Way of working is continuously changing in O&G field thanks to digital solutions and the possibility to have consistent data driven analysis to support decision-making process. Well Construction cycle from planning to execution and post well analysis is evolving as well, since data are at the base of all the analyses allowing higher operational safety, more efficient engineering, better real time optimization and more effective comparison of performances at the end of operations. Eni Well Operations Department has invested a lot in advanced analytics tools able to extract value from historical and real time data focusing the attention first of all on data coverage, quality and reliability, that are extremely important enablers to let the tools work and perform analyses, and then on proper data transmission system from different rig site locations towards a centralized database. High frequency performance measurement and data intelligence tools allow reaching the technical limit, predictive analytics help in reducing downtime while drilling and well simulation software enhances not only planning phase but also operational real time follow up activities. Applications of digital solutions have run in 2019 on most challenging activities with tangible results in terms of safety improvement, operational efficiency and time and cost savings. Almost 50 wells (more than the totality of most complex wells as per Eni classification) have been analysed in real time with both advanced analytics and predictive algorithms achieving: avoidance of specific Non Productive Time events (about 25% of NPT reduction), with a major impact on operational safetybetter performances throughout development projects, thanks to an improved learning curve and a reduction of Invisible Lost Time (average of 2,5% of time saving per well)enhanced real time monitoring and early detection of well events, leading to a faster decision making and adoption of corrective actions (anticipated actions by average 6 hours) The development and the application of these tools have been made possible thanks to a proper Data Management System. In fact, several initiatives have been put in place to provide proper data gathering, data transmission, data quality check and assurance and data storage. This paper will show in details how the results have been obtained starting from creating an appropriate data infrastructure up to real case of application along 2019 Eni drilling activity. The extensive use of digital tools, both in Geographical Units and Headquarters, has been proven to provide effective support to plan, monitor and evaluate performances during all well operation activities.

Bir Rebaa Nord (BRN) and Bir Sif Fatima (BSF) fields, operated by Groupement Sonatrach-Agip (GSA, a JV between ENI and Sonatrach), are located in the Berkine basin in north-eastern Algeria. These fields are characterized by oil-bearing sandstone reservoirs with low to medium petro-physical properties. During the development phase, to counteract the effect of pressure depletion, water and gas injection was implemented for reservoir pressure maintenance. In addition, due to the increasing water cut, artificial lift systems were employed to effectively produce these fields. Hydraulic fracturing has been implemented in GSA since year 2000 to improve well performance, both in terms of productivity and injectivity for oil producers and water injectors respectively. The fracturing process has been improved over the years regarding operational procedures, enhanced reservoir knowledge and implementation of new technologies towards resolving the many uncovered challenges. Changes to the perforation strategy, fracturing fluids formulation, rock mechanics studies and design of proppant schedules are examples of enhancement to the fracturing practice that have been implemented in the recent years. One of the uncharted matters in GSA, coming out from the post-job data re-processing, was the necessity of a precise characterization of the hydraulic fractures vertical coverage. The presence of several sandstone layers with different properties brought questions if the fracture had grown into an unwanted zone or may had not properly covered the entire target formation. Moreover, fracture height is an essential parameter for frac models calibration. Its accurate determination drastically reduces the margin of error in treatment net pressure matching, helping to more precisely established fracture half-length and width, stress profile and, last but not least, achieving a calibrated model for future operations in the same area. This paper describes the successful implementation on two water injector wells of a novel non-radioactive detectable proppant for the first time in Algeria. The taggant material within the proppant has been located by comparing the pulsed neutron capture cased-hole logging passes registered before and after the hydraulic fracturing treatments. The detectable compound does not affect proppant properties and, in addition, its non-radioactive nature reduces the timing for materials delivery and eliminates the HSE risks linked to other tracing methods. The pulsed neutron measurements evaluation provided valuable information regarding fractures confinement, avoidance of contact with undesired layers and possible presence of cement channeling. Furthermore, combined with sonic logs and cores data, it helped refining the geo-mechanical model for future interventions design in the same reservoirs.

In the last decade, hydraulic fracturing has been successfully applied in West Africa for the development of tight reservoirs. Since 2007, more than 200 fracturing stages have been achieved in 9 different fields targeting wells characterized by a wide range of conditions: from sandstone to carbonate formations, from low to high temperature reservoirs, and from old existing completions to new drilled wells. While applying this technology throughout the years, tailored solutions for treatments design have been continuously put in place to address the observed challenges and maximize the final oil recovery. The deployment of new technologies such as proppant flowback prevention additives, non-radioactive tracers for fracture height monitoring, and channel fracturing, to boost the fracture conductivity played a major role in achieving the desired results. The accumulated in-depth knowledge on hydraulic fracturing built from local experience allowed Eni West Africa to rapidly approach a new offshore tight oil field development with confidence that hydraulic fracturing would be an effetive stimulation technique. This paper will describe the fracturing campaign major milestones, from the promising results obtained on the exploration wells, to the optimization actions implemented during the first development phase. Thus far, six horizontal and two vertical wells were completed, including a total of 23 hydraulic fracturing stages during a single campaign spanning less than one year. On the first of the two vertical wells, each stimulated with a single frac stage, a non-radioactive tracer was employed for measuring the propped fracture height, and calibrating the frac model. For the horizontal wells, where 3 or 4 frac stages were implemented, a plug-and-perf (P&P) technique was selected. This method included coil tubing equipped with fiber optic, enabling precise perforation intervals placement, also providing flexibility in case re-perforation was required. Moreover, several actions were adopted to improve completion efficiency and cost-effectiveness, including perforation selection to limit near-wellbore pressure losses, and coiled tubing runs optimization for setting the bridge plug and perforating in a single trip. Finally, particular focus will be given to the steep achieved learning curve, describing the adopted decisions, to improve both completion performance and fracture conductivity.

In the global effort to reach near-term reductions in Green-House Gas (GHG) emissions, all Energy Companies have set an integrated strategy for a low-carbon future. The decarbonization target makes evident the need to also quantify the carbon footprint of well construction activities. The major direct emission source in Drilling and Completion (D&C) is represented by the fuel burnt by diesel generators at rig site to feed tools, machinery, and auxiliary systems. Therefore, data related to fuel consumption are fundamental to have a clear understanding of rig carbon footprint. In this framework, a dedicated GHG module was introduced within an existing real-time advanced analytic tool to unlock the possibility to track and map the CO2 equivalent emissions associated to the fuel consumption of Eni's rigs. This tool has been designed to collect and analyze the different data sources available at the rig site, typically sensor data, recorded at high frequency (1-5 sec), and reporting data, recorded at low frequency (1-2 hrs). The data are combined, with a specific algorithm, to automatically identify the activity ongoing and its related emissions. After that, data are gathered and consolidated to make them available in headquarters in near real-time. Furthermore, the tool was also applied to a case study by comparing its outcomes with the data directly provided by a rig contractor, showing a good level of reliability and consistency. The capability to monitor GHG emissions during D&C activities allows a better understanding of their related impact. It provides useful insights to implement corrective action and tackle them promptly. Finally, operation monitoring is directly linked with its related GHG emissions allowing new types of analysis and considerations. This integrated tool, able to recognize the most carbon-demanding activities, optimizes the process of targeting suitable solutions for GHG abatements during the well construction process. Having CO2 emissions reduction become crucial, this approach will certainly be the backbone of the transformation that Oil & Gas sector will have to undergo to reach its carbon neutrality commitments.

In a global context aiming to unlock a low carbon future by industry decarbonization, developing the infrastructure for capturing and storing CO2 emissions is a key target of countries, energy companies and regulatory bodies. Injection for geological storage in suitable reservoirs is an advantageous option which presents challenges related to the completion accessories and string exposed to the injected fluid and the thermodynamical loads during injection and the well life. The purpose of this work is to simulate by numerical analysis and full-scale test, the behavior of a gas-tight Metal-to-Metal OCTG premium dope-free connection when subjected to low temperatures and loads generated by the effect of a sudden CO2 high pressure drop during injection in depleted reservoirs. Extreme temperature drop down caused by the Joule-Thompson (J-T) effect between injection conditions (P-T) inside the tubular and those in the annulus, may expose tubing connections to a thermal shock reaching a temperature near the theoretical figure of -78.5°C. This temperature drop assumed as worst-case scenario is also explored. The analysis is performed considering estimated loads for a CO2 injection case study. The numerical analysis and full-scale test performed confirm the structural and sealability performance of the connection is not affected by the exposure to such low temperatures. Additionally, transient thermal loads, with a drop of approximately 100°C, appears to be not critical for the metal-to-metal dope-free seal integrity and also not affecting the structural integrity of the connection. The challenges setting up of a prototype testing frame, simulating the cooling by thermal shock, lead to a methodology for assessing CCS projects premium connection able to define a robust testing protocol for cryogenic temperatures. The numerical and full-scale results collected on the tested connection size, together with the ones previously tested, allow extrapolation to near sizes of the same premium thread family. The results achieved by testing a premium connection which has been subjected to a thermal shock approaching -78.5°C represent a forefront in the industry, demonstrating the reliability of the product not only in operative conditions during CO2 injection, but also after an extreme event, assessing performance for the CCUS storage projects.