Objectives/Scope This paper summarizes the innovative peculiarities and the result of field trial installation on ENI well in South Italy of the new Insert Sucker Rod Surface Controlled Subsurface Safety Valve ISRSCSSV. The ISRSCSSV, combined to a modified lock mandrel, is sucker rod retrievable and is possible to install in a WRSCSSV landing nipple. It is a normally closed failsafe safety valve so the CL pressure keeps the valve open (Orsini 2018). Methods, Procedures, Process The innovation resides in a variable geometry sealing mechanism, able to shut in the annular area between the sucker rod and the valve external body. The sealing path is composed of a segmented tapered pads system located at the end of the elastic fingers, travelling along a cone housing. The ISRSCSSV combined with the Hybrid Pump determines a new approach for interventions on existing wells completed for spontaneous flowing without workover, representing a first fundamental step towards the application of the dual barrier policy in production wells. The Innovation allows safely operating wells and recovering oil otherwise not economically advantageous (Mennilli 2019). Results, Observations, Conclusions The ISRSCSSV applies when need to convert a spontaneous flowing o ESP wells to the sucker rod artificial lift. After the manufacturing of the ISRSCSSV, the related modified lock mandrel prototypes and the dedicated test fixture, the functional test performed as per API 14A (2015)/UNI EN ISO 10432 annex C (2004), was successful. Before the installation in ENI's well, a shallow test well equipped with all the necessary accessories to install and test the Hybrid Pump, and the downhole safety valve was completed, the test results were positive. On January 2020 ENI after attending the above tests, decided to run a field trial installation, function test, and retrieving in a well located in South Italy. On the field, after the ISRSCSSV installation, the safety valve lock mandrel was tested to verify the hold-down mechanism. The ISRSCSSV test was performed applying pressure inside the tubing against a wireline plug. Then closed the ISRSCSSV, bled off 50% of the wellhead pressure and performed a positive test as per API 14A (2015). The field test ended with the assembly retrieving applying the necessary over pull to release the lock mandrel retainer system. The overall result of the trial was considered positive. Novel/Additive Information ISRSCSSV represents the first safety valve existing in the body of literature for wells with sucker rod artificial lift system, allowing the compliance to the dual barrier policy. Moreover, this approach gives the possibility to install and retrieve the safety valve always with the rods string, with considerable time and subsequent cost saving, safeguarding the protection of the environment and the Oil Company image (Mennilli 2019).

1 Abstract The center of excellence concept is worldwide associated to new software, tools and technologies that help the team to pursue excellence in a particular area. The increasing use of sensors and gauges in the Oil and Gas field drove eni to develop internally the Center of Excellence for Electrical Submersible Pumps, to monitor and interact directly with the worldwide Business Units and to address the ESP issues. The tool and all the technologies behind had been developed by the Artificial Lift team, under the Completion Department, thanks to the strong effort of the IT Department in San Donato Milanese, Italy. The Center of Excellence (from now CoE) gives mainly the following information for each well: Pump details and operative parametersWell surface dataKey Performance Indicators All the data are collected in real time and the team can visualize any variables to perform a detailed analysis. The CoE system is a web-based tool that is available on the eni intranet, and provide the possibility to store well-related documentation. The most important advantage given by the CoE is the possibility to navigate through the KPIs, easily adaptable based on the field experience. One of the analyses possible in the CoE consists of comparison of the real-time pump intake and discharge pressures and the relevant simulated values retrieved from the Prosper model stored in the CoE system. In case of mismatch, a notification will be generated and will be sent to the technicians (via mail). Once the wells that are producing with KPIs out of the desired range have been identified, the Artificial Lift team can immediately take corrective actions. Presently the tool is fully operative for 20 wells in Alaska, and for 1 well in Italy and for 20 wells in Iraq and the process is ongoing to have other eni BUs online. Definitely the CoE could be helpful to optimize the operation and to analyze the wells in a smarter way than in the past.

The world's first offshore Rigless Fully Retrievable Electric Submersible Pump (RFR-ESP) system has been successfully installed in the eni Congo Foukanda Field (Republic of the Congo). The project was developed between eni Milan and eni Congo as an Innovation Technology Application (ITA), and it is the world's first offshore RFR-ESP system. The RFR-ESP technology provided by ZEiTECS allows the rigless deployment and retrieval of a conventional Electric Submersible Pump (ESP) system through tubing by means of standard oil field wireline, rod or coil tubing technology. The RFR-ESP system technology is based around a specially designed oilfield wet connector system. This "plug and play" connector design permits the use of any ESP manufacturer's equipment, allowing ESP optimization to match changing well conditions and replacement of failed ESPs without rig interventions; thereby providing an opportunity for OPEX savings, a significant reduction in workover costs and deferred production due to limited rig availability. The success of the first RFR-ESP completion and the positive results achieved to date are encouraging in the pursuit of extending this innovative and valuable ESP completion philosophy to eni Congo wells where ESP failures are primarily related to pump or motor and workover cost are high. The paper describes the technical features of the new RFR-ESP completion, the experience acquired on the Foukanda well and shows, via theoretical study, the economic implications of applying this new ESP philosophy in all the eni Congo high OPEX wells. Introduction Electric Submersible Pumps (ESPs) have become a reliable and important tool in today's global oilfield. ESP technology itself has evolved to meet new, more challenging, operating environments but, nevertheless, the vast majority of ESP deployments use techniques developed decades ago. ESP systems are still installed using jointed pipe, lowered with a pulling unit, drilling or workover rig while power cable is secured to the tubing by means of metal clamps or bands. Even acknowledging the fact that the reliability of ESPs has increased tremendously since their first introduction, some form of remedial work will be required multiple times during the life of a producing field. If that work requires a pulling unit, a drilling or workover rig, the economics of field development may become unfavorable. Eni is looking at reducing its ESP operating costs and, in doing so, decided to evaluate the relative merits of "alternative" ESP deployment options. The RFR-ESP provided by ZEiTECS was selected for an offshore test installation in one of the eni Congo fields. The RFR-ESP technology represents a step change in ESP operating philosophy. ESP replacement without a hoist reduces operational disruption, reduces OPEX and deferment in production but, moreover, has profound safety and cost advantages with elimination of a number of the heavy offshore well interventions. To gain confidence in the new technology and in its new deploying mode, eni selected the well FOKM 101, located on the eni Congo offshore Foukanda platform.

The "Fully Retrievable" ESP System is a new technology, which permits the rigless deployment and retrieve of conventional Electrical Submersible Pump (ESP): a wire-line, coil-tubing or rod should perform these actions. This paper shows the eni experiences in this application and the approach used for the completion design according with the company policy highlighting the benefits and the criticalities faced. Two Fully Retrievable ESP were installed by eni in the following fields:Alaska - OP18-08 - Nikaitchuq Field - onshore arctic environmentCongo - FOKM 101 - Foukanda field - offshore. Each of them involved different issues and will be discussed in detail in the following sections. This paper goes all the way through the well definition, completion philosophy and ESP system selection exploring constraints and limitation of this equipment. An economical comparison was performed and the conclusion is that the retrievable ESP should be used in all of those fields where the workover cost is high and the deferred production is important due to rig unavailability. It will be presented that the main benefits of this technology include:Simple ESP retrieving with smaller environmental impactCapability to run temporary systems to clean up or test the wellFine tuning of the ESP based on production data. The benefits of the technology were tested using an internal eni tools for risk analysis based on Monte Carlo simulation: the results are discussed in the last part of the article and highlighted the above expressed consideration and main criticalities.

Eni is involved in a big project in the Middle East developed with an extensive use of Electrical Submersible Pumps.The installation of Electrical Submersible Pumps (ESPs) is a common solution in case of depleted reservoirs or where there is demand of high pressure from the surface facilities.The downside of ESP completions is that they restrict the access to the wellbore for stimulation and cleanup jobs.The use of a mechanical by-pass (Y-tool) is possible if the production casing/liner is at least 7Љ, and anyway imposes a reduction in the pump size. Moreover, ESPs are also affected by several factors that could lead to definitive failure, like solid plugging or scale depositions.During the field operations, both ESP stuck by plugging and reduction of productivity index were recorded.The possibility to perform stimulation jobs through the pump, to avoid the cost of retrieving the completion, was therefore studied as a possible solution even if no past experiences were found in literature and the feedback from the ESP contractors to consider the stimulation trough ESPs only as last chance before a workover.A dedicated production optimization was created putting together artificial lift and production optimization engineers.The jobs had to be carefully planned and evaluated case by case, considering that the reliability of all elastomeric and electrical elements downhole (protector, cable, and pothead) could be reduced in case of contact with the stimulation fluid.Several different interventions were performed: the first ones were aimed at dissolving possible plugs in the pump, starting from simple water or diesel wash and further evolving to more aggressive acid washes.Extensive lab analyses on the emulsion tendency of the oil lead to attempt also non emulsifier treatments. This paper will present and detail the successful results experienced in the field, especially in terms of production recovery from stuck pumps and PI improvement.