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).

The well (Figure 1) of the case study presented in this paper is an oil producer from carbonate reservoir located in Southern Europe. Reservoir is characterized by a complex fracture network that increases the difficulties of production optimization actions, as for example water shut off interventions. This well is completed with a 4-1/2" liner extending to a 4-1/2" slotted liner inside a 6" open hole (OH). During the production time, the Water Cut (WC) has increased steadily finally reaching 94%, preventing the well from producing naturally. Log acquisition and interpretation, with Production Logging Tool (PLT) and Spectral Noise Logging (SNL), have shown that the water was coming from a fractures network laying behind the liner, to enter the top of the slotted liner despite swellable packers A and B. The lack of accessibility to this fractures network was therefore posing a challenge for an effective placement of a sealant gel.

The Fully Retrievable ESP System Cable Deployed (CD) is a new technology which permits the rigless deployment of ultra slim OD Electrical Submersible Pump, able to reduce production loss while waiting for work over: these operations should be performed by a proprietary power and load carrying cable, and should be through tubing with the possibility to retrofit an existing completion. Based on previous Eni Partially Retrievable Experience, a R&D tender was launched among all ESP contractors interested to identify a complete rigless ESP solution. All technologies proposed were evaluated and Novomet was awarded the contract for the trial installation. Eni philosophy was to select the best candidate well which can be representative of the main criticalities of all Eni asset, in order to export the technology in the majority of operated fields. The scouting was performed among all Eni Geographical Business Units (GBU) and finally a well in Italy was selected to be the best candidate. The aim of the test was to install and operate the ESP for a short period of time, in order to validate the technology and diffuse it among the other GBU interested. It is important to highlight that the well selected is equipped with a Shallow Set Safety Valve, as common practices for ESP installation, so the R&D test will investigate also the functionality of the insert safety valve. The paper will describe all the steps needed to go further in a Rigless ESP installation project and all the lesson learnt that Eni can draw for the Oil & Gas Industry. The selected solution allows the retrofit option for the current shut-in wells, thus increasing the business opportunity for this type of technology. It is evident that each ESP solution (standard, partially or fully rigless) has pros & cons that will be discussed in the paper to guide the operator in the selection of the best possible option.

Primary production mechanism of a clean sandstone reservoir in a brownfield for oil production has been recently changed from natural depletion to waterflooding. Despite the apparently moderate petro-physical properties of the formation, injector wells performances were observed to be extremely poor, mainly due to: high drilling-induced formation damage and Fluids interaction within the reservoir (injection across the oil rim section). Several stimulation technologies have been applied to improve wells injection capability for pressure support optimization. Re-perforation via abrasive jetting, perforations wash through coiled tubing and various acid formulations via bullheading were attempted without achieving any significant increase in injectivity. Considering the modest rock permeability, the need to access a wider formation area to improve oil sweep efficiency and the crucial requirement to re-pressurize the reservoir, an additional card was played as last resort: hydraulic fracturing. This technique was not new to the area and already experimented by different operators. Several producer wells in different layers were hydraulic fracturing stimulated with proppant and/or acid in the past with a good rate of success. Why not to try then? Given the past experience on the same field with hydraulic fracturing in oil producers and accounting for well integrity and potential injectivity, one was chosen as suitable candidate. Offset wells hystorical data were used to build a hydraulic fracturing reservoir model and plan for the activity in details; operator and service providers engaged in a Frac Well On Paper activity in order to reduce any margin of error during field operations. An approach that proved successful. From there, the first trial well was planned and performed successfully. 4 other hydraulic fracturing jobs on 4 wells followed at close distance in time with different, but steadily comforting, results. Injection was improved from negligible initial values up to 2000 mc/day for the post-stimulation condition, exceeding the preliminary expectations. This paper introduces the steps taken to start the hydraulic fracturing campaign, the decision process that led to the design of the treatment, an overview of the execution phases, results well by well and lessons learned to optimize future campaigns.

Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events. However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access. The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools. After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction. Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir. Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval. The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.