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ExxonMobil Proprietary SAFETY IN PLANT DESIGN

DISPOSAL SYSTEMS

Section XV-D

DESIGN PRACTICES

Page 1 of 28

March, 2004 Changes shown by ➧

CONTENTS Section

Page

SCOPE ............................................................................................................................................................2 REFERENCES.................................................................................................................................................2 DESIGN PRACTICES .............................................................................................................................2 OFFSITE DESIGN PRACTICE................................................................................................................2 GLOBAL PRACTICES.............................................................................................................................2 OTHER LITERATURE.............................................................................................................................2 BACKGROUND...............................................................................................................................................2 DESIGN PROCEDURE ...................................................................................................................................3 EQUIPMENT DRAINAGE .......................................................................................................................3 TYPICAL CLOSED DRAIN CONNECTIONS ..........................................................................................4 DISPOSAL OF HYDROCARBON-CONTAMINATED AQUEOUS PLANT EFFLUENTS ........................5 CLOSED RELEASE SYSTEM.................................................................................................................6 Types of Closed Release Systems.......................................................................................................6 BLOWDOWN DRUMS ..........................................................................................................................11 Advantages of Condensable Blowdown Drums..................................................................................12 Disadvantages of Condensable Blowdown Drums .............................................................................12 EFFLUENT DISENGAGING SYSTEMS................................................................................................18 Water Disengaging Drums..................................................................................................................18 PROCESS STREAM DIVERSION AND SLOP STORAGE ...................................................................20

FIGURES Figure 1 - Typical Non-Condensable Blowdown Drum Arrangement ....................................................22 Figure 2 - Horizontal Non-Condensable Blowdown Drum Sizing ..........................................................23 Figure 3 - Vertical Non-Condensable Blowdown Drum Arrangement ...................................................24 Figure 4 - Vertical Non-Condensable Blowdown Drum Sizing ..............................................................25 Figure 5 - Condensable Blowdown Drum..............................................................................................26 Figure 6 - CondensAble Blowdown Tank Solvent Service (Phenol, NMP, MEK, MIBK) .......................27 Figure 7 - Water Disengaging Drum......................................................................................................28

Revision Memo 03/04

Page 2 Page 4 Page 7

Page 9 Page 11 Figure 4

Updated references to Global Practices Revised closed drain header connection details. Added sizing basis for branches serving individual PR valve services and for branches serving multiple PR valve services. Corrected Equation 1a. Added Equation 1b Added maximum velocity limitation for short cumulative duration releases such as PR valves. Deleted level “C” Added LHA at level “D”

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ExxonMobil Proprietary Section XV-D

SAFETY IN PLANT DESIGN

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DISPOSAL SYSTEMS DESIGN PRACTICES

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SCOPE This section covers the design of: (a) facilities to handle equipment drainage and contaminated aqueous effluents and send them to appropriate disposal, (b) closed release systems to receive pressure relief device discharges, emergency vapor blowdowns, etc., and (c) facilities for process stream diversion and slop storage. Also covered are criteria for selecting the appropriate method of disposal. Design of flares is covered in Section XV-E.

REFERENCES DESIGN PRACTICES Section II Design Temperature, Design Pressure and Flange Rating Section III Fractionating Towers Section V Drums Section X Pumps Section XIV Fluid Flow Other sections of Section XV

OFFSITE DESIGN PRACTICE Section XXII ➧

Storage Facilities

GLOBAL PRACTICES GP 03-02-01, GP 03-02-04, GP 03-03-02, GP 03-06-04, GP 03-09-01, GP 03-12-01, GP 05-02-01, GP 08-01-01, GP 09-02-01, GP 09-07-01, GP 18-10-01,

Sewer Systems Pressure Relieving Systems Suction and Discharge Piping for Centrifugal Pumps Vents and Drains, Flushing and Cleaning Connections Winterizing and Protection Against Ambient Temperatures Valve Selection Internals for Towers, Drums, and Fixed Bed Reactors Cooling Towers Additional Requirements for Pressure Storage Spheres Accessories for Atmospheric Storage Tanks Additional Requirements for Materials

OTHER LITERATURE API Standard 650 - Welded Steel Tanks for Oil Storage Frangible Roofs - Are They Needed?, EE.36E.84 Piping Vibration Evaluation Guide, EE.21E.89 Hot Oil and Slop Tankage Safety Guidelines, 87ECS3R10

BACKGROUND The purpose of the facilities described in this section is to provide for safe handling of various drainage and emergency streams, so that they may be safely routed to sewer, tankage, flare, or other appropriate destination. Drainage systems specified herein ensure that flammable or toxic materials may be disposed of without hazard of fire or injury when equipment is taken out of service. Also described are systems to handle process water drawoffs, cooling water, and other aqueous effluent streams which may be contaminated with hydrocarbons, and which could otherwise create hazardous conditions if they were discharged directly to the sewer. Pressure relief device releases are routed to the flare via the closed release system comprising laterals, headers, and blowdown drums when the presence of liquid, toxic properties, or other factors would make direct discharge to the atmosphere hazardous. These criteria are detailed in Section XV-C. Emergency vapor blowdown facilities for process units are described in Section XV-F. Product and intermediate process streams may need to be diverted to alternative disposal if they are off-specification (e.g., during startup) or in the event of emergency shutdown of downstream equipment. EXXONMOBIL RESEARCH AND ENGINEERING COMPANY - FAIRFAX, VA

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Section XV-D

DISPOSAL SYSTEMS DESIGN PRACTICES

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DESIGN PROCEDURE EQUIPMENT DRAINAGE General requirements for valving and discharge of all vent and drain connections on process equipment are detailed in GP 3-6-4. This GP covers low point drains and high point vents, as well as connections specifically provided for equipment drainage and venting at shutdown or when taken out of service. Also covered are vents and drains for instruments, gage glasses, sample points, etc. As an additional requirement not covered by GP 3-6-4, regularly used drain connections and sample points in light ends service must be double valved. The requirements of GP 3-6-4 for discharge of dangerous materials to closed drain systems are supplemented by the following paragraphs. Disposal of Drainage of Process Equipment Contents - When items of onsite process equipment are taken out of service, either individually during plant operation or for general turn-around, means of draining and safe disposal of the residual liquid hydrocarbon contents must be provided, in accordance with the following:

PROCESS EQUIPMENT CONTENTS

LIGHT ENDS (RVP > 15 psia) (103 kPa abs)

HEAVIER THAN HEAVIER THAN LIGHT LIGHT ENDS, AT ENDS, AT TEMPERATURE ABOVE TEMPERATURE BELOW FLASH POINT FLASH POINT

Vessels with liquid inventory >25 gallons (0.1 m3)(1)(2)(4)(5)

Closed Drain Header

Closed Drain Header

Vacuum Truck(3)(6)

Vessels with liquid inventory ≤ 25 gallons (0.1 m3)(1)(2)(4)(5)

Closed Drain Header

Vacuum Truck(3)(6)

Vacuum Truck(3)(6)

Pumps (see also Section X-H)

Closed Drain Header

Vacuum Truck(3)(6)

Vacuum Truck(3)(6)

Compressor casing, cylinder and knockout bottle drains

Closed Drain Header

—

—

Notes: (1)

“Vessels" include towers, drums, and miscellaneous onsite equipment such as filters, strainers, separators, etc. Heat exchangers are treated separately below (see Note 4).

(2)

“Inventory" refers to liquid hydrocarbon contents at the top of the working level range. Tray holdup is included, but piping contents are disregarded.

(3)

Refinery preference may exceed these requirements. In such cases, additional 1 in. (25 mm) connections from equipment to the closed drain header may be installed [3/4 in. (20 mm) connections are adequate for pumps].

(4)

Heat exchangers, which are valved for on-stream maintenance, should be considered as “vessels" in the table above, according to inventory and contents. Shell sides and tube sides should be treated separately. However, if the liquid contents of an exchanger can be gravitated into connected equipment through the process piping before closing all the isolating valves, then the requirement for drainage (called for by the table) may be deleted.

(5)

Heat exchangers, which are not valved for onstream maintenance, require only a means of drainage for a unit shutdown situation. If the liquid contents of a heat exchanger cannot be gravitated or displaced (as part of the shutdown procedure) into a connected vessel which is provided with appropriate means of drainage, then the exchanger should be considered as a “vessel" and provided with drainage facilities according to inventory and contents in the table.

(6)

The methods of equipment drainage described above are considered to provide safe disposal of liquid hydrocarbon contents of most process unit designs. Other methods may also be safe, such as draining to closed system or oily water sewer when permitted by environmental regulations. High pour point materials, which could solidify, should not be drained to the sewer. If using open connections to sewers: •

Consideration must be given to prevailing conditions (wind, adjacent ignition sources, need for protective clothing, etc.).

•

The connection must be at least 50 ft (15 m) from any continuous ignition source.

•

The release must be controlled.

Closed Drain Header Systems for Flammable Liquids - Closed liquid drain headers are provided, according to the criteria described in the preceding paragraphs, for the safe drainage of light ends and light stocks which would otherwise cause hazardous releases of hydrocarbon to the atmosphere or to the sewer. The connections are relatively small, and are intended for preparation of equipment for maintenance. Design of closed drain header systems should be as follows:

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1.

2.

➧

Connections to equipment are typically 2 in. (50 mm) and 3 in. (80 mm) for process vessels and exchangers, according to the size of the equipment. Each connection includes an accessible block valve. A check valve should be included if overpressure or other hazard could result from reverse flow during simultaneous drainage from more than one vessel. Individual connections from the equipment are made into the top of the drain header. The header is normally a 3 in. pipe (80 mm) [2 in. (50 mm) may be adequate for small units]. The individual vessel drain lines should connect to the top of the elevated CDH line and the CDH should be sloped downward to a non-condensable blowdown drum.

TYPICAL CLOSED DRAIN CONNECTIONS Process Pressure Class 300 or Less

Process Pressure Class 400 or Higher

Class 300 or Less Process

Class 300

3/4" (20 mm) (1) 3/4" (20 mm)

2" (50 mm)

Process

Class 400 or Higher

3/4" (20 mm) (1)

Class 300

3/4" (20 mm)

2" (50 mm)

Note: (1) In lieu of a blind, a breakaway connection may be used.

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DISPOSAL SYSTEMS DESIGN PRACTICES

Section XV-D

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3.

The header is rated the same as the highest pressure rated equipment connected to it, is fitted with a safety valve if designed for a lower pressure rating, or is blinded or provided with a breakaway from the high pressure equipment and only used when the high pressure equipment is out of service. Consideration must also be given to special cleaning operations (e.g., steam-out). Sections of the header, separated by check valves, may be designed for different pressure ratings, but safety valve protection is still required for the lower-rated sections, unless the header cannot be over-pressured to more than 1.5 times the design pressure. Conversely, in some situations, it may be appropriate to provide PRV for the lower rated equipment connected to the closed drain header. 4. The header must be designed for the extremes of high and low temperatures and corrosive conditions, which can arise from the discharge of process streams into it. The flashing and auto-refrigeration of light ends liquids may require special materials. Specify a Critical Exposure Temperature (CET) for the system and/or the temperature to which the metal may be exposed by shock chilling. The actual metallurgical requirements covered by GP 18-10-1 should then be followed. It is usually economical to minimize the use of special materials by segregating such streams into separate sub-headers of the closed drain system. These sub-headers may be routed separately to the blowdown drum with a high level cut-off valve in each, or may be combined into a single line with high level cut-off valve. Where sub-headers of different piping materials are combined, the material of the lower temperature header is continued for the rest of the combined line, and is also extended back into the other header for 20 ft (6 m), preceded by a low temperature check valve. 5. The header and laterals should be heat traced and insulated in accordance with GP 3-9-1, where ambient temperatures or stream temperatures could result in solidification of heavy process streams, or in freezing of water or moisture that may be present. 6. Several 1 in. (25 mm) valved stubs should be provided at appropriate points in the header, to which temporary drain connections can be made from equipment where permanent connections would not be justified because of infrequent usage or small inventory. The stubs should be located at grade, within 100 ft (30 m) of such equipment. Closed Drain Headers for Special Materials - Closed drain headers are normally provided for safe drainage of equipment containing severely toxic, corrosive, pollutant or high-cost chemicals [e.g., phenol, n-methyl-pyrrolidone (NMP), sulfuric acid, mono-ethanolamine (MEA), sulfur dioxide, Flexsorb solutions, etc.] where there is an appreciable inventory in a number of processing vessels in a plant. The header should be at least 2 in. (50 mm) in diameter, and should be tied into the major vessels and equipment with 1 in. (25 mm) minimum size connections [3/4 in. (20 mm) is adequate for pumps]. The header may be routed to a gravity drain drum (with recovery to the process by pump or gas pressurization), sump, or to a pump-out pump returning to the process, or in the case of sulfuric acid, to the acid blowdown drum. If the drain drum requires a vent, the vent should be piped to a closed system, or to a safe location, depending upon the toxicity and vapor pressure of the materials drained.

DISPOSAL OF HYDROCARBON-CONTAMINATED AQUEOUS PLANT EFFLUENTS Aqueous Drawoffs from Hydrocarbon Vessels - Water or aqueous materials that are withdrawn continuously or intermittently from vessels where they directly contact hydrocarbons (for example, process water from distillate drums, and spent wash water or spent caustic solution from settlers) must be disposed of in such a way that entrainment or inadvertent withdrawal of hydrocarbon will not create a hazard. Disposal is therefore a function of hydrocarbon category, as follows: 1. Vessels Containing Light Ends - Shall discharge to water disengaging drum, sour water disengaging drum or spent caustic disengaging drum according to subsequent treatment methods. These drums must be designed in accordance with this section. 2. Vessels Containing Hydrocarbons Heavier than Light Ends, at Temperatures Above their Flash Points, with their True Vapor Pressure less than 15 psia (103 kPa abs), and which have: a. Continuous automatic level controlled drawoff shall discharge as in Par. 1 above, or into a vented section of the oily water sewer through a closed connection. If the drawoff is sour water or spent caustic, see Par. 2c below. If the drawoff contains toxics (e.g., Benzene) alternative wastewater treatment may be required. b. Intermittent manually controlled drawoff shall discharge through open connection to oily water sewer catch basin. If the drawoff is sour water or spent caustic, see Par. 2c below. If the drawoff contains toxics (e.g., Benzene) alternative wastewater treatment may be required. c. Sour water or spent caustic shall be discharged as in Par. 1 above, or to an atmospheric collection tank for subsequent disposal, provided the tank has adequate venting capacity for the contingency of receiving hydrocarbon and has means of skimming liquid hydrocarbon.

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3.

Vessels Containing Hydrocarbons Heavier than Light Ends at Temperatures Below their Flash Points: a.

Discharge to an oily water sewer catch basin through an open connection, except when the drawoff is sour water or spent caustic, see Par. 3b below. If the drawoff contains toxics (e.g., Benzene) alternative wastewater treatment may be required. b. Sour water or spent caustic must be discharged as in Par. 1 above, or to an atmospheric collection tank for subsequent disposal, provided that it has means of skimming liquid hydrocarbons. 4. Vessels Containing Hydrocarbon Liquids Heavier than Light Ends at elevated temperatures such that their true vapor pressure is 15 psia (103 kPa abs) or higher, must be considered as light ends. Aqueous drawoffs from vessels containing such materials (for example, crude desalters) shall be discharged in accordance with Par. 1 above. 5. Water from Tankage - Special disengaging facilities are not provided for water withdrawn from offsite tankage and pressure storage. Details of water drawoffs from these installations are covered by appropriate International Practices GP 9-2-1 and GP 9-7-1. Refer also to Sections XV-B and XV-J. Aqueous Effluents from Heat Exchangers - Tube failure in a water-cooled or steam-heated exchanger in hydrocarbon service will result in contamination of the effluent cooling water or condensate by the process stream if the latter is at a higher pressure. These effluents must therefore be disposed of such that hydrocarbon contaminations can be safely contained. Design requirements are as follows: 1. Special disengaging facilities are required in the following cases: a. Coolers and condensers in light ends service with the hydrocarbon inlet pressure greater than the cooling water outlet pressure under normal operating conditions. b. Steam heaters and reboilers with the hydrocarbon inlet pressure greater than the condensate outlet pressure under normal operating conditions, and where the hydrocarbon at steam condensate temperature has a true vapor pressure of 15 psia (103 kPa abs) or greater. 2. The special disengaging facilities may consist of one of the following: a. A water-disengaging drum designed in accordance with this section. b. A cooling tower, in the case of a recirculating cooling water system, provided that the safety features described in this section (see EFFLUENT DISENGAGING SYSTEMS) are incorporated. c. A condensate disengaging drum, in the case of steam condensate where recovery and reuse is required, designed in accordance with this section (see EFFLUENT DISENGAGING SYSTEMS). 3. For coolers, condensers, steam heaters and reboilers that are not covered by cases a. or b. in Par. 1 above, effluent cooling water and condensate are discharged as follows: a. To clean water or oily water sewer in accordance with Section XV-B, which limits the discharge temperature to a maximum of 120°F (49°C), or b.

To an atmospheric collection tank, in the case of steam condensate where recovery and re-use are required. If the hydrocarbon pressure at the exchanger inlet is greater than the condensate outlet pressure, then the tank must have means of skimming liquid hydrocarbon and the tank vent should be large enough to safely relieve the pressure generated. The vent must release to a safe location.

CLOSED RELEASE SYSTEM Closed Release systems are designed to handle Pressure Relief device releases, and may also be used to handle certain other emergency and non-continuous releases. These include drainage from fuel gas, compressor and absorber knockout drums, vessel/unit depressuring, water disengaging drum vents and feed diversion streams. The requirements to use a closed release system for PR devices can be found in Section XV-C under “Selection of Atmospheric or Closed Discharge for PR Valves." Types of Closed Release Systems 1. 2.

Conventional Flare System - The majority of pressure relief devices discharges must be routed to the flare through a closed system consisting of laterals, headers, and a blowdown drum. Condensable Blowdown Drum with Atmospheric Vent - Releases which can be totally condensed may be routed through a closed release system consisting of laterals, headers and a condensable blowdown drum, which may be vented to the atmosphere provided that the criteria defined in this section (under BLOWDOWN DRUMS) are met.

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3.

➧

Section XV-D

Segregated H2S Flaring System - Continuous releases (greater than 30 minutes) of hydrogen sulfide are normally routed to a segregated H2S flare system described in Section XV-E, to remove a potential source of plugging from the regular flare system. PR devices in concentrated H2S service are not considered “continuous releases." They should be routed to the regular flare system, and not to the segregated H2S flaring system which has a higher probability of plugging. H2S flare headers should be constructed for ease of isolation, washing out and dismantling for cleaning. The need for periodic cleaning of the H2S flare header must be recognized, and alternative routing for H2S releases must be provided for such occasions if a shutdown of the H2S sources cannot be tolerated. 4. Other Segregated Closed Systems for Special Services - Special closed systems are also provided for PR device releases in certain services where operating problems or hazards would result from discharge into the regular flare header. Such services include severely toxic, corrosive, polluting, or high-cost materials; and the following are examples of the special facilities required: a. Segregated header and condensable blowdown tank for PR devices discharging solvents [i.e., phenol, methyl ethyl ketone (MEK), dimethyl formamide (DMF), n-methyl-pyrrolidone (NMP), etc.]. b. Segregated header and blowdown drum system (which vents into a regular flare header) for PR devices discharging corrosive material such as acid or acid extract in processes such as alkylation or isobutylene extraction. c. Segregated sections of flare header to prevent the mixing of vapors which would react chemically causing the deposition of solids. For example, ammonia must be segregated from H2S or CO2 to avoid header plugging by ammonium sulfide or ammonium carbonate. In some situations, heating of the flare line may prevent reaction and formation of solid deposits. Refer to Section XV-E, Figures 13 and 14 to establish if this is a concern and aid in design if it is. Sizing Closed Release Systems Laterals and Headers (Flare Header) - The laterals and headers must be sized to limit the built-up back pressure to a level consistent with the PR valve being used at the design relief rate. See Section XV-C for allowable backpressure for pressure relief valves. Note that the contingency that sets the PR valve size is not always that which results in the maximum discharge line pressure drop. This is particularly true if different contingencies result in the relief of different phases or greatly different molecular weight or specific gravity fluids. Therefore, all valid contingencies should be checked. In addition, when considering a remote contingency, the built-up back pressure limitation is relaxed to the extent possible without violating the “1.5 Times Design Pressure Rule," (for example, this is equivalent to allowing the built-up back pressure limit for a conventional PR valve to increase to 25% of set pressure, assuming the equipment has been hydrotested to 150% of the design pressure). 1. Releases into the System - All releases tied into the closed system must be considered for sizing; this includes PR device discharges, fuel gas compressor and absorber knockout drum drainage, vapors vented from water disengaging drums, feed diversion streams, and vapor blowdowns. 2. Maximum Flow to be Handled - The system must be sized to handle the largest total flow from all of the sources connected to it resulting from any single contingency. The capacity of the system must also be checked for any remote contingency (within the “1.5 Times Design Pressure Rule"). Each part of the system, headers, laterals, blowdown and disengaging drums, etc., must be capable of handling the maximum contingency flow which can occur in that section of the header. Any continuous load, such as excess gas flaring or gas purge for flash back protection, is additive to the largest contingency. Each branch of the system that serves a single PR valve service (which may include multiple PR valves) should be sized based on the combined rated capacity of all the PR valves installed for that service (excluding installed spares,if any). Branches of the system that serve two or more PR valve services may be sized based on the combined design capacity of all the services that discharge simultaneously. A PR valve service, in this context, refers to one (or more) PR valves installed on a specific equipment item or piping section. The contingency design bases for evaluating release rates into the closed release system are defined in Sections of Section XV, as follows: a. b. c. d.

Pressure relief device discharge rates: Section XV-C (Part 1). Vapor blowdown release rates: Section XV-F. Vapor releases from water disengaging drums: this section. Feed diversion streams: this section.

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3.

Pressure Drops through the Closed Release System a.

b.

4.

Pressure drops through the closed release system are made up of individual component pressure drops of the laterals, headers, and blowdown drum. These pressure drops must be determined in conjunction with the following: (1) Pressure Relief Valves including their inlet and outlet piping: Section XV-C. (2) Flare including headers, flare seal (determined by dipleg submergence), flare stack, and flare tip: Section XV-E. With the flare tip and seal pressure drop and flare elevation fixed (in accordance with the Design Procedures in Section XV-E), the flare stack, headers and laterals are sized for the largest release, while not exceeding the maximum allowable operating pressure in the associated blowdown drums and water disengaging drums. These maximum allowable operating pressures, as described in this section, are in turn determined by: (1) Maximum allowable backpressure on PR valves, which is a function of set pressure, type of valve, and largest contingency. Back pressure limitations are discussed in Section XV-C, Part II, Effect of Backpressure, and Part IV, PRV Outlet Piping.

(2) Maximum allowable backpressure on vapor diversion (or blowdown) streams which will permit the desired design rate to be released from equipment. (3) Maximum allowable backpressure on water streams from equipment, which will permit the design flow to be released to the water-disengaging drum. c. Overall capacity design of the flare system consists of appropriate sizing of the laterals, headers, and flare stack to meet the above criteria, using the fluid flow calculation procedures described in Section XIV. Method of Sizing Laterals and Headers a.

5.

6.

Divide the closed release system into segments usually beginning and ending with piping connections, i.e., a segment of the main header starts where one lateral joins the header and ends where the next lateral joins the header. Laterals can be considered as a segment or broken into several segments in the same manner. b. Determine the size of each segment separately by evaluating all valid contingencies, single and remote, which would result in material being released into that segment. c. Add in any continuous loads to reach the total for each segment. Routing of Closed Release System Header through Process Areas - Closed release system headers (flare header) in process areas should be routed to avoid locations of particularly high fire risk, such as over pumps, near furnaces, etc. The headers and laterals should also be laid out and provided with isolating CSO valves and spectacle blinds, unless prohibited by local codes, such that it is not necessary for flare lines to remain in service in units which are shut down separately. Liquid Drainage from Closed Relief System - Accumulation of liquid in closed relief systems can impose appreciable backpressure and reduce relieving capacity. The following design features must be included to avoid these problems: a. PR devices should be mounted above the header, so that the outlet piping drains into the header. In exceptional cases, location below the header is permitted, with special drainage for the outlet piping, as described in GP 3-2-4. b. c. d. e.

The closed release header system should slope continuously down to the blowdown drum from all points where discharge piping from PR devices or other releases enter it. The required slope must be greater than 0.2%. There must be no low points or other liquid traps where liquid can accumulate in closed release systems. Heat tracing of laterals and headers should be provided where plugging by deposition of wax, ice or congealing of viscous liquids may occur. (Refer also to GP 3-2-4.) Some pressure relief devices can discharge two-phases into the Closed Relief System, thus, the header design and support must be good for slug forces. Two phase flow curves have been developed (see Figures 1 & 2 in Section XIV-D) by which the existence of slug flow can be predicted if the fluid properties and process conditions are known. The properties of the mixture are then used in Equation (1a) to determine the magnitude of the reaction force. See Report EE.21E.89 for further details.

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where: F W g V θ ➧

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æWö æ1 ö F = 2 çç ÷÷ V cos ç θ ÷ è2 ø è g ø

➧

Section XV-D

= = = = =

Eq. (1a)

Force, lb (kg) Flowrate, lb/sec (kg/sec) 32.2 ft/sec2 (9.81 m/sec2) Fluid velocity, ft/sec (m/sec) Included angle of the direction change

To determine the direction of the reaction force relative to the direction of flow upstream of the bend, use the following equation:

φ = arctan where: φ θ

sinθ 1 + cosθ = =

Angle between the reactive force vector and the direction of flow upstream of the bend Included angle of the direction change

Design Temperatures of Closed Release System - The design temperatures of a header or lateral in the closed release system are set by the extremes of the emergency operating temperatures which can result from any of the streams tied into it. If materials are handled at temperatures below 60°F (15°C) or if they can auto-refrigerate to below 60°F (15°C), a minimum design temperature must also be specified. The extremes of discharge temperature used for relief systems design are based upon operating failure contingencies. Thus, the design temperature for the purpose of materials selection for laterals and headers is taken as the design temperature of the protected vessel, with credit for temperature drop as described below. However, in external fire exposure contingencies, the design temperature selected may be exceeded by the process fluid temperature (e.g., in the case of high-boiling liquids) or by equipment surface temperature (as a result of flame exposure). While these fire contingency temperatures are not used to set the design temperature of the closed relief system, they shall be tabulated in the specification for use by the piping designer. Establish design temperatures by: 1. Dividing the closed release system, including the main header and all laterals, into segments usually beginning and ending with piping connections (i.e., a segment of the main starts where one lateral joins the main and ends where the next lateral joins the main). Each lateral can be considered as one or more segments depending on complexity. 2. Determine the design temperature for each segment from the material with the highest temperature entering that segment resulting from a single contingency. It is best to start with the segments furthest from the blowdown drum and work towards the drum. Credit may be taken for expansion cooling as a result of a release and ambient convective cooling of the upstream segments with zero wind on the hottest day during a 30-minute release. 3. The minimum design temperature is determined for each segment in the same manner as 1 and 2 above except the lowest temperature material entering each segment is identified. Also, the lowest ambient temperature will have to be considered if this is lower than any materials entering a segment. Shock chilling should be considered if a segment can be exposed to cold liquids released into it. See GP 18-10-1 when applying low temperature requirements. Where laterals of different piping materials are combined, the material of the lower-temperature header is continued for the rest of the combined line, and is also extended back into the other lines for 20 ft (6 m). Thermal Expansion or Contraction Temperatures - The maximum thermal expansion or contraction of the header and laterals are set by the hottest and coldest relieving temperatures, ambient conditions (solar radiation and lowest one day mean temperature), operational failure, or external fire exposure contingencies. If fire exposure contingency temperatures are higher than the system design temperature, the allowable thermal expansion stress for piping flexibility calculations may be up to twice the normal ASME B31.3 allowable stress. 1. Design for thermal expansion/contraction shall be as follows: a. Divide the closed release system into segments as in Par. 4a above. b.

c.

Determine the thermal expansion temperature individually for every segment by evaluating all single contingencies, which would result in material flowing through the specific segment. Use the single contingency, which results in the highest pipe wall temperature. If the pipe wall temperature is hotter, credit can be taken for convective cooling on the hottest day with no wind. Credit can also be taken for expansion temperature drop of the related material. All pipe support shoes, beams, etc., for the entire piping system must be designed such that the lines remain adequately supported after thermal expansion to the emergency operating temperatures of a fire contingency.

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d. 2.

Design for thermal contraction shall be based on the lowest possible metal temperature for the piping, which may be due to operational upset or ambient conditions. This may be ambient temperature. Handling Thermal Expansion in Closed Release System - Piping expansion loops are the preferred way of handling thermal expansion, however, sliding-type expansion joints, may be used in headers if required to achieve a reduction in pressure drop or where expansion bends may result in liquid surging. Bellows type expansion joints shall not be used. If sliding type expansion joints are used they must meet the following conditions: a. They are permissible only in low fire risk areas, such as offsite areas, at least 15 ft (4.5 m) from roadways and 50 ft (15 m) from continuous ignition sources such as furnaces. b. They must not be used in segregated H2S flare headers or similar services, because of the toxicity of the fluid, in case leakage should occur. c. The liquid or vapor is non-corrosive to the sliding surfaces. d. The system in which they are installed operates below 50 psig (345 kPa gage), however, specify 50 psig (345 kPa gage) minimum design pressure. e.

f. g. h. i.

Maximum temperature limit is 750°F (400°C). The minimum is 50°F (10°C) for intermittent service, because ice formation could cause the joint to bind. If a sliding joint is specified, the Design Specification should also include the following notes: Provide guides and anchors to eliminate piping moments and absorb thrust on joints. Sliding cylindrical parts of the joint shall be Type 18-8 stainless steel. Joint shall be internally guided to maintain axial alignment. Joint shall have a minimum of 6 packing rings with lantern ring and provisions for non-combustible lubricant injection. The packing material shall be suitable to 750°F (400°C) and shall be at least 1/2 in. square (13 mm square).

j. k.

Joint shall be protected with tie rod limit stops to prevent overextension or compression. Joint marking shall include design pressure and temperature, temperature range, ambient setting, maximum movement range for compression and extension. Isolation Valves for Pressure Relief Systems - Manual block valves for maintenance isolation purposes (line size for the laterals and header) are permissible in pressure relieving systems, provided that they are car-sealed open and comply with the requirements of CSO valves defined in Design Procedure Part 1 of Section XV-C and in GP 3-2-4. These CSO valves are permitted in the closed relief system lateral at the battery limit of a unit that shuts down independently of other units tied into the same header. Although gate valves are preferred special fail safe (open) high performance butterfly valves have been used successfully and are permissible if a detailed valve specification is prepared. Contact ER&E Mechanical Engineering Section for assistance. Acoustically Induced Vibration Problems in Header Systems - Large headers inherently have the potential for flow induced vibration problems. In particular, flare headers for gas piping systems in which high capacity pressure reducing valves discharge have experienced problems of fatigue failure where excessive turbulence and high acoustic energy existed. The turbulent forces excite complex modes of vibration in downstream piping components. These vibrations can in turn result in stresses exceeding the endurance limit for the materials and thus, fatigue failure. Pressure relief devices may have the capability of generating sufficient acoustic energy to cause fatigue failures in downstream discharge laterals and/or header piping. Potential vibration problems of this type should be considered early in the design stage of the header system. Guidelines for assessing the potential of acoustically induced piping vibrations in pressure reducing systems are contained in the Piping Vibration Evaluation Guide, EE.21E.89 (Section 7). 1. The following screening criteria should be used to recognize services with potential vibration problems requiring further detail evaluation: a. Downstream line size 16 in. (400 mm) and greater: mass flow rate greater than 200,000 lb/hr (91,000 kg/hr) or upstream to downstream pressure ratio greater than 3. b. Downstream line size 8 to 14 in. (200 to 350 mm): downstream line velocity greater than 50% sonic and upstream to downstream pressure ratio greater than 3. c. Downstream line size less than 8 in. (200 mm) swaged up or “Teed" to 8 in. (200 mm) or larger line: downstream line velocity greater than 50% sonic and upstream to downstream pressure ratio greater than 3. The above criteria are a guide for detecting potential problems with gas letdown systems and apply for the piping downstream of the pressure reducer under concern. Systems with only liquid flow are not identified as potential problems and need not be investigated. For systems with two-phase flow, use the conservative assumption of the total mass flow rate as gas. Any system exceeding these criteria should be further evaluated in accordance with the guidelines and calculation procedures set forth in the Piping Vibration Evaluation Guide, EE.21E.89 (Section 7). It is further

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2.

3.

➧

4.

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recommended that the Mechanical Engineering Services Section of EETD be consulted when a piping system problem is suspected. A distinction must be made regarding the length of service of the pressure reducing systems. Fatigue failure of any mechanical system depends on time, i.e., the number of cycles to failure. Therefore, the treatment required for a continuous service may not be justified for a short-term service. Short Term Service - A system in short-term service is defined as one which operates a total of 12 hours or less during the life of the plant. Pressure relief devices typically do not exceed this limit. Systems in short-term service exceeding the screening criteria indicated above should be evaluated in accordance with EE.21E.89. Services determined from this evaluation to require special treatment should be identified as follows in the Design Specification: Notes for Design Specification - The following design features should be applied to the discharge piping and header for approximately 300 ft (90 m) downstream from the PR device in question. (A more rigorous distance formula based on acoustic power level is given in EE.21E.89.) a. Use pipe with a minimum wall thickness of 1/2 in. (13 mm) to increase flexural stiffness. b. Use completely welded full wrap-around reinforcement pads at branch connections per ASME B31.8, Figure 13, Sleeve Type, with pad thickness equal to header wall thickness. c. Use wrap-around reinforcement at welded support shoes and anchors. Alternatively, all welding of these fittings to the pipe wall may be eliminated by the use of bolted shoes and anchors. d. Minimize all vents, drains, and small diameter connections. Those remaining must be double gusseted. Continuous Service - Pressure reducing valves which will be operated more than 12 hours during the life of the plant should be considered to be in continuous service. Such systems, which exceed the screening criteria given herein, should be further evaluated in accordance with EE.21E.89. Systems in continuous service believed to be fatigue prone per EE.21E.89 require more positive action to reduce the acoustically induced vibrations because of the greater potential for fatigue failures in these systems. Treatment alternatives for these services typically require measures to reduce the acoustic energy generated at the source. The Mechanical Engineering Section of EETD should be consulted when problems of this type are suspected. Maximum Line Velocity - Sonic conditions at piping discontinuities such as at branch connections, reducers, etc., can also result in unacceptable acoustically induced vibrations. Maximum vapor or mixed phase flow velocities in piping should not exceed 50 percent of sonic for releases expected to exceed 12 hours during the life of the plant or 75 percent of sonic for releases having a lower cumulative duration (such as pressure relief valve releases). Design for Startup Conditions - Closed headers must be designed for any abnormal conditions that may exist during commissioning of the header or plant startups.

BLOWDOWN DRUMS The blowdown drum serves to separate liquid and vapor so that the vapor portion can be safely flared or vented to atmosphere in the case of condensable blowdown systems, and the separated liquid is pumped to appropriate disposal or rerun facilities. The blowdown drum may be of the condensable or non-condensable type, according to the characteristics of the streams entering the system. Selection criteria, for each type of blowdown drum, are detailed below. Criteria for Selection of Condensable or Non-condensable Blowdown Drum - The main purpose of a blowdown drum is to disengage closed safety valve releases and various drainage, blowdown, and diverted materials into liquid and vapor streams which can be disposed of safely. Entrainment of liquid hydrocarbon into a flare stack is not acceptable, because it may result in burning liquid falling onto the ground or adjacent facilities. Even if the blowdown drum is effective in disengaging liquid and vapor, further condensation may occur downstream if the vented vapor leaves the drum at a temperature above ambient. A portion of such condensable materials in the blowdown drum vapor release may condense as a result of cooling in the flare header and contact with seal water, and then disengage in the flare seal drum. Condensable vapors, which are not condensed out at this stage, may condense in the flare stack or its inlet line, creating the potential for hazardous fallout of burning liquid from the flare. Condensed hydrocarbon in the seal drum may be entrained out with the effluent seal water, which is normally routed to the sewer, and may result in pollution, toxicity or separator problems. If the extent of hydrocarbon condensation downstream of the blowdown drum is such that acceptable limits may be exceeded, then one or more of the following features may be considered as methods of reducing or eliminating it: 1. Select a condensable blowdown drum for condensable releases, rather than the non-condensable type. If a condensable blowdown drum is not suitable for handling the total blowdown service (for example, if cold liquids are involved), then a combination of a condensable and a non-condensable drum may be used. 2. Locate the non-condensable type blowdown drum at a minimum permissible spacing (per Section XV-E) from the flare, to minimize condensation in the flare header.

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3. 4. 5.

Install a knock-out drum immediately upstream of the flare seal drum to remove material condensed in the flare header. Provide settling facilities to separate hydrocarbon liquid from the flare seal water effluent, and appropriate means of disposal, e.g., to slop storage. Where a group of connected vessels is considered as one unit for pressure relief purposes, consider the possibility of an alternative location for the PR device such that the discharge stream would contain a smaller quantity of condensable materials.

Advantages of Condensable Blowdown Drums 1. 2. 3.

They are effective as a means of removing heavy hydrocarbon vapors from emergency release streams, thus minimizing condensation problems in downstream equipment. They are effective as a means of reducing flare capacity requirements, flare header design temperatures, and flare header thermal expansion problems. They are able to disengage oil mist better than non-condensable drums.

Disadvantages of Condensable Blowdown Drums 1.

Even though some oil may be removed through skimming connections (if provided), condensed hydrocarbon is discharged with the effluent water, often in the form of an emulsion, which may result in pollution, toxicity, or separator overload problems. However, these may be eliminated, if justified, by emulsion breaking and/or settling facilities and appropriate means of disposal for the separated oil.

2. 3.

They are unable to handle significant quantities of liquid light ends or materials cooler than 32°F (0°C). Large condensing loads, if handled on a steady state basis, result in appreciable cooling water and blowdown drum capacity requirements. These loads may be reduced by the use of unsteady state condensing, for example by worm cooler, as described later in this section. Horizontal Non-Condensable Blowdown Drums (Normal Service) - Non-condensable blowdown drums for normal hydrocarbon service are designed in accordance with the following: 1. A typical non-condensable blowdown drum and its associated equipment and headers are illustrated in Figure 1. Typically, a horizontal drum with 90° inlet nozzles is used. Crinkled wire mesh screens are not permissible. 2.

3.

4.

5.

A single blowdown drum may be used for more than one process unit, if economically attractive. When this is done, all units served by it must be shut down in order to take the drum out of service, unless cross connections are made to another system of adequate capacity. Normally all closed pressure relief device discharges are combined into one header entering the drum, although separate headers and inlet nozzles are acceptable if economically advantageous. The following releases are also normally routed into the closed release system header (as opposed to the closed liquid drain header) since it is always open and has a lower back pressure: a. Fuel gas knockout drum condensate and absorber overhead gas knockout drum liquid. b. Compressor suction and interstage knockout drum liquid. c. Emergency vapor blowdowns, if provided. d. Vapor streams diverted from process units, if this facility is provided (see PROCESS STREAM DIVERSION AND SLOP STORAGE in this section). Dry gas streams, where there is no possibility of liquid entrainment, may however be diverted around the blowdown drum to the flare header leading to the flare seal drum. The closed liquid drain header is run as a separate line to the drum and provided with a high level cut-off valve with local manual reset. In some cases the closed drain system is segregated into a number of subheaders, as described in this section. Emergency liquid pulldown connections, if provided, are routed to the blowdown drum via the closed drain header. As described later, diversion of liquid streams in the light ends range, when provided on process units, may in some cases be routed to a non-condensable drum for disposal. In these cases, the diversion stream is normally tied into the closed drain header upstream of the high-level cut-off valve, increasing the header size if necessary. [But see Par. 6b below for exceptions to this routing].

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Sizing of the blowdown drum and location of the level instruments are based on the following (see Figure 2): a. Liquid holdup below the LH(CO)A (A-B in Figure 2) is the light ends stream diversion requirement (if required, see PROCESS STREAM DIVERSION AND SLOP STORAGE in this section) or the closed drainage requirement for residual process liquids at a normal shutdown, whichever is greater. This closed drain requirement is taken as 10% of the total liquid hydrocarbon inventory of all vessels in one process unit which are provided with closed drain header connections. The process unit to be used for sizing purposes is the one which has the largest closed drain requirement and which can shut down independently for turnaround. Inventory of vessels is calculated at the top of the working level range, excluding tray holdup and the contents of piping. In the case of vessels containing large liquid inventories, e.g., surge drums, the individual closed drain header requirement may be reduced below 10%, where appropriate, by taking credit for alternative means of disposal of the liquid contents. b. If light ends stream diversion to the blowdown drum is required to be continuously available for safety reasons (as opposed to economic or operability reasons), then the sizing basis described in Par. 6a above is modified as follows: (1) A LH(CO)A is provided at a low level (B1 in Figure 2), actuating a cut-off valve in the closed drain header. Holdup below this LH(CO)A is the closed drainage requirement, calculated as in Par. 6a above.

c.

d.

(2) A second LH(CO)A is provided at a higher level (B2 in Figure 2), actuating a cut off valve in the liquid diversion stream, which is routed to the blowdown drum by a separate line. (3) The holdup between the two LH(CO)A's must equal the liquid diversion requirement. The volume in the drum above the LH(CO)A [above the upper LH(CO)A when two are installed] is made up of a holdup capacity (B-D in Figure 2) for 30 minutes' accumulation of pressure relief device liquid releases, plus a vapor space (D-F) for the associated vapor release. The drum sizing is determined by single normal contingencies, not remote contingencies, which require the maximum combined space B-D plus D-F. In addition to the contingency which requires the maximum combined space B-D plus D-F and which determines the drum sizing (as described in Par. 6c above), other contingencies are considered as follows: (1) The single contingency which results in the largest accumulation (B-E) of pressure relief device liquid releases during 30 minutes, regardless of any associated vapor rate. The level at Point E is used for pumpout pump sizing, as described in Par. 15 below.

e.

(2) The single contingency which results in the largest vapor load regardless of any associated liquid load, is used to determine the maximum required vapor space C-F, and a high level alarm is placed at Level C. In considering the contingencies described in Pars. 6c and 6d above, vapor and liquid loads are evaluated on the following basis: (1) Vapor load considerations must include all pressure relief devices, emergency vapor blowdown, and vapor stream diversion sources which release as a result of a single contingency. (2) Liquid loads are considered from all pressure relief devices that discharge as a result of a single contingency, plus in each case an allowance for knockout drum liquids (fuel gas K.0. drums, absorber overhead K.0. drums, and compressor suction and interstage K.0. drums) equal to the inventory of all drums which discharge to the blowdown drum, at their LHA point. (3) The vapor residence time in the drum should allow larger liquid droplets to fall to the liquid surface. The method used follows API 521. The vapor space velocity, as measured through the vertical cross-sectional area above the emergency liquid level (D, in Figure 2) determines the residence time. The liquid “dropout velocity” is determined as follows: Uc = 1.15

g D (ρL −ρ V ) ρV C

where: Uc

=

Dropout liquid velocity, ft/s (m/s)

ρL

=

Liquid density, lb/ft3 (kg/m3) at operating conditions

ρV

=

Vapor density, lb/ft3 (kg/m3) at operating conditions

D

=

Liquid particle diameter, ft (m)

g

=

Acceleration due to gravity 32 ft/s2 (9.8 m/s2)

C

=

Drag coefficient (see figure below)

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The droplet size should be selected as follows for normal contingencies: (a) 300 microns for new installations (1 micron = 1 x 10-6 m = 3.28 x 10-6 ft). (b) 450 microns for new installations handling liquid with an average molecular weight of 100 or less. (c) 600 microns for existing facilities. For remote contingencies: (a) The droplet size may increase to 750 microns for all cases. (b) The required hold up capacity for pressure relief valve liquid releases may be reduced from 30 to 20 minutes. The vapor velocity should be limited to 25 ft/s (7.6 m/s) or less in all cases. 80 60

C(Re)2= 0.95 x 108 (ρ v) (D)3 (ρ L - ρ v) (customary units)

µ2 = 0.13 x 108 (ρ v) (D)3 (ρ L - ρ v) (metric units)

40 30

µ

Drag coefficient, C

20

(31) (32)

2

µ = Viscosity of gas, centipoises ρ v = Density of gas, pounds per cubic foot (kilograms per cubic meter). ρ L = Density of liquid, pounds per cubic foot (kilograms per cubic meter).

10 8 6

D = Particle diameter, feet (meters)

4 3 2 1.0 0.8 0.4 101

2

3 4 5 6 78 102

2

3 4 5 6 78

103

2

3 4 5 6 78

104

2

3 4 5 6 78

105

2

3 4 5 6 78 106

C (Re)2 DP15Df0B

Drag Coefficient, C, Dimensionless (from API-521)

7. 8.

9.

(4) The depth of the vapor space under any contingency should be no less than 20% of the drum diameter or 12 in. (300 mm), whichever is greater. f. A LL(CO)A with local manual reset is provided to trip the pumpout pump when the liquid has been pulled down to a low level. When an oil layer is required for steam coil protection (see Par. 12 below), appropriate drum volume must be allowed with the LL(CO)A above this volume. The blowdown drum design pressure is 50 psig (345 kPa gage). The maximum allowable operating pressure in the blowdown drum is determined by the lower of the following: a. The maximum allowable back pressure on safety valves, which discharge to the blowdown drum, according to set pressure and type of safety valve. b. The pressure at which vapor diversion from any gas compressor suction to the blowdown drum is required to be released. These facilities are normally provided on cat cracker and steam cracker process gas compressors. c. The maximum allowable operating pressure in any other condensable blowdown drum, water disengaging drum, etc., which vents into the same flare header. The blowdown drum design temperature is set by the extremes of emergency operating temperature from any of the streams tied into it. A minimum design temperature must be specified if materials handled will be below 60°F (15°C) or can autorefrigerate below 60°F (15°C).

10. Blowdown drum materials must be adequate for any corrosive substance that may be released into it, and for the temperature limits defined by Par. 9 above.

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11. A steam coil is provided in the blowdown drum for deicinq, winterizing, and weathering purposes. Sizing of the coil is based upon weathering off the light ends from the flashed liquids at the maximum level accumulated as a result of any of the design contingencies described in Par. 6 above. This material must be weathered in two hours to temperature and vapor pressure conditions, which will permit safe pumpout to associated slop or other receiving facilities. In some cases weathering must be followed by cooling of the pumpout stream (see Par. 15 below). For most applications, a steam coil consisting of a nominal 200 ft (60 m), of 2 in. (50 mm) pipe is adequate. The coil should be sloped to insure condensate drainage. 12. For services where the heating coil may be exposed to cold or autorefrigerated liquids, the design should be such as to prevent blockage by freezing of steam condensate. The following methods are available to achieve this: a.

A 2 in. (50 mm) steam trap bypass direct to sewer. This is required in all cases where temperatures below 32°F (0°C) may occur in the blowdown drum. b. Provision of a line for injection of low-pour gas oil or similar material into the blowdown drum. A level of gas oil submerging the coil acts as a heat sink, but this volume must be allowed for when the drum is sized. This is the normal protection used when temperatures below -50°F (-45°C) may occur in the blowdown drum. c. Connections for methanol injection into the steam coil inlet and outlet piping for de-icing. d. Use of vertical double pipe (bayonet type) steam heaters. e. Use of a hot oil heating medium to the coil, or a cascade heating system (e.g., steam/methanol). 13. The drum is provided with a drawoff boot of nominal 2 ft (0.6 m) diameter by 3 ft (1 m) in height, to collect water, caustic or similar aqueous streams. The boot shall have a separate steam coil fabricated from 1 in. (25 mm) pipe. Normally, hydrocarbons pumpout is from the bottom of the drum and water drawoff is from the bottom of the boot. The water drawoff may consist of a connection to the sewer or, in the case of sour water, a connection routed to sour water facilities or other suitable disposal. In cases where the drum is cold or there is minimal water, a single pumpout for both hydrocarbon and water may be provided at the bottom of the boot. 14. A steam-driver manually started and automatically shut off on low level is often preferred for the pumpout service because it is not always known where the material will be disposed. A reciprocating is sometimes selected as this type of pump and provides greater flexibility to hold suction with liquids of various volatilities. A spare pump is normally not required. If a centrifugal pump is used, then the following requirements of GP 3-3-2 apply. a.

The suction line should be sloped up from the pump to the drum a minimum of 1:50 if vapor can be present. The suction line should also have a valved vent located close to the pump suction nozzle if required to pump volatile liquids at a temperature below the maximum specified ambient temperature. This vent need not be left open continuously if pump is not automatically started. b. The discharge line should have a 1 in. (25 mm) valved vent if the pump handles C5 and lighter material. This connection should preferably be located between the discharge check and block valves. This valve does not need to be left open continuously. c. If the pump can be blocked in from a remote location, then low flow protection is required. The low flow protection system should be sized after the pump has been selected and should meet the requirements of GP 3-3-2. These requirements should be included in the design specification. Pump sizing is based on pumping out the total drum contents in two hours from the maximum accumulated liquid level, as defined in Par. 6d above. Due to the wide range of fluids handled, the pump should be specified for 7 ft (2 m) NPSH requirement at the suction flange (see Section X) and spacing between pump and blowdown drum should be minimized. Drum elevation should be such as to meet the pump NPSH requirement. The pump design temperature should be the same as that of the blowdown drum, and design pressure is set according to the disposal routing downstream. 15. Disposal of pumpout material from the blowdown drum is normally to pressure slop storage, light atmospheric slop storage, or other atmospheric tankage. As described in Section XV-B, design features must be incorporated to avoid the hazards of excessive vapor evolution or froth-over which can result from routing light or hot materials to atmospheric tankage. In addition, a cooler should be provided in the discharge line from the pumpout pump if either of the following applies: a. b.

The blowdown drum can receive hot liquids [above 200°F (93°C)], or The blowdown drum liquid (after weathering if necessary), if routed to an atmospheric tank for disposal, could result in the true vapor pressure of material in the tank exceeding 13 psia (90 kPa abs).

The cooler should be sized to cool the maximum pumpout flow to 120°F (50°C).

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Vertical Non-Condensable Blowdown Drums (Normal Service) - When sufficient plot area is not available for the installation of a horizontal drum, a vertical drum with a tangential inlet nozzle and an annular ring should be used (see Figures 3 and 4). The design criteria for vertical drums are the same as for horizontal drums with the following exceptions: 1. The vapor velocity and residence time is based on the horizontal cross section area. The dropout velocity, Uc, must be greater than or equal to the vapor velocity. The upper limit of 25 ft/s (7.6 m/s) for the vapor velocity, which was applied in horizontal drums, does not apply for vertical drums. 2. A tangential inlet nozzle with an annular ring and wear plate should be provided. The annular ring width should be the same as the inlet nozzle diameter and the annular ring vertical height should be 2.5 times the inlet nozzle diameter. No support members should be present within the annular ring area between the bottom of the annular ring and the liquid level. Materials and thickness of the annular ring and wear plate should be specified by the designer. 3. The core area for upward vapor flow, i.e., the drum cross sectional area minus the annular ring area, should be no less than 67% of the standard cross-sectional area. 4. A distance equivalent to the drum diameter should be provided between the bottom of the annular ring and the subway grating, which is located 6 in. (150 mm) above the drum highest liquid level. 5. The minimum permissible vertical distance between the top of the annular ring and the top tangent line should be 3 ft (1 m). 6. Four vertical anti-swirl baffles should extend from 6 in. (150 mm) below the Level High Cut Out Alarm (if there are two then the lower of the two) to the bottom tangent line. The baffle width should be about 10% of the drum diameter. 7. Anti-vortex baffles are required above the liquid outlet nozzle (refer to Section V-A and GP 5-2-1). 8.

One circular tier of subway grating is recommended to minimize reentrainment. The tier diameter is sized to allow a superficial liquid velocity of 0.1 ft/sec (3.5 cm/sec) or less through the annular gap between the tier edge and the drum shell. However, the minimum permissible annular gap is 2 in. (5 cm). The subway grating should be supported by bolting onto vertically oriented support clips welded to the drum shell. Grating spacing and tier are the same as for anti-vortex baffles (see Section V-A). Non-Condensable Blowdown Drums (Special Service) - In some cases, because of severe corrosion problems or for special process reasons, a unit must have its own separate blowdown system. The sulfuric acid alkylation process is an example. Here the discharge from pressure relief devices, which can contain acid emulsion, presents two particular problems: corrosion and slow disengaging of hydrocarbon from acid. The first vessel in the blowdown system is therefore an acid-hydrocarbon separator. This drum is provided with a pump to transfer disengaged acid to the spent acid tank. Disengaged liquid hydrocarbon is preferably pumped back to the process, or to slop storage, or a regular non-condensable blowdown drum. The vented vapor stream from the acid-hydrocarbon separator is bubbled through a layer of caustic soda solution in a neutralizing drum and is then routed to the flare system. As a minimum there should be sufficient neutralizing agent for a 30-minute release. To avoid corrosion in the special acid blowdown system, no releases, which may contain water or alkaline solutions, are routed into it. Condensable Blowdown Drums - Condensable blowdown drums (see Figure 5) are provided as a means of preventing liquid hydrocarbon condensation in flare systems, to reduce flare capacity requirements, or to prevent discharge of condensable hydrocarbons to the atmosphere. Typically, a vertical drum with a submerged 90° elbow inlet nozzle is used. In some cases they serve the additional purpose of reducing the maximum temperature of flared gases and hence minimizing thermal expansion problems in the mechanical design of flare stacks. A condensable blowdown drum functions by a direct contact water spray arrangement, which condenses entering hydrocarbon vapors heavier than light ends. Condensed hydrocarbons and effluent water are discharged through a seal to the sewer, and uncondensed light hydrocarbon vapors are vented to the flare or to the atmosphere where environmentally acceptable. The design basis for condensable blowdown drums is as follows: 1. The maximum vapor load in the drum is based on the largest release from pressure relief devices discharging as a result of a single contingency. Vapor velocities in the drum should be determined using the same methods as for noncondensable blowdown drums. Crinkle mesh wire screens are not permitted. 2. The vapor outlet should preferably be connected to the flare system. However, when the safety valve releases and other streams tied into the drum contain only a small quantity of non-condensable hydrocarbons or inerts, and where no pollution problems are anticipated, then an atmospheric vent is acceptable, subject to the following conditions: a. The vent must be located at least 50 ft (15 m) above grade, and at least 10 ft (3 m) higher than any equipment within a horizontal distance of 50 ft (15 m). b. The vent must be located such that if inadvertent ignition of the maximum hydrocarbon vapor release should occur, the resulting radiant heat densities at grade do not exceed the prescribed limits for personnel exposures. See Section XV-E.

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c. d.

3. 4. 5.

The dispersion of flammable or toxic materials must be adequate in relation to adjacent equipment and working areas. The drum must be protected against flashback per Pars. 3 and 5 below. In addition, a snuffing steam connection shall be provided if the vent handles continuous or intermittent releases of hydrogen (> 35%), methane (> 35%) or vapors above autoignition temperatures. Provide a steam connection, manually operated at grade at least 25 ft (7.5 m) horizontally from the vent for snuffing vent fires. This connection should be a minimum 1 in. (25 mm). The blowdown drum design pressure should be 50 psig (345 kPa gage). Section III-F, Direct Contact Heat Transfer, and III-J, Baffles," together with the following paragraphs, describes the design of the disc and donut section and the other internals of the drum. The pressure relief device header containing condensable hydrocarbons enters the side of the drum above the water reservoir and terminates in a 90° bend discharging into the reservoir below the water level. The end of the slotted distributor should be open, that is not capped. Vertical slots with equidistant spacing and having a total area equal to that of the inlet pipe are provided. The top of the slots should be sufficiently submerged below the liquid surface so that the volume of water between the surface and the top of the slots is equal to the volume of 10 ft (3 m) of the inlet line.

6.

Water requirements are normally based on reducing gas and liquid outlet temperatures to about 150°F (65°C). Selection of optimum temperature is based on considerations of temperature and composition of entering streams, and the extent to which subsequent condensation of effluent vapors downstream of the drum can be tolerated. The water supply should be taken from a reliable water system. If a recirculating cooling water system is used, then the circulating pumps and cooling tower basin must have adequate capacity to supply the maximum condensable blowdown drum requirement for 30 minutes. A Temperature High Cut-in with alarm in the inlet line actuates an on-off control valve in the water supply line. A restriction orifice in the control valve bypass admits 10 to 20 gpm (0.6 to 1.2 L/s) continuously to maintain the outlet seal. In the event of loss of water of failure of the TH(CI), an emergency backup water connection from the firemain shall be provided, with an RBV actuated from the control house, and a restriction orifice sized for the maximum water requirement. To identify the need to initiate the backup water supply, an independent high temperature alarm is required in the vapor outlet from the drum. 7. The water holdup in the base of the drum is sized to absorb the heat of the maximum blow for 2 minutes without exceeding 200°F (93°C). The water velocity beyond the reservoir baffle should not exceed 0.4 ft/sec (0.12m/s). 8. The seal height in the liquid effluent line (assuming 100% water at the maximum drum liquid temperature) normally is sized for 175% of the maximum drum operating pressure, or 10 ft (3 m), whichever is greater. However, a seal height of only 110% of the maximum drum operations pressure is permitted when one is applying the “1.5 times Design Pressure Rule" to remote contingencies (see Section XV-C). 9. Maximum drum operating pressures are typically in the range of 1 to 2 psig (7 to 14 kPa gage). Higher pressures are acceptable providing that maximum allowable pressure relief device backpressures are not exceeded. A higher pressure will reduce the size of the off gas piping but will require a deeper safety seal and may lead to excessive sewer gassing. Steam generated in the condensable blowdown drum due to evaporation of cooling water should be included in the drum effluent gas stream composition when calculating backpressures. 10. Because of the continuous water flow through a condensable blowdown drum, it can safely handle cold or autorefrigerating releases only to the extent that effluent liquid and vapor temperatures remain safely above 32°F (0°C) [e.g., 37°F (3°C)]. 11. When for process reasons atmospheric pressure drums must be continuously vented to the blowdown drum, an additional inlet nozzle is provided for the vent line. This is a flush type nozzle located in the side of the vertical drum between the top of the water reservoir and the bottom baffle. Unsteady State Condensable Blowdown Systems - In some cases where condensing loads are high, or where it is required to recover condensed liquid blowdown material for pollution, toxicity, or economic reasons, an unsteady state condensing system may be appropriate. Examples of such applications are as follows: 1. Worm Cooler on Condensable Blowdown Drum Inlet. By use of a worm cooler in the condensable blowdown drum inlet, the high water requirement for direct contact condensing is avoided. The worm cooler must be elevated and the coil continuously sloped to avoid any liquid traps in the header. The holdup of static water in the cooler must be adequate for the design condensing duty during 30 minutes, allowing for heating-up of the water in that period. This type of design should not be applied where solidification of heavy materials within the cooler coil may occur. 2. Condensable Blowdown Tank, Solvent Service. A blowdown tank is used in Phenol or NMP (N-methyl-pyrrolidone) extraction plants and methyl ethyl ketone (MEK) dewaxing units to handle streams containing solvent and heavy hydrocarbons (lubricating oil stocks). The blowdown tank is illustrated in Figure 6. The design basis is as follows: a. The maximum vapor load to the tank is based on the largest release from pressure relief devices discharging as a result of a single contingency.

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b.

3.

4.

Equipment design temperature is 350°F (175°C). Design pressure is 6 in. water gage (1.5 kPa gage) in the vapor space, with the tank full of liquid, and the tank construction incorporates a weak roof to shell weld seam per API-650. Tanks under 50 ft (15 m) diameter should be checked with the procedures in report, EE.36E.84 to ensure the roof seam will fail before the bottom seam when pressurized internally. c. The atmospheric vent stack is concentric with the tank and terminates at least 50 ft (15 m) above grade and at least 10 ft (3 m) above the highest equipment within a horizontal distance of 50 ft (15 m). Additional elevation must be provided if necessary to ensure that solvent concentrations at grade and at working platforms do not exceed the Threshold Limit Value (TLV). The stack is slotted inside the top of the tank, with the slot area sized for a maximum tank vapor space pressure of 4 in. water gage (1 kPa gage) at maximum vapor load. d. The tank is provided with continuous flashback protection, sized in accordance with Section XV-B. A dry seal to reduce purge gas consumption, as described in Section XV-E, is permissible if a purge gas lighter than air is available. e. A level of oil is held in the tank to cool and absorb the solvent in the entering vapors. For lube extraction, the oil is extract and for dewaxing the oil is dewaxed oil. Sufficient oil, at 100°F (38°C), is required to absorb the largest quantity of solvent discharged in the maximum pressure relief valve release as a result of a single contingency, without exceeding oil temperatures of 300°F (148°C) for NMP or Phenol or 200°F (93°C) for MEK. The duration of the maximum release need not exceed 30 minutes for sizing purposes. Tank size must be adequate to hold the oil inventory plus the volume increases resulting from the release. Take into account the thermal expansion of the oil from the starting temperature to ending temperature. For lube extraction this calculated volume should be increased by an additional 25% to account for froth or expansion resulting from non condensed vapor (stripping gas) or steam. The tank dimensions are selected such that the maximum liquid level is below the elevation of the header, which collects the solvent bearing releases. f. The tank bottom must be designed for complete withdrawal of water. Safe disposal for the water is required; normally this is returned to the process. g. Pumpout facilities are provided to return saturated liquid to the process after a safety valve discharge into the tank. h. Inlet vapor is distributed through the tank by a sparger. Condensable Blowdown Tanks for Other Services - A condensable blowdown tank, designed on a similar basis to that described above for solvent, may be provided in other services where a conventional condensable blowdown drum would not be acceptable (for example, due to effluent water pollution considerations with Dimethyl Formamide (DMF). A suitable absorbing material shall be specified (for example, water for DMF), and the design must include consideration of maximum permissible operating temperatures to prevent excessive vapor evolution or the boiling of water. Venting Condensable Blowdown Tanks to Flare - In installations where local pollution regulations would not permit venting a condensable blowdown tank in toxic service to atmosphere, a pressure drum or sphere, vented to flare, may be necessary.

EFFLUENT DISENGAGING SYSTEMS Disengaging drums are provided to remove hydrocarbon liquid and vapor contaminants from aqueous plant effluent streams, to permit them to be safely discharged to the sewer. Typically, a horizontal drum with a 90° elbow inlet nozzle is used. Criteria for the routing of effluent streams to disengaging drums are defined earlier in this section. The design basis for disengaging drums is described below. Water Disengaging Drums (see Figure 7) 1. The liquid inlet header is sized for the maximum water rate to the drum. The available pressure drop for flow is based on Par. 4, below. 2.

3.

The vapor load on the drum results from the entering hydrocarbon vapor or liquid flashing to equilibrium conditions at atmospheric pressure. The design vapor load is the largest quantity of vapor resulting from a single contingency, such as a split exchanger tube or failure of a water drawoff valve in the wide open position (multiple control valve failures are not considered, provided that the control valves are specified to close on air failure). The calculation procedure for flow through a split heat exchanger tube is covered in Section XV-C. Water draw-offs are examined to determine the maximum vapor load resulting from the water outlet control valve failing wide open, with flow assumed to be all from hydrocarbon layer in the drum. The vapor outlet may discharge to a flare or to the atmosphere when environmentally acceptable. Atmospheric discharge may be considered, provided that a safe location can be achieved, as defined by the following: a. The vent must be elevated to at least 50 ft (15 m) above grade and at least 10 ft (3 m) above the highest equipment within a horizontal distance of 50 ft (15 m).

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Section XV-D

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b.

It must be located such that if inadvertent ignition of the maximum hydrocarbon vapor release should occur, the resulting radiant heat densities at grade do not exceed the prescribed limits for personnel exposures. See Section XV-E. c. The TLV of any toxic vapor that may be discharged from the vent is not exceeded at grade or at any working platform. d. An open-ended vent pipe directed vertically upwards is required, with steam or inert gas injection for flashback protection and snuffing, as required by Section XV-B. 4. The maximum allowable operating pressure in the disengaging drum for purposes of sizing flare headers, water headers, and laterals from exchangers is determined by the lower of the two following values (operating pressure should be designed as low as practical, to maximize disengaging effectiveness): a. The maximum allowable operating pressure on any condensable or non-condensable blowdown drum which vents into the same flare header, or b. The maximum pressure at which normal water flow can still enter the drum from the lowest pressure source. 5. A design pressure of 50 psig (345 kPa gage) should be specified. 6. The water outlet system is designed to seal the drum and prevent entrainment of hydrocarbon or air into the sewer. Figure 7 indicates the normal layout incorporating a single loop seal. 7. Sizing of the drum and seal leg is determined by the following: a. The drum vapor space should be based on the same criteria as non-condensable blowdown drums, after taking into consideration the fact that the water level in the drum will be depressed at the design vapor load due to back pressure in the drum. To reduce the likelihood that the outlet water rate will be limited due to vapor entrainment, the drum water level should be based on 50 in. (1.3 m) per minute rising rate for the hydrocarbon vapors rising through the water. However, the minimum water level shall be no less than 18 in. (450 mm) above the bottom of the drum. A low-level alarm (LLA) shall be provided at the minimum operating level. b. The height of the seal in the liquid outlet (assuming 100% water at the maximum drum liquid temperature) normally should be equivalent to 175% of the maximum allowable operating pressure, or 10 ft (3 m), whichever is greater. However a seal height of only 110% of the maximum drum operating pressure is permitted when one is applying the “1.5 times Design Pressure Rule" to remote contingencies (see Section XV-C). 8. The drum should be provided with a high level alarm (to give warning of overload or seal blockage) located 6 in. (150 mm) above the normal level at maximum water flow and zero gage pressure in the vapor space. 9. A vortex breaker should be installed at the water outlet to prevent hydrocarbon entrainment to the sewer, if required to prevent entrainment from the liquid surface, see Section V. 10. Effluent water from the seal is discharged through a closed connection to a vented sewer manhole, so that any air drawn in through the siphon breaker vent may be disengaged, and to prevent hydrocarbon release at grade level. 11. Four skimming connections with valved connections should be provided at the outlet end of the drum, at the normal liquid level, and at 6, 12, and 18 in. (150, 300 and 450 mm) below the normal level. Liquid hydrocarbon skimmed from these connections should be pumped to a suitable slop system. A connection to the suction of a blowdown drum pumpout pump, if available, is adequate for this purpose. Disengaging Drums for Other Aqueous Streams - Aqueous plant effluent and drawoff streams, such as steam condensate, sour water, or spent caustic soda solution may require disposal to a disengaging drum, but the regular water disengaging drum may not be suitable. Special disengaging drums may therefore be required, for example, in the following cases: 1. Condensate is to be recovered and returned to treating and boiler feed water facilities. 2. Sour water is to be routed to sour water stripping facilities. 3. Spent caustic is to be recycled to fresh caustic make-up facilities, or routed to deodorizing or other disposal facilities. The design of these drums generally follows the same basis as that for water disengaging drums, except that a pump (with spare) is required to transfer the aqueous liquid under level control to the appropriate receiving facilities. Combination Water Disengaging and Blowdown Drums - In some cases, it is possible to combine the functions of blowdown and water disengaging drums in one vessel. However, PR devices discharging liquid hydrocarbons lighter than pentane should not be connected into the drum if there is a possibility that such liquids could accumulate and be released to the sewer through the seal leg. Also, the drum vent should be sized to prevent pressure buildup due to vaporization. In these applications, the design criteria for both services must be met and special attention should be paid to potential hazards and problems which may be introduced, such as:

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1. 2.

Liquid traps in pressure relief device release lines. Combinations of water and hot hydrocarbon releases which could result in steam generation, frothing, and pressure surges. 3. Combinations of water and cold or autorefrigerating hydrocarbons which could result in freezing problems. 4. Reliability of water supply, if condensable blowdown and water disengaging services are combined. 5. Contingencies which may require the drum to be used for both services simultaneously. Cooling Towers - When the criteria detailed above in Aqueous Effluents from Heat Exchangers require a means of safely disengaging hydrocarbon from effluent cooling water, an acceptable alternative to a water disengaging drum in recirculating water systems is a cooling tower which incorporates all of the process safety features covered in GP 8-1-1. Cooling tower design should also include a vent stack on the vertical return riser to the tower, usually a vertical “T" extending full line size above the distributors. It should include a small overflow line from the water interface to a sump to drain small amounts of oil leakage. In the event of a major leak or tube rupture in a gas cooler, the vent stack helps avoid damage to the piping and structure by hydraulic surges and reaction forces. However, the water return line to the cooling tower and the vent line must be designed for the surge forces resulting from the limiting vapor release.

PROCESS STREAM DIVERSION AND SLOP STORAGE Materials to be Handled - Plant designs must include means of safe disposal for various slop materials, such as the following: 1.

Liquid hydrocarbons accumulated in non-condensable blowdown drums, originating from pressure relief devices, closed drain headers, knockout drum drainage, etc. Facilities are normally provided at the drum for weathering volatile liquids and cooling hot liquids before disposal. 2. Oil-water mixtures and emulsions for example, from separators, tank bottoms, ballast water, etc. Heating of such materials is often necessary to separate oil and water. 3. Off-specification products during startup, shutdown and plant upsets. Means of disposal of all off-specification product streams must be available when it is no longer possible to contain these materials within the unit. In many cases, blending off in product tankage or downgrading to another product is possible. 4. Streams which must be diverted because of emergency shutdown of downstream equipment (for example, compressor failure). Diversion routes should be provided where such a contingency would otherwise require the immediate shutdown of the affected process unit, resulting in appreciable economic and operational debits. Methods of Disposal - The following means of disposal may be considered for disposal of slop materials such as the above: 1. Flare - Vapor streams, such as compressor suction diversion on catalytic cracking and steam cracking units, are normally routed to a flare. 2. Fuel Gas - Light hydrocarbon vapors may be routed into fuel gas mains for disposal if this does not upset the fuel balance. If a propane vaporizer is available, this may be used as a means of routing liquid light ends to the main. 3. Storage Facilities - Recycling or blending of liquid streams into feed or product storage, etc., can be used in many cases. However, the design of such disposal systems must include consideration of the potential for excessive vapor evolution and boilover that can arise from routing light materials or hot streams to tankage. These hazards, together with appropriate design features to minimize them, are discussed in Section XV-B. 4. Slop Storage - Slop storage facilities are of three basic types according to the materials handled: a. b. c.

Pressure slop storage for light ends materials. Light atmospheric slop storage for materials which do not require heating for emulsion breaking. Heavy atmospheric slop storage for materials requiring heating for emulsion breaking. In the case of Pars. 4b and 4c, the same safety considerations must be applied as in Par. 3 above. Materials accumulated in slop storage are normally routed to rerunning facilities or blended into appropriate tankage for disposal. Design of Slop Storage Facilities - When selecting the means of stream disposal, one should use routes which, to the maximum extent possible, utilize normal plant facilities and tankage, etc. Streams, which cannot be handled in this way, require slop storage facilities. Sizing of slop storage facilities is usually based upon the normal flow rates of all streams, which must be diverted to slop under a single contingency, for the period of time necessary to eliminate the contingency or to carry out a controlled shutdown. 1. Pressure Slop Storage - If pressure slop storage is required to handle slop materials in the light ends range, it must comply with the following: a. The type of pressure slop storage vessel is selected on the basis of cost. Generally a sphere is cheaper than a drum for capacities over 1000 barrels (160 m3).

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March, 2004

b.

2.

Section XV-D

The vessel is vented through a pressure control valve to a low pressure gas line (if available) or to the flare header. The design vapor load is based on the single contingency (for example, feed diversion from a particular unit) which results in the largest quantity of vapor flashed from entering liquids. c. Overpressure and vacuum protection must be provided in accordance with Section XV-C. d. An independent high level alarm (LHA) is provided at the maximum permissible filling height of the vessel. This height shall provide adequate vapor space to accommodate any thermal expansion that may occur after filling is completed. The maximum filling height shall be set so that when a tank filled to that level at the minimum anticipated storage temperature is exposed to an external fire, the thermal expansion of the liquid will not cause the slop level to exceed 90 percent of the liquid full level at the set pressure of the pressure relief valve. e. A manually controlled pumpout pump is provided to transfer slop to a suitable process unit for rerunning. The size of the pump is determined by rerunning requirements. When the blowdown drum and slop storage vessel are close together, the pumpout pumps may be manifolded so that both are interchangeable in either service. As an alternative to special pressure slop storage, the necessary holdup may be provided in a non-condensable blowdown drum, as described earlier in this section. Light and Heavy Atmospheric Slop - Light and heavy atmospheric slop storage are normally both necessary in the average refinery. Sizing depends on the refinery complexity, volume and number of finished and intermediate products, and available means of disposal or rerunning. Further details are given in Offsite Section XXII and Report 87ESC3R10 entitled “Hot Oil and Slop Tankage Safety Guidelines." This document was prepared by the European Safe Operations Committee.

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Figure 1 - Typical Non-Condensable Blowdown Drum Arrangement

Safety Valve Header System Absorber Knockout Drains Fuel Gas Knockout Drains

Unit 1

Emergency Vapor Blowdowns Sloped Down

Vapor Stream Diversion Vapor and Liquid Safety Valve Releases Closed Drain System Unit 1 Liquid Pulldown Closed Drains

From Unit 2 Lines Sloped Down to Blowdown Drum

CSO

CSO

Closed Drain Header (Cold Sub-Header) Heat Traced

Water Disengaging Drum Vent

TI LL(CO)A

LL(CO)A

L H(CO) Unit 1 Liquid Diversion Closed Drains

L HA

NON-CONDENSIBLE BLOWDOWN LG DRUM

L H(CO)

L L(CO) TI

LH(CO)A

Steam Closed Drain Header (Normal Sub-Header)

Ldl

Steam Water Drawoff

From Unit 2

Unit 1 Liquid Diversion for Safety

DP15DF1

To Flare Seal Drum

Ld(HA)

Steam

PUMPOUT PUMP

PUMPOUT COOLER (if required)

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To Atmospheric Light or Heavy slop, Pressure Slop Storage etc.

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March, 2004

Figure 2 - Horizontal Non-Condensable Blowdown Drum Sizing

Vapor and Liquid Safety Valve Releases, Emergency Vapor Blowdowns, Fuel Gas and Absorber Knockout Drum Drains, Vapor Stream Diversion Closed Drain Header To Flare

Liquid Diversion for Safety (2)

(2) F E D C B2 B1

Legend: (1) A B1 B2 C D E F

-

LL(CO) LH(CO)A1 LH(CO)A2 Max. Liquid Level for LHA Location Max. Liquid Level for Drum Sizing Max. Liquid Level for Pumpout Pump Sizing Top of Drum

- Closed Drain Header Requirement or Liquid Stream Diversion Requirement B1 to B2 - Liquid Stream Diversion for Safety Reasons2 B2 to D - 30 Minutes' Liquid from Pressure Relief Devices plus Allowance for Liquid from Knockout Drums2 B2 to E - Largest Liquid Load from Pressure Relief Devices Regardless of Vapor Load D to F - Vapor Space for 100% of Critical Velocity (3) C to F - Largest Vapor Load from Pressure Relief Devices Regardless of Liquid Load

A to B1

A

Water Drawoff

Steam

Notes: (1) See TEXT FOR DETAILS OF ABOVE SIZING BASIS. (2) 90º elbow inlet nozzles are recommended for this service. The minimum permissible distance from the maximum liquid level used for drum sizing (D) to the bottom of the inlet nozzles is 6 in. (150 mm). (3) 175% for "remote" contingencies.

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Pumpout from Maximum Liquid Level in 2 hours

DP15DF2

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March, 2004

Figure 3 - Vertical Non-Condensable Blowdown Drum Arrangement

Safety Valve Header System

Unit 1

Absorber Knockout Drains Fuel Gas Knockout Drains

Sloped Down

To Flare

Emergency Vapor Blowdowns Vapor Stream Diversion TI Vapor and Liquid Safety Valve Releases

From Unit 2

Water Disengaging Drum Vent

CSO

CSO

LL(CO)A

L H(CO)

Heat Traced Closed Drain System Unit 1

L H(CO)

LHA

LG

LL(CO)A

LL(CO)

LH(CO)A

Liquid Pulldown TI Closed Drains

Steam Ldl

Liquid Diversion

Unit 2

Water Drawoff

Ld(HA)

Closed Drains Unit 1 Liquid Diversion for Safety

PUMPOUT PUMP Steam

DP15DF3

PUMPOUT COOLER (if required)

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To Atmospheric Light or Heavy slop, Pressure Slop Storage etc.

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March, 2004

Figure 4 - Vertical Non-Condensable Blowdown Drum Sizing

➧

D 2do 3N

See D etail "A"

min

do

Vapor Outlet N ozzle Skirt

min

3'(1m)

45°

d

1N

2.5d

DET AIL "A" "A"

"A" d

B 2 to E

Tangential inlet Nozzle

W ear Plate

1N

Annular Ring Core Area T angential inlet N ozzle

L

D

W ear Plate

2"(50mm) min. 6" (150mm)

5N

E D

6" (150mm)

B2 B1

"B"

A

Subway G rating

Annular R ing (C losed at Top)

Location of Second inlet N ozzle if R equired SECT ION "A-A"

"B"

3' (1m)

Anti-swirl Baffles

Anti-Swirl Baffles Anti-Vortex Baffles

0.1 D 4N

2N

Legend: SEC TION "B-B" A B1

- LL(CO) - LH(C O)A 1

B2 D E

- LH(C O)A 2 - Max. Liquid Level for Drum Sizing (LHA) - Max. Liquid Level for Pumpout Pump Sizing

A to B 1 B 1 to B 2 B 2 to D B 2 to E

- Closed Drain Header Requirement or Liquid Stream Dinersion Requirement - Liquid Stream D iversion for Safety - 30 Minutes' Liquid from Safety Valves plus Allowance for Liquid from Knockout D rums - Largest Liquid Load Regardless of Vapor Load

NOZ Z LES & CONNEC TIONS NO.

SERVIC E

1N 2N 3N 4N 5N

C LO SED RELEASE SYST EM IN LET LIQ UID O UT LET T O FLARE W ATER DRAIN C LO SED DR AIN H EADER IN LET

DP1 5DF4

Note:

See text for design notes.

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Figure 5 - Condensable Blowdown Drum

Vent to Flare Header or Atmosphere

THA

PHA set at maximum allowable operating pressure

PHA

TI

Siphon Breaker Vent (Locate as for Manhole vent per IP 3-2-1)

From Cooling Water Header CSO

Backup From Fire Main

R.O.

TH(CI)A

RBV

R.O. TI

TH(CI) LHA 12 in. (300 mm)

Safety Valve Header containing condensible hydrocarbons

6 in. (150 mm)

Drain Connections

Cleanout Connections Note: (1) For "remote" contingencies, 110% seal depth is acceptable (see text for details). DP15DF5

Normal level at maximum liquid rate and zero pressure in drum

Head equivalent to pressure drop at maximum liquid rate

TI Seal inlet Chamber sized for 0.4 ft/sec (10 mm/sec) liquid velocity at maximum load

175% (1) of drum operating pressure during largest release to vent (10 ft (3m) of water minimum)

Water and Condensed Hydrocarbon to sewer. (Closed connection into sealed and vented manhole if hydrocarbon in effluent can discharge at temperature above flash point.)

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Figure 6 - CondensAble Blowdown Tank Solvent Service (Phenol, NMP, MEK, MIBK)

Condensible Releases containing Solvents from Pressure relief devices. Header elevation greater than maximum tank liquid level.

Vent to Atmosphere

Vacuum Breaking Connection

Slots sized for maximum vapor load at pressure of 4 in. (1.5 kPa) water gage

Sloped Down Flashback Protection Purge

Combined Vent Stack and Root Support

Extract or Dewaxed Oil Make-up EXTRACT OR DEWAXED OIL

LI

TI

TI Sparger

Steam

Pumpout to Process Unit

Water Drawoff

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DP15DF6

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Figure 7 - Water Disengaging Drum

Effluent Water from Heat Exchangers, Process Water Drawoffs, etc.

Seal water, 20 gpm (75t/min) minimum continuous supply of water (effluent plus seal water) required

Vent to Flare Header or Atmosphere Steam or Inert (Alternate to LLA) Purge

RO

Siphon Breaker Vent (Locate as for Manhole Vent per IP 3-2-1) Head equivalent to maximum water flow rate pressure drop

PHA (1) 6" (150mm) LHA

Normal level at maximum water rate and zero pressure in drum Minimum operating level at maximum water rate with drum at operating pressure during largest release to flare (see text).

LLA

18" (450 mm) MIN. 175% (2) of drum operating pressure during largest release to vent (10 ft (3m) of water minimum).

Anti-Vortex Baffle

Skimmed oil to Slop System

Cleanout Connections

Effluent Water to Sewer (Closed connection into Sealed and vented Manhole)

Notes: (1) A 90° elbow inlet nozzle is recommended for this service. The minimum permissible distance from the high liquid level (LHA) to the bottom of the inlet nozzle is 6 in. (150 mm). (2) For “remote" contingencies, 110% seal depth is acceptable (see text for details).

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DP15DF7