A properly understanding of how oil mixtures behaves as they flows in a pipeline is a key factor for piping design. Facilities engineers from oil companies currently use commercial pipeline simulators in order to perform pressure and temperature gradients predictions. Nearly all the simulators apply the general mixing rule when they need to calculate the viscosity of a certain oil mixture. As viscosity depends both on molecular characteristics and molecular interaction, and oil is a complex mixture of components, it is not surprising that this rule gives poor results. Besides, non-Newtonian behavior makes things more complex. This paper discusses experimental results of mixing at lab several different oils and measuring their viscosity. Each oil had its own composition and rheological behavior. Some mixtures were prepared in order to reproduce real situations. Once the mixtures viscosities were obtained they were introduced as input data in a commercial pipeline network and nodal analysis software. Then, pressure and temperature gradients were calculatedUsing the experimental mixture viscosityUsing the general mixing rule viscosity estimated by the software Results showed, in some cases, dramatic differences between the two alternatives. Higher deviations were obtained where the mixtures were composed of crudes of different properties. In order to improve the accuracy other mixing rules were tried and some of them fit better. A proper understanding of crude oil properties seems to be essential for successfully applying complex simulators in pipeline design. Introduction Viscosity of liquid mixtures have been studied for a long time(1) but, unfortunately, this knowledge has not always been taken into account in the development of commercial pipeline simulation software. Viscosity has a molecular origin, and it is highly dependent on the molecular interaction. That is the case of complex multiphase and multicomponents fluids such as oil. If an engineer needs to design an oil pipeline, there are several commercial software available to predict pressure and temperature drop. It is only necessary to introduce a viscosity curve as an input to the soft. But the problem is presented when several pipes, which transport different oils, form the system to design. Most of this technical software makes use of the general mixing rule as the main alternative to calculate the mixture viscosity. This paper presents a study of viscosity mixtures of several crude oils. In each case individual crude oil viscosities were measured at a particular shear rate and shear stress, and different temperatures. The viscosity mixture measurements were made at similar conditions, and the same values were calculated using a commercial pipeline network and nodal analysis software. The results show that there is no satisfactory equation, which can be applied to all the practical cases. The simulator generally overestimates the pressure drop through the pipeline. Therefore this could carry out economical problems. Theory The general mixing rule is currently used to obtain an average value of many physical properties, including viscosity. The rule states that the property of a mixture is obtained by the weight average of the properties of each component. However, this equation is only valid when the fluids that are mixed do not interact with each other. That is not the case of oil mixtures. Besides it is not valid when dealing with emulsions or water-oil flow. These particular situations (also found in pipeline design) are not in the scope of this work.

Summary Cerro Fortunoso field produces a heavy and viscous oil and a separator gas which contains 95% of CO2. In 1996 a decision was made to reinject the gas to maintain pressure and prevent environmental damage. A technical team used a network simulator to model both the current oil gathering and the future gas reinjection systems. A parallel study was conducted to analyze the effect of non-Newtonian performance on predicted pressure drop. Although deviation was found to be slight, the non-Newtonian effect should be properly included in design calculations. Besides, as the gas will be reinjected near its critical point, thermodynamics becomes extremely important. Introduction Cerro Fortunoso oil field is located in the southern region of the province of Mendoza, in the Argentine Republic (Fig. 1), about 80 miles from Malargüe where YPF has its center of operations for this region. A net oil production of 6,300 B/D turns the field into the most important one in the zone. The reservoir's structure has a North-South-oriented direction. It is located on Malargüe sub-basin, which is an extension of Neuquina basin. The structure is folded and it gives origin to a faulted anticline as a consequence of a terciary compressional orogenesis. It contains oil and gas reserves in the Upper Cretacic of the Neuquen Group. Up to late 1997, 120 wells have been drilled with an average depth of 3,900 to 5,900 ft. Most of the wells are rod pumped, while half a dozen remain in natural flow. Due to the presence of a gas cap and probable gas coning effects the gas/oil ratio (GOR) has been continuously increasing with depletion. Gas has been vented to reduce bottomhole pressure at the annulus, but it also decreases pump efficiency. While the average GOR is about 2,200 ft3/bbl, some wells produce gas up to 3,500,000 scf/D. Although local regulations do not limit CO2 venting, and a recent reservoir study concluded that reinjecting the gas to the reservoir would not increase recovery, a decision was made to reinject the produced gas to the gas cap. Two main objectives are: maintain reservoir pressure above the estimated bubblepoint, and; avoid environmental damage to the atmosphere. Once the decision was made, a small engineering team began to model the future oil and gas surface network. The modeling should detect bottlenecks at the current oil production system and optimize future gas gathering and re-injection systems. Fig. 2 describes the future oil and gas network when the gas is being reinjected. Dotted lines show the oil and gas lines that are going to be installed at different stages of the project. Simulator's Description Several commercial software programs are used in the petroleum industry to optimize surface networks.1 Versions 7.01 and 7.03 from the PIPEPHASE simulator were used for modeling the current and future field surface networks. The oil production system was run using a black oil model while a compositional model was selected for the gathering and reinjection gas system. The simulator does not allow us to model indirect fire heaters. The model was run on a personal computer. The complete model needs about 100 Mb. Oil Properties Table 1 contains the main oil properties. Oil samples taken from two current batteries (CF-1 and CF-2) were carefully analyzed at the laboratory. Additional samples were taken before and after the demulsifier was added to the battery tank and at some point before one of the last heaters, where both oils flow together. Although oil from two batteries showed similar density, the other parameters were quite different, suggesting different molecular composition. This effect had also been reported in the reservoir study when analyzing available pressure/volume/temperature (PVT) studies. Moreover, one of the samples contained much more emulsion than the other. Analysis showed that only a small emulsion decrease is obtained after adding a demulsifier. This could be due to insufficient mixing time. Asphaltene content was found to be about 15%. The oil was characterized as 75% asphaltenic and 25% paraffinic. Rheological Studies Complete rheological studies were performed at a specialized laboratory using a modern Haake Model RV 20 viscometer with an RC20 rheocontroller. A Julabo temperature controller system allows keeping the temperature constant within 0.1°C. For each sample (with and without chemical demulsifier), the rheological model was first determined at different temperatures ranging from 86 to 122°F. For both oils a moderate pseudoplastic behavior was found below 120°F. The Ostwald coefficient (n) ranged between 0.94 and 0.99. Although both oils are slightly non-Newtonian fluids, the effect of shear rate on viscosity reduction may be important due to their high values. Fig. 3 shows the rheological model of CF-2 oil at different temperatures. Although slope seems to be quite constant, Fig. 4 shows that apparent viscosity decreases for increasing shear rates, indicating a slight pseudoplastic behavior. Shear rates were then calculated for both oils using the Oswald-De Waele and Poursille model at the current average pipe conditions. The CF-1 oil sample would have at its pipe a shear rate of about 22.7 L/s, while for the CF-2 oil sample the model predicted about 8.5 L/s. The difference is due not only to their different individual viscosities but to the fact that they flow in different pipes. The equations used for calculations are shown on Appendix A. Finally, curves showing apparent viscosity for temperatures ranging between 86 and 140°F were developed. Fig. 5 shows CF-2 oil viscosity curves with different emulsion contents for different temperatures. Each curve was developed at its predicted shear rate. It is clear from Fig. 5 that the emulsion content significantly increases the apparent viscosity and pseudoplastic behavior. Important viscosity reductions (up to 50%) could be obtained with some emulsion decrease. The decisive importance of pumping temperature can also be clearly appreciated. Both conclusions led to several exciting discussions with production engineers at the field.

Cerro Fortunoso is one of the main fields of YPF Mendoza Business Unit. Itcurrently produces more than 7,500 bbl fluid/d from a hundred wells, most of them on sucker rod pumping. The field is located 80 miles from the nearest town, near the Andes Mountains and the environment is quite hostile windy, cold and with frequent snowfalls). Besides the field is very near a National Park. Produced fluids are usually a problem. The oil is heavy (14.7 API) and viscous (more than 3,000 cp at ambient conditions). It tends to form emulsions with production water and behaves as a non newtonian fluid below 120 F. The produced gas contains about 95 % of CO2 and has been vented up to now. In late 1996 a decision was made to reinject the produced gas in order to maintain pressure and prevent environmental damage. A small technical team used a complex network simulator to model both the current field oil gathering and the future gas reinjection systems. Although the model fitted experimental data successfully and proved to be a powerful design tool some limitations to the simulator were found. Due to the fact that commercial simulators do not take into account non-newtonian performance. a parallel study was conducted to analyze the effect of this behavior on predicted pressure drop. The team concluded that although deviation was found to be slight, non- newtonian effect should be properly included on design calculations. As the gas will be reinjected at field conditions near its critical point. thermodynamics becomes extremely important. Five different thermodynamic software packages were run to predict gas phase envelope. Important differences between some models were detected. P. 307

The Vizcacheras License in Mendoza Province, Argentina, is a complex multi-reservoir asset within YPF's mature asset portfolio. Facing a current recovery factor averaging 46+% between the producing reservoirs, YPF embarked on a program to enhance recovery and maximize asset value. Vizcacheras, discovered in 1962, stands with 400 wells in 2 structures with homogenous and heterogenous reservoirs and operated by 4 different organizations. Peak production was 38,000 bopd; currently producing 10,000 bopd with water cut of 97%. Beyond the geologic complexity, was the commercial challenge rejuvenating the field under mounting operating costs. YPF decided to respond by assessing: if the field had stranded value; the magnitude of stranded value; and, method(s) to deliver value. A multi-disciplined YPF and Arthur D. Little team was formed to assess the Vizcacheras license from subsurface through surface employing innovative technical systems analysis to build a risk-based field development plan. The focus of revitalizing a mature field is to define a customized asset evaluation approach to quickly manage large amounts of data and identify key mechanisms for stranded value and value-added solutions, while minimizing costs. The team captured this through innovative systems planning and operation, displacing the traditional lab-to-field R&D search in that multiple options were generated from within functional technology contributions. The result is convergence toward multiple enhanced recovery and operational changes that are anticipated to yield increased recoveries and more efficient management of the asset. Diagnostic analyses of production profiles from individual wells and patterns of wells identified zones of poor reservoir sweep and bypassed oil, guided by large-grid simulation models aimed to reduce risks. Uplift opportunities from pump optimization, infill drilling, injection and adjusted secondary recovery patterns were identified using a risk-based value analysis, with an anticipated increase in recoverable oil of 3%. EOR strategy work is currently underway in which YPF envisions up to three times the recent optimization results. Use of a ground up approach to gather, quality check, and integrate data to build models of the geological framework and to conduct quantitative engineering analysis of the system's performance is showing added recovery benefits from the integrated workflow as it is implemented. Introduction Faced with an expiring lease, and mounting costs for water handling and disposal, YPF needed to assess: if the Vizcacheras license had stranded value; the magnitude of stranded value; and method(s) to deliver value. In 2007 YPF commenced a 2 year study to evaluate and recommend various scenarios to revitalize production from the Vizcacheras license located in the northern part of the Cuyo Basin, Figure 1. Currently the license is producing 10,000 bopd with a water cut of 97%. Two fields, Canada Dura and Vizcacheras lie within the license. Vizcacheras began production in 1965 and is a north plunging anticline on which the Papagayos and Barrancas formations are stratigraphically trapped, Figure 1. Canada Dura is a faulted domal structure producing from the Barrancas sands and has been producing since 2000. The Papagayos is homogeneous sand whereas the Barrancas sands are heterogeneous. The sands range from fine grained to coarse sand to pebble conglomerates. Most wells have artificial lift using Electric Submersible Pumps. The Papagayos reservoir is producing under an active natural water drive and the Barrancas reservoirs have been supported by water injection in their more recent production life cycle. The field was initially developed with a 600 m well spacing. Later, core areas were infilled at 300 m spacing. There are approximately 400 wells within the license area.

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