further preferred embodiment, the weight of the core sample filled with the contrast agent is determined compared to the weight of the core sample without the contrast agent. This embodiment enables determining further information about the core porosity. It is possible to classify large cores by inspection of typical areas found only by grey value measurements. Big core samples can be classified and compared to calibrated test samples to define general core parameters.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Fig.1 shows cross-sections of the same section of a core sample filled with air and filled with a contrast agent.

Fig.2 shows cross-sections of the same section of the core sample filled with air and filled with a contrast agent wherein each section is segmented into a number of voxels being analyzed for determining the porosity of the section of the core sample.

Reservoir modeling techniques play a crucial role in the success of a petroleum or gas reservoir development allowing in-time operational decisions and proper planning. Key part of the modeling is the core analysis that provides key core and hence reservoir features, in particular porosity, permeability, pore size distribution, phase permeability etc. Calculated core properties give data for calculations of reservoir features and allow informed decisions and proper reservoir development strategy. A problem to make high quality mapping of the core sample is a limited contrast between rock grain and pore spaces (empty space) which is solved with the method described hereinafter.

A core sample to be evaluated may be obtained by the drilling of a well bore through subsurface formations. It should be clearly understood that drill cutting is only one example of samples of rock formation that may be used with the present invention. Any other source of rock formation sample, e.g., whole cores, sidewall cores, outcrop quarrying, etc. may provide suitable samples for analysis using the method according to the invention.

Fig. l illustrates in a cross-section a core sample 1 of a porous material. The core sample 1 consists of rock grain 2 in which pore spaces 3 are enclosed. Isolated or non- interconnected pores 3 are depicted with reference numeral 5. Pores 3, which are connected so that a fluid can flow through them is depicted with reference numeral 4. In the section on the left side of fig. 1 the pore spaces 3 are filled with air 6. On the right hand side of fig. 1 the same section is shown wherein the material of the sample 1 is filled with a contrast agent 7.

If, in the present description a contrast agent is referred to, also a tracer is to be understood. As apparent to a skilled person, the contrast agent 7 is only able to distribute in connected pores 4. Therefore, in the non-interconnected pores 5 still air 6 is present while in the connected pores 4 the contrast agent 7 has spread.

The basic concept of the method for analyzing the porous material from a core sample thereof is based on a two-step evaluation of the core sample. In the first step, the core sample is examined without any substance in it. In the second step the same examination is made while the contrast agent is filled in the core sample.

The examination consists of making a three-dimensional topographic image of the sample of the material by use of a computer tomographic (CT) image generating device such as a CT scanner, the first image being made from the core sample without a fluid in it, the second image being made from the core being filled with the contrast agent. In fig. 2, the same sections of the core sample 1 are shown, on the left hand side with all pores 3 filled with air, and on the right hand side with the connected pores 4 filled with contrast agent 7 and the non-inter-connected pores 5 still filled with air 6. Just as an example the section of the core sample 1 is segmented into 16 voxels being located in four lines with four columns each. In fig. 2 the voxels are generally indicated with reference numeral 10. Specific voxels of the matrix are indicated by Vxjj where i indicates the line and j indicates the column.

In the following description voxels Vxn, Vx ₄₂ and Vx ₄₄ are considered in particular. For determining porosity P of the core sample 1 from the two images a first and a second contrast value for each of the voxels is determined. The first contrast values of the voxels 10 of the first image on the left hand side in fig. 2 are indicated as CVj _j where i represents the line of the voxels and j represents the column of the voxels 10. The second contrast values of the voxels 10 of the second image on the right hand side where the connected cores 4 are filled with contrast agent 7 are depicted with CVj _j ', where again i represents the line of the voxels and j represents the column of the voxels 10. As illustrated in fig. 2 voxel Vxn consists of rock grain 6 and air-filled pore 5 resulting in a first contrast value CVn. The contrast value is processed in a grey level, for example between 0 % (e.g. white) and 100 % (e.g. black). However, any other grey scale may be used. Since voxel Vxn consists of more rock grain 2 than air-filled pore space 5 the contrast value or grey level might be around 70 %, for example. Voxel Vx ₄₂ also consists of rock grain 2 and air-filled pore space 3. Since the amount of air-filled pore space is around equal to the amount of rock grain 2 the resulting contrast value CV ₄₂ may be around 50 % in grey scale. Voxel Vx ₄ only consists of rock grain. The corresponding contrast value CV ₄ therefore may be 100 %.

In the same manner the second contrast values CVj _j 'of the voxels of the core sample 1 with filled contrast agent 7 within the material is determined. Referring to voxel Vxn, the second contrast value CVn ' remains unchanged since the pore 3 is a not-interconnected pore 5 which still is filled with air 6. The same is true for voxel Vx ₄₄ . The second contrast value CV ₄₄ ' is the same as the first contrast value CV ₄₄ since the voxel Vx ₄ only consists of rock grain. In contrast, the second contrast value CV ₄₂ ' of voxel Vx ₄₂ has changed, since the pore space 3 is filled with the contrast agent 7 due to the fact, that pore space 3 is a connected pore. Dependent on the absorption properties of the contrast agent, the second contrast value CV ₄₂ ' may be higher or lower than the first contrast value CV ₄₂ where the core sample has not been filled with the contrast agent 7 yet.

As contrast agent 7 any substance can be used which penetrates the rock sample and contains elements that do not occur in the rock sample. In order to achieve high contrast ratios from the contrast agent to the rock material highly absorbing elements can be used such as, but not limited to, Gadolinium, which is available in liquid form as a contrast agent for medical purposes. The contrast agent filled in the core sample allows to determine the contrast of the rock to the known agent.

The contrast agent 7 solves several limitations. Even for pore sizes too small to be resolved an estimate of the porosity can be given. Since the results of the CT image is only a grey value per voxel (volume element) for each voxel only a combination of density and element composition can be given. A voxel containing higher absorbing elements but air-filled pores inbetween could result in the same grey value as a voxel completely filled with a lower absorbing material. Directly estimating the air contents within the voxel is therefore not possible. Only voxels containing only air can be determined which limits the pore size. By replacing the air in the sample to the contrast agent with known absorption properties and comparing the measurement without and with the agent the porosity P can be determined directly:

A voxel without pores delivers the same values before and after application of the contrast agent (cf. voxel Vx ₄₄ ) while a voxel (cf. voxel Vx ₄₂ ) containing a certain amount of air replaced by the contract agent changes its grey level. The change c in absorption (i.e. the grey level with contrast agent minus the grey level without the contrast agent) can be directly converted into the porosity P=c/c _ma x by comparing the maximum change c _max of a voxel without any rock material. Such a voxel contains only air before and contrast agent after filling the contrast agent in the core sample.

Even for core samples with very low absorption the porosity P can be determined since the density values and absorption values, respectively, are only of secondary importance since only the change between air and agent are taken into account.

It is to be understood that only interconnected pores 4 are penetrated by the contract agent 7. Therefore, the interconnectivity can be measured directly without any need for calculation. The interconnectivity is not dependent on the resolution of the CT image.

In an alternative embodiment by varying viscosity of the contrast agent and/or pressure and/or temperature the flow of petroleum can be simulated at different conditions by adjusting the physical properties of the contrast agent.

Further information about the core porosity may be generated by measuring the weight of the penetrated core sample and the comparison to a standardized core porosity. This information may be stored in a data base. By doing so, large cores will be possible to classify by inspection of typical areas found only by grey value measurements.

The principle of the method provided is an additional measurement of the porosity where a core sample is filled with the contrast agent of known absorption properties. By comparing the contrast values of the measurements of the core sample with and without the contrast agent several problems are solved.

It is possible to measure porosity when the core size is smaller than the resolution of the CT image. A lack of contrast between the rock grain and pore space is not relevant anymore since the second measurement with the core space which is filled with contrast agent enables determining the structure of the core sample. Furthermore, distinguishing of isolated pore spaces from the well connected pore network is possible since the contrast agent will go a similar way as the reservoir fluid (petroleum) would go. Big core samples may be classified and compared to calibrated test samples to define the general core parameters.