Gel conformance control technology is widely used in moderate and high temperature reservoirs. However, there are few studies on shallow low-temperature and high-salinity reservoirs. The difficulties are that it is difficult to crosslink at low temperatures and with poor stability at high salt concentrations. Therefore, the PHRO gel was developed, which was composed of gelatinizing agent (polyacrylamide), crosslinking agents (hexamethylenetetramine and resorcinol) and crosslinking promoting agent (oxalic acid). The PHRO could form high-strength gels in both deionized water and high-concentration salinity solutions (NaCl, KCl, CaCl2 and MgCl2). The observation of the microstructure of PHRO gel shows that a strong “stem—leaf”-shaped three-dimensional network structure is formed in deionized water, and the network structure is still intact in high-concentration salt solution. The results show that PHRO has good salt resistance properties and is suitable for conformance control of low-temperature and high-salinity reservoirs.
As a result of low porosity and low permeability in tight reservoirs, spontaneous imbibition plays an important role in oil recovery. While wettability has a crucial impact on the imbibition, the mechanism of the effect of wettability on imbibition is still unclear. In this study, we screened the surfactants with similar interfacial tension (IFT) at the same concentration to study the wettability properties, which will contribute to improve the oil recovery tight reservoir. Two betaine surfactants, lauramide propyl hydroxysulfonated betaine (LHSB) and cocamidopropyl betaine (CAB), were screened according to their IFT. Through spontaneous imbibition experiments, the recovery of LHSB (27.26%) was better than that of CAB (21.69%). The contact angle method and U.S. Bureau of Mines method were used to analyze the core wettability comprehensively. After LHSB treatment, the core wettability index turned to hydrophobic and the wettability index changed from −0.06 to −0.56. However, the wettability index did not change significantly after CAB treatment (−0.15). Further molecular simulations showed that, after the surface of the rock is modified by LHSB, the oil droplets spread gradually and the interface energy with the quartz was enhanced. In combination of the analysis of the ζ potential and adsorption measurement, LHSB is predicted to be adsorbed in a single-layer configuration, while CAB formed a double-layer configuration, which caused the difference in wettability. It can be speculated that, when the surfactant changes the pore surface of the tight sample toward hydrophobic, the oil-wet surface promotes the residual oil droplets to form a continuous phase and, at the same time, reduces flow resistance of the water phase, thereby increasing the spontaneous imbibition rate and the ultimate recovery. This study will help to understand the wettability impact on imbibition by the surfactant and contribute to the improvement of tight oil reservoir recovery.
The pore and throat structure of tight oil reservoir cores is complex, and the resistance of oil drop to discharge from the core is very high during dynamic imbibition. Surfactant has good ability in interfacial tension reduction and wettability reversal. It can reduce oil drop discharge resistance and enhance oil recovery effectively during dynamic imbibition in tight reservoirs. Here, we first analyzed the pore throat structure and mineral composition of tight core, and then the oil drop visualization instrument was used to study the discharge behavior of oil drop during dynamic imbibition. The oil drop discharge form was analyzed, and the influence of various factors on the oil drop discharge behavior was explored, and then the dynamic imbibition performance of surfactant in tight cores was obtained. The core throat diameter was mainly distributed in 0.07–1.1 μm, and the hydrophilic mineral content in core reached 50.8%. In the case of fluid flow in fracture, the oil drop discharge from near fracture matrix was faster, and its growth rate in height and width was faster than that without external fluid flow. Within a certain range, with the increase of IFT, the rate of core imbibition increased gradually. When the IFT increased from 0.32 mN/m to 0.59 mN/m, the oil drop rapture time decreased by 66.3%. The growth rate of oil drop discharged from the top and side of the core was faster than that from the bottom surface. Furthermore, it was easier to discharge. With the core thickness reduced by half, the rapture time of oil drop was reduced by 74.7%. For tight reservoirs, hydraulic fracturing can create more fracture surfaces and reduce the size of matrix blocks, which contributes to reduce the oil drop discharge resistance during imbibition and improve the oil recovery. This study provides a basis for surfactant to improve dynamic imbibition and oil production performance of tight sandstone oil reservoir.
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