The prediction of pressure drop in multiphase flow for risers is of particular interest for the oil industry and also a critical variable for the right design of surface facilities in offshore fields. Empirical steady state correlations, mechanistic models and dynamic models are available to calculate the multiphase flow pressure drop, holdup and phases distribution.The main purpose of this paper is to evaluate the accuracy of several steady state pressure drop prediction models with two phase flow laboratory data conformed by 108 point using air as gas phase and liquids with viscosity up to 310cP. The models considered in this study, for predicting pressure drop are model, using PIPESIM simulator. The evaluation was based on the comparison between the predicted and the measured pressure drops, demonstrating the performance of each model for highly viscous liquids. Statistical parameters as average absolute percent error and standard deviation have been calculated to find the most acceptable one. The statistical analysis showed that among the evaluated Hagedorn and Brown model has the best performance to predict pressure drop in risers with highly viscous liquids.

The objective of this paper is to define the best artificial lift system for recovering heavy oil in Vinita Field, located in Block 59 of the Ecuadorian Oriente Basin. This field produces from reservoir "M-1" sandstone. The crude oil gravity of M-1 varies between 13.5 and 15.4°API. In Vinita Field there have been three different types of artificial lift systems installed with local power generators. The amount of energy used in each lifting system is used as a factor in determining the most suitable lifting system for the wells in this oilfield.The fluid level of each well and other parameters for the simulation process are determined by pressure tests analysis. The flow simulation is an important step to get a better design and predict the future performance of an artificial lift system. The Inflow and Outflow curves are used to identify the optimal production levels and to determine the production capacity of the well.The Vinita-3 well used to produce by a hydraulic system. This had several mechanical failures resulting in production losses. The decision to implement the first progressive cavity pump completion (PCP) in Petroamazonas EP has been taken in order to reduce production losses and energy consumption. Vinita-3 is a directional well that presents several challenges for implementing a PCP system. All these challenges were satisfactorily overcome using optimal development of variables, getting optimal production and system performance. The initial investment to implement the PCP system was around 80% less than the investment required for other systems installed previously in the same well. The demand of energy consumption decreased from 53.7 Kw-hour to 8 Kw-hour. The PCP system was installed in June of 2014, and the system has been working with normality until today.The PCP system has had an optimal performance for lifting the heavy oil of Vinita-3 well and the energy required is less than the energy demanded by other lifting systems. The installation of PCP system in others wells with similar conditions to Vinita-3 can reduce energy demand from other companies that handle heavy oil wells.

Slug flow is the most common flow pattern presented in multiphase flow gas-liquid pipelines for highly viscous liquids. In this sense, it is important to know how this flow pattern behaved when oil viscosity increases in order to improve the operation and design of surface facilities, such as: pipelines, separators, flow conditioners, risers and multiphase equipments as pumps and flow meters, and also to reduce the corrosion and erosion effect in the systems. This requires a rigorous study of slug flow characteristics, i.e.: slug holdup, slug length, translational velocity and slug frequency as well as pressure gradient and liquid holdup in the pipe. For these reasons, it is necessary to carry out experiments that allow a better understanding of slug flow pattern and improving mathematical models to predict slug characteristics. In this work, an experimental study of three different gas/liquid systems is presented. This includes liquid viscosities of 1cP, 430cP, and 960cP and the liquid viscosity effect in slug flow characteristics such as: flow pattern transition, slug translational velocities, slug lengths, pressure drops, holdup, and slug frequency.

The efficient and economic recovery of heavy oil and bitumen is a mayor technical challenge due to their high viscosity. In the Orinoco Oil Belt, due to the high viscosity, different thicknesses and heterogeneities found, thermal recovery processes have demonstrated to be the best alternative for the enhancement and acceleration of heavy oil recovery. Bare Field, with an average API gravity of 10°, is among the fields of the Orinoco Oil Belt where thermal recovery has been applied through the implementation of Cyclic Steam Injection in horizontal wells, with substantial productivity increase. This led to the introduction of the first SAGD (Steam Assisted Gravity Drainage) pilot project on the Orinoco Oil Belt, on the Bare Field, this pilot test is in operation from 2009, and the recovery factor of the area affected by the steam is estimated to increase from 14 to 60 % The location and design of these SAGD wells was accomplished using independents models for reservoir, well and surface, creating a production scenario without taking into account the interaction between models. A dynamic coupling of the reservoir simulation model with the well and surface models allows the consideration of more realistic boundary conditions. In this sense, an integrated model was developed in the present work, allowing the dynamic evaluation of the entire system helping to understand the energy consumption along the system to improve the recovery method performance. To develop this model, a dynamic thermal reservoir model was created from an existing static model of the reservoir. Once the reservoir model was able to reproduce the flow rates, pressure and temperature with acceptable accuracy compared to the real history data, the next step was the elaboration of well models. The reservoir and well models were coupled in one model to evaluate the advantages of use integrated models for the evaluation of the energetic efficiency of SAGD projects.