Name: Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography (Video) | JoVE Journal
Uploaded: 2018-10-21T13:00:00.000+00:00
Duration: 12 min 18 s
Description: Learn to characterize hydrocarbon reservoir rock wettability using X-ray microtomography under subsurface conditions. This method enables detailed analysis of multiphase flow for enhanced oil recovery applications.

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We gratefully thank Abu Dhabi National Oil Company (ADNOC) and ADNOC Onshore (previously known as Abu Dhabi Company for Onshore Petroleum Operations Ltd) for funding this work.

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The high resolution X-ray micro-tomography datasets reported in this paper are available at the Digital Rocks Portal: 
www.digitalrocksportal.org/projects/151&#160; 
The codes used to run automatic measurements of contact angle and fluid/fluid interface curvature are available at GitHub: 
https://github.com/AhmedAlratrout/ContactAngle-Curvature-Roughness&#160;

The most critical steps for an in situ wettability characterization at high pressure and temperature to be successful are as follows. 1) Generate a good image segmentation that is essential to obtain accurate contact angle measurements. 2) Avoid including large impermeable grains in the mini-samples that could seal off the flow, and large vugs resulting in a very fragile sample with non-representative porosity. 3) A well-controlled flow experiment with no leaks is important because mini-samples are very sensitive to the amount of injected fluid (i.e., one pore volume is about 0.1 mL). 4) Avoid the presence of air (as a fourth phase) in the pore space. 5) Maintain a temperature control of the sample during the whole flow experiment. 6) Avoid any interface relaxation during the scan acquisition by waiting for the system to reach equilibrium. 7) Use an appropriate center shift correction, which is necessary for the effective X-ray image reconstruction.
The automated contact angle method is limited by the accuracy of the image segmentation because it is applied to segmented images only. Image segmentation depends largely on imaging quality that depends on the imaging protocol and the performance of the microtomography scanner. Furthermore, it is sensitive to the image reconstruction and the noise reduction filters, as well as the segmentation method such as the TWS32 or the seeded watershed method57. In this work, the TWS method provided more accurate contact angle measurements on raw X-ray images compared to those by a watershed method applied to filtered X-ray images (using noise reduction filters). The use of noise reduction filters makes the interface appear to be less oil-wet at some parts of the rock, due to the voxel averaging especially close to the three-phase contact line31. TWS can capture not only the amount of remaining oil saturation but also the shape of the remaining oil ganglia. This is especially the case for the remaining oil in the mixed-wet cases, in which oil is retained in the pore space as thin sheet-like structures, making it a challenge to be segmented based on gray-scale threshold values only.
This in situ wettability determination provides a thorough description of the wetting conditions of reservoir rocks compared to other conventional wettability measurement methods. It takes into account all important pore-scale rock parameters, such as rock surface roughness, rock chemical compositions, and pore size and geometry, that are not possible by wettability indices7,8&#160;and ex situ contact angle methods4,9,10,11. The use of an automated in situ contact angle measurement at the micron scale is robust and removes any subjectivity associated with the manual method24. Moreover, it is more effective in removing voxelization artefacts compared to other automated methods25,26. The in situ contact angle distribution measured using the automated method was relatively rapid. For example, the runtime for measuring the contact angle on any of the three sample images that contain 595 million voxels is approximately 2 h, using a single 2.2&#8239;GHz CPU processor.
In the future, this protocol can be used to characterize other reservoir rock systems saturated with formation brine and crude oil. The same method is not limited to the petroleum industry only and can be modified and adapted to characterize the wettability from any segmented three-dimensional images with two immiscible fluids in porous media with a variety of wettability conditions.

Wettability (the contact angle between immiscible fluids at a solid surface) is one of the key properties that control fluid configurations and oil recovery in reservoir rocks. Wettability affects macroscopic flow properties including relative permeability and capillary pressure1,2,3,4,5,6. However, measuring the in situ wettability of reservoir rock has remained a challenge. Reservoir rock wettability has been determined traditionally at the core scale, indirectly using wettability indices7,8, and directly ex situ on flat mineral surfaces4,9,10,11. Both wettability indices and ex situ contact angle measurements are limited and cannot characterize the mixed-wettability (or range of contact angle) that typically exist in hydrocarbon reservoirs. Moreover, they do not account for pore-scale rock properties, such as rock mineralogy, surface roughness, pore-geometry, and spatial heterogeneity, that have a direct impact on the fluid arrangement at the pore scale.
Recent advances in non-invasive three-dimensional imaging using X-ray microtomography12, in combination with the use of an elevated temperature and&#160;pressure apparatus13, have allowed the study of multiphase flow in permeable media14,15,16,17,18,19,20,21,22,23. This technology has facilitated the development of manual in situ contact angle measurements at the pore scale in an opaque porous medium (quarry limestone rock) at subsurface conditions24. A mean contact angle value of 45&#176; &#177; 6&#176; between CO2 and potassium iodide (KI) brine was obtained by hand from raw images at 300 points. However, the manual method is time-consuming (i.e., 100 contact angle points could take up to several days to be measured) and the values obtained could have a subjective bias.
The measurement of an in situ contact angle has been automated by different methods applied to segmented three-dimensional X-ray images25,26,27. Scanziani et al.25 improved the manual method by placing a circle at the fluid-fluid interface that intersects with a line placed at the fluid-rock interface on slices orthogonal to the three-phase contact line. This method has been applied to small sub-volumes extracted from three-dimensional images of quarry limestone rock saturated with decane and KI brine. Klise et al.26 developed a method to quantify the in situ contact angle automatically by fitting planes to the fluid-fluid interfaces and fluid-rock interfaces. The contact angle was determined between these planes. This method was applied to three-dimensional images of beads saturated with kerosene and brine. Both automated methods were applied to voxelized images that might introduce error, and in both methods, lines or planes were fitted at the fluid-fluid and fluid-rock interfaces and the contact angle was measured between them. Applying these two approaches on voxelized segmented images of complex rock geometry could lead to errors while also being time-consuming.
In this protocol, we apply the automated in situ contact angle method developed by AlRatrout et al.27 that removes voxelization artefacts by applying Gaussian smoothing to the fluid-fluid and fluid-solid interfaces. Then, a uniform curvature smoothing is applied only to the fluid-fluid interface, which is consistent with the capillary equilibrium. Hundreds of thousands of contact angle points are measured rapidly in combination with their x-, y-, and z-coordinates. The approach of AlRatrout et al.27 has been applied to water-wet and mixed-wet quarry limestone samples saturated with decane and KI brine.
In this protocol, we employ the latest advances in X-ray microtomography combined with a high-pressure and high-temperature apparatus to conduct an in situ wettability characterization of complex carbonate reservoir rocks, extracted from a very large producing oil field located in the Middle East. The rocks were saturated with crude oil at subsurface conditions to reproduce the reservoir conditions upon discovery. It has been hypothesized that parts of the reservoir rock surfaces (with direct contact with crude oil) become oil-wet, while others (filled with initial formation brine) remain water-wet28,29,30. However, the reservoir rock wettability is even more complex due to several factors controlling the degree of wettability alteration, including the surface roughness, the rock chemical heterogeneity, the crude oil composition, the brine composition and saturation, and the temperature and pressure. A recent study31 has shown that there is typically a range of contact angle in reservoir rocks with values both above and below 90&#176;, measured using the automated method developed by AlRatrout et al.27.
The main objective of this work is to provide a thorough protocol to characterize the in situ wettability of reservoir rocks (mixed-wettability) at subsurface conditions. An accurate measurement of an in situ contact angle requires a good segmentation quality. Hence, a machine learning-based segmentation method known as Trainable WEKA Segmentation (TWS)32 was used to capture not only the amount of remaining oil but also the shape of the remaining oil ganglia, thus facilitating more accurate contact angle measurements. Recently, TWS has been used in a variety of applications, such as the segmentation of packed particle beds, liquids within textile fibers, and pores of tight reservoirs33,34,35,36,37,38,39,40. To image the remaining oil accurately at a high resolution and at subsurface conditions, a novel experimental apparatus was used (Figure&#160;1 and Figure&#160;2). Mini-samples of rock were loaded into the center of a Hassler-type core holder41 made of carbon fiber. The use of a long and small diameter carbon fiber sleeve allows an X-ray source to be brought very close to the sample, hence increasing the X-ray flux and reducing the required exposure time, resulting in a better image quality in a shorter period of time. The carbon fiber sleeve is strong enough to handle high pressure and temperature conditions while remaining sufficiently transparent to X-rays21.
In this study, we outline the steps followed to characterize the in situ wettability of reservoir rocks at subsurface conditions. This includes drilling representative mini-samples, the core holder assembly, the flow apparatus and flow procedure, the imaging protocol, the image processing and segmentation, and finally running the automated contact angle code to generate contact angle distributions.

<table><tbody><tr><td>Xradia VersaXRM-500 X-ray micro-CT</td><td>ZEISS</td><td>Quote</td><td>X-ray microtomography scanner, https://www.zeiss.com/microscopy/int/products/x-ray-microscopy.html</td></tr><tr><td>Teledyne Isco syringe pumps</td><td>Teledyne Isco</td><td>Quote</td><td>Model 100DM, Model 260D and Model 1000D, http://www.teledyneisco.com/en-uk</td></tr><tr><td>Core holder</td><td>Airborne</td><td>Quote</td><td>9.5 ID Coreholder, www.airborne-international.com</td></tr><tr><td>Gas pycnometer</td><td>Micromeritics</td><td>Quote</td><td>AccuPyc II 1340 Pycnometer, http://www.micromeritics.com/Product-Showcase/AccuPyc-II-1340.aspx</td></tr><tr><td>Thermocouple</td><td>Omega</td><td>KMTSS-IM025U-150</td><td>0.25 to 1.0 mm Fine Diameter MI Construction Thermocouples Terminated With A Mini Pot-Seal and 1m PFA Lead Wire, https://www.omega.co.uk/pptst/TJMINI_025-075MM_IEC.html</td></tr><tr><td>Flexible heating jacket</td><td>Omega</td><td>KH-112/5-P</td><td>Kapton Insulated Flexible Heaters, https://www.omega.co.uk/pptst/KHR_KHLV_KH.html</td></tr><tr><td>PEEK tubing</td><td>Kinesis</td><td>1533XL</td><td>PEEK Tubing 1/16&amp;rdquo;OD X 0.030&amp;rdquo; (0.75mm) ID Green, http://kinesis.co.uk/tubing-tubing-peek-green-1-16-x-0-030-0-75mm-x100ft-1533xl.html</td></tr><tr><td>Tube cutter</td><td>Kinesis</td><td>003062</td><td>Tube cutter, http://kinesis.co.uk/tubing-tube-cutter-003062.html</td></tr><tr><td>PEEK fingertight fitting</td><td>Kinesis</td><td>F-120X</td><td>Fingertight Fitting, single piece, for 1/16&quot; OD Tubing, 10-32 Coned, PEEK, Natural, http://kinesis.co.uk/fingertight-fitting-single-piece-for-1-16-od-tubing-10-32-coned-peek-natural-f-120x.html</td></tr><tr><td>PEEK adapters and connectors</td><td>Kinesis</td><td>P-760</td><td>Adapters &amp;amp; Connectors: PEEK&amp;trade; ZDV Union, for 1/16&quot; OD Tubing, 10-32 Coned, http://kinesis.co.uk/catalogsearch/result/?q=P-760</td></tr><tr><td>PEEK plug</td><td>Kinesis</td><td>P-551</td><td>Plug, 10-32 Coned, PEEK, Natural, http://kinesis.co.uk/plug-10-32-coned-peek-natural-p-551.html</td></tr><tr><td>Digital Caliper</td><td>RS</td><td>50019630</td><td>Digital caliper, http://uk.rs-online.com/web/</td></tr><tr><td>Three-way valve</td><td>Swagelok</td><td>SS-41GXS1</td><td>Stainless Steel 1-Piece 40G Series 3-Way Ball Valve, 0.08 Cv, 1/16 in. Swagelok Tube Fitting, https://www.swagelok.com/en/catalog/Product/Detail?part=SS-41GXS1</td></tr><tr><td>Viton sleeve</td><td>Cole-Parmer</td><td>WZ-06435-03</td><td>Viton FDA Compliant Tubing, 3/16&quot; (4.8 mm) ID, https://www.coleparmer.com/i/mn/0643503</td></tr><tr><td>Drilling bit</td><td>dk-holdings</td><td>quote</td><td>Standard wall drill *EDS540, 5mm internal diameter x continental shank, reinforced stepped shank 5mm of the tube behind 20mm of diamond, http://www.dk-holdings.co.uk/glass/stanwall.html</td></tr><tr><td>Heptane</td><td>Sigma-Aldarich</td><td>246654-1L</td><td>Heptane, anhydrous, 99%, http://www.sigmaaldrich.com/catalog/product/sial/246654?lang=en&amp;amp;region=GB</td></tr><tr><td>Potassium iodide</td><td>Sigma-Aldarich</td><td>231-659-4&amp;nbsp;</td><td>purity &amp;ge; 99.0%, https://www.sigmaaldrich.com/catalog/product/sigma/60399?lang=en&amp;amp;region=GB</td></tr><tr><td>ParaView</td><td>Open source</td><td>Free</td><td>Data visiualization software (Protocol step 6.6), https://www.paraview.org/</td></tr><tr><td>Avizo Software</td><td>FEI</td><td>License</td><td>Data visiualization and analysis software (Protocol step 1.2, 5.7.1), https://www.fei.com/software/amira-avizo/</td></tr><tr><td>Recontructor Software</td><td>ZEISS</td><td>License</td><td>https://www.zeiss.com/</td></tr></tbody></table>

pore-scale imaging and characterization of hydrocarbon reservoir rock wettability at subsurface conditions using x-ray microtomography

Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography

In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon reservoir rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate reservoir rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon reservoirs (known as mixed-wettability). After the brine injection, high-resolution three-dimensional images (2 &#181;m/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale rock properties, such as rock surface roughness, rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. 
The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO2 in subsurface formations.

For the 3 samples studied, the measured in situ distribution of the contact angle is shown in Figure 6, with the oil recovery shown in Figure 11. Figure 12 shows images of the remaining oil distributions for different wetting conditions at the end of the waterflooding. The mixed-wettability (or the range of the contact angle) was measured using the automated contact angle method27. The measured contact angle distributions are considered to be representative results if there is a good match between the contact angle points measured using the automated method from segmented images compared to the manually measured contact angles from raw X-ray images. Figure 10 shows an example of a good match of a comparison measurement between the automated contact angles and the manual contact angles at the same locations for a sub-volume from mini-sample 1 (weakly water-wet).
Three aging protocols were performed to treat the 3 samples and generate 3 wetting conditions (Figure 6). Aging the sample at a lower temperature (60 °C) and statically (no oil injection during the aging period) could result in a weakly water-wet condition, such as the distribution shown for sample 1 in blue (Figure 6). On the other hand, aging the sample at a higher temperature (80 °C) and with partially dynamic aging (an oil injection during the aging period) could result in mixed-wet conditions with more oil-wet surfaces, like that of sample 2 shown in gray (Figure 6).
The oil recovery was found to be a function of wettability, similar to earlier core-scale studies51. However, at that time, the oil recovery was shown as a function of the core-scale wettability index. Similar oil recovery behavior has been observed at the pore scale and was plotted as a function of the mean value of the in situ contact angle distribution (Figure 11). The low oil recovery of sample 1 (weakly water-wet) was due to the trapping of oil in larger pore spaces. The brine percolated through the small pore corners, leaving the oil trapped as disconnected ganglia in the center of the pore spaces with quasi-spherical shapes (Figure 12a), similar to what has been observed in previous investigations in water-wet media52,53,54,55. In contrast, sample 2 (a mixed-wet case with more oil-wet surfaces) had oil layers that were largely connected (Figure 12b). These thin layers only allowed a slow oil production, leaving a high remaining oil saturation at the end of the waterflooding. The highest oil recovery was achieved in sample 3 (mixed-wet with a mean contact angle close to 90°) which was neither water-wet (so there is less trapping in large pores) nor strongly oil-wet (less oil is retained in small pore spaces)1. In the mixed-wet cases of sample 2 and 3, oil was left in connected, thin sheet-like structures (Figure 12b and 12c) similar to other studies in oil-wet porous media52,53,56.
<img alt="Rock deformation experiment diagram showing equipment: flowhead, thermocouple, heating jacket, tubing." class="xfigimg" src="/files/ftp_upload/57915/57915fig1.jpg" data-altupdatedat="1788250015000" data-alt="Figure 1"> 
Figure 1: A schematic illustration diagram of the core holder assembly. Components of the core holder are labeled, and the internal cross-section view of the core holder is shown. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig1large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Core flooding setup diagram with X-ray µCT, rotation stage, pumps, valves for CO₂/brine flow study." class="xfigimg" src="/files/ftp_upload/57915/57915fig2.jpg" data-altupdatedat="1788250015000" data-alt="Figure 2"> 
Figure 2: The high-pressure, high-temperature flow apparatus. The flow apparatus is comprised of four high-pressure syringe pumps: (A) an oil pump, (B) a receiving pump, (C) a brine pump, and (D) a confining pump. Panel (E) shows the core holder assembly, (F) shows the PID controller, and (G) shows the CO2 cylinder. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig2large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Concrete microstructure analysis; diagrams and microscopy images showing sample scaling and detail views." class="xfigimg" src="/files/ftp_upload/57915/57915fig3.jpg" data-altupdatedat="1788250015000" data-alt="Figure 3"> 
Figure 3: Images demonstrating the drilling of representative mini-samples. (a) This cartoon illustrates the orthogonal marks with a good drilling location. x and y are the distances from the center of the core plug used to find where to drill. (b) This panel shows a dry X-ray three-dimensional image of the core plug (rendered semi-transparent) with a mini-sample (in dark gray). (c) This is a horizontal cross-sectional view of the core plug (scanned at 40 µm/voxel). The rock grains and pores are shown in gray and black, respectively. (d) This panel shows a horizontal cross-sectional view of the mini-sample (scanned at 5.5 µm/voxel). (e) This is a vertical cross-sectional view of the core plug showing the complex and heterogeneous pore sizes and geometries along with the location of the mini-sample indicated by the black box. (f) This is a magnified vertical cross-sectional view of the highlighted mini-sample shown in panel e that was scanned at 5.5 µm/voxel. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig3large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="CT scan showing rock porosity, oil, and brine distribution; grayscale histogram chart of pixel density." class="xfigimg" src="/files/ftp_upload/57915/57915fig4.jpg" data-altupdatedat="1788250015000" data-alt="Figure 4"> 
Figure 4: A phase contrast scan. (a) This panel shows a contrast scan of crushed rock (light gray) mixed with brine (dark gray) and oil (black) phases. This was used to determine the appropriate doping of the brine to ensure a good phase contrast. (b) This is a histogram of the gray-scale value of the three phases. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig4large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Mineral texture analysis, microscope image, pattern recognition, 2mm scale, geological research." class="xfigimg" src="/files/ftp_upload/57915/57915fig5.jpg" data-altupdatedat="1788250015000" data-alt="Figure 5"> 
Figure 5: A horizontal cross-sectional view of raw and segmented X-ray images of three mini-samples. Panels (a), (b), and (c) show xy cross-sectional views of mini-samples 1, 2, and 3, respectively. The top row shows the raw gray-scale X-ray images (oil, brine, and rock, are in black, dark gray, and light gray, respectively). The lower images show the segmented images of the same slice using Trainable WEKA Segmentation (oil, brine, and rock, are in black, gray, and white, respectively). <a href="https://www.jove.com/files/ftp_upload/57915/57915fig5large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Contact angle distribution, frequency histogram chart; three sample comparisons, surface analysis." class="xfigimg" src="/files/ftp_upload/57915/57915fig6.jpg" data-altupdatedat="1788250015000" data-alt="Figure 6"> 
Figure 6: Distributions of the contact angle measurement of the three mini-samples. Sample 1 has a mean contact angle of 77° ± 21° with 462,000 values shown in blue. Sample 2 has a mean contact angle of 104° ± 26° with 1.41 million values shown in gray. Sample 3 has a mean contact angle of 94° ± 24° with 769,000 values shown in red. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig6large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Segmented image analysis showing extraction and smoothing of surfaces, highlighting three-phase contact line and contact angle measurement in rock pore structure." class="xfigimg" src="/files/ftp_upload/57915/57915fig7.jpg" data-altupdatedat="1788250015000" data-alt="Figure 7"> 
Figure 7: The workflow for an automated contact angle measurement. (a) This is a three-dimensional segmented image showing brine in blue and oil in red, while rock is rendered transparent. (b) This panel shows extracted surfaces of the whole image. The oil/brine surfaces are shown in green, while the oil/rock surfaces are shown in red. (c) This panel shows the smoothed surfaces of the whole image. (d) This panel shows the three-phase contact line of the whole image. (e) This is an example of the smoothed surfaces of an oil ganglion highlighted by the black square. (f) This panel shows the three-phase contact line of the highlighted oil ganglion. (g) This is an example of a single contact angle measuring at point i (highlighted in panel f). The oil/brine, oil/rock, and brine/rock surfaces are shown in green, red, and blue, respectively. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig7large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Soil texture analysis; grayscale segmentation images; microscopy; 220μm, 320μm scale comparison." class="xfigimg" src="/files/ftp_upload/57915/57915fig8.jpg" data-altupdatedat="1788250015000" data-alt="Figure 8"> 
Figure 8: Three sub-volumes extracted from the three mini-samples. (a) This panel shows the sub-volume extracted from mini-sample 1 (weakly water-wet). (b) This panel shows the sub-volume extracted from mini-sample 2 (mixed-wet). (c) This panel shows the sub-volume extracted from mini-sample 3 (mixed-wet). <a href="https://www.jove.com/files/ftp_upload/57915/57915fig8large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="3D microstructure segmentation diagram, visualizing cellular geometry at 100 μm scale, angle 61°." class="xfigimg" src="/files/ftp_upload/57915/57915fig9.jpg" data-altupdatedat="1788250015000" data-alt="Figure 9"> 
Figure 9: A one-to-one contact angle measurement workflow. (a) This is a visualization of a randomly selected contact angle point (60°) measured using the automated code (the image is obtained from the data visualization software used). (b) This panel shows how to identify the location of the same point using the data visualization and analysis software. (c) This panel shows how to conduct a manual contact angle measurement at the same location. (d) This is an example of the manually measured contact angle point at the same location (61°). <a href="https://www.jove.com/files/ftp_upload/57915/57915fig9large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Automatic vs. manual angle correlation graph, data points plotted along a linear fit." class="xfigimg" src="/files/ftp_upload/57915/57915fig10.jpg" data-altupdatedat="1788250015000" data-alt="Figure 10"> 
Figure 10: Automated contact angle measurements compared to the manual contact angle measurements at the same locations of the sub-volume from mini-sample 1. The values were measured following the procedure described in Figure 9. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig10large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="Oil recovery vs. contact angle graph; shows three samples, indicating recovery efficiency trend." class="xfigimg" src="/files/ftp_upload/57915/57915fig11.jpg" data-altupdatedat="1788250015000" data-alt="Figure 11"> 
Figure 11: Oil recovery as a function of wettability. The oil recoveries of sample 1, 2, and 3 are 67.1%, 58.6%, and 84.0%, respectively. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig11large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>
<img alt="3D reconstruction analysis diagrams, particle distribution in microvolumes, color-coded surfaces." class="xfigimg" src="/files/ftp_upload/57915/57915fig12.jpg" data-altupdatedat="1788250015000" data-alt="Figure 12"> 
Figure 12: The remaining oil morphology for different wetting conditions. (a) In sample 1 (weakly water-wet), the remaining oil was trapped at the center of the pores as disconnected ganglia with quasi-spherical shapes. Panels (b) and (c) show how in samples 2 and 3 (mixed-wet), the remaining oil was left in connected, thin sheet-like structures in small pores and crevices. The different colors represent disconnected oil ganglia. <a href="https://www.jove.com/files/ftp_upload/57915/57915fig12large.jpg" target="_blank">Please click here to view a larger version of this figure.</a>

This protocol is presented to characterize the complex wetting conditions of an opaque porous medium (hydrocarbon reservoir rock) using three-dimensional images obtained by X-ray microtomography at subsurface conditions.

In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to ...

pore-scale-imaging-characterization-hydrocarbon-reservoir-rock

Research

JoVE Journal

Engineering

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Learn to characterize hydrocarbon reservoir rock wettability using X-ray microtomography under subsurface conditions. This method enables detailed analysis of multiphase flow for enhanced oil recovery applications.

Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography (Video) | JoVE Journal

Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography

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