Thursday, February 5, 2015
Oil and gas pipelines play a critical role in delivering the energy resources needed to power communities around the world. In the United States alone, according to the U.S. Department of Transportation (DOT), more than 2.5 million miles of pipelines — enough pipeline to circle the earth approximately 100 times — deliver oil and gas to homes and businesses.
While pipelines are recognized by government agencies such as the DOT and the National Transportation Safety Board (NTSB) as being one of the safest and most efficient means of transporting these commodities, their use still poses an intrinsic risk due to failures and leaks. Although major pipeline failures occur infrequently, several pipeline incidents in recent years have put the issue of pipeline safety into prominent view. In response, both the Canadian National Energy Board (NEB) and the DOT are implementing measures that promote pipeline safety and security.
To better understand how corrosion can impact the safety and reliability of transmission pipelines, NACE International asked several of its members in the oil and gas industry to comment on the challenges faced by the industry when managing corrosion of pipelines, in particular the pipelines that transport crude oils. This report will be presented in two parts with the second article in April.
Panelists are Jenny Been with TransCanada Pipelines; Oliver Moghissi with DNV; Michael Mosher with Alberta Innovates-Technology Futures; Sankara Papavinasam, FNACE,(1) with CanmetMATERIALS; Trevor Place with Enbridge Pipelines; and Sonja Richter with Ohio University. (See their biographies in the sidebar, “Meet the Panelists.”)
NACE: The oil industry is facing concerns by the general public that heavy crude oils, particularly diluted bitumen (dilbit), are corrosive and can lead to leaks and oil spills from transmission pipelines. What are the main challenges the industry faces when managing corrosion of pipelines that transport crude oils?
Moghissi: Internal corrosion is one of many possible threats to a crude oil transmission pipeline that must be managed. It should be noted that crude oil by itself is not corrosive at pipeline conditions, but water can drop out of the crude oil and allow corrosion to occur where it accumulates.
Water carried by heavy crude oils, including dilbit, does not significantly differ in corrosivity from water carried by other crudes. Corrosion in crude oil pipelines is addressed by conventional corrosion control practices and is generally effective. However, pipelines travel over long distances, and what is considered unlikely at one location can become significant when summed over a pipeline infrastructure.
Place: Crude oils, including dilbit, are not corrosive in pipelines. The main technical challenge is that trace water and sediments — not the crude oil — cause corrosion. The presence of crude oil, including the dilbits we have tested, actually decreases the corrosiveness of the standard brine used in standard testing. Although we know that we have a minimally corrosive system, we think it may be possible to reduce corrosion even further — and this possibility is what drives our research and development efforts.
It is challenging to accurately measure very small or very rare things, and the corrosion that occurs in transmission pipelines is typically isolated and progresses rather slowly; this makes it difficult to identify and assess the likelihood of internal corrosion, and also to evaluate the beneficial effects of mitigation activities.
Mosher: One of the main challenges facing the industry with respect to managing corrosion of crude oil transmission pipelines is the difficulty in predicting internal corrosion. Most internal corrosion in crude oil transmission pipelines is caused by the settling of solid particles that can carry water to the pipe surface. Transmission tariffs are set to limit basic sediment and water (BS&W) to <1% (often 0.5%). The solid particles tend to be encapsulated by a layer of water that may concentrate water on the pipe wall surface. This creates the potential for corrosion to occur if the flow conditions of the pipeline system allow for these solids to settle out.
The water (an electrolyte) is a necessary component of the corrosion cell. Without it, corrosion will not occur at appreciable rates within the transmission pipeline. This type of corrosion is typically referred to as underdeposit corrosion and will often manifest as localized pitting. Moreover, pitting corrosion can proceed rapidly or lay dormant for extended periods of time, making this type of corrosion particularly difficult to predict.
Richter: The main challenge is to manage the water that is transported along with the crude oil and is responsible for the corrosion that occurs if it is in contact with the pipeline wall. Crude oils are not corrosive at temperatures encountered in pipelines. It is not until crude oils are heated in refineries that they can become corrosive. The industry severely limits the amount of water allowed into transmission lines to <0.5% by weight.
While this small amount of water (which is heavier than the oil) can easily be kept off the pipeline wall and entrained in the crude oil, it is a challenge for the industry if production (and flow rates) decreases, making it more challenging to keep the water entrained and off the pipeline walls. However, heavier crude oils entrain the water more easily than lighter crude oils, which is beneficial for corrosion protection.
Papavinasam: The main challenge the industry faces is to establish public confidence that the risk due to internal corrosion of oil transmission pipelines is low and that the risk can continue to be managed at the lower level using established engineering practices. Under normal oil transmission pipeline operating conditions, corrosion occurs by an electrochemical mechanism. Crude oil (including dilbit), being a non-conducting electrolyte, does not support corrosion. However, if the crude oil contains water, then corrosion may take place in those locations where water drops out of crude oil and comes in contact with the metallic surface. The bulk crude oil may indirectly affect the corrosion by influencing the locations where water may accumulate and by influencing the corrosivity of water in those locations.
The pipeline operators keep the risk of internal corrosion in oil transmission pipelines at a lower level by limiting the amount of water to <1% BS&W (typically to <0.5%). However, based on some non-scientific reports and extrapolation of corrosive conditions of refineries (operating above 200 oC) to the conditions of oil transmission pipelines (operating typically below 70o C), some members of the public are concerned that crude oils are corrosive.
NACE: What are the characteristics of crude oils and the transportation process that could lead to transmission pipeline corrosion? Are some crude oil grades more corrosive than others?
Place: The primary factor that affects internal corrosion in transmission pipelines is flow rate. Transmission/refinery-ready crude oils (including dilbit) contain very little corrosion-causing water or sediment, but internal corrosion can occur if the flow conditions in the pipeline allow these materials to accumulate and persist on the pipe floor for extended periods of time. No crude oil grades have yet been proven to be more corrosive than others, but there are measurable variations in certain corrosion-related properties of crude oil.
ASTM G2051 is an industry guide for evaluating three important crude oil properties that can have an impact on internal corrosion: these are wettability, emulsion-forming tendency, and effect of crude oil on the corrosiveness of brine. Based on our investigation so far, there does not appear to be any correlation between the crude oil grade and these corrosion-related crude properties. Our tests have shown these properties to vary as much within a crude grade as they do between different crude grades.
Moghissi: Corrosion in crude oil pipelines is often attributed to microbiologically influenced corrosion (MIC). The most significant factor in evaluating the likelihood of MIC is whether water and solids suspended in the oil remain entrained or fall to the bottom of the pipe. The critical velocity for entrainment depends upon physical properties of the oil (e.g., heavy crudes have lower critical velocities) and throughput. With everything else being the same, pipelines with slow flow (below critical velocity) tend to be more susceptible to corrosion than those with high flow (above critical velocity).
Mosher: The primary method of crude oil corrosion within transmission lines is underdeposit corrosion. Particles settling at the bottom of the pipeline establish an environment that can promote a water-wetted surface. Chemical properties of the settled water and presence/absence of active bacteria could vary between crude oil sources, but (to my knowledge) there is no literature comparing the corrosiveness of waters from different crude oils. However, several papers have been published that show crude oils can inhibit the corrosiveness of water when mixed together.
Settling of solids during the transportation process is largely governed by elevation changes in the pipeline. In areas of overbends or under bends in the pipeline, the fluid dynamics can promote the settling of particles where they would otherwise be carried safely through the pipe. I have seen no evidence — scientific or statistical — indicating that one type of crude is noticeably more corrosive than another under standard pipeline operating conditions.
Papavinasam: Industry has established that the BS&W of oil transmission pipelines is lower than 1% (typically lower than 0.5%) volume to volume. The result of low amounts of water in oil transmission pipelines is a low probability of internal corrosion. However, locations where water accumulates may be susceptible to corrosion.
ASTM G205 classifies crude oils into four categories in terms of how they affect corrosivity of the water phase and provides detailed and systematic procedures for determining corrosivity of the water phase in the presence of crude oil. Tests carried out by various research and testing laboratories conclude that corrosivity of various crude oils is low and that of dilbit is in the same range as that of other crude oils.
Richter: The density difference between oil and water causes the water to tend to separate at the bottom of the pipe. This is more prone to occur with light crude oil as compared to heavy crude oil and increases the possibility of corrosion. In addition, heavy crude oils are more likely to contain beneficial compounds that can help protect the pipeline from corrosion.
These beneficial compounds can contribute to high acid numbers and/or high sulfur content. Although beneficial at lower temperatures, such as in transmission pipelines, these compounds can become corrosive at high temperatures such as in refineries. A water wetting model is included in the MULTICORP corrosion prediction software developed by Ohio University, which allows for prediction of the flow rate necessary to keep the water entrained.
Been: The presence of a small quantity of water in crude oil is inevitable. However, <0.5% of water is not considered to be a corrosion concern unless conditions exist that enable the precipitation and accumulation of this water on the pipe wall. Water dropout and accumulation can occur at low velocities and under stagnant conditions. A model described in NACE SP0208-20082 can be used to determine the velocities at which water could drop out of crude oil as a function of the crude oil density and viscosity; the effect of temperature is minimal.
Water is less likely to drop out at lower velocities when entrained in heavier crude such as dilbit as compared to typical light crude. These velocities are well below our normal operating velocities on our transmission pipelines. Increasing flow velocity and turbulence after a period of low velocity or line stoppage will reintroduce the water back into the main oil stream. Suitable models to predict the deposition of solids are not available. However, it is well understood that the deposition of sediments is minimized in highly turbulent flow. Where conditions are amenable to deposition and underdeposit corrosion, laboratory underdeposit corrosion tests have indicated that relatively low corrosion rates are expected over a wide range of crude densities.
Been: The occurrence of internal corrosion is initially considered during the pipeline design phase when the line is designed to operate normally under turbulent flow conditions to prevent the deposition of water and sediments. Prior to and during operation, predictive models are used to identify potential susceptible locations, with continuous consideration of changes in operational parameters. Cleaning pigs and intelligent pigs are used to regularly assess the pipeline condition during operation.
Richter: Corrosion is identified with systematic inspections, which include measuring the wall thickness and the corrosion rate. The susceptibility to corrosion is determined in part by predictions based on the water chemistry, flow characteristics, temperature, and in part by corrosion measurements. Typically, corrosion in crude oil pipelines occurs due to dissolved acid gases and water, both of which have been mostly separated out before the crude oil enters the transmission pipeline.
Moghissi: The most common way to predict susceptibility to corrosion is to determine water content (usually measured as BS&W) and compare pipeline throughput to the critical entrainment velocity. Consideration can be given for the water chemistry, presence of corrosion inhibitors (including both carryover or injected), any biocide treatments, and whether the pipeline is pigged. Ultimately, the existence of corrosion damage can be verified by methods such as inline inspection (ILI), pressure testing, and/or internal corrosion direct assessment (ICDA). Each of these methods has different strengths and weaknesses.
Papavinasam: The industry assesses the susceptibility of oil transmission pipelines to internal corrosion by two processes: direct assessment and ILI. NACE SP0208-2008 documents the use of the direct assessment method and proposes a four-step process to identify the causes of corrosion in oil transmission pipelines: pre-assessment (collect and analyze pipeline operating data); indirect inspection (identify locations susceptible to corrosion based on operating data collected); direct inspection (inspect the locations predicted to be susceptible to internal corrosion); and post-assessment (establish the frequency of subsequent inspections). NACE SP0208-2008 also lists several models that can be used to predict the location of water accumulation in the indirect inspection step.
NACE Task Group 477 is developing a standard report to provide guidelines for selecting the most appropriate model for this purpose. NACE SP0102-20103 provides guidelines to perform ILI where instrumented tools (commonly known as intelligent pigs) are sent through the pipeline for determining the remaining wall thickness of the pipeline.
Mosher: ILI tools, such as magnetic flux leakage (MFL), ultrasonic testing (UT), or a combination of both, give the pipeline operator a “snapshot in time” of the internal and external condition of their pipeline. Corrosion features over a certain threshold are measured by the instrument as it passes through the pipeline. In addition, the location of the pig is recorded using a global positioning system (GPS). The tool gives the location of any anomalies detected along the length of the pipeline inspected.
Anomalies of significant size/depths will often be validated by an excavation of the pipe. Often operators will use sequential ILI runs to predict the corrosion rates of anomalies and schedule future ILI runs based on their calculations. Other methods of identification include the NACE protocol for ICDA of liquid petroleum pipelines (NACE SP0208-2008) and hydrotesting.
Place: Corrosion typically takes time to occur on a transmission pipeline and pipelines could easily operate for more than 20 years before sufficient evidence of corrosion would demonstrate susceptibility. In the past, such identification was usually afforded though inline pipeline integrity inspection tools (smart pigging) used to identify areas of internal corrosion metal loss. This was a purely “reactive” evaluation of corrosion susceptibility.
Enbridge now uses proactive operational analysis. An in-house susceptibility model based on theoretical analysis, in conjunction with our extensive pipeline operational history of more than 60 years, is used to assess the likelihood that water could accumulate in a pipeline. The primary driver in this analysis, as discussed previously, is flow conditions. The ability of flowing oil to harmlessly transport trace corrodents like water and sediment is related to velocity, density and viscosity of the oil. I believe most pipeline operators use either a theoretical model; an empirical experience-based model; or, like Enbridge, both.
(1)FNACE denotes a NACE International Fellow.
source : http://www.pipelineandgasjournal.com/managing-corrosion-pipelines-transport-crude-oils?page=6
Sour gas is evident in various oil and gas producing regions of the world, in particular, the Middle East and the Commonwealth of Independent States. The product can not only cause deterioration to pipelines, but is potentially harmful to the environment and personnel health. This calls for specific requirements in terms of steel manufacture, materials selection and testing, as well as a strict code of compliance.
The detrimental effects as a result of sour service can range from small pinhole leaks to catastrophic failure in pipelines owing to a number of phenomena as a result of the sour gas environment, namely: stress corrosion cracking, sulphide stress corrosion cracking, hydrogen-induced cracking, hydrogen embrittlement and exfoliation, and sulphide-oriented hydrogen-induced cracking.
Mitigation and/or control of cracking in sour gas pipelines can be approached in a number of ways, namely steel manufacturing control, materials and fabrication processes, controlling the environment, and isolating the components from the sour environment.
Mitigation at the design stage
Mitigation must start at ‘square one’ – namely, materials selection, which requires careful review, testing and control such that they will be stipulated as ‘fit-for purpose’ for sour service. The materials selection process should reflect project-specific requirements, intended design life, costings, failure evaluations as well as environmental considerations, etc. As an absolute minimum, the following should be taken into consideration:
Design life and system availability;
- Pipeline system design – avoidance of deadlegs to mitigate stagnant conditions, correct pipeline sizing to reduce water hold ups and solids deposition;
- Facilities and process systems design and layout – gas dehydration;
- Full evaluation of operational and process conditions – H2S, CO2, O2 contents, pressures, temperatures, flow velocities and regimes, entrained solids, biological activity, etc.;
- Damage mechanism and failure modes with respect to health safety and environmental consequences; and,
- Materials availability and cost implications.
Notwithstanding the use of carbon and low-alloy steels as sour service linepipe and its susceptibility to various types of cracking, the various materials treatment/processes such as heat treatment, cold working or both must be carefully controlled. Where cold working or rolling of the steel plate may occur, thermal stress relief must take place to mitigate any residual stresses that may remain within the steel. Similarly, where production fluids contains a sulphur or CO2 content which is too high for the corrosion-resistant properties of carbon steel alone, a corrosion-resistant alloy (CRA) is often employed.
It provides a good balance between the mechanical properties of carbon steel and the corrosion resistant properties of a CRA. The use of CRAs such as Inconel 625 or 825 to form solid pipe is neither considered to be the norm nor can be economically justified owing to its prohibitive costs. Therefore, the synergistic combination of carbon steel and CRA together provides a cost-effective and optimum combination of materials.
Such a combination of materials can be manufactured through metallurgical bonding, known as clad pipe (through co-extrusion, hot-rolled bonding, explosive bonding), or by only a mechanical bond between the CRA and steel (through thermohydraulic gripping), known as lined pipe.
Mitigation at the manufacturing stage
Manufacturing of sour linepipe requires optimum steel chemistry and ‘steel cleanliness’. The presence of free sulphur during steel manufacture causes a reduction in overall steel mechanical properties, especially toughness; which dictates the requirements for very low sulphur concentrations; typically 0.005–0.010 per cent.
The use of manganese as an alloying element (and having particular importance as a de-sulphuriser and de-oxidiser element) during steel manufacture provides a mechanism whereby any remaining sulphur can be removed to form manganese sulphide.
The manganese sulphide inclusions formed have a significant influence on the mechanical properties of steel – such as toughness, hardness etc., with their size, composition and numbers influencing steel cleanliness – and must therefore be removed. Such inclusions are usually benign in low-strength steels, and their transverse ductile toughness is sufficient to prevent any ductile fracture. However, for the typical higher strength steels used for linepipe applications, higher transverse toughness values are required.
As part of linepipe manufacture, steel plate is hot rolled, causing the inclusions to transform into an elongated morphology known as ‘stringers’, owing to their ductility. Often with sour service pipelines, the presence of atomic hydrogen can diffuse through the steel structure accumulating at the apex of stringers. Recombination of atomic into molecular hydrogen causes a pressure build-up at these stress concentrator sites, causing crack initiation and subsequent propagation over time. Characteristic cracking or ‘stepwise’ cracking where successive cracks are ‘joined’ are well documented in practice and in the literature.
In addition, the type of rolling is important in order to produce steels which are grain refined, can achieve high strength and toughness in the heat-affected zone (HAZ), provide excellent weldability and formability and, importantly, high-resistance against cold cracking. This is achievable through a process known as thermomechanical rolling process (i.e. deformation without recrystallisation) and thermomechanical controlled process, which combines thermomechanical rolling with accelerated cooling.
To ensure that the final steel product is free from detrimental ‘stringers’, the use of compounds such as calcium or cerium are typically employed, whereby its combination with sulphides is greater than with manganese and promotes a transformation of the elongated forms into spherical particles. In this way, any potential sites for hydrogen diffusion and potential steel cracking cannot now take place.
Prior to fabrication of production linepipe, pre-qualification testing is a normal procedure that includes hardness testing in accordance with NACE specification (NACE MR0175), and is carried out to ensure that during production, welding of linepipe achieves a hardness value on materials testing of no greater than 22 HRC (Rockwell Hardness scale) in order to obviate brittle fracture within the weld itself, parent metal and HAZ. Similarly, the welding procedure must introduce strict controls for welding parameters, welding consumables as well as control and storage of welding rods.
The hardness of parent materials and of welds and their HAZs play important roles in determining the sulphide stress cracking resistance of carbon and low-alloy steels. Hardness control can be an acceptable means of obtaining sulphide stress cracking resistance.
Mitigation at the operational stage
So far examined have been a number of mitigation methods which provide certain controls in terms of safeguarding sour service pipelines. In addition, can also be introduced (additional measures) during the pipeline operational and maintenance stage in the form of a robust pipeline management system.
Pipelines and chemicals management plays a critical role in all pipeline operations and more so with respect to sour service pipelines. Through the implementation of a well-planned risk-based inspection plan, a thorough internal and external examination of pipelines can be carried out and their condition assessed using methodologies such as remotely operated vehicles, divers, and intelligent pigging (in-line inspection). The collective data from the inspection and surveys provide a condition assessment of the internal and external pipeline condition, as well as providing a confidence statement as to the continued pipeline’s ‘fitness for purpose’ or otherwise to the pipeline operator.
In this case therefore, pipeline management must be robust such that both physical and chemicals maintenance is applied to pipelines in sour service. Pro-active pipeline pigging – both intelligent and maintenance – will ensure that the pipeline is kept clean but also that the internal/external condition of the pipeline shall be known. Periodic pigging of pipelines removes liquids, solids, various debris, and other contaminants. In addition, pig ‘trash’ analysis is a useful way to understand what is being transported within the pipeline.
Pipeline pigging is one of the most effective methods of not only cleaning the pipelines but also reducing the potential for any bacterial colonisation – such as sulfate-reducing bacteria (SRBs) – leading to microbiologically influenced corrosion attack, and under deposit corrosion effects, leading potentially to loss of pipeline containment or complete failure. It is important therefore that the selection, type and size of pigs is correctly made in order to ensure complete effectiveness and resulting cleanliness for the pipeline, as this plays an extremely important part in terms of improving the effectiveness of corrosion inhibitor and biocide treatments for sour pipelines in terms of chemical volumes and contact time.
Inhibitor and biocide treatments provide a barrier between the corrosive elements and the pipe surface itself and, dependent on requirements, can be applied either by a batch or continuous programme. All corrosion inhibitors and biocides used for pipelines will be recommended in accordance with manufacturers’ recommendations and specifications, as well as undergoing trials and testing (laboratory and field) to ensure that the correct materials are used. In the case of sour pipelines, determining the correct inhibitors, biocides as well as dosage rates and application methodologies becomes a critical task.
Corrosion monitoring plays an essential part in providing information as to the internal condition of the pipeline. The ongoing monitoring of acid gases such as H2S and CO2 should be periodically assessed, as changes in operating conditions over the lifetime of a pipeline will inevitably occur such as increasing water cuts, dissolved metals and entrained solids such as sand.
Sour service pipelines under the influence of SRBs have been well studied and documented to date. The use of bio-spools in low- and high-pressure systems in conjunction with other corrosion monitoring methods as discussed, can be well placed to monitor such bacteria presence and yield extremely useful data on corrosion activity and efficacy of biocide treatments for corrosion control.
Sour service pipelines carrying fluids or gases in addition to a wet internal environment causes problems to the pipeline leading to corrosion and potential loss of containment or complete breakdown of the pipeline. In addition, the presence of SRBs also play a critical role in generating hydrogen sulphide gas and equally cause potential pipeline corrosion problems.
The article outlines a number of mitigation methods with respect to sour service gas pipelines, such as during manufacturing and fabrication stages and, importantly, during the pipelines operational and management phases. The use of well-planned and structured inspection, maintenance and repair regimes together with a robust campaign of pipelines and chemicals management will be well placed to mitigate the effects of pipeline deterioration and potential failure as a result of sour gas.
source : http://pipelinesinternational.com/news/sour_gas_pipelines_how_do_we_deal_with_them/065073/
|Nord Stream pipeline route. (Image courtesy Nord Stream)|
- Pre-commissioning spreads onshore were located in autonomous areas separate from the construction sites used for the permanent facilities
- Pre-commissioning pigs for the subsea pipeline would not traverse the permanent pig traps or permanent valves
- Flooding, cleaning, and gauging (FCG) were performed offshore onboard the SCV. All subsea handling was performed by ROV
- Water was treated with sodium bisulphite and ultra violet light (UV) only
- Pressure test of sections 1 and 2 from SCV
- Pressure test of Section 3 from the receiving terminal in Germany (to reduce vessel time and risk from waiting on weather)
- De-watering from Germany with water discharge in Russia, after completion of subsea hyperbaric tie-in at KP 297 and KP 675
- Drying from Germany to Russia
- Nitrogen as a barrier between air and gas during commissioning of the pipelines.
|Flooding, cleaning and gauging activities were performed by the crew aboard the subsea construction vessel. (Image courtesy Nord Stream)|
|Flooding, cleaning and gauging pig. (Image courtesy Nord Stream)|
- The first batch of four pigs was separated by slugs of potable water designed to dilute to an acceptable level the residual salt content remaining on the pipe wall
- The second batch of four pigs was separated by dry air to pick up water remaining after the desalination pigs
- The pig train was spaced so that the first four pigs could be received and removed before the arrival of the second set of four pigs.
|Dewatering pig. (Image courtesy Nord Stream)|
|Sealing tool. (Image courtesy Nord Stream)|
Schedule and execution
- RFQ issued for pre-commissioning operations, November 2008
- Pre-commissioning contract awarded to Baker Hughes, August 2009
- Engineering and procurement operations commenced, September 2009
- Contracts placed for all Wet Buckle Contingency (WBC) equipment, December 2009
- WBC equipment mobilized and function-tested, March 2010
- Contracts placed for all pre-commissioning equipment, June 2010
- Pre-commissioning FCGT equipment mobilized, February 2011
- Operational period for FCGT on Line 1, March to May 2011
- Dewatering and drying equipment mobilized, June 2011
- Operational period to dewater, dry, and N2 pack Line 1, July to August 2011
- Line 1 gas in work completed, September 2011
- Operational period for FCGT on Line 2, March to May 2012
- Operational period to dewater, dry, and N2 pack Line 2, July to August 2012
- Line 2 gas in work completed, September 2012
- Pre-commissioning sites reinstated, October 2012.
Dewatering and drying
- Line 1 was completely filled with 99.9% pure nitrogen from Germany
- Line 2 was partially filled from Russia (gas filling end) using a 99.9% pure nitrogen batch equal to 10% of the pipeline volume.
- Filtration through 200 ?m and 50 ?m cartridge filters
- Online injection of oxygen scavenger (OS), a commercial solution of sodium bisulphite and iron-based catalyst
- UV light treatment.
- Early identification and focus on long-lead items
- Early establishment of a pre-commissioning concept
- Early selection of main water source and water treatment regime
- Early start of engineering and planning
- Early involvement in permanent design work (identify pre-commissioning requirements)
- Early establishment of any additional local authority requirements
- Early establishment of pre-commissioning environmental basis
- Early identification of risks and maintaining a focus on them
- Maintaining a risk register with regular reviews and updates
- Maintaining focus on equipment and function tests
- Carefully selecting key subcontractors and suppliers
- Careful and comprehensive follow up and control of critical supplies and suppliers
- Approving procedures well in advance of field operations.
- World's longest, single-section dewatering operation
- World's longest travel distance for tie-in sealing tools
- Combined dewatering/sealing tool removal operation
- Effective dewatering operation confirmed by the quick-drying operation
- Quick and effective pressure test operations (favorable temperatures)
- Effective water pumping through two 6-in. LFH (2,500 cu m/hr or 0.66 m/s pig speed in 48-in. pipeline)
- Effective cleaning and gauging operations
- Effective pigs specifically designed for the work
- Successful pig tracking for good control and operational confidence
- Effective water treatment concept with practically no effect on the environment.
- Early engineering and planning
- Early involvement in pipeline design requirements
- Early focus on long-lead items (e.g. pipeline head)
- High-quality equipment and experienced personnel
- Continuous attention to safety, risk, and environment
- Correct procedures prepared early by involved personnel
- Professional operational execution, monitoring and control
source : http://www.offshore-mag.com/articles/print/volume-73/issue-5/pipelines-flowlines/pre-commissioning-the-nord-stream-pipeline.html