Atlanta Field, offshore Brazil, is probably the most challenging deep-water heavy oil field in the world. Great challenges have been overcome to build and test the first two wells in this field which have already been detailed elsewhere (Papers OTC 25813, SPE 174893, SPE 174896, SPE 174897, SPE 173946). The refurbishment of the FPSO Petrojarl I, to enable it to process the high viscous oil will be described elsewhere. Finally, the last frontier to prove the technical and economic viability of Atlanta Project is the so called "First Oil" and the ESP operation. In normal conditions starting an offshore well when equipped with an ESP (Electrical Submersible Pump) is not a trivial task. Furthermore, Atlanta's wells lower completion is composed of Open Hole Horizontal Gravel Packs, due to the completely unconsolidated reservoir. To produce the viscous oil to the FPSO, the most powerful ESPs in the world, with 1,550 HP induction motors, were installed into the wells. Because of the low temperature on the seabed (around four degrees Celsius) in the event of any (expected or unexpected) plant or pump shutdowns, the viscosity of the cold oil could increase to up 100.000 cP in a few hours, despite the flowline insulation. Finally, managing the treatment plant start up procedure is a very complex task. All these conditions combined made the Atlanta Field Start Up a real challenge. A very restrictive procedure to increase the production drawdown, the production rates, the ESP demand and the plant processing capacities were successfully implemented. These extremely harsh conditions and the effective procedures to cope with them are thoroughly discussed in this paper.

Most of the artificial lift strategies in deepwater environments require sophisticated and robust solutions, aiming to improve the system's run life and reliability. Due to that, oil companies choose only trustable technology and field-proven solutions for artificial lift design. This is the case of Atlanta Field's artificial lift project, with electrical submersible pumps (ESP) installed at more than 1,550 m water depth, to produce heavy oil. For Atlanta Field, the ESP must handle high viscous oil and emulsions at high flow rates to be economically feasible. To achieve this goal, it was deployed one of the most powerful ESP in the world with 1,550 HP induction motor and more than one hundred pump stages into the well. This is the largest ESP in-well successfully installed in Brazil. The artificial lift strategy adopted for Atlanta Field was an in-well ESP as primary method and an artificial lift skid (ALS) installed on the seabed for back-up. When the primary method fails, there is no in-well ESP replacement, because of high costs involved with workover and the back-up system becomes the main one. When the back-up system fails, the replacement of the pumping module is done by an AHTS equipped with active compensate crane for subsea installation. In this way, replacement costs are much lower than those needed to replace pumps inside the wells. So far, this artificial lift strategy has proven to be reliable and project results will be discussed in this paper. Strategies to optimize production will be addressed and observations regarding free gas ESP pumping will be made. After a period producing, the in-well ESP have failed, and the ALS became the main system to produce both wells, as planned. The project faced some challenges with ALS operation, since there was an expressive flow restriction in the in-well ESP. Experimental tests were permeformed to better determine the pressure drop caused by the flow through the pump stages and to propose a solution to the production restriction. By-pass valves were adopted in the project to avoid the mentioned issue. The well ATL-4 was drilled in March 2019. As this operation requires a drill ship, it was decided to perform workovers in wells ATL-2 and ATL-3 to replace the in-well ESPs and install the by-pass valves in the well's production string.

In an oil field development, the choice of the appropriate artificial lift method is extremely important to obtain the best financial return for the project. The most efficient artificial lift method for heavy oil is the ESP, in the perspective of lift capacity and flow assurance, but, due to its low MTTF (Mean Time to Failure), in some cases, the associated cost for the offshore workovers is prohibitive. An alternative to reduce the cost of the workover is positioning the ESP in the seabed, in a pumping skid (Subsea ESP / skid-ESP). Positioning the ESP in the seabed, however, reduces the initial well flow rate. Most commonly, the Artificial Lift Method is chosen based on the previews experience of the operator, not giving appropriate effort to a technical and commercial evaluation. This paper proposes a methodology to provide quantitative data to assist the decision of the best positioning of the pumping system, inside the well or on the seabed, in order to obtain the best financial return. The methodology is based on three stages: technical evaluation, which is an eliminatory step, based on the GVF (Gas Volume Fraction) limit that the pump can handle without flowing problems; then, an economical and risk analysis are performed for both projects (ESP and skid-ESP). Three case studies were performed to evaluate the proposed methodology, and to confirm that it is a good tool to assist the decision of the best positioning of the pumping system. The results show that the three stages proposed are important. One of the three cases show a scenario where the skid-ESP is declassified in the first step of the methodology because of the high GVF calculated for the project, above the limit for this specific well. In the other two cases all the three stages of the methodology were applied. The economical deterministic analysis was not enough to define the best positioning of the pumping system, in order to obtain the highest financial return, and the probabilistic risk analysis was essential to obtain quantitative data to support an efficient decision. In both cases the suggested positioning of the pumping system was the seabed (skid-ESP or subsea ESP). In the literature, some works propose methodologies to choose the appropriate artificial lift method. Some of them offer an economical evaluation tool; but a methodology that includes the subsea ESP as an option for heavy oil deep water projects was not found in the literature. This paper proposes a methodology that can be easily applied with the software's commonly used in the industry, therefore adding information to the existing body of literature that can benefit practicing engineers.