No abstract

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.

No abstract

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.

Improving hydrocarbon recovery from reservoirs needs both a better understanding of fluid flow through the reservoir porous media and new technologies. This paper addresses the later. Early steam breakthrough, unknown heat distribution and existing exploitation policies inhibit recovery of the remaining reserve of millions of barrels of heavy oil. Integrated reservoir studies and numerical simulations results indicated that proper reservoir management practices such as, reservoir monitoring, heat management, and reservoir characterization can improve final recovery. In order to better manage heat distribution in heavy oil reservoirs, it is required that vertical and areal distribution of temperature fronts are known. Permanent well-bore temperature distribution profile was obtained by means of the deployment of a 2,500 ft-long fiber optic cable in two parallel SAGD horizontal wells in Tia Juana field, western Venezuela. A laser bean is sent through the fiber cable and its reflections are collected by a computer, which transforms light reflections into distributed temperature profile information. Distributed temperature profile when compare to resistivity logs easily indicates and correlates which pay zones are being contacted by steam. Distributed temperature profile information allows reservoir engineers and operators to anticipate which horizons are being swept by steam and which are not. Proper actions on the injection profile can be made in order to improve spatial steam distribution and heat management. Fiber optics applications also include pipeline monitoring, horizontal well production profiles, electrosubmersible pump monitoring, cross-flow detection, gas lift valve performance, energy management and other general safety application.