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Figure 17. Pore shape proportions before and after polymer flooding injection in low-permeability sandstones. Figure 18. Pore shape proportions before and after polymer flooding injection in high-permeability sandstones.

Figure 17 Pore shape proportions before and after polymer flooding injection in low-permeability sandstones. Figure 18. Pore shape proportions before and after polymer flooding injection in high-permeability sandstones.

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Figure 1. Hebron field location at Jeanne d’Arc Basin (taken and modified from ExxonMobil* and Xiong et al.), Figure 2. Hebron field structural section (taken and modified from ExxonMobil’).
Figure 1. Hebron field location at Jeanne d’Arc Basin (taken and modified from ExxonMobil* and Xiong et al.), Figure 2. Hebron field structural section (taken and modified from ExxonMobil’).
Table 1. Ben Nevis Formation Pool 1 Reservoir Properties*
Table 1. Ben Nevis Formation Pool 1 Reservoir Properties*
Table 4. Oil Mix Properties at Reservoir Conditions (62 °C and 2775 psi) Table 3. Brine Composition
Table 4. Oil Mix Properties at Reservoir Conditions (62 °C and 2775 psi) Table 3. Brine Composition
“Perm (permeability) and temp (temperature). ’(3) Corresponds to a property in the average or best value, (1) corresponds to a property in the value range, (0) is assigned when there is no data available, and (—5) corresponds to a property outside of the value range. Value ranges correspond to the screening guidelines. Table 2. Ben Nevis Formation Pool 1 EOR Screening”
“Perm (permeability) and temp (temperature). ’(3) Corresponds to a property in the average or best value, (1) corresponds to a property in the value range, (0) is assigned when there is no data available, and (—5) corresponds to a property outside of the value range. Value ranges correspond to the screening guidelines. Table 2. Ben Nevis Formation Pool 1 EOR Screening”
5115 (FP-515), and a modified natural polymer, guar gum, were used for polymer studies and screening. Detailed polymer characteristics can be found in Table S.
5115 (FP-515), and a modified natural polymer, guar gum, were used for polymer studies and screening. Detailed polymer characteristics can be found in Table S.
“ATBS (acrylamide-tertiary-butyl sulfate). */(no data available). Table 5. Characteristics of Polymers“
“ATBS (acrylamide-tertiary-butyl sulfate). */(no data available). Table 5. Characteristics of Polymers“
Figure 3. Sampling depth of composite cores (map modified after ExxonMobil’).
Figure 3. Sampling depth of composite cores (map modified after ExxonMobil’).
2.8.3. Digital Image Analysis (DIA). The DIA was performed using JMicroVision v.1.2.7 software, which was developed to analyze high- definition images of thin sections. Image analysis of thin sections is a well-known method for quantitative analysis of pore structures and rock characterization. The process of DIA for porosity prediction comprises 2.7. Core Flooding Experiments. The experiments were conducted at 62 °C with 2775 psi back pressure and 3500 psi overburden pressure. Table 6 displays the experimental sequences. The four cores from D-94 were used to examine polymer flooding in the tertiary recovery mode. The experimental steps were as follows: (1) two pore volumes (PV) of SW were injected into the core at 0.28 mL/min, (2) two PV of polymer solutions were injected at 0.06, 0.11, and 0.28 mL/min to avoid potential plugging problems, and (3) one PV of SW was injected at 0.28 mL/min as additional waterflooding. The four cores from M-04 were used to perform polymer flooding in the secondary recovery mode: (1) two PV of polymer solutions were injected at 0.06, 0.11, and 0.28 mL/min and (2) one PV of SW was injected at 0.28 mL/min as additional waterflooding. The flow rates used in the core flooding experiments were chosen to ensure that the Figure 4. Image selection pattern (selection pattern of 12 thin sections for core M-04-H-2).
2.8.3. Digital Image Analysis (DIA). The DIA was performed using JMicroVision v.1.2.7 software, which was developed to analyze high- definition images of thin sections. Image analysis of thin sections is a well-known method for quantitative analysis of pore structures and rock characterization. The process of DIA for porosity prediction comprises 2.7. Core Flooding Experiments. The experiments were conducted at 62 °C with 2775 psi back pressure and 3500 psi overburden pressure. Table 6 displays the experimental sequences. The four cores from D-94 were used to examine polymer flooding in the tertiary recovery mode. The experimental steps were as follows: (1) two pore volumes (PV) of SW were injected into the core at 0.28 mL/min, (2) two PV of polymer solutions were injected at 0.06, 0.11, and 0.28 mL/min to avoid potential plugging problems, and (3) one PV of SW was injected at 0.28 mL/min as additional waterflooding. The four cores from M-04 were used to perform polymer flooding in the secondary recovery mode: (1) two PV of polymer solutions were injected at 0.06, 0.11, and 0.28 mL/min and (2) one PV of SW was injected at 0.28 mL/min as additional waterflooding. The flow rates used in the core flooding experiments were chosen to ensure that the Figure 4. Image selection pattern (selection pattern of 12 thin sections for core M-04-H-2).
Table 6. Experimental Sequences from well D-94 at the depth of 1922 m. This sample belongs to the same section of the reservoirs but is not used for core flooding experiments.
Table 6. Experimental Sequences from well D-94 at the depth of 1922 m. This sample belongs to the same section of the reservoirs but is not used for core flooding experiments.
These two shape factors were used for pore shape and morphological characterization. Circles, squares, ellipses, and rectangles are examples of geometric forms that were defined according to the criteria listed in Table 7. Figure 6. Viscosity variations of polymer FP-5115 solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
These two shape factors were used for pore shape and morphological characterization. Circles, squares, ellipses, and rectangles are examples of geometric forms that were defined according to the criteria listed in Table 7. Figure 6. Viscosity variations of polymer FP-5115 solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 5. Object extraction by gray intensity threshold (the red section represents intragranular porosity and the green section represents intergranular porosity).
Figure 5. Object extraction by gray intensity threshold (the red section represents intragranular porosity and the green section represents intergranular porosity).
Table 7. Pore Geometric Equivalent Forms (Modified After Palacios~*) three main steps: image acquisition, image segmentation, and image measurement. Image acquisition. Based on the preliminary evaluation by optical microscopy, eight polished thin sections were selected. Twelve images from each thin section were obtained using the SEM technique following a systematic pattern (Figure 4) and a consistent standard image magnification scale to ensure adequate coverage of all thin sections.
Table 7. Pore Geometric Equivalent Forms (Modified After Palacios~*) three main steps: image acquisition, image segmentation, and image measurement. Image acquisition. Based on the preliminary evaluation by optical microscopy, eight polished thin sections were selected. Twelve images from each thin section were obtained using the SEM technique following a systematic pattern (Figure 4) and a consistent standard image magnification scale to ensure adequate coverage of all thin sections.
Figure 7. Viscosity variations of polymer FP-3430S solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 7. Viscosity variations of polymer FP-3430S solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 8. Viscosity variations of polymer guar gum solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 8. Viscosity variations of polymer guar gum solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 9. Polymer concentration required to achieve the desired viscosity in polymer solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Figure 9. Polymer concentration required to achieve the desired viscosity in polymer solutions (left) prepared in SW at 62 °C and (right) prepared in FW at 62 °C.
Table 9. Properties of Composite Cores
Table 9. Properties of Composite Cores
Figure 11. Mineralogical profile at Pool 1 reservoir. Figure 12. Sandstone classification.
Figure 11. Mineralogical profile at Pool 1 reservoir. Figure 12. Sandstone classification.
Figure 10. Thermal stability of the polymer solutions (left) in SW at 62 °C and (right) in FW at 62 °C.
Figure 10. Thermal stability of the polymer solutions (left) in SW at 62 °C and (right) in FW at 62 °C.
Figure 13. Contact angle of the FW drop on the 1-day-aged core.
Figure 13. Contact angle of the FW drop on the 1-day-aged core.
Figure 15. Oil recovery factor as a function of volume injected for four M-04 composite cores using FP-5115 and FP-34308: (left) high-permeability cores and (right) low-permeability cores. Figure 16. Grain size distribution before polymer flooding.
Figure 15. Oil recovery factor as a function of volume injected for four M-04 composite cores using FP-5115 and FP-34308: (left) high-permeability cores and (right) low-permeability cores. Figure 16. Grain size distribution before polymer flooding.
Figure 14. Oil recovery factor as a function of volume injected for four D-94 composite cores using FP-5115 and FP-3430S: (left) high-permeability cores and (right) low-permeability cores.
Figure 14. Oil recovery factor as a function of volume injected for four D-94 composite cores using FP-5115 and FP-3430S: (left) high-permeability cores and (right) low-permeability cores.
Table 10. Porosity Comparison After Applying Polymer Flooding in Pool 1 Composite Cores“ in the tertiary mode using FP-3430S (D-94-H-2 and D-94-L-1) for both high- and low-permeability cores.
Table 10. Porosity Comparison After Applying Polymer Flooding in Pool 1 Composite Cores“ in the tertiary mode using FP-3430S (D-94-H-2 and D-94-L-1) for both high- and low-permeability cores.
“Swi (initial water saturation), BF (before flooding), AF (after flooding), and DF (difference).
“Swi (initial water saturation), BF (before flooding), AF (after flooding), and DF (difference).
Table 11. Average Proportions of Pore Shapes Before and After Flooding®
Table 11. Average Proportions of Pore Shapes Before and After Flooding®
Figure 20. Mineral and textural changes observed in the high- permeability Pool 1 sandstones. (A) Optical microscope image before polymer flooding, (B) optical microscope image after polymer flooding, (C) SEM image before polymer flooding, and (D) SEM image after polymer flooding. Blue and black spaces represent porosities in the optical microscope and SEM, respectively. 4.1. Polymer Performance and Flooding Sequence Order on Oil Recovery. The use of polymer FP-S115 resulted
Figure 20. Mineral and textural changes observed in the high- permeability Pool 1 sandstones. (A) Optical microscope image before polymer flooding, (B) optical microscope image after polymer flooding, (C) SEM image before polymer flooding, and (D) SEM image after polymer flooding. Blue and black spaces represent porosities in the optical microscope and SEM, respectively. 4.1. Polymer Performance and Flooding Sequence Order on Oil Recovery. The use of polymer FP-S115 resulted
Figure 19. Porosity probability S-curves: (left) low-permeability sandstone cores and (right) high-permeability sandstone cores
Figure 19. Porosity probability S-curves: (left) low-permeability sandstone cores and (right) high-permeability sandstone cores
Figure 21. Mineral and textural changes observed in the low- permeability Pool 1 sandstones. Optical microscope images (A) before and (B) after polymer flooding and SEM images, (C) before, and (D) after polymer flooding. Blue and black spaces represent porosities in the optical microscope and SEM images, respectively.
Figure 21. Mineral and textural changes observed in the low- permeability Pool 1 sandstones. Optical microscope images (A) before and (B) after polymer flooding and SEM images, (C) before, and (D) after polymer flooding. Blue and black spaces represent porosities in the optical microscope and SEM images, respectively.
Figure 22. Proposed fluid—rock mechanism interaction model in low- permeability facies.
Figure 22. Proposed fluid—rock mechanism interaction model in low- permeability facies.
Figure 23. Differential pressure as a function of pore volume injected for high-permeability cores D-94-H-1 and D-94-H-2. Figure 24. Differential pressure as a function of pore volume injected for low-permeability cores D-94-L-1 and D-94-L-2.
Figure 23. Differential pressure as a function of pore volume injected for high-permeability cores D-94-H-1 and D-94-H-2. Figure 24. Differential pressure as a function of pore volume injected for low-permeability cores D-94-L-1 and D-94-L-2.
Figure 25. Differential pressure as a function of pore volume injected for high-permeability cores M-04-H-1 and M-04-H-2. Figure 26. Differential pressure as a function of pore volume injected for low-permeability cores M-04-L-1 and M-04-L-2.
Figure 25. Differential pressure as a function of pore volume injected for high-permeability cores M-04-H-1 and M-04-H-2. Figure 26. Differential pressure as a function of pore volume injected for low-permeability cores M-04-L-1 and M-04-L-2.
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