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 1 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 2 UK Pipelines Safety Regulations 3 Pipeline Risk Management Manual - by Muhlbauer 4

ABSTRACT Nowadays most of the Oil and Gas Companies, in view of a project for the exploitation of a new shallow water oilfield, are considering to reuse existing offshore structures removed from previous service site. This solution is considered strategic, in comparison to the construction of a new platform, with respect to the time required to production, which can be anticipated. Moreover the cost benefits may prove significant taking into account the lower price of the used platform compared to the cost to be incurred for the design/construction of a new structure. Cost saving is the issue but, of course, also the structural safety is to be considered as primary target: therefore, in view of the possible purchase of the existing structure, it must be carried out an appropriate assessment in order to confirm the engineering feasibility of the project and analyze the costs with the purpose to quantify the economic benefits. First, the feasibility study consists of evaluating, by means of a system structural analysis, the residual life of the platform in relation to the new installation site conditions (e.g. soil, waves, current, etc.), then the platform assessment shall include the execution of a gap analysis between the requirements of codes & standards, specifications, procedures used as reference for the original project and those defined by the potential purchaser in order to highlight any discrepancies. As a definitive step, a survey must be carried out according to the "condition assessment plan" prepared on the basis of the findings of the above mentioned activities. This plan is intended to describe the inspection activities by defining, for example, the non-destructive methods and extension, the laboratory mechanical and chemical tests to be carried out. In addition the "corrosion assessment" of the existing structure must be carried out during the survey. Based on the findings coming from the survey, additional checks and tests will be carried out; moreover, if necessary, a refurbishment, repair or modification plan is to be issued. In conclusion, the correct execution of the above described activities will provide to the potential purchaser greater confidence on the usability of the existing platform and all the elements needed to perform an accurate economic evaluation for his final decision making.

ABSTRACT In a time when drilling efficiencies are significant, the advancement of conventional clear brine systems has led to both economic and technological breakthroughs. Clear brine fluids have been in the industry since the 1950's, and since inception, different base brines have been utilized to maintain different densities. Calcium chloride is a great base fluid due to its natural density and highly lubricious nature. By adding calcium nitrate, densities have been increased to 1.6 sg (13.35 lb/gal), exceeding the density of potassium formate 1.57 sg (13.1 lb/gal). These calcium brine systems can be cost effective providing a reduction in cost for base fluid up to 90% as compared to formate or bromide systems. However, divalent brines are known for having excessively high corrosion rates and compatibility issues when used with polymers. By focusing efforts on process control and product compatibility, low corrosion rates can be achieved in a brine system. After exhaustive autoclave testing, a corrosion package was developed and perfected in the field. Results of a 140-well dataset showed the calcium chloride system with a novel corrosion package yielded better results than formate brines employed in the same area. The exhaustive efforts in the field also led to determining a suitable flocculent polymer that can hydrate in the calcium chloride/calcium nitrate dual-brine system. This novel application of a polymer provided improvements in both corrosion and drilling performance. This paper discusses the use of clear calcium chloride brine drilling fluids in drilling over 140 wells and the challenges overcome. It also details the equipment used and highlights the comprehensive technique for evaluating all aspects of the drilling fluid. INTRODUCTION Clear brine fluids create density without the need to maintain viscosity solely to carry weight-material particulates as all the weight-material is totally dissolved. The fluid density is dictated by the amount and type of salt used. Each salt has a maximum concentration before it reaches saturation limiting the maximum density of the solution. Thermal expansion of water affects the solubility, crystallization point, and density of clear brine.

Abstract An experience of ESP issues troubleshooting to overcome high corrosion media of GSA wells is presented. Likewise, actions taken to extend run life of pumps are explained. GSA is the unique company in Algeria adopted ESP system including all services, there was no chance to share experience with other entities in Country. Thus, it became necessary to try all available approaches during a journey of 10 years to mitigate ESP failures and eventually production downtime. To overcome high salinity of >320 g/l, several actions were introduced in either ways, ESP equipment or well completion. Simple motors and protectors changed to tandem to prevent water penetration inside motor. Power cable was changed from Galvanized to Monel Armor for high corrosiveness. Completion wise, one or double 1/2" water dilution lines were adopted, run along tubing, connected to tail pipe which run to perforations. Modification in completion metallurgy took place also, when Carbon steel replaced by Super 13Cr instead. Supplementary actions taken at surface, pressure switch was connected with VSD to smoothly shutdown ESP for unforeseen SCSSV closures. The adopted actions yielded considerable positive results. ESP failures originated from water penetration inside motor was reduced to 20%. Whereas, salt deposition blocs were almost prevented and resulted decrement in bullheading and coiled tubing interventions by 85%, except for some wells when salt bloc build-up is occasionally quicker and more important than water dilution rate. Running 1/2" injection line along with tail pipe led to less ESP shutdowns frequency. Changing the power cable type gave roughly good results as well. Once running Monel Armor, number of power cable failure related decreased and consequently contributed in reduction of whole failures. Saying that because power cable failure related represented 70﹪ of ESP failures in 2015. Considering Super 13Cr instead of Carbon steel tubing gave positive indications and reduced sharply tubing integrity failure related. The problem still exists, however, with very low frequency. For surface equipment, all unforeseen SCSSV closure, actuated from control panel is always accompanied with gradual decrement of frequency and consequently smoother ESP shutdown. As our organisation is the truly company that uses ESP with a proper sense in Algeria, This paper presents some best practices to be considered for other companies and ESP contractors based in the country or abroad that intend to both install ESP system in very high salinity and corrosive fields and adopt lease model for downhole Equipment.

ABSTRACT The aim of this research is to Preparation of nonionic surfactants from Oleic acid and their application in the field of corrosion inhibitors are the main goal of the present work. In this respect, oleic acid reacted with maleic anhydride using Diles Alder reaction to produce adduct, which esterified with ethoxthylated aniline to produce branched nonionic surfactants. The effect of ethylene oxide modification on both surface activity and corrosion inhibition efficiency on carbon steel pipelines in deep oil wells' formation water saturated with CO 2 at 50 °C was studied by both potentiodynamic polarization techniques and electrochemical impedance spectroscopy (EIS) measurements. The corrosion inhibition efficiency of the synthesized nonionic surfactants is correlated with surface tension measurements data. The nature of protective film formed on carbon steel surface is studied by scanning electron microscopy (SEM) and energy dispersive analysis of X-rays (EDX) techniques. Polarization curves indicated that the studied inhibitors acted as mixed (cathodic/anodic) inhibitors. EIS data showed that the values of charge transfer resistance (R t ) increased by increasing the inhibitor concentration, while the values of electrochemical double layer capacitance (C dl ) decreased. 1. INTRODUCTION Oil wells' Formation water that naturally exists in the rocks before drilling contains a variety of dissolved organic and inorganic compounds. This water considers the most corrosive environments in oil field operations due primarily to the presence of large quantities of the corrosive carbon dioxide and hydrogen sulfide in addition to other aggressive salts such as chloride and sulfate [1-3]. The severity of corrosion depends on temperature, fluid characteristics (CO 2 , partial pressure, gas / liquid ratio, formation water composition, water-to-oil ratio, and pH), flow characteristics and material characteristics. When CO 2 is present in the gas phase, any water in contact with this gas will dissolve CO 2 , forming carbonic acid which is corrosive to steel [4].

ABSTRACT The present investigation, four ester derivatives from oleic acid based on Diels Alder reaction are prepared, characterized and tested as corrosion inhibitors for pipeline carbon steel specimensin deep oil wells' formation water saturated with CO 2 .at 50°C (323K). The corrosion inhibition efficiency is measured using electrochemical techniquesof impedance and potentiodynamic polarization measurements. The corrosion inhibition efficiency of the surfactants is correlated with surface tension measurements data. The protective ?lm formed on the carbon steel surface is studied by scanning electron microscopy (SEM) and energy dispersive analysis of X-rays (EDX) techniques.Polarization curves indicated that the studied inhibitors acted as mixed (cathodic/anodic) inhibitors.

ABSTRACT The exploration for new petroleum resources is venturing into deeper formations as most of the conventional reservoirs are less productive over time. These deeper, high-pressure high-temperature (HPHT) reservoirs create major challenges for various operations, such as acidizing, fracturing, and sand control. Especially for acidizing operations, the formation of wormholes at high temperatures is a challenge because the acid reaction rate is higher and the viscosity of the fluid is lower. Therefore, acid emulsified in diesel, using diesel as the external phase, is used in acidizing applications. This is anticipated to perform better compared to neat acids at higher temperatures when it remains in an emulsified form. Hence, the emulsion stability of the system is a major concern, especially for high-temperature applications. The stability depends on various factors, such as temperature, corrosion inhibitors, and intensifiers, among others. This paper presents a recent study including the effect of different corrosion inhibitor intensifiers, acid strengths (20 to 28%), and temperatures (275 to 300°F) on the emulsion stability and corrosion rate. The instability of the emulsified acid system and corrosion were found to be positively correlated. The addition of a high amount of corrosion inhibitor also destabilizes the emulsion. Hence, it needs to be used at an optimum concentration. The effect of two different corrosion inhibitor intensifiers on the stability of the system was also studied. One inhibitor intensifier was found to affect the stability of the emulsion only at higher temperatures (300°F and above). The effect was a result of a faster release of the degradation products of the additive at higher temperatures. The amount of this intensifier should be limited to 5 gal/1,000 gal for higher temperatures (300°F and above) for 28% HCl acid at pressures less than or equal to 1,000 psi. The stability of the emulsion was enhanced by the addition of another intensifier at higher temperatures. Based on these observations, an optimized emulsified acid recipe was designed that was stable at 300°F. This system can be used for acid stimulation of carbonate reservoirs with bottomhole static temperatures (BHSTs) of 300°F, meeting the current market demand for acidizing operations. In addition, the findings reveal the effect of corrosion inhibitor intensifiers on emulsified acid systems. The results of this study are very useful for designing an emulsified acid system for use in high-temperature applications.

ABSTRACT Far from being negligible, corrosion related to the activity of the micro-organisms is responsible for the degradation of many metal structures in the installations of gas. The gas industry meet a problems involved to this induced corrosion by the microorganisms (biocorrosion). The biocorrosion on the treatment gas plants is caused by associated water (cooling waters, collectors’ water …) with the gas and contaminated by the micro-organisms. The awakening on the need for fighting against the biocorrosion of the gas treatment plants was a factor of research, the development and application of technical methods making it possible to evaluate the severity of this biocorrosion. These evaluation techniques updated in the gas industry become impossible to circumvent for the prevention against the bacterial corrosion origin. The main of this work is to present the biocorrosion evaluation of the gas treatment plant (cooler flow line of the water and the collecting system). The results showed that some spot of the gas treatment plant such as the gas collecting mains, the balloons and the flash tanks of produced water of the gas production process are affected by the biocorrosion. Adequate methods of treatments to cure these problems in the treatments gas plants were proposed and which can be applied for all of the treatment gas plant from sonatrach.

ABSTRACT: Atmospheric plasma spray is a very efficient thermal spray technique to obtain coatings resistant to corrosion and wear. Coatings obtained by thermal spray techniques are used in many applications where wear and abrasion resistance are required and due to the simplicity of application and facility of the covering of large areas, protection against corrosion is made possible The corrosion behavior of stainless steel coating samples was investigated in two medium: seawater and oilfield production water using the scanning electron microscope (SEM) and electrochemical techniques (potentiodynamic polarization and AC Impedance Spectroscopy). The surface morphology and microstructure of the specimens, before and after the corrosion experiments, were investigated by SEM analysis. The test, which were performed with Potentiodynamic polarization shows that the stainless steel coating ennobles the metal by anodic protection effect. The test, which has been performed with Electrochemical Impedance Spectroscopy, indicates the barrier properties of coating. Stainless steel coating was more effective in oilfield production water compared to seawater. This is probably due to the presence of oxygen in seawater, normally absent in producing oilfield systems. Thus, the aim of this work was to study the plasma sprayed stainless steel coating onto a steel substrate in terms of the corrosion protection of the facilities in gas and oil field mainly, flow lines (oil, water, gas) and Storage Vessels with Separated Water Bottom. Key words: Petroleum industry, corrosion, protection, stainless steel coatin

ABSTRACT: In oil and gas production, carbon steel is widely used as the material of construction for downhole tubing, vessels and piping. Although it is inexpensive compared to stainless steel, carbon steel is susceptible to corrosion attack from CO2 and/or H2S present in the produced water. Therefore, the corrosion risks of this material have to be proactively managed. To this end we have to develop and to implement corrosion control strategies which integrate risk assessment and corrosion control with corrosion monitoring and inspection. The application of corrosion monitoring as part of a corrosion control strategy is complex and often becomes the responsibility of engineers who are not experts in the field. The aim of corrosion monitoring is primarily to ensure that the design life is not being adversely affected or compromised and also to maximise the safe and economic operational life of a facility. When undertaking corrosion monitoring it is important not to rely on just one method. The best results are obtained by using a range of techniques. Some corrosion measurement techniques can be used on-line, constantly exposed to the process stream, while others provide off-line measurement, such as that determined in a laboratory analysis. Some techniques give a direct measure of metal loss or corrosion rate, while others are used to infer that a corrosive environment may exist. The aim of this work is to provide an aid to the operator in the choice of the corrosion monitoring technique

ABSTRACT: Pipelines are becoming an increasingly important means to transport large volumes of hydrocarbons over long distances in the Mediterranean region. If well constructed, carefully monitored and properly maintained, pipelines can be a safe and environmentally/economically sound means of transport; however, pipeline integrity is a growing and challenging problem for oil companies since the age of components is increasing and the responsibility and awareness about environmental protection is increasing too. Procedures and practices to monitor pipeline integrity are an important challenge for operators. Internal corrosion is one of the most active and dangerous damage mechanisms. In the frame of a research project the attempt was made to apply well known models in different sections of a long pipeline, with the objective of obtaining, coupled with flow dynamics properties of the transported fluid, a ranking of corrosion risks along the pipe. Other studies have shown that long term effects on mechanical properties of pipeline steel can be observed in presence of internal corrosion. The results of such studies need an effort towards application, to understand their capability of giving a measure of pipeline integrity. The application to the case of Meleiha-El Hamra pipeline (Agiba Pet. Co., Egypt) - having a length of 166 km and operating since 1985 to transport oil and condensate from different fields - is discussed in this paper. Hydraulic analysis was performed. Fluid velocity and flow regime as a function of pipeline length were obtained. The run was completed with the application of Water Wetting Models. Obtained results were compared with intelligent pig output to verify the reliability of the proposed procedure. Moreover, on a section of the serviced pipeline provided by Agiba, hydrogen embrittlement effects were assessed to verify the ageing of the pipeline steel, and field applicable technologies to characterize on site mechanical properties of the material were evaluated

ABSTRACT: Since 2000, global deepwater production capacity has increased more than a threefold. Development of deepwater assets is challenging and expensive. In the case of a failure or leakage, environmental impact is high and restoring control is difficult. Hence, proactive inspection and integrity monitoring to minimize failure and leaks is an essential element of offshore operations. This paper reviews the state-of-the-art of inspection techniques, with special focus on technologies that can be deployed in deepwater First, subsea failure modes are reviewed, both for rigid and for flexible pipelines and risers. Then, inspection and monitoring techniques are categorized by sensing principles and are compared. Installation and deployment methods are also discussed. Finally, the latest R&D trends in inspection and monitoring, such as the development of new sensing principles, autonomous inspection vehicles, or hybrid deployment methods, are also addressed

ABSTRACT: Internal CO2 corrosion is a dangerous phenomenon which affects hydrocarbon transportation in pipelines, with occurrence of production spill and safety issues. Models are available to determine the exp ected corrosion rate and to allow selecting suitable materials to minimize failures. However, different conditions can be experienced during the life of a pipeline and there is a need to predict the occurrence of damage for a be tter risk management. This paper presents comparison of predict ive models results with field damage observations, with the final objective of obtaining data for the assessment of pipeline life. Corrosion models were thus coupled with hydraulic analysis performed with the help of flow dynamics codes. Obtained results show that flow dynamics can help in assessing risk levels, which can be dif ferent in different region of a long p ipeline. Flow regimes and the potential water wetting at the pipeline wall are e stimated using one-dimensional code and simple models available in literature. Computational Fluid Dyna mics (CFD) is also evaluated as a powerful tool in some critical sections. The proposed methodology can be considered as an integrated approach for CO2 corrosion risk prediction for differ ent pipeline sections. As it is observed in field experience, damage can be high in some section of a pipe line, while in near sections no corrosion is active. The predicted corrosion rate is actu ally a function of local flow conditions and the comparison with observed damage is expected to help in the planning of inspection and maintenance activities. This methodology is just a first attempt to couple corrosion and fluid dynamics analysis and further applications are foreseen to allow completing the procedure and proposing a methodology for risk assessment of pipelines transporting hydrocarbons

ABSTRACT: The LPG sphere tanks are considered the most risky hazard due to consequences of its failure to the business and HSE health safety and environment. The probabilistic study is considering the effect of corrosion on the capacity of the LPG sphere legs. The sphere legs is under corrosion attack due to the surrounding severe environmental conditions and the regular fire fighting test which is done periodically. Observations and modeling of general corrosion of Steel legs are described. The probability of failure based on the ultimate capacity of the sphere steel column under corrosion effect is determined using Monte-Carlo simulation technique. The study is performed in case of two cases, the hydrostatic test or system purge by water and the operating condition with the effect of earthquake. Therefore, it may be concluded that the corrosion parameter is an important factor in the safety of LPG sphere tanks. Moreover it defines the probability of failure along the structure life time in case of hydrostatic test and operating conditions

ABSTRACT: In deepwater, corrosion protection of flowlines is becoming a major issue as fluid temperature and pressure increase. Conventional corrosion allowance on carbon steel pipe thickness leads to excessive procurement costs, installation weight and welding thickness resulting in non-economic solutions. Clad flowlines require expensive implementation with additional non destructive testing difficulties during installation. Plastic liners present an interesting alternative but have been mostly limited up to now to reel-lay installation. For J-lay operations, the frequency of pipe section welding requires a specific field joint design that limits welding and non-destructive-testing difficulties and, thus, maintains the attractiveness of plastic lining. This paper describes an innovative and cost-effective field-joint system for J-lay (named IFJ for Inconel® Field Joint) that has been developed and patented by Saipem to answer that issue. This system maintains the corrosion barrier across girth weld locations along the flowline using a sleeve made in an austenitic nickel-based alloy crimped into the adequate plastic liner. This technology has a minimal impact on the offshore laying rate as the offshore welds remain standard carbon steel welds. Combined with a self gas release system on every quad-joint, this technology will soon be proposed for production applications within plastic liner capabilities. Riser application shall follow. The paper will discuss the results of the extensive qualification program carried out on the IFJ technology over the last 2 years

ABSTRACT: Hydrocarbon transfer pipelines that passing/traversing across protected areas have always the risk of sudden failure due to unseen internal corrosion causing damage to the surrounding environment. Therefore, it is necessary to maintain the integrity of hydrocarbon transfer pipelines especially, aged pipelines in order to minimize the risk of its failures, avoid oil spill, protect the environment from pollutants and achieve a proactive pipeline failure control. This paper presents a pipeline risk assessment program that was designed to manage corrosion, control pipeline's failures and to assure a renovated pipeline system. This program includes practical techniques to 1) refurbish a doubtful pipeline, 2) determine exact condition & remaining life of a pipeline and 3) to make active pipeline maintenance. This technique is successfully implemented in GUPCO Oil Company and proved its capability to be a powerful tool to evaluate & maintain the overall integrity/strength of GUPCO pipeline's systems. It is simple now for pipeline operators to identify areas of greatest impact to the environment & safety and to respond with the necessary course of actions to remedy the deficiencies. Thus, they succeeded in maximizing economic returns for pipelines-owners, protecting the safety of employees/community, minimizing risk to the environment and finally complying with the laws and regulations of Egypt.