Effect of Brine Dilution and Surfactant Concentration on Spreading and Wettability

Abstract

The interfacial phenomena of spreading and adhesion of fluids on rock surfaces have serious implications because of their impact on production strategy and oil recovery. The present study reports new experimental data on the effect of brine dilution and surfactant addition on spreading and adhesion behavior of Yates crude oil on dolomite surfaces. Spreading and adhesion have been characterized through measurements of oil-water interfacial tension (IFT) and dynamic (water-advancing and receding) contact angles. The interfacial tension was measured using Computerized Axisymmetric Drop Shape Analysis (CADSA) Technique, which was calibrated against the well-known du Nuoy Ring Technique. The Dual-Drop-Dual-Crystal (DDDC) Technique has been used to measure dynamic contact angles. In order to study the effect of brine dilution, Yates reservoir brine was mixed with deionized water (DIW) in various proportions. For each diluted brine, crude oil-water IFT, water-advancing and receding contact angles were measured. The oil-water IFT initially decreased as the volume percent of brine in the mixture decreased. However, the IFT increased with further dilution of reservoir brine with DIW. A decreasing trend was observed in the behavior of water-advancing contact angle with brine dilution. This indicated that the initial oil-wet nature of the system was changed to intermediate-wettability simply by diluting the reservoir brine. However, a strange behavior of spreading of crude oil drop against brine on the dolomite surface (with large water-receding contact angles) was observed at certain brine dilutions. This spreading of crude oil appears to be related to interfacial tension in a manner similar to Zisman's observations in solid-liquid-vapor systems. The use of surfactants to enhance oil recovery through reduction in IFT is well known in the industry. However, this study examines the capability of certain surfactants to alter wettability in addition to reducing IFT. For the Yates reservoir rock-fluids system, an Ethoxy Alcohol surfactant altered the strongly oil-wet nature (advancing angle of 158°) to water-wet (advancing angle of 39°) at a concentration of 3500 ppm. While the DDDC technique yielded significant changes in wettability due to surfactant addition, the Wilhelmy Plate Technique remained insensitive throughout the range of surfactant concentrations. The practical significance of this study is that it identifies two simple modes through surfactant addition and brine dilution to alter wettability to minimize capillary trapping of oil. Introduction The primary and secondary oil recovery processes currently being practiced have been successful in recovering only about a third of the original oil in place leaving behind nearly two-thirds as residual oil. This points out the need to study and implement new and innovative methods to recover the remaining oil. This in turn requires an understanding of the interactions that take place between crude oil, brine and the rock surface, which are collectively represented by the term wettability. Reservoir wettability is affected by several factors including roughness and mineralogy of the rock surfaces and the compositions of brine and crude oil. The effect of rock mineralogy and surface roughness have been reported previously (SPE # 75211) and this paper presents the effects of fluid characteristics brine dilution and surfactant concentration) on spreading and wettability as characterized by receding and advancing contact angles, respectively. Effect of Brine Composition on Wettability Several previous studies have been reported in the literatures that describe the effect of brine composition on formation damage and waterflooding. Mungan(1) investigated the role of pH and salinity changes on core damage. He concluded that the primary cause of permeability reduction was blocking of the pore passages by dispersed particles. A change in the salt concentration (salinity) or pH of the reservoir fluid can liberate these clay particles and cause the clay particle to swell and clog the pores thus resulting in lower permeability.

Review of Recovery Mechanisms of Ionically Modified Waterflood in Carbonate Reservoirs

“…It has been observed by many researchers that advanced water influences the capillary forces, and this is seen mainly in contact angle (wettability) alteration rather than IFT change. However, Vijapurapu and Rao observed an approximately 10% decrease in IFT (22.1–12.4 dyn/cm) by diluting Yates reservoir brine with deionized (DI) water to a moderate level (60% brine and 40% DI water) compared to more dilution (90% DI water and 10% brine) in an oil-spreading study. Alotaibi and Nasr-El-Din measured the IFT between oil and brine using the pendant drop method.…”

An Experimental Investigation of Nanoparticles Assisted Surfactant Flooding for Improving Oil Recovery in a Micromodel System

“…Changing wettability towards adequate circumstances (more water preferable) to increas oil recovery factor has been selected in plenty of research studies. These works show the high capability of surfactants to change wetness of surface [1][2][3][4][5]. Other associated mechanism with surfactant injection is the interfacial tension reduction between oil and water owing to mitigate capillary forces which allows recovering of trapped oil.…”

Evolution and Interfacial Dynamics of Thin Electrolyte Films in Oil–Brine–Carbonate Rock Systems due to Chemical Equilibrium Disruptions

“…A change in the wettability of any particular rock surface is determined by contact angle measurements. Factors that affect the contact angle and therefore, wettability include pressure and temperature, − rock mineralogy, ,, pH, , salinity, ,,− and the surface reactive components mostly reported as total acid number (TAN) and total base number (TBN) . Changes in these factors can be investigated by analyzing the stability of the thin liquid film. , The augmented Young–Laplace equation is used to assess the stability of liquid films bound by surfaces that deviate from ideal solid surfaces, represented by the following equation P normalc = Π T + 2 σ ow H where P c [Pa] and Π T are respectively the capillary pressure and the total disjoining pressure.…”