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Southern Region Process Engineering Guideline Storage Tanks Issuing Department:

Document No:

Supersedes:

Previous Rev. Date:

Southern Region - Process Rev No.:

Issue Date:

0

16, Dec. 2013

Prepared By:

Checked by:

R. Rivera

Page:

TG-58-33.05-2041

R. Vaidyanathan

1 of 47 Rev.:

0 Current Revision Date:

16, Dec. 2013 Approved By:

K. Syphard

TABLE OF CONTENTS SECTION

PAGE NO.

INTRODUCTION AND PURPOSE DEFINITIONS GOVERNING BODIES AND REFERENCES TYPES OF STORAGE AND SELECTION OF TANK TYPE 4.1 TYPES OF STORAGE 4.2 TYPES OF TANKS 4.3 SELECTION FACTORS EQUIPMENT DESIGN 5.1 CAPACITY 5.2 SELECTION OF TANK SIZE 5.3 DESIGN TEMPERATURE

5 5 6 8 8 9 9 14 14 15 15

5.3.1

MINIMUM DESIGN METAL TEMPERATURE

16

5.3.2

MAXIMUM DESIGN TEMPERATURE 5.4 DESIGN PRESSURE 5.5 DESIGN DENSITY 5.6 NOZZLES AND APPURTENANCES 5.7 MATERIALS OF CONSTRUCTION 5.8 VAPOR SPACE MANAGEMENT 5.9 TANKS FOR SPECIFIC SERVICES 5.10 STORAGE TANK DATA SHEETS SAFETY/ENVIRONMENT PROTECTION 6.1 TANK VENTING

16 16 18 18 23 24 25 26 27 27

1 2 3 4

5

6

Copyright 2013 by Jacobs Engineering Group Inc. All rights reserved. The contents of this document are proprietary and produced for the exclusive benefit of Jacobs Engineering Group Inc and its affiliated companies. No part of this document may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without the prior written approval of Jacobs Engineering Group Inc.

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6.2 6.3 6.4 6.5 6.6 6.7

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27 28 28 28 29 29

WEAK ROOF TO SHELL ATTACHMENTS LARGE TANKS WITHOUT FRANGIBLE ROOFS LIFTING MANWAYS FIRE FIGHTING LOCATION OF STORAGE AREAS Vapor Emissions

APPENDIX A – TABLES/CHARTS/FIGURES Table 1 Table 2 Figure 3 Table 4 Table 5 Table 6 Figure 7 Table 8 Figure 9 Table 10 Figure 11 Table 12 Table 13 Chart 14 Table 15 Figure 16 Figure 17 Table Table Figure Figure Figure Figure Table

18 19 20 21 22 23 24

Figure 25

API Tank Specification Standards API Specification 12D Standard Tank Dimensions Standard Tank Dimensions Standard API Tank Sizes Maximum Size and Nominal Capacity of API Small Tanks Comparison of Roof Types Common Roof Types for API Standard 650 Comparison of Various Fixed Roof Tanks Typical Fixed-Roof Tank Non-Contact and Contact Aluminum Internal Floating Roofs Typical Internal Floating Roof Tank NFPA Classifications Typical Product Flash Points True Vapor Pressures vs. Temperatures for Typical LPG, Motor and Natural Gasolines Two Most Common External Floating Roof Tanks Typical External Floating Roof Tank Isothermal Lines of Lowest One-Day Mean Temperatures (°F) [°C = (°F – 32)] Standard Letter Designation for Nozzle Connections Preferred Locations for Tank Accessories Typical Floating Roof Tank Assembly Pressure/Vacuum Valve Typical Gas Blanketed Storage Tank API 650 Annex F Decision Tree General Practice Matrix of Tanks for Specific Services Typical P&ID Arrangement for Storage Tanks

28 29 30 31 33 34 34 35 35 36 37 37 37 38 39 40 41 42 42 43 43 44 45 46 47

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1

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INTRODUCTION AND PURPOSE

This Process Design Guideline provides guidelines to Process Engineers for the selection and specification of most common cases of vertical, cylindrical, non-refrigerated, above ground storage tanks with design pressures from atmospheric to 15 psig and temperatures from ambient to 500oF. It will cover primarily tanks which fall under the API-650 and API-620 specifications (Ref. 1 and 2). See Tables 1, 2, 4 and Figure 3 in the Appendix. For the sake of completeness, a brief discussion on horizontal and special shaped storage tanks as well as storage tanks for fluids stored under a broad temperature (-260 F to 500 F) and pressure (atmospheric to 250 psig) range are also included. The primary function of a storage tank is to store liquid substance. Tanks vary considerably, in the type and size based on the type of products to be stored and the volume involved. Broadly, the storage tanks can be divided into two types: Atmospheric Storage Atmospheric storage tanks operate at or near atmospheric pressure. This type of tank is used to hold liquid which will not vaporize at ambient temperature. The common atmospheric storage tank types are open top, fixed roof (cone & dome) and floating roof. Open top tanks have no roof, and the shell is used to store fire water and cooling water. Pressurized Storage Pressurized storage vessels (mounded bullets) are designed to withstand pressure sufficient to keep the liquid stored from vaporizing. Types of products requiring pressurized storage vessels are high vapor pressure hydrocarbons such as propane, butane, LPG and isopentane. For safe storage first consider product properties such as volatility, pour point and flash point.

2

DEFINITIONS

Accumulation - pressure increase over the maximum allowable working pressure or design pressure of the vessel allowed during discharge through the pressure-relief device. Design Pressure - the maximum positive gauge pressure permissible at the top of a tank when the tank is in operation. It is the basis for the pressure setting of the safety-relieving devices on the tank. Double-deck Floating Roof - the entire roof is constructed of closed-top flotation compartments. Corrosion Allowance - any additional thickness specified by the Purchaser for corrosion during the tank service life. Flame Arrester – a device or form of construction that will allow free passage of a gas or gaseous mixture but will interrupt or prevent the passage of flame. Maximum Design Temperature - the highest temperature considered in the design, equal to or greater than the highest expected operating temperature during the service life of the tank. Overpressure - pressure increase at the PV valve inlet above the set pressure, when the PV valve is relieving.

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PV Valve - weight-loaded, pilot-operated, or spring-loaded valve, used to relieve excess pressure and/or vacuum that has developed in the tank; also, known as a breather valve. Single-deck Pontoon Floating Roof - the outer periphery of the roof consists of closed-top pontoon compartments, with the inner section of the roof constructed of a single deck without flotation means. Storage Tank - for the purpose of this guide, it is defined as permanent, stationery, non-code, storage container designed for pressures not exceeding 15 psig, used for long or intermediate-term storage of fluids.

3

GOVERNING BODIES AND REFERENCES

1.

American Petroleum Institute, API Standard 650, "Welded Steel Tanks for Oil Storage," Eleventh Edition, June 2007.

2.

American Petroleum Institute, API Standard 620, "Design and Construction of Large, Welded, Low-Pressure Storage Tanks," Eleventh Edition + Addendum 1 + Addendum 2, February 2008, March 2009, August 2010.

3.

Sherwin-Williams, Protective and Marine Finishes; http://protective.sherwin-williams.com/pdf/tools-charts/standard_api_tank_sizes.pdf

4.

American Petroleum Institute, API Specification 12B, "Specification for Bolted Tanks or Storage of Production Liquids,” Fifteenth Edition, October 2008.

5.

American Petroleum Institute, API Specification 12D, "Specification for Field Welded Tanks for Storage of Production Liquids,” Eleventh Edition, October 2008.

6.

American Petroleum Institute, API Specification 12F, "Specification for Shop Welded Tanks for Storage of Production Liquids," Twelfth Edition, October 2008.

7.

American Petroleum Institute, API Bulletin 2513, "Evaporation Loss in the Petroleum Industry – Causes and Control," February 1959.

8.

American Petroleum Institute, API Bulletin 2516, "Evaporation Loss from Low-Pressure Tanks, January 1962.

9.

American Petroleum Institute, API Publication 2517, "Evaporation Loss from External Floating Roof Tanks," Second Edition, February 1980.

10.

American Petroleum Institute, API Bulletin 2518, "Evaporation Loss from Fixed-Roof Tanks," June 1962.

11.

American Petroleum Institute, API Bulletin 2522, "Comparative Methods for Evaluating Conservation Mechanisms for Evaporation Loss," January 1967.

12.

American Petroleum Institute, API Bulletin 2521, "Use of Pressure-Vacuum Vent Valves for Evaluating Pressure Tanks to Reduce Evaporation Loss," September 1966.

13.

American Petroleum Institute, API Bulletin 2523, "Petrochemical Evaporation Loss from Storage Tanks," November 1969.

14.

American Petroleum Institute, API Bulletin 2519. "Evaporation Loss from Internal Floating-Roof Tanks," June 1983.

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15.

Manual of Petroleum Measurement Standards Chapter 19.1, API MPMS 19.1, "Evaporative Loss From Fixed-Roof Tanks – Fourth Edition, October 2012.

16.

Manual of Petroleum Measurement Standards Chapter 19.2, API MPMS 19.2, "Evaporative Loss From Floating-Roof Tanks – Third Edition, October 2012.

17.

Manual of Petroleum Measurement Standards Chapter 19.4, API MPMS 19.4, "Evaporative Loss Reference Information and Speciation Methodology - Third Edition, October 2012.

18.

American Petroleum Institute, API Standard 653 - Tank Inspection, Repair, Alteration, and Reconstruction – Fourth Edition, January 2012.

19.

American Petroleum Institute, API Standard 2000, "Venting Atmospheric and Low-Pressure Storage Tanks," Sixth Edition, November 2009.

20.

American Petroleum Institute, API RP 520, "Sizing, Selection, and Installation of Pressure Relieving Systems in Refineries, Part I – Sizing and Selection," Eighth Edition, December 2008.

21.

American Petroleum Institute, API RP 2001, "Fire Protection in Refineries," Eighth Edition, May 2005.

22.

National Fire Protection Association, NFPA 30, "Flammable and Combustible Liquids Code," National Fire Codes, Vol. 1, 2012.

23.

National Fire Protection Association, NFPA 11, "Standard for Low-, Medium- and HighExpansion Foam," 2010 Edition.

24.

PIP-VEETA001 Tank Selection Guide, Complete Revision June 2009.

25.

PIP-VESLP001 Low pressure, Welded Vessel Specification, Complete Revision June 2012.

26.

PIP-VESTA002 Atmospheric Storage Tank Specification (Supplement to API Standard 650), Complete Revision Oct. 2012.

27.

PIP-VEDTA003 Atmospheric Storage Tank Supplemental Data Sheet and Instructions (Supplement to API Standard 650), Complete Revision June 2009.

28.

Petroleum Storage Tanks Basic Training Part 1, Rev. 2 - SlideShare; http://www.slideshare.net/ledzung/storage-tanks-basic-training-rev-2

29.

EPA (Nov. 2006), AP 42, Compilation of Air Pollutant Emission Factors, Vol. 1: Stationary Point and Area Sources. Chapter 7.

30.

A.E. Wallace and W.P. Webb, "Cut Vessel Costs with Realistic Corrosion Allowances," Chemical Engineering, August 24, 1981, pp. 123-126.

31.

E.E. Morgenegg, "Frangible Roof Tanks," 1978 Proceedings, Refining Department, American Petroleum Institute. Vol.57,(43rd Mid-Year Meeting, Toronto, 8-11 May 1978), pp. 509-514.

32.

R.F.Murphy, "Guidelines Optimize Foam Fire-Fighting System," Oil and Gas Journal, January 25, 1982, pp. 224-232.

33.

V.F. Peyton, "Better Tank-Fire Protection System in Use," Oil and Gas Journal, July 23, 1984, pp. 70-73.

TG-58-33.05-2041 Storage Tanks 34.

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Engineering Design Encyclopedia, Typical P&ID Arrangement for Storage Tanks, http://www.enggcyclopedia.com/2011/04/typical-pid-arrangement-storage-tanks/

35.

Gas Processors Suppliers Association, FPS Version, Volumes I & II, GPSA Section 6: Storage, 12 ed., 2004.

36.

Liquid & Water Jet Eductors, http://www.venturipumps.com/eductor.htm

37.

American Petroleum Institute, API RP 2210, "Flame Arresters for Vents of Tanks Storing Petroleum Products," Third Edition, May 2000.

38.

North American Mixing Forum, www.1.mixing.net/?q=oil_2

39.

Hidromix Pump Mixing Systems, www.hidrostal.co.uk.

4

Mixing

in

crude

oil

storage

tanks

article,

TYPES OF STORAGE AND SELECTION OF TANK TYPE Types of Storage

4.1 4.1.1

Feedstock Storage

The feed storage must provide enough capacity to keep the plant running without interruption due to supply availability. The required feed to the process can come from several sources and sometimes can be different in quality. Typical sources include pipeline, rail car barge, tank truck or ship. The reliability of each source should be evaluated to determine how many days of feed storage are required. A reliable pipeline or tank truck may require 7 days of storage, while a rail car barge or ship may require 30 days of storage. In addition to the frequency of the delivery, the quantity of the delivery must be considered. A pipeline may be dedicated and continuous or operated in batches. Barges and ships are of different sizes. Plant location will play into the decision process also. A remote isolated location or an area which can be isolated by weather conditions could require 3 or 4 months of storage. If multiple types or qualities of feed are to be received, additional tanks may be required to provide blending and sampling/analysis time. For example, a refinery receiving a single type of crude normally requires three tanks for receiving, analysis and feed. If there were three types of crude, five tanks could be used. In some applications the refinery may use inline blending to reduce the number of required tanks. 4.1.2

Day Storage

The purpose of day storage is to stabilize pressure and flow rates between units. It may also be used for transitions from continuous to batch operation and visa versa. 4.1.3

Intermediate Storage

This storage is generally required for surge to keep certain units operating when related units are shutdown or for quality control. Intermediate storage may be provided for the following services: 

Unit start-up



Unit shutdown



Catalyst regeneration



Blocked operation



Rundown for quality control

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Product Storage

The storage of products is essentially the reverse process of feed storage. The number of product tanks required depends on the method of quality control required, the time required to analyze the product, rundown rates, shipping and blending requirements. It also allows product to be tested against product specifications and reprocessed if necessary. Ideally these criteria are provided by the client. 4.2 4.2.1

Types of Tanks Atmospheric Storage Tanks

API 650 provides construction requirements (i.e., material, design, fabrication, erection, and testing) for large, welded, vertical cylindrical, non-refrigerated, aboveground, closed and open top welded steel and aluminum storage tanks with internal pressure less than or equal to 2.5 psig (17.2 kPa). It has a maximum design temperature of 200ºF. However, to design for maximum temperatures from 200°F but not exceeding 500°F the tank must be fabricated per Annex M, (Ref. 1). 4.2.2

Low Pressure Storage Tanks

API 620 provides construction requirements (i.e., material, design, fabrication, erection, and testing) for large, low-pressure carbon steel, vertical, aboveground tanks with a single vertical axis of revolution. Metal temperatures not greater than 250ºF (120ºC) and design pressures not greater than 15 psig (103 kPa) are covered under Low Pressure Storage Tanks.

See Figure 23 as aid in selection of tank. 4.3 4.3.1

Selection Factors Storage Conditions

The Process Engineer is responsible for specifying storage conditions. The conditions specified will largely determine the configuration, materials of construction, fabrication methods, venting requirements, and cost of the vessel. Petroleum fluids are commonly stored in large quantities in above-ground tanks at temperatures from -260oF (LNG) to about 500oF (asphalt) and at pressures from atmospheric to about 250 PSIG (propane). 4.3.1.1 Storage Temperature Storage temperatures are not usually controlled. The battery limit conditions will usually set the product temperature. However, due to the impact of temperature on evaporation losses, if necessary, changes should be made in the process unit to provide more cooling. Consequently, cooling facilities may be included in the storage area. Other considerations that will affect the operating temperature are the temperature requirements for the subsequent processing step and energy conservation, the vapor pressure and flash point of the stored material, the stability of the material at a proposed storage temperature, and the freezing point or pour point of the material. If possible, petroleum liquids should be stored below their flash point temperatures. It is apparent that even in cold climates it will not always be possible to store materials such as gasoline below their flash point temperatures. In hot climates it is quite possible that storage temperatures will exceed the flash points of materials such as kerosene and aviation turbine fuel. In such cases, fixed roof tanks should be avoided due to the potential for breathing and working losses being high, which may have undesirable safety and environmental consequences.

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Precautions must be taken to prevent water entering the tank. If the material is stored at above 200oF, the water will boil and the tank will froth over. Tanks that operate below 200 oF are designed to never see temperatures above 200 oF. Similarly, tanks that normally operate hot should not be allowed to cool to less than 200oF. Tank temperatures in the range 200oF to 260oF should be avoided to avoid problems. Storage temperature should be kept at least 20 oF above the freezing or pour point of stored material to avoid plugging of nozzles and instrument taps. Once the storage temperature is chosen, the density and corrosivity of the material at the proposed temperature must be determined. Excessive corrosivity may force a re-examination of the storage temperature. 4.3.1.2

Storage Pressure

The vapor pressure of the stored liquid plus the partial pressure of any air or inert gas in the space is equal to the pressure in the vapor space in a tank. The vapor space above a high vapor pressure liquid will be relatively rich in the vaporized liquid and any loss of vapor through the vent can result in significant losses of product. Low tank pressures which cause in-breathing of air also give rise to losses. Therefore, the difference between the opening pressures of the vacuum and pressure vents should be as high as practicable to minimize losses. Also consider that a slightly positive pressure may be chosen to exclude air and prevent the possibility of developing a flammable mixture in the vapor space. Yet, storage of toxic materials may require a negative pressure to prevent contamination of the atmosphere. 4.3.1.3 Stored Materials It is more difficult to contain volatile flammable liquids than materials of lower vapor pressure. Accordingly, different types of tanks are recommended for different materials being stored. The NFPA (National Fire Protection Association, Ref. 22) classifies petroleum liquids on the basis of both flash point and boiling point. See Table 12 in the Appendix. 4.3.2

Configuration

4.3.2.1 Horizontal Vessels Horizontal vessels are practical only for relatively low-volume storage, that is, up to about 100,000 gallons (2,500 bbls.). Storage vessels are occasionally specified with a high length to diameter ratio for high pressure storage (above 15 PSIG). Such vessels are generally constructed with two hemispherical, toro-spherical (ASME flanged and dished), or elliptical (2 to 1) heads, depending upon design pressure, temperature, and application. These vessels are most frequently mounted horizontally for structural reasons. However, horizontal vessels usually require a larger foot print. Horizontal vessels are generally easier to clean and drain and they withstand thermocycling and high temperatures better than vertical storage tanks. 4.3.2.2 Vertical Vessels Vertical vessels are generally those covered by the API specifications (see Tables 1, 2 and 4 in the Appendix). They are normally used for high volume and low pressure applications. The costs per unit volume and plot space requirements are considerably less than those for horizontal vessels. 4.3.2.3 Special Shapes For high pressure and high volume applications, spheres and other similar shapes are frequently used. For low-pressure gas storage, expansion roof tanks or lifter roof tanks are sometimes used. These are essentially constant pressure variable volume devices.

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Losses in Storage

For evaluating the effect of evaporation losses and the influence the losses can have on the selection of the type of tank for a specific service: the following API Bulletins and Manual of Petroleum Measurement Standards should be used for guidance: (References 6 thru 17). These standards contain methodologies for estimating the total evaporative losses of hydrocarbons from fixed-roof tanks, external floating-roof tanks (EFRTs), freely vented internal floating-roof tanks (IFRTs) and domed external floating-roof tanks (domed EFRTs). The total loss Lt is the sum of the standing loss Ls and the working loss Lw: Lt = Ls + Lw. 4.3.3.1 Breathing Loss Breathing losses occur due to temperature changes. A decrease in temperature will cause shrinkage of the liquid and vapor contents of a tank and condensation of some of the vapor. The pressure will fall and if the pressure drop is enough, the vacuum vent will open to allow air or blanketing gas into the tank. Air thus drawn in will be free of hydrocarbon vapor and the vapor space in the tank will contain less than the equilibrium hydrocarbon concentration. Further vaporization may take place to bring the vapor space closer to saturation. The pressure will rise and the pressure vent set point could be exceeded. An increase in temperature will cause a pressure rise due to the expansion of the tank contents and vaporization of some liquid. If the pressure rise is great enough the pressure vent will open and some of the tank vapor will be expelled. 4.3.3.2 Standing Losses Standing losses occur from idle tanks due to leakage from valves and fittings, vapor losses from open hatches, or lifting manways and vaporization from the seal areas of floating roof tanks. 4.3.3.3 Filling Losses When filling a tank, the vapor space inside a fixed roof tank is compressed by the rising liquid. A filling loss occurs if the tank pressure exceeds the pressure vent set point. Consequently, as safety feature the pressure vent opens to prevent the container from rupturing due to high pressure. There are no filling losses for floating roof tanks. 4.3.3.4 Emptying Losses When emptying a tank, the vapor space in a fixed-roof tank expands as the liquid surface falls. When the pressure decreases below the vacuum vent set point, air or blanketing gas will be drawn in to prevent implosion of the tank. The partial pressure of hydrocarbon in the vapor space thus falls and hydrocarbon vaporizes to re-saturate the vapor space. Then the pressure increases and venting may occur. 4.3.3.5 Wetting Losses When a floating roof is lowered by withdrawal of liquid, evaporation of liquid from the wet exposed tank wall is termed "wetting loss". 4.3.3.6 Boiling Losses Boiling loss is when a vapor is expelled from a tank due to boiling. It can occur in any tank. 4.3.3.7 Working Losses Working losses in low pressure (2-15psig) tanks occur during filling if the vent set pressure is exceeded and vapors are expelled. Possible compression of the vapor space and condensation

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and consequent temperature change of the vapor space due to the rate of emptying and filling the tank have an unpredictable effect. (Ref.7) 4.3.4

Roof Types

There are two general roof designs for API Standard 650 Storage Tanks: 

fixed roof



floating roof

See Table 6 for features of fixed versus floating roof designs. Figure 7 (Ref. 28) displays pictures of most common roof designs for API Standard 650. 4.3.4.1 Fixed Roof Fixed roof types are cone, dome, and umbrella. Cone roofs can be self-supporting, internally supported or externally supported. The maximum slope of a cone roof is 2 inches per foot. Dome roofs are used when design pressures are too high for cone roofs. Dome and umbrella roof designs are self-supporting. Although a fixed roof design is the least expensive roof option, the potential for breathing and working losses is high, which may have undesirable safety and environmental consequences. Most API-620 tanks will have dome roofs while API-650 tanks will mostly have cone roofs. Comparative features of the various types of fixed roof storage tanks are summarized in Table 8. Low vapor pressure, high flash point liquids such as gas oils, diesel fuel, catalytic cracker feed (cold or hot), and asphalt (high pour point liquid) are usually stored in fixed roof tanks. Figure 9 (Ref. 6) displays a picture of a typical fixed roof tank. Fixed roofs are not recommended for tanks larger than 120 feet in diameter because it is difficult to extinguish fires in large tanks with this type of roof design. Shell corrosion in the vapor space of a fixed roof tank containing sour stocks can be a serious problem. To eliminate the corrosion, the fixed roof and shell are coated with a film. To insure the best application, an externally supported cone roof or a self-supporting roof is used. 4.3.4.2 Floating Roof There are two types of floating roof designs: 

internal



external

Most sour vapor-related corrosion problems can be eliminated by using a floating roof. Vapor venting is less from a floating roof tank than from a fixed roof tank. With a floating roof, the vapor space does not vary as the tank is filled or emptied. Since the vapor-liquid interface area and vapor volume are significantly reduced, the working plus breathing losses are minimized, and emissions and product losses are reduced. Due to low vapor emission from a floating roof tank, there is a low probability of accumulating a combustible mixture in the top of the tank. The potential of a fire hazard caused by lightning and a combustible mixture is much lower for a floating roof tank than a fixed roof tank. Because of the lower probability of fire hazard, the floating roof tank is recommended for tanks with diameters larger than 120 feet when storing liquids with flash points lower than 100 F and for heavier liquids stored at temperatures within 20 F of their flash points. Stocks having a vapor pressure of 0.2 to 0.9 psia at the tank storage temperature can form flammable mixtures in the vapor space if they are stored in fixed roof tanks. Certain naphthas, thinners, solvents, and refinery intermediates, as well as Jet-B fuels have vapor pressures in

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this range and may accumulate static charge on liquid surface. As a safety precaution floating roofs are sometimes installed on such tanks. See Table 13 for typical product flash points and Chart 14 for vapor pressure vs. temperature for typical. 4.3.4.2.1 Internal Floating Roof (IFR) An internal floating roof tank has both a permanent fixed roof and a floating deck inside. The deck or floating roof is the structure floating on the liquid stored within the tank. The deck of an internal floating roof tank rises and falls with the liquid level while in full contact on the underside thus achieving no vapor zone. Existing fixed roof tanks are frequently converted to floating roof when their service change to stocks with low vapor pressure or low flash points. Appendix H in API 650 gives requirements for several types of internal floating roofs. Metallic pan roofs and metallic bulkheaded roofs are not recommended as they are not positively buoyant and, therefore are very susceptible to sinking. Two commonly used aluminum internal floating roofs, non-contact and contact roofs are compared in Table 10. An internal floating roof is selected to deprive the water from coming in contact with the product. This roof type is commonly used for reformer feed, benzene and finished jet fuel storage tanks. Figure 11 (Ref. 28) displays a picture of a typical internal floating roof tank. 4.3.4.2.2

External Floating Roof (EFR)

External floating roofs are currently of three general types: pan, pontoon, and double deck. Various versions are available to emphasize features such as full liquid contact, load carrying capacity, roof stability, or pontoon arrangement. See Table 15 for the comparison of the two most common types of external floating roofs: pontoon roof and double deck roof. The pan roof lacks positive buoyancy, is very susceptible to sinking, and should not be used for the new storage tank designs. This roof type is usually used for crude oil storage tanks. Gasoline and naphtha are stored in small tanks (less than 64 feet in diameter) with internal floating roofs and larger tanks with external floating roofs. For small tanks see Table 5. Some advantages of the internal floating roofs over the external floating roofs are protection by the fixed roof from severe weather conditions, particularly rain, snow and ice. Also, there is no product contamination from rain water and melting snow. Disadvantages of the internal floating roofs versus external floating roofs are that the internal floating roofs are more difficult to inspect and to repair than the external floating roofs. Figure 16 (Ref. 29) displays a picture of a typical external floating roof tank. 4.3.5

Bottom Types

There are generally four types of tank bottoms used on API 650 tanks: 

flat horizontal



flat sloping



coned up bottom



coned down bottom

4.3.5.1 Flat Horizontal Typically tanks with diameters less than 20 feet use flat horizontal bottom. It is inexpensive to fabricate and bottom connections are easily accessed. The disadvantage is thorough draining may be difficult due to low spots caused by settling of the foundation.

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Flat Sloping

Generally tanks with diameters less than 50 feet use flat sloping bottom. This design has a minimum slope of 2 %. Flat sloping bottom tanks have better drainage than flat horizontal bottom and coned up bottom tanks. A tank with a flat sloping bottom design is suitable for change of service. Some Disadvantages of the flat sloping bottom are: 

less capacity than all other configurations



more expensive than coned up or coned down bottoms



anchors may be required in earthquake prone zones



sediment can form in pockets that do not drain completely

4.3.5.3

Coned Up Bottom

Larger tanks most frequently use the coned up bottom. A coned up bottom design has a minimum 1/120 slope. It also has better drainage than a flat horizontal bottom tank. This design is suitable for liquids with specific gravity greater than 1 and can facilitate cleaning. Some Disadvantages of the coned up bottom are: 

less capacity than flat horizontal and coned down bottom tanks



water drains to shell where it accumulates

This poor drainage may result in severe corrosion of the shell next to the tank bottom and the bank bottom plate near the edge. 4.3.5.4

Coned Down Bottom

A coned down bottom tank has more operating capacity than all other bottom configurations. Generally, this type of design is used for floating-roof tanks. It has the best drainage for water, allows better drainage of the liquid, and is thus more suitable for tanks that need to change service. The slope of a coned down bottom design is typically between 2 and 4 %. Some Disadvantages of the coned down bottom are: 

greater product loss when a water phase is removed



greater potential for corrosion problems



a reduced capacity for differential settlement

Of all major tank components, the bottom is probably the most often repaired or replaced. API 653 (Ref. 18) provides a long list of causes of bottom failures that necessitate appropriate corrective action.

5 5.1

EQUIPMENT DESIGN Capacity

The Process Engineer is responsible for specifying the capacity of storage vessel. Determining the working volume is the second most important planning criteria. Not only does this set the tank’s dimensions, it also determines the number of tanks required. The working volume (nominal capacity) is the volume required by the process. In other words it is the part of the tank

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volume that is actually available for storage use. Actual capacity is calculated from the tank dimensions. It includes the nominal capacity plus heel and freeboard. Actual heel and freeboard requirements for cone roof tanks are about 18 inches at the bottom and 9 inches at the top. If the tank is fitted with an overflow, the top allowance will be increased accordingly. For floating roof tanks about 2 1/2 feet is lost at the bottom and 3 feet at the top. Actual dimensions will depend upon the floating roof design. A safety factor is frequently added to the calculated process volume requirement of the tank. This may be as much as 20 percent. Frequently 10 percent is identified as heel and 10 percent as freeboard. Safety factors of this kind allow for uncertainties in process requirements. In the case of day tanks and intermediate storage vessels the safety factor is generally larger than for feed or product storage. The safety factor also allows some margin for the engineer to choose a standard tank size for a given process requirement. Several lists of standard tank sizes from a vendor and from API Standard are found in Tables 1, 2 and 4. On occasion the Process Engineer may be required to choose the diameter and height of the storage tank. In that case, the engineer obviously also specifies the actual capacity. 5.2

Selection of Tank Size

The Process Engineer should specify the nominal volume rather than tank dimensions. The vendor will determine the optimum dimensions of a storage tank based on the given volume. The nominal volume should include an appropriate safety factor. For storage tanks, if it is subjected to an internal pressure, the optimum configuration will be a much higher length to diameter ratio. As the height to diameter ratio is increased, the allowable design pressure increases. For a given capacity, a taller tank will allow a greater pressure variation and consequently will reduce breathing and filling losses. The optimum configuration requires maximizing the height for a given volume, with the exception of small tanks. Therefore, the diameter will be fixed. The plate thickness is directly proportional to the tank diameter. 5.3

Design Temperature

For a specified design pressure, the design temperature is the maximum and/or minimum temperature that will be maintained in the metal of the vessel. Design temperature is specified based on the expected operating temperature. The main influence of design temperature is on material class and on materials testing requirements. Since allowable stresses differ for different grades of steel, design temperature will also influence plate thickness. For vessels operating under vapor/liquid equilibrium conditions, the saturation temperature at the design pressure should be used for atmospheric and low pressure tanks and saturation temperature at 110 percent of design pressure should be used for pressure vessels fitted with relief valves. This allows for a 10 percent relief valve accumulation. A design temperature greater than 200 oF should not be specified if such a temperature could not possibly be reached. The lower design temperature should be set at the lowest possible temperature that might occur due either to auto-refrigeration or to ambient conditions. The design temperature should not be specified for steam out conditions, however if the vessel will be steamed out, this should be mentioned on the data sheet. 5.3.1

Minimum Design Metal Temperature

API 650 The lowest temperature considered in the design, which, unless experience or special local conditions justify another assumption, shall be assumed to be 8 °C (15 °F) above the lowest

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one-day mean ambient temperature of the locality where the tank is to be installed. Isothermal lines of lowest one-day mean temperature (Ref. 1) are shown on Figure 17. The minimum design metal temperature is used to determine the material group, plate thickness limitations and minimum impact test requirements. For more details on the material groups and impact test requirements refer to API-650 Tables 4.4a/b and Tables 4.5a/b (Ref. 1). API 620 The standard API 620 tank design provides for areas where the lowest recorded 1-day mean atmospheric temperature is -50 °F or higher. Appendix S of API 620 covers stainless steel lowpressure tanks in ambient temperature services in all areas. Appendix R of API 620 covers lowpressure storage tanks for refrigerated products at temperature from +40°F to -60°F. Appendix Q of API 620 covers low-pressure storage tanks for liquefied gases at temperature not lower than -325°F. 5.3.2

Maximum Design Temperature

API 650 API 650 applies to tanks in non-refrigerated service and has a maximum design temperature of 200 ºF. To design for temperatures from 200 ºF to 500 ºF the tank must be fabricated per Annex M. Annex AL applies to aluminum storage tanks with maximum design temperatures up to 400ºF. For the process specification, the process engineer should specify the required design temperature keeping in mind that above 200 ºF will increase the cost of the tank due yield strength reduction factors, improved bottom to shell joints, thicker bottom plates and increase piping flexibility requirements. The following limitations are invoked when designed per Annex M for design temperatures over 200 ºF. 

No open-top tanks



No floating roof tanks



No structurally-supported aluminum dome roofs without purchaser exception.



No internal floating roofs constructed of aluminum without purchaser exception.



No internal floating roof constructed of composite material without purchaser exception.

API 620 Tanks designed per API 620 are designed for maximum design temperatures of 250 ºF or less.

Design Pressure

5.4

The Process Engineer sets the design pressure of a tank and the tank is designed mechanically to contain the fluid with the vapor space subjected to the design pressure. Tanks are essentially atmospheric pressure containers and even small increases in design pressure above atmospheric may have a severe impact on the cost. The required tank design pressure determines whether the tank will be designed per API-650 or API 620. API-650 can be used on tanks requiring a design pressure of 2.5 psig or less. API-620 can be used on with design pressure 15 psig or less with the following exceptions: 

Appendix Q Low-pressure Storage for Liquefied Gases at – 325 ºF or Warmer the design pressure is from -0.25 to 7.00 psig.

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Appendix R Low-pressure Storage Operating Between at 40 ºF and -60 ºF the design pressure is from -0.25 to 7.00 psig.

Within API-650 there are three levels of pressure which impact the design and cost of the tank. The first level relies on the weight of the roof plates only to contain the pressure. The roof which, in many cases, rests on supporting rafters will feel the first effect of increasing pressure in the tank. The next limit to be reached will be at the tank's roof-to-shell joint. This joint is frequently made weak deliberately to ensure that in the event of emergency over-pressuring, e.g. due to fire, the tank will fail at the roof seam rather than at its base. The third level requires the shell-tobottom to be anchored to prevent uplifting. To properly set the tank internal design pressure several items must be considered: 

Fluid true vapor pressure @ maximum operating temperature.



Inert padding requirements.



Conservation vent over-pressure protection requirement.



Margin between maximum operating pressure and the conservation vent set pressure.



Margin between conservation vent’s relieving pressure and the emergency vent’s set pressure.



Emergency vent over-pressure/ accumulation requirement.

Atmospheric Pressure Rated Tanks If environmental and product contamination criteria allow the tank to be free vented to the atmosphere, the design pressure should be designated as atmospheric pressure. Although the tank will have a slight pressure when venting, it can be considered atmospheric provided the free vent is not under sized. When specified as atmospheric design pressure the minimum internal pressure typically used in the tank internal design pressure is 1.5 inches w.c. which corresponds to API-650’s minimum roof plate thickness of 3/16 inch. Caution should be used when changing the service of an existing undocumented tank’s designed for atmospheric pressure. Adding padding or changing the inflows and outflow for existing atmospheric tanks is risky because there is no standard design pressure has for atmospheric storage tanks. Having an existing non-documented tank re-rated is difficult due to evaluating the tank’s conditions and the assumption of liability. Low-Pressure Rated Tanks An important difference between API 650 and API 620 is that API 650 allows no relief device accumulation pressure and API 620 allows 10% for normal contingencies and 20% for fire contingencies. The difference between the set pressure and the higher relieving pressure is defined in API 2000 as the overpressure. Overpressure often is confused with accumulation, which is defined in API 2000 as a pressure increase above the maximum allowable working pressure (MAWP), which API 650 refers to as the design pressure. So let’s get it straight: Overpressure is the difference between the set pressure and the relieving pressure, while accumulation refers to pressure in excess of the tank’s design pressure. Confusing overpressure with accumulation can lead to serious trouble. A common error is to specify a limit on overpressure when the intent is to limit accumulation. API and ASME requirements (API Standard 620, Design and Construction of Large, Low-Pressure Storage Tanks and the ASME Boiler and Pressure Vessel Code; both allow the tank pressure to exceed the design pressure by 10 percent for normal conditions and 20 percent for emergency conditions. These are limits

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on accumulation. Neither standard limits the overpressure, which is the increase in the tank pressure above the set pressure of the vent valve. Applying the limits to the overpressure can result in grossly inefficient operation of the vent and would not achieve the intended purpose of allowing limited accumulation above the design pressure. Another error is to apply the 10 or 20 percent limit on pressure accumulation to API 650 tanks. 5.5

Design Density

The operating density specified should be of that material with the highest density to be stored in the tank at the highest specified operating temperature. The design density specified should be of the material of normal composition at the lowest operating temperature specified. 5.6

Nozzles and Appurtenances

Threaded connections should be avoided on the shell of any tank. Flanged connections are preferred. Process connections are 1.5 inches minimum. A tank may be fitted with mixers, heaters, relief/vacuum breaking devices, platforms and ladders, gauging devices, manways, and a variety of other connections which include sumps, inlet and outlet nozzles, temperature gauges, pressure gauges, vents, and blowdowns. Appurtenance and internal details should be sized according to API 650 (Ref. 1), API 2000 (Ref. 19) and NFPA 11 (Ref. 23). 5.6.1

Nozzles

Table 18 includes recommended standard letter designations for nozzle connections. Clients usually are not concerned with what tag designations are assigned to nozzles. 5.6.2

Process Inlets

Normally only one process inlet is required. A second nozzle may be required either for a pump minimum flow by-pass or for recycle flow through a jet mixing nozzle. To minimize the build-up of static charges, all liquid inlet nozzles should be located below the low liquid level. A liquid inlet nozzle may be located in the roof of a fixed roof tank if the process requires it. This nozzle must be furnished with a dip pipe which terminates 6 inches above the tank bottom. The dip pipe shall have a minimum of one 1/4 inch siphon break hole drilled through the pipe wall at an elevation above the high liquid level. 5.6.3

Process Outlets

The Process Engineer should provide a single suction nozzle to supply all connected pumps. Minimum distances from the bottom of storage tank to the center of the suction nozzle are tabulated in API 650 (Ref. 1). An overflow nozzle should be avoided on a fixed roof tank not equipped with an internal floating roof. If required by process or safety considerations, the overflow line shall be equipped with a vapor seal. 5.6.4

Drains

All storage tanks should be provided with a water drain. Two types of primary drainage systems that can be used to remove water from the top of an external floating roof are: Closed System Using pipe or hose, water cannot come in contact with stored product (See Figure 20) and Open Drain - Water flows down through the stored product. A siphon type draw off sump should be sized according to API 650 (Ref. 1). If the stock is heavier than water, the tank should instead have a swing line installed to draw water. Minimum water drain sizes are as follows:

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Diameter Minimum Drain Size

Water Total Number of Drains

less than 50

2" (or 3")

1

50 to 100

4"

1

100 to 150

4" (or 6")

2 (or 1)

150 to 200

4"

3

over 200

4" (or 6")

4 (or 2)

A variety of roof drains, such as hose, jointed pipe or siphon type, can be provided for external floating roof tanks. The minimum size drain should be capable of preventing the roof from accumulating a water level greater than design at the maximum rain fall rate when the roof is floating at the minimum operating level. A roof drain should not be smaller than 3" for roof diameters less than or equal to 120 feet in diameter, or less than 4" for roofs greater than 120 feet. 5.6.5

Manways

Shell manways are normally 24 inches in diameter and spaced evenly around the tank when more than one manway is specified. If access for cleaning or repairs is expected larger manways may be specified. Fixed roof tanks require roof manways for ventilating a tank for maintenance access before and during entry by workers. Fixed roof tanks are usually equipped with the following manholes: 

Screws-down, gas tight hinged-cover roof manholes



Bolted-cover shell manholes



Sliding/tight fitting cover for pontoon manholes in floating roof tanks

Per API 650 (Ref. 1), a fixed roof of an internal floating roof tank requires a 24 inch minimum inside diameter manway. However, to be able to use a ladder to access the top of the internal floating roof, it is recommended to use a 30 inch or 24 inch by 36 inch rectangular manway. Double deck and pontoon type floating roofs require manways to provide access for inspection of each compartment or pontoon interior. These manways must be minimum 20 inches in diameter with water tight gasketed covers. A 24 inch diameter manway is provided near the center of the floating roof to provide access for inspection and ventilation of the space below the roof when the roof is resting on its supports. Depending on the tank diameter, the number of manways is normally specified as follows:

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diameter Number of Manways Number of Manways in the shell in the roof

less than 50

1

1

5.6.6

Blanketing Purging

and

Fixed roof tanks are blanketed or purged with inert gas to prevent over 120 to 180 3 3 the formation of flammable mixtures in over 180 4 4 the vapor space. For fixed roof tanks equipped with breather valves, the gas flow rate should be sufficient to account for maximum pumpout rate and normal thermal in-breathing. For open vents, the minimum purge requirement should result in a vent nozzle velocity of 0.1 ft/s to prevent backflow of air. A gas flow rate equal to the maximum expected pumpout must be added to the vent velocity requirement to allow for tank emptying. 50 to 120

2

2

Gas flow rates for API 650 tanks can be calculated by the procedures listed in API 2000 (Ref. 19). 5.6.7

Circulation Vents

A minimum of four circulation vents on the fixed roof or the shell of internal floating roof tanks is required. The total open area of these vents should be greater than 0.2 square foot per foot of tank diameter. The maximum spacing between vents shall be 32 feet, and they should be equally spaced. An open vent with minimum area of 50 square inches should be provided at the center or at the highest elevation of the fixed roof. See API 650 Annex H (Ref. 1) for other requirements. Per PIP VESTA002 (Ref. 26) the minimum number and sizes of rim vents shall be provided as shown in the following table:

Nominal Tank Minimum Diameter D ft (m) Number

Size (NPS)

D ≤ 140 (43)

1

4

140 (43) < D ≤ 275 (84)

2

6

275 (84) < D

3

6

5.6.8

Relief Vents

Process Engineers should provide adequate vent capacity for normal breathing due to inflow, outflow, thermal effects, and include emergency vent considerations. A single vent located at the highest point on the tank is preferred over multiple vents for normal breathing. Size the pressure and vacuum relieving equipment per API Standard 2000, "Venting Atmospheric and Low Pressure Storage Tanks" (Ref. 19). A fixed roof tank may be designed

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with a frangible roof joint to handle emergency venting, or be equipped with approved venting devices such as emergency hatches or manway pressure/vacuum relief covers. Process Engineers should be aware that environmental factors used to adjust emergency venting rates differ among the published procedures - API 2000 (Ref. 19), and OSHA 1910.106 (identical to NFPA 30, Ref. 22). 5.6.9

Gauge and Sample Hatches

Tank shall be supplied with one dip hatch for gauging and sampling, unless additional hatches are specified. Generally these roof mounted gasketed hatches are 4, 6, or 8 inches in diameter. When the tank is furnished with a drawoff sump, this hatch is positioned over the sump. 5.6.10 Instrument Connections All storage tanks shall be furnished with connections for the installation of pressure, when required, temperature and level sensors. See Figure 25 for Typical P&ID Arrangement for Storage Tanks (Ref. 34). 5.6.10.1 Temperature The minimum temperature connection is a 1.5 inch flanged nozzle located below the low liquid level. If the contents of the tank are considered hazardous a thermowell should be provided. Otherwise for local readout a dial thermometer is installed. If remote temperature indication is required, or if the tank is heated, an additional nozzle is provided for the temperature sensing element. 5.6.10.2 Level The most common type of level monitoring device for storage tanks is the automatic tank gauge, which can provide both local and remote indication. The size and number of tank connections will vary with the style of gauge and the type of tank roof. Floating roof tanks use the roof position as an indication of level. On fixed roof tanks, the gauge is often furnished with a stilling well or guide wires to stabilize the level readout. Storage tanks should be provided with at least two independent level alarm systems: 

Low, high and high/high level alarms



Independent high level alarm

The Hi/Hi level shall be set such that the maximum filling height is limited to 8 in. (200 mm) below the top of the shell. For tanks with an internal floating cover (IFC) the Hi/Hi level shall be set such that at least 8 in. (200 mm) clearance remains between any moving part of the IFC and any obstruction fixed to the shell, including the roof supporting structure. The low level alarm shall be set such that the IFC still remains floating with its supports at least 4 in. (100mm) above the tank bottom. The high liquid level switches are used to operate pumps, alarm operators or interrupt liquid flow into the tank. The low liquid level switches are used to alarm operators, shut off pumps on the suction line or agitators. Level instruments should be located away from tank inlets, tank outlets and tank mixers. Level instruments should be located near the gauging hatch so that accuracy can be easily checked by manual gauging.

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The Process Engineer should work closely with the Instrumentation and Controls discipline to ensure that the connections indicated on the process data sheet properly reflect the requirements of the selected instrument. The Process Engineer should note on the data sheet if level measurement is required for either custody transfer, or for inventory measurement. 5.6.11 Foam Chambers Fixed roof storage tanks containing flammable and combustible liquids should be fitted with fixed foam discharge outlets that uniformly distribute foam over the liquid surface in the event of a fire. Foam system requirements may be found in NFPA 11 (Ref. 23). Floating roof tanks containing flammable and combustible liquids shall be provided with a foam dam located on the top roof deck to confine the foam to the area above the roof seal. 5.6.12 Heaters Tank heaters may be required to maintain the process liquid temperature needed for operation or a temperature at least 20 F above the liquid pour point or melting point. Heating coils or fin tube bundle heaters are the preferred options when tanks require heating. Consider using removable electric heaters for small heat duties. 5.6.13 Mixers Mixing, when required, can be provided by either a side-entry mixer or an eductor or by pump recirculation. Side-entry mixers are used for continuous blending, where homogenization is required. Side entry mixer is motor driven and the motor and shafts are connected by a tooth belt adequately sized to transmit motor power. The mixer shaft is in the shaft seal and shut off area and fitted with a one piece cast three bladed, pitch impeller, balanced and keyed in position. The sideentry mixer is mounted horizontally on a manholes-type shell nozzle on the sides of the tank, near the bottom to allow easy removal for maintenance without entering the tank. The number of side-entry mixers required depends on the diameter of the tank. The following table can be used as a rule of thumb (Ref. 38).

Tank diameter, 60

Number mixers

2

3

4 or 5

of

1

Eductors are being used to agitate or mix liquids stored in tanks. The working principle of tank mixing eductors involves passing pressurized liquid through the nozzle to entrain another liquid, mix the two and discharge the mixture against a counter pressure. When eductors are combined with a pump for mixing, due to the pumping infrastructure, installation and maintenance costs are higher in comparison to side-entry mixing. In addition, eductor nozzles are susceptible to clogging particularly if the tank contains solids and BS&W (Bottom Sediments & Water). Therefore, eductors are used for clean services. For slurry services, pump recirculation mixing is used to avoid plugging issues with eductors. By mounting the pump outside the tank at ground level, it is easily accessible for installation,

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inspection and maintenance. Pump recirculation requires lower maintenance than the side-entry mixer due to the complete elimination of moving parts within the tank (Ref. 39) 5.6.14 Preferred Locations of Tank Accessories The attached Table 19 indicates preferred location of tank accessories such as vents, drains, relief valves, etc. It is a good idea to obtain the client preference early to avoid rework on equipment data sheets and engineering flow diagrams. 5.7

Materials of Construction

The materials of construction shall be chemically resistant to the range of products to be stored at the temperature range expected in service. Suitable material of construction for various fluids involved in the process is typically provided by the licensor of the process technology. In the absence of such licensor data, Process Engineer with the help of metallurgists is responsible for specifying material of construction. Carbon steel is the most common material of construction for tanks. Carbon steel comes in a multitude of specifications and grades. The specification and grade are based upon the allowable stress required, design temperature, cost, fabrication, and other similar considerations. In general, the restrictiveness of the specification for carbon steel increases with decreasing temperature. Break points are 65oF, 25oF, -5oF, and -35oF on the lower end, and 200oF, 250oF, and 500oF on the upper end according to API 650. Steel specifications get more stringent with increasing wall thickness. Sometimes at high temperatures, stainless or alloy steel are specified in preference to carbon steel for reasons other than corrosion resistance. Seldom, linings such as epoxy or rubber are used for storage of highly corrosive materials in carbon steel vessels due to their development of leaks that cannot be detected until serious damage has already been done to the carbon steel shell. Corrosion resistant linings generally should be specified only as a last resort. On occasions, aluminum has been found to be an acceptable and cost effective material of construction of storage tanks. This is generally not the case in refineries. A material that is gaining some acceptance in the petrochemical and refining industries is fiberglass-reinforced polyester (FRF). FRP tanks are resistant to many corrosive chemicals, especially mineral acids, caustic, and the like. They are generally very cost effective when compared to carbon steel tanks. 5.7.1

Corrosion allowance:

Corrosion allowance (CA) is commonly used for steel parts subject to uniform corrosion. The wall thickness is made greater than necessary for structural integrity, with the additional thickness serving as a CA. Chemical Engineers as a common practice specify 1/8 inch as a minimum corrosion allowance for carbon steel tanks and vessels. Subsequent analysis and experience often show that in many instances, this added thickness is excessive. This practice can be quite costly and is frequently not justified (Ref. 30). In cases where corrosion effects are indeterminate prior to the design of the tank, API standard 620 Appendix G recommends a minimum corrosion allowance of 1/16 inch. API standard 650 does not recommend a minimum corrosion allowance. If the Purchaser requires that a corrosion allowance be provided, the allowance and the areas to which the allowance is to be added shall be specified. If a corrosion allowance is specified without an indication of the area to which it is to be added, the Manufacturer shall assume that it

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is to be added only to the calculated shell-plate thickness. When a corrosion allowance is specified for the roof and bottom plates, it shall be added to the minimum nominal thicknesses. 5.8 5.8.1

Vapor Space Management Open Vents

Open vents are used for high flash point material of low volatility. For these materials a frangible roof or emergency hatch for emergency relief is used. Therefore, open vents are designed for non-emergency venting only. Capacities of open vents can be determined, using the usual orifice equation, using one of the following orifice coefficients: Vent Size

Orifice Coefficient

3”

0.43

4”

0.44

6” – 8”

0.45

10" and larger

0.46

These orifice coefficients are consistent with the API recommended value of 0.5 (Ref. 19) but include an allowance for a return bend connected to the tank by a length of straight pipe. 5.8.2

Flame Arresters

Flame arresters are fitted to open vents to prevent any ignition of petroleum vapor outside the tank from being transmitted to the inside. For a flame arrester to be necessary, the stored material would have to be stored at a temperature above its flash point. The value for petroleum liquids tends to increase with vapor pressure and when a flame arrester is necessary a breather valve will often be justified by reduced breathing losses (Breather valves are effective flame arresters in themselves). Flow capacities of flame arresters may be determined from vendor's literature. According to API 2210 (Ref. 37), flashback through an open tank vent can only result from the coincidental occurrence of two unlikely events: efflux of a flammable mixture and the presence of an ignition source (such as lightning) at the right time and place. The records support the belief that the probability of this coincidence is very low. 5.8.3

Breather Valves

Breather valves, otherwise known as pressure-vacuum valves or PV valves, are devices that restrict the pressure in a tank to a fixed range above and below the prevailing atmospheric pressure. They are essentially pressure and vacuum relief valves combined in one valve body. A diagrammatic sketch illustrating the main features of a breather valve is shown below as Figure 21.

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Blanketing and purging

Nitrogen, inert gas or fuel gas is used to purge or blanket the vapor space of a vessel or storage tank containing highly flammable or unstable materials. Figure 22 shows a typical gas blanketed storage tank scheme. The vent system has the following features: 

The tank has an emergency relief manway that opens at +5 inches w.c. This is sized for emergency pressure relief.



The tank has a conventional weighted pallet conservation vent. The important characteristic of this device is that it operates on pressure difference. The valve is sized for normal pressure relief of vapor to the atmosphere. The vacuum side of the valve is sized for emergency relief of only air into the tank.



The tank has provision for addition of gas to the tank for normal vacuum relief.

5.8.5

Vapor Recovery

Frequently, vapor recovery systems are included in storage facilities. Gas and vapor mixtures from blanketed or purged tanks are collected and the organic vapors are disposed of in one of several ways. The method of disposal chosen depends primarily upon economics. Usually organic vapors are recovered using refrigeration. The gas is discharged and condensed vapor is returned to storage. This method is generally used in cases of high value products and in locations where operation and service of a refrigeration unit are not inconvenient. A second method of disposal is incineration. In many of these cases, however, fuel gas must be added to the vapor in order to make it combustible. The economics of this solution depend largely on the value of the vapor incinerated and the quantity and cost of supplementary fuel gas. A third solution is carbon adsorption. This is regularly used for gasoline storage facilities. A carbon adsorption bed is connected directly to the tank vent and it adsorbs any organic vapor emissions. Periodically the bed is steamed out and regenerated and the resultant gasoline/water mixture is trucked back to the refinery for recovery. In some cases absorption is used. A liquid/ liquid absorber or scrubber is sometimes connected directly to tank vents. Alternately, the bed can be changed out when saturated. The choice of changing the bed out versus regeneration is based on an evaluation of the economics involved. One main constraint on the design of vapor recovery systems is the design pressure of the tank. The design pressure of most tanks is so low that very little driving force is left to push tank vapors through a recovery system. Most systems are designed large enough to take very low pressure drops. 5.9 Tanks for Specific Services 5.9.1

Crude Oil Tanks for Refineries or Import Terminals

Middle East crude oils will usually have flash points of less than 73 oF. Vapor pressures vary; Arabian Heavy will have a vapor pressure of about 4.5 PSI. Some crudes have vapor pressures as high as 7.0 PSI. Most foreign crudes will contain some salt, present as dispersed droplets of brine. Tanks will usually be large. Select a floating roof tank, and specify double seals.

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Gasoline, Naphtha, Benzene, Jet B, and Similar Material (See Table 13)

Gasoline is a high-value, high-vapor pressure, low flashpoint material potentially containing some Benzene. Benzene is extremely toxic, both by inhalation and skin contact. For storing high purity products, floating roof tanks are not permissible as leakage of water will occur at the seal. A fixed-roof tank may be specified for such applications. For small tanks, less than 64 ft. diameter, an API 620 or API 650 Annex F type tank may be specified. 5.9.3

Kerosene, Jet A/Al, White Spirits and Similar Products (See Table 13)

These materials are intermediate between the gasoline type materials and the gas oils. In cold to temperate climates these materials can be stored below their flash points at temperatures where their vapor pressures are low. Under these circumstances they may be treated as gas oil type material. In warmer climates these materials should be treated as gasoline. 5.9.4

Gas Oils, Diesel Fuel, Catalytic Cracker Feed (See Table 13)

These materials are all high flash point, low vapor pressure stocks which can be stored in fixed roof tanks without hazard or product loss. Select a supported fixed cone roof. 5.9.5

Hot Catalytic Cracker Feed

Gas oils (AGO and VGO) may be stored hot in order to conserve energy when downstream processing, such as cracking would involve heating the stock. In the case of catalytic cracker feed, the storage temperature will frequently exceed the flash point. Tanks must have fixed roofs. Internal floating decks are allowed by API 650 but the seal material must be suitable for the operating temperature. 5.9.6

Asphalt and Residual Stocks

These stocks are characterized by high viscosities at normal temperatures and sometimes by high pour points. Such stocks can be corrosive. The tanks in which these materials are stored are heated and insulated. Use fixed roof non-pressure tanks with open vents. Flame arresters are not normally necessary and can be dangerous. Roofs should be watertight and vents arranged to prevent ingress of water. See Table 24 for general practice matrix of tanks for specific services. 5.10 Storage Tank Data Sheets Standard storage tank data sheets contain information provided not only by the Process Engineer but also by other company specialists and the manufacturer. The Process Engineer is responsible for providing the following data on the data sheet: service, nominal/normal/working volume, max. flow in/out, density, viscosity, flash point, vapor pressure, operating/design temperature, design pressure, design density, material/corrosion allowance (for shell, bottom and roof), nozzles size and quantity, thermowell quantity and elevation and remarks if required. Process also, to determine if a sketch, on a separate sheet is required to fully define the process requirements. A sample Storage Tank data sheet (per API 650) can be accessed at: JNet\Work Location & Regions\Regions\Southern Regions\Houston Operations\Mechanical\Datasheets.

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SAFETY/ENVIRONMENT PROTECTION Tank Venting

In normal operation, storage tanks can be subjected to internal and external pressures due to the addition or withdrawal of liquid and the daily variation in ambient temperature. Protection against tank damage by these mechanisms is afforded by open vents or by pressure/vacuum relief valves, also know as "PV vents," "PV valves" or "breather valves". The venting requirements shall include the following conditions: 

Inbreathing resulting from a maximum outflow from the tank



Inbreathing resulting from contraction of vapors caused by a maximum decrease in atmospheric temperature



Outbreathing resulting from a maximum inflow of product into the tank and maximum evaporation caused by such inflow



Outbreathing resulting from expansion and evaporation due to a maximum in atmospheric temperature (thermal breathing)



Outbreathing resulting from the fire exposure

Emergency conditions that may threaten the integrity of storage tanks include the following: 

External fire.



Internal fire due to lightning or internal static discharge.



Sudden inrush of gas due to a loss of liquid level in a distillation column feeding the tank.

API-650 5.8.5.2 Normal venting shall be adequate to prevent internal or external pressure from exceeding the corresponding tank design pressures and shall meet the requirements specified in API 2000 for normal venting (Ref. 19) API-620 9.2.1 Tanks shall be protected by automatic pressure-relieving devices that will prevent the pressure at the top of the tank from rising more than 10% above the maximum positive gauge pressure except as provided in 9.2.2 (see Appendix K). API-620 9.2.2 Where an additional hazard can be created by the exposure of the tank to accidental fire or another unexpected source of heat external to the tank, supplemental pressure-relieving devices shall be installed. These devices shall be capable of preventing the pressure from rising more than 20% above the maximum positive gauge pressure. A single pressure-relieving valve may be used if it satisfies the requirements of this paragraph and 9.2.1. Venting requirements for both refrigerated and non-refrigerated atmospheric and low-pressure storage tanks are covered in API standard 2000 (Ref. 19) and API RP 520 (Ref. 20). 6.2

Weak Roof to Shell Attachments

API Standard 650 (Ref.1) describes a roof-to-shell attachment designed to fail at a lower pressure than any other joint. When a tank is provided with such a joint, referred to as a "frangible" joint, emergency venting provisions are not obligatory. However, making a weak joint can be problematic, therefore an emergency hatch is generally used, especially for small diameter tanks.

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For tanks with diameters equal to or less than 50 feet, emergency venting provisions are recommended even where a frangible roof is provided. The recommendation to provide emergency vent provisions for tanks of 50 feet diameter and less is based on an incident described by E.E. Morgenegg (Ref. 31). A 20 feet diameter tank containing methanol was struck by lightning, the contents ignited and the tank failed at the shell-to-bottom joint with catastrophic results. 6.3

Large Tanks without Frangible Roofs

For tanks with design pressures of less than 1 PSIG, API Standard 2000 (Ref.19) requires the provision of emergency venting for fire based on a maximum wetted area exposed to the fire of 2800 ft2. The reasoning described in the appendix to the standard is that for tanks with design pressures of less than 1 PSIG, complete involvement of the tank in a fire is unlikely and that, in any case, the overheating and failure of metal in the vapor space will occur before the development of the maximum vapor evolution rate. This argument is not firm for the following reasons: 

2800 ft2 is a very small wetted area. For a wetted height of 30 feet, the maximum height of fire involvement assumed in the API standard, the maximum diameter for a tank to be assumed completely involved in the fire is only 30 feet.



If the fire is assumed only to affect the tank below a height of 30 feet, the metal in the vapor space cannot be assumed to overheat and fail.



An internal fire, following a lightning strike for example, should be assumed to involve the whole surface of the stored liquid. 2800 ft 2 is the area of the top surface of liquid in a 60 feet diameter tank; still only a relatively small tank.

Emergency vent capacities should therefore be calculated based on exposure to the fire of the whole tank periphery to a height of 30 feet. Unfortunately, this will result in vent areas which are impracticably high even for moderate tank sizes. In this case the options are as follows: 

Choose a different type of tank. A floating roof design will usually be applicable, if not, consider pressure storage.



Accept the risk and take steps to minimize the consequences. Locate the tank remote from process areas and from other tanks. Install a dike of sufficient height to contain the contents in case of bottom seam failure. Install fixed water sprays to cool the tank surface. Provide foam facilities at the tank (Ref. 32 and 33).

6.4

Lifting Manways

Lifting manways provide emergency venting at comparatively low cost when emergency failure of the shell-to-roof joint is not acceptable. The manway starts to open when the tank internal pressure reaches the set pressure. One manufacturer claims 60 percent orifice efficiency at 40 percent above set pressure. For determination of the number of manways required, refer to manufacturers' data. 6.5

Fire Fighting

For the provision of general fire-fighting facilities in storage areas, The American Petroleum Institute has published a recommended practice on the subject (Ref. 21), which refers to publications of the National Fire Protection Association. A review of trends in the industry as regards fixed foam installations is provided in (Ref. 32).

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Location of Storage Areas

Storage areas should not be located where spills could involve processing equipment or populated areas. If possible, the storage areas should be at lower elevations than processing facilities. Facilities for draining the storage area must be provided. 6.7 Vapor Emissions Vapor Emissions are virtually the only environmental concern associated with storage tanks. For permitting or other regulatory purposes any emissions calculated will be checked by local, state or federal personnel against EPA AP-42 (Ref. 29). Therefore, emissions from vertical storage tanks are estimated based on the method presented in EPA AP-42, Section 4.3. To estimate working losses from low pressure tanks use API-2516 method (Ref. 8), which is not included in AP-42. Additional information can be obtained from the API publications that form the basis for the method presented in AP-42. API-2517

(Ref. 9)

Evaporation Loss from External Floating Roof 'Tanks

API-2518

(Ref. 10)

Evaporation Loss from Fixed Roof-Tanks

API-2521

(Ref. 12)

Use of Pressure-Vacuum Vent Valves for Atmospheric Pressure Tanks to Reduce Evaporation Loss

API-2523

(Ref. 13)

Petrochemical Evaporation Loss from Storage Tanks

See section 5.8 above for prevention of vapor emissions.

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Table 1: API Tank Specification Standards (Ref. 1)

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Table 2: API Specification 12D Standard Tank Dimensions (Ref. 4) 1

2

3

Design Pressure oz/in.² a

Approximate Working Capacity bbl (See Note)

4 Nominal Outside Diameter ft, in. A

8

9

Height of Overflow-line Connection b ft, in. C

7 Height of Walkway Lugs ft, in. D

Location of Fill-line Connection b in. E

Size of Connections in.

5

6

Nominal Height ft, in. B

Nominal Capacity bbl

Pressure, Vacuum

Hlgh-500 750 Low-500 Hlgh-1,000 1,500 Low-1,000 2,000 3,000 5,000 10,000

8, 1/2 8,1/2 6, 1/2 6, 1/2 6,1/2 4,1/2 4,1/2 4,1/2 3,1/2 3,1/2

479 746 407 923 1,438 784 1,774 2,764 4,916 9,938

15, 6 15, 6 21, 6 21, 6 21, 6 29, 9 29, 9 29, 9 38, 8 55, 0

16, 0 24, 0 8, 0 16, 0 24, 0 8, 0 16, 0 24, 0 24, 0 24, 0

15,6 23,6 7,6 15,6 23,6 7,6 15,6 23,6 23,6 23,6

13, 7 21,7 5, 7 13, 7 21, 7 5, 7 13, 7 21, 7 21,7 21,7

14 14 14 14 14 14 14 14 14 14

4 4 4 4 4 4 4 4 4 4

Tolerance

-

-

-

-

± 1/8 in.

± 1/8in.

± 1/8in.

-

NOTE The approximate working capacities shown in Column 3 apply to flat-bottom tanks. Type A (unskirted) cone-bottom tanks have 6 in. greater working height than the corresponding f1at-bottom tanks. The approximate increase in capacity is 17 bbl for the 15-ft, 6-in. diameter tanks, 32 bbl for the 21-ft, 6-in. diameter tanks, 62 bbl for the 29-ft, 9-in. diameter tanks, 104bblfor the 38-ft, 8 in. diameter tanks, and 208 bbl for the 55 ft diameter tanks. a See 5.17 for frangible deck limitations. b Viscous oil option. When so specified on the purchase order, tanks shall be furnished for viscous oil service. On such tanks, dimension C of the overflow-line connections shall be 6 in. less than shown in Column 6 above, and dimension E of the fill-line connection shall be 6 in., ± 1/8in.

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Figure 3: Standard Tank Dimensions (Ref. 4)

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Table 4: (Ref. 3) STANDARD API TANK SIZES DIMENSIONS

CAPACITY

WEIGHT (lbs)

BARRELS

GALLONS

DIAMETER

X

HEIGHT

500

21,000

15'

X

16'

11,200

1,000

41,000

21'

X

16'

18,800

1,150

48,000

18'6"

X

24'

19,600

1,200

50,000

23'

X

16'

21,500

1,500

63,000

26'

X

16'

25,000

1,750

75,000

23'

X

24'

26,000

2,000

88,000

25'

X

24'

29,000

2,500

102,000

27'

X

24'

32,100

3,000

126,000

30'

X

24'

37,200

3,650

153,000

33'

X

24'

42,400

4,000

170,000

30'

X

32'

43,500

4,850

204,000

33'

X

32'

49,500

5,000

210,000

33'6"

X

32'

50,500

5,000

210,000

30'

X

40'

50,000

5,500

230,000

35'

X

32'

53,300

6,100

257,000

37'

X

32'

57,800

7,150

300,000

40'

X

32'

65,000

8,650

364,000

44'

X

32'

75,000

8,950

375,000

40'

X

40'

74,000

9,650

407,000

46'6"

X

32'

85,900

10,100

424,000

42'6"

X

40'

83,000

10,310

433,000

48'

X

32'

85,000

10,700

450,000

40'

X

48'

86,300

10,800

455,000

44'

X

40'

97,100

12,100

508,000

46'6"

X

40'

96,000

12,100

509,000

52'

X

32'

107,000

12,100

510,000

42'6"

X

48'

95,600

12,900

540,000

48'

X

40'

99,300

14,000

580,000

50'

X

40'

121,200

15,100

635,000

52'

X

40'

125,000

15,400

650,000

48'

X

48'

117,200

Table 4 (continued) STANDARD API TANK SIZES

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DIMENSIONS

CAPACITY

WEIGHT (lbs)

BARRELS

GALLONS

DIAMETER

X

HEIGHT

16,800

700,000

50'

X

48'

135,500

18,100

760,000

57'

X

40'

147,000

20,100

840,000

60'

X

40'

156,500

24,100

1,010,000

60'

X

48'

184,000

24,375

1,023,000

66'

X

40'

86,150

25,100

1,050,000

67'

X

40'

191,000

27,400

1,150,000

70'

X

40'

205,600

29,800

1,250,000

73'

X

40'

221,000

30,100

1,260,000

67'

X

48'

225,100

32,900

1,380,000

70'

X

48'

244,000

35,700

1,500,000

73'

X

48'

264,200

35,800

1,500,000

80'

X

40'

264,000

40,420

1,700,000

85'

X

40'

293,000

42,910

1,800,000

80'

X

48'

315,900

45,300

1,900,000

90'

X

40'

326,000

48,300

2,030,000

93'

X

40'

347,000

49,600

2,080,000

86'

X

48'

359,000

54,400

2,280,000

90'

X

48'

390,000

55,900

2,350,000

100'

X

40'

394,000

67,100

2,820,000

100'

X

48'

472,000

67,700

2,840,000

110'

X

40'

473,000

80,600

3,380,000

120'

X

40'

574,000

81,250

3,410,000

110'

X

48'

570,000

96,700

4,060,000

120'

X

48'

681,000

100,470

4,220,000

134'

X

40'

699,000

109,700

4,600,000

140'

X

40'

765,000

120,560

5,060,000

134'

X

48'

846,000

125,900

5,290,000

150'

X

40'

871,000

131,600

5,530,000

140'

X

48'

920,000

143,200

6,020,000

160'

X

40'

985,000

151,000

6,350,000

150'

X

48'

1,050,000

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Table 5: Maximum Size and Nominal Capacity of API Small Tanks

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Table 6: Comparison of Roof Types

Figure 7: Common Roof Types for API Standard 650 (Ref. 28)

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Table 8: Comparison of Various Fixed Roof Tanks

Figure 9: Typical Fixed-Roof Tank (Ref. 6)

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Table 10 Non-Contact and Contact Aluminum Internal Floating Roofs

Figure 11: Typical Internal Floating Roof Tank (Ref. 28)

Table 12: NFPA Classifications (Ref. 22)

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Class IA IB IC II IIIA IIIB

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Description Liquids having flash points below 73°F and boiling points below 100°F. Liquids having flash points below 73°F but with boiling points at or above 100°F. Liquids having flash points at or above 73°F, but below 100°F. Liquids having flash points at or above 100°F, but below 140°F. Liquids having flash points at or above 140°F, but below 200°F. Liquids having flash points at or above 200°F.

Table 13: Typical Product Flash Points

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Chart 14 (Ref. 35)

Table 15: Two Most Common External Floating Roof Tanks

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Figure 16: Typical External Floating Roof Tank (Ref. 29)

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Figure 17: Isothermal Lines of Lowest One-Day Mean Temperatures (°F) [°C = (°F – 32)] (Ref. 1)

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Table 18 Standard Letter Designation for Nozzle Connections

Table 19 Preferred Locations for Tank Accessories

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Figure 20: Typical Floating Roof Tank Assembly (Ref. 28)

Figure 21: Pressure/Vacuum Valve

Figure 22: Typical Gas Blanketed Storage Tank

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Figure 23: API 650 Annex F Decision Tree (Ref. 1)

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Table 24: General Practice Matrix of Tanks for Specific Services

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Figure 25: Typical P&ID Arrangement for Storage Tanks (Ref. 34)