Throughout the world, there are lots of local projects containing large amounts of freely available vintage seismic data. Differently from modern survey techniques, in which data are collected, processed and stored digitally, these vintage data are currently available only as scanned paper sections. Such a large amount of data can be very useful not only for scientific purpose, but also for the oil industry when other kind of data are not available. However, in the actual digitized form, vintage data do not show their full potential: in most cases, they represent only stacked seismic sections, with some additional noise derived from the vectorization process, and therefore they show a poor final quality. The enhancement of scanned vintage seismic data is presented as workflow, that involves a digitalization process and a processing path in a Seismic Un*x environment. The digitalization process is an essential procedure, because it converts the scanned section in a readable seismic format, the seismic standard SEG-Y, through a series of steps that implies image enhancement and rectification and a georeferencing procedure to assign the shotpoint coordinates. The processing sequence, instead, is the core of the quality enhancement procedure, with well-defined steps that remove the noise related to the digitalization process through filtering and allow to efficiently improve the seismic data by applying a post-stack migration. Furthermore, this is achieved employing only open source and/or freely available software.
A real data example is presented, using marine seismic lines coupled with well data from the ViDEPI project of Italian Geological Society (SGI) in collaboration with Italian Ministry of Economic Development and Assomineraria (Italian petroleum and mining industry association).
The first seismic experiment was performed in the early 1920s, when a team of geologists and physicists recorded seismic waves that had travelled through earth, making use of a dynamite charge as source and a seismograph as a recorder; but was only during the 1930s that reflection seismic was worldwide accepted as a proven method for hydrocarbon exploration.
Front End Engineering Design (FEED) has been stuck in the same workflow paradigm for decades. Recent developments have created new process simulation software that allows multiple global users to collaborate at the within the same model at the same time. This leads to brand new paradigm in FEED. At Schneider Electric we are calling this new paradigm “Simulation Driven Engineering.” This new FEED process uses the actual process simulation as the repository for all of the design information and utilizes the collaboration capability to enable multiple engineering departments to work on their part of the simulation when they need to. The typical FEED process follows the plant lifecycle below, is sequential, and currently uses separate modelling tools for each major step in the plant lifecycle. The new paradigm uses a single simulation platform as a single common point for the entire FEED process. This presentation will detail how Schneider Electric’s “Simulation Driven Engineering” will revolutionize the process engineering, operator training, and optimization.
The typical paradigm within process simulation software is for only one person to have access to a given simulation at any one time. That paradigm is inherently limiting in that typically you need several different people to work on the same simulation, sometimes in different areas, as part of the engineering design lifecycle. This creates all sorts of time delays and potential issues in making sure that the final simulation incorporates feedback and changes from various departments. It is clear that industry requires simulation software to be more collaborative than it is now.
That paradigm is currently shifting! Schneider Electric built SimSci SimCentral by Schneider Electric was built from the ground up with collaboration capabilities. Multiple users can work on the same, shared simulation simultaneously. Not only can people in the same office work on the same model, people spanning the globe can access and work on the same model at the same time or sequentially. SimCentral promotes collaboration with access to the same simulation on multiple applications and devices, and by multiple users.
Agate, G. (Ricerca sul Sistema Energetico - RSE S.p.A. ) | Colucci, F. (Ricerca sul Sistema Energetico - RSE S.p.A. ) | Guandalini, R. (Ricerca sul Sistema Energetico - RSE S.p.A. ) | Moia, F. (Ricerca sul Sistema Energetico - RSE S.p.A. ) | Pagotto, R. (Università degli studi di Milano - Bicocca) | Crosta, G. B. (Università degli studi di Milano - Bicocca)
The natural gas storage in underground structures, known as geological reservoirs, plays a key role in the Italian energy system. The gas storage satisfies several needs such as responding to the gas market demands, ensuring wide margins in the management of production facilities and transport nets and ensuring the maintenance of strategic reserves that are used exclusively to deal with exceptional situations.
The numerical modeling is the only approach that allows preliminary analyses of operating scenarios and the assessment of the safety requirements connected to industrial process related to the natural gas production and storage. The methodology developed in order to characterize gas storage sites and to simulate the related fluid dynamic behaviours was documented by a test case application focused on the Sergnano site, located in Lombardia Region (Italy). The methodology pointed out for the site characterization includes the geological information collection, the creation of a static geological model and then the realization of a corresponding 3D fluid dynamic model. In the shown case, the geological reservoir is located in the conglomerate formation known as Sergnano Gravel while the caprock is identified in the overlying clay formation known as Santerno Clay. For this site, an accurate 3D numerical model, including geological and spatial discretisation, has been realized using GeoSIAM software system which allows to simulate the original conditions of the reservoir at the time of the discovery and to reproduce the industrial storage process, also taking into account the effect of the natural gas production and storage cycles on the geological structure. The results confirmed the goodness of the methodology based on the GeoSIAM system in terms of accuracy and reliability and its fundamental role to support sustainability analyses of geological gas storage.
The natural gas geological storage is a process that consists in re-injecting gas into the porous rock of a depleted reservoir that originally already contained it, with the goal of withdrawing it on demand. Each storage field is characterized by two quantities as the working gas, that is the volume of natural gas that can be withdrawn or injected according to the market demand, and the cushion gas, that is the volume of gas that must be always in site in order to maintain an adequate minimum operating pressure.
Signorini, A. (Infibra Technologies) | Nannipieri, T. (Infibra Technologies) | Di Pasquale, F. (Scuola Superiore Sant'Anna and Infibra Technologies) | Gaudiuso, G. (GE Oil & Gas Nuovo Pignone) | Girezzi, G. (GE Oil & Gas Nuovo Pignone)
In this paper, we present a field test of temperature sensors, based on arrays of Fiber Bragg Gratings (FBG), on a co-generation steam turbine operating at the GE Oil&Gas Nuovo Pignone facility in Florence. This unit has been upgraded with new components and high efficiency stages designed by GE technicians over the last years, providing the opportunity to test and validate the FBGs sensors for temperature measurements.
Two different kind of FBGs, packaged in flexible and rigid loose tubes of stainless steel AISI 304, have been developed and adapted to Oil&Gas requirements from INFIBRA TECHNOLOGIES, following GE technicians’ expertise; the temperature distribution in 44 different sensing points has been acquired, along the thickness and the surface of the turbine casing, with only 5 fiber optic acquisition channels for an extended temperature measurement range up to 500 °C.
Accurate static and dynamic temperature measurements are fundamental for operation and control of turbomachinery. Current technologies, based on thermocouples or thermo resistances, are characterized by bulky packaging and massive wiring requirements; in addition, a dedicated thermo element is needed for each acquisition point, limiting their use to a few discrete sensing points. Fiber Bragg Grating (FBG) sensors are extremely attractive for temperature measurements due to their compactness, light weight, immunity to electromagnetic interference and multiplexing capabilities in time and frequency domains. A single array of FBG sensors allows for multipoint static and dynamic high temperature measurements in harsh and hazardous environments like those of turbomachinery systems.
This paper describes in detail a novel temperature monitoring system, permanently tested for more than 3 months on a steam turbine in operation, fully demonstrating the advantages of fiber optic sensors, including the compliance with ATEX directive for operation in environment with an explosive atmosphere. The acquired data are used for thermal model validation and for optimizing the start-up, shut-down and load variations of the turbine during operation, pointing out the attention of GE Oil&Gas to address new market requirements.
Danovaro, R. (Polytechnic University of Marche, Italy and Stazione Zoologica Anton Dohrn, Naples) | Barone, G. (Polytechnic University of Marche, Italy) | Carugati, L. (Polytechnic University of Marche, Italy) | Lo Martire, M. (Polytechnic University of Marche, Italy) | Dell'Anno, A. (Polytechnic University of Marche, Italy) | Corinaldesi, C. (Polytechnic University of Marche, Italy)
Vast marine areas still require an extensive exploration prior the onset of any industrial extractive activity and some areas could be degraded due to the intense exploitation activities. The exploration of the seafloor for the exploitation of natural resources is increasing the global concerns for the potential detrimental consequences and there is an urgent need of developing eco-sustainable tools and approaches for better environmental monitoring. New monitoring protocols and technologies are becoming available for the assessment of the status and, eventually, habitat restoration of degraded habitats. In order to cope with the large heterogeneity of seafloor ecosystems, the current marine monitoring needs to be enforced either in temporal and spatial scales. According to the ecosystem-based approach and the Marine Strategy Framework Directive (MSFD), organisms and ecosystems should be at the centre of marine management strategies, which requires the achievement of a good environmental status either in coastal and deep-sea ecosystems. The new spatial-temporal monitoring strategy should be based on the best available technologies including mobile platforms, autonomous vehicles, and animal-mediated data acquirement, enabling an adaptive and extensive monitoring of marine ecosystems. Established protocols for the biologically-based monitoring should be based on the availability of essential environmental and ecological variables able to identify criteria for the sustainable exploitation of vulnerable marine ecosystems. Here we present an analysis of the essential variables that will allow the implementation of the Marine Strategy for the development of a new eco-sustainable blue-based economy able also to identify the criteria to assess the restoration/recovery of degraded habitats.
Leadership in Health & Safety – Driving Cultural Change in an Offshore Fleet
Maintaining a strong culture of safety presents numerous challenges to the leaders that operate within our organization.
This paper will demonstrate the methodology that is employed in the assessment, planning and execution of our Leadership in Health and Safety program within our offshore business unit in order to maximize the positive effects of cultural change.
Since its launch in 2007 Saipem’s Leadership in Health & Safety program became truly embedded in the organisations DNA, within daily actions and decisions, and the unseen mind-set triggering this. We have achieved a unified vision of a single safety culture through continuous engagement with our offshore vessel management teams & supervisory personnel. We have developed these key roles to be true safety leaders and to further disseminate our safety culture to the people within their sphere of influence.
Our cultural safety training programme is tailored to accurately meet the demanding needs of the population and collaborative training events are undertaken in order to cross pollinate concepts and ideas and the release of multiple ‘phases’ ensures the change process is nurtured and remains omnipresent.
Staggering improvements are evident in terms of organisational safety performance, a very definite year-on-year accident frequency reduction totalling over 50% since the LiHS process was launched, whilst proactive safety observations increased by 70%. Organisational locations where the program implementation was poorly communicated (mainly due to local commitment), sees these positive results lagging. A strong correlation exists between sharp increases in proactive safety observation, with launching of new phases. Reporting gradually decreases over several months, and again spikes with in line with new phase releases. The change process is still ongoing, and constant feeding is critical to ensure high levels of visibility is maintained.
Tempa Rossa is an oil field within Gorgoglione Concession in Basilicata region, Italy, discovered in 1989. Lying more than 4,000 meters beneath the surface, the field is planned to be produced with height wells. One of six existing well has a total depth around 7145mMD, and another well has a horizontal drain around 600m.
Dual Boosting ESP system is the selected solution to deliver 10 000 blpd per well as production target rate. The ESP and completion string were designed considering the limited size of production casing, the high stresses (tubing movement, tension, weight, pressure) and the corrosive environment from the oil characteristics. According to the casing size, two completion designs were created to deploy the dual boost system (type A for 9-5/8” production casing and type B for 7-5/8” casing).
The ESPs can be operated as single, back-up system, or as dual boost system. For the first production years, the ESP will be used in back up mode, thanks to high reservoir pressure, and then subsequently with declining reservoir pressure, the dual boost system will be operated to maintain the required flow.
A Work-Over campaign started in March 2016 with the objective to equip the six existing wells with new upper Dual ESP completion in anticipation of the first oil. Under abstract submission’s date, four of the six Tempa Rossa wells have been equipped with Dual ESP completion: three type A and one type B. Significant improvements in running performances have already been observed thanks to the dedicated operation follow-up.
A post ESP installation data monitoring has been put in place, thru a dashboard, to allow the detection of potential early failure of the Dual ESP system during the idle period until production start-up. Operation follow-up and data monitoring are key factors to minimize the probability of ESP failure prior to the first oil. Mitigation measures for ESP preservation during long period play a key role to accomplish first oil and planned ramp-up in due time.
The objective of this paper is to describe the first application of three unique chemical tracer technologies in the optimization process of a field development in the Black Sea offshore Romania. These technologies helped in the understanding of fluid flow, fracture effectiveness, and completion design. The paper describes the methodology employed and the results obtained from the combined application of water tracers, oil tracers, and gas tracers in one multistage hydraulically fractured well. Additionally, the tracer design, operational logistics, operational lessons learned, results interpretation, and application of the results in order to improve subsequent completions will also be discussed. Clear correlations were seen between the results of all three tracers, which were in turn compared to production and treatment data, further confirming the value of diagnostic technology. The importance of adequate sampling and offshore operational limitations were identified and resolved. Results from a planned, but due to tracer results, not executed water shutoff of high watercut zones are presented. The results were applied to future completion designs and decision-making processes. This case study is an inside look at the first-ever combined application of oil, water, and gas tracers in an offshore hydraulically fractured well development in Europe. It will discuss how the results from using all three chemical tracer technologies, coupled with additional data sets while applying a synergistic interaction between teams, can be highly leveraged to understand current completions designs and optimize future developments.
The applications of tracers can be tied to most disciplines in the oilfield; from drilling to secondary and tertiary recovery. The focus of this paper is in the application of chemical tracers to completion diagnostics and optimization, and in particular, to multistage fracturing operations offshore.
In the multistage fracturing application of tracer technology, there are mainly three sub-categories of chemical tracers: tracers for the gas phase of hydrocarbons, the liquid phases of hydrocarbons, and tracers for the water-based completion fluids. The presented project utilized all three tracer types at the same time.
Gouda, G. (Eni Egypt) | Kaja, M. (Eni Egypt) | Abdel Fattah, S. (Petrobel) | Shaker, E. (Petrobel) | Abd ElHakim, W. (Petrobel) | Korany, M. (Petrobel) | Samir, E. (Schlumberger) | Metwally, A. (Schlumberger)
Abu Rudeis Field is considered one of the oldest oil fields in the Gulf of Suez, Egypt, producing since 1957. Most of the oil production comes from the Nukhul sand, which resulted in the depletion of this zone. The depletion of the Nukhul sand creates a challenge for the drilling engineering in terms of the optimum well design and the drilling methodology to implement, which would help reduce the drilling costs and ensures smooth drilling operation for early production. The focus of this paper will be on the ARM block in the Abu Rudeis Field where recent field studies has shown that better production rates can be achieved from drilling horizontal wells as compared to drilling deviated wells. Four horizontal wells were drilled in the ARM block and for all four wells; a pilot hole was drilled in order to determine the unconformable top of Nukhul Sand Formation. The pilot holes that were used to determine the sand top was then plugged and abandoned and side-tracks were drilled for a build-up section whose casing point selection was made based on the pilot hole data. Failure to set casing at the top of the reservoir sand would result in complete mud circulation losses due to the difference in pore pressure between the depleted sand and the pressurized shale above it. The analysis of the nonproductive time including the pilot hole cost, the sticking pipe risk and the possible oil based mud losses ranged +/- 1.8 M$.
This paper highlights the engineering solution and the technology usage of the first reservoir mapping while drilling service in Egypt to land a horizontal well with proactive detection of the casing point in order to eliminate the nonproductive time associated with drilling pilot holes. The main objective is to continue drilling more horizontal wells in order to increase the oil production from the field.
In order to minimize risk of fatigue failure of pipes and other structural components, a subsea condition monitoring or inspection tool may be required to keep production at a safe level. Reliable and efficient condition monitoring solutions are increasingly important as a growing body of production and processing assets are moved subsea. This paper will illustrate the use of an efficient condition monitoring system that can also be used for one-shot inspection, with smart installation method and data retrieval solution – as well as data from a field case.
Vibration monitoring can be performed using clamp-on and retrofit instrumentation and even included in instruments that also perform other tasks such as particle monitoring, leak detection, or corrosion/erosion monitoring. The combination of vibrometry and passive acoustic noise detection at ultrasonic frequencies holds an interesting potential for condition monitoring of critical equipment.
The subsea sensors can either be installed as permanent on-line condition monitors, or deployed at intervals to detect changes over time in vibrational and acoustic signatures. The latter is of particular interest in cases where provision of power and communication for retrofit instrumentation is costly, and where data from great numbers of inspection points are desirable.
Subsea testing of a vibration inspection concept is carried out early 2013, using battery operated instruments in combination with a novel quick-mount solution for ROV deployment on subsea structures. The instrumentation is placed in standard ROV buckets at measurement points of interest and left at each position for a period of choice, ranging from hours to months. Returning to the same site, vibration and noise measurements can be compared to records from earlier inspections. The concept, preliminary results, and further possibilities for reliable and efficient condition monitoring and inspection are presented.
INTRODUCTION Statistics tells us that 21% of all topside pipework failure in the UK sector is due to vibration-induced fatigue, whilst erosion and corrosion stands for 13% (Figure 1). This is not directly comparable with the subsea world. Still, we now know that aging subsea pipework and structures suffer from fatigue, in many cases caused by vibration. The number one cause of vibration-induced fatigue is flow line induced vibration (FIV). Advanced simulation and modelling are often used when designing subsea structures and subsea pipework to ensure that the design minimizes the risk of harmful vibration occurring. Simulation and modelling have become very accurate but does not always fully reflect real conditions due to the complexity of the pipework in combination with the unpredictability of multiphase flow regimes. Therefore, these models are usually quite conservative, with a significant safety margin built in. In some cases, this may lead to a “permitted production rate” that is less than is safely possible. Installation of permanent or temporary vibration monitoring is the only way to be sure what the actual state is. Data from instrumentation is valuable for several reasons.