Erosion and impact tests were performed on downhole valves with different materials to determine the best valve configuration for the field conditions. Due to premature failures (less than 1 year of operation) in three wells caused by erosion of the valves, a complete investigation was conducted. First, the history of rod pumps installed in Caño Limón Field was analyzed to obtain configuration statistics of valves installed since 2005. Six different configurations were analyzed, including valves installed in failed and running wells. These configurations included six different ball metallurgies and two different seat metallurgies, combined in double valve setups installed in the pumps. The six valve setups were compared with the average run life and reservoir conditions to determine the best configuration for Caño Limón field. The statistics alone were not clear enough to determine the best configuration for the field, so a laboratory bench was designed to test the different ball and seat metallurgy configurations. Silicon nitride balls were selected due to their resistance to abrasion, fluid cutting, and impact. The statistics showed good performance when installing silicon nitride balls with tungsten carbide seats, combined with titanium balls and tungsten carbide seats. But when installing single or double silicon nitride balls with tungsten carbide seats, the run time was less than 100 days. The laboratory tests were performed for titanium carbide, silicon nitride, and 440C balls, all of them with tungsten carbide seats. The erosion and wear tests were performed simulating the flow of a slurry around the ball. Silicon nitride balls showed less erosion than titanium carbide and 440C balls. The impact test was performed simulating the downhole pumping action, where the ball is impacted against the seat in a slurry made of water, polymer, and frac sand. Silicon nitride balls showed less wear than titanium carbide and 440C balls, but the seat working with silicon nitride ball showed higher wear than the other metallurgies. When installing single or double silicon nitride balls, the seat wear was higher than when combined when another metallurgy. It was possible to correlate the lab test results with the pump failures to determine the best configuration for the application. When selecting the valve assembly's metallurgy, it is important to take into consideration not only the properties of the materials, but the effect of combining different metallurgies. Before standardizing an equipment change, field trials and lab tests should be performed.

Throughout a waterflood project, injector wells can experience scale build up mostly related to formation-water incompatibilities; as a consequence, injectivity index (II) decreases and vertical conformance can suffer leading to poor sweep efficiency. Stimulation treatments are required to reestablish well injectivity; usually Hydrochloric acid and Regular Mud Acid are used in sandstone reservoirs. Such treatments involve a number of difficulties such as handling highly corrosive fluids, risk of clay instability, secondary reactions and time-consuming flowback of spent treatment in low pressure reservoirs. Recently, a novel chemical was identified to effectively dissolve scale obstructions in injector wells while avoiding the operational constrains found in traditional acidizing jobs, including the need of flowback. Fluids containing the environmentally friendly chelating agent Glutamic acid N, N diacetic acid (GLDA), were tested in the laboratory under downhole conditions to evaluate the dissolution of a scale sample from the field composed by Fe2O3 and CaSO4. Additionally, core-flood, compatibility and corrosion tests were carried out to evaluate the interaction with clays, formation and well's metallurgy. Results showed effective dissolution of the scale sample, while being fully compatible with formation clays and fluids which indicated that the treatment could be left downhole and pushed into the formation without causing further formation damage. Furthermore, corrosion tests showed no need of corrosion inhibitor for a low carbon tubular under tested conditions. Field implementation took place in an on-shore injector well completed selectively with injection valves between packers. A two stage treatment was designed; the target of the first phase was cleaning out the injection valve itself and the tubing-casing annular space of this interval, and the second stage aimed the dissolution of scale located in the perforations and deeper into the formation. Step rate tests were performed before and after the treatment to evaluate well injectivity. Low injection treatment rates and soaking allowed enough time for the GLDA to effectively dissolve the scale obstruction along the treated interval; spent treatment was pushed further into formation once regular water injection was reestablished with a 51% increase in its injectivity index. The use of GLDA in the field was considered cost-effective due to the lack of additives, no need for of N2 to kick-off flow-back, nor flow-back fluids neutralization and disposal.

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The Oil and Gas industry in recent years have been a great challenge for operators and aervice companies as well. This situation resulted in great opportunities to find efficiencies that can enhancement production, avoid down times and optimize operation in Electric Submersible Pump Systems (ESP). Keeping this on mind, one of the main drivers is implement procedures that can extent ESP run life, and one of the key challenges is to identify any trouble that can impact ESP performance timely so it can implement solutions to avoid failures. The main objective was to develop a troubleshooting manual that could be used for any engineer to identify likely conditions that could be affecting negatively ESP performance and to implement solutions to minimize failure or damage beyond repair in ESP equipment. A jointly team composed by the operator and the service company developed a troubleshooting manual to the proper identification of likely conditions that could be impacting the production and performance of ESP systems. This was achieved using monitoring information, tear down evidence, setting configuration and building a database with all the information in order to group similar cases to identify the best ways to respond to any anomaly in ESP behavior. This procedure was implemented in the field that have an average of 450 active wells with 93% being ESP systems, by socializing it with all the parties that participate in ESP troubleshooting to guarantee a proper handling of any occurrence. The main purpose of the creation of this procedure was to avoid failures associated with ESP operation conditions that could result in early failure; this is measured with the Failure Index (IF) that means the number of average interventions in an ESP field related to the average number of active wells in the same period. The implementation resulted in awareness in all the personnel that when best practices are followed there are better chances of field KPI improvements and savings, in this case the Failure Index of the field was reduced from 0.4 to 0.18 attributed to technology and best practices implementation as well. This paper aims to present the most relevant analyzed cases, the procedures implemented and the results in FI after implementation as well of recommendations to any party interested in implement similar projects in their operations.

Conventional methods used for downhole sand or debris cleaning have considerable investments in economic costs and time. Scheduling these activities to minimize production interuptions and to maximize unrestricted flow is a constant challenge faced by production and flow assurance engineers in the Oil & Gas industry. A sand and fill cleaning decision can be expressed as an optimization problem since its purpose is to maximize the production of the well to accomplish production goals at the end of a time period. This paper presents optimization algorithms applied in dynamic programming to help in scheduling cleaning interventions for wells in order to maximize the continuous production under physical, technical and economic considerations while minimizing the investment cost of the total operation. A strategy will be presented which takes into account mainly the fixed costs but also the variable costs and sensitivity analysis that allow the model to better approximate reality. The strategy considers three options based on the costs of cleaning with either electric line or coiled tubing technology; 1) to completely remove a given volume of sand, 2) to clean to a minimum acceptable level or, 3) not to clean and allow sand volume increases to continue. The cost to perform sand cleaning with a certain technology based on a mathematical function, considers the following requirements:the relationship between volume of sand produced per unit time, Vt (flow),(Vmax-Vmin) or the interval between Vmax in which production of oil is minimized and the Vmin for maximum production,the time horizon to perfom the sand cleanings, andPoints that make the operation unfeasible such as physical restrictions in the well or operator time/cost constraints. This paper will also present two cases demonstrating the strategy to schedule cleaning interventions that achieves a set production goal.