Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods (such as SAGD) cannot be applied, like in thin reservoirs. Polymer flooding in heavy oil recently proved to be a viable recovery method. The use of surfactants for heavy oil is reported only in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated to the use of alkali as well as negative impacts on project logistics are often reported. Objective of this work is to demonstrate at lab scale the efficiency of alkali-free surfactant/polymer process in the context of heavy oil reservoirs. The present investigation was focused on a Canadian heavy-oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation was designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions were evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation were then evaluated in corefloods. Cores at Swi were first polymer flooded until no oil is produced to reach a pseudo-residual oil saturation. A surfactant-polymer formulation was then injected after the polymer flood. Results show that additional oil was produced as a continuous oil bank, corresponding to 90% ROIP. This indicates that the surfactant was able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work are also be presented on optimization of the process including injection strategy improvement and surfactant dosage reduction.
If chemical stability of EOR polymers has been extensively studied over the past decades, surfactants have attracted less attention except for a few reference papers. This article presents existing and new data on the chemical stability of a variety of surfactants classically used for EOR applications in aqueous solutions. The aim is to clarify under which reservoir/operational conditions each surfactant types and combinations can be safely used regarding chemical stability. Anionic surfactants, including alkyl benzene sulfonates, internal olefin sulfonates, alkyl ether sulfates and alkyl glyceryl ether sulfonates are investigated. Their thermal stability is monitored in a wide range of conditions: temperature from 25 to 120°C, pH, oxygen level… Their performance in terms of solubility and interfacial tension reduction is monitored through classical bulk aqueous tests over several months. In addition, liquid chromatography and two phase titration are used to identify any loss of integrity of the studied products. Results indicate that both hydrolysis and oxidation mechanisms should be considered to guarantee long term stability of EOR surfactants. Hydrolysis sensitive surfactants, e.g. alkyl ether sulfates, undergo hydrolysis with associated loss of performances at high temperatures. This is shown to be true even in alkaline conditions as pH essentially impacts degradation kinetics and not inner stability. This study also shows that properly selected EOR surfactants and blends can withstand very harsh conditions (up to 120°C) for several months allowing high confidence in EOR process performance along with time in a reservoir. Oxygen management is however critical to achieve such performance. This paper initiates a series of articles giving a clear framework for safe use of surfactants in oil reservoirs regarding their chemical integrity. It is intended to provide reliable guidelines for products selection, lab evaluation and field application. These aspects, often underestimated or simply by-passed in some EOR studies, are critical to ensure field trial success in challenging conditions.
Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods cannot be applied, like in thin reservoirs. The use of surfactants for heavy oil is only reported, both at lab and field scale, in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated with the use of alkali as well as negative impacts on project logistics are often mentioned. The objective of this work is to demonstrate at lab scale the efficiency of alkaline-free surfactant-polymer processes in the context of heavy oil reservoirs.The present investigation is focused on a Canadian heavy oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation is designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions are evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation are then evaluated in corefloods.Cores at Swi are first polymer flooded until no oil is produced to reach a residual oil saturation. Surfactant-Polymer formulations are then injected. Typical results show that additional oil is produced as a continuous oil bank (up to 100% ROIP depending on the slug size) and with a moderate adsorption if a salinity gradient strategy is applied (typically 0.2 mg surfactant per g of rock). This indicates that the surfactant is able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work will also be presented on optimization of the process through injection strategy improvement and surfactant dosage reduction as well as on extrapolation of the lab results to field-scale technical and economical feasibility.
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