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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Chapter 13 – Oil Storage

George H. Stilt, CB&I

Pgs. 505-523

ISBN 978-1-55563-118-5
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Production, refining, and distribution of petroleum products require many different types and sizes of storage tanks. Small bolted or welded tanks might be ideal for production fields while larger, welded storage tanks are used in distribution terminals and refineries throughout the world.

Product operating conditions, storage capacities, and specific design issues can affect the tank selection process. This chapter discusses the types of storage tanks most commonly used with emphasis on welded construction. General guidelines are provided that aid in the selection of the correct tank.

References to various codes, standards, and recommended practices supplement the material provided in this chapter. Owners and operators should contact manufacturers directly for questions on specific design or operating issues for a particular type of storage tank.

Storage Tanks

Types of Storage Tanks

Storage tanks come in all sizes and shapes. Special applications might require tanks to be rectangular, in the form of horizontal cylinders, or even spherical in shape. Horizontal cylinders and spheres are generally used for full pressure storage of hydrocarbon or chemical products. For the purpose of this chapter, we focus on the atmospheric or low-pressure storage tank widely used from the production fields to the refinery.

The most common shape used is the vertical, cylindrical storage tank. Gross capacities can range from 100 bbl to over 1.5 MMbbl in a single storage tank. Corresponding tank sizes range from approximately 10 ft in diameter to over 412 ft in diameter for some of the largest floating-roof tanks ever constructed.

Fig. 13.1 shows a 312-ft diameter floating-roof storage tank for crude oil storage at a large refinery. The photograph was taken during construction and shows the single deck, pontoon-style external floating roof.

Production Tanks—Construction Practices. The type of construction selected for a storage tank depends on the size of tank required and might be dependent on the type of product being stored, the location and space available for storage, prevailing weather or site-specific conditions, and local safety or environmental considerations.

Riveted, Bolted, and Shop-Welded Tanks. Although the earliest storage tanks used by the petroleum industry were constructed from various types of wood, we will concern ourselves with tanks fabricated from steel or optional nonmetallic materials. Before the development and perfection of welding processes, petroleum storage tanks used either bolted or riveted construction techniques. The tanks would be designed and supplied as segmental elements for final assembly on site.

Riveted tanks dating back to the early 1900s can still be found around the world—many still in service. It is safe to say, however, that recurring maintenance costs and increased environmental and safety concerns dictate that older riveted tanks be replaced with new, state-of-the-art storage tanks.

However, bolted tanks are still used, especially in the smaller sizes typical of produced liquid storage. The fourteenth edition of American Petroleum Institute (API) Spec. 12B, Bolted Tanks for Storage of Production Liquids provides standard designs for capacities from 100 bbl to 10,000 bbl. Current suppliers of bolted tanks can provide capacities up to 40,000 bbl or more depending on the storage application.

Generally, bolted tanks are fabricated either from 12- or 10-gauge steel or several nonmetallic materials. If not galvanized or furnished with a protective coating for corrosion protection, bolted steel construction might not have the expected service life provided by welded-steel tanks. Welded-steel tanks are constructed of thicker plate materials that can be designed to provide some corrosion allowance.

One alternative to bolted construction is the shop welded storage tank. The size and capacities of this type of tank are limited primarily by the method of transportation used to transfer the shop built tank to the final production site. The eleventh edition of API Spec. 12F, Shop Welded Tanks for Storage of Production Liquids provides standard designs for capacities of 90 to 500 bbl. Table 13.1 presents a partial listing of the standard sizes specified in API Spec. 12F. In this table, "working capacity" refers to the maximum amount of oil that can be stored between the oil outlet and the overflow connection.

Shop-welded storage tanks provide the production industry with tanks of adequate safety and reasonable economy for use in the storage of crude petroleum and other liquids commonly handled by the production segment of the industry. A shop-fabricated tank is tested for leaks in the shop, so it is ready for use once it arrives on site. Tanks are transferred from the truck to the final location on site; completed piping connections and the tank is then ready to be brought on line.

A second alternative for bolted construction is the shop fabricated or field assembled nonmetallic storage tank. Nonmetallic tanks customarily are constructed from plastic materials. These have the advantage of being noncorroding, durable, low-cost, and lightweight. Probably the most common type used is the fiberglass reinforced plastic (FRP) tank. FRP tanks are suitable for outdoor as well as indoor applications. Refer to API Spec. 12P, Fiberglass Reinforced Plastic Tanks for minimum requirements for the design, fabrication, and testing of fiberglass reinforced plastic tanks.

The temperature limits of plastic tanks are approximately 40 to 150°F. Because plastic tanks are considered to degrade more quickly than metal tanks when exposed to fire, some operators prohibit the use of plastic tanks in hydrocarbon service.

Color must be added to the outer liner for protection against ultraviolet radiation. The inner liner must be selected for compatibility with the product stored. Protection from mechanical abuse such as impact loads is necessary. Good planning dictates that plastic storage should not be located next to flammable storage tanks. Special attention should be given to local codes, ordinances, and provisions for insurance relative to storing a flammable product in a flammable container.

Field-welded storage tanks. Field-welded storage tanks easily meet industry needs for increased storage capacity whether at a remote production site, at the refinery, or at the marketing terminal. As noted, earlier single-tank capacities have exceeded 1.5 MMbbl of storage with tank diameters of 412 ft and shell heights exceeding 72 ft.

As with the smaller bolted storage tanks, API standards have been developed and improved over the years to ensure the tanks meet the safety and operating needs of the petroleum industry. The tenth edition of API Spec. 12D, Field Welded Tanks for Storage of Production Liquids provides standard sizes with nominal capacities from 500 to 10,000 bbl for the production sector.

When larger tanks are required, the industry can refer to the tenth edition of API Standard 650, Welded Steel Tanks for Oil Storage for material, design, fabrication, erection, and testing requirements. The standard covers open-top or fixed-roof storage tanks that generally operate at atmospheric pressures. Design pressures above atmospheric and design temperatures exceeding 200°F may be permitted when additional requirements are met. Table 13.2 shows the capacity of welded storage tanks as a function of diameter and height.

Current Storage Options

The petroleum industry has experienced significant changes in the types of products used to feed the refineries around the world. The increased use of petroleum products has prompted the industry to turn to other sources for supply. Changes in product, physical, and chemical properties impose new challenges to the storage tank industry. Environmental and safety requirements continue to be a significant factor in the selection and design of the storage tanks used by the petroleum industry.

The general types of atmospheric storage tanks (AST) in use may be open top tanks (OTT), fixed-roof tanks (FRT), external floating-roof tanks (EFRT), or internal floating-roof tanks (IFRT). Depending on the product, a closed floating-roof tank (CFRT) may even be selected.

The aboveground storage tank has evolved with time. Fig. 13.2 illustrates this trend, which has emphasized improved safety and improved product loss control. Production facilities generally rely on either open-top tanks or fixed-roof tanks operating at or slightly above atmospheric pressure.

Open-Top Tanks. The OTT was one of the first tanks used to store petroleum products. While it provides liquid containment, direct exposure of the liquid surface to the atmosphere assures high evaporative losses, product odors, and increased potential for fires. The OTT has only limited use, primarily for collection of contaminated run-off or wash water and wastewater processes.

Fixed-Roof Tanks. The FRT provides improved containment of product vapors and reduces the potential for fires. The FRT still exposes the liquid surface to the tank vapor space, producing significant product evaporative losses. This increases the possibility of forming a combustible gas mixture in the vapor space for certain more volatile petroleum products. For this reason fixed-roof tanks in refineries are generally used for products with vapor pressures less than 1.5 psia.

Fixed-roof tanks are common in production facilities to store hydrocarbons with vapor pressures close to atmospheric pressure. In this use, they should be equipped with pressure-vacuum valves and purged with natural gas to eliminate air intake into the vapor space. Product evaporative losses can be high especially when crude is added to the tank and vapors are expelled through the pressure vent valve.

In crude oil terminals and pumping stations, internal floating roofs may be added to the fixed-roof tank to reduce product vapor losses if the crude oil has been stabilized to vapor pressures less than 11 psia. Examples of fixed-roof tanks are shown in Fig. 13.3.

The most common fixed-roof design contains a shallow cone roof utilizing a single center column plus internal (or external) framing to support the roof plates. Intermediate columns are used for diameters greater than 120 ft. Designs may include a frangible roof joint for added protection in the event of a sudden increase in internal pressure. In this case the design pressure is limited to the equivalent pressure of the dead weight of the roof plates including structural rafters. Other fixed-roof designs such as the self-supporting dome roof or umbrella roof may be used if storage pressures exceed the capabilities of the cone roof design. Depending on the size (diameter) of the tank, API Standard 650, Appendix F designs can permit internal pressures up to 2.5 psig. If operating pressures exceed 2.5 psig, API Standard 620, Design and Construction of Large, Low-Pressure Storage Tanks provides design procedures for internal pressures up to 15 psig.

Pressure-Vacuum Valves

The evolution of hydrocarbon vapors is dependent on the product’s physical characteristics, the operating pressure of upstream equipment, tank storage conditions, and tank operations. In production operations, the fluid entering a tank often comes from a higher-pressure source (separator, treater, or other production vessel). As the fluid enters the tank, a portion of the fluid will "flash" to vapor. Depending on tank design, vapors may be directed through pressure vent valves directly to a vent or lighted flare. Alternatively, a vapor recovery compressor (or blower) may be installed to direct vapors vented from storage to downstream compressors for sales or injection. Vacuum relief valves are needed to keep a vacuum from occurring because of tank breathing and pumping operations. If a vacuum develops, the tank roof will collapse. Typically, both pressure and vacuum relief are combined in a single pressure-vacuum relief valve such as that shown in Fig. 13.4.

Gauge Hatches

Fixed-roof tanks should have a quick opening gauge hatch in the roof, which allows the operator access to the tank to "gauge" the tank, determine if water is present, measure the height of the oil/water interface, and take samples of the crude oil. The gauge hatch can be weighted in such a way as to work as a backup pressure or pressure-vacuum relief device to the primary pressure-vacuum valve.

Standards for manual gauging of petroleum and petroleum products are given in the API Manual of Petroleum Measurement Standards, Chap. 3.1 A. "Gauging" includes measuring the amount of liquid contained in the tank as well as determining the temperature of the liquid and obtaining representative samples.

Tank Breathing

When a volatile product is stored in a freely ventilated fixed-roof tank, the concentration of volatile vapors in the vapor space can vary depending on the tank operating conditions. During holding periods, when no liquid is added or removed from the tank, the vapor space comes to equilibrium conditions based on product temperature and vapor pressure.

Emissions during holding are generated by the vapor space breathing process. As a result of daily ambient heating and cooling processes or changes in barometric pressure, the air/vapor mixture in the vapor space expands and contracts. During the daily heating process, some of the air/vapor mixture is expelled from the tank, resulting in evaporative emissions. During product cooling, air is drawn into the vapor space and becomes saturated with product vapor from natural evaporation. The air becomes saturated with product vapors. Note that this can result in a combustible gas mixture in the vapor space, increasing the fire risk.

Filling/Pumping Operations

Normal tank filling and pumping operations also affect the vapor space of a fixed-roof tank. When product is removed from the tank, air is drawn into the vapor space as liquid is removed, creating a hazard. During the holding period before the next tank filling operation, evaporative breathing losses increase because of the increased volume of the vapor space. When product is added to the tank, the increasing liquid volume displaces the air/vapor mixture through the tank vent, resulting in significant evaporative emissions.

Gas Blanketing Systems

As long as the product vapor pressure is low (below 1.5 psia), it is considered safe practice to use a freely ventilated fixed-roof tank. For production tanks or other applications in which vapor pressure of the incoming liquid normally exceeds atmospheric pressure at normal ambient temperatures, a gas blanketing system is required to maintain a positive tank pressure and minimize the chance of air being drawn into the tank vapor space. During periods of no inflow, the tank breathing process alone could cause air to flow into the tank through the pressure-vacuum valve and form an explosive mixture.

A gas blanketing system includes a suitable supply of natural gas and a pressure regulator that operates as needed to maintain the tank pressure at a predetermined level. During the heat of the day, as pressure increases, the regulator closes. If pressure continues to rise, the pressure vent opens to relieve tank internal pressure by venting vapors (blanket gas + product vapor) to atmosphere or some downstream vapor recovery process. Note that a vacuum relief still must be used to protect the tank against vacuum should the gas blanketing system fail.

Fire Exposure

Out breathing, resulting from fire exposure, may exceed the design venting rate based on normal operating conditions. In such cases, the construction details of the tank determine whether additional venting is required.

On fixed-roof tanks, where the roof-to-shell attachment is constructed in accordance with API Standard 650, Sec., the roof-to-shell joint may be considered frangible, and in the event of excessive internal pressure may fail before failure occurs in the tank-shell joints or the shell-to-bottom joint. In tanks built in this manner, consideration need not be given to any additional requirements for emergency venting if the tank is isolated from other equipment and loss of the roof during emergency conditions is acceptable.

On tanks that do not follow the frangible joint details, design procedures are provided in the API Standard 2000 for calculating the required venting capacity for fire exposure.

Vent System Design

Safety should be a primary concern when selecting a storage tank vent system for a specific application. In production operations, this normally means that a safe way of handling vapors that evolve from the liquid must be designed into the system, and air must be excluded from entering the tank and mixing with hydrocarbon in the vapor space. Fixed-roof tanks should be configured to operate with a suitable gas blanketing system that maintains the tank at positive pressures under all operating conditions. Specially designed pressure/vacuum vent valves should be provided to protect the tank against overpressure or vacuum conditions.

Tank vent piping should include flame arrestors such as that shown in Fig. 13.5, which protect the tank against ignition of the vent gases owing to lightning strike or a discharge of static electricity at the vent location. Where the vent piping is routed to a lit flare system, a constant bleed of purge gas into the vent is required in addition to a flame arrestor. More complex flow devices, such as fluidic seals and molecular seals, are available from several manufacturers to minimize the amount of purge gas needed to assure the flame is not sucked back into the vapor space.

Fixed-roof tanks will fail if exposed to excessive internal pressure or extreme vacuum conditions. Regular maintenance of pressure/vacuum vent valves and flame arrestors is critical to the safe operation of any fixed-roof tank. In oil fields, crude oil service flame arrestors can become plugged. A separate pressure/vacuum valve (or specially weighted gauge hatch) set at higher pressures and vacuums than the primary should be installed without a flame arrestor. In the event the flame arrestor becomes plugged, it is better to operate without a flame arrestor then to blow off the roof of the tank.

Many design and operating conditions must be considered when designing a vent piping system. Larger vents may be required on tanks storing heated products or tanks that receive products from a source subject to a surge in pressure or flow. The pressure drop owing to flame arrestors or other vent restrictions must be considered to assure that under design vent conditions the pressure in the tank remains less than the tank design pressure.

Design recommendations can be found in the fifth edition of API Standard 2000 , Venting Atmospheric and Low-Pressure Storage Tanks covering nonrefrigerated and refrigerated storage. The standard presents design guidelines for the determination of venting requirements and types of vents that may be used under normal tank operations and possible emergency conditions (fire exposure).

When provided, tank vents should be sized to protect the tank against unusually high internal pressures (venting required) or low pressure vacuum conditions (in breathing or vapor makeup required). Normal operating conditions include:
  • In breathing (vacuum) resulting from maximum outflow of product from the tank.
  • In breathing (vacuum) resulting from contraction of vapors caused by a maximum decrease in atmospheric temperature.
  • Out breathing (pressure) resulting from flashing of hydrocarbons as liquid flows from a higher pressure source into the tank. In production operations this can be the largest source of vent vapors. The flow rate is process specific and not addressed in the API Standard 2000.
  • Out breathing (pressure) resulting from maximum inflow of product into the tank, hydrocarbon flash vapors, and maximum product evaporation caused by the inflow.
  • Out breathing (pressure) resulting from expansion and evaporation caused by a maximum increase in atmospheric temperature.
  • Out breathing (pressure) resulting from fire exposure.

Floating-Roof Tanks

Although not normally used in production operations, floating-roof tanks are often used in pump stations or terminals where the crude oil has been stabilized to a vapor pressure of less than 11.1 psia.

Product Loss Management and Safety Considerations for Floating-Roof Tanks

When product vapor pressure is greater than 0.5 psia (more in some states) but less than 11.1 psia, the U.S. Environmental Protection Agency permits the use of a floating-roof as the primary means of vapor control from the storage tank. Floating-roof tanks are not intended for all products. In general, they are not suitable for applications in which the products have not been stabilized (vapors removed). The goal with all floating-roof tanks is to provide safe, efficient storage of volatile products with minimum vapor loss to the environment.

Design requirements for external floating roofs are provided in Appendix C of the API Standard 650. The external floating roof floats on the surface of the liquid product and rises or falls as product is added or withdrawn from the tank.

The internal floating roof tank (IFRT) was developed in the mid-1950s to provide protection of the floating roof from the elements, including lightning strikes to the floating roof. The tank vapor space located above the floating roof and below the fixed-roof includes circulation vents to allow natural ventilation of the vapor space reducing the accumulation of product vapors and possible formation of a combustible mixture. Fig. 13.6 shows a typical internal floating-roof tank.

The closed floating roof tank (CFRT) is similar to an IFRT. It uses an internal floating roof but eliminates natural ventilation of the tank vapor space. Instead, the CFRT is equipped with a pressure-vacuum (PV) vent and may even include a gas blanketing system such as that used with fixed-roof tanks. Emissions from a CFRT are virtually the same as those from an IFRT, however, can be easily collected for further treatment if necessary. One such closed roof tank for benzene storage with associated vapor recovery equipment is shown in Fig. 13.7.

Floating-Roof Tank Net-Working Capacity

Determining what tank size is required for the desired net storage capacity must consider several factors. Internal or external floating-roof tank shell height must account for the space required by the floating roof as shown in Fig. 13.8.

The tank working capacity is obtained by operating a floating-roof tank between the maximum high gauge and recommended low landing position for the specific floating-roof tank design. A floating roof should be landed only if the tank is to be removed from service for routine inspection or maintenance activities. Landing the floating roof during normal tank operations should be avoided. Product losses increase whenever the roof is not in complete contact with the liquid surface.

In general, floating-roof tanks have been used only at terminal or refinery locations where larger storage capacities are needed. Increased emphasis on the control of evaporative emissions from storage tanks might change the roll of floating-roof tanks in the future with the increased use in smaller tanks. Internal floating roofs have been used in tanks as small as 15 ft in diameter to minimize product losses.

Product Vapor Control with Floating-Roof Tanks

In general, the floating roof covers the entire liquid surface except for a small perimeter rim space. Under normal floating conditions, the roof floats essentially flat and is centered within the tank shell. There should be no vapor space underneath a welded-steel floating roof. Under normal conditions, the amount of product vapor that might become trapped beneath the floating roof should be insignificant. However, if large quantities of flash vapor or other noncondensable vapors become trapped, the floatation stability of the roof can be affected. These conditions should be avoided if possible.

It is important to understand how a floating roof works and why details are so important in the design of a floating-roof storage tank. The study of evaporative emissions from storage tanks and possible methods to control or eliminate these emissions has been the focus of an extensive series of analytical studies, field, and laboratory testing programs sponsored by the American Petroleum Institute.

API Publications 2517 (EFRT), 2518 (FRT), and 2519 (IFRT) summarized methods for calculating evaporative losses from the storage and handling of petroleum liquids. These were first published in 1962 and then updated in 1991. Most recently, Publications 2517 and 2519 were consolidated in April 1997 in "Evaporative Loss From Floating-Roof Tanks," Chap. 19.2 of the API Manual of Petroleum Measurement Standards.

The new publication updates the evaporative loss estimation procedures for EFRTs, IFRTs, and CFRTs. The results continue to be used as the basis for the U.S. Environmental Protection Agency (U.S. EPA) publication on air pollution emission factors.

It has been demonstrated that evaporative emissions from a fixed-roof tank can be reduced by over 98% through the use of a properly designed and maintained external floating roof tank, assuming the same product and ambient conditions.

Evaporative emissions, although greatly reduced, cannot be entirely eliminated. Normal practice is to use floating-roof tanks only to store products that are considered "stabilized" such that large quantities of vapor will not be introduced underneath the floating roof. In cases when the product entering the tank is at a condition that produces flashing conditions, vapors produced will be captured underneath the floating roof. Evaporation and associated product losses still occur from the rim space, standard roof deck fittings, product that remains on the tank shell, and tank operations that require the tank to be emptied and the floating roof landed on its supports.

Tank Appurtenances

Tanks may include a variety of appurtenances depending on the storage application, owner requirements, and applicable design codes. In addition to normal product fill and withdrawal connections, access man-ways and various instrument or gauging connections, a tank can include shell-mounted mixers, internal heaters, platforms, ladders, and pressure/vacuum relief vents.

Floating-roof tanks require special attention to details because many can affect safe operation of the floating roof. In external floating-roof tanks, be sure that the rim seals, rolling ladder, and roof drain(s) are designed to minimize any unbalanced loads in the floating roof structure. Each floating roof should include a single antirotation device designed to limit the rotation of the floating roof while it is free to move up or down within the tank shell.

Some features are required for safe operation of the floating roof while others may be optional based on specific storage requirements. Many of these features affect the low operating levels of the floating roof. Optional details are available to address many of these interference issues, enabling a qualified designer to minimize the product heel while maximizing the working capacity of a floating-roof tank. Figs. 13.9 and 13.10 identify several features that must be considered when designing the floating-roof tank.

Controlling Liquid Leaks from Tanks

Liquid loss from a storage tank is generally caused by localized material failure in the form of localized corrosion. Tank bottom leaks can be a result of improper foundation design or operating a tank outside the recommended design pressure or temperature boundaries. Product liquid leakage remains a significant environmental concern. Any tank used to contain a hydrocarbon product can be prone to develop leaks sometime during the service life. Tank design options that reduce the risk of a leak can be considered, or in the event of a leak, any product that escapes is contained and detected in a realistic time frame.

Design options are generic with respect to the type of storage tank. Similar details are used on fixed-roof and floating-roof tanks alike. Options considered by most tank owners include internal and external corrosion protection and bottom cathodic protection systems. Secondary containment and detection systems are also considered an essential part of a tank installation.

Tank Corrosion Protection–Coatings. A primary method used to protect metal surfaces against surface corrosion is to apply a suitable coating. Exterior surfaces generally require protection only from the elements, although in some chemical production plants, chemical vapors can be prevalent in the atmosphere and might impact selection of the coating material. Applying a suitable primer and topcoat per manufacturer’s recommendations normally provides adequate protection of the external tank surfaces at onshore locations. More elaborate multicoat epoxy-based paint systems are used at offshore locations.

Internal surfaces can be more problematic. Water and other corrosive products naturally collect on the bottom. In many cases, only the bottom and 18 to 24 in. of the shell are coated.

Various types of coatings are used depending on the service requirements stipulated in the coating specification. Some of the more common coatings that remain in use in petroleum storage are coal tar, various two-part epoxy paints, and conventional fiberglass coatings. Internal flexible liners may be used for the most severe product applications.

For tanks in petroleum service, internal cathodic protection in conjunction with coatings has not gained widespread use. Under certain conditions, it can be effective in protecting against corrosion at holidays in the coating. More detailed information on internal cathodic protection is available in the National Association of Corrosion Engineers (NACE) RP05-75 and RP03-88.

External Corrosion Control with Cathodic Protection. Corrosion of the steel tank bottom may be reduced or eliminated with proper application of cathodic protection. Systems may be used in new tank construction or may be added to an existing structure when the original bottom is replaced.

With cathodic protection systems, the entire bottom surface acts as the cathode of an electrochemical cell. Two methods currently used to protect the underbottom surfaces against corrosion are the impressed current system or the galvanic/sacrificial anode system. Each is described in some detail in the second edition of the API RP651, Cathodic Protection of Aboveground Petroleum Storage Tanks.

A typical galvanic system, shown in Fig. 13.11, uses a metal more active than the structure to be protected to supply the current required to limit or stop corrosion. The more active metal is called the anode, commonly referred to as the galvanic anode or a sacrificial anode. A galvanic corrosion cell develops, and the active metal anode corrodes (is sacrificed) while the metal bottom (cathode) is protected. Metals commonly used as the anodes are magnesium and zinc in either cast or ribbon form.

Impressed current systems use an external power source through a rectifier to provide direct current (DC) to the anode and then on to the tank bottom, as shown in Fig. 13.12.

The operation of any cathodic protection system can be affected by the tank foundation design, the use of secondary containment liners, and general site conditions. The system designer should complete a thorough review of all tank details.

Secondary Containment/Leak Detection. Appendix I, "Under-Tank Leak Detection and Sub-grade Protection" in the API Standard 650, provides acceptable construction details that may be used to detect and contain leakage from aboveground storage tanks. It is noted that the API supports a general position that owners consider the installation of release prevention barriers (RPB) under new tanks during initial construction.

Acceptable RPB includes second steel bottoms, impermeable clay materials, or synthetic materials such as high density polyethylene (HDPE) materials. The API Standard 650, Appendix I provides several different construction details for consideration; however, the tank owner must determine whether the undertank area is to include leak detection. If required, the owner must then select the method or methods to be used.

Whenever a new bottom is going to be added to an existing tank, the owner should consider adding some type of RPB. In many cases, a new bottom is only added after the original bottom has corroded through and product has leaked through to the foundation. This is covered in the second edition of API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction.

Examples of typical RPB systems that are used are shown in Figs. 13.13 and 13.14. Each of these uses a synthetic liner fabricated from sheets of HDPE material (60–90 mil thick) welded together to form a continuous barrier. Fig. 13.13 shows a detail of a system used primarily for new tank construction on earthen birm or a concrete ring wall when leak detection is required.

The example in Fig. 13.14 is specifically used when a new bottom is to be added to an existing tank using the slotted shell method of construction. The Endolock™ system also relies on a synthetic HDPE liner as the barrier. This system also includes leak detection and can be used either with granular fill or concrete between the old and new bottom. The systems shown in Figs. 13.13 and 13.14 are patented by CB&I. Other potential systems are available, as well as systems that use adhesives or nails to secure the liner at the ringwall or inner tank shell surfaces.

Cathodic protection systems may be incorporated into each design. In most cases, an impressed current system is installed with the ribbon anodes installed between the flexible liner and the new bottom.

Site Considerations for Production Tanks

API RP12R1, Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production Service provides information on new battery installations and can serve as a guide for revamping existing batteries if required. A typical tank battery contains two or more tanks and usually has a capacity equal to four days production. Tanks should be level with each other and have a minimum spacing of 3 ft between tanks, unless increased spacing is required by local code.

Selecting the proper location for a storage tank is of prime importance. The tank foundation or grade should be slightly elevated, level, and somewhat larger in diameter than the tank itself, with the surrounding area graded to provide good drainage away from the tank(s). The best grade is one made of small gravel, crushed rock, etc. This type of grade allows no water to stand underneath the tank and provides air circulation. If the tank is to be set directly on the ground, felt tarpaper may be applied to the grade first and the tank set on this. If concrete is used for the grade, it should be slightly larger in diameter than the tank and might have shallow grooves on the surface for improved air circulation. Numerous codes, standards, and specifications may regulate the location, design, and installation of storage tanks dependent on their end use. Selection of the proper specification and providing adequate fire protection for the installation may lower insurance rates over the life of the installation.

Dikes are generally provided to contain the volume of a certain portion of the tanks enclosed depending on the tank contents. Dikes are used to protect surrounding property from tank spills or fires. In general, the net volume of the enclosed area should be the volume of the largest tank enclosed (single-failure concept). The dike walls may be earth, steel, concrete, or solid masonry designed to be watertight with a full hydrostatic head behind them. Local codes might require provisions for secondary containment of the area to limit environmental risks, should a tank leak develop. If more than one tank is within the area, curbs or, preferably, drainage channels can be provided to subdivide the area to protect the adjacent tanks from possible spills.

Tank-Battery Connections and Operations

The suggested setting and connection plan for a typical tank battery is shown in Figs. 13.15 and 13.16. The pipeline connection in the tank should be located directly below the thief hatch and a minimum of 12 in. above the tank bottom. It should be equipped with a valve and sealing device immediately adjacent to the tank. Pipeline valves should be checked frequently for leaks.

Inlet connections, preferably, should be located in the deck of the tank and should have a valve located near the inlet and capable of closing off against pressure.

Drain connections should be located immediately above the tank bottom in the side of the tank or in the tank bottom immediately adjacent to the side. They should be equipped with a valve and sealing device located next to the tank. Drains from all the tanks in a battery should be connected together and piped well away from the tanks.

Tank batteries are operated by flowing into a single tank that is "equalized" to another. The "equalizer line" allows flow from the primary tank to overflow to a secondary tank when the primary tank is full. The operator then equalizes the second tank to another empty tank so that there is a new primary and new secondary tank.

The original primary tank is then ready to be run to sales. Before the tank is accepted by the crude purchaser, the water should be drained from the tank if necessary and the water valve sealed closed. All other valves should be sealed, except the vent or vapor-recovery line. The pipeline valve is then unsealed and opened for delivery to the purchaser. When a closing gauge is taken, and before the tank is filled again, the pipeline valve should be sealed, the drain valve checked to ensure that it is closed, and the seal removed. The seal from the equalizer-line valve can then be removed, and the tank is ready to be put in service as an equalizing tank.

Equalizer connections should be installed below the deck in the tank shell. A valve and sealing device should be installed immediately adjacent to the tank if more than two tanks are in the battery and should be connected in such a manner that any two tanks can be equalized together.

Vent connections should be installed in the center of the tank deck and all tanks connected to a common line. The line should have a pressure-vacuum valve installed in the line or on the end of it. The line should be sloped to prevent accumulation of liquids in it or in the valve. The use of gas to roll stored products is usually considered poor practice and should be restricted to temporary or emergency use. If a roller line is used, it should enter the tank through the deck and be equipped with a valve next to the tank.

Tank Battery for Hydrogen Sulfide Crude Storage

Constant attention should be given to the hazardous condition created by iron sulfide deposits. These occur most frequently within the vapor space and particularly on the underneath exposed side of the deck. These iron sulfide deposits generate severe corrosion that can go unnoticed when deck conditions are observed from the topside only. When sour crude is stored, all openings on the tanks should be kept closed because hydrogen sulfide is poisonous. This can be accomplished by equipping the tanks with some type of ground-level gauging and by locating thermometers in the tank shell. Gauges and temperatures then can be read from the ground without the tank being opened. These gauging devices usually require approval by the crude purchaser. Grounding-level sampling also can be accomplished by installing pipes that extend into the tank at any desired level and to any desired distance. Valves are located at a convenient level to permit sampling on the ground without the tanks being opened. If available, a small amount of sweet gas should be fed into the top of the tank continuously to establish a "gas sweep." This ensures positive pressure within the tank at all times and prohibits air from entering the tank, thereby greatly reducing corrosion. It is advisable to extend the tank vent line well beyond the tank battery and to use a back pressure valve and flame arrester in the vent line. The vapors should be flared and not vented.

Maintenance of Tank Batteries

Storage tanks that are properly designed, constructed, and maintained can provide 30 to 50 years of service.

Steel tanks should be kept clean and free from spilled oil or other material. They should be kept painted and all water or accumulated dirt should be removed from around the bottom edge of the tanks. Thief hatches and vent-line valves should be kept closed and inspected periodically for proper operation and gasket condition. Should any leaks occur, they may be repaired temporarily with lead sealing plugs or toggle bolts. These leaks should be repaired permanently as soon as possible.

General References

Evaporative Loss Measurement. 1997. Manual of Petroleum Measurement Standards, Chap. 19, Sec. 2-E. Washington, DC: API.

API RP12R1, Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production Service, fifth edition. 1997. Washington, DC: API.

API RP575, Inspection of Atmospheric and Low-Pressure Storage Tanks, first edition. 1995. Washington, DC: API.

API RP651, Cathodic Protection of Aboveground Petroleum Storage Tanks, second edition. 1997. Washington, DC: API.

API RP652, Lining of Aboveground Petroleum Storage Tank Bottoms, first edition. 1991. Washington, DC: API.

API RP2003, Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents, fifth edition. 1991. Washington, DC: API.

API Spec. 12B, Bolted Tanks for Storage of Production Liquids, fourteenth edition. 1995. Washington, DC: API.

API Spec. 12D, Field-Welded Tanks for Storage of Production Liquids, tenth edition. 1994. Washington, DC: API.

API Spec. 12F, Shop-Welded Tanks for Storage of Production Liquids, eleventh edition. 1994. Washington, DC: API.

API Standard 650, Welded Steel Tanks for Oil Storage, tenth edition. 1998. Washington, DC: API.

API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, second edition. 1995. Washington, DC: API.

API Standard 2000, Venting Atmospheric and Low-Pressure Storage Tanks (Nonrefrigerated and Refrigerated), fifth edition. 1998. Washington, DC: API.

API Standard 620, Design and Construction of Large, Low-Pressure Storage Tanks, tenth edition. 2002. Washington, DC: API.


SI Metric Conversion Factors

ºAPI 141.5/131.5 ºAPI = g/cm3
bbl x 1.589 873 E - 01 = m3
(F - 32)/1.8
= ºC
ft x 3.048* E - 01 = m
gal x 3.785 412 E - 03 = m3
in. x 2.54* E + 00 = cm
in.3 x 1.638 706 E + 01 = cm3
psi x 6.894 757 E + 00 = kPa


Conversion factor is exact.