TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe performance prediction of a Rotary Gas Separator (RGS) is very important for ESP systems applications. The pump performance is severely affected when it handles high Gas Void Fraction (GVF) at its intake. The function of the RGS is to separate both liquid and gaseous phases, and to expel the gas through a crossover section to the annular area between casing and tubing. Typical designs use separation efficiency values based on an empirical standpoint of view. Also, the literature references regarding an important parameter like the inducer head is very scarce. The performance analysis of a RGS (540 series separator), under two-phase flow conditions, has been conducted using 3D-CFD simulation tools (CFX 5.6). Water-air mixtures were used as working fluid and the mixture GVF was varied from 10% up to 30%. The results shows that the RGS separates efficiently the phases, but the inducer head is insufficient to overcome the friction losses in the crossover and the liquid column static pressure in the annular space. As a consequence, a new inducer design is necessary to create a higher head value to push the gaseous phase out of the RGS and not to be dragged by the liquid phase. The simulation could be an alternative tool for selecting the depth of the downhole equipment as a function of the liquid level. This could help the designer to properly obtain the minimum submergence of the equipment that satisfy the phases separation and gas expulsion of the RGS, getting a lower GVF at the PIP.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe performance prediction of a Rotary Gas Separator (RGS) is very important for ESP systems applications. The pump performance is severely affected when it handles high Gas Void Fraction (GVF) at its intake. The function of the RGS is to separate both liquid and gaseous phases, and to expel the gas through a crossover section to the annular area between casing and tubing. Typical designs use separation efficiency values based on an empirical standpoint of view. Also, the literature references regarding an important parameter like the inducer head is very scarce. The performance analysis of a RGS (540 series separator), under two-phase flow conditions, has been conducted using 3D-CFD simulation tools (CFX 5.6). Water-air mixtures were used as working fluid and the mixture GVF was varied from 10% up to 30%. The results shows that the RGS separates efficiently the phases, but the inducer head is insufficient to overcome the friction losses in the crossover and the liquid column static pressure in the annular space. As a consequence, a new inducer design is necessary to create a higher head value to push the gaseous phase out of the RGS and not to be dragged by the liquid phase. The simulation could be an alternative tool for selecting the depth of the downhole equipment as a function of the liquid level. This could help the designer to properly obtain the minimum submergence of the equipment that satisfy the phases separation and gas expulsion of the RGS, getting a lower GVF at the PIP.

Objectives/Scope This study is addressed to evaluate the field implementation of the Progressing Cavity Pump (PCP) Hydraulic Driveheads, in remote locations with a lack of energy supply in the YPF Santa Cruz and in the South of Argentina. Santa Cruz area represents 20% of the total PCP population for YPF, being 5% of them operating in remote locations. The traditional PCP applications used for remote areas without electricity consider the use of PCP Driveheads angular type with engine motors as prime mover, but this kind of drivehead is old technology that carries on several limitations on safety, control, optimization, reliability, etc. Despite the poor utilization and no massification of Hydraulic Driveheads in Argentina, this technology has been considered as an alternative to probe in the field looking for improvements with the main variables that are the weakness for angular driveheads showing successful results. Methods, Procedures, Process The project scope cover the full deployment of the drivehead technology in a field trial evaluation considering the operational features and benefits combined with a positive impact on production increase and cost saving, follow up by the technology field implementation. The trial stage was addressed by installing two (2) hydraulic drivehead replacing direct-drive gas engine power transmissions during a 6-month of period evaluation. Combining a telemetry system with a closed field visit, key operational parameters were monitoring and comparing performance against the previous traditional surface systems. All data collected were analyzed to determine the feasibility of this technology in the mature, non-electrified field. Results, Observations, Conclusions During the trial period, a close comparison with the traditional system was performed, finding important enhancements with the implementation of Hydraulic Driveheads application addressed to torque control and its benefits that angular drivehead systems can't offer. The introduction of torque control through Hydraulic Driveheads creates a safe operational window in terms of HSE (health safety environment) as no moving parts and external brakes are in place, aim is to overcome the troubles related to parted rods because of no torque control, improving the PCP System uptime due to no sheave and belts, schedule maintenance with a direct impact on the production. The torque control, no moving parts, and reliable system with uptime combined with steady speed results in production increase due to constant operation and less maintenance. Based on the technical and economical results of the trial, the Hydraulic Driveheads represent a reliable, safe technology that justifies the technology deployment in order to replace obsolete angular driveheads in almost 78 PCP wells in a remote location without an electrical supply. Novel/Additive Information The novelty of this Project is the adoption of a technology not implemented before in this field as the solution to maximize value creation from existing matures non-electrified fields.

One of the greatest challenges for wells using an artificial lift system (ALS) is the ability to optimize production while minimizing expenditure. This process involves a perfect balance between effective oil production management, extending ALS longevity, and ensuring energy efficiency, to produce the lowest operational cost. In oil fields under secondary recovery and mature or depleting conditions, production optimization involves continuous monitoring and surveillance of operational variables affecting changes in flow rates caused by surface and subsurface conditions, such as water injection, pressures, obstructions, etc. To achieve the desired goal of a properly optimized process, strong technical expertise is required almost continuously. Based on years of experience in ALS monitoring, surveillance and optimization, various tools and software have been developed to assist in parameter monitoring. Traditionally, the well optimization of progressive cavity pumps (PCP's) is completed on a daily or weekly basis through the analysis of continuous monitoring and surveillance data by a technical expert. As an alternative, downhole (DH) gauges have been installed to directly measure the exploitation conditions, however, such gauges can be costly relative to the production lifting method. To improve the process, well optimization control units have been produced to maximize oil production using algorithms. These systems take advantage of surface variables such as velocity, current, torque, flow rate, and wellhead and casing pressures to respond to changes in operational conditions, ensuring maximum system uptime and reducing intervention costs by increasing the mean runtime between failures. This paper will focus on the well monitoring and optimization system implemented in a YPF well in Neuquen, Argentina. The theoretical bases, concerns, benefits and results will be discussed throughout. The evaluated well used a surface flow meter to allow the system to converge to an optimal flow rate by changing velocity while considering system performance in terms of submergence, torque, current, and wear between the tubing and rod string at high operating speeds. Post-implementation, by optimizing the flow rate, the oil production doubled while reducing the manhours required, ultimately increasing profit while reducing operational costs. The results of implementing this well monitoring and optimization system have been validated through field trial, creating a trusted method to extend throughout Argentina fields and aiding production engineers in their optimization targets.