fax 01-972-952-9435. AbstractThe EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases.Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper presents an efficient solution approach for the latter issue.The approach is based on the construction of quadratic response surface models (surrogates) of reservoir simulator outputs and three-level D-optimal design of experiments. It allows to effectively and efficiently establish the optimum ASP injection scheme, and was applied to determine the optimal values of injection rates, slug size and initial date for injection of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela. The optimum injection scheme resulted in substantial savings in chemicals used when compared to the laboratory design.
A reliable future development plan of an oilfield would require that all of the elements in the petroleum system are modeled in an integrated manner if a timely response, a more realistic economical evaluation, and risk analysis are needed for better decisions making. The main goal for future development of Tomoporo field is to change the traditional focus (petroleum system elements by separated) by enabling to multidisciplinary team members to take advantage of their expertises within a collaborative environment based on interaction among petroleum system components. The Tomoporo field's hydrocarbon reserves have been largely developed in offshore, but barely in onshore. It has been planned to increase production twice through new producing wells in onshore area which presents several limitations for handling production. Also a plan for pressure support, and improved oil recovery have been considered by implementing a waterflooding project. This paper shows an innovative integrated asset methodology, applied for forecasting scenarios where reservoir, surface network, geographic location aspects, economy, risk, and uncertainty analysis were considered. The evaluation of forecasting scenarios was performed by implementing an integrated asset modeling (IAM) where all of simulation scenarios were coupled with a surface network model. Such network modeling included itself three integration levels to address complexity of surface facility needed for future offshore-onshore field development. In addition, an innovative link from reservoir-surface network models to the economic model was developed for a fully assisted asset modeling, resulting in faster and more reliable scenarios evaluation. The IAM for Tomoporo field provided valuable information for all team members of the production stream, maximizing benefits from decision making based on a fully coupled asset model. This integrated approach determined that greater recovery factor and less reservoir pressure drop are achieved if an onshore flow station is added for new onshore wells in spite of existing capabilities in offshore surface facilities. The IAM approach triggered warnings about future needs (investment, expenses), and also to be alert in minimizing bottlenecks in order to ensure no violation of surface capacity constraints. In addition, it allowed to define operating limits of water injection plants, enabling that optimum operation conditions are set, and the added value of the Tomoporo field development be maximized.
This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as X-plot, comprehensive Y-plot (cY-plot), and WOR vs cumulative oil (Np) for the case of unstable immiscible displacement (viscous-oil fingering effect). These methods were reviewed based on fractional flow analysis (FFA) for unstable immiscible waterflood. These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters A and B). Those assumptions tend toover predict ultimate oil recovery for the case of viscous-oil waterfloods because flow functions do not capture the viscous fingering effect. This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by Luo et al. (2016), which accounts for viscous fingering effects. In addition, an accurate exponential expression of kro/krw ratio as function of water saturation and an exact solution for a water saturation-dependent parameter B (named Bj) are proposed. New approaches of classic analytical methods were derived, and both laboratory and field cases were tested at the light of new equations. Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new X, cY, and WOR functions are viscous-finger number dependent (Nvf). The bigger the Nvf the lower the oil recovery, the earlier the water breakthrough, and the narrower the water saturation ranges. In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.
Despite the great effort made to characterize reservoir rock, proper techniques in grouping rock type, in predicting permeability, and also in estimating water saturation from reservoirs that exhibit high variability in permeability-porosity relationship are still debatable today. In addition, core sampling for both routine and special core analysis may be biased in spite of the wide number of existing rock types, mostly in the case of heterogeneous rock reservoirs.The main objective of this work was to develop a new mathematical expression for water saturation prediction, in the case study Urdaneta-01 heavy oil reservoir, in Maracaibo Lake basin, Venezuela, based on an alternative approach of traditional Leverett J-function. This new equation was developed by introducing two additional power-fit coefficient as function of water saturation (for specific capillary pressure values), Leverett J-function slope (from all values of capillary pressures test), and height above free water level (FWL). In addition, an automatic Rock Type Index was used to accurately estimate reservoir permeability.A reliable water saturation profile according to rock type was obtained from the new water saturation approach. At least 3 to 5% difference between water saturation from log-based traditional techniques and that of the alternative approach (new expression for Sw) was obtained, mostly in heterogeneous intervals. Also it was determined that the innovative rock type indicator provides a better permeability estimation and rock description because of the high definition of rock type obtained from this new technique. IntroductionUrdaneta-01 reservoir represents one of the largest oilfield in Maracaibo basin, Venezuela, in terms of heavy oil reserves. The reservoir as a whole is experiencing a rapid pressure decline due to high flow rates by using electro-submersible pumps as one of their main artificial lifting methods.As a result of the installation of electro-submersible pumps, completion problems and early water production have been occuring. The reservoir does not have a strong waterdrive and is very heterogeneous. Additionally, to maintain pressure and to improve oil recovery, several enhanced oil recovery pilot projects are being planned, such as in-situ combustion, steam and polymer injection.Understanding and solutions of all of the issues mentioned above are highly dependant of having both static and dynamic accurate models. Appropiate models of water saturation, porosity, permeability, and rock typing, which represent the output variables of the static model and the input variables to the simulation model are necessary to explain the past, the current and the future performance of the reservoir. The water saturation distribution that results from the new proposal presented in this study will help in the characterization and management of the reservoir, and also will explain the origin and mechanisms causing early water production.This study is based on several key offshore wells from Urdaneta-01 reservoir, located in Venezuel...
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