Surfactant Flooding in Challenging Conditions: Towards Hard Brines and High Temperatures

Abstract

Surfactant flooding processes become challenging in hard brines and/or at high temperatures. When hard brine is used as surfactant make-up brine (injection brine), chemical adsorption is high using conventional injection strategies. This makes the overall process performance limited. High temperature (>80°C) raises thermal stability issues with subsequent loss of effectiveness.This paper illustrates recent progresses achieved in those difficult conditions. We show that good performances can be obtained by combining appropriate formulations with adapted injection strategies, i.e. slugs design, depending on reservoir conditions. A particular emphasis is set on solutions that can be applied in the field.High performances solutions first rely on selecting appropriate surfactants and polymers from an extended portfolio of industrial products. We demonstrate that ultra-low interfacial tension formulations can be successfully designed for a wide range of conditions, i.e. from mild to difficult conditions, including very hard brines, very high salinities (>200 g/L) and/or high temperatures (up to 120°C).Various coreflood experiments are then reviewed to define guidelines to address challenging conditions:  Starting from mild conditions, i.e. soft brine at moderate temperature, we show that performance of surfactant flooding relies on the combination of properly designed chemical formulation and appropriate injection strategy. In soft brine, a salinity gradient is shown to provide high performance; In hard brines, surfactant adsorption is significantly higher than in soft brines. We demonstrate that a conventional salinity gradient injection strategy becomes ineffective when hardness is increased. Surfactant adsorption is drastically reduced (<0.2 mg/g) when using appropriate adsorption inhibitors. This results in a very high oil recovery (90 %ROIP) with performances comparable to the one achieved in soft brine conditions; For high temperatures (>70-80°C), adapted protocols are required to address thermal stability issues and subsequent loss of performances. New surfactants, polymers and additives are available to address these conditions. Successful oil recovery experiments done up to 120°C are discussed.The paper will demonstrate how surfactant flooding can be successfully applied in challenging reservoir conditions opening new opportunities for chemical EOR.

Silica Nanofluids in an Oilfield Polymer Polyacrylamide: Interfacial Properties, Wettability Alteration, and Applications for Chemical Enhanced Oil Recovery

“…Subsequent to water flooding, various EOR techniques, such as chemical EOR, thermal EOR, microbial EOR, and gas injection EOR, are employed depending upon the nature of the reservoir. Out of these EOR methods, chemical EOR methods are one of the most promising methods for conventional crude oil reservoirs due to their improved recovery factor. − Chemical methods primarily include the use of polymer (P), surfactant–polymer (SP), and alkali-surfactant–polymer (ASP) flooding and are applied to enhance the oil recovery by reducing the interfacial tension (IFT) between the crude oil–water present within the reservoir. , Chemical EOR methods, although they have developed over the years, need improvement for their application toward complex reservoir conditions , and for improved reservoir characterization …”

“…4−6 Chemical methods primarily include the use of polymer (P), surfactant− polymer (SP), and alkali-surfactant−polymer (ASP) flooding and are applied to enhance the oil recovery by reducing the interfacial tension (IFT) between the crude oil−water present within the reservoir. 7,8 Chemical EOR methods, although they have developed over the years, need improvement for their application toward complex reservoir conditions 9,10 and for improved reservoir characterization. 11 Nanotechnology helps to improve the performances of various processes by exploiting the properties of various nanoparticles which typically have the dimensions of the order of 100 nm or less.…”

Effect of the surface charge of silica nanoparticles on oil recovery: wettability alteration of sandstone cores and imbibition experiments

“…Because wettability is one of the most important properties controlling oil recovery [2,7,26], the efficiency of this process has been improved using wettability modifiers such as surfactants and polymers [6,29]. The utilization of these agents can induce changes in the wettability of the rock surface from an oil-wet to a water-wet state, which affects the flow behavior of water and oil in porous media [6].…”

Study of mechanisms responsible for foaming-agent loss in porous media at high-temperature conditions

“…Then, it is important to know reservoir salinity for surfactant selection and to avoid any future complication. Besides, adsorption inhibitors could allow achieving good performances with a properly designed formulation [57].…”