Tank Storage Magazine v06 i04


Volume: 6
Issue: 4
Date Published: September 8, 2010



Realise Canada's potential

And we’ve certainly not found a shortage of topics to explore. The country has a lot going for it when it comes to storage. Not only does it have the second largest proven oil reserves, second only to Saudi Arabia, it is also a bulk oil exporter to the US. Oil exports from Canada to the US hit 2.35 million barrels a day in December 2009, accounting for 25.1% of US oil imports and 12.7% of US total oil demand, according to the API. This represents a massive opportunity for storage operators. US-based Magellan Midstream Partners, for example, is already looking to play a role in supplying Houstonarea refi neries with Canadian crude. The concept of Canada shipping crude oil to Asian markets has also warmed considerably over the past year. This opens up new growth opportunities for additional tankage at ports and marine terminals, such as Kitimat and Vancouver in British Colombia. Jet fuel is another market which represents big potential for storage operators. While only 10% of Canada’s aviation fuel was imported a decade ago, one third of the country’s jet fuel is now imported. This is mainly because a lack of refi ning capacity to turn oil into jet fuel within Canada led to high prices.

Venturing into automated tank cleaning

In early 2010, a big Gulf Coast Refiner (GCR) needed three crude oil storage tanks cleaned, of which two were neighbouring tanks. The GCR was searching for a safer, more predictable and faster way of cleaning oil storage tanks, compared to the conventional tank cleaning methods. Making the move from conventional cleaning systems to automated can be a big decision. There are many factors to consider: Worker’s health and safety: Tank operators increasingly face the risk of litigation claims relating to health and quality of life relating to worker activities. Environment: Increased regulatory requirements require tank operators to minimize air emissions and hazardous waste generated from cleaning tanks. Storage capacity and reduction of downtime: Terminal operators want as little downtime as possible, but it is required every so often to allow for integrity inspection. To fit around this tank cleaning schedules need to be predictable and fast. Oil recovery: The value of hydrocarbons means that it is important to recover as much entrained oil as possible from tank bottom sludge. The company decided to try out a non-man entry automated cleaning system, Blabo. This was offered by Houston-based Cinatra, which has the rights to the Denmark-based tank cleaning specialist Oreco’s technology in North America. The fact that two of the tanks were neighbouring tanks allowed for fast change over from one tank to the other with a minimum of modification to the piping and ground mobilisation.

Long may it continue

Terminal construction and expansions have occurred over the past few years in major oil trading locations such as Cushing, Rotterdam, Fujairah and Singapore, supporting trader activities. And on top of that tank leasing rates have been rising. What else could a terminal operator ask for? Perhaps another four years of the same. Increasing product demand will continue to support construction and expansion activities. Much of the expansion in the trading locations has been fueled by traders asking for storage in order to participate in the physical oil market. Market prices supported storing oil for future use. But is the shine about to come off those brand new tanks? Contango Light sweet crude oil futures trade on the Chicago Mercantile Exchange who purchased the New York Mercantile Exchange (NYMEX) in 2008. The delivery point for the crude oil futures contract is Cushing, Oklahoma. During the latter part of 2006 the difference in price between the first two crude oil futures months began to regularly exceed $1 (€0.8) per barrel. Traders could buy the first month futures contract and sell the next month futures contract and collect the $1 per barrel. With monthly storage costs of approximately $0.35 per barrel and financing costs of only $0.25 per barrel, traders regarded this as one of the lowest risk trades, if in fact, a profitable no risk trade.

All change for IMTT

Terminal operator IMTT’s facility in Quebec City is surrounded by change. The commodity markets are declining, the Canadian dollar is rising and in June Shell confi rmed its decision to close its 130,000 barrel-a-day Montreal East refi nery and convert it into a fuel terminal. All this has a dramatic impact on the structure of the market and the amount of storage capacity required. Fewer paper mills means a decline in demand for chemical storage and Shell’s new terminal will add a new competitor to the market for some terminal operators, particularly those located in Montreal. Although this may sound like bad news, Marc Dulude, Quebec City’s executive vicepresident, explains that the terminal is having a brilliant year: ‘Shell’s closure may lead to a rise in imported petrochemicals and refi ned products, which will need storage space. And this will inevitably be in Quebec City since the new generation of ocean going vessels need to be lightened in the Quebec City deep water port before proceeding further up on the St-Lawrence River,’ he explains.

Canada's storage transformation

In terms of proven oil reserves, Canada has some 178 billion barrels of them – placing it second only to Saudi Arabia. While it sits seventh amongst the world’s largest oil producers, its remote and sparsely populated territory means barely any of Canada’s production is actually destined for its own domestic markets, making Canada a bulk oil exporter and a good business prospect for storage operators. Almost all of Canada’s oil exports go to the US, which receives over 2.5 million bpd of petroleum from its northerly neighbour, easily making Canada the largest exporter of petroleum to the US. According to a recent report from Global Data Canada was rated fourth in a list of top 10 emerging growth countries for oil storage, after China, UAE and Iran. In addition to a leading role in crude storage, industry data from the Canadian Petroleum Products Institute (PPI) puts the number of Canada-wide products terminals at 67. With many of these the sole such tank farm in very remote areas, individual terminals are of great importance to local economies. Some of Canada’s main hubs are the Port of Montréal on the east coast, Toronto on the northwestern shore of Lake Ontario, Vancouver on the west coast, and Alberta. A major refining centre, the Edmonton area of the province is also a major hub for energy storage and transhipment and home to what the industry terms ‘Pipeline Alley’, linking Canada’s oil sands producers to markets in eastern Canada and the US. Although oil sands development has received heavy scepticism in Canada and worldwide for its alleged environmental impacts, the sector is booming, and is contributing to an outlook that sees Canada’s oil producing peak now pushed out up to, and possibly beyond, 2020.

The 'other' costs of the project

The success of any project is always judged by three simple things: scope, schedule, and budget. No matter if it is as large as a tank farm expansion or greenfield terminal, or as small as minor maintenance and repair, no project is truly a success unless it has hit all three. A project may come in 20% under budget and right on time, but if it does not ‘do’ what it is supposed to it has not been a success... and it will just cost even more time and money to make it right. On the other hand if the new system performs perfectly and came in right on the money, but was completed a few months too late due to permitting delays or confusion with the contractor it is still deemed unsuccessful. There is no such thing as partial success. The key to getting these three goals met (scope, schedule, and budget) is not by luck, or by having enough contingency or weather days programmed in. It is by good solid front-end planning, and by involving the right people to discuss it. The beginning of the project is where all the promises are made – project cost, delivery date, and functionality – but too many projects get shortchanged at this stage. Huge amounts of time and money can be saved just by having a better understanding of what it will take to make the project happen. The industry’s time, money and knowledge are all very firmly planted in the product systems and what make these systems run.

Flame detection now more effective than ever

A fire at a storage terminal can have disastrous effects. A blaze at the end of July at a petrochemical factory at Iran’s largest oil terminal – killing four – is just the latest in a long line of incidents plaguing the terminal sector. Even when by some miracle lives are not lost, like at Buncefield back in 2005, the damage to infrastructure, profits and company reputation can still be incredibly damaging. So what protection measures can be taken? Rim-seal fires are the most common type of fire for floating-roof tanks, especially external floatingroof tanks. It is estimated 0.16% of all tanks with rim seals will experience a rimseal fire in any given year. To prevent vapours escaping from around the periphery of the floating roof, a seal typically rides up and down the tank walls along with the roof. As the seal rides up/ down the tank wall, it wears. This wear allows vapours to leak into the skirt valley. Leaked vapours can then be ignited, most likely by a lightning strike, causing a fire around the entire perimeter. Rim seal fires are a concern to storage operators, but if the fire remains inside the tank it is controllable and can be quickly extinguished by foam systems. If, on the other hand, it continues unobserved, the structure of the tank may be damaged, leading to product spill, which could escalate into a full blown disaster. The solution? Terminal operators cannot afford to not have some sort of system providing early warning of fire. Linear heat detection cable is a proven fire detection system for these rim seal fire risks and has over many years been successfully used at storage terminals. Patol, as a pioneer of this technology, has been involved with linear heat detection cable systems since 1978. When it comes to fire prevention, a combination of detection systems is undoubtedly safer, giving the operator peace of mind that they are still covered even if one system fails for any reason or is involved in a maintenance (scheduled or corrective) programe. UK-based fire detection equipment supplier Patol has just launched a new groundbreaking technology development of a flame detector capable of detecting flames at distances in excess of 100 metres – further than any other technology available on the market (patent pending).

BUNCEFIELD - its impact on safety measures

Prior to Buncefield in 2005, an unconfined vapour cloud explosion from a large fuel storage tank was not considered a credible major hazard. Because of this the UK Health and Safety executive (HSE) set the consultation distance for the Buncefield site at 185 metres – the distance based on thermal radiation from a pool fire. In actual fact a large vapour cloud explosion can be more of a threat to the surrounding population than a fire. A person can retreat to safety from a fire but he cannot outrun an explosion. Since the explosion the HSE has now set a hazardous zone of 400 metres from the overflow of all Buncefield type fuel storage tanks. These larger zones can encompass more people on and off site and for some sites present a societal risk. Risk is a factor of consequence and likelihood. As the consequences of an explosion are greater than a pool fire, to maintain an acceptable level of risk additional preventative measures are required, particularly where sites present a significant societal risk. To prevent an explosion, either ignition sources must be eliminated or flammable atmospheres avoided. As the site operator has very little control over offsite ignition sources and eradicating all onsite ignition sources is extremely difficult, it is impossible to guarantee all ignition sources are eliminated. Safety cannot therefore be based on the eliminating ignition sources so instead flammable atmospheres must be avoided, by ensuring tanks are not overfilled. Best practices are detailed in the Process Safety Leadership Group (PSLG) report ‘Safety and environment standards for fuel storage tanks’.

What lies within?

earthen tanks for product warehousing, to larger and more elaborate vessels that take many shapes, sizes, and mechanisms aimed at parking, churning, insulating, and moving their precious cargo. Beginning as a simple matter of containing product awaiting further treatment processes within the facility or transmission to other locations via ship, rail, or over-theroad haulers, tank design has evolved due to many influential factors, including environmental pressures. Internal floating roof tanks are growing in popularity, either in the initial design or as retrofit projects in order to reduce emissions. The ultimate aim is to minimise – or to eliminate completely – the potential flammable vapour zone above the stored liquid as the floating roof rises and falls with the product level within. However, despite the most robust primary, secondary, and even tertiary seal design efforts, tables reveal that some dissipation of product remains a reality resulting in flammable vapour content. For many reasons emissions from any floating roof tank are never fully eliminated. These include the insurmountable aspects of available tank designs — the inherent characteristics of mechanical devices e.g. electrical connections, surface penetrations, joints, wear, friction and tolerances etc. Are tanks safer today than in 1940? Absolutely. Is the industry as a whole safer today than in 1940? Absolutely. However the industry cannot assume that facility or equipment designs can fully eliminate the potential for accidents.

Tank site remediation

Terminal owner Petroterminal de Panamá, S.A., planned to construct two largediameter internal floating roof (IFR) above ground storage tanks (AST) on shallow ringwall foundations at their Atlantic Terminal in Chiriquí Grande, Republic of Panama. Prior to construction a thorough geotechnical investigation was performed to determine the adequacy of the underlying soils to support the AST foundations. Each planned tank was 265 feet in diameter, 67 feet tall, and had a capacity of 709,400 barrels and a maximum liquid level height of ~64 feet. Initial site and soil testing US-based geotechnical construction specialist Hayward Baker completed a series of cone penetrometer soundings (CPT) and standard penetration test borings (SPT) on the site. Standard penetration test (SPT) borings revealed an upper stratum (S1) of mixed sand, silty sand, and sandy silt with occasional organic material, extending to a nominal depth of 65 feet (~EL -68 feet). This upper stratum also contained a variable layer of medium dense sand, typically within the depth range of 25 to 40 feet. A lower stratum (S2) consisted of sandy to clayey silt, soft and normally consolidated to slightly underconsolidated, extending to a nominal depth of 90 feet (~EL -93 feet). This was underlain by weathered rock and/or gravelly material. Settlement and seismic criteria Settlement and seismic design criteria were established by the tank builder Chicago Bridge & Iron Company (CB&I). Settlement tolerances were calculated using the methods outlined in API Standard 653.

Supporting tanks with controlled modulus columns

When any tank is built and put into service some amount of settlement occurs. The settlement is only problematic when it exceeds the tolerance for the tank or for the lines connected to the tank. The amount that a tank will settle is dependent on the tank loading properties (e.g., the diameter and the weight of the tank and its contents) and the properties of the underlying soils. In addition to excessive settlement, bearing capacity failure may occur where weak soils are present. This occurs when the underlying soils cannot carry the load from the tank, and the ground shears or ruptures, causing either a rotation of the tank or punching of the tank into the ground. When weak soils are present in areas that tanks are to be built, and it is not practical to change the location of the tanks, the weak ground can be replaced, bypassed with piles, or treated by a number of different ground improvement technologies. Removing and replacing soft ground with compacted backfill can be impractical or very costly when the soft ground extends below a few feet or if it is necessary to excavate below the groundwater table. For tanks, the goals of ground improvement are to reduce the total and differential settlement that occurs while tanks are in service, to increase the factor of safety against bearing capacity failure, and at some locales, to reduce the risk that the soils supporting a tank liquefy during seismic events (i.e., earthquakes).

EPA delays SPCC compliance deadline

timeconsuming and frustrating experience to evaluate regulatory changes, especially with respect to how they may affect operations. The January 2010 revisions to the Spill Prevention Control and Countermeasure (SPCC) rule (40CFR112) are no exception since they are a complex compilation of several years’ worth of proposed changes, reversed changes and basic commentary. So what is important in these revisions? Many of the changes directly reflect the SPCC Guidance for Regional Inspectors document that was published by the US Environmental Protection Agency (EPA) in December 2005. This document encompasses EPA’s wish list of how everyone should comply with the published 2002 regulations and even includes model plans for both bulk storage and production facilities. The document is helpful in understanding the regulations, as well as EPA’s goals and objectives for the program. The key elements of the recent changes that affect most facilities: • The moving target for compliance? The United States Environmental Protection Agency (EPA) has now set a November 10, 2011 deadline for final compliance with the new requirements – facilities must amend or prepare, and implement SPCC Plans by the compliance date taking into consideration all of the revisions to the SPCC rules since 2002. But of course, they have updated the deadline no less than 7 times in the past – will it happen again? Not sure, but this may be the right time to be prepared, especially since the five year mandatory amendment requirement for your plan may have already passed or be looming as well.

Leak detection in confined spaces

Coastal Oil Company has been part of the Northern California business scene since 1935 when the company was founded to blend and sell lube oil. Situated at the south end of the San Francisco Bay, the company has grown to become one of the largest distributors of petrol, diesel fuel, and lubricants in the US with over 875,000 gallons of above ground storage located on four acres in east San Jose. The specific challenge for Coastal Oil was how to retrofit an existing facility with stateof- art leak detection to monitor the soil below the above ground storage tanks while at the same time keeping the normal day-today business running smoothly. Sensor cables are a popular choice for storage facilities, although usually when tanks are spaced widely apart, which makes it easy to position the construction equipment. In this case Coastal Oil had 12 tanks relatively small in diameter, situated very close together. The standard technique for installing the sensor cable is to position slotted PVC conduit beneath the tank floor plates using horizontal boring equipment. For the Costal Oil project the limited working space proved to be a major problem.

Playing it safe

Loading terminals are busy places with trucks coming in to fill up and be on their way as quickly as possible, driving many thousands of miles per year in all weathers to deliver fuel to customers. Terminal operators have a duty of care to ensure their equipment is functional and safe. The tank truck operators have the same duty to ensure their vehicles are in good working order when they come in for loading. To ensure site safety, liquid overfill prevention and effective discharge of static electricity is a primary concern. The interface between vehicle and terminal has inherent risks that must be accounted for. What can go wrong Filling by a pre-set meter has its risks, i.e. it is all too easy to input 54,000 litres instead of 5,400 litres, or send a full load to an already partially filled compartment. Meters do not ‘know’ if the wrong data has been dialled into the system. Because all petrol tankers in the UK bottom load, an undetected overfill is not necessarily obvious until it is too late; the first sign of this is when fuel gets pushed up the vapour recovery line and cannot pass the flame arrestor, so pressure backs up and fuel flows out through the pressure relief vent on the tanker. In addition to overfill protection, static electricity must also be effectively bonded to earth. Vehicles and their cargo can generate very high amounts of static electricity through movement and agitation in transit. Effective bonding to earth is vital if flash over is to be prevented in the tanker. European standards In Europe compliance with EN13922 and VOC directive 94/63/EC is mandatory. This standard provides a failsafe platform for overfill protection systems for liquid fuels with a flash point up to 100?C excluding LPG. Alongside the long accepted API RP1004 this standard has created a safe common interface between trucks and loading gantries throughout Europe.