Abstract Distributed optical fiber sensors (OFS) are very promising candidates for remote online-monitoring of pipelines, above or below ground as well as underwater. Usage of OFS is a very interesting way for environmental monitoring of this kind, owing to advantages including resistance to electromagnetic interference, durability under extreme temperatures and pressures, high sensing speed, light weight, small size, and flexibility. In particular, phase-sensitive Optical Time Domain Reflectometry (Φ-OTDR) can provide for sensitive and prompt detection of vibroacoustic signals. It can be useful for leakage or other malfunctioning detection along the pipeline or also for monitoring of processes in wells. Leakage of hydrocarbon products from a pipeline not only represents loss of natural resources, but it also poses a serious and dangerous environmental pollution, in addition to the risk of fire disaster. Suitable diagnostic systems need to be used to monitor gas and oil pipelines in order to early detect and precisely locate leakage problems. Furthermore, by specific analysis of the backscattered signals, Φ-OTDR sensors can detect unwanted activities (intrusion or drilling or others) in proximity of the pipeline. To achieve such detection capability, a single-mode optical fiber is laid along the pipeline and it is continuously interrogated by a narrow-linewidth 1.55 μm laser in order to detect vibrations and acoustic perturbations in proximity of the fiber and pipeline itself. Sensing with Φ-OTDR in wells makes it possible to raise the quantity and quality of information from well seismic observations, for monitoring the hydraulic fracturing and extracting of hydrocarbons. Also this technology allows cost reduction of the operations. In this paper, a real-time distributed oil and gas pipeline security pre-warning system based on the O-OTDR technology is proposed. The experimental platform is established in the laboratory and some trials have been performed in the field over a pipeline length of 180 km in Yakutia (RU) and in well. Both the laboratory and in-field experiments proven the validity of the optical sensing technology applied to pipelines and wells, so we are now proposing these sensors to the Scientific and Industrial communities.

Abstract Sustainability is one of the most important challenges of our time. How can we develop prosperity without compromising the life of future generations? Companies are integrating ideas of sustainability in their marketing, corporate communications, annual reports and in their actions. It is for that reason inevitable that ‘sustainability’ will find its way into project management methodologies and practices in the very near future. Achieving sustainability-related targets in EPC projects is increasingly becoming a key performance driver. Yet sustainability is a complex concept in projects and there are many diverse stakeholders. Some stakeholders are generally recognized as important, i.e., the client and main contractor, yet there are others not always perceived as such and whose absence from the decision-making processes may result in a failure to address sustainability issues. Hence, there is a need for a systematic approach to engage with stakeholders with high salience in relation to sustainability. Moreover, the oil and gas sector has a significant impact on sustainable development, making it important for the sector to implement serious changes in the way it does business. Oil and gas operations involve both upstream activities, and downstream activities. Due to the nature of these activities which cause high risks, companies work continuously to reduce the significance of their adverse impacts on the environment and people. The paper displays an agile model created by the author for collection and measurement of stakeholder feedback in the context of the social dimension, which is one of the three sustainability pillars, in an EPC company working on oil and gas sector for down-stream projects, by applying relative weight calculation methodology. Introduction Currently, the concept of success in projects is being widely discussed in management literature and has been central to the literature of PM (Diallo & Thuillier 2003). Cooke-Davies (2001) explains that project success is measured against the overall objectives of the project and the standards by which the success or failure of a project will be judged could be called success criteria. Lim and Zain Mohamed (1999) suggest that the criteria for assessing project success consist of a set of principles or standards by which project success is or can be judged. Chan and Tam (2001) conducted a quantitative study on construction projects in Hong Kong which identified three dominant criteria affecting project success and client satisfaction, namely, effective time, cost and quality management. The time budget-quality triangle is the most commonly cited criteria for success (Westerveld 2002). A study carried out in the telecommunications, IT and construction industries in Norway and China also suggested the time - cost - quality triangle as the main success criteria (Andersen, Dyrhang & Jessen 2002). Waterside (1998) conducted a study of successful and failed projects and concluded that the following were the major criteria for measuring the success or failure of projects, namely, whether the project: Meets user requirements Is completed on time Is carried out within budget Meets the quality requirements

Abstract Petroleum biomarkers are complex carbon-based molecules derived from formerly living organisms and found in crude oils. These molecules are used by geochemists to get information on the source rocks responsible for the oils generation, such as lithology, depositional environment, organic matter, maturity and age. So they are of paramount importance for Petroleum System Modelling and more generally for exploration de-risking and sedimentary basin characterization purposes. Very often, biomarkers datasets are very large and interpretation process by geochemists can take several months to complete. For this reason, we developed an innovative Machine Learning-based support tool to facilitate and speed-up the whole process of biomarkers examination and interpretation. The core of tool is an advanced clustering method that allows expressing biomarkers data as a combination (mixing) of underlying components, directly ascribable to different source rocks. Non-negative constraint is a key aspect: the objective is to express each data sample, i.e. a vector with mainly non-negative values such as biomarkers concentrations and/or concentration ratios, as an additive combination of some of the underlying components, whereas subtracting components would not have any physical interpretation. A sparsity constraint is added to find solutions that allow to represent data as an additive combination of few source rock components. Both constraints greatly reduce non-uniqueness of the solution, greatly enhancing interpretability of the results. The tool then groups data in clusters, each one having a specific geochemical signature given by a set of scores for each of the different biomarkers' parameters. Each sample is assigned to a specific cluster with a "purity" percentage indicator. Geochemists can then easily use the high-purity samples to label the relevant samples as belonging to different source rocks. Moreover, the tool is able to distinguish the amount of mixing between different source rocks, through accurate deconvolution algorithms. Two applications of the tool are here presented, borrowed by real exploration case studies. In both cases the tool was able to separate samples into clusters that geochemists successfully recognized as lacustrine, marine and in some cases, transitional, with less than 10% of misclassifications, isolating also strongly biodegraded samples. This tool opens the doors also to the insertion and integration of other types of data (light hydrocarbons, diamondoids, etc.) for the whole ‘Big Data’ geochemical characterization of a sedimentary basin.

Abstract Significant risks faced by the oil and gas industry lead to the need of methodologies able to evaluate project and measure risk. Risk-mitigation strategies are most effective when the assessment of the risk includes an in-depth study of several uncertainties involved, with the aim of optimizing investment return. In this basket, petrophysical uncertainty acts a significant role in the risk assessment phase, especially in the computation of volumetrics. The scope of this work is the presentation of a methodology coming up from a real case study, where the limited information available makes challenging, yet critical, the creation of a robust input dataset for petrophysical interpretation and the assessment of the relevant uncertainties. The well log database is heterogeneous due to the complex data acquisition history of the field, and no information are available about tools and hole conditions. Thus, the use of neural networks allowed the prediction of missing log sections, and core data poor representativeness leaded to the need of integration from analogue wells from a regional database, making the uncertainty assessment quite complex. The work proposes the use of Monte Carlo Simulations to assess and propagate petrophysical uncertainty information, and different solutions to integrate the results in the static geological model, ranging from building discrete petrophysical scenarios (conservative, expected and optimistic), to the use of full petrophysical output distribution. The petrophysical uncertainty shows a significant impact on the in-place volume distribution and therefore provide an important element for the subsequent risk analysis phase. Introduction Many people faced the issue of quantifying the petrophysical uncertainty through years, resulting in the production of several approaches, but unfortunately not so many available "on the shelf" and, thus, rarely facing the problem of having poor database, with scarce information about the environment at the moment of the measure. One of the first issues to approach is the following: a direct measure of the main petrophysical parameters does not exist, since there are not tools provided for their measure. We use so to call them indirect measures.

Abstract Scope of this paper is to show how the proper definition of reservoir rock types, based on core data and integrated with nuclear magnetic resonance (NMR) log results, is able to provide a reliable strategic estimation of permeability in un-cored wells where only conventional logs are available. The target is to optimize the perforated intervals by means of a robust discrimination between movable and un-movable fluids and consequent detection of the reservoir zones characterized by the best gas deliverability potential. Mercury injection capillary pressure measurements have been used to evaluate the core pore throat size distribution and to separate micro from macro porosity. The integration of these information with NMR, acquired on the same core, allows to calibrate the most efficient T2 cut-off, discriminating movable from the unmovable fluids. The final outcome is a robust link between reservoir properties (defined and directly measured on core data) and log classification, giving a key driver for the definition of a synthetic permeability profile, rock type dependent, and applied for perforated interval optimization in wells where no cores are available. The blind test was a comparison between estimated permeability from the well production performance and permeability derived from NMR logs, showing a good match. The work has greatly increased the value of NMR acquisition in Gas industry, showing how a proper T2 Cutoff core /log calibration is a vital factor to get the benefit of NMR in Gas reservoirs permeability prediction, providing a useful driver for perforated interval optimization. Introduction At present time, permeability estimation still remains a great challenge due to its not scalar nature: different correlations have been defined in literature to link this parameter to conventional downhole measurements and petrophysical properties, anyway none of the current available open hole logs can deliver directly an indication of the estimated permeability. Even the most advanced NMR tool will fails if applied in a standalone approach. The result is that the conventional log analysis approach, where core data are used mainly for outcome validation, still leave some uncertainties in the permeability profile definition and related reservoir effective deliverability.

Abstract The current oil business panorama demands for cost effective and efficient methods for well surveillance and production monitoring optimization. The integration between traditional technologies such as PLT and geochemistry fingerprint with innovative technologies such as tracers (both interwell and intrawell) and/or Fiber Optic (in both its temperature and acoustic deployments), is a requisite for fluid movement surveillance. This strategy is fundamental, especially if field developments are based on long horizontal drains, deep waters/extreme well paths, multilateral wells, ESPs and subsea clusters where the risk of tool stack is high, the borehole access is limited and the monitoring activities are very expensive. In Eni, the integration of intrawell tracers with permanent Fiber Optic system, wireline logs, inter-well tracers and geochemical fingerprint is considered a successful and comprehensive approach for field/well management and production optimization. The proposed 4 case studies prove, with their high quality data availability and interpretation, how the information collected in this way can be the turning point for a long-period reservoir monitoring during clean up, steady state and re-start stages leading to a more specific intervention and management at well and field levels. Introduction Reservoir surveillance is a critical part of reservoir management. It is aimed at risk minimization by proactively identifying and fixing problems encountered during completion and production by means of different technologies. Information derived from reservoir surveillance is a key factor in taking important decisions associated with optimizing total recovery from the field. Fluid movement monitoring is one of the purposes of reservoir surveillance to understand where oil comes from and how much and where water breakthrough occurs. The monitoring can be done through traditional technologies such as PLT and Geochemistry and innovative technologies such as Fiber Optic as Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS), Tracers and Advanced Logging (Spectral Noise Logging). Integration between different technologies could improve the reservoir knowledge. The aim of this paper is to show the possible benefits associated with the installation of downhole chemical tracers directly along the completion and integrated with the data coming from the other technologies. This can improve reservoir behavior monitoring, completion strategy verification and field management saving, at the same time, costs.

Abstract Eni is an international company that daily manages several different realities and contexts all over the world. The changing market challenges, as well as the proactivity and business integration in the HSE issues management, have led Eni to be one of the first companies to adopt HSE management systems certified at the various organizational and operational levels. Over time, the mature business management systems have been developed, driven by external changes (among which surely the international standards upgrading), but also through a growing awareness of the opportunities that are emerging in the management of HSE tools and sustainability as integrated parts of operations. With focus on some specific processes, in this paper we present through which tools the Eni HSE Integrated Management System (IMS) have become new and effective: Search for extensive approaches, involving the greatest number of resources and functions; Simplification and optimization of internal regulatory standards; Abatement of the barriers of businesses peculiarities. and how this approaches ensure consolidation and growth of sustainability values in Eni's activities. Introduction This paper will show the new systems introduced in Eni, for the following scopes: Context as a proactive opportunity; Risks and opportunities evaluation - review of risk assessment methodologies, which have introduced the logic and metrics for evaluating opportunities, in order to valorize the positive interventions on the organization; HSE commitment in the supply chain and green procurement; Internal control system redesign - to ensure a continuous verification process and a high frequency and effectiveness in the execution of internal audits on the HSE IMS, at all responsibility levels; Training, communication and transparency - to improve and higher level of awareness and competency of workers in relation to HSE and sustainability aspects. ENI AND THE HSE INTEGRATED MANAGEMENT SYSTEMS Eni adopted an homogeneous and shared HSE IMS, based on an HSE Management System Guideline (HSE MSG) and relevant internal standard, that gives foundamentals to all Business Units and subsidiaries of scheme for implementation of HSE management systems. For Eni Business Lines, as well as for Eni Subsidiaries, the HSE MSG defines the criteria and process for allocating in HSE risk clusters and the related obligations regarding the adoption of the whole HSE IMS, certifications and control activities.

Abstract Information obtained from 4D gravity and subsidence monitoring provides improved decision-making in the exploitation of offshore reservoirs. Field cases demonstrate the impact of this technology in the estimation of hydrocarbon volumes, the evaluation of risk of water breakthrough, understanding of drive mechanisms and identification of undrained compartments. The additional information provides increased hydrocarbon recovery in later phases of the projects, through the identification of infill-well targets or by the optimization of compression facilities. The cost of this technology, which is typically 10﹪ of that of 4D seismic, makes it feasible in a large range of offshore fields. The technology has been used in eight fields on the Norwegian continental shelf (NCS). 4D gravity is sensitive to changes in the mass distribution in the reservoir. Gas depletion and water influx from surrounding aquifers produce an observable time-lapse gravity signal. The observed signals are independent of seismic velocities, which makes this technology complementary to seismic monitoring. In addition, gravity provides a more precise quantification of mass changes than 4D seismic, and it can provide a better sensitivity to the movement of the gas-water contact. Seafloor subsidence is also sensitive to important reservoir and overburden properties. It is directly related to compartmentalization, and it can be a key factor for the safety of installations. It is an observable effect of geomechanical changes. Seafloor subsidence has been used to identify non-depleted compartments; determine the drilling-window for in-fill wells; understand aquifer properties; and improve the geomechanical model hence the interpretation of seismic time-shifts. In this abstract, we review the principles of the 4D gravity and subsidence monitoring technology. We then discuss some of the case studies from the NCS that illustrate the value these data provide for reservoir management. Finally, we discuss the main cost drivers of the technology, and which steps are taken by the industry to reduce cost and hence extend its feasibility to a wider range of fields. Introduction Optimizing hydrocarbon recovery in offshore hydrocarbon fields involves decisions involving costly investments, like drilling infill wells or installing compression facilities. A good understanding of the dynamical behaviour of the reservoir over the lifetime of the field is of key importance to support and reduce the risk related to such investments.

Abstract Seafloor subsidence is a matter of concern in areas with offshore hydrocarbon exploitations relatively close to the coast, like the central and northern Adriatic Sea. Traditional bathymetry methods provide sensitivities to seafloor deformations of the order of tenths of centimetres, which is often insufficient to determine subsidence patterns and rates. We propose a new, patented method for regional subsidence monitoring with an absolute accuracy of 2 to 5 millimetres, based on a technology developed for offshore reservoir monitoring. The method uses water pressure measurements as a starting point and reaches accuracies much better than pressure sensor specifications. The new method will allow distinguishing natural from anthropogenic subsidence in the Adriatic, and monitoring the extension of the anthropogenic subsidence bowls. The new measurements can cover the gap between the fine grid of land measurements and the sparse measurements obtained by GPS on offshore hydrocarbon platforms. In particular, the new information will allow to determine how close to the coastline the effects of hydrocarbon production extend. The method can also be used to enable accurate real-time subsidence monitoring in the area by using pressure sensors on the seabed. Regional subsidence monitoring can provide value to hydrocarbon exploitation itself. A good understanding of compaction processes is required for an optimal management of oil and gas reservoirs. Compaction depends on key properties of the reservoir like lateral compartmentalization and pore compressibility. In documented field cases, for instance, the analysis of subsidence patterns above producing fields have allowed to identify non-depleted compartments and have been used to identify target locations for infill wells. Introduction The context of the main Adriatic fields offshore is represented by young unconsolidated terrigenous sediments, where hydrocarbon production is likely to cause seafloor subsidence. The area features shallow water depths and a naturally subsiding sedimentary basin (Teatini et al., 2005). The coast presents large areas with elevations below 2 m above mean sea level. The Italian Adriatic coast features important natural sites and cities, including Venice and Ravenna. Italian authorities require that offshore development projects include a subsidence monitoring plan. ENI, the major operator in the area, has implemented a monitoring network since the beginning of the 90's (Dacome et al., 2015). The network includes onshore measurements with several technologies, and a network of 48 continuous GPS measurement stations placed on offshore platforms.

Abstract In many engineering projects, submarine gravity flows may represent one of the aspects that require geohazard assessment according to which mitigation measures have to be implemented. Numerical modelling represents the used methodology for the analysis of the turbidity currents and the quantification of their associated flow parameters. To this purpose, we developed a proprietary fully 3D forward modelling tool for modelling the complex hydrodynamic behavior of bipartite (dense and turbulent) gravity flows, as well as the associated depositional aspects. In particular, the presented 3D modelling approach is able to quantify near the route of a planned seafloor structures either sedimentation/erosion processes, and flow velocity variation through time, event duration, direction and water density. A case is shown to provide an example of simulations and results that were used to select the best monitoring tools locations, improving the installation phases. First of all, morphological analysis of the seabed was performed to identify the principal structures and the instability prone areas. Furthermore, slope stability simulations implemented on a selected profile allowed to define the initial sediment volumes to be used as input into the 3D forward modelling. Simulations were run on a high-resolution sea floor bathymetric map to test different flows and quantify the potential effects of their impact on the subsea facilities, allowing improvements on structures design. Beside the 3D analysis of the whole simulated event, velocity versus time and velocity versus depth diagrams allowed a detailed investigation of the potential effects of a bipartite gravity flow at specific locations, contributing to the selection of the proper installation layouts. When these simulations are performed during the early phase of a geo-hazard campaign, they can significantly contribute to the risks assessment and to the development project optimization. Introduction Deep-water canyons often represent preferential pathways for turbidity currents or debris flows and, in some cases, a pipeline route may include a canyon crossing. Gravity flows may travel at velocities up to 19 m/s and can maintain velocities up to 10 m/s on slopes as low as 0.2° (e.g. Piper et al., 1999; Talling, 2014). They can flow for long distances (>100 km) over several days duration, causing damage over large areas of the seafloor. Even less powerful flows (1-2 m/s) can potentially damage seafloor equipment, or break submarine telecommunication cables (Clare at al., 2015). The consequences of turbidity currents affecting seafloor structures depend on flow characteristics such as velocity, duration, direction of impact, density and capability to erode the seafloor. The ability to model properly the gravity flows, in order to evaluate the potential impacts against submarine facilities, represents a strong improvement in risk assessment. To this purpose, a 3D forward modelling tool was recently developed to reproduce the hydrodynamic behaviour of bipartite (dense and turbulent) gravity flows, as well as the associated deposits. We present here a case study along a submarine canyon hypothetically crossed by pipelines (Fig.1), where we tested gravity flows, either triggered by gravitational failures or associated to the downcurrent evolution from storm events affecting the shelf. In the former case, slope stability simulations implemented on a selected profile were used to define the initial sediment volumes representing an input into the 3D forward modelling. In the latter case, turbidity flows were assumed to feed continuously the canyon, from the canyon head, and allowed to propagate down the slope until reaching a quasisteady state.

Abstract Goal of this project is the development and realization of a software and hardware system for the in-situ movement reconstruction of a top-tensioned marine riser, an enabling technology that aims to improve the performance of the dynamic positioning system and of the BOP control system. During drilling processes a subsea riser is subject to external forcing due to vessel motion, subsea currents and internal forcing given by the mud flow in the riser and the drill head. Excessive riser vibrations may lead to structural damage and dangerous operative conditions. As a result, it is common practice to use a riser monitoring system which can estimate the riser state and communicate it to an on-board control unit to help engineers making the right decisions. Nonetheless, the riser state is currently computed by systems available on the market by using as unique inputs the upper and lower flex joint inclinometers and the telescopic joint stroke: the objective of this study has been to improve the reliability of state of the art systems by adding distributed measuring point on the riser string. The precise knowledge of the position of each riser joint allows the determination of the vessel location without relying on the currently used satellite or acoustic technologies. Furthermore, the subsea wireless communication integrated in the riser joints can be used as emergency or additional mux cable for the BOP control system to guarantee increased reliability of the BOP operations. The same technology can be used also to perform distributed measures along the riser string, such as the sea current at various water depth. Introduction The riser monitoring system proposed in this paper is organized into subsystems which implement the fundamental functions of sensing, raw data processing, communication, riser dynamic data processing and visualization. Fig 2 shows the system layout, whereas Fig 3 illustrates the main functions and correspondent subsystems. The system is characterized by a subsea assembly and a surface assembly. The subsea assembly is a chain of nodes (pods) installed inside the buoyancy modules wrapped around the riser segments. Each segment is equipped with a node close to the top flange and a second node close to the bottom flange. Each node comprises the electrical and optical devices to measure the local lateral linear accelerations and angular velocities of the riser and thermodynamic state variables of the node (namely temperature, pressure and humidity). The chain is designed such that the data collected by the nodes are sent to the surface assembly processing unit, which computes information on riser dynamic motion for the engineers. The data communication from each node up to the control unit is accomplished by transferring the data from the deepest node up to the vessel node by node. As the information moves upwards the data sampled by a node are added to the existing data flow and the overall size of the data package increases.

Abstract Obtaining a detailed description of the reservoir evolution is an essential step for several reasons. Among the most important ones, there are the estimation the reservoir efficiency and the estimation of some of its dynamic properties. The internal structure of reservoir rocks is traditionally investigated using thin sections that are prepared so that they represent the main geological units of the reservoir itself. At the optical and electron microscope, the thin sections (30 micron) allow for the recognition of the depositional and diagenetic features that are present in the sediments. Some of this information is conveyed through the pore types and their geometrical, morphological and appearance features. The type of the pores (e.g. primary or secondary) that can be found in the thin sections is related to their origin, the geological evolution of the rocks and of the reservoir itself. However, several millions of pores can be present in an image and technicians have done the pore classification manually for more than 20 years. Such an activity, therefore, is extremely time consuming. Moreover, the technician can insert some of her own subjectivity in the interpretation of the pore types. Therefore, we aim at overcoming the outlined criticalities by an automatic classification of the pore types present in the images gathered with a scanning electron microscope. This will allow for a faster interpretation of the classes of the pores in the images and an improved objective classification. We want to achieve the automatic classification of the pore types by using only the geometrical, morphological and some simple appearance features of the pores as extracted from the images. We use an unsupervised algorithm to cluster the pores and from the result obtained, the type of the pores themselves is inferred. Several different algorithms have been tested on images coming from sandstone and carbonate reservoirs. The results of the proposed workflow are promising.

Abstract Old ammunition or unexploded ordnance (UXO) poses a threat during the construction of oil and gas platforms and the installation of offshore pipelines. If UXO detection and clearance activities are executed erroneously, managed poorly or even overall omitted, UXO threaten the lives of construction workers, the construction schedule, the marine fauna and the public image of the involved parties The increase in knowledge about the potential UXO impacts has created an urge to address the challenge on a strategic level. Therefore, a "Quality Guideline for Offshore UXO Treatment" was developed. The quality guideline addresses the four phases (I) desk based Pre-Investigation, (II) Technical Investigation, (III) Investigation of Suspected UXO Sites and (IV) Clearance and Disposal of present UXO. For each of these phases a detailed work flow of processes was identified. The processes are characterized by the requirements and responsibilities of the stakeholders (clients, maritime surveyors, UXO specialists, consultants and public authorities), that are involved in UXO treatment. For the individual processes the prerequisites for involved personnel as well as requirements for reporting and documentation are laid out. The final chapter of the guideline is a comprehensive delineation 32 relevant technical and natural quality drivers, which serve as operating limits during offshore UXO operations. This paper outlines the need for high quality offshore UXO treatment in the Mediterranean, describes the generation of the quality guideline The final section describes the process of the Relocation of a Suspected UXO Site, which is an excerpt of the guideline. Introduction More than 70 years past the conclusion of the second world war submerged ammunition - commonly referred to as unexploded ordnance (UXO) – remains a global challenge. The problem has been growing steadily since 1870 and at an accelerated speed since World War I [1]. UXO was introduced to the sea during combat operations, such as air raids, mine laying and naval battles, but also due to dumping-activities, that occurred mainly after the conclusion of wars [2]. It presents an obstacle to the economic development offshore. When UXO has to be cleared, it is usually detonated on site or it is salvaged and subsequently disposed onshore [3].

Abstract The Adriatic Sea is scattered with steel platforms designed in the 70 /80's and most of these have already undergone a requalification process based on Structural Reliability Analysis (SRA). As they approach decommissioning, benefits from advanced analyses decrease dramatically and annual inspections might be required to satisfy engineering and statutory demands; yet most of the inspection campaigns carried out in the last decade depicted a very healthy scenario for the Adriatic Sea offshore portfolio with the only exception of very rare cases. The probabilistic approach to life extension can be enhanced by taking advantage of the progresses made in technology and data science over the last decades. The idea is to first collect inspection and monitoring data across fields, "brush" them into a standardised format, in order to create a baseline representative of the current status of the offshore portfolio, identify structural KPIs and categorise assets archetypes in different classes. In a second phase chosen structures would be subject to combined metocean and structural monitoring, in particular strain and stresses of critical connections, that would provide data for the training of a machine learning algorithm that would expose a direct cause effect relationship between environmental loading and structural performance. The information gathered would provide a valuable tool in the detection of anomalies and early indicators of structural degradation; furthermore an updated correlation model could be built on top of actual observations to extend structural warnings and considerations not just among the connections of the same structure but also between connections of similar structures. Advanced SHM techniques are becoming more valuable as new technologies become more accessible in a race to drive down operational and maintenance costs. Introduction The number of fixed platforms presently installed in the Adriatic Sea for oil or gas production nearing, or even exceeding, the end of their design life is increasing. Fixed steel offshore platforms are typically designed with a target service life in the range of 20-25 years; according to that target, the corrosion and the fatigue issues, as well as the strength assessment against extreme environmental loads, such as the 100-yr extreme wave loading, are properly addressed at design stage.

Abstract This paper introduces high-resolution acoustic borehole imaging as a new service available in logging-while-drilling (LWD). Borehole images (BHI) are an important part of the formation evaluation portfolio and contribute significantly to the understanding of subsurface structures and formation characteristics throughout the entire lifecycle of a field; from exploration, where BHIs yield detailed information about the depositional environments and the inferred depositional trends, to late field life where the accuracy of the estimated hydrocarbons in place are determined by the precision of the geological model. This information is crucial for the planning phase of new wells, determining recoverable reserves in place, analysis in production behaviour and a detailed understanding of the target formations. Acoustic images can also provide a detailed picture of the borehole shape that is used to reduce well construction and completions risk on a well and provides valuable geomechanical information. The new method is based on ultrasonic transducers that scan the borehole wall with acoustic signals, while the tool is rotating in the borehole. The tool sends a high frequency acoustic signal towards the wellbore wall and measures the travel-time and the amplitude of the returning signal. Each measurement is recorded with its azimuthal position and can therefore be used to create a borehole image. Whereas the amplitude image contains information about the scanned formation, the traveltime represents the borehole shape and can be converted into a distance when the borehole environmental conditions are known. Both images can be acquired while drilling or tripping (reaming/washing). Since the selected transducers are highly focused they can reveal small scale features such as fractures, cross-bedding and mud-cracks. The high acquisition frequency enables the tool to acquire high resolution images for almost any ROP/RPM combination and the physical acquisition method results in an independence of the used mud type. High resolution images significantly improve the understanding of reservoir architecture, presence and type of fractures or faults and are now available in WBM and OBM.

Abstract A successful ongoing cycle of optimization, unlocking opportunities and expanding development has enabled Western Desert fields not only to achieve production levels that assure asset value but also set the area on a growth path through expansion beyond original scope. The Western Desert is located between Libya-Egypt and the Agiba/IEOC production started in 1984. The historical and main producing oil formation is Bahareyia, a shallow reservoir composed of unconsolidated sand layers with gross thickness of 50 ft and oil density ranging from 30°-40° API. However, the deep reservoir targets have improved their contribution in the last years driven by successful exploration and the increase in gas treatment facilities. The peculiarity of play drove the distinctive exploration/reservoir synergy, which consists on near field appraisal with a time to market competitive with a standard development well in the Western Desert. Such approach allows continually discovering new resources and constantly renew/enlarge the field basket to sustain/enhance production. The tangible result reflects on a stable oil production over 30 years of history and its ramp-up in the last decade. In this framework, the Western Desert gas debottlenecking will be a key factor to fully exploit the deep reservoir potential. In order to accomplish such task new infilling and facilities upgradation would need to be taken into account. Introduction The paper want to present the peculiar exploration & reservoir approach aiming to unlock resource and the plan for gas debottlenecking. An overview of the recent deepening campaign is presented and afterwards an insight toughing the main future project foreseen in the Western Desert. 2018 DEEPENING CAMPAIGN In March 2018 a full wellbore revision was carried out for the Western Desert with the aim to identify new opportunity. The results of such analysis was the identification of an oil bearing level in AEB-IIIE & AEB-IIID in the central part of the field. The development plan started with the drilling of a new dedicated well targeting the area of interest. The exploration/reservoir intuition was confirmed by a well production exceeding 4'000 bopd. Afterwards, a screening of the entire existing well targeting shallow target in the zone was performed resulting in the identification of possible candidate for deepening.

ABSTRACT This paper presents a new technique to provide a quality controlled correlation of live oil spectroscopic data to the composition and PVT properties of the related petroleum. Fluid analytical data are obtained at the well-site using a high resolution spectrometer in combination with an advanced optical sample tank. This technique is of particular interest, since it analyses spectra from 400 to 2200 nm which covers the whole visible (VIS) and near-infrared (NIR) spectroscopic region for hydrocarbon description. The information contained in spectra is embedded in multiple absorption bands. Principal component analysis (PCA) and multivariate analysis (MVA) are performed on spectral data for correlation to the PVT properties of the petroleum. The reproducibility and repeatability of the analytical procedure will be illustrated on performed lab measurements whereas the benefits of the new technique will be discussed on first field applications from the Middle East. INTRODUCTION The accurate determination of crude oil physical and chemical properties is imperative to comprehensive reservoir characterization. In this context, various analytical techniques and data for oil and gas are routinely employed for correlation to physical oil characteristics. In particular, the pressure-volume-temperature ( PVT ) data for reservoir fluid behavior and properties are an important tool in reservoir performance calculations and the design of various stages of oilfield operations (Ahmed, 2007; Pederson et al., 2015). Understanding the phase behavior of petroleum in a reservoir for achieving optimal design and cost-effective production. Such pressure-volume-temperature (PVT) data for reservoir fluid behavior and properties are determined in certified laboratories on live oil and gas samples. The data are then delivered to the production and field developing companies in turnaround times of several weeks. Obtaining such data for PVT properties already while drilling or just after POOH provides important information on reservoir characteristics, such as compartmentalization, and local compositional variability of oil and gas to the client for early decision making. The provided data are essential for the reservoir and production management to mitigate operation risks, and to maximize production.

ABSTRACT Within the Oil&Gas activities, the Produced Water (PW) management is a key aspect to deal with. This study aims at identifying and testing a sequential methodology applicable to different offshore environments for the assessment of environmental effects associated to potential PW management solutions, such as injection, discharge into the sea, etc. For the quantification and comparison of the environmental pressures associated to the involved processes (drilling of injection wells, pumping, water treatment, discharge), a standard Life Cycle Assessment approach, in line with the ISO 14044, is implemented. Then an integrated approach is adopted to screen for the presence of biodiversity and ecosystem services (biodiversity screening), combining global and local datasets and scientific bibliography, in order to identify the significant receptors potentially occurring within the project area. In order to evaluate with a quali-quantitative approach the significance of the effects on receptors, a matrix approach is proposed, combining: the sensitivity of species and habitats to project pressures; the magnitude of the local pressures. Lastly, considering the potentially high significance of some effect, a further detailed modelling of a specific impact can be carried out. The result of the process shall be a complete and quantitative assessment of the best option for PW management, both from a global prospective (LCA considering processes and project peculiarities) and from a local prospective (focus on receptors through biodiversity impact assessment and dispersion modelling). INTRODUCTION This study aims at identifying and testing a Methodology for the assessment and comparison of the environmental effects associated to different solutions for the management of produced water (PW). The study is focused on a Gas Field project located offshore (about 200 km from coasts, see next figure), used as Pilot test for the application of the Methodology. Reinjection and discharge into the sea are the 2 options considered for PW management in such project. The present paper describes both: the methodology, applicable also to other environments and to other PW management options, such as transfer to an authorized site, reuse, etc.; the assumptions, inputs and results for the Pilot test project.

ABSTRACT Saipem has developed and is implementing for its fleet a Spill Risk Assessment and Oil and Chemical Mapping methodology aimed at creating for each vessel a comprehensive reference document containing the spill risk for the equipment on board and the conditions that may result in a spill to the environment. In this way appropriate mitigation measures can be chosen, prioritized and implemented more effectively. INTRODUCTION Saipem is ISO 14001 certified and it is rated in a number of environmental and sustainability indexes. Furthermore, the interest of Saipem's stakeholders in spill prevention and response continues to increase. For the last two years the Materiality Assessment conducted among both internal and external stakeholders showed that spill prevention and response is a very important topic on their agenda. To this end, Saipem is strongly committed to improve both ‘Prevention’ and ‘Preparedness’. To this end, Saipem introduced two activities for its vessels: the Spill Risk Assessment (SRA) and the associated Oil and Chemical Mapping (OCM). The process started already in 2016 when all vessels were required to produce a list and a mapping of the equipment and storage areas on board and continued in 2017 with the development of a detailed SRA methodology that is currently being deployed on all Saipem fleet. METHODOLOGY The SRA aims to evaluate the spill risk for the equipment on board Saipem vessels and the conditions that may result in a spill to the sea. This evaluation, which combines the experience of personnel on board with a rigorous and consistent methodical process assigns a risk level for every equipment on board in order to understand whether the risk is unacceptable, if any risk mitigation measures could be implemented and to choose / prioritize them appropriately. The process consists of three different steps: Identifying and listing all the equipment capable of generating spills of oil or of other substances hazardous to the environment: for each equipment several details were required, such as: name of equipment, location, name and quantity of oil / chemicals contained, existing barriers, etc. At a later stage, an additional set of parameters were required to be provided for each equipment, thus enabling the risk to be assessed by evaluating the: Probability of release , considering details such as: Wear and tear of the equipment (if equipment is subject to weather or possible impacts, the type of usage - e.g. often dragged across hard surfaces, the frequency of usage Frequency of the maintenance; Spill history of the equipment, and of other similar equipment in Saipem and in the Oil & Gas sector (if any); Condition of the equipment during the spill risk assessment inspection., etc.) Magnitude of the consequences for the environment, calculated based on: Evaluation of the maximum amount of substance that could be spilled from the equipment: quantity of substance contained, pressure of the equipment, response time before a spill could be stopped; Evaluation of how much of the substance spilled could affect the environment: spill barriers in place; Evaluation of the damage to the environment: toxicity for the environment of the substance spilled. Considering the risk level for each equipment, choosing the best prevention and mitigation measures.

ABSTRACT In recent years, the deep directional resistivity logging-while-drilling technology has enabled operators to take strategic geosteering decisions by mapping reservoir features before their intersection. As a result, the workflow to understand and update sub-surface structural information while-drilling is increasingly being practiced. A new service has recently been developed to meet the challenges of geosteering and reservoir mapping operations in slim hole environments. While conceptually based on existing larger tool size options, the new Reservoir Mapping-While-Drilling (RMWD) service involves innovative engineering adaptations to extend its capability to the 6-inch hole size. This technology and first application in Italy is presented in this paper. Downsizing this technology presents various challenges that require redesign of the transmitter and receivers in order to maintain high reliability, high measurement quality, and very deep depth of detection. For example, 50% less effective antenna areas negatively influence measurement quality and detection depth. Reducing the tool diameter enables handling higher dogleg severity (wellbore direction variations), however this also induces higher bending moments within the tools and creates more misalignment between transmitter and receivers. The new tool service overcomes the mentioned challenges and is capable to delineate multiple subsurface layers in real time with a robust inversion algorithm. The new Reservoir Mapping-While-Drilling (RMWD) service has been tested in Italy to increase production of a carbonate oil field. Faulted structural blocks and the presence of a potentially moved oil-water contact required a suitable technology that could help safely steer the wellbore close to the top of the formation without exiting or touching the sealing above. With seismic uncertainty, the plan was to use LWD high-resolution imaging and distance-to-boundary measurements to precisely describe the reservoir and interpret the complex structure setting for optimal well placement. An overview of the performance and results are presented in the paper. INTRODUCTION The geosteering world is an exciting environment, undergoing continuous innovations in both technology and interpretation solutions.