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.

As part of a three-year research project, a solvent based process for downhole upgrading as well as for concurrent enhanced oil recovery of the bituminous heavy oil from an Argentina reservoir was evaluated in the laboratory using physical models. Potential solvents were sourced from a gas plant located close to the target reservoir. To evaluate feasibility, first a specially designed dynamic asphaltene apparatus was used to screen readily available solvents and their mixtures. Solvent/oil miscibility and on-set of asphaltene deposition were determined by analyses of light transmitted through a micro-visual cell containing a flowing stream of oil/solvent mixtures. The optimized solvent composition thus identified was then used in Vapex experiment in a physical model packed with crushed reservoir rock.It was seen that the chosen solvent mixture (containing carbon dioxide and gas condensate) was effective in upgrading the produced oil under test conditions (high permeability). Asphaltene and heavy metal content of the upgraded (produced) oil were reduced to less than 20% of the original values, while oil recovery in excess of 75% of OOIP was achieved in the physical model. Oil sweep in the model, especially within the solvent swept zone was exceptionally efficient with a remaining oil saturation of less than 5%. At the same time, oil saturation of the least swept region was reduced from 85% to 45%. Deposition of asphaltenes in the porous medium did not seen to materially affect oil production

H2S is an element toxic to life that can be associated to natural gas, oil and production water. It is very dangerous to operational staff and causes corrosion -cracking and pitting of steels-, especially when it is associated to water. The petroleum fields can early show H2S associated to the original fluids or it can appear later in mature stages. The generation mechanisms of H2S have been classified as biotic (biological sources) or abiotic (geological or geochemical sources). The first one is related to the development of Sulphate Reducing Bacteria (SRB) in reservoirs. The best-known reason is the injection of SRB with seawater in combination with nutrients of formation waters. Abiotic mechanisms involve only chemical reactions between organic, inorganic phases and water. Temperature and pressure are critical parameters: themochemical sulphate reduction (TSR), hydrolysis of metallic sulfhurs, cracking of organic compounds, cracking of kerogen and volcanogenic sources are examples of abiotic mechanisms. According to this classification, most of the H2S souring cases in Argentina can be, on some level, related to the development of SRB, but alternative sources have been studied to explain the new reports of H2S on fields with high contents of original H2S. This paper classified the fields in Argentina with H2S in three categories;-The oilfields that show progressive H2S souring after a secondary recovery project. SRB were introduced with the injection of foreign waters and three examples are shown: Chihuido Lomitas, Barrancas and Las Heras-Cerro Grande (Cases A, B, C).-A second group of oilfields report low concentrations of H2S still in primary production without previous history of H2S. SRB could be indigenous or introduced with drillings fluids. El Alba and Grimbeek fields are presented in this paper as Case D.-A third group of fields show medium and high values of original H2S (>2000 ppmv) since the firsts development activities. A possible contribution of abiotic H2S sources is now considered. Some fields in the Neuquen area could show a mixture of mechanisms (biotic and abiotic). The characteristics of these fields are summarized in Case E. All reservoirs require H2S simulation to design surface pipelines and environment management. However, according to the origin of the H2S, a variety of mitigation and control technologies have already been implemented in these fields. This paper summarizes the three groups of fields in Argentina that produce H2S, altogether with their water-chemistry, evidences of H2S origin, associated problems and control practices. Introduction H2S is a toxic gas, heavier than air and flammable. It burns with a blue flame producing sulfhur dioxide (SO2), which is itself a toxic gas that can have harmful effects on heath and environment. Concentrations of 1 ppm (0,0001%) of H2S are detectable by the human nose (rotten eggs odour), 10 ppm is considered to be the short time exposure limit (maximum of 4 exposures a day of less than 15 minutes each), 100 ppm suppresses the sense of smell and concentrations above 500 ppm cause respiratory problems and unconsciousness. H2S is also a corrosive compound. It has been estimated that H2S alone is responsible for about 20% of the metal corrosion losses in the petroleum industry (Elshashawi H., and Hashem M., 2005). Many reservoirs world-wide even show variable H2S concentrations associated to original fluids, around 70% of water-flooded reservoirs worldwide have turned sour, and it appears to be a systematic increase in the sulphur content of crude oils over the past 10–20 years (Elshashawi H., and Hashem M., 2005).

Water treatment and injection well stimulation are two important contributions to oil lifting cost at Barrancas oil field. As most of mature fields, waterfloding represents a hugh amount of oil production. Although average water quality is quite good some injection wells require regular hydrochloric acid stimulation in order to restore injectivity, impaired by different solids, mainly calcium carbonate and sulfides. A new stimulation system was designed. The system combines the conventional acid system with an aqueous chlorine dioxide solution. In this approach chlorine dioxide activates at the bottom of the injection well. The oxidating power of chlorine dioxide removes completely all solids that are not sensitive to acid treatments. The synergistic effect of the proposed treatment was determined in two different flow core tests on reservoir samples. Due to successful results at the lab, a decision was made to perform field tests in four injection wells. A dramatic and continuous decrease in wellhead pressure were the results obtained after several weeks of treatment. In order to analyze and prevent corrosion effects a parallel study was designed and conducted on tubing samples at reservoir conditions. Introduction Injectivity losses are a usual problem in several Repsol YPF waterflooded fields. Barrancas, a mature oil field, has started waterflooding in 1967. For several years fresh water was injected but in the 90 s and aggressive program lead to the gradual replacement of fresh water by prodution water. More than one hundred wells currently inject 15,000 m3/day. Injection pressures are quite high (20,000 KPa), leading to a high energy consumption. Table 1 shows an average of Barrancas treated injection water composition at the plant s outlet. The importance of water quality to minimize formation damage has been stated by several researchers. Reference 1 is an excellent summary of guides to follow. Although it can be seen that the water treatment system has a fair good performance, some injection wells need a periodic acid stimulation in order to restore injectivity and decrease wellhead pressure. Historically, 10 % HCl or 10% HCl plus 1 % HF are used for stimulations. In both cases acetic acid and additives are also added. About 100 acid treatments are annually performed. In some cases hydrochloric acid stimulation frequency is less than two months. A typical injectivity decline curve of one of this problematic wells is shown in figure 1. Statistics shows that plugging frequency decreases as time passes. On the other hand acid treatments must be handled with care for preventing injection facilities failures. The effect of this situation on economics is clear: sweep efficiency is reduced, water treatment cost increases and as a consecuence the overall lifting cost of the field also increases. As the oil production has been declining and fields profitability is very senstitive to oil prices the injectivity of problematic wells needs to be restored or improved without affecting the field economics. Previous approaches Many references discussed the use of different oxidizers to remove solids that are not attacked by hydrochloric acid. Many of the papers analyze the possible use of chlorine or chlorine dioxide. Probably the most interesting one is a paper by Mc Cafferty et al2. The authors discussed in detail the use of chlorine dioxide as a stimulation fluid. They stated that more than 1,000 injection and production wells had been successfully treated with a combination of hydrochloric acid and chlorine dioxide. Chlorine dioxide was generated on site using a venturi and mixing three different components, HCl, sodium hypochlorite and sodium chlorite. A detailed description of the generation system is given in their paper.

By mid-2000, the H2S content in gas from the Chihuido Lomitas field separator started to increase significantly up to an average of 2,000 ppm. A multidisciplinary team was formed to address the problem, which was deemed to be very likely due to bacterial activity in the reservoir. Therefore, the group focused on the issue of concern, which is generally known as reservoir souring. It was concluded that using sulphur isotope measurement techniques was one of the few tools available to effectively determine the cause of the souring. A group of specialists in isotope assessments from a local Research Institute was called in to join the team. Based on the team's findings, supported by a geochemical model, it was shown that H2S generation in the Troncoso and Avile formations was due to the activity of sulphate reducing bacteria living in the reservoir. The model developed relates increasing bleeding water injection to the phenomenon studied. A thermo-chemical reduction was proposed to explain the H2S content in El Filon Reservoir. Innovative H2S removal techniques are currently being applied. Introduction The Chihuido Lomitas light oil field is located in the Neuquen Basin, in Argentina. The main producer reservoirs (Agrio Formation and Avile Member) are in the Mendoza Group (Late Jurassic - Early Cretaceous). One non-conventional reservoir produces from an igneous rock (see Figure 1). The field started to produce in the early 1980s, and is currently Repsol YPF's main oil field in Latin America. Water injection started in 1996 and, by the end of 2001, nearly 100,000 m3/day were injected through 480 injection wells. Initially, just fresh water was injected, but it was gradually replaced by production water. When the H2S content in the separator gas started to increase, a team was formed including field staff from Engineering and researchers from Repsol-YPF's Applied Technology Centre (CTA) in order to address the problem by looking at different approaches. Measurements were thoroughly checked, and a sampling survey at key points was designed. Different gas treating alternatives were discussed. It was concluded that sulphur isotope measurement techniques were one of the few tools available to effectively determine the origin of the problem. Sampling H2S collection was accomplished with a sampling device developed at INGEIS, including a flow meter and two H2S traps, with two online flasks containing AgNO3 or NaOH. Sixty samples were taken from all batteries, including formation, production, and injection water, oxygen scavengers, and crude oil. Isotope analyses were performed at INGEIS using VG 602 and Finnigan Delta-S mass spectrometers. CTA performed a standard geochemical analysis, and determined the level of fatty acids in the formation waters. Results and Discussion The main data are shown in Tables 1 and 2. We carefully analysed the different possibilities for H2S generation in the reservoir, on the basis of the isotopes results, geology, temperature range, presence of sulphides in reservoir formations, and injection/production water characteristics. The analysis also took into account the exploitation history, and the absence of H2S in the early years.