# Evaluation of Novel Preformed Particle Gel System for Conformance Control in Mature Oil Reservoirs
## 4 Materials and Methods
### Methodology
Following the securement of the connection lines, a confining pressure exceeding the injection pressure by a minimum of 500 psi was applied. Initial brine injection was conducted at 1 mL/min until the pressure stabilized. PPG dry particles were swollen in 2% KCl brine, placed in the accumulator, and injected at the designated flow rate. After the pressure stabilized, the injection process was terminated, and lines were cleaned and prepared for post-water flood. Post-water flooding was conducted at flow rates of 0.1, 0.25, 0.5, 0.75, and 1.0 mL/min,  
Figure 20: Haake MARS III rheometer used to measure the elastic modulus of CMC/PAMBA PPG samples. until the pressure stabilized for each flow rate. The residual resistance factor (Frr) is a common term used to assess the plugging efficiency of the injected PPG, and it is calculated using the following equation [57]:  
\[F_{rr}=\frac{K_{b}}{K_{a}} \tag{2}\]  
where:  
\(\rm{K_{b}}\) is the initial permeability of the fractured sandstone model including the matrix and fracture. \(\rm{K_{a}}\) is the permeability of the fractured sandstone model after the CMC/PAMBA PPG placement. Five core flooding experiments were conducted to investigate the effects of gel particle size and injection flow rate on the gel injection pressure and the plugging efficiency. All experiments were performed at room temperature. Table 2 below shows the core flooding experiments. The experimental procedure is illustrated in Figure 22. \begin{table}
\begin{tabular}{c c c c c c c c c c} \hline \hline \multirow{2}{*}{**Exp. \#**} & **Core Matrix** & **Core** & **Core** & **Fracture** & **Gel Dry** & & & **Gel Injection** & \\  & **Permeability** & **Matrix** & **Length** & **Width** & **Particle Size** & **Brine** & **SR** & **Flow Rate** & **Flow Rate** (\({}^{\circ}\)**C)** \\  & **(md)** & **Porosity** & **(cm)** & **(mm)** & **(mm)** & **(microns)** & & & **(mL/min)** & **(\({}^{\circ}\)**C)** \\ \hline \hline
1 & & & & & & & & & 0.5 & \\ \hline
2 & & & & & & & & & & 1.0 & \\ \hline
3 & 95 & 0.2 & 14 & 1.0 & & & & 2\% & & 5.0 & \\ \hline
4 & & & & & & & 250–600 & & & 1.0 & \\ \hline
5 & & & & & & & Mixed & & & 1.0 & \\ \hline \hline \end{tabular}
\end{table} 
Table 2: Core flooding experiments. Figure 21: Core flooding setup. (**a**) is the swollen gel packed in the accumulator, (**b**) is the fracture model, and (**c**) is the wrapped fracture model inserted in the core holder. **Author Contributions:** Conceptualization, I.A.H. and B.B. ; Methodology, A.A. and A.B.A. ; Investigation, A.A. and A.B.A. ; Data curation, A.A.; Writing--original draft preparation, A.A. and A.B.A. ; Writing--review and editing, B.B. ; Supervision, I.A.H. and B.B. All authors have read and agreed to the published version of the manuscript. **Funding:** This research was funded by Qatar National Research Fund (a member of Qatar Foundation) for funding through Grant # NPRP13S-1231-190009. Al-Salam Petroleum Services Company, Qatar, is also acknowledged for co-funding this project. **Institutional Review Board Statement:** Not applicable. **Informed Consent Statement:** Not applicable. **Data Availability Statement:** All data and materials are available on request from the corresponding author. The data are not publicly available due to ongoing research using part of the data. **Acknowledgments:** The authors acknowledge the Qatar National Research Fund (a member of Qatar Foundation) for the financial support provided through Grant # NPRP13S-1231-190009. Additionally, recognition is extended to Al-Salam Petroleum Services Company, Qatar, for co-funding this project. It is important to note that the outcomes presented in this work are the sole responsibility of the authors. **Conflicts of Interest:** The authors declare no conflicts of interest.