crude oil storage

CHAPTER ONE 1.0 INTRODUCTION

Crude oils and liquid petroleum products are transported, handled and stored in their natural liquid state. Hydrocarbon gases are transported handled and stored in both the gaseous and liquid states and must be completely confined in pipelines, tanks, cylinders or other containers prior to use. The most important characteristic of liquefied hydrocarbon gases (LHGs) is that they are stored, handled and shipped as liquids, taking up a relatively small amount of space and then expanding into a gas when used. For example, liquefied natural gas (LNG) is stored at –  at – 162°C, 162°C, and when it is released the difference in storage and atmospheric temperatures causes the liquid to expand and gasify. One gallon (3.8 l) of LNG converts to approximately 2.5 m3 of natural gas at normal temperature and pressure. Because liquefied gas is much more “concentrated” than compressed gas, more useable gas can be transported and provided in the same size container.(Kraus, 2011) Pipelines, marine vessels, tank trucks, rail tank cars and so forth are used to transport crude oils, compressed and liquefied hydrocarbon gases, liquid petroleum products and other chemicals from their point of origin to pipeline terminals, refineries, distributors and consumers. The industry also had a problem with what to do with the oil after it came out of the well. Often wooden barrels were the only containers available, and early operators used these for collecting, storing, and shipping petroleum (Figure. 1). A barrel of crude, as it remains till date for measuring petroleum, equals 42 gallons, or 0.1589 m3 (1m3 is 6.2897 bbls). Later, earthen pits were used. Handling and separation were difficult in any scale and became even more when considerable amounts of water and sand came mixed with the produced oil. Tanks slowly replaced wooden barrels, first made of wood, rivet iron, and finally bolted or welded steel. After 1920s, large advances were made in the operation of lease facilities. Petroleum engineers improved methods for oil, gas, and water separation, chemical and emulsion treatment, and water handling.

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Figure 1 Wooden barrels for storing oil produced The storage of well fluids are initially directed towards the surface, the natural flowing well head  pressure supplied by the reservoir naturally flowing well head pressure supplied by the reservoir naturally decreases. This pressure reduction allows the volume of free gas present in the fluid to increase and additionally promotes the breakout from solution of dissolved gases. Both of these reactions restrict the volume of crude oil that can be delivered to the surface. This mixture is defined as multiphase fluid. It is classified of two or more phases where one phase is a gas and atleast the other a liquid. A fluid of this type provides assurance and flow management challenges for upstream producers due to complex flow regimes that form as well as the

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undesirable contaminants (eg sand, salt sulfur,  paraffin’s  etc.) that are borne along by the  production well stream. Prior to the 1990s, the traditional way of managing multiphase fluids was to separate the liquid and gas streams at up streams batteries with the natural gas being either flare off, if the gas was of poor quality or if there was no immediate use or market for its use or in some cases boosting the gas back to a central processing facility via a second separate gas pipeline supported by a gas compressor (a similar pipeline been provided for the liquids requiring a liquid pump). Both methods were deemed harmful from an environmental impact stand point, which led to the needful development of a new line of pumping technology termed multiphase pumps. Multiphase pumps will be required to handle the raw production feed stream with no  pretreatment or conditioning of the fluid . The storage and handling of well fluids

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 petroleum industry can be explained thus: 1.1 Surface Handling of Well Fluids

As produced well fluids are initially directed towards the surface, the natural flowing well head  pressure supplied by the reservoir naturally decreases. This pressure reduction allows the volume or free gas present in the fluid to increase and additionally promotes the breakout from solution of dissolved gases. Both of these reactions restrict the v olume of crude oil that be delivered to the surface. This mixture is defined as multiphase fluid. It is comprised of two or more phases whose one phase is a gas and at least one phase is a liquid. A fluid of this type creates flow assurance and flow management challenges for upstream producers due to complex flow regimes that form as well as the undesirable contaminants (e.g sand salt, sulphur, paraffin etc.) that are borne along  by the production well streams. Prior to the 1990s the traditional way of managing multiphase fluids was to separate the liquid and gas streams at upstream batteries with the natural gas being either flared off if the gas was of  poor quality or if there was no immediate use of market for its use or in some cases bursting the gas back to a central processing facility via a second separate gas pipeline supported by a gas compressor ( a similar pipeline being provided for the liquids requiring a liquid pump ). Both methods were deemed harmful from an environmental impact standpoint which led to the needful development of a new line of pumping technology termed multiphase pumps, multiphase 3

 pumps would be required to handle the raw production fluid stream with no pre-treatment of condition of the fluid, operating in a near continuous upset mode due to the widely varying  pressure, temperature and fluid composition from the wells(www.colfaxfluidhandling.com)

1.2 Measuring and Testing Oil and Gas

Today’s technology, some very simple is capable of measuring hydrocarbons production quite accurately. We will look at how crude oil and natural gases are measured. Produced crude oil and natural gas (hydrocarbons) are measured prior to leading the well site as required by law. The gross volume from which royalty share is calculated is based on the oil and gas measurement. (a) Crude Oil Measurement The modifier crude oil is used to denote oil that comes from the earth in its raw form which generally means it contains some salt water and possibly a few other impurities-thus the term crude oil. The unit for measurement for crude oil as reported on royalty statement in the BBL. A BBL is 42 U.S gallons. The first step towards accurate crude oil measurement is to remove any free water and sediments. This is done in one of the several type of surface equipment such as free water knockout, a gun barrel separator, or a three phase separator. Following this step, the oil is now isolated and can be measured. Crude oil is measured in one of two ways depending on the aggregate volume available for measurement. For smaller volume in the range of 1-100 BOPD say the oil generally flows into an atmospheric tank and is held there until sufficient quantity is accumulated to make a run. A run is simply the act of removing the oil from the lease location and taking it off site for further treatment. When a run is ready to be made, the first step is to do a shake-out test. A sample of the oil is taken and placed in a portable centrifuge which forces entrained impurities to separate from the oil. The result will be use d to adjust the final volume on which all owners are paid. For large volume in the range of 100-1000 BOPD say the oil generally flows through an automated lacy unit, which stands for lease Automatic Custody Transfer. This system provides for the automated system sampling transfer oil from the least location into pipeline (www.mineralweb.com).

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(b) Natural gas measurement The unit of measurement for volume of natural gas is MCF or thousand cubic feet. A related unit of natural gas measurement based on the heating or energy value of natural gas is called MMBTU, or British Thermal Unit (www.mineralweb.com). The majority of producing wells measures natural gas production with an orifice style meter. Orifice meter have no moving part and are easily serviced in the field. Differential pressure and recorded as gas passes an orifice  plate, creating a pressure drop allowing for a calculation of the volume of gas passing through  pipe. Typically there will be two meters on the well one owned by the well operator and one owned by the first purchaser. This serves as a check for each other, a benefit from the royalty owner. Calculation of total gas flow is done on a monthly bases, usually by a third party gas measurement contractors. These calculations are,passed along to the operators who enters the natural gas measurement accounting system. The software through which royalty owners are  paid. (www.mineralweb.com). 1.3 WELL SERVICING AND WORK OVER

The term work over is used to refer to any kind of oil well intervention involving invasive techniques such as wire line, coiled tubing or Snubbing. More specifically though it will refer to the expensive process or pulling and replacing a completion work over rank among the most complex, difficult and expensive types of well work. They are only performed if the completion of a well is terminally unsuitable for the job at hand. The production tubing may have become damaged due to operational factors like corrosion to the point where well integrity is threatened. Down hole components such as tubing retrievable down hole safety valves, or electrical submersible pumps may have malfunctioned, needing replacement. In other circumstances, the reason for a work over may not be that the completion itself is in a  bad condition but that changing reservoir conditions make the farmer completion unsuitable. For example, a high productivity well may have been completed with 51/2 tubing to allow high flow rates (a narrower tubing would have unnecessarily choked the flow). The narrower bore makes for a more stable flow. Operation of a Work over

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The operation of any work over is based on first killing the well. Since workers are long planned in advance, there would be much time to plan the well kill and so the reverse circulation would  be common. The intense nature of this operation after requires no less than the capabilities of a drilling rig (en.wilkipedia.org). The work over begins by removing the withheld and possibly the flow line then lifting the tubing hanger from the casing head, thus beginning to pull the completion out of the well. The string will almost always be fixed in place by at least one production packer if the packer is retrievable it can be released easily enough and pulled out with the completion string. (b) Servicing Although some wells flow oil to the surface without mechanical assistance, most are in mature  production areas that require pumping or some other form of artificial lift. Pumping mature oil well characteristically require more maintenance than flowing well because of the operation of the mechanical pumping equipment installed on the well. (www.bormido.com) 1.4 TRANSPORTATION

Advances in exploration and production have helped to locate and recover a supply of oil and natural gas from major reserves across the globe. At the same time, demand are rarely concentrated in the same place. (www.api.org) Transportation therefore is vital to ensuring the reliable and affordable flow of petroleum we all count on to fuel our cars. Transportation of oil fluids and gas are made possible by pipelines/ ships at sea, trucks and railways. (a) Pipelines It is generally the case that all crude oils, natural gas, liquefied natural gas, liquefied petroleum gas (LPG) and petroleum products flow through pipelines at some time in their migration from the well to a refinery or gas plant, then to a terminal and eventually to the consumer. Aboveground, underwater and underground pipelines, varying in size from several centimeters to a meter or more in diameter, move vast amounts of crude oil, natural gas, LHGs and liquid

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 petroleum products. Pipelines run throughout the world, from the frozen tundra of Alaska and Siberia to the hot deserts of the Middle East, across rivers, lakes, seas, swamps and forests, over and through mountains and under cities and towns. Although the initial construction of pipelines is difficult and expensive, once they are built, properly maintained and operated, they provide one of the safest and most economical means of transporting these products. The first successful crude-oil pipeline, a 5-cm-diameter wrought iron pipe 9 km long with a capacity of about 800 barrels a day, was opened in Pennsylvania (US) in 1865. Today, crude oil, compressed natural gas and liquid petroleum products are moved long distances through  pipelines at speeds from 5.5 to 9 km per hour by large pumps or compressors located along the route of the pipeline at intervals ranging from 90 km to over 270 km. The distance between  pumping or compressor stations is determined by the pump capacity, viscosity of the product, size of the pipeline and the type of terrain crossed. Regardless of these factors, pipeline pumping  pressures and flow rates are controlled throughout the system to maintain a constant movement of product within the pipeline. Types of pipelines

The four basic types of pipelines in the oil and gas industry are flow lines, gathering lines, crude trunk pipelines and petroleum product trunk pipelines. 

Flow lines. Flow lines move crude oil or natural gas from producing wells to producing field storage tanks and reservoirs. Flow lines may vary in size from 5 cm in diameter in older, lower-pressure fields with only a few wells, to much larger lines in multi-well, high-pressure fields. Offshore platforms use flow lines to move crude and gas from wells to the platform storage and loading facility. A lease line is a type of flow line which carries all of the oil produced on a single lease to a storage tank.

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Gathering and feeder lines. Gathering lines collect oil and gas from several locations for delivery to central accumulating points, such as from field crude oil tanks and gas plants to marine docks. Feeder lines collect oil and gas from several locations for delivery direct into trunk lines, such as moving crude oil from offshore platforms to onshore crude trunk  pipelines. Gathering lines and feeder lines are typically larger in diameter than flow lines. 7

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Crude trunk pipelines. Natural gas and crude oil are moved long distances from  producing areas or marine docks to refineries and from refineries to storage and distribution facilities by 1- to 3-m- or larger-diameter trunk pipelines.

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Petroleum product trunk pipelines. These pipelines move liquid petroleum products such as gasoline and fuel oil from refineries to terminals, and from marine and pipeline terminals to distribution terminals. Product pipelines may also distribute products from terminals to bulk plants and consumer storage facilities, and occasionally from refineries direct to consumers. Product pipelines are used to move LPG from refineries to distributor storage facilities or large industrial users.

(b) Marine Tankers and Barges The majority of the world’s crude oil is transported by tankers from producing areas such as the Middle East and Africa to refineries in consumer areas such as Europe, Japan and the United States. Oil products were originally transported in large barrels on cargo ships. The first tanker ship, which was built in 1886, carried about 2,300 SDWT (2,240 pounds per ton) of oil. Today’s supertankers can be over 300 m long and carry almost 200 times as much oil (see figure 2). Gathering and feeder pipelines often end at marine terminals or offshore platform loading facilities, where the crude oil is loaded into tankers or barges for transport to crude trunk  pipelines or refineries. Petroleum products also are transported from refineries to distribution terminals by tanker and barge. After delivering their cargoes, the vessels return in ballast to loading facilities to repeat the sequence.(International chambers of shipping,1978)

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Figure 2. SS Paul L. Fahrney oil tanker. (Source: American petroleum institute) Liquefied natural gas is shipped as a cryogenic gas in specialized marine vessels with heavily insulated compartments or reservoirs (see figure 3). At the delivery port, the LNG is off-loaded to storage facilities or regasification plants. Liquefied petroleum gas may be shipped both as a liquid in uninsulated marine vessels and barges and as a cryogenic in insulated marine vessels. Additionally, LPG in containers (bottled gas) may be shipped as cargo on marine vessels and  barges.

Figure 3. LNG Leo tanker loading at Arun, Sumatra, Indonesia. (source: American petoroleum institute)

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(c ) Motor Vehicle and Railroad Transport of Petroleum Products

Crude oil and petroleum products were initially transported b y horse-drawn tank wagons, then b y railroad tank cars and finally by motor vehicles. Following receipt at terminals from marine vessels or pipelines, bulk liquid petroleum products are delivered by non-pressure tank trucks or rail tank cars directly to service stations and consumers or to smaller terminals, called bulk  plants, for redistribution. LPG, gasoline anti-knock compounds, hydrofluoric acid and many other products, chemicals and additives used in the oil and gas industry are transported in  pressure tank cars and tank trucks. Crude oil may also be transported by tank truck from small  producing wells to gathering tanks, and by tank truck and railroad tank car from storage tanks to refineries or main pipelines. Packaged petroleum products in bulk bins or drums and pallets and cases of smaller containers are carried by package truck or railroad box car. 

Railroad tank cars

Railroad tank cars are constructed of carbon steel or aluminum and may be pressurized or unpressurized. Modern tank cars can hold up to 171,000 l of compressed gas at pressures up to 600 psi (1.6 to 1.8 mPa). Non-pressure tank cars have evolved from small wooden tank cars of the late 1800s to jumbo tank cars which transport as much as 1.31 million liters of product at  pressures up to 100 psi (0.6 mPa). Non-pressure tank cars may be individual units with one or multiple compartments or a string of interconnected tank cars, called a tank train. Tank cars are loaded individually, and entire tank trains can be loaded and unloaded from a single point. Both  pressure and non-pressure tank cars may be heated, cooled, insulated and thermally protected against fire, depending on their service and the products transported. All railroad tank cars have top- or bottom-liquid or vapour valves for loading and unloading and hatch entries for cleaning. They are also equipped with devices intended to prevent the increase of internal pressure when exposed to abnormal conditions. These devices include safety relief valves held in place by a spring which can open to relieve pressure and then close; safety vents with rupture discs that burst open to relieve pressure but cannot reclose; or a combination of the two devices. A vacuum relief valve is provided for non-pressure tank cars to prevent vacuum formation when unloading from the bottom. Both pressure and non-pressure tank cars have

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 protective housings on top surrounding the load ing connections, sample lines, thermometer wells and gauging devices. Platforms for loaders may or may not be provided on top of cars. Older non-pressure tank cars may have one or more expansion domes. Fittings are provided on the  bottom of tank cars for unloading or cleaning. Head shields are provided on the ends of tank cars to prevent puncture of the shell by the coupler of another car during derailments. 

Tank trucks

Petroleum products and crude oil tank trucks are typically constructed of carbon steel, aluminum or a plasticized fiberglass material, and vary in size from 1,900-l tank wagons to jumbo 53,200-l tankers. The capacity of tank trucks is governed by regulatory agencies, and usually is dependent upon highway and bridge capacity limitations and the allowable weight per axle or total amount of product allowed. There are pressurized and non-pressurized tank trucks, which may be non-insulated or insulated depending on their service and the products transported. Pressurized tank trucks are usually single compartment, and non-pressurized tank trucks may have single or multiple compartments. Regardless of the number of compartments on a tank truck, each compartment must be treated individually, with its own loading, unloading and safety-relief devices. Compartments may be separated by single or double walls. Regulations may require that incompatible products and flammable and combustible liquids carried in different compartments on the same vehicle be separated by double walls. When pressure testing compartments, the space between the walls should also be tested for liquid or vapour. Tank trucks have either hatches which open for top loading, valves for closed top- or bottomloading and unloading, or both. All compartments have hatch entries for cleaning and are equipped with safety relief devices to mitigate internal pressure when exposed to abnormal conditions. These devices include safety relief valves held in place by a spring which can open to relieve pressure and then close, hatches on non-pressure tanks which pop open if the relief valves fail and rupture discs on pressurized tank trucks. A vacuum relief valve is provided for each non pressurized tank truck compartment to prevent vacuum when unloading from the bottom. Non pressurized tank trucks have railings on top to protect the hatches, relief valves and vapour

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recovery system in case of a rollover. Tank trucks are usually equipped with breakaway, selfclosing devices installed on compartment bottom loading and unloading pipes and fittings to  prevent spills in case of damage in a rollover or collision. 1.5 STORAGE TANKS

There are a number of different types of vertical and horizontal aboveground atmospheric and  pressure storage tanks in tank farms, which contain crude oil, petroleum feedstocks, intermediate stocks or finished petroleum products. Their size, shape, design, configuration, and operation depend on the amount and type of products stored and company or regulatory requirements. Aboveground vertical tanks may be provided with double bottoms to prevent leakage onto the ground and cathodic protection to minimize corrosion. Horizontal tanks may be constructed with double walls or placed in vaults to contain any leakage. Atmospheric cone roof tanks

Cone roof tanks are aboveground, horizontal or vertical, covered, cylindrical atmospheric vessels. Cone roof tanks have external stairways or ladders and platforms, and weak roof to shell seams, vents, scuppers or overflow outlets; they may have appurtenances such as gauging tubes, foam piping and chambers, overflow sensing and signaling systems, automatic gauging systems and so on. When volatile crude oil and flammable liquid petroleum products are stored in cone roof tanks there is an opportunity for the vapour space to be within the flammable range. Although the space between the top of the product and the tank roof is normally vapour rich, an atmosphere in the flammable range can occur when product is first put into an empty tank or as air enters the tank through vents or pressure/vacuum valves when product is withdrawn and as the tank  breathes during temperature changes. Cone roof tanks may be connected to vapour recovery systems.

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Conservation tanks

These are a type of cone roof tank with an upper and lower section separated by a flexible membrane designed to contain any vapour produced when the product warms up and expands due to exposure to sunlight in the daytime and to return the vapour to the tank when it condenses as the tank cools down at night. Conservation tanks are typically used to store aviation gasoline and similar products.

Atmospheric floating roof tanks

Floating roof tanks are aboveground, vertical, open top or covered cylindrical atmospheric vessels that are equipped with floating roofs. The primary purpose of the floating roof is to minimize the vapour space between the top of the product and the bottom of the floating roof so that it is always vapour rich, thus precluding the chance of a vapour-air mixture in the flammable range. All floating roof tanks have external stairways or ladders and platforms, adjustable stairways or ladders for access to the floating roof from the platform, and may have appurtenances such as shunts which electrically bond the roof to the shell, gauging tubes, foam  piping and chambers, overflow sensing and signaling systems, automatic gauging systems and so on. Seals or boots are provided around the perimeter of floating roofs to prevent product or vapour from escaping and collecting on the roof or in the space above the roof. Floating roofs are provided with legs which may be set in high or low positions depending on the type of operation. Legs are normally maintained in the low position so that the greatest possible amount of product can be withdrawn from the tank without creating a vapour space between the top of the product and the bottom of the floating roof. As tanks are brought out of service prior to entry for inspection, maintenance, repair or cleaning, there is a need to adjust the roof legs into the high position to allow room to work under the roof once the tank is empty. When the tank is returned to service, the legs are readjusted into the low position after it is filled with product. Aboveground floating roof storage tanks are further classified as external floating roof tanks, internal floating roof tanks or covered external floating roof tanks. 13

External (open top) floating roof tanks   are those with floating covers installed on open-top

storage tanks. External floating roofs are usually constructed of steel and provided with pontoons or other means of flotation. They are equipped with roof drains to remove water, boots or seals to  prevent vapour releases and adjustable stairways to reach the roof from the top of the tank regardless of its position. They may also have secondary seals to minimize release of vapour to the atmosphere, weather shields to protect the seals and foam dams to contain foam in the seal area in case of a fire or seal leak. Entry onto external floating roofs for gauging, maintenance or other activities may be considered confined-space entry, depending on the level of the roof  below the top of the tank, the products contained in the tank and government regulations and company policy. Internal floating roof tanks usually are cone roof tanks which have been converted by

installing buoyant decks, rafts or internal floating covers inside the tank. Internal floating roofs are typically constructed of various types of sheet metal, aluminum, plastic or metal-covered  plastic expanded foam, and their construction may be of the pontoon or pan type, solid buoyant material, or a combination of these. Internal floating roofs are provided with perimeter seals to  prevent vapour from escaping into the portion of the tank between the top of the floating roof and the exterior roof. Pressure/vacuum valves or vents are usually provided at the top of the tank to control any hydrocarbon vapours which may accumulate in the space above the internal floater. Internal floating roof tanks have ladders installed for access from the cone roof to the floating roof. Entry onto internal floating roofs for any purpose should be considered confinedspace entry. Covered (external) floating roof tanks  are basically external floating roof tanks that have been

retrofitted with a geodesic dome, snow cap or similar semi-fixed cover or roof so that the floating roof is no longer open to the atmosphere. Newly constructed covered external floating roof tanks may incorporate typical floating roofs designed for internal floating roof tanks. Entry onto covered external floating roofs for gauging, maintenance or other activities may be considered confined-space entry, depending on the construction of the dome or cover, the level of the roof below the top of the tank, the products contained in the tank and government regulations and company policy.

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1.6 FUEL OIL STORAGE AND HANDLING PROBLEM Water is a predominant factor in a number of problems faced when using heavy oils. Water not

only comes from condensation, ground seepage and leaky heating coils in storage, but also from the Load On Top procedure used by today’s marine tankers in transporting fuel oils. The LOT  procedure means loading the oil cargo on top of the salt water ballast. Inevitably, a portion of the  ballast water is dispersed in the oil, and is delivered along with the oil. Salt water is one of the sources of fireside slagging. Salt itself often forms a slag, especially on

super-heater tubes. The sodium in the salt encourages sodium vanadate and sodium sulfate formation, both of which may deposit slag. Tank bottom corrosion   is caused by water, salt, acidic constituents of the oil (largely sulfur

compounds) and bacterial growth in the tank. The bacterial growths produce acid and accelerate metal corrosion. Bacterial slime masses and viscous oil/water emulsions  can be drawn into the fuel distribution

system with resultant clogging of lines, strainers, preheaters and burners. Such conditions interfere with proper flow and heating of the oil so that good atomization is not obtained. Combustion efficiency is reduced with the formation of sticky coke residue (made up of carbon, heavy hydrocarbons, and ash) which adheres to tube and refractory surfaces. While the carbon may burn out in the combustion zone, the deposits remain and act as adsorbents for other oil-ash constituents and a reaction site where sulfur and vanadium gases can form condensable compounds that may build up into corrosive slags in the cooler parts of the boiler. Typical sludge is made up of viscous water-oil emulsions and slime, heavy hydrocarbons, and

oxidation residues from unsaturated hydrocarbons in the oil. Heavy hydrocarbons in residual fuels have increased substantially in recent years because of the high demand for gasoline and jet fuel. Intensive refining processes have reduced the percentage of residual obtained from a barrel of crude to approximately 5% from its previous level of about 20%. This has led not only to the formation of extremely heavy long-chain hydrocarbons but also to a greater tendency toward instability in the residual oil. 15

Manual cleaning of tanks, strainers, preheaters and burners  is expensive, but the increased

fuel consumption caused by sludge accumulations is even more costly. Sludge on burners  prevents proper atomization and destroys the flame pattern; this encourages buildup of fireside deposits, may cause serious flame impingement and tube overheating, generally reduces boiler efficiency, and adds to maintenance and fuel costs. Sludge in oil heaters leads to difficulty in m a i n t a i n i n g p r o p e r p r e h e a t f o r atomization; excessive steam or electricity may be needed to maintain preheat or, in extreme cases, it may not be possible to maintain the preheat temperature at all. The fuel cannot be atomized adequately by the burner and the larger fuel  particles that are formed are thermally cracked before complete gasification occurs. Heavy hydrocarbons that are formed by cracking often form coke rather than burning completely. An even flow of homogeneous fuel to the burners helps to assure proper preheat and good atomization with a minimum of coke formation.

Figure 4 Burner wall

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Figure 5 Preheater

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REFERENCE

American National Standards Institute (ANSI). 1967. Illumination. ANSI A11.1-1967. New York: ANSI. Anton, DJ. 1988. Crash dynamics and restraint systems. In Aviation Medicine, 2nd edition, edited by J Ernsting and PF King. London: Butterworth. International Chamber of Shipping. 1978. International Safety Guide for Oil Tankers and Terminals. London: Witherby. International Labour Organization (ILO). 1992. Recent Developments in Inland Transportation. Report I, Sectoral Activities Programme, Twelfth Session. Geneva: ILO. — . 1996. Accident Prevention on Board Ship at Sea and in Port. An ILO Code of Practice. 2nd edition. Geneva: ILO. Kraus Richard 2011 storage and transportation of crude oil naturalgas, liquid petroleum products and other chemicals www.api.org-home oil and Natural gas overview/ june 13th  2014 www.bormido. com/services workshop june 12th 2014 www.enwikipedia.org/wiki/workover , june 12th  2014 www.mineralweb.com/measurement/june 13th 2014

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