Relief Device Design

Pressure relief valves or other relieving devices are used to protect piping and equipment against excessive over-pressure. Proper selection, use, location, and maintenance of relief devices are essential to protect personnel and equipment as well as to comply with codes and laws. Determination of the maximum relief required may be difficult. Loads for complex systems are determined by conservative assumptions and detailed analysis. By general assumption, two unrelated emergency conditions caused by unrelated equipment failures or operator error will not occur simultaneously (no double jeopardy). The sequence of events must be considered. The development of relief loads requires the engineer to be familiar with overall process design, including the type of pump drives used, cooling water source, spares provided, plant layout, instrumentation, and emergency shutdown philosophy.

This section suggests methods to calculate relief capacity for most emergency conditions, including fire. A common reference for determining individual relieving rates is contained in Section 3 of API RP 521. The design of the proper relieving device must take into consideration all of the following upset conditions for the individual equipment item if such upset can occur. Each upset condition must be carefully evaluated to determine the "worst case" condition which will dictate the relieving device capacity.

Blocked Discharge

The outlet of almost any vessel, pump, compressor, fired heater, or other equipment item can be blocked by mechanical failure or human error. In this case, the relief load is usually the maximum flow which the pump, compressor, or other flow source produces at relief conditions.

Fire Exposure

Fire is one of the least predictable events which may occur in a gas processing facility, but is a condition that may create the greatest relieving requirements. If fire can occur on a plant-wide basis, this condition may dictate the sizing of the entire relief system; however, since equipment may be dispersed geographically, the effect of fire exposure on the relief system may be limited to a specific plot area. Vapor generation will be higher in any area which contains a large number of uninsulated vessels. Various empirical equations have been developed to determine relief loads from vessels exposed to fire. Formula selection varies with the system and fluid considered. Fire conditions may overpressure vapor-filled, liquidfilled, or mixed-phase systems.

Tube Rupture

When a large difference exists between the design pressure of the shell and tube sides of an exchanger (usually a ratio of 1.5 to 1 or greater), provisions are required for relieving the low pressure side. Normally, for design, only one tube is considered to rupture. Relief volume for one tube rupture can be calculated using appropriate sizing equations in this section. When a cool media contacts a hot stream, the effects of flashing should be considered. Also the possibility of a transient overpressure caused by the sudden release of vapor into an all-liquid system should be considered.

Control Valve Failure

The failure positions of instruments and control valves must be carefully evaluated. In practice, the control valve may not fail in the desired position. A valve may stick in the wrong position, or a control loop may fail. Relief protection for these factors must be provided. Relief valve sizing requirements for these conditions should be based on flow coefficients (manufacturer data) and pressure differentials for the specific control valves and the facility involved.

Thermal Expansion

If isolation of a process line on the cold side of an exchanger can result in excess pressure due to heat input from the warm side, then the line or cold side of the exchanger should be protected by a relief valve. If any equipment item or line can be isolated while full of liquid, a relief valve should be provided for thermal expansion of the contained liquid. Low process temperatures, solar radiation, or changes in atmospheric temperature can necessitate thermal protection. Flashing across the relief valve needs to be considered.

Utility Failure

Loss of cooling water may occur on an area-wide or plantwide basis. Affected are fractionating columns and other equipment utilizing water cooling. Cooling water failure is often the governing case in sizing flare systems. Electric power failure, similar to cooling water failure, may occur on an area-wide or plant-wide basis and may have a variety of effects. Since electric pump and air cooler fan drives are often employed in process units, a power failure may cause the immediate loss of reflux to fractionators. Motor driven compressors will also shut down. Power failures may result in major relief loads.

Instrument air system failure, whether related to electric power failure or not, must be considered in sizing of the flare system since pneumatic control loops will be interrupted. Also control valves will assume the position as specified on "loss of air" and the resulting effect on the flare system must be considered.

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Gasoline and LP-Gas Treating

Most gasoline and LP-gas streams contain sulfur in various forms and LP-gas and raw NGL streams also can contain carbon dioxide. Especially objectionable are hydrogen sulfide, mercaptans, and elemental sulfur. Gasoline containing hydrogen sulfide has objectionable odor and is corrosive. Mercaptans give an objectionable odor to gasoline and elemental sulfur makes the gasoline corrosive. Carbonyl sulfide in the LP-gas can hydrolyze and cause the product to become corrosive. A product containing the objectionable materials can be treated to remove the hydrogen sulfide, carbonyl sulfide, and elemental sulfur and to either remove the mercaptans or convert them to less objectionable compounds.

Hydrogen Sulfide and Carbon Dioxide Removal

Hydrogen sulfide and carbon dioxide can be removed from LP-gas and gasoline by liquid-liquid contacting processes using a caustic solution, aqueous alkanolamines, or solid KOH. The caustic wash processes are described later. The alkanolamine processes were described earlier in the gas treating section. For application, both a coalescer and a full flow carbon filter should be used to minimize the introduction of hydrocarbons into the regeneration section of the amine unit. When treating hydrocarbon liquids with amine, contacting is generally accomplished in a liquid-liquid contactor, though stirred reactors can be used. The tower should have a minimum of 20 feet of packing. The design flow rates for packed towers should not exceed 20 gpm liquid per square foot of cross sectional area.

Sulfur Removal

Elemental sulfur is removed from the gasoline by contacting it with a polysulfide wash solution. The solution is made up by using the following amounts of chemicals per 1,000 gallons of water: 1,000 lb. of caustic (NaOH), 800 lb. of commercial Na2S, and 20 lb. of sulfur. The sodium sulfide (Na2S) is melted in a vat by use of a steam lance. Add the sulfur to the melted Na2S. The sulfur must be completely dissolved in the liquid sulfide, and then this mixture is added to the 10% (1,000 gal. water and 1,000 lb. NaOH) caustic solution. Protective clothing and goggles should be worn when handling these chemicals.

Mercaptan Treating

Mercaptans can be converted to disulfides or removed from liquid hydrocarbons by several methods. The method or combination of methods that can be used depends on the mercaptan content of the product to be treated and the specification that must be met.

Carbonyl Sulfide Removal

Because carbonyl sulfide (COS) can hydrolyze and cause sweet LP-gas to become corrosive, and as the concern for minimizing total sulfur emissions has increased, there has been a growth of interest in removing COS from propane and LP-gas streams. Several alternative processes can be used. COS can, of course, be removed sacrificially by MEA. Mick has reported successful use of a combination of potassium hydroxide and methyl alcohol. This process is also sacrificial. The Malaprop process uses diglycolamine but requires unspecified modifications in the process flow from that used for gas treating. The ADIP process utilizes aqueous diisopropanolamine. Molecular sieves can be used for removing COS. The Malaprop, ADIP and molecular sieve processes are regenerative.

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Burner Retrofit Considerations

Flame Envelope

1. Conventional raw gas and premix burners have luminous flames. The combustion reaction occurs within the visible flame boundaries. The flame envelope is defined as the visible combustion length and diameter. Ultra-Low NOx and latest generation burners have non-luminous flames. Much of the combustion reaction is not visible. The flame length and diameter are often determined by inserting a CO probe into the firebox and defining the flame envelope as CO concentrations greater than 50 ppm.

2. Ultra-Low NOx and latest generation burners have longer flame lengths than conventional burners. Longer flame lengths change the heat transfer profile in the firebox. Longer flame lengths can result in flame impingement on the tubes and mechanical supports.

3. The flame diameter is often defined in terms of ratios of the burner tile outside dimension. Many burners have flame diameters that are1 to1-1/2 times the diameter of the burner tile. Since the tile diameters are often larger for Ultra-Low NOx and latest generation burners, the flame diameters at the base of the flame many be slightly larger. The flame diameter often necks outs, giving a wider flame at the top.

Physical Dimensions of Firebox

1. Optimized designs have burner spacing that is designed to have gaps between the flame envelopes. Since the tile diameters are often larger for Ultra-Low NOx and latest generation burners, retofits can result in closer Burner-burner spacing and flame interaction. Flame interaction can produce longer flames and higher NOx values. Flame interaction and congealing can interupts the flue gas convection currents in the firebox, reducing the amount of entrained flue in the flame envelope. This condition increases the NOx levels. Ultra-Low NOx and latest generation burners should be spaced far enough apart to allow even flue gas recirculation currents to the burners.

2. The burner centerline to burner centerline dimension is one of the most important dimensions in the firebox. Many tube failures are causes by flame and hot gas impingement. When Ultra-Low NOx and latest generation burners are being retrofitted, the larger size of the flame envelope must be evaluated. Firebox convection currents can push the slow burning flames into the tubes.

3. Flame impingement on refractory often causes damage. When Ultra-Low NOx and latest generation burners are being retrofitted, the larger burner diameter may result in the burners being spaced closer to the refractory. Unshielded refractory may require hot face protection.

4. Many heaters are designed for flame lengths that are 1/3 to ½ the firebox height. Ultra-Low NOx and latest generation burners typically have flame heights of 2-2.5 ft/million Btu (2-2.5 m/MW). Longer flame heights from Ultra-Low NOx and latest generation burners may change the heat transfer profile in the firebox. The longer flames may result in flame or hot gas impingement on the roof and shock tubes. These tubes may require protection to prevent failures. Protection may include metallurgical upgrades, increased tube thickness or tube shielding. Some older heaters have very short firebox heights and may not be suitable for retrofits to Ultra-Low NOx and latest generation burners.

5. When retrofitting burners, may companies test prototype burners in a test furnace with similar geometry and fuels as the heater to be retrofitted.

Fuel Treatment

1. While many conventional burners have orifices 1/8”(3 mm). and larger, Ultra-Low NOx and latest generation burners often have tip drillings of 1/16”(1.5 mm). These small orifices are extremely prone to plugging and require special protection. Most fuel systems are designed with carbon steel piping. Pipe scale forms from corrosion products and plugs the burner tips. Tip plugging is unacceptable for any burner, but it is even more important not to have plugged tips on Ultra-Low NOx and latest generation burners because plugged tips can result in stability problems and higher emissions. Many companies have installed austenitic piping downstream of the fuel coalescer/filter to prevent scale plugging problems.

2. Coalescers or fuel filters are required on all Ultra-Low NO_x and latest generation burner installations to prevent tip plugging problems. The coalescers are often designed to remove liquid aerosol particles down to 0.3 to 0.6 microns. Some companies install pipe strainers upstream of the coalescer to prevent particulate fouling of the coalescing elements.

3. Piping insulation and tracing are required on fuel piping downstream of the coalescer/fuel filter to prevent condensation in fuel piping. Some companies have used a fuel gas heater to superheat the fuel gas in place of pipe tracing.

4. Unsaturated hydrocarbons can quickly plug the smaller burner tip holes on Ultra-Low NOx and latest generation burners.

5. Higher hydrogen content in the fuel gas results in higher NO_x production. It also increases the stability of the flame.

6. Natural gas fuel has often produced unstable flames and flameouts on Ultra-Low NOx and latest generation burners. Its use should be avoided if possible.

Air Control

1. Ultra-Low NOx and latest generation burners must be operated at design excess air levels to control NOx emissions.

2. Most refinery general service heaters are natural draft heaters. It is important to control the draft at the design value, usually 0.1”(3 mm) H2O at the top of the radiant section. High drafts increase tramp air ingress and often result in higher excess air levels at the burners. This condition results in higher NOx levels on Ultra-Low NOx and latest generation burners. Automated draft control has been installed on retrofits to obtain better excess air control.

3. Ultra-Low NOx and latest generation burners are usually supplied with individual plenum boxes and individual damper controls. Because excess air control is so important on these burners, some companies have installed individual actuators on each burner damper for better control. Others have connected all the burner dampers on a jack shaft to control the excess air levels.

4. New heaters are designed with seal welded construction to prevent tramp air ingress. Many older heaters have bolted panel design. High temperature silicon and foil tape have been used on these heaters to reduce tramp air. Observation openings should be designed to minimize excess air ingress. Observation openings should be closed when not in use.

5. Ultra-Low NOx and latest generation burners are usually supplied with individual plenum boxes. Many of these burners are supplied with mufflers to control noise emissions. The mufflers are often an effective devise to eliminate excess air fluctuations due to wind. Windscreens are often installed to eliminate wind effects when burner mufflers are not used. A 15 mph wind can cause a ± 0.11” H₂O draft variation at the burner, resulting in a ± 15%change in excess air level for a burner designed at 0.4” H₂O draft.

6. Forced draft systems should be considered for Ultra-Low NOx and latest generation burner retrofits. The forced draft system provides better excess air control, eliminates wind effects, and the increased burner pressure drop often results in a smaller flame envelope.

7. Ultra-Low NOx and latest generation burners may be installed in a common air plenum. Internal baffles may be required to obtain even air distribution.

Structural Considerations

1. Hole for Hole Replacement is the optimum situation for retrofits. However, since many Ultra-Low NOx and latest generation burners have larger burner tiles and larger burner cutouts, hole for hole replacement cannot occur. It is often more economical to replace the floor when hole for hole replacement is not an option.

2. Ultra-Low NOx and latest generation burners often weight more than conventional burners. Retrofits may require additional structural bracing. Floor Levelness/ Refractory Thickness

3. Heaters floor steel should be level. Bowed sections should be repaired or replaced.

4. The floor refractory thickness should be checked to ensure the heater floor steel is an acceptable temperature.

5. Physical constraints below the firebox floor should be checked. There should be sufficient space underneath the burner plenum for tip removal.

Process Related Parameters

1. Ultra-Low NOx and latest generation burners often have longer flames that change the heat flux profile. This is especially important on cracking heaters such as cokers and visbreakers. The longer flames may increase the bridgewall temperature and change the duty split between the radiant section and convection section.

2. When the heat flux profile changes, the location of the maximum tube metal temperature changes. Retrofitting Ultra-Low NOx and latest generation burners in short fireboxes can result in high roof and shock tube metal temperatures.

3. Ultra-Low NOx and latest generation burners may have less turndown capability than conventional burners. High CO levels can occur when firebox temperatures are below 1240ºF. Flame instability and flameout can occurred when firebox temperatures are below 1200ºF.

4. Conventional raw gas burners can handle a wide variation in fuel gas composition. Since Ultra-Low NOx and latest generation burners are often designed at the limit of stability, a fuel composition change may cause a stability problem. Since methane fuel is the hardest fuel to burn, many companies specify burn test using methane as the test fuel.

5. The proper design basis for the burner retrofit is extremely important. Sometimes the process requirements have changed significantly since the furnace was designed. Important design basis items include:

1) Emission Requirements

2) Process Duty Requirements

3) Heater General Arrangement Drawings

4) Turndown Requirements

5) Fuel Composition Ranges

6) Fuel Pressure

7) Startup Considerations

6. It is important to review existing plant data accurately. Heater tube fouling may result in high bridgewall temperatures. Fouled convection sections may result in higher firing rates. Tramp air may result in high excess air levels. Stack dampers are often frozen in place.

Instrumentation

1. When retrofitting Ultra-Low NOx and latest generation burners, addition heater instrumentation is often required. Most companies will install analyzers to determineO₂ and NO_x levels. Some companies will install CO and combustibles analyzers.

2. When retrofitting burners, may companies install the firebox draft indication and damper control on the DCS system to obtain better excess air control.

3. When retrofitting Ultra-Low NOx and latest generation burners, Flame Scanners may be require to protect against flameouts during turndown and startup situations.

4. When retrofitting burners, minimum fuel gas pressure instrumentation may be require to protect against flameouts during turndown and startup situations.

5. The heater should have a bridgewall temperature indicator on the DCS system.

Operations

1. Many operators have been trained to observe luminous conventional flames. After retrofitting Ultra-Low NOx and latest generation burners, the operators will have to be trained to observe non-luminous flames. A bright yellow flame on an Ultra-Low NOx burner may be an indication of a burner setup problem.

2. Ultra-Low NOx and latest generation burners have non-luminous flames that are hare to detect. Bright burner tile or flame holder color is often an indication that the primary tips are operating properly.

3. Special startup procedures may be required for Ultra-Low NO_x and latest generation burners.

4. Special premix gun inserts and pilot designs may provide additional stability during startup and turndown conditions.

5. Ultra-Low NOx and latest generation burners may have less turndown capability than conventional burners. High CO levels can occur when firebox temperatures are below 1240ºF. Flame instability and flameout can occurred when firebox temperatures are below 1200ºF.

5. Ultra-Low NOx and latest generation burners are designed to operate within closely controlled oxygen levels to obtain the lowest levels of NO_x. This may require more operator attention and interaction.

Installation Checkout

1. Correct burner installation is extremely important on Ultra-Low NOx and latest generation burners. It is often beneficial to have burner company representatives assist in checkout before initial operation.

2. Tip orientation and tip height should be checked

3. The burner tile must be installed properly. Check the diameter in different locations to ensure proper diameter dimensions and concentricity.

4. The damper should be checked to ensure freedom of movement through the entire range of operation.

Instability Issues Specific with Low NOx Burners

CFD Modeling

1. CFD modeling (Computational Fluid Dynamic modeling) is a useful tool in modeling firebox conditions. It has been used in multi-burner systems to analyze problems such as flame interactions, firebox currents, and localized high heat fluxes.

2. CFD modeling capability is relatively expensive and should be limited to special situations.

3. CFD modeling capability is improving as companies gain experience. However, field results may vary significantly from the model results.

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Refinery Hydrogen Management

by Alan Zagoria, Solutions & Services

Introduction

Refiners today are finding that hydrogen is one of the most critical challenges facing them as they plan production of clean fuels. In addition, hydrogen management practices significantly impact operating costs, refinery margin, and CO2 emissions.

Therefore, an effective hydrogen management program must address refinery-wide issues in a systematic, comprehensive way. Managing hydrogen more effectively has been found to improve refinery profitability by millions of dollars a year, often enabling the refiner to avoid the capital cost of new hydrogen production.

The hydrogen system consists of producers, purification processes, consumers, and the distribution network itself. Daily operating decisions impact the performance of the hydrogen network and therefore profitability. There are tools and techniques available to manage each of these individual hydrogen network components. However, when you consider the refinery as a whole, instead of individual process units, there is much greater opportunity to impact the refinery profit. The key is to focus on the effect of hydrogen on the performance of hydroprocessing units, and therefore gross margin, to unlock significant profit improvement opportunities.

Hydrogen Producers

The primary sources of hydrogen in a refinery are catalytic reformers, hydrogen plants, and purchased hydrogen.

Catalytic Reformers – Operations

Operating conditions of the catalytic reformers (rates and severities) are typically set by overall refinery economics (the gasoline pool) rather than the need for hydrogen.

Hydrogen yields are primarily a function of the properties of the feed naphtha, severity, catalyst, and operating pressure. Since operating conditions are set by the Planning Department based on refinery-wide economics, there is little opportunity to improve hydrogen production through operating adjustments.

Hydrogen Plants - Operations

Hydrogen plants produce hydrogen primarily through the steam reforming and water gas shift reactions. The optimum operation (temperature, steam to carbon ratio) is unique to each hydrogen plant because the constraints in each unit will be unique. If the refiner's goal is to minimize the per-unit cost of hydrogen rather than maximizing production, there is a different optimum temperature and steam to carbon ratio. Since these optimum setpoints can change daily, as a function of rates and feed compositions, the operator should have the tools to optimize the reformer accordingly.

Increasing Hydrogen Production

In a catalytic reformer, there are a number of methods available to increase hydrogen production. Obviously, hydrogen production may be increased by modifying equipment to enable increased charge rate. Also hydrogen yields can be improved by changing the naphtha feed to one more favorable for hydrogen production; decreasing pressure; or replacing the catalyst charge with one that provides a higher hydrogen yield. Large increases in hydrogen production can be achieved through pressure reduction by converting from fixed bed to continuous catalytic regeneration mode. This type of project can be quite attractive if the alternative is building a new hydrogen plant.

For hydrogen plants, there are a number of approaches to revamp for higher capacity. Increases of up to 25% are common. Debottlenecking may be achieved by mechanical modifications to remove equipment constraints, adding pre-reforming, or adding post-reforming.

Hydrogen Recovery

Hydrogen recovery is typically much less expensive than hydrogen production. Look for hydrogen-containing streams, such as hydrotreater off-gases or “excess” hydrogen streams that are currently being sent to fuel gas or hydrogen plant feed. Hydrogen recovery is typically accomplished using either membrane or PSA technology. The optimum purification scheme takes into consideration feed stream compositions and pressures, required product purity and pressure, and the economic trade off of product purity vs. hydrogen recovery.

Debottlenecking existing purification units is often a very attractive way to increase hydrogen recovery. Debottlenecking of PSAs can be achieved through inexpensive cycle modification, adsorbent change, reduction of tail gas pressure, or additional beds. Membrane purifiers are typically debottlenecked by adding more membrane cartridges or pressure changes.

Hydroprocessing

A minimum hydrogen partial pressure (usually measured as reactor inlet purity or recycle gas purity) is required to operate with a reasonable catalyst life and reactor temperature. The minimum hydrogen partial pressure is not a fixed value. It is a function of current operating conditions – charge rate, feed properties, desired product properties It is critical to think beyond the issue of minimum hydrogen partial pressure. For any set of operating conditions there is an optimum hydrogen partial pressure. Since hydrogen partial pressure drives the reactions, increasing hydrogen partial pressure can enable increased charge rate, improved product properties, or longer catalyst life.

In hydrocrackers, it can enable improved yields, or greater conversion per pass. Therefore, increasing hydrogen partial pressure beyond the minimum can increase the refinery gross margin well above the additional hydrogen cost associated with increasing the hydrogen partial pressure. To maximize the profitability of these units, one must have a good understanding of the process characteristics and refinery economics. Detailed process models that reflect the performance of the units as a function of hydrogen partial pressure are required.

Best Practices for Hydroprocessing Operations

Operators should:

• Regularly monitor the hydrogen partial pressure in key hydrotreaters and hydrocrackers
• Have available hydrogen partial pressure targets that reflect current operating conditions and optimization of refinery gross margin
• Adjust hydrogen partial pressures accordingly

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