Theis Solling and Xiomara Marquez (Maersk Oil Research and Technology Centre, Doha, Qatar). Thomas McKay and Andrew Fogden (Department of Applied ...
SPE SPE-166023-MS Multiscale characterization on the pore network in carbonate rocks Theis Solling and Xiomara Marquez (Maersk Oil Research and Technology Centre, Doha, Qatar) Thomas McKay and Andrew Fogden (Department of Applied Mathematics, Research School of Physics and Engineering, Australia National University, Canberra)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Reservoir Characterisation and Simulation Conference and Exhibition held in Abu Dhabi, UAE, 16–18 September 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract The flow properties of carbonate reservoir rocks depend on the pore and throat shape (geometry), the way they are interconnected (topology) and on the forces associated with the fluid-rock interactions (wettability). Little quantitative information on these parameters and their dependencies are currently available. We present the preliminary results of an on-going multiscale study of carbonate rocks which integrates classical diagenetic characterization of their pore system with 3D visualization and analysis of its structure (from micro-CT imaging) and mineral and elemental surface composition (from QEMSCAN). Tomograms of carbonate cores and minicores were obtained with our in-house micro-CT scanners, which allow us a spatial resolution down to the order of 1 µm. Macroporosity, microporosity and pore networks were extracted by image processing and analysis using the MANGO software. These same cores and minicores were then sectioned for 2D maps of their mineral composition to be acquired by QEMSCAN and subsequently spatially registered into the corresponding 3D tomogram. In addition to this analysis of carbonate samples in their dry state, minicores were also prepared and micro-CT imaged in a series of wet states after saturation, drainage, aging and spontaneous imbibition. This facilitated visualization and quantification of the pore-scale changes in saturation during these processes. The observations will help to guide the further development of modelling and simulation of multiphase flow in carbonates to predict and enhance the recovery of oil. 1. Introduction
Digital methods for core characterization based on x-ray computed micro-tomography (micro-CT) have developed tremendously over the past decade to now include in situ studies and computations in a realistic timeframe. Micro-CT is obviously a very important tool to aid in the understanding of complex behaviour in oil reservoirs, as not only can one calculate a given property of a rock sample but also visualize the pore-scale phenomena giving rise to it. In addition to the advances in micro-CT, the advent of automated mineral analysis, most recently with the implementation of QEMSCAN® by FEI, further enhance our capabilities to more completely characterize reservoir rocks. Moreover, the combination of 3D micro-CT maps with 2D mineral maps offers the promise to specify both the physical and chemical structure of a rock at every location. Further integration of knowledge of the fluid interactions with the pore surfaces would then provide a complete set of boundary conditions for modelling or simulation of multiphase flow. The relatively recent extensions of micro-CT protocols for scanning of dry samples to instead image the distribution of fluids in their pores provides the means to further develop and validate the computational flow models. The present work will demonstrate these expanding capabilities, partly
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using the newly established laboratories in Maersk Oil Research and Technology Centre, in a study of a set of outcrop and reservoir carbonate plugs by micro-CT and QEMSCAN. 2. Materials and Methods 2.1 Rocks A set of three carbonate rocks, comprising two from outcrops and one from a Middle Eastern reservoir, were selected. The reservoir carbonate, received in a solvent-cleaned state, was further cleaned of oil residues in o azeotropic chloroform/methanol at 45 C for 14 days. The samples and the results of their characterization by Mercury Injection Capillary Pressure (MICP, Micromeritics AutoPore IV) are presented in Table 1 and Figure 1. For micro-CT imaging, small plugs of each were cored in a drill press, using air as lubricant, to the diameters listed in Table 2. Three Edwards limestone plugs were analysed, namely two small sisters plugs of 5 mm diameter and 15 mm height, and one 30 mm high section of the as-received 38 mm diameter core. Table 1. Rocks and their pore metrics (mean and standard deviation) from MICP. Rock Liege chalk Reservoir carbonate Edwards limestone
Porosity (%) 27.3 11.8 19.8 ± 0.4
Pore volume 3 (cm /g) 0.144 0.049 0.094 ± 0.002
Throat diameter,
Surface area 2 (m /g) 1.26 0.19 0.18 ± 0.00
0.70 1.53 4.75 ± 0.08
Pore volume intruded, cm3/g
0.16 Liege chalk
0.14
Reservoir carbonate
0.12
Edwards limestone
0.10 0.08 0.06
0.04 0.02 0.00 0.001
0.01
0.1
1
10
100
1000
Pore throat diameter, mm Figure 1. Averaged mercury intrusion curves for the carbonate rocks.
Table 2. Dimensions of the rock plugs and their tomograms in the scanned states. Rock Liege chalk Reservoir carbonate Edwards limestone Edwards limestone Edwards limestone
Plug diameter (mm) 3 5 38 5 5
Imaged state Dry Dry Dry Dry Dry and wet
Field of view 3 (XxYxZ mm ) 3.9x3.9x3.0 5.7x5.7x4.5 42.4x42.4x33.3 6.5x6.5x9.2 5.9x5.9x4.6
Voxel size (mm) 1.9 2.8 20.8 3.3 2.9
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2.2 Oil and brines While the outcrop chalk and reservoir carbonate were only analysed in the dry state, the Edwards limestone plug at the bottom of Table 2 was prepared and imaged in a series of wet states. These experiments used an asphaltic -3 crude oil denoted WP (Alaska), with density 0.9125 gcm , viscosity 111 mPa.s, n-C6 asphaltene content 6.3 wt%, and acid and base numbers 1.46 and 2.49 mg KOH/g, all at room temperature [Loahardjo et al., 2010]. The synthetic brines used as simulated formation water (FW) and seawater (SW) were based on the literature recipes [Fathi et al., 2010] listed in Table 3. These compositions were altered by addition of 0.5 M of cesium chloride (CsCl) to increase the x-ray attenuation of the brine, and thus its contrast to oil in micro-CT. The 0.5 M CsCl replaced 0.5 M NaCl in the FW recipe (to preserve its ionic strength) and 0.4 M NaCl (i.e. the total amount present) in the SW recipe, as detailed in Table 3. The two doped brines were prepared from A.R. grade salts with deionized water (Millipore Milli-Q), and were vacuum degassed prior to use at the pH values in Table 3. Table 3. Molar concentration of ions, total dissolved salt (TDS), ionic strength (IS) and pH of the brines. Brine FW FW_Cs SW SW_Cs
Na (M) 1.000 0.500 0.450 0.050
K (M) 0.005 0.005 0.010 0.010
Ca (M) 0.029 0.029 0.013 0.013
Mg (M) 0.008 0.008 0.045 0.045
Cl (M) 1.070 1.070 0.525 0.626
SO4 (M) 0 0 0.024 0.024
HCO3 (M) 0.009 0.009 0.002 0.002
Cs (M) 0 0.500 0 0.500
TDS (g/l) 63.03 117.98 33.43 94.23
IS (M) 1.12 1.12 0.66 0.76
pH 7.5 7.4 7.9 7.9
2.3 Micro-CT Tomographic datasets were obtained and analyzed using the micro-CT facility built at ANU [Sakellariou et al., 2004] and housed there and at the newly established digital core laboratory at Maersk Oil Research and Technology Centre. Each of the plugs in Table 2, in the dry- or wet-state, was mounted in an anodized aluminium sample holder, of inner diameter 3, 5 or 38 mm. The holder was scanned through the aluminium-filtered Bremsstrahlung from the polychromatic x2 ) were captured by a flat panel detector. Most scans were o performed using a circular trajectory, in which 2880 projections were acquired over the 360 of rotation, at a source-camera distance of 1000 mm. Due to the limitation of the circular reconstruction algorithm to small cone angles of the x-ray beam, the resulting tomograms only spanned a 1600 voxel-high section near the middle of the plug. One Edwards limestone 5 mm plug (in the second bottom row of Table 2) was instead scanned using a double-helical trajectory, in which the sample was both rotated and vertically translated to acquire 2520 projections per helical pitch. This translation, together with the exactness of the helical reconstruction algorithm at high cone angles, allowed a much taller section of the plug to be imaged [Varslot et al., 2011]. Moreover, the much smaller source-camera distance of 300 mm yielded a tomogram of equivalent or better signal/noise than from the circular scan, and with less phase contrast, for the same 22 h duration of the run. All scans were performed at room temperature, and the dimensions of all resulting tomograms are summarized in Table 2.
2.4 Electron microscopy After micro-CT scanning, each plug in Table 2 was embedded in epoxy resin and a horizontal, polished thin section was prepared at close to the middle of the plug height, within the volume of its tomogram. One face of electrons (BSE) and energy-dispersive x-ray spectroscopy (EDS), using an automated QEMSCAN (FEI-650F) system at the newly established digital core laboratory at Maersk Oil Research and Technology Centre. From these, a 2D mineral map of the rock section was obtained using the spectral engine in the FEI Idiscover package.
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2.5 Wet sample preparation The Edwards limestone plug at the bottom of Table 2, of 5 mm diameter and 15 mm height, was evacuated and vacuum saturated with the initial brine FW_Cs (in Table 3) for 4 h. The saturated plug was transferred to stand in a glass vial (10 mm diameter) pre-filled with 1.8 g of oil and with 1.0 g of clean quartz sand (F-35, U.S. Silica) at the bottom. Primary drainage of the oil-immersed plug was performed by centrifuging the vial for 20 min in each direction at 3250 rpm, equivalent to a capillary pressure, Pc, of 48 kPa. The plug was then moved to a second vial o filled with 2.5 g of oil and aged (sealed) in a 75 C oven for 14 days. Micro-CT scans of the plug were performed at a series of stages during this aging, namely at day 0 (after drainage, prior to aging), 6 (midway) and 14 (end), by transferring the plug to an aluminium sample holder (5 mm diameter) filled with the same oil and sealed. At the conclusion of aging, the plug was switched to a third vial filled with 3.0 g of SW_Cs brine (in Table 3) for oil o recovery by spontaneous imbibition of this doped seawater. After 21 days of immersion at 75 C, the plug was micro-CT scanned in the same sample holder, filled with this same flood brine. The plug was subsequently o o cleaned using toluene at 75 C and methanol at 45 C and then vacuum dried for preparation of its thin section. The first vial mentioned above was used to determine the plug’s average initial water saturation (S wi) after primary drainage, from the difference between the brine mass saturating the plug (measured gravimetrically) and the brine mass centrifugally drained from the plug into the sand bed. The latter was measured by Karl Fischer titration (870 KF Titrino plus, Metrohm). This experimental procedure yielded an estimated Swi of 43.7% for this plug, in line with results presented in a previous study [Marathe et al., 2012]. The calculated P c from centrifugation corresponds to a smallest oil-intruded pore throat diameter of 2.2 -air drainage of Edwards limestone in Figure 1 at the intrusion volume fraction equivalent to the titration-measured average Swi would pore network, the uncertainties stemming from the small plug volume, and the lack of correction to inflow face saturation [Hassler and Brunner, 1945].
3. Results and discussion 3.1 Tomograms and image analysis of dry plugs Figure 2a shows a central vertical slice through the circularly-scanned tomogram of the 3 mm dry plug of Liege chalk (the first row in Table 2). This outcrop, quarried from Hallembaye, Belgium, is a highly porous coccolith chalk from the Upper Cretaceous, and has been well studied in the literature as a potential analogue for North Sea reservoir chalk. It is reported [Strand et al., 2007] to typically possess porosity of around 40%, permeability 12 2 mD and specific surface area 2 m /g (so its MICP values in Table 1 are somewhat on the low side), and contains less than 2% of quartz and clay. The most readily observable features in the tomogram are the foraminifera shells, the majority of which are completely cemented to solid calcite and appear brightest (i.e. most x-ray attenuating) in Figure 2a. Others retain a virtually open interior, resulting in micro-CT-resolvable macropore chambers which appear darkest (i.e. least x-ray attenuating). The remainder of the shells house smaller macropores and micropores; the latter lie below micro-CT resolution and appear as a grayscale intermediate to solid calcite and macropore. The matrix surrounding the shells is also microporous, and fairly uniformly so throughout, judging from its homogeneous intermediate attenuation. This microporosity dominates the void space of Liege chalk; the contribution of the macroporous shell interiors is relatively small and is not observable in the MICP curve in Figure 1 as they are only accessible through micropore throats in the shell. Figure 2b displays a central vertical slice through the circularly-scanned tomogram of the 5 mm dry plug of reservoir carbonate (the second row in Table 2). This rock has the texture of a grainstone of poorly sorted skeletal fragments which has undergone substantial diagenesis. Judging from the x-ray attenuation, the brighter grains, typically of fluffier and fissured form, are calcite as indicated by petrographic observations, while the darker, euhedral rhombs are dolomite crystals replacing the matrix.. The porosity is low, as expected from Table 1 and
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Figure 1, as it is mainly limited to microporosity in the calcite regions (of intermediate grayscale in Figure 2b) between these larger dolomite crystals. Figure 2c shows a central vertical slice through the helically-scanned tomogram of the 5 mm dry plug of Edwards limestone (the fourth row in Table 2), and Figure 3 displays a similar slice through the circularly-scanned tomogram of the 38 mm dry core from the same block (third row in Table 2). This grainstone was quarried from a member of the Edwards Formation near Garden City, Texas. It has been proposed as model rock for oil research [Tie and Morrow, 2005], partly owing to its homogeneity, which is apparent from the repetition of the features of the plug in Figure 2c throughout the core in Figure 3. Edwards limestone is reported [Tie and Morrow, 2005; 2 Fernø et al., 2007] to have a porosity of approx. 21%, permeability 13 mD and specific surface area 0.20 m /g (in good agreement with its MICP values in Table 1), and is essentially monomineralic calcite. Figure 2c shows that the grains comprise skeletal grains and the interparticle porosity is largely occluded by calcite cement, thus the pore space chiefly comprises intraskeletal and moldic macropores. Some grains are substantially infilled with calcite, and some contain coarse microporosity. Molds walls are lined by calcite microcrystals which allow neighbouring pores that may appear separate in Figure 2c, to connect via this intercrystalline microporosity. However, microporosity is far less prevalent than in Liege chalk, as is apparent from the lower frequency of intermediate grayscales in Figure 2c compared to Figure 2a, and is in line with the MICP curves in Figure 1. The tomograms provide the departure point for image post-processing and analysis using the MANGO software suite to quantify the observations, and in particular to extract estimates of phase volumes by segmentation. This is illustrated here using the example of the helically-scanned 5 mm dry plug of Edwards limestone (Figure 2c). Its tomogram was first segmented into two phases, namely grain (solid rock) and the rest. An additional segmentation was then applied to this second phase to separate it into micro-CT-resolvable pores (defined as macropores, of 100% porosity) and microporous regions lying below resolution. An effective porosity value was then assigned to each voxel in the microporous phase based on its grayscale. The total porosity of the sample was then determined as the sum of the macro- and microporous contributions. The first two rows of Table 4 list the values obtained for Edwards limestone from the tomograms of its 5 mm sister plugs scanned helically and circularly (in the two bottom rows of Table 2). The total porosity estimates are both in good agreement with the MICP total in Table 1 and with literature values [Tie and Morrow, 2005], and further evidence the homogeneity of this rock seen in Figure 3. Owing to the voxel size of ar microporous fraction inferred from segmentation is naturally larger than predicted from measurements employing a lower cut-
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(a)
(c) (b) Figure 2. Micro-CT images of plugs, showing a vertical slice along the cylinder axis, for (a) Liege chalk (image size 3.0 mm x 3.0 mm), (b) reservoir carbonate (4.6 mm x 4.5 mm) and (c) Edwards limestone (5.0 mm x 9.2 mm, helically scanned).
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Figure 3. Micro-CT image of the large plug of Edwards limestone, showing a vertical slice along the cylinder axis (image size 38.2 mm x 30.3 mm). Table 4. Volume percentages of pores in the dry state, subdivided into macropores and micropores, and their percentage occupancy by oil and brine in the three endpoint wet states, as determined by segmentation of the tomograms. Plug state Macroporosity Microporosity Total Air (% porosity) Air (% porosity) Air (% porosity) Dry (helical) 12.4 9.1 21.5 Dry (circular) 10.5 8.2 18.7 Oil Brine Oil Brine Oil Brine (% PV) (% PV) (% PV) (% PV) (% PV) (% PV) Drained 42.2 13.9 7.3 36.6 49.5 50.5 Aged fully 51.1 5.1 28.0 15.9 79.1 20.9 Flooded 44.4 11.7 5.2 38.6 49.7 50.3 A pore network can then be extracted from the segmented pore phase as input to modelling of transport properties. The MANGO software [Sheppard et al., 2005] generates the pore network using the computational algorithms of Euclidean distance, watershed transform, cluster region merge and maximum covering sphere. Figure 4 shows a vertical slice through the tomogram of the helically-scanned 5 mm dry plug of Edwards limestone and a visualization (using MAYAVI software) of its pore network within a vertical slab volume encompassing 10 tomogram slices either side of it. Due to the density and complexity of the pore network, this visualization in Figure 4b appears very similar to the grayscale tomogram slice in Figure 4a, and close-ups of subregions such as in Figure 4c and d are necessary to distinguish network features. In these ball-and-stick visualizations, the ball at each node represents the pore (of size proportional to the ball size) and the sticks connecting balls represent the throats (of cross-sectional width proportional to the stick width).
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(a)
(b)
(d) (c) Figure 4. (a) A vertical slice through the tomogram of Edwards limestone (image size 4.9 mm x 9.2 mm), and visualizations of its pore network over (b) this same slice area, (c) a close-up of the bottom right of (b), and (d) a close-up of the bottom right of (c).
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3.2 Mineral mapping and registration to tomograms Results are presented for the QEMSCAN mineral mapping of the 3 mm plug of Liege chalk and the 5 mm plug of reservoir carbonate. Table 5 lists the relative volumes of mineral phases identified in the plug section. As expected from the literature [Strand et al., 2007], Liege chalk is dominated by calcite and contains only 1-2% of other minerals, mainly made up of quartz, feldspar and illite. The results in Table 5 also confirm that the less attenuating crystals in the tomogram of the reservoir carbonate (Figure 2b) comprise dolomite, and that virtually no other minerals are present. Table 5. Modal mineralogy (volume %) of Liege chalk and reservoir carbonate from QEMSCAN.
Calcite Dolomite Quartz K-feldspar Illite Apatite Gypsum/Anhydrite Unclassified/traces
Liege chalk 98.70 0.01 0.38 0.15 0.17 0.06 0.01 0.52
Reservoir carbonate 45.33 54.46 0.04 0.00 0.00 0.00 0.05 0.12
The QEMSCAN maps of the plug sections are displayed in Figure 5, together with the corresponding section from the tomogram. The spatial alignment of the 2D map within the 3D tomogram was performed using the registration software [Latham et al., 2008] of the MANGO suite. In particular, the QEMSCAN color map file was converted into a black-and-white tomogram file, from which a small subarea was registered to a small subvolume of the tomogram, found from inspection to contain the chosen subarea. The registration transformation was then applied to the whole dataset, after which the color was reapplied to the QEMSCAN map. Such registration provides a means to segment minerals in the tomogram based on their characteristic attenuation and morphology, which is especially useful for rocks with more complex mineralogy than the two samples considered here. Further, the backscatter SEM map can provide images of microporous regions at higher resolution than in the tomogram, and thus serve to calibrate the segmentation of grayscale microporosity.
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(a)
(b)
(c)
(d)
Figure 5. (a) QEMSCAN mineral map of a section of the 3 mm plug of Liege chalk and (b) its registration to the tomogram; (c) QEMSCAN mineral map of a section of the 5 mm plug of reservoir carbonate and (d) its registration to the tomogram. Pale and dark purple represent calcite and dolomite, respectively.
3.3 Tomograms and image analysis of wet plugs As mentioned in the Materials and methods section, the 5 mm plug of Edwards limestone that was circularly scanned in the dry state (bottom row of Table 2) was subsequently saturated with the doped formation brine FW_Cs in Table 3, and then primary drained by centrifugation in oil and again micro-CT scanned. Afterwards, the plug was aged for 6 days, imaged again, and then returned to aging for a total of 14 days and imaged once more. Finally, the plug was immersed in the doped seawater SW_Cs in Table 3 for recovery of oil by spontaneous
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imbibition, again followed by imaging. The tomograms acquired in these four wet states were registered using MANGO software to the tomogram in the dry state. The same vertical slice of the plug as it evolved through this sequence is shown in Figure 6. The dry-state tomogram in Figure 6a appears very similar to that of the sister plug helically scanned in Figure 2c, again with dark regions corresponding to (air-filled) macropores and intermediate grayscales corresponding to (air-filled) microporosity. For the wet-state tomograms, in which air was no longer present, the oil now appears as the dark phase (due to its low x-ray attenuation), while the CsCl-doped brines should have attenuation intermediate to oil and calcite and thus appear as a middle gray. After primary drainage in Figure 6b, the oil is seen to mainly have invaded macropores, appearing as larger dark blobs, while the formation brine remains in the micropores, in line with expectations. During the course of aging, from Figure 6b to c to d, the oil further advanced to occupy even more of the macropores, and also partly invaded the micropores. At the same time, the increasingly scarce brine that remained is seen to increase its brightness, implying that its concentration (especially of the CsCl dopant) was steadily rising during aging. This concentration increase is due to dehydration of the brine by the oil. While o efforts were made to pre-equilibrate the crude oil with water at 75 C for an extended period prior to use, the very large volume ratio of oil immersing the plug (in a vial) to brine in its pores dictates that a water content in the oil only slightly lower than the equilibrium level will suffice for partial dehydration of the connate brine. This effect likely also took place during the aging experiments of a previous study [Marathe et al., 2012], in which plugs with high Swi values after drainage were not prevented from undergoing substantial wettability alteration. After the conclusion of aging, the change in the oil-brine occupancy of the plug due to immersion in the doped seawater can be seen by comparing Figure 6d to e. Brine re-enters micropores to substantially displace oil from these tighter locations, while oil in macropores is far less efficiently removed. This is to be expected from the high aspect ratio of pores in Edwards limestone (Figure 4), which tend to favour snap-off of oil in the tight throats to remain as trapped blobs in the macropores [Tie and Morrow, 2005].
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(a)
(b)
(c)
(d)
(e)
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Figure 6. Micro-CT images of the same Edwards limestone 5 mm plug, showing the same vertical slice along the cylinder axis in the sequence of six states: (a) dry, and after (b) primary drainage, (c) 6 days of aging, (d) 14 days of aging, and (e) oil recovery by spontaneous imbibition. These qualitative observations from inspection of the registered tomograms were supported by segmentation analysis. As mentioned above, segmentation of macropores and grayscale microporosity was performed on the dry-state tomogram of this Edwards limestone plug (in the second row of Table 4). The resulting macropore and microporosity segmentations were then applied as masks to the wet-state tomograms. Additional segmentations were performed within the unmasked regions to distinguish oil- from brine-containing voxels. The voxels assigned to oil or brine were then counted to determine their relative volume and porosity-weighted using the grayscale segmentation of the dry-state tomogram in microporous regions. The results of this image analysis are listed in the bottom three rows of Table 4. The values for oil and brine within the three pore categories (macro-, micro- and total porosity) verify the above-mentioned observations, and show that the tomogram-averaged pore occupancies after spontaneous imbibition are very similar to those after primary drainage, although the detailed pore-scale distributions differ (e.g., comparing Figures 6b and e). The values of total brine content of the Edwards limestone plug prior to aging and at its conclusion were compared to the laboratory-measured content of sister plugs prepared in an identical manner and aged for varying durations. The water within each plug was extracted and subjected to Karl Fischer titration, using a procedure analogous to that mentioned in the Materials and methods section. Figure 7 shows a good agreement between the saturations determined by experiment and by imaged analysis of the tomograms. This verifies the validity of the two approaches and suggests that the middle subvolume of the plug scanned by micro-CT is representative of its entire volume.
Brine saturation (%PV)
60
Titration
50
Micro-CT 40 30 20 10 0 0
5
10
15
20
Aging time (days) Figure 7. Comparison of evolution of brine saturation in the Edwards limestone plug during aging, as determined by laboratory titration or from segmentation of the tomograms.
4. Conclusions A set of outcrop and reservoir carbonate plugs was analysed in 3D by micro-CT and in 2D by mineral mapping of thin sections. The tools of tomographic image analysis were utilized to extract the volume fractions of macropores and micropores and the network connecting them. The mineral map was registered into the tomogram to illustrate how this external input could be used to more reliably and accurately segment the mineral phases in the
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tomogram. One outcrop carbonate plug was micro-CT scanned in a sequence of wet states during primary drainage, aging and oil recovery, to visualize the pore-scale configurations of oil and brine and quantify their occupancy of macropores and micropores. All of the results of tomographic and mineral mapping analysis compared well to independent experimental measures and to the literature.
5. References Loahardjo, N.; Xie, X.; Morrow, N. R. Energy Fuels 2010, 24, 5073-5080. Fathi, S. J.; Austad, T.; Strand, S. Energy Fuels 2010, 24, 2514-2519. Sakellariou, A.; Sawkins, T. J.; Senden, T. J.; Limaye, A. Physica A 2004, 339, 152-158. Varslot, T. K.; Kingston, A. M.; Latham, S. J.; Middleton, J.; Knackstedt, M. A.; Sheppard, A. P. Proceedings of the International Symposium of the Society of Core Analysts; Austin, TX, Sep 18-21, 2011; Paper 2011-26. Marathe, R.; Turner, M. L.; Fogden, A. Energy Fuels 2012, 26, 6268-6281. Hassler, G. L; Brunner, E. Trans., AIME 1945, 160, 114-123. Strand, S.; Hjuler, M. L.; Torsvik, R.; Pedersen, J. I.; Madland M. V.; Austad, T. Pet. Geo. 2007, 13, 69-80. Tie, H.; Morrow, N. R. Proceedings of the International Symposium of the Society of Core Analysts; Toronto, Canada, Aug 21-25, 2005; Paper 2005-11. Fernø, M. A.; Treinen, R. ; Graue, A. Proceedings of the International Symposium of the Society of Core Analysts; Calgary, Canada, Sep 10-12, 2007; Paper 2007-22. Sheppard, A. P.; Sok, R. M.; Averdunk, H. Proceedings of the International Symposium of the Society of Core Analysts, Toronto, Canada, Aug 21-25, 2005; Paper 2005-20. Latham S.; Varslot T.; Sheppard A. P. Proceedings of the International Symposium of the Society of Core Analysts, Abu Dhabi, UAE, Oct 29-Nov 2, 2008; Paper 2008-35.
