It highlights the good performance of various Progresive Cavity Pumping (PCP) Systems with pumps landed in ultra high deviated angles, superior than 54°, and critical dog leg severity, 3.4 - 4.5°/100ft in Dina Terciarios field. This performance goes beyond the traditional Colombian oil industry conception about PCP system, it can only be used for vertical or slightly deviated wells and there is a large prevention regarding. This paper applies for any well with fluid properties and production conditions where PCP technically applies as an artificial lift system, and the critical well geometry rejects the PCP systems due to curvature characteristics, horizontal and highly deviated wells. This specific case is focused to Dina Terciarios as an oil field and two Operator oil companies, Petrominerales and Ecopetrol. Five PCP Systems have successfully been working in this field since March 2010 with pumps landed at deviation angles of up to 80 degrees and 4.5°/100 ft dog leg severity. The average Run Life for those wells is higher than 652 days, including a maximum performance in the DT-137 well of 1041 days and counting. Technically speaking the key factors of these PCP applications are the use of continuous rod, instead of conventional sucker rods, tubing rotators in surface and an appropiate management of application (lifting and pumping capacities, speed and torque control), all oriented to minimize contact loads and wearing effect associated to the well survey and operational conditions. For both Operator companies this new PCP scope has shown economic advantages in terms of equipment and maintenance costs, well services and spare parts, changing their technical point of view and being a reference for other areas in Colombia.

The main artificial lift method used in the field Corcel, located in the Llanos Basin, since its beginning in 2007, is the electric submersible pump (ESP). Until April 2011, 9 ESP units were running with an average run life of 218 days and, during those four (4) years, a total of 37 installations were performed, of which 21 were associated to ESP failures. As a result of the high number of failures and low run life presented, an interdisciplinary research group was created, including production, completion, reliability, product and applications engineers from Petrominerales and Baker Hughes, with the ultimate goal of increasing the life of the equipment, reducing intervention costs and minimizing deferred production. Failure analysis focused on two main points: identification of the affected components and root cause of the failures. First results evidenced that the seal was the most affected component of the Electric Submersible Pump, and, more specifically, the elastomer bags and mechanical seals. Although the initial root cause of failure was not clear and was associated exclusively to a problem of compatibility between the seal elastomers and the well fluids, a further detailed analysis was performed to determine other possible failure mechanisms of this component. This paper aims to describe and analyze the failure mechanisms, as well as to provide the solutions designed specifically to mitigate them, starting with the development of a new technology such as the SP1 seal to substantially improve the lifetime of the equipment. An illustration of one of the most important applications of fluid characterization for the sizing or selection of an ESP is presented, as well as the results in reduction of deferred production and intervention costs.