Search

A phenolic resin cross-linked nonionic polyacrylamide (NPAM) gel used for in-depth profile control was systematically analyzed. Long gelation time and strong gel strength of the gel system was obtained by adjusting NPAM or cross-linker concentration. An increase in temperature and salt concentration accelerated the gelation process and improved the gel strength. Although shearing brings a negative effect on gel performance, the gel system still had strong gel strength which could make it long-term stability in in-depth formation. Differential scanning calorimetry determined that this gel system should be used for oilfield application at temperatures below 143 °C. A compact three-dimensional network structure was formed in the bulk gel system and in porous media which contributed to long-term gel stability in the formation. Sand-pack flow experiments showed that the NPAM gel had a good plugging capacity and could selectively plug high permeability zones. By retention, adsorption, and bridging across the pore throats, the gel systems effectively reduced the permeability of porous media in high permeability zones and diverted fluid into low permeability zones, and thus improved the formation profile. Furthermore, this gel system for in-depth profile control treatment was successfully used in the Xinjiang oilfield of China which provided a reference for other similar high water cut oilfields for water control worldwide. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is required during development of tight oil reservoir. Flowback fluid, usually surfactant, is generally used in fracturing fluid to accelerate the fluid flow back. For the reservoir with matrix and fracture construction, this flow of surfactant is dynamic imbibition. Betaine surfactant has good salt and temperature tolerance. In this study, a betaine surfactant was characterized from interfacial tension and wettability. In order to simulate complex fracture conditions, a matrix-fracture network model was established. It was featuring adjustable fracture width from 476.5 to 72.8 μm through changing the confining pressure. Then series of experiments were carried out on the dynamic imbibition in tight oil fracture network model with the aid of surfactant. Various factors that impact on the oil recovery during dynamic imbibition of models were examined. The oil recovery by dynamic imbibition was gradually increased with the increasing concentration of surfactant, matrix permeability, and temperature. The oil recovery reached to 22.6% with surfactant concentration of 0.5 wt%. With various surfactant flow rate, the oil production reached to 18.1% at a flow rate of 0.1 mL/min during dynamic imbibition. The oil distribution in the matrix and fracture was analyzed using Magnetic Resonance Imaging (MRI) method. It showed that the surfactant can effectively improve the oil recovery in the matrix near fracture during dynamic imbibition. The study would provide further understanding for the dynamic imbibition with aid of surfactant in tight oil sandstone reservoir after fracturing. • A fracture network tightsand model is developed, featuring controllable fracture width. • The dynamic imbibition behavior of an amphoteric surfactant in fracture network is clarified with various factors. • An amphoteric surfactant is characterized from interfacial tension and wettability. • The oil saturation in fracture and rock matrix during dynamic imbibition is illustrated by MRI. [ABSTRACT FROM AUTHOR]