After two decades of relative calm, chemical EOR technologies are currently revitalized globally. Techniques such as alkaline surfactant-polymer flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared to, for example, thermal enhanced oil recovery, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field. Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale whereas applications of surfactant-polymer (SP) or alkaline surfactant-polymer (ASP) flooding were limited to multi-well pilots or to small field scale. Next to the oil price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and of strong emulsions in the production facilities. Having identified significant target oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full- field ASP developments. The paper discusses the extensive design process that was followed. Starting from a description of the optimisation of chemical phase behaviour in test tubes as well as core-flood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir simulation model. Using this model we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern-flood pilot.
Summary After two decades of relative calm, chemical enhanced-oil-recovery (EOR) technologies are currently revitalized globally. Techniques such as alkaline/surfactant/polymer (ASP) flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared with, for example, thermal EOR, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field. Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale, whereas applications of surfactant/polymer or alkaline ASP flooding were limited to multiwell pilots or to small field scale. Next to the oil-price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and formation of strong emulsions in the production facilities. Having identified significant target-oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full-field ASP developments. This paper discusses the extensive design process that was followed. Starting from a description of the optimization of chemical phase behavior in test-tube and coreflood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir-simulation model. Using this model, we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern- flood pilot.
Chemicals such as anionic surfactants and polymers often contain groups that complex divalent ions such as Ca2+. The formation of divalent ion complexes can decrease emulsifying or viscosifying power and lead to adsorption or precipitation. This is particularly relevant in chemical enhanced oil recovery, where high viscosities and low interfacial tensions are required for mobility control and the formation of oil–water microemulsions, respectively. In this work, we use a Ca2+-sensitive dye to determine the Ca2+ concentration and Ca-complex formation constants in solutions containing complexing agents. This method can be used to rapidly screen the affinity of different chemicals to form Ca-complexes in low-salinity solutions. The complex formation constants can be implemented into chemical flooding simulators to investigate the interplay with mineral dissolution and cation exchange and model adsorption processes.
Alkaline Polymer Surfactant (ASP) flooding is an Enhanced Oil Recovery (EOR) technique aiming to mobilise remaining and residual oil. Estimating the average oil saturation prior to and post ASP flooding is a recognised challenge, but is vital to the evaluation of an ASP pilot. The use of oil-water partitioning tracers is a method to determine the average oil saturation in the water-swept regions between wells. The implementation of partitioning tracer technique is known in the industry to evaluate effectiveness of waterfloods, but its applicability in ASP flooding is a topic of investigation due to additional complexities. Often, the partition coefficients of tracers depend on salinity of the aqueous phase. It is equally important to know how the presence of polymer and surfactant may influence the behaviour of partitioning tracers. Laboratory study has been performed to analyse the behaviour of partitioning tracers prior to and post ASP injection for a field that is currently undergoing sea water injection and is being evaluated for ASP flooding later in the field life. A group of six oil-water partitioning tracers have been included in the study. Batch (bottle tests) and dynamic (core flood) experiments were performed to evaluate the partitioning behaviour of the tracers. The residual oil saturation to water (Sorw) before ASP flooding was determined using pulse injections of tritium labelled water (HTO). Several passive tracers were also injected in the core floods and their retention times were compared with that of HTO. Herein we describe evaluation of oil saturation, through the tracer responses, over a range of brine compositions such as soft brine, sea water, ASP and polymer solutions. Batch studies indicate the dependency of the partitioning of the tracers on brine salinity. The results of core floods show earlier breakthrough of anionic passive tracers in comparison with HTO suggesting possible rock/fluid interactions for the anionic passive tracers. The residence time distribution of HTO measured before, during and after the ASP flooding illustrates that the flow paths available for water were changed during ASP flooding. The paper highlights the importance of good laboratory experimental protocols using a more accurate passive tracer such as tritium labelled water. The results from the experiments draw attention to the uncertainties associated with the flow of tracers under changing salinity and chemical composition.
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