Alkaline-Surfactant-Polymer Flood: From the Laboratory to the Field
- Martin Stoll (Shell E&P International Ltd) | Hamad Al-Shureqi (Shell E&P International Ltd) | Jose Finol (Shell E&P International Ltd) | Said Amor Al-Harthy (Petroleum Development Oman) | Stella Nneamaka Oyemade (Shell Petroleum Dev Nigeria SPDC) | Alexander de Kruijf (Petroleum Development Oman) | John N.M. Van Wunnik (Petroleum Development Oman) | Fred Arkesteijn (Shell EPT-R) | Ron Bouwmeester (Shell Intl. E&P BV) | Marinus J. Faber (Shell Intl. E&P BV)
- Document ID
- Society of Petroleum Engineers
- SPE EOR Conference at Oil & Gas West Asia, 11-13 April, Muscat, Oman
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 1.8 Formation Damage, 5.2.1 Phase Behavior and PVT Measurements, 5.6.5 Tracers, 2.2.2 Perforating, 4.3.4 Scale, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2 Reservoir Fluid Dynamics, 5.5.8 History Matching, 5.1 Reservoir Characterisation, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 5.4.1 Waterflooding, 5.7.2 Recovery Factors, 5.5 Reservoir Simulation, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.7 Carbonate Reservoir, 4.1.2 Separation and Treating, 5.1.5 Geologic Modeling, 1.6.9 Coring, Fishing
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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.
Culminating from intense research work carried out across the petroleum industry and universities throughout and after the 1970's, Nelson et al (Nelson, 1984) proposed a new type of chemical flooding process termed "Enhanced Alkaline Flood??, or perhaps more commonly known today as "Alkaline Surfactant Polymer Flood?? (ASP). While the previously known chemical flooding processes had suffered from inherent disadvantages (significant adsorptive surfactant loss in a plain surfactant flood; long duration of a dilute alkaline flood), the ASP process promises to mitigate these through the combined chemical phase behaviour of the injected surfactant and the in-situ generated natural surfactant known as petroleum soaps. Augmented by an internal polymer drive suitably adjusted to the oil viscosity, the ASP process routinely reduces oil saturation to zero in laboratory core floods. Its range of applicability is largely determined by stability criteria for the involved chemicals and by economic constraints: a reservoir temperature below 90°C to prevent polymer degradation, a formation water salinity below 20 wt.% to limit the necessary polymer concentration, a sufficiently high permeability greater than a few tens of millidarcies to allow the polymer molecules propagating, an oil viscosity not exceeding a few hundreds of centipoises to warrant sufficient injectivity of the ASP slug.
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