Introduction
Many macroscopic oil recovery laws and fluid seepage characteristics of reservoirs are the comprehensive reflection of the micro-structure of reservoir rock and the transport of various phases of fluids at the pore scale, i.e., the micro-structure of the rock and the property of the fluid are fundamental and the macroscopic characteristics are appearance. In order to enhance oil recovery of oilfields at high water-cut stage, it is necessary not only to study the reservoirs at the macroscopic scale and production dynamics, but also to describe the dynamic characteristics and study seepage laws of multiphase fluid in the pores of the reservoir at the microscopic pore scale.
Heterogeneity of the reservoir has a great influence on the macroscopic sweep efficiency and the producing degree of the crude oil in the area that has been swept is closely related to the heterogeneity of the microscopic pore structure. The microscopic pore structure involves the sizes of pores and throats, pore coordination, and pore connectivity etc. Even if relatively homogeneous macroscopically, a reservoir would inevitably have some microscopic heterogeneity. Conventional research methods cannot describe the influence of microscopic heterogeneity on the production of crude oil[1,2], for example, the basic rock slice or glass etching model are quite ideal[3,4,5,6,7], but cannot show the producing degree and distribution characteristics of the residual oil under three-dimensional space. In the conventional experiments, the study on heterogeneity of pore structure basically stops at the qualitative comparison level, and the influence of heterogeneity of microscopic pore structure on the production of crude oil and distribution and morphology of remaining oil cannot be quantitatively characterized.
In recent years, the development and application of CT technology in petroleum engineering has promoted the quantitative characterization of microscopic pore-throat structure[8,9,10,11]. In this study, CT scan imaging was performed on cores with different types of pore structures selected from the cores of the Donghe sandstone reservoir in the Hudson Oilfield, Tarim Basin, Xinjiang, by mean of Micro-CT scanning technology, to characterize the microscopic heterogeneity of pore structures and check the influence of heterogeneity of pore throat on the production of remaining oil and the distribution and morphology of microscopic residual oil, and find out the formation mechanism of microscopic residual oil in the reservoir.
1. Reservoir types
The Donghe sandstone reservoir of Hudson Oilfield Shoreline is weak in heterogeneity, but diversified in microscopic pore-throat structure[12,13]. Li Qiang et al.[14] concluded through study that there were 6 types of pore-throat combinations in this area. However, this classification standard does not quantify the range of pore-throat radius, and the radius of throat plays a decisive role on permeability[15]. Therefore, the classification neglecting heterogeneity of pore-throat structure is not conducive to the study of oil-water two-phase flow. Although macroscopically, the influence of pore-throat structure on the heterogeneity of the entire reservoir is weak, but for the microscopic remaining oil, the influence is great. The radius, distribution, proportion and connectivity of pore-throats will greatly affect the oil-water flow path, and thus the producing of residual oil at the pore-scale.
As shown in Table 1, according to the radius of the throat and permeability measured by the mercury injection curve at the site, the reservoirs in this area are divided into three classes: Class I, medium-thin throat high permeability type, Class II, thin throat medium permeability type and Class III, thin-tiny throat low permeability type. Comparing the saturation of remaining oil in the cores taken from these three types of reservoirs, it was found that the core with thin throat medium permeability, class II, is the lowest in residual oil saturation, rather than the class I core with middle-thin throat high permeability, which indicates it is difficult to describe the producing process and producing degree of crude oil and the distribution of the remaining oil by using porosity and permeability only.
Table 1 Classification results of Donghe sandstone reservoirs with different pore-throat structures in Hadeson Oilfield.
| Type of pore- throat structure | Porosity/% | Permeability/ 10-3 μm2 | Range of pore-throat radius/μm | Range of porosity/% | Range of permeability/ 10-3 μm2 | Classification result | Average saturation of residual oil /% | ||
|---|---|---|---|---|---|---|---|---|---|
| Maximum pore- throat radius | Average pore radius | Average throat radius | |||||||
| Large pore, medium throat | 22.90 | 1 492.6 | >20 | >15 | >8 | >20 | >500 | Class I: Medium- thin throat high permeability type | 37.4 |
| Medium pore, medium throat | 18.48 | 812.5 | |||||||
| Large pore, thin throat | 19.38 | 1 088.0 | |||||||
| Medium pore, thin throat | 17.43 | 270.2 | 5-20 | 5-15 | 2-8 | 15-20 | 100-500 | Class II: Thin throat medium permeability type | 32.1 |
| Small pore, thin throat | 9.15 | 26.2 | <5 | <5 | <2 | <15 | <100 | Class III: Thin- tiny throat low permeability type | 46.4 |
| Small pore, tiny throat | 4.05 | 1.4 | |||||||
In view of this issue, four cores from three types of reservoirs were selected for water flooding experiments and CT scanning, and then the influence of the heterogeneity of pore-throat structure on the distribution of microscopic residual oil in three dimensions were examined.
2. Design of CT scanning experimental
2.1. Experimental materials
(1) Cores: The four small cores are all Carboniferous marine clastic fine sandstone of the East River block of the Hudson Oilfield in the Tarim Basin drilled from different conventional 1.0 inch cores. The wettability and seepage physical properties of the cores were measured at room temperature and atmospheric pressure by the infiltration experiments, as shown in Table 2.
Table 2 Main petrophysical properties of the cores.
| Num- ber | Reservoir type | Wettability | Poro- sity/% | Permeability/10-3 μm2 | Diameter/mm | Length/ mm |
|---|---|---|---|---|---|---|
| No.1 | Class I | Water wet | 21.7 | 763.3 | 7.64 | 50 |
| No.2 | Class II | Water wet | 18.6 | 445.5 | 7.48 | 50 |
| No.3 | Class II | Water wet | 17.9 | 476.4 | 7.67 | 50 |
| No.4 | Class III | Water wet | 13.5 | 65.7 | 7.78 | 50 |
(2) Fluids: The experimental fluids were white oil and water, and NaI was added to the water at 10%wt to increase the contrast of the oil and water gray values in the scanned image. The interfacial tension of oil and water was 0.074 N/m. The viscosity and density of the oil at room temperature and atmospheric pressure were 8.6 mPa•s and 828 kg/m3, respectively.
2.2. Experimental procedure
The same experiment was conducted on all the four cores, and the experimental apparatus diagram is shown in Fig. 1. The carbon fiber core holder used in the experiment (Fig. 2) has the function of online in-situ CT scanning under high temperature and high pressure[16,17]. Before each time of CT scanning, the pump was turned off to stop fluid injection. All scans were in-situ CT scans, the core was not moved, and the core was placed vertically on the sample stage. The X-ray scanning position was 25 mm from the bottom of the core. The CT scanning resolution was 2.1 μm, the scanning field of view was about 3.5 mm × 3.5 mm × 3.0 mm, and each time of CT scanning took about 35 min.
Fig. 1.
Fig. 1.
Schematic diagram of experiments.
Fig. 2.
Fig. 2.
Schematic diagram of carbon fibre core holder.
The experimental procedure was as follows: (1) The core was washed and dried and placed in the core holder. The temperature was heated to 55 °C. The pore pressure was increased to 8 MPa and the confining pressure to 12 MPa and stabilized for 5 hours by using the back-pressure pump. The first CT scanning was performed on the dry core. (2) After vacuumed, the core was saturated with water by injecting 100 PV of water at low-speed. Then 100 PV of oil was injected at a constant flow rate of 0.02 mL/min to displace the water, and the second CT scanning was performed after stabilization. (3) At a constant rate of 0.02 mL/min, 1 PV of water was injected to displace oil, then the third CT scanning was performed. (4) At the same flow rate, 50 PV of water was injected to displace the oil and the fourth CT scanning was performed.
2.3. Image processing
After reconstruction, the scanning image was analyzed with professional image processing software. Before segmentation, the images were processed by edge hardening correction and removed of ring artifacts. Then Non-Local Means filter was used to reduce noise and enhance the contrast between the phases[18].
Fig. 3a is a slice of dry core, in which the gray gradient at the interface between the pores and the particles is larger, making it easy to obtain an accurate pore-throat structure through segmentation (Fig. 3b). This image can be used to analyze the pore structure and assist in the image segmentation containing multiphase fluids (Fig. 3c). Although the image containing multiphase fluid can also be divided into three phases directly, since the gray gradient at the interface of each phase is not large, the error of dividing by the segmentation threshold is large. Therefore, only image containing the oil and water two phases with obvious contrast in the pores can be obtained by subtracting Fig. 3c from Fig. 3b to remove the particles (Fig. 3d). Then the image with a higher precision was obtained by segmentation of the three phases (Fig. 3e). Finally, the three-dimensional structure of water and oil phases were extracted (Fig. 3f), to calculate and analyze other physical properties.
Fig. 3.
Fig. 3.
Image processing workflow (diameter=2.94 mm).
3. Characterization of micro-heterogeneity of pore-throat structure
3.1. Representative elementary volume
Representative elementary volume (REV) refers to the smallest core element which can characterize the physical properties of the core. In other words, the physical properties of the minimum element are the same as those of the entire core. Before analyzing properties of the core, it is necessary to determine the size of REV in the scanning area[19]. The research mainly involves fluid changes in the pores. Therefore, after extracting the pore-throat structure from the scanning data, a series of three-dimensional volumes need to be cut out (with the side of the data cube gradually increasing from 0.105 mm to 2.310 mm) to calculate the porosity of each data cube separately (Fig. 4). The calculation results show that with the data volume increasing, the curve of each parameter becomes horizontal gradually, indicating that the scanning scope is larger than the REV and the studied area can represent the entire core.
Fig. 4.
Fig. 4.
Variation of porosity with various data volumes from core samples.
3.2. Pore-throat structure characteristics
Classic geometric and topology network extraction methods were adopted to extract the pore network structure[20]. Fig. 5 shows the pore network structure results of No.1 core. By analyzing the pore network model, the radius distribution, shape factor, coordination number, and connectivity of pore-throats etc. were obtained.
Fig. 5.
Fig. 5.
Extraction of pore network model (Size of data = 1000 × 1000×1000voxel3).
Fig. 6 shows the number of pores and throats in core scanning region calculated by the pore network model. It can be seen that No.1 core with higher porosity and permeability has the smallest number of pores and throats while the tighter No.4 core has the largest number of pores and throats. Belonging to class II reservoir, No.2 and No.3 cores have similar number of pores and throats falling in between the four cores.
Fig. 6.
Fig. 6.
The number of pores and throats of cores.
The throats determine the connectivity and permeability of the core basically, therefore have a great impact on the flow path of the crude oil. Through the bat-stick pore network model, the radius and length of each throat can be calculated, and then the number of throats in the statistical range can be obtained. In general, distribution frequency of throats only counts the number of throats, however, the throats are different in length and large in number, so this kind of statistics can’t characterize the distribution of pore-throat volume accurately. The statistical frequency method has poor accuracy in characterizing the distribution of throats. Through calculating radius and length of throats, the volume of throats in the statistical range is calculated, and then the proportion of the volume of different radius throats is obtained, and the distribution of the throat in the core can be accurately characterized.
Fig. 7 shows the distribution of throat volume in each radius in the four cores. The No.1 core has the largest range of throats radius (0-40 μm), great fluctuation in proportion of volume of different radius throats, and an average throat radius of 15.06 μm, meeting the standard of Class I reservoir. With an average throat radius of 6.83 μm and 7.71 μm, respectively, No.2 and No.3 cores are both Class II reservoir with thin throats and moderate permeability. In comparison, No.3 core has a wider range of throat radius between 0 μm and 20 μm and a higher proportion of larger throats (10-20 μm). No.2 core has a narrower range of throat radius of 0-10 μm. No.4 core has the narrowest range of throat radius (0-6 μm) and an average throat radius of only 2.31 μm, which is slightly higher than the standard of throat distribution of Class III reservoir.
Fig. 7.
Fig. 7.
The distribution of volume corresponding to different radius of throats.
The pore throat coordination number can reflect the physical properties of the core, such as pore structure, connectivity etc. Fig. 8 shows the coordination numbers of the four cores. It can be seen from the figure that the No.2 and No.3 cores have the widest range of coordination number distribution range of 0-20, and the high-frequency coordination numbers of 2-5. The No.1 core has a moderate range of pore-throat coordination number range of 1-13 and the high-frequency coordination numbers of 1-4. The No. 4 core has the narrowest range of coordination number of 1-10, and the high-frequency coordination numbers of 1-3. It can be seen that the cores with good macroscopic porosity and permeability have not necessarily good connectivity and homogeneity (such as No.1 core). The cores of the class II reservoirs in the four cores (such as No. 2 and No. 3) have a better pore structure more favorable for fluid flow.
Fig. 8.
Fig. 8.
The distribution of pore coordination number.
Pore connectivity can be described by the Euler characteristic. The pore connectivity equation proposed by Vogel et al.[21] was used to calculate the Euler characteristic:
Pore connectivity curves of the four cores were calculated by equation (1) (Fig. 9). As the radius of the pore-throat increases, the value of the Euler characteristic increases first, then decreases after reaching the highest value, and finally approaches zero. From the variation trend of the curves, No.2 and No.3 cores have the most narrow variation range of the Euler characteristic, and the slowest decline after reaching the highest point. This indicates that the pore connectivity changes little and the pore-throat structure has weak heterogeneity with the increase of pore-throat radius. Comparison of the variation shape of the curves show the No. 3 core has slightly weaker heterogeneity of microscopic pore-throat structure than No. 2 core. In contrast, the No.1 and No.4 cores have a larger range of variation of the Euler characteristic, and a fast drop of Euler characteristic after reaching the highest point, showing a strong microscopic pore-throat structure heterogeneity, and higher heterogeneity of No.4 core.
Fig. 9.
Fig. 9.
The distribution curves of pore connectivity.
3.3. Fractal characterization of pore-throat structure
In the fractal dimension model, there is negative linear relationship between the capillary pressure and fluid saturation in the double logarithmic coordinate system[24]. This feature can be used to verify whether the data of pressure mercury capillary pressure meets the fractal characteristic. Fig. 10 shows the distribution of pore-throat radius and fractal characteristics of pore structure of the four cores. The fitting equation and fractal dimension are shown in Table 3. It can be seen that, (1) in the double logarithmic coordinate system, the fractal feature of the pore structure presented a “double-segment type” in No.1 core, and the corresponding curve of the pore-throat radius shows a bimodal shape, indicating that the pore-throat structure is complex and strong in microscopic heterogeneity. The low-pressure section of the fractal feature curve has a wide range, and high-pressure section has a narrow range, indicating that the distribution range of the large pore-throats is wide, and the distribution range of the small pore throats is narrow. The fractal dimension of large pore-throats (2.64) is larger than the fractal dimension of small pore-throats (2.07), indicating that the microstructure of large pore-throats is more heterogeneous; (2) the fractal feature curves of the pore structure of No.2 and No.3 cores are “single-segment type”, and the distribution of pore-throat radius is single-peak and concentrated. The fractal dimension of No. 2 core is close to that of No. 3 core (2.31 and 2.19 respectively) and smaller than No. 1 core, which implies No.2 and No.3 cores have weaker heterogeneity of pore-throat structure than No. 1 core; (3) the pore structure of No.4 core also has “single-segment type” fractal feature curve, more concentrated pore-throat radius distribution, and larger fractal dimension (2.48), meaning stronger micro-heterogeneity of pore-throat and more complex pore-throat structure. Comprehensively, No.1 core has the strongest heterogeneity of micro pore structure, followed by No.4, No.2, and No.3.
Fig. 10.
Fig. 10.
The distribution of pore-throat radius and fractal characteristics of pore structure.
Table 3 Fitting equation and fractal dimension of fractal feature.
| Core No. | Fitting equation | Correlation | Fractal dimension |
|---|---|---|---|
| No.1(Large pore-throat) | $S=69.00{{p}_{\text{c}}}^{-0.36}$ | 1.00 | 2.64 |
| No.1(Small pore-throat) | $S=359.57{{p}_{\text{c}}}^{-0.93}$ | 0.99 | 2.07 |
| No.2 | $S=122.02p{{_{\text{c}}^{{}}}^{-0.69}}$ | 0.95 | 2.31 |
| No.3 | $S=114.40{{p}_{\text{c}}}^{-0.81}$ | 0.98 | 2.19 |
| No.4 | $S=40.01{{p}_{\text{c}}}^{-0.52}$ | 0.96 | 2.48 |
In conclusion, the microscopic heterogeneity of the core can’t be quantitatively characterized by merely porosity and permeability. In the actual seepage process, the reservoir with good macroscopic porosity and permeability may have poor connectivity of pore throats and strong heterogeneity in local parts. In this kind of reservoir, some of the large pores and large throats may form a favorable flow channel controlling fluid flow, making the reservoir show better seepage characteristics on the whole. But the production of oil in such reservoirs is extremely unbalanced. The crude oil in the and near the favorable channel can be effectively produced, however, but the oil in area with poor connectivity or far away from the favorable channel is difficult to produce or cannot be produced. Therefore, it is necessary to introduce parameters such as throat radius, pore coordination number, pore-throat connectivity factor and fractal characteristic to accurately quantify the microscopic physical properties of the reservoir and describe the heterogeneity of the pore-throat structure in order to better analyze the production of crude oil and the distribution of remaining oil.
4. Relationship between microscopic heterogeneity and remaining oil
4.1. Morphological changes of oil clusters (droplets)
The oil phase in scan images of the four cores was extracted and the oil saturations in three stages, initial stage, 1 pore volume (PV) water flooding stage and 50 PV water flooding stage were calculated, as shown in Fig. 11. It can be seen that the No.4 core has the lowest initial oil saturation due to its strong heterogeneity. Except No. 4 core, most of the crude oil was produced after 1 PV water flooding from the other 3 cores. After 50 PV water flooding, No. 3 core has the lowest and No.4 core has the highest residual oil saturation. It can be seen that the macroscopic physical properties of the reservoir and the microscopic heterogeneity of the pore structure determine the distribution of remaining oil, and the influence of the microscopic heterogeneity of the pore structure is greater. The residual oil saturation of No.1 to No.4 core were 33.6%, 25.3%, 18.7%, and 46.3%, respectively.
Fig. 11.
Fig. 11.
Variations of oil saturation in the process of water flooding of the cores.
By extracting the oil phase in the scan images, the morphological changes of oil clusters (droplets) during water flooding can be observed clearly (Fig. 12, the different colors in the figure represent independent oil clusters (droplets)). In the initial oil-saturated state, the oil clusters are the continuous phase, the oil phase is gradually dispersed after 1 PV water flooding, transforming to discontinuous phase. After 50 PV water flooding, the residual oil mainly exists in non-continuous phase such as membrane and droplet[25].
Fig. 12.
Fig. 12.
Morphological changes of oil clusters (droplets) during water flooding in the No.3 core.
Fig. 13 shows the changes in the number and average volume of oil clusters (droplets) with water saturation in the core scanning region during the water flooding process. During the water flooding process, the continuous oil phase in the core pores is gradually divided by the water phase to form isolated oil clusters (droplets). The speed of the division and the number of oil clusters (droplets) are closely related to the micro-heterogeneity of the pore-throat structure and the distribution of the pore throat radius: (1) The No.4 core, with the strongest microscopic heterogeneity of pore-throat structure and uneven distribution of pore-throat radius, witnessed the fastest speed of segmentation, the number of oil clusters (droplets) much larger than the other three cores, and the smallest average volume of oil clusters (droplets) in the whole flooding process. (2) The number of oil clusters (droplets) in No.1, No.2 and No.3 cores were almost equal in the initial stage and increased significantly with the rise of water saturation. With weaker microscopic heterogeneity of pore-throat structure, No.3 core had the increasing rate of number of and the decreasing rate of average volume of oil clusters (droplets) much lower than the other two cores. (3) In the process of 1 PV water flooding of No. 3 core, the crude oil maintained continuous, the number of oil clusters (droplets) increased little, the mobility of the fluid was good, the relative permeability of the reservoir was high and the subsequent recovery degree of crude oil was the highest[26]. (4) Although Core No.1 has higher permeability, due to the strongest micro heterogeneity of pore-throat structure, after 1 PV water flooding, the oil phase was divided by the water phase faster than No. 2 and No. 3 cores, and the number of oil clusters (droplets) is the most, resulting in more crude oil left in the unswept area in the later stage of water flooding.
Fig. 13.
Fig. 13.
Variation of number and average volume of remaining oil clusters (droplets).
It can be seen that macroscopic porosity-permeability and microscopic heterogeneity of pore-throat structure have different degrees of effects on the migration of oil phase and the distribution of remaining oil, and the influence of micro heterogeneity pore-throat structure is stronger.
4.2. Oil-water flow paths
To discuss the effect of microscopic heterogeneity pore- throat structure on remaining oil distribution specifically, No.2 and No.3 cores with very close porosity and permeability were selected to analyze their oil-water flow paths. In order to overcome the defects of few CT scans (only three times) in the water flooding experiment and demonstrate the initial flow path of the injected water more clearly, the two-phase flow in the pore network model of the two cores was simulated, and four nodes were selected for comparison (Fig. 14): (1) After saturated with oil, the No.3 core was better saturated, with the irreducible water distributed evenly. In contrast, in No.2 core with slightly stronger heterogeneity, the irreducible water existed in the large pores after saturated with oil. (2) It can be clearly seen that favorable paths occurred in Core No.2 and part of the water advanced first after 0.5PV of water was injected. The continuous oil phase was broken up into small oil clusters (droplets) by the water phase in the initial water flooding, resulting in a rapid increase in the number of oil droplets; the water displacement was more uniform and the microscopic sweep efficiency was higher in Core No.3. (3) After waterflooding of 1PV, a main seepage network composed of large pore-throats was formed in Core No.2, the oil phase in some small pores migrated to the large pores by imbibition and the displacement efficiency and sweep efficiency of micros pore-throat were poor; the remaining oil was trapped in flakes (in largely continuous phase). In the No.3 core with weaker microscopic heterogeneity of pore-throat structure, the water phase was distributed evenly, and the water advanced stably during the whole flooding process, and the displacement efficiency was high. (4) After 50 PV water was injected, the remaining oil in the No. 3 core was mostly driven out, while some of the remaining oil in the No. 2 core was trapped in the large pores. In general, the higher the microscopic heterogeneity of the pore-throat structure, the larger the ratio of the pore volume in the flow path to the total pore volume, the more even the remaining oil distribution and the higher the remaining oil saturation will be.
Fig. 14.
Fig. 14.
Oil phase production and residual oil distribution under different water injection volume.
4.3. Type of residual oil
During water flooding process, the oil phase is constantly divided and dispersed by the water phase and changed from continuous phase to discontinuous phase. The micro heterogeneity of pore-throat structure has great influence on the saturation distribution, flow path and number of oil clusters (droplets) of oil phase in the process of water flooding. Li Junjian et al.[26-27] classified the remaining oil into five shapes: membrane, droplet, multi-pore, column and cluster according to Euler number, shape factor and contact ratio. Among them, the cluster shape of oil is a continuous phase and the rest four shapes of oil are discontinuous phases.
According to this classification, the distribution of these five types of remaining oil in No. 2 and No.3 cores are shown in Fig. 15. The proportions of different types of remaining oil in the total remaining oil are shown in Table 4. It can be seen that: (1) In the No.2 core with stronger heterogeneity of pore-throat structure, most of the remaining oil is continuous phase, mainly in cluster, accounting for 56.5% of the remaining oil. (2) In the No.3 core with weaker heterogeneity, the residual oil is mainly in the form of discontinuous phase, largely in multi-pore shape, making up 53.5% of the remaining oil, while the continuous phase oil in cluster shape only accounts for 20.1%.
Fig. 15.
Fig. 15.
The morphologies of the five types residual oil at the end of water-flooding in No.2 and No.3 cores (above: No. 2 core; below: No.3 core).
Table 4 Distribution of different types of remaining oil.
| Core No. | Proportion of one type of remaining oil in total remaining oil/% | ||||
|---|---|---|---|---|---|
| Membrane | Droplet | Column | Multi-pore | Cluster | |
| No.2 | 10.9 | 0.7 | 1.6 | 30.3 | 56.5 |
| No.3 | 6.7 | 10.5 | 9.2 | 53.5 | 20.1 |
At present, the mainstream view is that microscopically the discontinuous residual oil phase dominates in the water- flooded layer in the high-water-cut period of the water flooding development oilfields. The focus of this type reservoir to enhance oil recovery is to increase the effective producing degree of the residual oil in the discontinuous phase. Through this experimental research, it is found that microscopically most of the residual oil in the reservoirs with stronger heterogeneity of pore-throat structure appears in continuous phase in local parts in the middle or high water-cut period. How to improve the effective producing rate of this type of remaining oil will be the main direction of future research.
4.4. Identification of continuity of remaining oil
When studying the process of displacement of reservoir fluid by invasion phase under different heterogeneity and wetting angle, Blunt[20] did not consider the permeability of porous media and the capillary number. The real reservoirs are complex and diverse, and the permeability is closely related to the heterogeneity, and the capillary number of displacement phase is also closely related to the phase state of the displaced phase. Based on the study of Blunt, considering the permeability, capillary number, and micro heterogeneity of pore- throat structure, the final residual state of the displaced oil phase in water wet medium is classified into three types (Fig. 16, the phase dominated in the figure means that the saturation of this oil phase is high): (1) When the heterogeneity is weak the permeability is high, and capillary number is small, the displacing front advances evenly, the oil phase migrating in the pores keeps in good continuity, so oil recovery would be high, with little residual oil left mainly in discontinuous phase. (2) When the capillary number increases to a certain level, fingering would appear, and the residual oil comes in a continuous sheet shape in local parts, at this point, the dispersed phase and continuous phase coexist. (3) With the increase of heterogeneity and decrease of permeability, seepage mainly occurs in the favorable paths, so the microscopic sweep efficiency is lower, and the remaining oil mainly exists in continuous phase. In this case, simply changing the displacement pressure to change the displacement speed doesn’t work well in enhancing oil recovery. It can be found that the distribution of remaining oil is mainly related to the absolute permeability, capillary number and heterogeneity of microscopic pore-throat structure. Fig. 16 shows the relationship between these three factors and the remaining oil distribution, based on which the continuity of the remaining oil distribution can be identified and corresponding measures can be taken to improve oil recovery.
Fig. 16.
Fig. 16.
Relationship between residual oil distribution and macroscopic and microscopic physical properties of reservoir.
5. Conclusions
Even cores with the same macroscopic porosity and permeability can still differ widely in microscopic heterogeneity of pore-throat structure. The macroscopic porosity and permeability, and microscopic heterogeneity of pore-throat structure affect the migration of oil phase and the distribution of remaining oil to different extent. The stronger the heterogeneity, the more water would seep along the favorable paths, and the remaining oil would be trapped in the small pores in flakes; the more the number of oil clusters (droplets) would be formed during the displacement process, the smaller the average volume would be, and the remaining oil would mainly appear in continuous phase of cluster shape with higher saturation. The weaker the heterogeneity, the higher the sweeping efficiency in the pore-throats would be, and the remaining oil would come in discontinuous phase in pores.
The distribution of microscopic residual oil is related to the absolute permeability, capillary number and microscopic heterogeneity. The continuity identification plate of microscopic residual oil thus established can well describe the relationships between these three factors and the remaining oil distribution and accurately identify the continuity of remaining oil distribution.
Nomenclature
D—pore fractal dimension, dimensionless;
NB,r—the number of pores with radius greater than r;
NN,r—the number of throats with a radius greater than r;
Pc—capillary pressure corresponding to the pore-throat radius r, MPa;
Pmin—capillary pressure corresponding to the largest pore-throat radius r, MPa;
r—pore-throat radius, μm;
S—fluid saturation, %;
V—pore volume, μm3;
${{\chi }_{\text{V,}r}}$— Euler characteristic, μm-3.
Reference
Micro anisotropies influences distribution of micro scale residual oil.
Micro anisotropy refers to sand porosity, throat size, homogenous level, and coordination relations of porosity and throat and interconnection degree. It has direct effects on displacement efficiency of inputted water and controls distribution of micro scale residual oil in porosity structure. We regard Hu12 Block as research region in the article and select six parameters such as maximum interconnection radius of porosity and throat, median radius of porosity and throat, etc. We use parameters to explain how micro anisotropies influences micro scale residual oil during water injection and natural depletion exploitation.
Heterogeneity of sandy conglomerate reservoir and its influence on remaining oil distribution: A case study from Badaowan Formation in the mid-west of block Ⅱ in Karamay Oilfield
At present,the voidage-injection imbalance,interlayer interference and in-layer interference leaded by the reservoir heterogeneity are extremely highlighted during the production tail of sandy conglomerate reservoir in the mid-fan of alluvial fan.Taking the Jurassic Badaowan Formation in mid-west of the block II in Karamay Oilfield as an example,this paper studied the reservoir heterogeneity of alluvial fan sandy conglomerate reservoir.Based on outcrop observation,core description,electrofacies analysis,the single sand body description technique was used to divide the reservoir into 4 types of microfacies-lithofacies single sand body.Combining with the macroscopic and microscopic heterogeneity in different single sand body,the remaining oil were divided into 3 enriched types: Ⅰ-type braided channel gritstone facies,which has mesopore and small throat texture;Ⅱ-type braided channel fine sandstone facies,which has small pore and small throat texture;Ⅲ-type braided channel sandy conglomerate facies,which has small pore and fine throat texture.It is concluded that the type Ⅲ has the best water flooding effect and should be the main object of stabilizing oil production and controlling water cut,and the type I and Ⅱ,where the properties are relatively worse and the heterogeneity is stronger,should be the next potential target.Using this method of"recognizing the reservoir hetero-geneity and resolving it" as the breakthrough point to analyze the single sand body and the heterogeneity,which can provide better reference for forecasting the distribution of remaining oil in the sandy conglomerate reservoir.
Percolation characteristics investigation of microscopic remaining oil in water flooding reservoir with ultra-high water cut.
The study of remaining oil percolation characteristics under microscopic pore scale plays an important role in enhanced oil recovery for ultra-high water cut period water flooding reservoir. In this paper, microscopic glass-etching model experiments and computer image processing recognition techniques are combined to re-classify the microscopic remaining oil flowing patterns to analyze the flowing shape and the connect-relationship among the oil, water and rock. Research result indicates all the remaining oil in ultra-high water cut period can be classified into five categories, clustered stream, multi-porous stream, columnar stream,membranous stream and droplet stream. Among of the five categories, clustered stream possess the largest proportion and is also the main factor of relative permeability curves re-curved. Meanwhile, with water saturation rising, clustered stream gradually transforms into other patterns like multi-porous stream, columnar stream, membranous stream and droplet stream. The flow rules of the remaining oil and the reason of the non-linear percolation curve are explained microscopically, which provides a guiding for the development and recovery of water flooding reservoir with ultra-high water cut.
Distribution of remaining oil by water flooding in heterogeneous reservoirs and indoor simulation study for its potential tapping
In order to tap the potentiality of the remaining oil from water flooded layer of the long-term water flooding oil fields, a visualized heterogeneous model was developed through analyses of the pore structure and the size of pore throats of the reservoirs, which was used to carry out indoor observation of the formation process of water flooding remaining oil by way of video and analysis was conducted of its distribution characteristics and way of thinking of potential tapping techniques. Based on the material properties of elastic particles in throat structure, the screening principle for the diameter of this elastic particle which was in match with reservoir throat was presented. And through test of profile control of particles after water flooding in heterogeneous cores, evaluation was made on the dynamic plugging capacity and profile control effectiveness of this elastic particle. The results show that heterogeneity occurs commonly in oilfield reservoirs, which affects the distribution of water flooding remaining oil; the remaining oil in flooded layers is mainly heterogeneous remaining oil, mostly found in local low-permeability zones of the layers and distributed dispersedly, so its potential tapping will be mainly by improving the microscopic sweep efficiency; the plugging strength of elastic particles on throat increases first and then keeps constant with the enlarging of elastic particle diameter-when the ratio of particle diameter with throat diameter is over 3, the particles will be broken in throat structure; when plugging the water channel in water flooded layer and tapping the remaining oil, the elastic particle works effectively whose diameter is three times of the size of throat.
Microscopic heterogeneity characteristics of marine clastic reservoirs and effect to remaining oil distribution in high water cut stage
ABSTRACT Using core fine description, cast thin section image analysis and X-ray diffraction of clay minerals and other means, the microscopic heterogeneity of marine clastic reservoir of lower Carboniferous reservoir in TLM basin was studied, and through the real core water flooding experiment the influence of micro-heterogeneity on the remaining oil distribution was analyzed. The study suggests that, depending on the type of pore throat, the pore throat portfolio type and microstructure type, microscopic heterogeneity of the reservoir can be divided into three types of type I, type II and III. Type I heterogeneous has homogeneous coarse-grained structure, and has the development of two pore throat combination types of secondary dissolution type and primary porosity type. In the Flooding process, the phenomenon of flow around is obvious, and it has a patchy remaining oil enrichment in this heterogeneous type. Type II heterogeneity has calcium plaque coarse structure, and develops two pore throat combination types of secondary dissolution type and secondary calcium plaque-type. In the process of oil displacement, by effect of calcium plaque shelter, the remaining oil within heterogeneity was patchy enrichment. Type III heterogeneous develops homogeneous fine-grained structure and primary porosity pore throat combination, and the remaining oil was even patchy distribution. Among the three heterogeneous types, type I heterogeneous has the largest residual oil ratio, type II followed, typeIII being minimum. Vertically, there is a evolution of type III to typeII to typeI bottom-up, and the thickness is successively larger from type III to typeI. On the plane, the proportion of remaining oil of type I heterogeneity is gradually increased from the northwest to the southeast of the study area, and it is the opposite for type II and type III heterogeneous.
Characterization of micro-nano pore networks in shale oil reservoirs of Paleogene Shahejie Formation in Dongying Sag of Bohai Bay Basin, East China
DOI:10.1016/S1876-3804(17)30083-6
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[Cited within: 1]
For typical blocky,laminated and bedded mudrock samples from the Paleogene Shahejie Formation in the Dongying Sag of Bohai Bay Basin,this work systematically focuses on their structure characterization of multiple micro-nano pore networks.A use of mercury injection capillary pressure (MICP) documented the presence of multiple μm-nm pore networks,and obtained their respective porosity,permeability and tortuosity.Different sample sizes (500-841 μm GRI fractions,1 cm-sized cubes,and 2.54 cm in diameter and 2-3 cm in height core plugs) and approaches (low-pressure N_2 gas physisorption,GRI matrix permeability,MICP,heliumpy cnometry,and pulse decay permeameter) were used to measure pore size distribution,porosity and permeability.The average porosity and matrix permeability determined from MICP are (6.31±1.64)% and (27.4±31.1)×10~(-9) μm~2,the pore throat diameter of pores is mainly around 5 nm,and the median pore throat diameter based on 50% of final cumulative volume is (8.20±3.01) nm in shale.The pore-throat ratios decrease with a decrease of pore size diameter.Moreover,the permeability of shale samples with lamination is nearly 20 times larger than matrix permeability.The geometrical tortuosity of the nano-scale 2.8-10.0 nm pore networks is 8.44 in these shales,which indicates a poor connectivity of matrix pore network and low flow capability.Overall,the variable and limited pore connectivity of shale samples will affect hydrocarbon preservation and recovery.
Simulation analysis of microscopic water-oil displacement based on Level set method
Experimental simulation of dissolution law and porosity evolution of carbonate rock
DOI:10.1016/S1876-3804(16)30072-6
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Experiments of acetic acid (initial 0.2%) with porous dolostone, fractured-porous-vuggy dolostone, porous limestone and fractured limestone were done in a continuous flow diagenesis simulation system to find out the controlling factor of dissolution and dissolution effect. The results show that the dissolution quantity of carbonate rock inversely proportional to temperature and directly proportional to pressure, and the temperature effect is greater than the pressure effect. Therefore, relatively shallow burial and lower temperature environment is more beneficial to the formation of large scale carbonate dissolution pores. Quantitative comparison of porosity volume and permeability variation, and evolution of pores inside the rock before and after the experiment show that pore structure has apparent control over the carbonate dissolution and pore evolution. After dissolution, porous dolomite with homogeneous pore distribution saw rise in pore volume (matrix pore volume) and permeability, and remained as pore type in terms of reservoir space; porous limestone, with significant heterogeneity in original pores and texture, saw significant increase in pore volume and permeability, but the increased pores were fracture type, so its reservoir space turned into fracture-pore type; dissolution increased the permeability of fracture-pore dolomite and fracture limestone remarkably by 2-3 orders of magnitude; and the pores increased were mainly along dissolution fractures, turning the reservoir space into fracture-cave type.
Micro-influencing mechanism of permeability on spontaneous imbibition recovery for tight sandstone reservoirs
DOI:10.1016/S1876-3804(17)30107-6
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The upper part of the 4 th member of Paleogene Shahejie Formation in Bonan sag, Bohai Bay Basin, East China was taken as the study object. Conventional core analysis, casting and conventional thin section inspection, scanning electron microscope observation, particle size analysis and fluid inclusion analysis were carried out on cores, and the data from these analyses and tests was used to find out the evolution of diagenetic environment of the saline lacustrine basin and the main factors controlling the deep formation of high quality reservoirs. The diagenetic environment of the saline lacustrine basin experienced alkali and acid alternation. In the early alkali diagenetic environment, large amounts of carbonate cement filled the primary pores, making the reservoir porosity reduce sharply from 37.3% to 18.77%, meanwhile, keeping the primary pores from compaction, and retaining the dissolution space. In the middle-late stage of acid diagenetic environment, early carbonate cement was dissolved, resulting in rise of reservoir porosity by 10.59%, and thus the formation of the deep high quality reservoirs. The distribution of high quality deep reservoirs is controlled by the development of gypsum salt rock, source rock, fracture system and sedimentary body distribution jointly. Deeply buried high quality reservoirs in the upper part of the 4 th member of the Shahejie Formation in Bonan sag are nearshore subaqueous fan-end sandstone and some fan-medium fine conglomerate buried at 3 400-4 400 m in the north steep slope.
Microstructure characteristics and its effects on mechanical properties of digital core
Three-dimensional characterization and quantitative connectivity analysis of micro/nano pore space
DOI:10.1016/S1876-3804(16)30057-X
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[Cited within: 1]
To overcome the deficiencies of the material balance method, according to strong heterogeneity of tight oil reservoirs, the flow region of fractured horizontal well is divided into high permeable zone and low permeable zone, which are equivalent to radial composite percolation model. Based on parallel plane theory, multiple media of each zone are equivalent as a continuous medium, and with the integral method, the multi-region material balance to calculate the dynamic reserves for the fractured horizontal well of tight oil reservoirs is proposed base on the nonlinear seepage mechanism of tight oil reservoirs, and the corresponding pressure distribution equation and material balance equation for the two zones have been established. In view of the actual production performance, this method considers the pressure mutation and fluid exchange at the interface of two zones. The computational results of an example show that this method can work out the dynamic reserves within a single well control, the dynamic reserves of high permeable zone and low permeable zone, and the recharge rate from the low permeable zone to the high permeable zone in different production time accurately, which provides a basis for selection of well production and appropriate working system, and deployment and adjustment of development well pattern.
Classification of microscopic pore-throats and the grading evaluation on shale oil reservoirs
DOI:10.1016/S1876-3804(18)30050-8
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On the basis of the characterization of microscopic pore-throats in shale oil reservoirs by high-pressure mercury intrusion technique,a grading evaluation standard of shale oil reservoirs and a lower limit for reservoir formation were established.Simultaneously,a new method for the classification of shale oil flow units based on logging data was established.A new classification scheme for shale oil reservoirs was proposed according to the inflection points and fractal features of mercury injection curves:microscopic pore-throats(less than 25 nm),small pore-throats(25-100 nm),medium pore-throats(100-1 000 nm) and big pore-throats(greater than 1 000 nm).Correspondingly,the shale reservoirs are divided into four classes,Ⅰ,Ⅱ,Ⅲ and Ⅳ according to the number of microscopic pores they contain,and the average pore-throat radii corresponding to the dividing points are 150 nm,70 nm and 10 nm respectively.By using the correlation between permeability and pore-throat radius,the permeability thresholds for the reservoir classification are determined at 1.00× 10~(-3) μm~2,0.40×10~(-3) μm~2 and 0.05×10~(-3) μm~2 respectively.By using the exponential relationship between porosity and permeability of the same hydrodynamic flow unit,a new method was set up to evaluate the reservoir flow belt index and to identify shale oil flow units with logging data.The application in the Dongying sag shows that the standard proposed is suitable for grading evaluation of shale oil reservoirs.
Water-out performance and pattern of horizontal wells for marine sandstone reservoirs in Tarim Basin, NW China
Based on geological analysis, reservoir numerical simulation and production performance analysis, water-out performance and pattern of horizontal wells in Tarim marine sandstone reservoir were studied. Compared with continental sandstone reservoirs, the marine sandstone reservoirs in Tarim Basin were characterized by low oil viscosity, good reservoir continuity, and development of interbeds, which together with the large amount of horizontal wells, resulted in fast production rate and high recovery degree of the reservoirs. The main controlling factors of uneven water-out in horizontal wells were reservoir seepage barrier, injection-production well pattern, and dominant seepage channel. Thus 9 types in 4 categories of typical water-out pattern of horizontal wells in Tarim marine sandstone reservoirs were identified, and water-out management measures were proposed for them respectively according to their water-out mechanism and remaining oil distribution characteristics. Finally, the water-out pattern can be identified based on the inflection characteristics of derivative curve of water-oil ratio. This study of the water-out pattern can provide guidance for the adjustment policy of water injection in horizontal wells in marine sandstone reservoirs of Tarim Oilfield.
The mechanism of reservoir transition through waterflooding of Donghe sandstone in Hadeson Oilfield
In order to block the dominate pathway after waterflooding in Donghe sandstone reservoir of Hadeson Oilfield efficiently,the data of reservoir physical properties,mercury injection,cast thin sections,clay mineral Xray diffraction,scanning electronic microscope and waterflooding interpretation conclusions,were used to study the petrologic features,pore throat structure,reservoir transition rule and mechanism after waterflooding in Donghe sandstone reservoir. The results show that the absolute content of clay mineral Donghe sandstone reservoir is low,and most clay minerals are kaolinite and illite with velocity sensitivity,and range from 1 to 2 m in grain size.Donghe sandstone reservoir can be divided into three types:thin-micro throat and low permeability reservoir with throat radius less than 2 m,thin throat and middle permeability reservoir with throat radius of 2-5 m,and middlethin throat and high permeability reservoir with throat radius larger than 5 m. Clay mineral block and migration after waterflooding are the reasons for the change of reservoir physical properties. The matching of clay mineral grain size and throat radius controls the reservoir transition rule after waterflooding. There are three kinds of mechanism:the porosity and permeability of thin-micro throat and low permeability reservoir decrease after waterflooding,and they decrease from original to low waterflooding,then slightly increase till middle waterflooding,and decrease again in high waterflooding. The porosity and permeability of thin throat and middle permeability reservoir firstly increase,then increase higher and decrease in high waterflooding. The porosity and permeability of middle-thin throat and high permeability reservoir increase with the increase of waterflooding degree,and this type of reservoir is favorable for advantageous pathway development. There are a large number of residual oil after waterflooding,therefore in the study area,so it is of significance to conduct reservoir transition rule and mechanism research after waterflooding.
A review on pore structure characterization in tight sandstones
DOI:10.1016/j.earscirev.2017.12.003
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Tight sandstone reservoirs typically contain a wide pore throat sizes ranging from the nano-scale to micro-scale, and have complex pore geometry and pore throat structure. Microscopic pore throat structures are the most important factors affecting the macroscopic reservoir quality and fluid flow in tight sandstones. Evaluation and characterization quantitatively the microscopic pore structures, including pore geometry, pore size distribution, and pore connectivity, are of great importance for maintaining and enhancing petroleum recovery. This paper critically reviews the pore throat structures of tight sandstones, as assessed from peer reviewed papers in the literature as well as from the authors' personal experiences, in the particular contexts of comprehensive characterization and description of the entire pore throat structure using various complementary techniques. The depositional controls and diagenetic imprints on reservoir quality and pore structure are firstly discussed. The pore systems including pore throat type, pore geometry, pore size and connectivity, which are related to the depositional attributes and diagenetic modifications, are summarized. Then the theories and procedures of various testing techniques commonly used for pore structure characterization of tight sandstones are reviewed. Additionally, the pore throat structure characteristics in tight sandstones are obtained from various techniques such as MICP, NMR, N 2 GA and XCT. Pore throat distribution and capillary parameters of tight sandstones are examined, and the relationship between pore throat size distribution and permeability is overviewed. The pore size distribution and 3D pore connectivity are evaluated from NMR and XCT analysis. The NMR spectrum is also linked to the macroscopic performance, and the pore network is determined from N 2 GA. Then fractal theory is introduced to explain the irregularity and heterogeneity of pore throat structure characteristics, and the models for fractal dimension calculation through various techniques are summarized. Lastly the integration of various techniques is encouraged to fully characterize the entire pore size spectrum in tight sandstones by considering the complex pore structures and limitations of a single experiment in pore throat structure evaluation. This review will provide important insights into the microscopic pore structure characteristics of tight sandstones, and address the gap in comprehensive and quantitative evaluation of the heterogeneity in tight sandstones with complex microscopic pore structures.
One kind of core holder for CT scanning: CN106706684A
High pressure-elevated temperature x-ray micro-computed tomography for subsurface applications
DOI:10.1016/j.cis.2017.12.009
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PMID:29526246
[Cited within: 1]
Physical, chemical and mechanical pore-scale (i.e. micrometer-scale) mechanisms in rock are of key importance in many, if not all, subsurface processes. These processes are highly relevant in various applications, e.g. hydrocarbon recovery, CO2 geo-sequestration, geophysical exploration, water production, geothermal energy production, or the prediction of the location of valuable hydrothermal deposits. Typical examples are multi-phase flow (e.g. oil and water) displacements driven by buoyancy, viscous or capillary forces, mineral-fluid interactions (e.g. mineral dissolution and/or precipitation over geological times), geo-mechanical rock behaviour (e.g. rock compaction during diagenesis) or fines migration during water production, which can dramatically reduce reservoir permeability (and thus reservoir performance). All above examples are 3D processes, and 2D experiments (as traditionally done for micro-scale investigations) will thus only provide qualitative information; for instance the percolation threshold is much lower in 3D than in 2D. However, with the advent of x-ray micro-computed tomography (μCT) – which is now routinely used – this limitation has been overcome, and such pore-scale processes can be observed in 3D at micrometer-scale. A serious complication is, however, the fact that in the subsurface high pressures and elevated temperatures (HPET) prevail, due to the hydrostatic and geothermal gradients imposed upon it. Such HPET-reservoir conditions significantly change the above mentioned physical and chemical processes, e.g. gas density is much higher at high pressure, which strongly affects buoyancy and wettability and thus gas distributions in the subsurface; or chemical reactions are significantly accelerated at increased temperature, strongly affecting fluid-rock interactions and thus diagenesis and deposition of valuable minerals. It is thus necessary to apply HPET conditions to the aforementioned μCT experiments, to be able to mimic subsurface conditions in a realistic way, and thus to obtain reliable results, which are vital input parameters required for building accurate larger-scale reservoir models which can predict the overall reservoir-scale (hectometer-scale) processes (e.g. oil production or diagenesis of a formation). We thus describe here the basic workflow of such HPET-μCT experiments, equipment requirements and apparatus design; and review the literature where such HPET-μCT experiments were used and which phenomena were investigated (these include: CO2 geo-sequestration, oil recovery, gas hydrate formation, hydrothermal deposition/reactive flow). One aim of this paper is to give a guideline to users how to set-up a HPET-μCT experiment, and to provide a quick overview in terms of what is possible and what not, at least up to date. As a conclusion, HPET-μCT is a valuable tool when it
A non-local algorithm for image denoising
DOI:10.1109/CVPR.2005.38
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We propose a new measure, the method noise, to evaluate and compare the performance of digital image denoising methods. We first compute and analyze this method noise for a wide class of denoising algorithms, namely the local smoothing filters. Second, we propose a new algorithm, the nonlocal means (NL-means), based on a nonlocal averaging of all pixels in the image. Finally, we present some experiments comparing the NL-means algorithm and the local smoothing filters.
Micro-scale experimental investigation of the effect of flow rate on trapping in sandstone and carbonate rock samples
DOI:10.1016/j.advwatres.2016.05.012
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We present the results of a pore-scale experimental study of residual trapping in consolidated sandstone and carbonate rock samples under confining stress. We investigate how the changes in wetting phase flow rate impacts pore-scale distribution of fluids during imbibition in natural, water-wet porous media. We systematically study pore-scale trapping of the nonwetting phase as well as size and distribution of its disconnected globules. Seven sets of drainage-imbibition experiments were performed with brine and oil as the wetting and nonwetting phases, respectively. We utilized a two-phase miniature core-flooding apparatus integrated with an X-ray microtomography system to examine pore-scale fluid distributions in small Bentheimer sandstone (D = 4.9 mm and L = 13 mm) and Gambier limestone (D = 4.4 mm and L = 75 mm) core samples. The results show that with increase in capillary number, the residual oil saturation at the end of the imbibition reduces from 0.46 to 0.20 in Bemtheimer sandstone and from 0.46 to 0.28 in Gambier limestone. We use pore-scale displacement mechanisms, in-situ wettability characteristics, and pore size distribution information to explain the observed capillary desaturation trends. The reduction was believed to be caused by alteration of the order in which pore-scale displacements took place during imbibition. Furthermore, increase in capillary number produced significantly different pore-scale fluid distributions during imbibition. We explored the pore fluid occupancies and studied size and distribution of the trapped oil clusters during different imbibition experiments. The results clearly show that as the capillary number increases, imbibition produces smaller trapped oil globules. In other words, the volume of individual trapped oil globules decreased at higher brine flow rates. Finally, we observed that the pore space in the limestone sample was considerably altered through matrix dissolution at extremely high brine flow rates. This increased the sample porosity from 44% to 62% and permeability from 7.3 D to 80 D. Imbibition in the altered pore space produced lower residual oil saturation (from 0.28 to 0.22) and significantly different distribution of trapped oil globules.
Quantitative morphology and network representation of soil pore structure
DOI:10.1016/S0309-1708(00)00055-5
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Pore-network models are attractive to relate pore geometry and transport processes in soil. In this contribution a `morphological path' is presented to generate a network model based on quantitative morphological investigations of the 3D pore geometry in order to predict soil hydraulic properties. The 3D-geometry of pores larger than 0.04 mm in diameter is obtained using serial sections through impregnated samples. Beside pore-size distribution an important topological aspect of pore geometry is the spatial connectivity of the pore space which is difficult to measure. A connectivity function is proposed defined by the 3D-Euler number. The goodness in the estimation of the Euler number using serial sections is investigated in subsamples of different sizes and shapes. Then, a simple network model is generated which can be adapted to a predefined pore-size distribution and connectivity function. Network simulations of hydraulic properties are compared to independent measurements at the same soil material and the effect of topology on water flow and solute transport is investigated. It is concluded that a rough estimation of pore-size distribution and topology defined by the connectivity function might be sufficient to predict hydraulic properties.
Evaluation of fractal models to describe reservoir heterogeneity and performance
Fractal measurements of sandstones, shales, and carbonates
DOI:10.1029/JB093iB04p03297
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[Cited within: 1]
Measurements were made of the fractal properties of sandstones, shales, and carbonates using a statistical analysis of structural features on fracture surfaces. Fractal behavior is associated with power law behavior for the number of features as a function of the feature size on the pore-rock interface. Only one sedimentary rock, a novaculite, was found not to have a fractal structure. The fractal dimensions range from 2.27 to 2.89, and the long-length limits to the fractal regime range from 2 0204m to over 50 0204m. In all cases, the fractal behavior extends to less than 0.2 0204m which is the measurement resolution. The porosity associated with the fractal pore-rock interface can be calculated from the fractal parameters. Some of the samples have additional porosity not associated with power law behavior. Photographs and other evidence are used to show that the fractal structures are the result of diagenesis. Fractal diagenetic structures include euhedral quartz overgrowths, druse quartz, calcite, dolomite, clays, and chert.
Quantitative evaluation of carbonate reservoir pore structure based on fractal characteristic
Pore structure of large scale porous limestone reservoir with strong heterogeneity is very complex,so it is difficult to evaluate its pore structure of Mishrif Formation of W oilfield in Iraq.Based on thin section observation,porosity and permeability test and mercury injection capillary pressure test,fractal theory was applied to quantitative pore structure evaluation,and the pore fractal dimension criterion for reservoir type classification was established.There are two types of reservoir pore structure fractal characteristics.Some samples called"single segment"perform obvious fractal character overall.Others called"multiple segments"have distinct large pore throat system and small pore throat system which perform unique fractal characters respectively while have no uniform fractal character overall.The complexity and heterogeneity of pore structure of porous limestone can be reflected by fractal dimension,the greater the fractal dimension,the more complex pore structure,and the more conspicuous segmental character in the relationship between capillary pressure and water saturation,the stronger the heterogeneity.The samples were classified based on the fractal dimension combined with porosity and permeability distribution of the samples.The majority of type Ⅰ-Ⅱ and type Ⅲ-Ⅳrespectively corresponded to"multiplesegments"and"single segment"fractal characteristics.It has an important guiding significance for the quantitative evaluation of pore structure to similar carbonate reservoir.
Characterization of residual oil microdistribution at pore scale using computerized tomography
DOI:10.7623/syxb201402012
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[Cited within: 1]
The microdistribution of residual oil in reservoir pore is an important basis for remaining oil potential tapping.With the aid of computerized tomography(CT) scanning and displacement experimental system,CT images at different displacement moments were acquired,these images were then transformed to three-dimensional data volume by image processing technology.On this basis,information of residual oil was extracted and such characteristic parameters as number,average volume,contact area ratio and shape factor were defined to characterize the microdistribution of residual oil at pore scale.Experimental results showed that:the number of residual oll increased and average volume decreased with the increase of injected water volume;oil blobs smaller than 20 times average pore volume constitute the overwhelming majority of residual oil in quantity and their total volume ratio increased;residual oil were washed out from the rock surface gradually and nearly one third oil blobs had contact with the rock surface in water wet core;shapes of oil blobs changed from meshwork to other forms.Meshwork andmultiple pore forms were in the majority at the end of the displacement so that they were the principal object of potential tapping during later stage of water-injection recovery.
Pore-scale investigation of microscopic remaining oil variation characteristics in water-wet sandstone using CT scanning
DOI:10.1016/j.jngse.2017.04.003
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[Cited within: 2]
With the aid of CT scanning and image processing techniques, water displacing oil experiments were performed to analyze six natural water-wet sandstone cores of different permeability and porosity visually and quantitatively. Microscopic remaining oil was categorized on the basis of quantitative characterization parameters, such as shape factor, contact ratio, Euler number etc. The remaining oil characteristics with different flow types were presented in different water displacement stages. Experimental results show that the remaining oil can be divided into five categories. They are, respectively membranous flow, droplet flow, columnar flow, multi-porous flow and clustered flow from hard-to-produce to easy-to-produce. The relative permeability of oil phase is represented by the macro-average relative permeability of all the above five flow regimes. Among them, clustered flow possesses strong producing capacity and high relative permeability, and the other four flow regimes have weaker producing capacity and lower relative permeability. Variation of number and average volume of five types remaining oil and several measurements of the ganglion size distribution have been performed in the literature. The nonlinear knee point on the relative permeability ratio curve is intrinsically caused by the decreasing of volume and quantity fraction of clustered flow when water saturation increases. This paper has studied the flowing law of microscopic remaining oil, explained the intrinsic mechanism for the appearance of an inflection point on the relative permeability ratio curve and microscopic sweep phenomena, and also presented a new effective way of upscaling to a certain extent.
Pore-scale imaging of the oil cluster dynamic during drainage and imbibition using in situ X-ray microtomography
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