Summary The sucker-rod pumping (SRP) system is the most used artificial lift method in oil wells in Brazil and in the world. This method stands out for its simplicity and low cost in investments and maintenance, and can be operated in a large range of flow rates, with fluids of different compositions and viscosities. However, the SRP units as well as all other mechanical equipment require periodic adjustments and maintenance, whether corrective or preventive. Two important procedures commonly made at the SRP units are the adjustment for counterbalancing the pumping unit and the adjustment of the polished rod stroke length. Performing these procedures requires stopping the production of the well. Usually, such adjustment procedures are made manually by a work team that is transported to the place where the pumping unit is located. In this context, Petrobras in partnership with Federal University of Rio Grande do Norte and other companies developed a new type of pumping unit, called smart sucker rod pump (SSRP), which is capable of counterbalancing the unit and adjusting the polished rod stroke length without mobilizing a team to go to the field. Thus, this work proposes to develop a strategy to automatically control the SSRP. The development of this strategy aims to ensure that the equipment operates under proper conditions and within its safety limits (previously set by the operator), as well as to optimize the well production. In order to test the control strategy developed for the SSRP, simulations were performed using synthetic wells. It was observed that the developing strategy reached the proposed goals for which it was developed; that is, to keep the parameters of the SSRP within the limits set by the operator and optimize the production flow rate.

Summary One of the main problems regarding the use of the artificial-lift method of electrical-submersible-pump (ESP) systems is the presence of gas in the pump. This paper presents and describes an analysis of ESP systems with a stage-by-stage calculation to determine intake and discharge pressures to adjust total dynamic head (TDH) for each stage of the pump. The modeling was designed to acknowledge free gas in the pump, and iterative calculations are applied to recalculate, for each stage, fluid characteristics and physical properties, such as viscosity, density, formation volume factor (FVF), surface tension, solubility ratio, gas/oil ratio (GOR), and other flow characteristics along the tubing, such as temperature and pressure. Developed modeling validation was achieved by comparisons in two scenarios. In the first one, fixed values of intake pressure and changeable values of GOR were used to assess gas effect. In the tests for the second scenario, fixed values of GOR and changeable values of intake pressure were used. Necessary research was conducted through a developed computational tool used to size ESP components. The results were different from those obtained with the usual calculations, and it may be implied that the developed modeling is more accurate to determine parameters related to this artificial-lift method. Also, the results were more consistent and closer to the actual behavior of multiphase-flow phenomena within the tubing because each stage has its characteristics individually evaluated. These observations may have an effect on the number of pump stages and influence in choosing the adequate equipment of the system.

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One of the main problems regarding the use of artificial lift method by Electric Submersible Pump (ESP) systems is the presence of gas in the pump. This paper presents and describes an analysis of ESP systems using a stage by stage calculation to determine intake and discharge pressures to adjust total dynamic head (TDH) for each stage of the pump.The modeling was designed acknowledging free gas in the pump and iterative calculations are applied to recalculate, for each stage, fluid characteristics and physical properties, such as viscosity, density, formation volume factor, surface tension, solubility ratio, oil-gas ratio (OGR), and other flow characteristics along the tubing, like temperature and pressure. Developed modeling validation was achieved by comparisons in two scenarios. In the first one, fixed values of intake pressure and changeable values of GOR were used to assess gas effect. In the tests for the second scenario, fixed values of OGR and changeable values of intake pressure were used.Necessary research was done through a developed computational tool used to size ESP components. The results were different from those obtained with usual calculations and it may be implied that the developed modeling is more accurate to determine parameters related to this artificial method. Also, the results were more consistent and closer to the actual behavior of multiphase flow phenomena within the tubing because each stage has its characteristics individually evaluated. These observations may have effect on the number of pump stages and influence in choosing the adequate equipment of the system.

No abstract