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Context: Currently, renewable energy sources are playing an important role in counteracting the environmental impact of traditional energy sources. For this reason, system operators must have analytical tools that allow them to incorporate these new forms of energy. In electrical power systems, when incorporating renewable resources such as photovoltaic solar generation, wind power generation or electric vehicles, uncertainty is introduced due to the stochasticity of primary resources.Method: Uncertainty costs are proposed that incorporate the injected power variability of the main sources of renewable energy (solar and wind) and the consumed power (electric vehicles). Variability is considered by the probability distributions of the primary sources of renewable energy (solar irradiation and wind speed).Results: The main result of this research is the application of analytical costs of uncertainty. In this way it is possible to modify the cost function of a traditional economic dispatch. Additionally, it is proposed to solve the problem with a heuristic optimization method of economic dispatch of active-reactive power. Finally, a comparison is made with the operating cost of the system without the incorporation of renewable energies.Conclusions: The proposed model in this article is a potential decision-making tool that power system operators may consider in the operation of the system. The tool is capable of considering the uncertainties of the primary sources of renewable energy. The probability distribution of the primary source forecast is assumed to be known. An opportunity in order to extend the model is to study its applicability to dynamic time horizons, contemplating the constraints of the unit commitment problem

Well evaluation is the primary method used in the oilfield to determine the true well's production potential and reservoir characteristics. During a well evaluation, downhole parameters are commonly registered using downhole memory gauges, which can only be retrieved and read after the evaluation have finished. The problem with this conventional method is the uncertainty or ambiguity results and the inaccurate data of the downhole parameters; which often lead to inefficient tests times and difficulties for well test interpretation.The use of Fiber Optic for Real-time downhole measurements conveyed on Coiled Tubing (CT) and Nitrogen (N2) Lifting provide a unique live insight that allow us to monitor the well response while production or evaluation is performed, eliminating the uncertainties that surrounds traditional methods. Nitrogen lifting with Coiled Tubing was introduced as an alternative evaluation method for the common Hydraulic Jet Pumping that proved advantages accelerating well response and increasing the accurate of the reservoir data for well evaluation and artificial lift design nevertheless this still faces the delayed on the pressure data and transient interpretation. Implementing the Real Time downhole measures (P, T) is possible to eliminate uncertainties of reservoir parameters that surround well evaluations, adjust job parameters on-site, optimize job resources and time and finally anticipate artificial lifting design. This paper will present the results of the implementation of this new method in the area for well evaluation allowing real-time measurements of down hole pressure/temperature. Combining the fluid lifting with N2 through the CT, reservoir response is continuously monitored; thereby, allowing in advance an adequate design of the lifting system reducing nonproductive time. Real-time measurements and accurately data of the reservoir allow defining if a further stimulation treatment is needed. Actual treatment program can be continuously monitored or modified, to achieve optimal results. The first trial using the system demonstrated that the application can be used with a high degree of accuracy and control for the parameters and treatment designs that are not achievable using conventional techniques as the Hydraulic Jet pumping, gauges conveyed in slick line, joined tubing and/or using surface data to predict downhole behavior.

Production in the Shushufindi-Aguarico oil field (SSFD), Ecuador, is from three stacked reservoir sands: basal Tena, U, and T. The SSFD is considered under saturated and is characterized as having two simultaneous driving mechanisms. The first mechanism is associated with solution gas drive, and the second is associated with an active bottom and lateral aquifer. This latter mechanism offers high recovery factors that oscillate between 25 and 30% and high water cut in most of the wells, especially in those producing from the T sand. The reservoir is compartmentalized by stratigraphic pinchouts with the result that each of the sands has a different pressure regime: T sand from 2400 to 2600 psi, U sand from 1400 to 3000 psi, and basal Tena sand from 1200 psi. The reservoir pressure limits natural flow; therefore, artificial lift is required. The dominant artificial lift method is the electric submersible pump (ESP), which is used in 106 wells. Other methods in the field are hydraulic pumping in 5 wells, gas lift in 1 well, and bean pumping in 1 well. The saturation pressure for the U and T sands varies between 1010 and 1062 psi. Some wells are exploited with dynamic bottomhole pressure (Pwf) below the bubblepoint pressure; there are cases where Pwf is approximately 600 psi. Originally, the casing used to complete wells in the field was 5 ½-in. × 17 lbm/ft and 7-in. × 26 to 29 lbm/ft. The wells perforated during the last 3 years have been completed with 9 5/8-in. × 47 to 53 lbm/ft casing and 7-in.× 29 lbm/ft or 26 lbm/ftliner. From the beginning of production in the field in 1970, a total of 140 ESPs have been run: 17 ESPs in 5 ½-in. casing, 39 ESPs in 7-in.casing, 42 ESPs in 9 5/8-in. casing, and 42 ESPs in 7-in. casing. Wells are completed as monobore completions, either in the U or T sand, or have been selectively completed when both sands are to be exploited sequentially. The latter completion includes a sliding door to allow sequential production over time. In 2012, concentric dual completions were deployed in four wells, with some success. This technology involves high risk to the well operations because of its complexity (numerous accessories), tie drifts, and lack of flexibility to intervene the well with even a rigless intervention. Additionally, this completion technique requires high CAPEX and a considerable amount of surface equipment. This makes a future workover operation lengthy and risky. A very important production consideration in this field is that the hydrocarbons regulatory authority in Ecuador, ARCH, does not allow the commingled exploitation of the U and T sands because of the issues this raises with reservoir management and petroleum accounting. The technical and regulatory challenges are the drivers for considering intelligent completion (IC) or compact IC for the operator, Consorcio Shushufindi (CSSFD), and evaluating and testing IC and compact IC completions for this field are the objectives of the present technical work. As part of this work, significant advances have been made in increasing the information that makes up the portfolio for a candidate well; this information includes a definition of the architecture required, conceptual simulations to estimate production rate for the sands, operation philosophy, advantages and disadvantages of the application, and antecedents worldwide. In addition, technical presentations have been conducted at all levels of management to explain the technical justification and the benefits of implementing IC completions in terms of production optimization, reserves development, reduction of formation damage induced by the effect of well intervention (recompletions), etc.. Based on early technical meetings with the ARCH, Petroamazonas (PAM), and the Hydrocarbon Secretary (SH), a pilot test has been approved which will implement and evaluate IC in five wells in the SSFD field.