The novel dual electric submersible pump (ESP) completion was designed to maximize oil recovery by improving waterflooding efficiencies while minimizing capital expenditures (capex) and surface facilities. The design enables the operator to produce oil and formation water from the same well. The injection of water, produced from the same oil producer, is part of a waterflooding project to boost secondary recovery. Based on the dual concentric completion (DCC) concept, this novel solution integrates an inverted flow architecture to provide the upper ESP with direct access to the lower reservoir zone, which is the water-producing zone. This single ESP is then used as the only equipment to lift the produced water and then provide sufficient pressure for direct injection into a neighboring well, without the need for surface treating and handling facilities. Oil production is lifted by the encapsulated lower ESP. The complete solution includes a monobore anchor with an automatic release tool to eliminate oil-zone damage during the completion phase and maximize water-zone productivity. The upper reservoir expected to produce approximately 700 BOPD with 1% water cut; after the successful implementation and commissioning of this novel architecture and its impact on the secondary recovery process, the recorded production reached more than 1,000 BOPD, with an overall 35% oil production increase in the field. Using a monobore anchor with an automatic release tool to perforate the lower sand allowed to combine the underbalance technique with clean perforations system and high impact penetration charges, which resulted in greater water zone productivity and improved pump efficiency, reducing power consumption by 33%. Considering that the project was implemented with a local diesel generator, the total CO2 emissions reduction was approximately 700 metric tons per year in just one well. Because the novel inverted DCC solution does not require the construction of traditional surface facilities for water injection, which include horizontal pumping systems (HPSs), capex was significantly reduced. In addition, because this solution was developed, designed, and implemented in far less time than a traditional method would have been, production was increased earlier than otherwise possible, helping the operator meet production targets and increase cash flow.

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.

The development of the Ishpingo-Tiputini-Tambococha (ITT) project was extremely important to increase the Ecuadorian oil production curve at least 10%, and to have a low cost per barrel of oil produced, considering Ecuador's oil industry as the primary income source in the national economy. This work presents the experiences, learnings, and results acquired on the first 100 wells drilled for ITT, becoming the integrated project of reference for performance drilling and optimization for the Ecuadorian oilfield industry. The first approach to comply with the reduced budget planned per well was based on dedicated integrated project management to maximize overall efficiency, using basic drilling technology such as downhole motors together with wire-line logs after drilling to acquire a comprehensive formation evaluation data. However, the complexity of the wells would be increased along the project, and basic technology would not be longer effective. Multidisciplinary engineering, based on a cost-benefit analysis, was fundamental to determine the fit-for-purpose advanced drilling and logging-while-drilling technologies and the proper drilling practices to optimize drilling performance. These optimizations enabled delivering wells in a shorter time and with a lower budget than planned. The ITT project started in March 2016. By January 2019 the first 100 wells (3 vertical wells, 7 water injection wells, 71 J type wells, 19 horizontal wells) were finished successfully at an average of 3 wells per month with outstanding results that exceed the proposed objectives. The first 100 wells were delivered in the equivalent time of 80 wells planned time. That outstanding achievement has its main stone on the engineering developed by the integrated drilling services and the operator during the planning and execution phases. Now, the ITT project is recognized as a real example of integrated drilling optimization in Ecuador. It was the second-highest producing oil field with 70,000 barrels produced per day up to April 2019, and with more than 80,000 barrels produced per day up to September 2019, it became the highest producing oil field in Ecuador. This represents around 18% of the total Ecuadorian oil production. That level of production has been reached in less than four years, several years less than the time it took to develop other oil fields in the country. The optimization done has other excellent results, such as creating the lowest cost per barrel of oil produced in Ecuador and having zero environmental impact without affecting the ecosystem of the ecological reserve where the oil fields are located. The latest drilling, measuring, and logging-while-drilling technologies are more expensive than basic technology. However, when the right solutions are properly applied, it's possible to create a correct drilling solution that optimizes the cost-benefit for the project and results in a win-win relationship between operators and drilling service providers. The achievements of the ITT project are documented in this paper as reference for true performance drilling in the Ecuadorian oilfield industry and any environmentally sensitive area around the world.