Skip to content
BY 4.0 license Open Access Published by De Gruyter Open Access October 3, 2022

Study on the influence of physical interlayers on the remaining oil production under different development modes

  • Zhao Yu , Ma Wenguo EMAIL logo , Du Qinglong , Xu Qiang , Li Zengzhi , Ma Ruilin and Chen Qi
From the journal Open Chemistry

Abstract

Using the complex stratigraphic structure model, we study the changes in remaining oil on the millimeter scale in different structural parts during the different water flooding development methods. According to the actual geological structure characteristics of the oil layer, We designed and produced the meter-level experimental model, which ensures the similarity between the model structure and actual oil layer structure. The recovery rate of the primary water flooding stage is 10.36%. The stage recovery rate addition of the change flow direction stage is 7.85%. The final recovery rate is 41.36%. The physical interlayer structure has an influence on the oil saturation change in the nearby layers. The oil saturation reduction value is highest in the left part of layer 3 in the primary water flooding stage, the reduction range is 24.81%. There are 2 parts and 1 part where the oil saturation decreases by more than 10.0% in the second boost flooding stage and the change flow direction stage, respectively.

1 Introduction

The macroscopic and microscopic residual oil distribution in the reservoir is complex in the stage of high water cut [1,2,3]. Scholars have carried out a lot of research work on the distribution of residual oil after different flooding methods [4,5]. Through the sand-packing pipe experiments, some scholars analyzed the mechanism and effect of nitrogen foam flooding to enhance oil recovery, and concluded that the high-porosity, high-permeability and strong edge-water reservoirs entered the high water-cut stage. Remaining oil mainly distributes at the top and edge of the structure, and it is useless to rely solely on the energy displacement of marginal water [6]. Some scholars have used a combination of literature research, theoretical research and numerical simulation of oil reservoirs to conduct research on the adaptability of kilometer-scale well patterns in oilfields. Research works of numerical simulation show the water flooding effect change worse after the longer the development time. The more inhomogeneous the oil layer structure is, the more oil remains after the conventional well pattern development [7,8]. Scholars have carried out research on the microscopic pore structure and the characteristics of rock seepage capacity [9,10]. Some scholars have carried out continuous flow research at the pore scale, and carried out research on the formation causes, types, and re-production mechanisms of remaining oil at the nanometer scale [11,12,13]. There are also many scholars who have carried out a lot of research on the coupling effect of the fluid–fluid interface. They assumed that the relative permeability and capillary pressure curves only depend on the saturation condition, and carried out fluid flow simulation analysis to study the understanding of the pore size fluid distribution law, and formed a certain understanding [14,15,16,17]. In recent years, with the help of industrial CT scanning reconstruction technology and nuclear magnetic resonance technology, scholars have carried out a lot of research work on the distribution and quantification of micro-scale residual oil at the nano-micro pore level [18,19,20]. The researchers have got certain results in the study of oil types and occurrence changes [21,22,23,24]. Scholars have compared and analyzed the micro-scale residual oil distribution, but while ensuring the test accuracy, the test area is small, which cannot effectively reflect the influence of the actual reservoir geological structure on the oil displacement effect [25,26]. In this work, using the medical CT, we studied the variation law of remaining oil in millimeter-scale heterogeneous oil reservoirs with different displacement methods, the results can provide a theoretical basis for the optimization of development methods and the enhanced oil recovery technology.

2 Experimental materials

2.1 Experimental model

The experimental model was designed according to the statistical analysis of the inspection well data in the XLD block. The research site is a low-curved channel and middle of the point bar. The model contains two physical interlayers and the inclination of the interlayers is 5 degrees represents the reservoir: Class II oil layer; the permeability values of different parts are given by comprehensive statistics of the data of six inspection wells, and the development characteristics of the channel sand body in the P122 unit of Well Xing 6–20-Jian 647 are the main reference objects. The design size of the model is 0.6 m long, 0.208 m high, 0.3 m wide, and has a net weight of 82.60 kg. The model includes two physical interlayers. The gas permeability of the physical interlayer is 30 × 10−3 μm2 and the thickness is 0.1 m. The designed permeability in the model is 30.0 × 10−3 μm2 and the thickness is 4.0 mm. In the actual strata, the permeability of oil layers on both sides of each layer with physical properties at the same depth is different due to the barrier of physical properties. The composition is shown in Figure 1 and Table 1.

Figure 1 
                  The geological model of typical heterogeneous reservoirs and the schematic diagram of the layers.
Figure 1

The geological model of typical heterogeneous reservoirs and the schematic diagram of the layers.

Table 1

Analysis of horizon parameters of heterogeneous model in laboratory oil flooding experiment

Layer number Distance from the top (m) Permeability (×10−3 μm2) Actual layer thickness (m) Thickness of indoor model (m)
Left part Right part Left part Right part Left part Right part
1 0.01 300.0 500.0 0.5 1.0 0.02 0.04
2 0.03 800.0 500.0 1.0 0.04 0.04
3 0.05 800.0 1000.0 1.0 0.04 0.04
4 0.07 1000.0 1.0 0.02 0.04
5 0.09 1600.0 600.0 1.0 0.5 0.04 0.02
6 0.11 1600.0 1400.0 1.0 1.5 0.04 0.06
7 0.15 1400.0 1.0 1.5 0.04 0.06
8 0.18 2500.0 1.0 0.04 0.04

In order to compare and analyze the remaining oil distribution in different parts of the model during the experimental test by the medical CT test model, we selected eight different layers in the physical model for comparative analysis of the distribution change in remaining oil. The specific location of the layer is shown in the Figure 1.

There are 8 wellhead ends at the top of the model and 30 discharge ports in 4 directions on the sides. Model saturated water, saturated oil, and water flooding experiments are carried out. The three-dimensional schematic diagram of the development of each layer and the position of the wellhead in the indoor heterogeneous reservoir geological model is shown in Figure 2. The schematic diagram of the well location of water well and oil well is shown in Figures 3 and 4 (Table 2).

Figure 2 
                  Schematic diagram of the development of each layer and the position of the wellhead in the three-dimensional position of the indoor heterogeneous reservoir geological model.
Figure 2

Schematic diagram of the development of each layer and the position of the wellhead in the three-dimensional position of the indoor heterogeneous reservoir geological model.

Figure 3 
                  Geological model and well layout of artificial heterogeneous reservoir.
Figure 3

Geological model and well layout of artificial heterogeneous reservoir.

Figure 4 
                  Weighing diagram at the end of saturated water of the model.
Figure 4

Weighing diagram at the end of saturated water of the model.

Table 2

The calculated values of the volume of different permeability parts of the model

Analysis of parts Permeability (×10−3 μm2) Volume of parts (cm3) Site volume weight (%)
1 Left 300.00 1950.00 5.38
1 Right 500.00 1600.00 4.41
2 Left 800.00 400.00 1.10
2 Right 500.00 2000.00 5.51
3 Left 800.00 200.00 0.55
3 Right 1000.00 3520.00 9.70
4 1000.00 5000.00 13.79
5 Left 1600.00 2000.00 5.51
5 Right 600.00 457.00 1.26
6 Left 1600.00 1543.00 4.25
6 Right 1400.00 3200.00 8.82
7 1400.00 7200.00 19.85
8 2500.00 7200.00 19.85
Total 36270.00 100.00

2.2 Experimental fluid

The experimental oil is the kerosene and the viscosity value is 10.0 mPa·s at room temperature. The experimental water was prepared by adding 15.0% KI to deionized water.

3 Millimeter residual oil production analysis

Analysis of remaining oil production at the millimeter scale CT scans were carried out before and after the oil displacement experiment to quantitatively characterize the fluid in the micro-scale pores, and to analyze the reproducing ability of different chemical systems for various types of microscopic remaining oil and the distribution of remaining oil.

3.1 Test equipment

In order to obtain the millimeter scale change data of oil saturation in each layer of the large-sized pore model in different displacement stages, the experimental model was tested by medical CT. The CT scanning medical equipment is shown in Figure 5.

Figure 5 
                  Picture of medical CT instrument for testing.
Figure 5

Picture of medical CT instrument for testing.

3.2 Experiment scheme

We carried out water flooding experiments by using the large-scale heterogeneous model, and we ended the experiments at different stages of water flooding to 98.0% water cut, and CT scans were performed to obtain the distribution law of remaining oil in each layer.

  1. The primary water flooding stage: W1 and W2 water flooding, injection rate of single well is 2.40 mL/min, oil production from O1–O6 wells, CT scanning evaluation after water flooding.

  2. The first boost flooding stage: W1 and W2 water flooding injection wells, the injection rate is 3.04 mL/min. CT scan is performed to obtain the distribution law of remaining oil in each layer.

  3. The second boost flooding stage: The injection rate is 3.60 mL/min, W1 and W2 water flooding was injected, and CT scan was performed to obtain each layer.

  4. The change flow direction stage: Wells W1 and W2 were closed, and wells O2 and O5 were adjusted to injection wells for water injection. The injection rate of a single well was adjusted to 3.60 mL/min. Oil was produced from O1, O3, O4, and O6 wells. CT scanning was performed to obtain the distribution law of remaining oil in each layer.

  5. The horizontal well flooding stage: The horizontal well is 0.025 m away from the top layer of the model, and drills pass through the model from left to right. Horizontal wells are set at both ends. The wells O2 and O5 were adjusted to injection wells, the injection rate of a single well was adjusted to 3.60 mL/min, the horizontal wells P1 and P2 produced oil. CT scan was performed to obtain the distribution law of remaining oil in each layer.

3.3 The flooding experiment results

  1. The injection rate of saturated water and saturated oil is 2.40 mL/min/well. First, the experimental simulated oil is injected from the O1 and O6 wells on one side. After the liquid produced by the remote liquid port is free of water, close the liquid port, and open the vent ports at the bottom on both sides one by one from far to near. After the current group of vent ports is 100% oily, close the two vent ports in this group. Open a closer set of vents and continue to saturate the simulated oil until reaching the closest set of vents for injection wells O1 and O6. Then, the above process is repeated using O3 and O4 wells as injection wells in reverse, until all injection wells at the top are injected with simulated oil, and when saturated oil is over, the liquid produced by each vent is 100% oil-containing, and the saturation process is ended.

  2. Water flooding experiment: In order to study the change in remaining oil in different water flooding stages and the effect evaluation of different development measures under water flooding limit conditions, an indoor oil flooding experiment was carried out. The injection rate was 2.40 mL/min, the cumulative injection of simulated oil was 7.5283 L, and the initial oil saturation was 64.43%. The recovery rate results of each development stage and the effect of different development measures (including the change flow direction stage and horizontal well flooding stage) under the condition that the water flooding water reaches the limit, carry out the laboratory oil flooding experiment, experimental plan, injection conditions and results are shown in Table 3, and the experimental characteristic curve is shown in Figure 6.

Table 3

Experimental parameters and results

Flooding stage Injection speed (mL/min) A/B pump injection pressure (kPa) Pore volume Stage recovery rate addition (%) Total recovery rate (%)
The primary water flooding stage 2.40 82/101 2.27 10.36 10.36
The first boost flooding stage 3.06 107/138 1.66 5.94 16.3
The second boost flooding stage 3.60 107/135 0.30 0.38 0.38
The change flow direction stage 3.60 117/170 1.20 7.85 8.23
The horizontal well flooding stage 3.60 128/156 2.53 16.82 41.36
Figure 6 
            Total recovery rate curves at different flooding stages. Note: (a) the primary water flooding stage; (b) the first boost flooding stage; (c) the second boost flooding stage; (d) the change flow direction stage; and (e) the horizontal well flooding stage.
Figure 6

Total recovery rate curves at different flooding stages. Note: (a) the primary water flooding stage; (b) the first boost flooding stage; (c) the second boost flooding stage; (d) the change flow direction stage; and (e) the horizontal well flooding stage.

In different water flooding development stages, the experiment is stopped when the water flooding reached 98.0% of the water in the stage. The recovery rate of the primary water flooding stage is 10.36%. The stage recovery rate addition of the first boost flooding stage and the second boost flooding stage is 5.94 and 0.38%, respectively. The stage recovery rate addition of the change flow direction stage is 7.85%. The stage recovery rate addition of the horizontal well flooding stage is 16.82%, and the final recovery rate of the displacement flooding is 41.36%.

4 Variation and quantitative analysis of remaining oil distribution

4.1 Analysis of the distribution change in remaining oil

In order to compare and analyze the changes in oil saturation in each layer during the water flooding process, the large-scale medical CT test data and image analysis software were used to carry out image reconstruction and quantitative analysis of the remaining oil in each layer, and the oil saturation at the millimeter scale of each layer in each stage was obtained. Distribution map, the influence of oil saturation distribution in different stages of each layer is shown in Figure 7. From the results of the influence of different measures to improve the development effect of water flooding on the distribution of remaining oil at the millimeter scale in each layer of the model, it can be seen that the physical interlayer has an influence on the change in oil saturation in the nearby structural layers. Layers 5 and 6 have obvious influence on the production of remaining oil in each water flooding development measure, while layers 7 and 8 have less influence. In the horizontal well flooding stage, the variation in remaining oil at different distances from the horizontal well can be seen to be affected by the physical interlayer. In the far area, there is no effective seepage channel, and the oil-bearing production is less. The layers near the upper horizontal well, the lower the oil saturation, but the oil-bearing production near the edge of the model is less. As the distance increases, the residual oil production becomes worse, and the influence of horizontal wells near the layer 4 on the remaining oil production disappears.

Figure 7 
                  Influence of physical interlayer on the remaining oil distribution in different parts. (a) Original saturated oil; (b) the primary water flooding stage; (c) the first boost flooding stage; (d) the second boost flooding stage; (e) the change flow direction stage; (f) the horizontal well flooding stage.
Figure 7

Influence of physical interlayer on the remaining oil distribution in different parts. (a) Original saturated oil; (b) the primary water flooding stage; (c) the first boost flooding stage; (d) the second boost flooding stage; (e) the change flow direction stage; (f) the horizontal well flooding stage.

4.2 Quantitative analysis of remaining oil

CT scanning method is used to study the change in fluid distribution in the rock pores during the water-flooding process. According to the theoretical basis of quantitative calculation, the same X-ray linear attenuation theory is used for the calculation of the remaining oil distribution in the micro-pores of nano-micron CT, that is, the single-energy X-ray conforms to Beer’s law [25], it is assumed that the pore structure and the shape of the framework particles do not change during the process of oil-saturated and water-saturated oil displacement, and it is assumed that the total pressure along the path of the fluid in the pore seepage process has no effect on the stress-sensitive characteristics of the rock, and the pores of the core are not affected. There is no change in the structure, and on this basis, the oil saturation change analysis at the millimeter scale is carried out. Using CT scanning imaging technology, the cores at different displacement times were scanned to obtain the CT values of the cores, and the oil saturation of the model in the failure stage is calculated by formula (1).

(1) S o = H water H air H w,r H a,r H w,r H two-phase H water H oil × 100 % ,

where H a,r – CT value of dry core before saturation of formation water, H stone – CT value of core skeleton particles, H air – CT value of air, H w,r – CT value of wet core after saturation of formation water, H water – CT value of formation water, H two-phase – CT value of core at a certain time of water flooding, H oil – CT value of crude oil.

Due to the complexity structure of this model, according to the CT value data of different parts of the model, the partition weighting method is introduced in this study to calculate the oil saturation changes in different parts. Combined with the remaining oil saturation distribution image, a comparative study can be carried out on the model as a whole and the changes in remaining oil in each layer at different stages during the water flooding process. Table 4 shows the oil saturation of the parts.

Table 4

Oil saturation data of each layer in different displacement stages

Part The saturated oil stage (%) The primary water flooding stage (%) The first boost flooding stage (%) The second boost flooding stage (%) The change flow direction stage (%) The horizontal well flooding stage (%)
1 Left 69.25 56.23 49.56 48.16 43.37 38.50
1 Right 58.49 71.25 65.62 56.24 48.32 48.93
2 Left 66.95 55.06 54.27 49.88 38.56 34.65
2 Right 63.41 64.35 62.17 51.22 41.97 39.87
3 Left 68.97 44.16 43.12 41.26 37.22 31.05
3 Right 62.24 60.27 61.66 50.71 43.12 37.13
4 65.80 58.80 52.40 46.60 39.40 37.20
5 Left 66.94 52.34 48.21 44.25 38.84 36.01
5 Right 50.06 50.51 53.53 50.43 47.23 38.11
6 Left 69.40 53.66 51.94 50.10 41.47 38.25
6 Right 63.77 58.31 49.66 48.77 45.81 46.77
7 64.20 49.00 43.60 43.80 38.40 29.40
8 65.00 50.20 47.60 44.40 37.60 32.40

We carried out the primary water flooding stage, the first boost flooding stage, the second boost flooding stage, the change flow direction stage, the horizontal well flooding stage in order. In the primary water flooding stage, there are seven parts where the oil saturation decline is higher than 10.0%, and the oil saturation in the left part of layer 3 has the largest decline, from 68.97 to 44.16%, a decline of 24.81%, the other 3 parts have a decline of less than 10.0%. The oil saturation reduction in each layer in the first boost flooding stage is less than 10.0%. There are 2 parts in the second boost flooding stage in which the oil saturation decline is higher than 10.0%, namely, the right part of layer 2 and the right part of layer 3, with a reduction range of 10.94 and 10.95%, respectively. There is 1 part in the change flow direction stage in which the oil saturation decline is higher than 10.0%, and the decline range of the left part of layer 2 is 11.32%. In the horizontal well flooding stage, the oil saturation decreased by less than 10.0%, and the oil saturation increased in 2 parts, but the increase was less than 1.00%.

We analyzed the changes in oil saturation near the physical interlayer in different displacement stages by CT detection data. The oil saturation of the right part of the layer 1 increases abnormally after the primary water flooding stage, which is higher than the original oil saturation, 12.75%. Other oil saturation increases occurred on the right side of layer 2, with an increase of 0.94%, and on the right side of layer 5, the oil saturation increased by 0.45%. The oil saturation also increased in the right part of layer 3 and the right part of layer 5 in the first boost flooding stage, and the increments were 1.39 and 3.02%, respectively. The oil saturation of layer 7 in the second boost flooding stage increased slightly, with an amplitude of 0.2%; the oil saturation on the right side of layer 1 and the right side of layer 6 in the horizontal well flooding stage increased slightly compared with the previous stage, the amplitudes were, respectively, 0.61 and 0.96%. Using the variation data of oil saturation in different layers, combined with the millimeter-scale oil saturation field map obtained by CT detection, it is possible to analyze the production capacity of oil in each layer and the reasons for the generation of remaining oil enrichment sites by development methods in different displacement stages.

5 Conclusion

  1. The Recovery Rate of the primary water flooding stage is 10.36%. The stage recovery rate addition of the first boost flooding stage and the second flooding stage is 5.94 and 0.38%, respectively. The stage recovery rate addition of the change flow direction stage is 7.85%. The stage recovery rate addition of horizontal well flooding Stage is 16.82%, and the final recovery rate of the water flooding is 41.36%.

  2. In the horizontal well flooding stage, the change in remaining oil at different distances from the horizontal well can be seen to be affected by the physical interlayer, no effective seepage channel is established, and oil production is less. As the distance from the horizontal well increases, the remaining oil production gradually deteriorated, and the horizontal well effect disappeared near layer 4.

  3. The oil saturation reduction value is higher in the primary water flooding stage and the change flow direction stage. The oil saturation reduction value is highest in the left part of layer 3 in the primary water flooding stage, the reduction range is 24.81%, from 68.97 to 44.16%. There are 2 parts and 1 part where the oil saturation decreases by more than 10.0% in the second boost flooding stage and the change flow direction stage, respectively.

  1. Funding information: This work was supported by the National Science and Technology Major Projects of China for Oil and Gas (Projects no. 2016ZX05010 and 2016ZX05058).

  2. Author contributions: Investigation: Y.Z., M.W., and D.Q.; resources: Y.Z. and M.W.; funding acquisition: Y.Z., M.W., and D.Q.; experiment: X.Q., L.Z., M.R., and C.Q.; methodology: Y.Z., M.W., D.Q., and X.Q; data curation: Y.Z., M.W., D.Q., X.Q., L.Z., M.R., and C.Q. All authors have read and agreed to the published version of the manuscript.

  3. Conflict of interest: The authors declare no conflict of interest.

  4. Ethical approval: The conducted research is not related to either human or animal use.

  5. Data availability statement: All data generated or analyzed during this study are included in this published article.

References

[1] Li Y, Jing Z, Deng P, Yun Y, Liu M, Han C, et al. Occurrence law of microscopic remaining oil in high water cut stage-Taking Xiaoji block and Gangxi block of Dagang Oilfield as examples. Xinjiang Pet Geol. 2021;42(4):444–9.Search in Google Scholar

[2] Xu LH. A brief talk on the description method of residual oil in thick reservoir. IOP Conf Ser Earth Env Sci. 2021;770(1):1.10.1088/1755-1315/770/1/012009Search in Google Scholar

[3] Zhu W, Zou C, Wang J, Liu W, Wang J. A new three-dimensional effective water-flooding unit model for potential tapping of remained oil in the reservoirs with rhythmic conditions. J Pet Exploration Prod. 2021;11(3):1375–91. 10.1007/s13202-020-01068-z.Search in Google Scholar

[4] Akai T, Alhammadi AM, Blunt MJ, Bijeljic B. Mechanisms of microscopic displacement during enhanced oil recovery in mixed-wet rocks revealed using direct numerical simulation. Transp Porous Media. 2019;130(3):23–36.10.1007/s11242-019-01336-5Search in Google Scholar

[5] Dehghan AA, Farzaneh SA, Kharrat R, Ghazanfari MH, Rashtchian D. Pore-level investigation of heavy oil recovery during water alternating solvent injection process. Transp Porous Media. 2010;83(3):65–79.10.1007/s11242-009-9463-5Search in Google Scholar

[6] Li Y, Ling X, Peng Q, Cheng Y. Study on nitrogen foam flooding for enhanced oil recovery in high porosity, high permeability and strong edge water reservoirs. Petrochem Appl. 2021;40(10):71–6 + 81.Search in Google Scholar

[7] Ma W. Research on the distribution of remaining oil in high water-cut oil fields. Sci Technol Eng. 2011;11(14):3278–9 + 3283.Search in Google Scholar

[8] Ning L, Liu H, Yang H, Sun Y, Bo Q, Zhang Y, et al. Unconformity reservoir modeling digital-analog integration technology and its application [Natural Science Edition]. J Xi’an Shiyou Univ. 2021;36(6):134–9.Search in Google Scholar

[9] Ma W, Liu A. Study on the pore structure of rock by CT scanning technology. Zhongwai Energy. 2011;16(7):54–6.Search in Google Scholar

[10] Xie M, Zong D, Luo D, Li H, Fang T, Tu Z. A new method for analysis of remaining oil characteristics in heavy oil reservoirs based on micro-CT scanning displacement experiment. Fei Changgui Youqi. 2020;7(5):102–7.Search in Google Scholar

[11] Ma W, Xia H, Liu Y, Wu W, Wang K, Wang Y. A method for identifying and quantifying oil-water distribution in micron-scale pores, Faming Zhuanli Shenqing Gongkai Shuomingshu. CN 102628354A; 2012 (in Chinese).Search in Google Scholar

[12] Junjian LI, Yang LI, Yajun GA, Baoyang CH, Fanle ME, Huaimin XU. Influence of microscopic pore-throat heterogeneity on the distribution of remaining oil. Pet Explor Dev. 2018;45(6):1043–52.Search in Google Scholar

[13] Zhang Y, Zhao P, Cai M, Lu F, Wu X, Guo Z. Occurrence state and forming mechanism of microscopic remaining oil controlled by dynamic and static factors. J Pet Sci Eng. 2020;193:107330. 10.1016/j.petrol.2020.107330.Search in Google Scholar

[14] Parmigiani A, Huber C, Bachmann O, Chopard B. Pore-scale mass and reactant transport in multiphase porous media flows. J Fluid Mech. 2011;686:40–76.10.1017/jfm.2011.268Search in Google Scholar

[15] Dou Z, Zhou ZF. Numerical study of non-uniqueness of the factors influencing relative permeability in heterogeneous porous media by lattice Boltzmann method. Int J Heat Fluid Flow. 2013;42:23–32.10.1016/j.ijheatfluidflow.2013.01.020Search in Google Scholar

[16] Tang M, Lu S, Zhan H, Wenqjie G, Ma H. The effect of a microscale fracture on dynamic capillary pressure of two-phase flow in porous media. Adv Water Resour. 2018;113:272–84.10.1016/j.advwatres.2018.01.015Search in Google Scholar

[17] Adenutsi CD, Li Z, Lai F, Hama AE, Aggrey WN. Pore pressure variation at constant confining stress on water–oil and silica nanofluid–oil relative permeability. J Pet Explor Prod Technol. 2019;9(3):3.10.1007/s13202-018-0605-6Search in Google Scholar

[18] Bin L, Wang Ximei X, Zeng J, Wang Q, Wei Y, Kang W. Application of CT scanning technology in the analysis of core microscopic oil displacement characteristics. Logging Eng. 2019;30(2):34–7 + 133.Search in Google Scholar

[19] Wang YF, Li ZY, Zhang SM, Liu DX, Ding MC. Remaining oil distribution in models with different heterogeneities after CO2 WAG injection: visual research by nuclear magnetic resonance technique. J Cent South Univ. 2021;28(5):1412–21.10.1007/s11771-021-4712-zSearch in Google Scholar

[20] Wildenschild D, Sheppard AP. X-ray imaging and analysis techniques for quantifying pore-scale structure and processes in subsurface porous medium systems. Adv Water Resour. 2013;51(Jan):217–46.10.1016/j.advwatres.2012.07.018Search in Google Scholar

[21] Jamaloei BY, Kharrat R. Analysis of microscopic displacement mechanisms of dilute surfactant flooding in oil-wet and water-wet porous media. Transp Porous Media. 2010;81(1):1–19.10.1007/s11242-009-9382-5Search in Google Scholar

[22] Afrapoli MS, Alipour S, Torsaeter O. Analysis of microscopic displacement mechanisms of a MIOR process in porous media with different wettability. Transp Porous Media. 2012;93(3):3.10.1007/s11242-012-9978-zSearch in Google Scholar

[23] Yu T. Quantitative characterization of microscopic residual oil based on CT scanning. MA thesis. Northeast Petroleum University; 2017.Search in Google Scholar

[24] Sun P, Xu H, Zhu H, Jia L, Hu X, Fang H. Investigation of pore-type heterogeneity and its control on microscopic remaining oil distribution in deeply buried marine clastic reservoirs. Mar Pet Geol. 2021;123:104750. 10.1016/j.marpetgeo.2020.104750.Search in Google Scholar

[25] Jian G, Dong H, Wang J, Wu K, Li L. Application of CT imaging technology to study oil saturation distribution characteristics of core water flooding. Xinjiang Pet Geol. 2009;30(2):269–71.Search in Google Scholar

[26] Li H, Pan C, Miller CT. Pore-scale investigation of viscous coupling effects for two-phase flow in porous media. Phys Rev E Stat Nonlin Soft Matter Phys. 2005 Aug;72(2):026705.10.1103/PhysRevE.72.026705Search in Google Scholar PubMed

Received: 2022-04-05
Revised: 2022-07-09
Accepted: 2022-07-13
Published Online: 2022-10-03

© 2022 Zhao Yu et al., published by De Gruyter

This work is licensed under the Creative Commons Attribution 4.0 International License.

Downloaded on 6.2.2023 from https://www.degruyter.com/document/doi/10.1515/chem-2022-0194/html
Scroll Up Arrow