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ABSTRACT DP4 Platform in Bouri Oil field is located in the Offshore Libyan Mediterranean Sea and operated by Mellitah Oil and Gas B.V. Libyan Branch. The Platform Jacket was launched in 1987, protected against corrosion by galvanic cathodic protection system, constituted of slender cylindrical anodes made from aluminium-zinc-indium alloy. The design life of the CP system is 35 years. Owing to recent installation works of I and J tubes on the jacket, the removal of some anodes was foreseen in order to allow free space for the installation of clamps on bracing elements. For these reasons, an assessment of the protection status of the platform jacket with and without anodes removal was required. The aim of the assessment was to verify that protection conditions can still be achieved in all areas of the jacket, despite of the modification of the original galvanic anode system. Furthermore, with the platform approaching the end of its original design life, and the intent of the Operator to extend the life, it was fundamental that the actual protection status be established in order to ensure the integrity and durability of the structure. Investigation was carried out mainly with the use of Finite Element Method (FEM) modelling, applying various scenarios based on expected current density at different levels of cathode polarization and anode consumption. The model was also compared and validated through real CP inspection data collected during a recent inspection campaign after the installation of the "I" and "J" tubes. Results of the modelling confirmed that protection conditions are still being achieved all over the jacket structure, with minor variation of polarization. Consequently, installation of additional galvanic anodes in the modified regions was not necessary, leading to significant cost saving. INTRODUCTION Platform DP4 is located in Block NC 41 (Bouri Field) offshore Libya in the Mediterranean Sea, at a water depth of 169 m. It was launched in 1987. Jacket of the DP4 is protected against corrosion by galvanic cathodic protection system, comprising of 2,344 slender cylindrical anodes, made of aluminium zinc indium alloy with initial net mass of 600kg. The design life of the system at the time of 1987 was 35 years. New I-tube and J-tube have been installed in 2016 on the east side of the jacket of DP4 platform. For the fixing system, based on clamps, thirteen (13) existing galvanic anodes has been removed. The removal of 13 galvanic anodes in the zone where clamps of I/J-tube have been installed could result to a lack of protection current sources in that area, then less negative potentials, with simultaneous effect on the surrounding anodes, that shall provide protection current for a higher cathodic surface area.
- Europe (0.95)
- Africa > Middle East > Libya (0.25)
A Case Study of Pipeline Integrity Management in Greenstream Natural Gas Export Pipeline Through Corrosion Mitigation and Inspection Strategy
Ahmad, Iftikhar (Mellitah Oil & GAS B. V.) | Elshawesh, Fawzi (Mellitah Oil & GAS B. V.) | Sassi, Osama (Mellitah Oil & GAS B. V.) | Aburiah, Husaameddin (Mellitah Oil & GAS B. V.)
ABSTRACT The GreenStream pipeline is the longest underwater pipeline ever laid in the Mediterranean Sea. The primary objective of pipeline integrity management (PIM) is to maintain pipelines in a fit-for-service condition while extending their remaining life in the most reliable, safe and cost effective manner. The objective of a corrosion management plan is to define all necessary activities to assure the integrity of the pipelines by control of corrosion. This will ensure consistent availability and safe operation of the transmission pipelines throughout the specified design life. Under these circumstances, it has become crucial to manage operational risk through the use of effective technology and best practices for inspection and maintenance planning. This paper presents the experience of corrosion management of GreenStream pipeline through corrosion mitigation, corrosion monitoring and inspection strategy used in Mellitah Oil & Gas BV. External corrosion on GreenStream pipeline is controlled with a combination of coatings and cathodic protection while internal corrosion is controlled with a combination of chemical inhibitors, periodic cleaning, internal lining and process control. The monitoring and inspection techniques provide a way to measure the effectiveness of corrosion control systems and provide an early warning when changing conditions may be causing a corrosion problem. This paper describes corrosion management system used in Mellitah Oil & Gas BV for its natural gas export pipeline based on standard practices of corrosion mitigation and inspection. INTRODUCTION The GreenStream pipeline is an offshore pipeline laid in the Mediterranean Sea. It is 516 km long natural gas pipeline which has 32 inches diameter. It runs from Mellitah in Libya to Gela in Sicily, Italy. It was constructed with initial capacity of 8 billion cubic meters (bcm) of natural gas per year. Later the capacity of the pipeline was increased to 11 bcm. The pipeline parameters are given in Table -1. Maintaining pipeline in a safe and reliable condition is one of the major tasks for pipeline owners and operators. Assuring safety and reliability of a pipeline demands an integrated and efficient integrity management system. Pipeline integrity management is a process for assessing and mitigation pipeline risks in order to reduce both the likelihood and consequences of incidents. The U.S. Office of Pipeline Safety (OPS) has established a set of regulations impacting operators of hazardous liquids and natural gas transmission lines. Part of the mandate is the development of a comprehensive integrity management program to address ongoing pipeline safety. Other international references related to pipeline integrity management are:ASME B31.85 - 2012: Managing System Integrity of Gas Pipelines UK Pipelines Safety Regulations Pipeline Risk Management Manual - by Muhlbauer
- North America > United States (0.94)
- Africa > Middle East > Libya (0.24)
- Europe > Italy > Sicily (0.24)
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
Abstract Glass Reinforced Epoxy (GRE) resin is a well known and widely tested tubing lining system inside carbon steel tubing, that can be applied in production and water injection well as a cost effective alternative to high alloy materials. This paper presents the characteristics of the technology applied, a summary of laboratory testing including CO2 and H2S resistance, high flow direct impact and erosion results, the implications and recommendations to be considered during the installation, case histories and the feedback from the fields where it has been applied. The first of Eni's application of GRE lined tubing was done in 2005 in North Africa on production wells originally completed with Carbon Steel that were frequently prone to corrosion failures because of a high CO2 concentration and high water cut and subjected to costly work-over. Further field experience was achieved in another location in North Africa, with production tubing, which suffered frequent flow-induced corrosion, CO2 corrosion and sand abrasion failures. Another reported case is related to an installation in the Middle East, where the GRE lining has been run in two water injection wells, with cost saving in terms of Capex and Opex. Eight water injection wells completed with 7" and 4"1/2 tubing in the Norwegian Sector of the Barents Sea is the last field case discussed in this paper. Due to high corrosiveness of the injection fluid, raw seawater with antifouling chlorination, the lining technology has been applied as a cost effective alternative to high alloy materials. Feedback from the fields demonstrated that, when GRE resins are used within the operating limit, then this material represent's a valid option for the well life extension and offers a life cycle cost saving. Introduction A GRE lined pipe is the combination of two materials: a Carbon Steel tubing with a Glass Reinforced Epoxy internal liner, a composites material belonging to the group of Fibre Reinforced Plastics [1]. Carbon Steel guarantees the mechanical resistance of the system and the internal GRE liner assures the corrosion resistance. GRE has an outstanding corrosion resistance even in very aggressive environments.
- Africa > North Africa (0.45)
- Europe > Norway > Barents Sea (0.24)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract Eni started producing oil reserves from the Aquila reservoir in the Adriatic Sea after the discovery in 1981. As primary production decreased, a decision was made to start enhanced recovery with artificial gas lift. Located in deep waters (815 meters) and 46 km off the southern coast of Italy, a floating production, storage and offloading vessel (FPSO) was needed. As part of the production process scheme, the vessel needed to generate steam and electricity from the produced associated gas. Equipment was installed to remove hydrogen sulfide (H2S) from a combination of the oil stabilizer overhead vapors, the sour water stripper overhead vapors and, if required, a slip stream of the produced gas. The treated gas must meet an H2S specification of 100 parts per million vapor (ppmv) to provide stripping gas for the sour water stripper and meet post combustion emissions specifications from the steam boiler and turbine generator. The anticipated sulfur removal requirement was 2.3 metric tons per day (MTPD). Eni requested a process that would be economical while minimizing environmental impact, operator attention and logistical support. Following a detailed evaluation, the liquid redox process from Merichem Company (Merichem) was selected for the Aquila Phase II Project and installed as part of the topsides on the FPSO Firenze. After a five-year run (2013-2018), the FPSO Firenze has stopped production due to low oil production. This case study looks at the decision to use LO-CAT H2S removal technology (a liquid reduction-oxidation process), the cost of operation, and the unit availability over its' lifetime. Introduction As the energy industry searches for reserves in ever-deeper formations, there appears to be more sulfur with which to contend. Deep oil reservoirs in the Caspian Sea, Gulf of Mexico and offshore Brazil show significant amounts of H2S in the produced well fluids. H2S at low levels (just 100 ppmv) is a life-threatening, corrosive and flammable gas. Exploration and production of fields with significant H2S levels must be done under very strict safety precautions. Ultimately, disposal of the H2S must be designed into the production facilities. Several H2S removal technologies are available, including non-regenerative liquid scavengers (triazine-based), non-regenerative solid-bed absorbents and the regenerative liquid reduction-oxidation (redox) process. These technologies remove sulfur from associated gas streams and do not release them to the environment. The non-regenerative technologies are often referred to as scavengers. Process Evaluation
- North America > United States (0.25)
- North America > Mexico (0.25)
- Europe > Italy (0.25)
- South America > Brazil (0.24)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
Abstract Spoolable pipes are of great interest in O&G industry: they offer well-known advantages like high resistance to internal and external corrosion and low roughness, high fatigue resistance, reduced maintenance cost and improved flow rates. Another important advantage is the easy transportation and installation thanks to the capability of the pipe to be reeled in continuous sections of pipe, which allows reaching high installation rates, also because of their simplified yard: no X-ray, no welding, etc. In the last five years, breakthrough enhancement in Spoolable pipes performance (materials, manufacturing and quality control) have occurred. The Spoolable market is extremely vital as witnessed by the large number of actual suppliers; however, the different products own significant "different" performances in term of materials and applicability field such as max Pressure and Temperature. For this reason, before the application of these materials in demanding environments (HT, HP, sour service, deep water), a proper assessment is requested. This paper introduces the Eni installation of two Spoolable reinforced thermoplastic pipes at Zubair Field, South Iraq, and Aquila Field in Italy. The Zubair project started in 2011 when a new type of Reinforced Thermoplastic Pipe (RTP) was developed and available in the market, showing important advantages: the Aramid reinforcement allows a High Density Poly-Ethylene (HDPE) pipe to reach working pressures around 72 bar. Onshore Zubair Field is characterized by high corrosivity of crude oil and injection water, salty soil and need for fast installation. The Spoolable pipes were selected for the water disposal pipelines construction. The installation phase highlights the main criticalities and advantages given by the Spoolable pipe. The second case is the installation of two RTPs at Aquila Field, offshore Adriatic Sea. They are two lines in 850m water depth, used in two sour gas wells. This pipe is made with PEEK polymeric material, reinforced with carbon and glass fibers. The positive results given by this technology allows to consider RTPs also for other applications as oil production flowlines, both onshore and offshore, once the material compatibility with operating limits is verified. Introduction Carbon steel is the construction material most widely used for pipelines. However, steel pipelines have a number of limitations, such as low corrosion resistance, relatively high weight and costs. In the 60s-70s, non-metallics were introduced as pipeline materials to avoid corrosion issue and have been utilized for low pressure onshore gas distribution network.
- Asia > Middle East > Iraq > Basra Governorate (0.56)
- Europe > Italy > Adriatic Sea (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.50)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Europe > Italy > Adriatic Sea > Adriatic Basin > Aquila Field (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.99)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
Abstract Insulation systems should not only be able to minimize the heat exchange with the ambient, but also withstand the operational conditions during its service life. Pipelines operating in hot service are often bound to Flow Assurance problems requiring both, passive insulation and active heating. An optimization study for the integration of a full coating system and a heat tracing system was conducted through the execution of a full scale test. The test consisted in subjecting the samples to heat-up and maintain stages, as well as cool down cycles which involved the recording of temperatures and power input. Pipelines operating in cryogenic conditions require passive insulation systems able prevent thermal bridges at any of their components, and to withstand extreme contractions / expansions whenever a thermal cycle occur. A pipeline section, coated with polyurethane foam (PUF) insulation, was installed in dedicated area and a fit-for purpose testing facility was designed and erected for such purpose. The pipeline section was subjected to several thermal cycles, from cryogenic to ambient temperature, to verify its fitness for such service. Pipelines for cold or hot service require monitoring systems, which have to be integrated with insulation systems. Such devices have been used in the experiments mentioned above. This paper will discuss our recent experience with well-established insulations systems that extended its field of use to LNG (-163°C) and molten Sulphur (+180°C) pipelines, acting as a key enablers for the integration of additional valued added components, like heat tracing and monitoring systems. Introduction A well established insulation technology like PUF, has the capability of getting solidly integrated with other coating technologies, like for example anticorrosion coatings. Such capability is instrumental for the development of cost effective solutions able to extend its field of application and compete against other methods and materials normally used in such field. One of the goals was to extend the service temperature range suitability. In the hot service, the challenge was to design, select and ensure that all coating system components area able to withstand higher temperatures and are also able to integrate heating systems that are often associated to such services. In the cold (cryogenic) service, the challenge was to verify the robustness and compactness.
ABSTRACT The presence of contaminant gases in new discoveries is becoming more and more common and among these gases hydrogen sulfide (H2S) is the most frequent. H2S detection, together with the identification of formations and well intervals bearing it, is crucial for Oil Companies, since it heavily impacts completion strategies and field development. For many years, inorganic scavengers were used and through mud acidification it was possible to release H2S and to get an evaluation of its concentration. Nowadays, the use of organic scavengers which bound irreversibly to H2S, makes impossible its detection and hinders all the information regarding well sourness. In the current paper we present a novel methodology which aims to overcome this problem by core/cutting analyses. Methodology development started from the hypothesis that part of the formation gas is still preserved in cutting pores. Experimental evidences, collected in the last few decades, show that gas (hydrocarbons and contaminant gases, including H2S) is mostly released by the rocks while drilling into mud (so-called mud gas); nevertheless, some further gas can be released by cuttings e.g. in sealed vials (so-called head space gas) and, finally, a last portion is still preserved in cuttings. Our experimental approach implies the analysis of this last portion, also called interstitial or residual gas, that can be recovered by grinding the cuttings in a sealed mill, gas recovery from the gastight chamber and its analysis by GC-TCD detector. It must be highlighted that the obtained H2S concentration value is not only depending on its abundance but also on many other concurring factors which are difficult to precisely evaluate and quantify, such as rock permeability, sample preservation and treatment and rock-gas interactions. Therefore, the detected concentrations cannot be interpreted on a strict quantitative basis, but they still give us an important indication of H2S presence and of its relative abundance. Analyses of samples of ditch cuttings, stored for years, pointed out that this methodology is applicable not only for fresh samples. Case histories will support the presented methodology and shed light about the potentialities of such analysis kind.
- Asia > Middle East (0.28)
- North America > United States (0.28)
- Geology > Mineral (0.92)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Kazakhstan > Atyrau Oblast > Caspian Sea > Precaspian Basin > Kashagan Field (0.99)
Improving Hybrid-Solvent Formulations for Energy Efficiency and Optimal Gas Treating
Langé, Stefano (TOTAL SA) | Zhao, Jing (TOTAL SA) | Cadours, Renaud (TOTAL SA) | Weiss, Claire (TOTAL SA) | Layeillon, Lise (SOBEGI Induslacq) | Bernadet, Mikael (SOBEGI Induslacq) | Caetano, Michel (SOBEGI Induslacq) | Pottier, Fabien (SOBEGI Induslacq)
ABSTRACT The exploitation of gas reserves with significant amounts of sulphur together with the tightening of commercial specifications for these compounds represents a tough challenge for operating companies. Considering the current energy scenario and the natural gas market, more efficient gas processing solutions are needed to allow the profitable commercialization of these sour gas reserves. Energy efficiency and optimal production are two strongly linked constraints for operating companies. Chemical absorption processes based on aqueous alkanolamines solvents have been widely adopted industrially to remove CO2 and H2S from natural gas. However, these solvents show limited mercaptans removal capacity. This drawback affects the overall gas processing economics due to the need for supplementary removal steps. To face this challenge, TOTAL has put efforts over the last decades to develop a new series of hybrid solvents able to remove, in a one-step operation, CO2, H2S and mercaptans, improving process performances without plant modification. The last developed formulation is based on a blend of MethylDiEthanolamine and Piperazine (MDEA+PZ), allowing to couple the good chemical stability of MDEA and the high performance of PZ as an activator. Without plant modification, this new formulation has been implemented in the SOBEGI industrial sweetening unit at the Lacq site (France). This new solvent has allowed to decrease the reboiler duty of the solvent regeneration, to reduce chemicals consumption, while keeping the final product quality unchanged. This paper describes the benefits when operating acid gas removal units with hybrid solvents. The operational feedback recorded at SOBEGI plant are presented. The benefits of using this new hybrid solvent formulation are supported by operating data collected on the plant. INTRODUCTION The exploitation of sour gas reserves coupled with the tightening on sulphur compounds specifications in natural gas products and the increasing trend of the global natural gas demand represent a serious challenge for operating companies. Estimations reveal that about 40% of the global remaining natural gas reserves contain acidic compounds, such as H2S, CO2, COS and mercaptans. Considering this scenario it is evident the strategic importance of natural gas sweetening for sales gas or LNG production, pointing out the need of improved and more efficient process solutions.
- North America > United States (0.69)
- Europe (0.48)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.18)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- (2 more...)
Abstract The effectiveness of poly (2-acrylamido-2-methylpropane sulfonic acid) (PAMPS) and copolymers with acrylic acid (AA) and acrylamide (AM) magnetic nanogels as protective corrosion of CS in reaction with water by (EIS), (EFM) and tafel polarization method. Polarization method demonstrated that all the polymers are mixed inhibitor type. (EIS) Electrochemical impedance given that the attendance of these investigated polymers declines the double layer capacitance and improvement the charge transfer resistance. The polymers adsorption on surface of steel was follow isotherm Temkin. The morphology of the CS surface was examining by (EDX) energy dispersive X-ray and (SEM) scanning electron microscope. The data obtain showed improvement in efficiencies for inhibition with raising the dose of inhibitor. Introduction CS is the common regularly utilized pipeline materials as a part of petroleum creation. In any case, it is exceptionally inclined to corrosion in environments include sulphur [1]. Corrosion of sulfur has been one of the corrosion sorts in gas/oil manufacture, offering ascend to the pipelines failure and equipment's and utilized in biggest economic reduction and accidents. Likewise, spillage of raw petroleum because of endures consumption of pipelines would actuate fire accident, and natural contamination [2-4]. Explored to comprehend its mechanism, decrease the corrosion rate, additionally create experimental models to survey and foresee the parametric effects and the states-of the-art of internal corrosion of pipelines [5-12]. Theoretical approaches provide means of experimental of these reactions and there are many reports connection with this area [13]. Last papers have study the connection between the efficiency and structure of the inhibitor molecule, but low attention has been paid to the reliance of the protection efficiency on the size and electronic distribution of the protective molecule, Relation between chemical structure and inhibition efficiency was not research, The super paramagnetic Fe3O4 nanoparticles covered with polymers are usually connected to the magnetic cores to ensure a strong magnetic [14]. Attractive nanogels of regular interest are ferromagnetic magnetite (Fe3O4) covered with cross-connected polymer nanogels. The Fe3O4 center has solid attractive characteristic and super paramagnetic conduct, is of generally declines danger to the human body when epitomized in the defensive shell of polymer, which is cross-connected hydrogels polymer. The shell keeps the Fe3O4 center from total oxidation. In this appreciation, the utilizing of nanogels particles as a part of the field of consumption hindrance insurance for steel rather than ordinary natural inhibitors can deliver uniform flimsy film (with no pine opening because of cross-connected polymers) on the surface of CS to coat all surface with no deformities which give focal points over typical natural inhibitors. A few strategies have been produced to get ready attractive miniaturized scale and nanogels, for example, reverse microemulsion polymerization and emulsion polymerization [15-18]. The target of this paper is to calculation the inhibitive effect of these polymers on carbon steel in formation water by various electrochemical methods.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.74)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (0.69)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.69)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.48)
Prediction and Prescription of Operation Upset in H2S Gas Sweetening Unit: Implementation of an Innovative Big Data Analytics Procedure
Cadei, L. (Eni SpA Upstream and Technical Services) | Camarda, G. (Eni SpA Upstream and Technical Services) | Montini, M. (Eni SpA Upstream and Technical Services) | Rossi, G. (Eni SpA Upstream and Technical Services) | Fier, P. (Eni SpA Upstream and Technical Services) | Bianco, A. (Eni SpA Upstream and Technical Services) | Lancia, L. (Eni SpA Support Function and Continuous Improvement) | Loffreno, D. (Eni SpA Support Function and Continuous Improvement) | Corneo, A. (Eni SpA Support Function and Continuous Improvement) | Milana, D. (Eni SpA Support Function and Continuous Improvement) | Carrettoni, M. (Eni SpA Support Function and Continuous Improvement) | Silvestri, G. (Eni SpA Support Function and Continuous Improvement)
ABSTRACT This paper highlights the development and results of a machine-learning based end-to-end system for process upset and hazard events prediction in gas-sweetening procedures; this tool has been applied to production operations of an oil-and-gas field. High H2S concentration in the produced gas represents a serious issue due to its environmental impact, the impossibility to deliver acid gas to the distribution network and the asset deterioration. The proposed tool monitors the status of the equipment in near real-time. Whereby an alarm is raised, prescriptive information is provided to avoid, or mitigate, operational issues. This can be accomplished by using machine learning algorithms and data mining techniques in a Big Data Infrastructure. In the illustrated case, a complex data-lake was built by ingesting and aggregating in a Big Data Environment times-series data from field sensor network, maintenance reports and chemical analyses. A machine learning algorithm has been trained to identify faults in the gas-sweetening unit resulting in a high concentration of H2S in the processed gas. The development of the tool has been conducted in collaboration with site engineers and operators to identify the most relevant data sources describing the process and to validate the algorithm outputs. Several machine learning algorithms have been tested (Deep Learning, Random Forest, Gradient Boosting Trees) to improve model accuracy and clarify the interpretation of the phenomenon root causes. Finally, the tool is now fed with real-time data and predicts hazardous events in near real-time. The alerts raised by the system are stored and archived in the Big Data Environment for further analysis. Field operators and process engineers can therefore access those new insights, and the related data, using the tools already in use during the daily monitoring operations. Alongside, a dedicated visualization tool was designed to monitor the model performances and guarantee its life-cycle. The innovative characteristics of the tool lay in its ability to exploit the huge amount of field-data and to simulate complex phenomena through Big Data Analytics. It is now possible for the site operators to receive preventive warnings on relevant events, gather information on the possible root causes and on the recommended actions to prepare for the upcoming event. Ultimately, this framework allows to insure the constant flow of the gas into the distribution network, to avoid or mitigate halts in production and to guarantee asset integrity.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- Information Technology > Data Science > Data Mining > Big Data (1.00)
- Information Technology > Artificial Intelligence > Machine Learning (1.00)