Carbonate scale is a mineral deposit transported by produced water, and its presence negatively affects well production and electrical submersible pump (ESP) performance. Instead of attempting to remediate it after it has already accumulated, a suitable and more-cost-effective process is to use a continuous inhibition treatment through an additional hardware installed in the ESP. An acid treatment can be suitable for certain types of scale, but acid treatments can cause damage to the tubing string and the ESP if not handled properly. A new hardware was developed and used in ESP applications by looking for inhibition in fouling fluids as soon as the fluid comes out of the reservoir and before considerable pressure or heat changes occur by increasing the contact time with the treatment and by looking for a faster homogenization between the reservoir fluid and the inhibitor treatment with a 360° tool injection. An analysis of historical data demonstrates a significant increase in ESP mean time between failure in wells dealing with fouling fluids where the tool, a tail pipe with a multipoint centralizer, was implemented. Additionally, a more-stable downhole parameter condition was reached. It was also observed that, depending on where the tool was placed, production improved by postponing the buildup of deposits at the reservoir face and mitigating skin damage. This hardware, which improves flow assurance, has been continuously improved, and each step will be covered. Additional information was retrieved during the analysis performed during teardown of the ESPs, and it has been possible to identify wells dealing with similar problems. Some wells were newly categorized as problematic, and several data suggest that the increase in water cut related to a waterflooding process could have changed the fluid properties. By understanding the specific cause of the ESP failure let us understand that there was a direct relationship to a lack of an effective chemical treatment, not related to the formulation or dosage of the chemical treatment, but because of the challenging well trajectory due the mechanical configuration or for uncertainties in the producing fluid properties. It was necessary to create alternative tools as new solutions to improve flow assurance. This project will provide an alternative solution that is cost effective and provides a tangible value to projects in which flow assurance and effective chemical treatment are effective when dealing with harsh fluid properties or the behavior of the fluid is unknown before ESP installation.
For many years, commingled production has not been considered as a valid alternative to produce mature fields; actually, oil regulations in many countries do not allow this technique. This was the case in Ecuador until 2021. In 2021, Ecuadorian regulations allowed commingled production to increase the oil recovery. The main objective of this project is to present the artificial lift expertise applied in and the initial results, best practices and lessons learned of the first 13 wells of a commingled production campaign in the Shaya Project; the project focused on electrical submersible pumps (ESPs) and their operation. The aim was to enable a local best practice that established the well potential in commingled production model. This required the ESP design to lift at and beyond the expected target production, which was accomplished by the design of a robust enough system to cover the wide range of uncertainties presented by the multilayered production and related problems with mature fields, including fines production, increased viscosity, and free gas into the pump. An additional requirement was to handle both the current and higher rates associated with future waterflooding. Thirteen wells were completed with a commingled strategy for close to 1 year. The analysis of input data together with the ESP design criteria for pump model selection and production regime has successfully achieved optimum results, producing without issues two producing zones at the same time without any additional downhole tools. This resulted in an average incremental production of 29% compared to the historical single zone production, 92% of the artificial lift systems are operating inside the optimum operating range with high efficiencies (above 50%), and 62 % of the wells achieved maximum drawdown with a flowing intake pressure of approximately 250 psia. Even though the pressure is below the average bubblepoint pressure, the downhole flowing conditions remain stable, and hence there is a constant flow regime at the surface. The statistical projection of the mean time between failures shows a 100% survival probability for the already reached 384 days of operation, thus giving to the project the confidence that it is on trend to accomplish the expected target run life of the field. This project aims to share with the technical community what has been learned in the Shaya Project, after more than a year evaluating the commingled wells following a clear journey through all the phases: reservoir evaluation, inflow consideration, production analysis, uncertain scenarios, combined fluid properties, artificial lift selection best practices, the surveillance, and performance evaluation.
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