Experimental Evaluation of Combined Plugging System for CO₂-Improved Oil Recovery and Storage

Abstract

High-performance CO 2 -improved oil recovery (IOR) and storage technology is one of the most promising measures for global oilfield companies to achieve zero carbon targets. Due to the severe heterogeneity of most petroleum reservoirs and the significant density difference between CO 2 and reservoir fluid, the efficiency of CO 2 -IOR and storage is usually limited. In this paper, a hightemperature and high-pressure 30 cm core displacement experiment was used to study the CO 2 conformance control performance of both the single-and the combined plugging system in long sandstone cores. The single systems evaluated included polymer gels, CO 2 foams, and CO 2 -responsive thickening polymer (CO 2 -RTP) systems. The combined systems were pairwise combinations of the three of them. Results show that the pressure rise and maximum breakthrough pressure of the gel system were the highest among three single-plugging systems. Its plugging efficiency was the highest, reaching 86.13%. At the same time, its gas production reduction rate was also the highest, reaching 95.71%. In the parallel 30 cm core plugging experiments, three combined plugging systems all showed excellent plugging and CO 2 conformance improvement performance. Among them, the combined plugging systems containing polymer gels had larger plugging efficiency, and their gas production reduction ratios reached about 90%. Compared with single systems, the combined plugging systems had the advantages of easy injection and in-depth propagation, which can significantly improve CO 2 conformance and oil recovery. The research results of this study can provide the experimental understanding and theoretical guidance for the current tricky oilfield problems of CO 2 channeling.

Experimental Performance Evaluation and Optimization of a Weak Gel Deep-Profile Control System for Sandstone Reservoirs

“…The weak gel solution was prepared from low molecular weight FPAM and cross-linking agent PEI-600. The steps in this experiment are as follows. A fixed volume of water was added to a 500 mL beaker, and the deoxidant (0.005 wt %) and the dosage of salt were mixed in. The dosage of the main ingredient (FPAM) was calculated, weighed accurately using the balance, added to the beaker, and stirred at 600 rpm for the first 10 min, followed by 400 rpm for 4 h . Afterward, the solution was aged for 24 h. The amount of cross-linking agent (PEI-600) was calculated, weighed accurately, added to the beaker, and then stirred for 20 min at 400 rpm to ensure proper dissolution. The prepared solution was poured into a glass medicine bottle and placed in the thermostatic chamber.…”

“…(1) A fixed volume of water was added to a 500 mL beaker, and the deoxidant (0.005 wt %) and the dosage of salt were mixed in. (2) The dosage of the main ingredient (FPAM) was calculated, weighed accurately using the balance, added to the beaker, and stirred at 600 rpm for the first 10 min, followed by 400 rpm for 4 h. 31 Afterward, the solution was aged for 24 h.…”

Review on Experimental Investigation into Formation Damage during Geologic Carbon Sequestration: Advances and Outlook

“…However, high formation damage was reported from the dolomite rock as a result of the reaction between CO 2 and silicate minerals. Similarly, in either homogeneous or heterogeneous rocks, formation damage may happen as a result of precipitation or the blockage of water, making the damage more severe …”

“…84 However, high formation damage was reported from the dolomite rock as a result of the reaction between CO 2 and silicate minerals. Similarly, in either homogeneous or heterogeneous rocks, 85 formation damage may happen as a result of precipitation or the blockage of water, 74 making the damage more severe. 86 Furthermore, numerous researchers from the field and experimental studies have demonstrated that the dissolution of active minerals may raise permeability or porosity, 87,88 but this is not well-suggested because the increase of permeability may result in a high flow rate of CO 2 during injection, which could potentially result in a reduction in the pressure gradient, particularly at the near wellbore zones.…”

Effects Evaluation on Multiround Injection of a N2 Foam & Viscosity Reducer to Improve the Recovery of Fault-Block Heavy Oil Reservoir with Edge-Bottom Water: A Two-Dimensional Visualization Experimental Study

“…This leads to widespread residual oil remaining at the top and boundaries of the inclined reservoir layers. , Furthermore, the viscosity difference between oil and water is significant, making it difficult for the crude oil to flow during the water flooding stage. This leads to a rapid increase in water cut, and water flooding methods are hard to further improve the recovery factor. , In order to address the low recovery factor in fault-block reservoirs with bottom water, many scholars have conducted research on how to enhance the oil recovery after water flooding. − Various auxiliary water flooding techniques have been implemented in domestic oil fields, such as nitrogen foam flooding and viscosity reducer flooding in the Shengli oilfield, Liaohe oilfield, and Bohai oilfield. − These techniques have all resulted in a decrease in water cut and an increase in crude oil production. Both laboratory studies and field applications have shown that for edge-bottom water fault block reservoirs, nitrogen foam flooding and viscosity reducer flooding technologies have significant advantages among the existing enhanced oil recovery technologies. , …”