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ExxonMobil Proprietary SECTION XXV

FUEL SYSTEMS DESIGN PRACTICES

Section XXV

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December, 2003 Changes shown by ➧

CONTENTS Section

Page

SCOPE............................................................................................................................................................................................ 3 REFERENCES .............................................................................................................................................................................. 3 BACKGROUND ............................................................................................................................................................................ 4 DEFINITIONS............................................................................................................................................................................... 4 SYSTEM TYPES AND APPLICATION..................................................................................................................................... 6 DESCRIPTION OF A FUEL OIL SYSTEM................................................................................................................................... 7 DESCRIPTION OF A FUEL GAS SYSTEM ................................................................................................................................. 7 DESCRIPTION OF A PILOT GAS SYSTEM................................................................................................................................ 8 DESCRIPTION OF A GAS TURBINE FUEL SYSTEM ................................................................................................................ 8

SYSTEM DESIGN CONSIDERATIONS ................................................................................................................................. 10 RELIABILITY/FLEXIBILITY ........................................................................................................................................................ 10 ENVIRONMENTAL REQUIREMENTS....................................................................................................................................... 11 FUEL SELECTION..................................................................................................................................................................... 11 FUEL REQUIREMENTS ............................................................................................................................................................ 12 FUEL BALANCES...................................................................................................................................................................... 12 FUEL PROPERTIES .................................................................................................................................................................. 12 FUEL SYSTEM OPERATING CONDITIONS AND CONTROLS ............................................................................................... 13 PILOT GAS SYSTEM................................................................................................................................................................. 15

SYSTEM DESIGN PROCEDURES .......................................................................................................................................... 16 COMPONENT DESIGN CONSIDERATIONS ....................................................................................................................... 16 FUEL OIL SYSTEM COMPONENTS ......................................................................................................................................... 16 HIGH BTU/JOULE FUEL GAS SYSTEM COMPONENTS......................................................................................................... 21 LOW BTU/JOULE FUEL GAS SYSTEM COMPONENTS ......................................................................................................... 24

REVAMP AND EXPANSION PROJECTS .............................................................................................................................. 26 GUIDANCE AND CONSULTING ............................................................................................................................................ 26 APPENDIX A: RELIABILITY CHECK LIST ........................................................................................................................ 27 Purpose...................................................................................................................................................................................... 27 Common Areas .......................................................................................................................................................................... 27 Grass Roots / Major Projects ..................................................................................................................................................... 28 Revamp / Small Projects ............................................................................................................................................................ 29 Cold Eyes Review ...................................................................................................................................................................... 29

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Table Table 1 Typical Fuel Balance .......................................................................................................................................................... 30 Table 2 Typical Fuel Gases............................................................................................................................................................. 31 Figures Figure 1 Typical Fuel Oil System..................................................................................................................................................... 32 Figure 2 Typical Fuel Gas System .................................................................................................................................................. 33 Figure 3 Typical Flexicoking Unit Low Btu/Joule Gas System......................................................................................................... 34 Figure 4 Fuel Oil Accumulator Sizing .............................................................................................................................................. 36 Figure 5 Fuel Oil Tank Sizing .......................................................................................................................................................... 37 Figure 6 Typical Fuel Oil Surge Drum ............................................................................................................................................. 38 Figure 7 Fuel Oil Surge Drum Sizing ............................................................................................................................................... 39 Figure 8 LPG Vaporizer Sizing ........................................................................................................................................................ 40 Figure 9 Central Collection Drum Sizing.......................................................................................................................................... 41

EMRE FUEL SYSTEMS SPECIALISTS

CONTACT

PHONE NO.

EMAIL (@EXXONMOBIL.COM)

Nathan Keesecker

(703) 846–7481

Nathan.S.Keesecker

Andrew Turner

(703) 846–5934

Andrew.D.Turner

John Hardcastle

(703)846-7293

John.M.Hardcastle

Revision Memo 12/03 - Highlights of this revision are: 1. Overall update. 2. IP References changed to corresponding GPs 3. Consistency check performed with EMCC's Best Practice for Fuel Systems 4. Updates from Gas Turbine and HRSG Fuel Flexibility Guide (EE.10E.2000) 5. Updates from hMobil tutorials on Fuel Gas Systems (EPT 04-T-13) and Heavy Fuel Oil Systems (EPT 04-T-08) 6. Addition of reliability check list

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SCOPE This Design Practice (DP) presents the criteria and procedures for the design of process plant fuel systems. The systems covered are fuel oil, fuel gas and pilot gas. It is not intended to imply that these are the only fuel system configurations possible. The type of system selected depends on many factors, such as economics, type and source(s) of fuel and consumer requirements. This Design Practice does not cover instrumentation and controls for furnaces and boilers, burner selection criteria, or design details for onsite facilities. REFERENCES DESIGN PRACTICES Section II,

Design Temperature, Design Pressure and Flange Rating

Section V,

Drums

Section VIII-F, Fired Heaters (Burners) Section IX,

Heat Exchange Equipment

Section X,

Pumps

Section XI,

Compressors

Section XII,

Instrumentation

Section XIV,

Fluid Flow

Section XV,

Safety in Plant Design

Section XVI,

Thermal Insulation

OFFSITE DESIGN PRACTICES Section XXII, Storage Facilities / Systems Section XXVI, Steam Facilities Section XXX, Electrical Power Facilities GLOBAL PRACTICES ➧

GP 01–01–01,

Drawings, Diagrams, and Line Lists

GP 03–04–01,

Piping for Fired Equipment

GP 07–02–01,

Industrial Boilers

GP 07-04-01,

Burners for Fired Heaters

GP 09–01–01,

Spacing and Dikes for Storage Vessels and Tanks

GP 15–01–01,

Instrumentation for Fired Heaters

OTHER EXXONMOBIL REFERENCES ➧

ExxonMobil Blue Book ExxonMobil Refinery Construction Materials Manual Gas Turbine and HRSG Fuel Flexibility Guide (EE.10e.2000)

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BACKGROUND Process plant fuel systems are mainly collection and distribution systems. Fuels are collected from various sources within the plant and distributed to consumers at the required pressure, temperature and flow rate. Fuel consumers are typically process furnaces, boilers, incinerators, gas turbines, and gas engines. The basic design considerations and equipment will be illustrated using typical fuel oil/fuel gas systems. By necessity, these systems are somewhat less complex in terms of the number of producers and consumers than normally found in a plant. However, the principles and considerations are applicable to all fuel systems. DEFINITIONS ATOMIZERS Atomize liquid fuel into small droplets for rapid and complete combustion. Normal atomizing medium is steam but other means are available in the absence of steam. Refer to DP VIII-F for considerations and design criteria. CONTINUOUS PILOT A pilot that burns throughout the entire period the unit is in service, whether or not the main burner is firing. DESULFURIZATION A treating process that removes sulfur compounds from a petroleum stream. DEW POINT ➧

The temperature at which a vapor starts to condense when it is cooled. Of special concern is the dew point of the sulfuric acid in the flue gases produced when burning fuels containing sulfur (normally referred to as "acid dew point"). FIRM CAPACITY Total installed capacity minus spare equipment. FUEL GAS Any combustible gas used as a source of energy in a process plant. Typical heating value of refinery fuel gas is about 1000 3 Btu/SCF (37,000 kJ/m ). FUEL OIL SYSTEM A system which is designed to distribute any combustible liquid hydrocarbon that is designated as plant liquid fuel. These liquid fuels may range from naphthas to residuum. GII General Instructions and Information Design Specification. Lists plant utility, process and environmental conditions. HIGHER HEATING VALUE (HHV)

➧

The theoretical gross heat available from the combustion of fuel, assuming the water formed by combustion is condensed. HHV is usually expressed as Btu/lb (kJ/kg). INTERMEDIATE BTU/JOULE GAS 3

A fuel gas typically in the 200-400 But/SCF (7,500-15,000 kJ/m ) range produced from coal or residual petroleum products via an oxygen blown gasification process.

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INTERMITTENT PILOT A pilot that burns during light-off of the main burner and while the main burner is firing, but which shuts off with the main burner. INTERRUPTED PILOT A pilot that burns during light-off of the main burner and is then shut off. INSTALLED CAPACITY The total available capacity of a system or component. LIQUID FUEL Any combustible liquid hydrocarbon used as a source of energy in a process plant fuel oil system. LOW BTU/JOULE GAS 3

A lean fuel gas typically in the 100–150 Btu/SCF (3700 - 5600 kJ/m ) range produced from coal or residual petroleum products via an air blown gasification process. As pertaining to FLEXICOKING, a fuel gas produced by steam/air gasification of process–produced fluid coke with a LHV of approximately 110 Btu/SCF (4100 kJ/m3). LOWER HEATING VALUE (LHV) The net heat available from the combustion of fuel, assuming that the water formed by combustion remains in the vapor state. LHV is usually expressed as Btu/lb (kJ/kg). Fuel balances are typically done on a LHV basis. LIQUEFIED PETROLEUM GAS (LPG) Light hydrocarbon material, gaseous at atmospheric temperature and pressure, held in the liquid state by pressure and/or refrigeration to facilitate storage, transport and handling. Commercial liquefied gas consists mainly of propane and/or butane. MARGINAL FUEL ➧

The fuel source that balances the fuel demand. The control system will be designed to regulate the fuel flowrate from this liquid or gas source to maintain the fuel gas system pressure. Liquid fuel may be used as the marginal fuel by increasing the fuel oil firing to reduce the fuel gas consumption or vice versa. MIDDLE DISTILLATES Distillates whose boiling ranges lie between those of kerosene and lubricating oil. These include light fuel oil and diesel fuel. NAPHTHA A general term applied to low–boiling liquid petroleum products, ranging from butane to 430°F (221°C) final boiling point. PITCH The residuum from the distillation of crude petroleum, natural asphalts, etc. (a virgin product). Where pitch and tar are used as fuel, these systems operate at high temperature. RESIDUAL FUEL OIL A petroleum product intended for combustion in large industrial installations, composed mainly of pitch, tar and the bottoms from distillation processes, with enough lighter oil added to give a product of satisfactory viscosity. RESIDUUM The material remaining as non-vaporized liquid or solid from processes involving distillation or cracking (often abbreviated to “resid").

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SOUR GAS Hydrocarbon gas containing malodorous sulfur compounds, such as sulfides and mercaptans. The most prevalent of these compounds are hydrogen sulfide and methyl mercaptan. SWEET GAS Hydrocarbon gas that is relatively free of sulfur compounds. TAR The bottom product from any cracking operation (a non–virgin product). TURNAROUND The period during which an entire process unit is off stream for inspection and repair. TURNDOWN Capability of equipment to operate at lower than design capacity. Turndown is typically expressed as a ratio of Maximum Design Capacity to Minimum Operating Capability. VISCOSITY Viscosity is the measurement of a fluid's resistance to flow. Since viscosity varies with temperature, its value is meaningless unless the temperature at which it is determined is reported. For liquids, viscosity decreases with increasing temperature. The opposite is true for gases. There are many methods of determining viscosity and therefore different units of reporting are used. The more customary unit of kinematic viscosity is the centistoke (cSt). Other units of viscosity are Saybolt Universal, Saybolt Furol, Engler, and Redwood. In designing liquid fuel systems, viscosity plays a major factor as related to pumpability and atomization at the burners. Heating of the liquid fuel is often required to achieve and maintain design requirements. WOBBE INDEX A measure of Btu/sec (Joule/sec) that can pass a given orifice. In addition to the heating value of the fuel, it also considers the effects of specific gravity and temperature. Therefore, it is a better indication of heat input to combustion equipment than heating value alone. Acceptable variation in Wobbe Index should obtained from the combustion specialist or the equipment manufacturers (for boilers, gas turbines, etc.).

Wobbe =

LHV SG x Temp

SYSTEM TYPES AND APPLICATION

➧

Typical fuel oil and fuel gas systems are shown in Figures 1 and 2, respectively. A low Btu/Joule gas system is shown in Figure 3A. Although not interconnected, the oil and gas systems are interrelated since individual furnaces and boilers can in many cases fire both oil and gas, either separately or simultaneously. Thus, the total refinery fuel requirements are shared by each system according to the respective fuel availability and consumer demand. In addition, a pilot gas system is also required. The symbols and nomenclature used in the figures are defined in GP 01–01–01. A brief description of each of these three systems follows.

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DESCRIPTION OF A FUEL OIL SYSTEM Liquid fuel is supplied from process units, blending systems, product tankage or a combination thereof. More than one source is usually provided for increased reliability. A fuel oil tank or surge drum provides reserve holdup for use during emergencies or system upsets. Pumps distribute fuel oil to process and offsite consumers at the required operating conditions. Normally, a looped distribution network is provided. Looping (e.g. with recirculation) is not required for lighter liquid systems such as naphtha and kerosene. Lighter (more volatile) fuel systems also require special attention with regard to burner selection and general safety precautions (as detailed in DP Section VIII-F). Typically, two 100% capacity fuel oil pumps with different types of drivers are provided. The spare pump will start automatically if the system pressure falls below a preset level. The looped distribution network keeps fuel temperatures in all parts of the system high enough to avoid plugging and to maintain a constant viscosity at the burners. The network contains sufficient valves and blinds to allow system components, individual consumers or groups of consumers to be isolated for maintenance. A pressure control valve located downstream of the last consumer on the loop controls the network. Flow rate and temperature are monitored at various locations in the system. Strainers are provided to protect the burners from particulate matter, such as pipe scale and coke. Heaters are employed in the system when the temperature of the fuel oil must be increased to meet minimum temperature and/or maximum viscosity requirements of the consumers. An accumulator is used to maintain system pressure during automatic startup of a spare pump. The accumulator is pressurized by an external nitrogen source and is located in the system to protect critical consumers. For typical heavy fuel oils stored at temperatures under 200°F (93°C), heaters are used to raise the temperature of the fuel oil in excess of 250°F (121°C) to achieve the proper viscosity at the burners. The designer must consider potential problems during periods of low fuel demands with this system. During these periods, the hot recycle stream makes up a greater proportion of total pump flow that has resulted in cavitation problems at several affiliate locations. In addition, sending the recycle stream back to the atmospheric storage tank poses the risk of hydrocarbon/water boil-over of the tank by exceeding its maximum operating temperature. Solutions to this problem are generally a compromise between risk and operating flexibility. Heavy resid fuels are typically run off the unit as illustrated in Figure 6. Only a nominal holdup volume is provided in the pressurized surge drum. DESCRIPTION OF A FUEL GAS SYSTEM •

Refinery Fuel Gas (High Btu/Joule Gas) A fuel gas system may collect and distribute gas at one or more pressure levels, depending on consumer requirements. A high–pressure system is normally used to supply fuel to gas turbines. The low–pressure system supplies fuel to process furnaces and to offsite consumers such as boilers and incinerators.

➧

The fuel gas system is operated under pressure control. The high–pressure system is controlled by letdown of excess gas to the low–pressure system (upstream of collection drum) or by introducing backup gas (i.e., from an independent process or natural gas source). The low–pressure system is controlled by venting to the flare during periods of excessively high system pressure or by introducing backup gas from the high pressure fuel gas system or other sources; e.g., natural gas, LPG vaporizer, etc. Instruments are provided to monitor flow rates at various locations in the system. The refinery boilers normally handle large fluctuations in the overall refinery fuel oil/fuel gas balances. They are usually designed for multiple fuel firing and will be set to fire fuel gas preferentially to avoid flaring during sustained high fuel gas production. In some designs, automatic boiler fuel gas firing controls help to maintain a constant fuel gas system pressure. Before this type of control can be specified, a detailed analysis of the fuel and steam balances must be performed to determine if such a design is compatible with both the fuel and steam systems. A piping network collects and distributes the gas. Sufficient valves and blinds are provided to allow system components, individual consumers or groups of consumers to be isolated for maintenance. All fuel streams are sent to a central collection drum to dampen the effect of wide fluctuations in stream composition and thermal content. The drum is the pressure control point for the system. It provides volume to reduce pressure fluctuations and to disengage entrained liquid.

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The vaporizer is used to dispose of excess or off–specification LPG and as a backup source of fuel gas. Sometimes the functions of the central collection drum and the vaporizer may be incorporated into a single vessel although this is normally not the case. A heater superheats the fuel gas to minimize condensation in the distribution network. Knockout drums, located immediately upstream of all consumers, disengage and collect any entrained liquid before gas enters the burners. Refer to GP 03–04–01 for design details. • ➧

Low Btu/Joule Gas Low Btu Gas (LBG)/Low Joule Gas (LJG) is produced via an air blown gasification process. This type of gas typically 3 has a heating value in the range of 100-150 Btu/SCF (3,700-5,600 J/Nm ). LBG/LJG from a FLEXICOKING Unit has a heating value of about 100-130 Btu/SCF (3,700-4,800 kJ/Nm3) and is available at low pressures in very large quantities resulting in large diameter piping in the distribution system. Normally, a limited number of the larger onsites furnaces and the offsites boilers are provided with the capability to combust the LBG/LJG. LBG/LJG is consumed in dedicated burners separate from those used for normal refinery fuel gas. Pressure controller(s) and valves are used to modulate LBG/LJG to consumers or the vent/flare system during periods of excessively high system pressure. Once the FLEXICOKING Unit is started up, the amount of LBG/LJG produced is primarily a function of the amount of coke gasified. Since LBG/LJG is a single source gas, reliability is dependent upon the operation of the FLEXICOKING Unit. Two major short term problems that will quickly affect the availability of LBG/LJG are the loss of the air blower or a problem with the desulfurization unit (if provided). Typically, offsites boilers and some process furnaces designed to fire LBG/LJG utilize auxiliary fuel to provide minimum firing requirements with the capability to meet full load upon total loss of LBG/LJG. The minimum rate for this auxiliary fuel will be a function of burner(s) turndown capability. For fuel gas, minimum firing could be as low as 10% whereas heavy fuel oil may require as much as 25%.

•

Intermediate Btu/Joule Gas Intermediate Btu Gas (IBG)/Intermediate Joule Gas (IJG) is produced via an oxygen blown gasification process. This 3 type of gas typically has a heating value in the range of 200-400 Btu/SCF (7,500-15,000 kJ/Nm ). The gasifier(s) work under high pressure, thus making the fuel suitable for gas turbines (i.e. no need for a fuel gas compressor). Cleanup facilities downstream of the gasifier(s) remove sulfur and other contaminants from the fuel prior to use in the gas turbine(s). Feed to the gasifier(s) can be coal, petroleum coke or so called petroleum bottoms. Industry interest in the implementation of Integrated Gasification Combined Cycle (IGCC) projects has been growing. This process gasifies low value fuels (such as coal or petroleum coke) for use in efficient power generation cycles. A simplified scheme showing the IGCC process is shown in Figure 3B. Refer to Table 2 for heating values and compositions of typical fuel gases.

DESCRIPTION OF A PILOT GAS SYSTEM Reliable pilot gas is normally supplied from a totally independent source that is separate from the refinery fuel gas system (i.e., from dedicated process units or from an outside source such as natural gas). If such a source is not available, pilot gas may be taken directly from the normal refinery fuel gas system if the instrumentation is as specified in GP 15–01–01 (for pilots with unreliable pilot gas). For a separate pilot gas system, control is similar to that of a low pressure fuel gas system. Pilot Gas Knockout drums are used to ensure that liquid does not enter the pilot burners. DESCRIPTION OF A GAS TURBINE FUEL SYSTEM Gas turbines are capable of firing a wide variety of fuels ranging from natural gas to crude oil. Experience has clearly shown that the cleaner the fuel, the better and more reliable the operation will be.

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Fuel Gas Systems ➧

The gas turbine package typically includes fuel shutoff valves and the fuel control and injection systems. The gas supply system has to be capable of providing clean fuel at constant pressure and with relatively constant heating value. •

High Btu/Joule Gas may be available at the desired pressure (e.g. Natural Gas or high pressure process gas) or some booster compression may be necessary. In any case, the reliability of the source supply and/or compression facilities will have a direct impact on gas turbine availability.

•

Fluctuations in the fuel gas Wobbe Index as an indicator of heating value should be kept at a minimum (typically ±5% is acceptable for streams supplying gas turbine fuel). Gas turbine fuel is controlled on a volumetric basis and performance problems can occur when the Wobbe Index fluctuates widely. The gas turbine manufacturer will provide specific guidelines on acceptable Wobbe Index fluctuations.

•

Wider Wobbe Index fluctuations may require fuel gas blending facilities or separate fuel gas manifolds and associated modification to the combustor nozzles. Use of special controls (such as fuel gas analyzers) need to be checked for time delay (response times) to be compatible with the precise speed control requirements for industrial gas turbines. Consult with the gas turbine manufacturer or EMRE machinery specialist to determine suitability of such instrumentation.

•

Low Btu/Joule Gas is typically available (from process) at low pressure and requires compression. Gas turbine application with such a fuel has been limited in the past but may find wider application in the future. The volumetric fuel flow for LBG/LJG is higher than for HBG/HJG and will affect the air / fuel ratio at the gas turbine. The system, therefore, also has to address the design of the air compression side of the gas turbine in order provide the proper air / fuel ratio. The optimum configuration will depend on specific plant requirements (e.g. possible utilization of bleed air) and the gas turbine manufacturer's capability. Expected compositions of the LBG/LJG should be provided to the gas turbine manufacturer early in the project.

•

Intermediate Btu/Joule gas produced by the oxygen blown process will have sufficient pressure for direct feed to the gas turbine. Volumetric flow of the gas may still exceed standard gas turbine limits thus requiring the manufacturer to modify the typical gas turbine design.

•

Fuel specification requirements may also dictate the use of fuel gas scrubbing facilities to limit metals, sulfur and particulates from entering the gas turbine combustor.

•

Hydrogen content in the fuel can also impact system design. Typically, if the hydrogen content is less than 5% by volume, no special precautions are necessary. For higher values, the manufacturer may require an alternate starting fuel as well as design modifications and additional safety devices specific to hydrogen use. Potential swings in hydrogen content in the fuel gas can also impact the design of the combustion controls.

•

Fuel gas streams containing olefins should be avoided if possible, especially when specifying gas turbines with Dry Low NOx combustors. Olefins may polymerize and form deposits in small diameter orifices. If fuel gas with olefins must be used, generally the manufacturer can modify the design to accommodate the olefins provided the concentration is stable. EMRE's machinery specialists and gas turbine manufacturers should be consulted when considering olefinic fuels. Olefinic fuels can also be problematical when used as a supplementary fuel in a Heat Recovery Steam Generator (HRSG) duct burner. This type of fuel has been known to cause coking/polymerization in the runners of the duct burner.

•

Liquid and solids carry over in gaseous fuel systems should be avoided to prevent flashback in the combustion zone. This has been a problem in designs that use dry low NOx combustors. To combat this problem, recent designs have taken the following steps: −

Use clean high pressure FG for the gas turbines.

−

Have NG supplier install KO drum(s) to avoid slugs of liquids from contacting downstream facilities.

−

Install coalescer/filter elements downstream of KO drums to eliminate liquid/solids carry-over. These units can be designed to remove 100% of all liquid particles above 3 microns and 99.98% of all particles less than 3 microns.

−

Install NG superheater to assure that the gas entering the gas turbine contains at least 50°F (28 C) superheat.

−

Provide low point drains in all FG piping to avoid accumulation of liquids.

−

Heat trace piping as appropriate to prevent FG condensation.

−

Install SS piping and valving downstream of the filters/separators to prevent solids (rust) carry-over into the combustor system.

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Liquid Fuel Systems Liquid fuels ranging from distillates to crude oils have been used successfully. High gas turbine service factor can only be maintained if special attention has been paid to all parts of the liquid supply system. The fuel must meet the manufacturer's specification (e.g. water, metals and solids contents) and be delivered to the gas turbine fuel skid at the proper pressure and viscosity. •

Dual fuel storage tanks are recommended to allow filling and settling of one tank while the other is in service. Tank bottom design should be compatible with effective water draw-off.

•

Floating suction or high suction nozzles should be used to assure water and solid free fuel.

•

Lighter fuels may only require filtration whereas heavier fuels (crude oils and resid fuels) are likely to require other treatment to meet fuel specifications and emissions standards.

•

Lighter fuels such as kerosene, naphtha, and NG liquids are directionally better fuels than normal distillate fuel. However, these lighter fuels exhibit low lubricity and low flash points. Both of these characteristics are likely to require special design features and/or special additives to assure fuel supply reliability and safety.

•

Soluble salts can be removed from heavily contaminated fuels by water washing. The wash water is then separated from the fuel by centrifuges or electrostatic means.

•

Inhibitor systems can be used to inject chemicals into the liquid fuel to avoid high temperature corrosion due to the presence of sodium, vanadium and lead in conjunction with sulfur in the fuel.

•

Requires a source of atomizing air (or steam) unless the gas turbine manufacturer fuel skid provides sufficient pressure for mechanical atomization.

•

Ash-bearing fuels have not proven to be economically or technically feasible in advanced gas turbines because of firing temperature limitations (resulting in poor fuel economy) and ash deposition on critical film cooling systems in the gas turbine. Refer to EMRE's machinery engineering specialists before considering these applications.

Dual Fuel Systems •

The typical dual fuel system includes NG and distillate fuel with automatic transfer.

•

The liquid fuel system has to be in ready mode for automatic switchover during loss of gaseous fuel supply. Ready mode may include running of liquid fuel pump(s) and recirculation of the liquid fuel.

•

Automatic switchover to liquid fuel is not always successful. Designer should ensure that the gas turbine and associated equipment will safely shut down on the failure of the auto-transfer. SYSTEM DESIGN CONSIDERATIONS

RELIABILITY/FLEXIBILITY ➧

The fuel system is an important utility and its reliability and flexibility is essential to successful plant operation. The typical system normally must be able to run continuously, so that it can always provide fuel to critical consumers. The fuel system must be designed to meet the constraints set by the site overall Utility Reliability Philosophy. See Appendix A for a check list of items to review to achieve a reliable system. The fuel system must include sufficient flexibility to cover present and likely near–term future operating requirements. The type of flexibility features provided in a system may include the following: •

Valves and blind flanges to permit future fuel sources or consumers to be tied into the system without a system shutdown, or to permit adding additional system components.

•

Integrating the new system with existing fuel systems.

•

Sizing the system for the viscosity and temperature requirements of the future fuel.

•

A 10% Reserve Capacity Factor (RCF) on total grassroots fuel gas system capacity for future expansion and sudden load swings if Owner approves.

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ENVIRONMENTAL REQUIREMENTS ➧

The fuel system designer should be aware of air pollution criteria, since these may impose limitations on firing certain fuels. The principal criterion is normally the allowable total release of sulfur, expressed as SO2, per unit of time. The various plant operating conditions should be evaluated to determine the amount of SO2 released to the atmosphere. This information forms the basis for furnace stack design as it relates to ground level pollution. Results of this study may indicate that special features, as discussed below, should be included in the fuel system to limit the amount of sulfur released during certain operating conditions. In process plants that have fuel gas sweetening units, the major source of sulfur is in the liquid fuels. These fuels are normally atmospheric pipestill bottoms, vacuum pipestill bottoms, or heavy fuel oil blends. Therefore, during maximum liquid fuel firing, it may be necessary to reduce the sulfur content of the liquid fuel by blending the normal fuel oil with a low–sulfur stock. Alternatively, naphtha or low–sulfur gas oil could be burned in certain furnaces to meet SO2 release limitations. Also, it may be necessary to limit the sulfur content in the liquid fuel when process units release large quantities of sulfur to the atmosphere. This could occur when a sulfur plant is out of service and sour gas from the desulfurization units is disposed of in a flare or furnace, or, in the case of LBG/LJG, in a vent stack. Limitations on NOx emissions have also become more stringent especially with the increased employment of gas turbines/waste heat boilers. Designers should consider (and based on local regulations may be required to use) low NOx technologies for gas turbines, boiler, and process furnaces. If the required NOx reduction cannot be met with modifications to the combustion equipment, additional measures can be used to lower the NOx levels in the exhaust including selective catalytic reduction (SCR) and other methods. See DP XI-N "Reciprocating Engines and Gas Turbines," DP VIII-F "Burners," and DP XVIII "Air Polution Control, Industrial Hygiene, and Noise Control" for more guidance on choosing low NOx technologies. To implement these low NOx technologies additional fuel conditioning equipment may be required. Fuel composition is critical to the design of these low NOx systems due to the potential of fouling the small orifices used in many of the designs. Olefinic fuel gas streams in particular may require strainers and/or coalescers upstream of low NOx burners as well as special designs for the burners. The strainer mesh size should be designed such that it will plug prior to the orifices in the downstream equipment (normally 25% or less of the size of the orifice to be protected). Stainless steel piping should also be considered between the strainer and the equipment to be protected due to the potential for pipe scale to plug the orifices. The EMRE fired heater specialists and equipment manufacturers should be consulted for further assistance in fuel system design issues related to low NOx technologies. Excess LBG/LJG is flared for pressure control under conditions of excessively high system pressure. However, in certain locations, venting through a stack may be permissible. In these cases, the vent stack must be sized to assure acceptable ground level concentrations. In locations with stringent air pollution abatement requirements and where there is insufficient sweet gas to blend off with sour fuel gas, it may be necessary to burn sour fuel gas only in those furnaces that have stacks tall enough to assure acceptable ground level concentrations. Depending on local regulations, SOx removal technologies may also be required. Continuous flaring should generally be avoided. However, it may be considered if process fuel gas production exceeds plant fuel gas demand and if flaring is environmentally acceptable. Fluctuations in fuel gas availability are typically handled by the combustion control system(s) of boilers (or large furnaces). Fuel gas rates are automatically increased or decreased with a corresponding change in fuel oil rates to maintain steam production or furnace duties. FUEL SELECTION The selection of gas and/or liquid hydrocarbons to be used for plant fuel is usually made during the planning stage of a project. Some factors that influence fuel selection are: •

Gas Containment

•

Economics

•

Marketing constraints (e.g. inability to sell high sulfur pitch) ExxonMobil Research and Engineering Company – Fairfax, VA

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•

Air pollution criteria

•

Compatibility with existing plant fuel systems

•

Process unit requirements (e.g. H2 plant reformer furnace must burn gas)

•

Equipment limitations (e.g. gas turbines, typically require high pressure gas or clean distillate fuel)

FUEL REQUIREMENTS Design fuel requirements are usually obtained directly from the appropriate process and utility design specifications, as qualified below: •

Boilers - Use installed capacity plus over-firing requirements.

•

Heat Recovery Steam Generator (HRSG) - Use maximum supplementary fuel rate to produce design steam output with minimum waste heat input. (Use cold air operation if HRSG needs to remain on–line when associated gas turbine trips.)

•

Process Fired Heaters - Use the heat fired; check with the designers for special operating conditions affecting fuel requirements.

The above requirements are usually expressed in Btu/h (kJ/h). They are later translated to fuel requirements on the basis of lower heating values (LHV) for the fuels involved. FUEL BALANCES ➧

Fuel balances similar to those shown in Table 1 are prepared after the overall fuel production and requirements are defined. The purpose of these balances is to insure that some type of fuel is available under all operating conditions. If fuel oil and fuel gas are used in the same system, they should be expressed on an energy-equivalent basis such as fuel oil equivalent barrels or other consistent units. In developing the balances, the designer must make sure that the cases selected are the limiting ones that will control system sizing. The cases to be investigated may include, but not be limited to, the following: •

Normal plant operation

•

Minimum and maximum plant operation

•

Minimum and maximum LPG operation (production and/or sales)

•

Emergency operations (loss of major producers or consumers - especially FLEXICOKING Unit, Utility failures, etc.), with each emergency operation analyzed separately, as required.

•

Seasonality which is especially important for identifying potential gas containment problems.

•

Turnaround operation.

•

Process variables such as catalyst regeneration, and start and end of run operations on powerformers or hydrofiners.

•

Startup

In addition to these cases, the fuel balance must consider the fuel requirements for process use (e.g. Hydrogen Plant feed). FUEL PROPERTIES Liquid Fuels - The physical properties of liquid fuels are shown in the GII and heat and material balances for the process units. This information is used for designing the distribution network and sizing equipment. In the listing of composite liquid fuel characteristics, the metals content (i.e., vanadium, nickel, iron and sodium) must be shown, since these metals have an important bearing on radiant section furnace design. Cracked stocks should be avoided, as they have been particularly troublesome in causing coking in hot environments and plugging of the fuel nozzles. Fuel Gas - The heat and material balances for various process units show the composition of gas entering the fuel system from each source. The composition and properties of the mixed fuel gas must be calculated for the various operating cases used in the fuel balance. These data are used for equipment sizing and for determining the extent of the variations in gas composition and thermal content under different operating conditions.

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The hydrocarbon and water dew points of the fuel gas must also be determined. These should be calculated for each individual stream, as well as for the composite stream. This information is used to determine the possible need for superheating and steam tracing of all or part of the fuel gas distribution system, to prevent condensation in the fuel gas lines. Where specific dew point requirements are not specified by fired equipment and gas turbine manufacturers, the dew point should be such that no condensation occurs at the lowest temperature of the distribution system. Fuel gas systems with high C4+ content may require superheating, since the hydrocarbon dew point usually falls within the normal operating ranges of low–pressure gas systems. C4+ rich sections of the distribution system may require heat tracing and insulation. Low Btu/Low Joule Gas - The properties of the LBG/LJG are shown in the GII and in heat and material balances for the FLEXICOKING Unit. Unless superheating is provided, the LBG/LJG will be water saturated at temperatures in the 95 to 135°F (35 to 57°C) range. Pilot Gas - The information discussed above is also applicable to pilot gas systems. FUEL SYSTEM OPERATING CONDITIONS AND CONTROLS The recommended operating conditions and controls for fuel systems are based on the requirements of typical consumers. Exact consumer requirements should be determined for each system and the operating conditions should be adjusted as required. Operating conditions in existing fuel systems will normally prevail when those systems are expanded. System control principles are described below. Instrumentation details for individual system components are discussed under “Component Design Considerations". Fuel Oil

➧

Fuel Oil Systems - The system should deliver fuel oil to the burners at a pressure of 120 to 130 psig (830 to 900 kPa). To ensure good control, an allowance of 50 to 70 psi (345 to 480 kPa) should be provided for the burner control system. Because of turndown requirements and the occasional use of mechanical atomization, burners for boilers may require higher fuel supply pressure than other consumers in the fuel oil system. The designer can satisfy this requirement by providing booster pumps for the boiler fuel, an independent system to service the boilers, or by raising the operating pressure of the entire system. The method selected should be based on considerations of economics, system control, safety and operating requirements. 2

Fuel oil viscosity should be a maximum of 25 cSt (25 mm /s) at the burners. However, in some cases, especially when burning resid–type fuels, the ideal burning viscosities may be lower in which case the system should be designed to supply fuel oil at the lower viscosity. Residual and tar type fuel oils (such as vacuum pitch or fuel oils with high ash and metals content) should have a minimum temperature of 350°F (177°C) regardless of the temperature required to meet viscosity requirements. This minimum temperature increases the life of refractory linings and reduces burner maintenance. Proper temperature/viscosity is required to prevent maintenance problems with oil drip-back and to achieve acceptable particulate emissions/opacity. Heavy fuel oil distribution systems consists of main supply and return headers, plus supply and return laterals to each consumer (see Figure 1). Recirculation from each consumer is necessary to maintain the minimum temperature and viscosity conditions at the burner under all system flow rates. Fuel oil pumps should have sufficient capacity to recirculate oil at a rate equal to 150% of normal or 125% of maximum requirements (whichever is greater) to each consumer. The fuel oil system is maintained under pressure control by a PIC located downstream of the last consumer takeoff on the supply header. The controller is set to maintain pressure to the last consumer on the loop under all flow conditions. Recirculated fuel oil should always flow through the pressure control valve to maintain proper system control. The flow of hot oil through this valve at the end of the loop also ensures that there will be no dead legs in the system. For extremely heavy fuels such as vacuum tower resid, temperatures of the fuel may be controlled back at the unit, and only a surge drum of nominal 30 to 120 minute holdup capacity needs to be provided. Longer storage periods for extremely high temperature fuels >450°F (232°C) may result in cracking of the fuel. A fired or electric heater would be required to maintain the supply temperature of such fuels. A backup liquid fuel to such a system must be selected considering the pressure/temperature of the main fuel, the vaporization tendencies of the cold backup liquid fuel and the possibility of solidification of the fuel mix.

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If a fuel oil system has multiple loops, a detailed analysis of the system must be made to locate the proper sensing point for the controllers. This is to insure that there are no system operating conditions that could cause interaction between the controllers and produce instability in the system. Radial systems (non–circulating) are normally provided with a flow controlled recycle line at the pump discharge to protect the pumps from low–flow operation. Figure 1 shows the instrumentation that should be provided at the end of the fuel oil loop. Typical alarm settings are as follows: PLA – Set at 10 to 15 psi (69 to 103kPa) below the normal system operating pressure. FLA – Set at 5% of the recirculated fuel oil flow rate. TLA – Set 20 to 30°F (11 to 17°C) below the normal system operating temperature. The flow instrumentation shown in Figure 1 represents the minimum that should be provided. Operating procedures and accounting methods may dictate the need for additional flow instrumentation. Refinery Fuel Gas (High Btu/Joule Gas) ➧

High–Pressure Fuel Gas Systems - High–pressure fuel gas is required as the fuel supply to gas turbines. Pressure must be sufficient to overcome the pressure drop of the control skids (control valves, filters, etc.) and to ensure proper fuel distribution in the combustion unit. Initial fuel supply pressure requirements can be estimated from the gas turbine pressure ratio (varies widely depending on gas turbine type; e.g. ranges from 8 to 30) and adding an allowance of 50 to 100 psig (345 to 690 kPa) for controls. Exact pressure requirements can be obtained from the gas turbine manufacturer or from the machinery specialists. The gas source(s) selected must be capable of delivering a gas of fairly uniform composition under all operating conditions. Consult with the gas turbine manufacturer or refer to Section XI–N “Reciprocating Engines and Gas Turbines," for the required fuel gas properties. Process units are usually under pressure control, with excess gas being sent to the fuel gas system. The system pressure is controlled by letdown of the excess gas to a lower pressure fuel gas system upstream of the collection drum. Backup source(s) of gas must be provided to maintain system pressure during periods of reduced gas production from primary sources. Backup process sources must not be affected by the same conditions that would cause loss of the primary sources. Backup may be from other process units, outside gas sources (natural gas), or in rare cases an LPG vaporizer. It is important to minimize the response time for backup gas entry into the system. Therefore, gas from another process unit or outside source is preferred over the use of a vaporizer for primary backup. Pressure controllers on backup gas should be set 10 to 15 psi (69 to 104 kPa) below the normal system operating pressure, and should have a PLA. The pressure controller on the letdown to the low–pressure fuel gas system should have a PHA. A flow indicator should be provided to measure total gas consumption.

➧

Low–Pressure Fuel Gas Systems - The low–pressure system collects fuel gases from the process units and delivers them to plant consumers. This system also receives excess high pressure process gas under pressure control, and vaporizer gas. The system should deliver gas to the furnace or boiler burners at a minimum pressure of 30 psig (207 kPa) to avoid any limitations on burner turndown. The system should be designed for operation at 50 to 60 psig (345 to 414kPa). This allows for system friction losses and provides 15 to 20 psi (104 to 138 kPa) pressure drop across the burner control valve. This pressure level is normally low enough for all fuel sources to enter the system and high enough to accommodate the burner pressure requirements of the most remote consumer at maximum system demand. The operating temperature must be high enough to preclude the possibility of condensing in the fuel gas system. Superheating the fuel gas may be required to avoid this possibility. The composition of the fuel gas will normally vary according to the number of gas sources in the system. The central collection drum provides volume to minimize fluctuations in fuel gas composition and thermal content. The use of low NOx burners may also require particulate cleanup to avoid plugging of small clearances associated with these burners. Early consultation with EMRE's burner experts or the burner manufacturers is recommended to determine if a filtering system (scrubber, coalescer, centrifugal separators, fine mesh strainers, etc.) is required. Common centralized vs. multiple local cleanup systems should be evaluated based on economics (consider piping, process unit turnaround effects, etc.). In some cases the fuel gas system pressure is controlled by the boilers. In these installations the boilers are dual fuel fired, with the fuel control system preferentially set to fire gas to maintain the gas system pressure and to avoid flaring. If boiler controls do not have sufficient capacity to handle excess gas when production increases, then some gas must be flared. A reduction in fuel gas supply actuates boiler controls to increase fuel oil firing. ExxonMobil Research and Engineering Company – Fairfax, VA

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In addition to the above, backup fuel gas sources are introduced under the low–pressure gas system pressure control. If the boilers cannot be used as the normal control for the system, low–pressure fuel gas system backup may be provided by: •

Let down from HP gas system

•

Natural gas

•

LPG vaporizer

Excess gas is sent to the flare under pressure control to relieve excessively high system pressure. However, normal flaring for control purposes should be avoided and may not be permitted by local regulations. Set point for the excess gas controller to flare is typically 10 psi (69kPa) above normal operating pressure. Figure 2 shows the instrumentation that should be provided. Flow indicators should be included to measure total fuel gas consumption and gas flow to the flare. Low Btu/Joule Gas Systems The LBG/LJG system distributes FLEXICOKING Unit gas to plant consumers. ➧

The LBG/LJG is typically available at low pressure from the onsite source facilities (battery limit pressure of 10–12 psig (69 to 83kPa)). The pressures required by the consumers vary from a few inches of water (for open–port type burners used with tangentially–fired boilers) to about 3 psig (21kPa) (for process furnace burners). Distribution piping is usually sized to deliver the LBG/LJG to the user's battery limit at 6 to 8 psig (41 to 55kPa) minimum. Normally a large percentage of the available LBG/LJG pressure drop is taken across the user's control valves. Pressure control of the distribution system is maintained by having one or more consumers capable of adjusting LBG/LJG consumption dependent upon LBG/LJG availability with total fuel demand met by changing the proportion of auxiliary fuel fired. In addition, pressure control valves are used to relieve excess LBG/LJG to a flare or vent stack during periods of excessively high system pressure. Overpressure relief for safety reasons is also provided with set pressures at 20–22 psig (138 to 207kPa) and discharging to a flare or vent stack. Offsites boilers, if used to control system pressure, are typically designed for a minimum (10 to 25% depending on fuel type) auxiliary fuel firing with LBG/LJG gas making up the remainder. The auxiliary fuel system should be capable of firing the boilers at 110% MCR when LBG/LJG is lost. LBG/LJG is received from the FLEXICOKING Unit at 95 to 135°F (35 to 57°C) saturated with water. Due to corrosion considerations, carbon steel lines having a 1/4" (6mm) corrosion allowance are used for LJG distribution. In extreme cold climates, insulation and a gas superheater may be required to limit condensation within the distribution system. The distribution piping should be insulated and sloped to users and provided with condensate pots at the low points. Disposition of the condensate is normally to the oily water sewer system. Site specific requirements may call for an alternate (closed) disposal system for the hydrocarbon containing condensate. PILOT GAS SYSTEM The pilot gas system distributes fuel to pilots in the various process furnaces and boilers. The three types of pilots available are defined as continuous, intermittent and interrupted. Continuous pilots are normally used on process furnaces and interrupted pilots are used on boilers. The type of instrumentation used on a furnace pilot gas system depends on the source of pilot gas. GP 15–01–01 defines the instrumentation required and also provides the following definition of a reliable pilot gas source: •

It must be separate from the main source of fuel gas, such that both sources will not be simultaneously interrupted by a single contingency; e.g., power failure or instrument failure.

•

It must be available during startup.

Pilot gas should preferably be supplied from an independent and reliable source, if such a source is available. Uniform composition is desirable but this is not always possible if pilot gas must be supplied from the plant fuel gas system. During startup operations, bottled LPG is normally used for interrupted pilots. Continuous pilots can be supplied from a vaporizer or from an existing fuel gas system. An estimate of the pilot gas consumed in each furnace and boiler should be obtained from the appropriate design group. A value of 100,000 Btu/h (29 kW) per burner can be used for estimating pilot gas requirements.

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➧

If the pilot gas dew point at operating conditions can result in condensation, consideration should be given to providing a knockout drum and/or superheater. A knockout drum is also required if the piping configuration requires pilot gas to be taken from the plant fuel gas system upstream of a knockout drum. Pilot gas supplying the flare tip requires special considerations as defined in DP Section XV-E. The pilot gas system is usually designed on the following basis: •

A pressure of 2 to 15 psig (14 to 104 kPa) is maintained at the pilots.

•

A system pressure of 20 to 25 psig (138 to 173 kPa) is maintained upstream of the pilot gas control valve.

•

The overpressure release to the flare is set 5 psi (35 kPa) above the system design pressure.

•

Pressure–controlled backup gas enters the system when the operating pressure falls 3 psi (21 kPa) below normal. A PLA is also provided. SYSTEM DESIGN PROCEDURES

The following general procedures should be used for developing the basic fuel system design: •

Obtain information on existing fuel systems in the plant. This information should include operating conditions, rates and composition of fuel from each source, a list of consumers (including rates) served by the system and excess capacity available.

•

Seasonal variations of consumption and production rates should also be obtained.

•

Obtain fuel characteristics, rates and operating conditions for each new fuel source.

•

Obtain fuel requirements for each new consumer.

•

Determine which furnaces and/or boilers will be dual fuel fired, as well as the possible variations in firing rate of each fuel.

•

Consider any special features or operating procedures that have been included in the individual furnace or fuel system design.

•

Prepare a fuel balance and update the balance as the design progresses.

•

Select the controlling operating cases.

•

Prepare a heat and material balance for each controlling operating case.

•

Develop flow plans for each fuel system; i.e., fuel oil, fuel gas and pilot gas.

•

Size the equipment components using criteria given below. COMPONENT DESIGN CONSIDERATIONS

FUEL OIL SYSTEM COMPONENTS • ➧

Fuel Oil Pumps Capacity - The firm fuel oil pumping capacity is equal to the maximum fuel oil requirement, as determined from the operating cases in the fuel balance, plus the required system recirculation. Recirculation rate should be equal to the greater of 150% of normal load or 125% of maximum load for each user. The firm capacity for fuel oil pumps supplying a boiler plant should correspond to the fuel requirement associated with the maximum steam demand including fuel oil recirculation. The installed pumping capacity should also be sufficient to supply the fuel requirement for the total installed boiler capacity (including over-fire) plus recirculation. Number/Individual Pump Capacity - The most commonly used fuel oil pump arrangements are: − Two 100% capacity pumps − Three 50% capacity pumps In some cases, pump capacity may be selected to match existing pumps. Driver Type - Different driver types are normally used for fuel oil pumps to provide reliability during utility outages. The most common arrangement is electric motor(s) and steam turbine(s). Pump Head - The fuel oil pump DP is based on supplying the most distant consumer with its maximum fuel oil requirement at the process design pressure established for the fuel oil system. ExxonMobil Research and Engineering Company – Fairfax, VA

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NPSH - The procedures covered in DP Section X–D, “NPSH," should be used to determine the NPSH requirements. Automatic Starting Requirements - The capability for auto–start should be provided for each of the fuel oil pumps. A selector switch should be provided so that any of the pumps can be used as the spare. Low pump discharge pressure should be used to initiate the auto–start system. An accumulator may be required in order to assure an uninterrupted fuel supply during the changeover. Refer to DP Section X–H, “Installation Facilities," for the design considerations for automatic starting facilities. Low Flow Operation - Fuel oil pumps used in a non–recirculating system should be protected against less than minimum allowable flow conditions. This may be done by providing a flow controlled recycle line at the pump discharge. The recycle line should return to a tank or process vessel. If this is not possible, fuel oil may be returned to the pump suction. The designer should evaluate the potential for excessive suction temperature affecting proper pump operation. Pump Seals - Mechanical seals are normally used for fuel oil pumps. The pump requirements should be reviewed with the Machinery Specialist to determine if any special provisions for seal flushing are necessary. Fluid Properties - Fuel oil pumps are usually designed to handle more than one type of liquid fuel. Alternate fluid properties at operating temperatures must be specified to insure that the pump will be capable of meeting its design requirements under all fluid conditions. Consider the design impacts of handling heavier fuels in the future. Location - Fuel oil pumps are normally located close to the drum or tank from which they take suction. •

Fuel Oil Strainers Application - Strainers are used in the system to protect the burners from particulate matter such as pipe scale and coke. Strainer Type - The two principal types of strainers used in fuel oil systems are the removable basket and the “Auto Klean" or Cuno type. The “Auto Klean" type strainer has cleaning blades and filter elements that can be rotated by an electric motor drive. The strainer can be cleaned on–line by rotating the elements and back flushing. The “Auto Klean" type strainer should be used for high–viscosity fuel oils such as atmospheric or vacuum pipestill bottoms/tar–like fuels and for any fuels containing coke particles. Basket type strainers are adequate for the lighter fuel oils. Capacity - The firm strainer capacity must be equal to the firm pump capacity. Number/Individual Strainer Capacity - Two 100% units should normally be provided. Particle Removal - The strainers should be capable of removing all particles with diameters greater than 0.02 inch (0.5 mm). Insulation and Heat Tracing - The strainer may require insulation and tracing to maintain a minimum fluid temperature when there is no flow through the strainer. Flushing - The “Auto Klean" type strainers require permanent connections to the flushing system, and a connection to either the slop system or another suitable disposal system. Flushing is usually done with a hot gas oil stream that is then discharged to slop or another suitable disposal. Location - The strainers should be located as close as possible to the consumers to protect the burners from pipe scale and/or particulate matter that collects in the distribution system. This is especially important for high–sulfur content fuels that are distributed at high temperatures. Multiple strainer locations may be required.

•

Fuel Oil Heaters Application - Heaters are used when the fuel oil temperature must be increased to provide optimum combustion at the burners. Viscosity requirements for heavy fuel oil typically falls in the 15–30 cSt range (15 - 30 mm2/s). For additional information refer to DP Section VIII–F (Burners). Type - The most common type of fuel oil heater is a steam heat exchanger. Other types that may find application in special circumstances are: − Electric heaters − Tank or suction line heaters using steam, hot circulating oil, or direct firing The method of heating used depends on the required fuel oil temperature and on the available heating media. The choice of method should be based on investment, operating costs and system operating requirements. Duty - The heater duty is based on raising the fuel oil temperature from its normal minimum to the required operating temperature at the firm pumping capacity. Number/Individual Heater Capacity - Two 100% heaters are normally provided in the fuel oil circuit.

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•

Fuel Oil Accumulator (See Figure 4) Application - Critical consumers require an accumulator (pressurized drum) to assure an uninterrupted fuel supply during the interval between loss of a fuel pump and startup of the spare. Critical consumers are boilers or essential process furnaces that may fire only liquid fuel. Capacity - The volume between LLL and LL(CO) should be sufficient to meet maximum fuel requirements for 10 seconds. For boilers, this is based on installed capacity plus over-fire. The space above the NLL should have sufficient gas inventory to maintain the minimum fuel system pressure without inert gas makeup when the liquid is displaced to the LL(CO) point. Instrumentation - Remote level alarms at the HLL, LLL and a LL(CO) are provided. The distance from the drum bottom tangent line to the LL(CO) should be the minimum distance required to insure that the cutout valve will close before nitrogen enters the fuel system. Operating Pressure - The drum pressure is equal to the normal fuel oil system operating pressure. The self–actuating regulator on a nitrogen cylinder is set to maintain a pressure in the drum equal to the fuel oil system pressure at which the spare pump is started. Restriction Orifice - A restriction orifice is provided to limit the nitrogen flow to the accumulator if the nitrogen pressure controller fails. The orifice should be sized so that the safety valve(s) provided for overfill, fire, etc. will be adequate to handle the maximum nitrogen rate as well. Insulation and Steam Tracing - If fuel oil properties so dictate, the entire drum should be steam traced and insulated to maintain fuel oil at the required temperature. Safety Valves - Safety valve(s) should be provided on the accumulator to protect the vessel from overfill, fire, and/or operational failure of the nitrogen pressurization system. Location - The accumulator should be located as close as practical to the consumers it is protecting, consistent with safety spacing and area classification requirements.

•

Fuel Oil Tankage (See Figure 5) Application - A tank is used to provide holdup capacity in the fuel oil system. The use of a tank rather than an onsite surge drum is a function of the holdup capacity required for system reliability and storage conditions of the liquid fuel. Onsite surge drums with minimum holdup have most often been provided for heavy fuels (pitch, tar) and in situations where there are several fuel sources available. The following factors should be evaluated to determine if tankage is required for overall fuel system reliability: 1. Method of supplying fuel oil to the system. 2. Reliability of the primary liquid or gas fuel(s); i.e., under what conditions are the primary fuels available and not available. 3. Operating procedures required to introduce backup liquid or gas fuels into the system. 4. Time required to initiate these operating procedures. 5. Interaction of the fuel gas with the liquid fuel system. 6. Security required for each consumer. This is especially important for boilers which must be capable of operating during utility failures, process plant upsets, etc. A fuel oil tank is normally operated in one of the following ways: 1. Dedicated Tankage a. The tank is maintained at a constant level by a continuous supply under level control to the tank. The supply may be from one or more process or rundown streams. b. The tank is periodically filled, either directly from process rundown streams or by transferring fuel from product tanks. The transfer may be accomplished by product loading pumps. The first method is preferred, because it requires less operator attention and normally results in a smaller tank. 2. Product Tankage - Product tankage may be used as the fuel system supply; however, this is recommended only when liquid fuel is not the primary fuel and is used primarily during startup and turnaround operations. If product tankage is used, a separate tank nozzle is provided for the fuel suction line. The product suction nozzle is located above this nozzle, to insure a reserve of fuel in the tank at all times. Capacity - The capacity of a fuel tank must provide the holdup volume for system security plus the volume required for tank operation. The volumes are based on maximum fuel oil requirements, as determined from operating cases in the fuel balance. The tank capacity for various methods of operation is as follows: ExxonMobil Research and Engineering Company – Fairfax, VA

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1. Tank Under Level Control a. Below LLL - Holdup volume (above tank innage) for system security. The volume is determined by evaluating the six factors listed under “Application" above. This is normally equivalent to 12 to 24 hours of operation. A remote LLA, independent of the LIC, is provided at the LLL point. Innage is the inventory remaining in the tank after the tank contents have been pumped to their lowest level as permitted by the permanent pump/suction system. b. Between LLL and HLL - Working or surge volume required for level control. This is a function of maximum filling rate, tank diameter and level controller characteristics (See DP Section XII–C, “Level Measurement and Control"); normally 1.5 to 3.0 ft. (460 to 915 mm). A remote LHA, independent of the LIC, is provided at the HLL point. c. Above HLL - This is the outage allowance, normally 1.0 to 1.5 feet (305 to 460 mm). Outage is the space left in the top of a storage container to allow for expansion of the contents during temperature changes and to provide a safety margin to prevent spill–over during filling. 2. Tank Filled Periodically a. Below LLL - Holdup volume for system security. The same volume criteria apply as for a level–controlled tank. A remote LLA is provided at the LLL point. b. Between LLL and HLL - Working or surge volume required for tank filling, normally equivalent to 24 to 72 hours of operation. A remote LHA is provided at the HLL point. c. Above HLL - Outage allowance. The same criteria apply as for a level–controlled tank. 3. Product Tank Used as Fuel Oil Tank a. Below LLL - Holdup volume for system security. The same volume criteria apply as for a level–controlled tank. The LLL is located at the bottom of the product suction nozzle. A remote LLA is provided at the LLL point. b. Above LLL - Product volume and outage are based on product storage requirements. Location - The tankage should be located as close as practical to fuel consumers. Safety spacing requirements for tankage are defined in GP 09–01–01 and DP Section XV–G, “Equipment Spacing." Other Design Considerations - Other considerations regarding gross volume, physical dimensions, tank type, tank accessories, etc., are defined in Section XXII, “Storage Facilities / Systems." • ➧

Fuel Oil Surge Drum Application - A surge drum (see Figure 6) is normally used when the primary fuel, typically atmospheric or vacuum pipestill bottoms, comes directly from process units at a high temperature and holdup volume requirements are low. (Refer to the previous fuel tankage section for factors influencing holdup volume.) The surge drum is normally provided with fuel gas blanketing. The design should include sufficient safeguards to prevent accidental overfill of the drum especially in heavy fuel oil applications. Overfill could result in plugging of lines and valves due to solidification of heavy liquids. Design Capacity - The design capacity of the drum (see Figure 7) provides holdup volume, working or surge volume, allowance for overfilling, and the minimum required vapor space. The design capacity is based on maximum fuel oil requirements, as determined from operating cases in the fuel balance. The drum capacity is allocated as follows: 1. Below LLL - Holdup volume for system security. This is normally equivalent to 30 to 120 minutes of operation. 2. Between LLL and HLL - Working or surge volume required for level control or spacing for standard level controller connections, normally a minimum of 14 in. (355 mm). (See DP Section XII–C, “Level Measurement and Control.") 3. Between HLL and ELL - Overfilling allowance, equal to 15 minutes at the maximum filling rate. 4. Above ELL - Minimum vapor space (See DP Section V, “Drums.") Alarms are provided at the appropriate level locations. Insulation and Steam Tracing - The drum is normally insulated to minimize heat loss. For high–viscosity fuel oils, the drum should be steam traced to maintain the fuel oil at a pumpable temperature. Safety Valves - Safety valve(s) should be provided on the surge drum to protect the vessel from fire and/or operational failure. Location - The surge drum is normally in or immediately adjacent to the areas supplying fuel. This is done to minimize collection and distribution piping, and to permit operation when adjacent process equipment is down.

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Fuel Oil Collection/Distribution Network Configuration - The fuel oil network is usually a looped system with a return line from each loop to a tank, surge drum, or pump suction. Fuel oil that has been heated above the operating temperature limits of a tank should not be returned to the tank. (See DP Section XV–B, “Minimizing the Risks of Fire, Explosion or Accident.") Each consumer has a separate return line back to the return header. The purpose of a looped system is to provide sufficient continuous flow under all operating conditions, to insure that the fuel oil temperature and viscosity are maintained at proper levels. Piping configuration should be evaluated in detail to insure that no dead legs (no flow sections) exist. A looped network is required for most heavy fuel oils. In addition, a separate loop may be required to permit independent operation of the boiler plant. If middle distillate or naphtha fuels are used, a looped system is not required. These systems are operated at temperature levels where temperature loss and viscosity are not critical. Layout - The routing of the network piping should connect all fuel sources and consumers in the most direct manner permitted by the plant layout. Careful consideration should be given to the turnaround areas in the plant. The network layout should preclude the necessity of having fuel oil lines that are in service running through an area that is being turned around. One or more loops may be required to accomplish this objective. Valves and Blinds - Valves with “spectacle" or “figure 8" blinds should be provided in the network, to isolate individual consumers and fuel sources from the system. Valves with such blinds should also be provided to isolate individual loops supplying turnaround and utility areas. Valves should be provided to permit onstream removal and maintenance of spared equipment. Blocks and bypasses are required on pressure control valves and surge drum level control valves.

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Distribution System Design Basis - The network is sized so that fuel oil is delivered to the most distant consumer at a pressure equal to the required process design pressure. Flow Rate - Each segment of the distribution network is sized for the maximum simultaneous flow that occurs in the segment under any operating condition. The maximum flow in the supply portion of the network consists of the fuel oil demands plus the allowance for recirculation. The return lines from individual consumers are sized for the recirculation allowance of 20% of normal flow. At startup, fuel is recirculated to establish the required temperature in all parts of the distribution network before sending fuel to the consumers. The return header portion of the looped network should be sized to allow a minimum of 50% of normal fuel oil requirement or 25% of maximum fuel oil to be recirculated. These recirculation rates reduce heat-up time and minimize temperature gradients in the network during initial startup. Line Sizing Basis. The distribution system should be sized with the guidelines established in DP Section XIV, "Fluid Flow". Equivalent Length Factors. Equivalent length factors are used in pressure drop calculations for sizing the distribution system. The piping length scaled from the plot plan is multiplied by an equivalent length factor to compensate for piping elbows, expansion loops, and other piping variations. The equivalent length factors are selected based on the expected variation from a straight piping run. Typical equivalent length factors suitable for planning purposes for different piping applications are as follows:

Equivalent Length Factors

Type of Piping

1.2 to 1.4

Long piping runs (> 1000 ft, (300m))

1.5 to 2.0

Onsite and boiler plant distribution piping

For design purposes, the actual piping layout should be evaluated to insure that the equivalent length factors are applicable to the specific situation. Particular attention is required for revamp work and projects involving changes to heavier fuels.

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Tracing and Insulation - The fuel oil distribution network normally requires heat tracing and insulation. Tracing and insulation are provided to prevent or minimize heat loss during operation and to maintain the fuel oil at pumpable conditions. Steam is the preferred tracing medium. For very heavy fuels such as pitch, high pressure (600 psig) steam tracing is required. Electrical tracing may be used on systems requiring a tracing temperature higher than that available from condensing steam, but electrical tracing of fuel oil systems is not common. Flushing - A middle distillate flushing system is sometimes provided to flush individual fuel laterals when they are removed from service. Flushing is most often used in systems that handle vacuum pipestill bottoms or other heavy fuels. When flushing is used, the fuel oil network should have connections to the slop system. Piping Class. For heavy resid fuels, class 300 piping is typically required due to pressure and temperature considerations (see DP Section II, "Design Temperature, Design Pressure, and Flange Rating"). HIGH BTU/JOULE FUEL GAS SYSTEM COMPONENTS • ➧

LPG Vaporizer Sizing (See Figure 8) Application - A vaporizer may be included in the system to perform one or more of the following functions: 1. Provide backup to the fuel gas system to cover loss of one or more sources of fuel gas. 2. Provide a primary source of gas for the fuel gas system. 3. Provide total fuel gas and/or pilot gas requirements during startup and turnaround operations. 4. Dispose of off–specification or excess LPG. 5. In rare cases to control the heating value of the fuel mixture. Vaporizer Capacity - The vaporizer capacity is based on the maximum fuel balance requirements. Drum Size 1. Vapor Disengaging Space - The disengaging space is sized for the maximum vapor rate at 100% of critical velocity using DP Section V, “Drums." 2. Liquid Holdup - The amount of liquid holdup provided in the drum depends on the function that the vaporizer performs, as indicated in Figure 8. 3. Drain - The drain from the drum is normally connected to the closed drain header. 4. Feed - LPG feed from process units or tankage is introduced into the vaporizer at a minimum distance from the bottom tangent line of the drum. For fuel system reliability, LPG is usually supplied from tankage (pressure storage). Product loading or blending pumps can be used to transfer off–specification LPG to the vaporizer if the storage pressure is insufficient. Dedicated pumps should be provided if the LPG is needed to meet normal fuel system operating requirements. LPG may also be sent to the vaporizer directly from the process units, although this is generally considered a less reliable design than providing pressure storage. In this case, the vaporizer is connected into the appropriate rundown line(s) at unit battery limits.

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Instrumentation and Control - The instrumentation and control scheme used for a vaporizer depends on the vaporizer functions (see Figure 8). Most vaporizers perform multiple functions and the control system will vary accordingly, as described below: 1. Vaporizer Used as a Primary Source of Gas - The feed is introduced under level control. The vaporization rate is regulated by a pressure controller sensing the fuel system pressure at the central collection drum and varying the amount of steam to the heat exchanger. An LLA below the LLL point of the control range and an LHCO above the HLL of the control range are provided. When used as primary source of gas, special attention should be given to the reliability of the steam trap on the condensate outlet from the vaporizer exchanger. Failure of the trap can result in a shutdown of the vaporizer system. 2. Vaporizer Used as a Backup Source of Gas - The feed rate to the vaporizer is regulated by a pressure controller sensing the fuel gas system pressure. Steam is fed to the exchanger at all times. A LHA and LHCO are provided. 3. Vaporizer Used for Disposal of LPG - The feed is introduced under level control. The steam to the heat exchanger is introduced manually when the vaporizer is used. A LHCO is provided. Safety Valves - Safety valve(s) should be provided for the vaporizer to protect it from an operational failure and/or fire.

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Insulation - The designer should evaluate the need for vaporizer and fuel gas system insulation depending on local ambient conditions and LPG composition. ➧

Location - The vaporizer should normally be located near the central collection drum to minimize condensation upstream of the drum. Also consider a fuel gas superheater downstream of the vaporizer or central collection drum as described under "Fuel Gas Superheater." •

Fuel Gas Central Collection Drum (See Figure 9.) Application - The use of a central collection drum is recommended. A drum serves the following purposes: 1. It provides surge volume to reduce pressure fluctuations and improve pressure control. It serves as the control point for the pressure controller(s) on the fuel gas system. 2. It provides a central holdup volume to disengage and collect entrained liquid from all fuel gas producers. This reduces the liquid load on individual knockout drums at the furnaces and boilers and may eliminate the need for knockout drums on certain fuel gas consumers. 3. It assists in blending of fuel gas to obtain uniform composition. This is especially important when there are gas sources with substantially different properties. Fuel gas analysis (e.g. via heating value or Wobbe Index analyzer) should be considered to provide feed forward instrumentation for the combustion controls systems of boilers, process heaters and gas turbines. Consult with the manufacturer and equipment specialist regarding acceptable variations in heating value and/or Wobbe Index number. Drum Size 1. Vapor Disengaging Space - Design criteria for the vapor disengaging space are given in DP Section V, “Drums." 2. Liquid Holdup - Liquid holdup equivalent to 5 minutes at the maximum liquid rate from a fuel gas producer is required. This operating contingency should be reviewed with the onsite designer. The holdup is measured between the HLL and the ELL. Instrumentation - The central collection drum is provided with a remote LHA, located 12 in.(300 mm) above the bottom tangent line. A level–indicating controller may be provided for automatic release of liquid accumulations to the closed drain header of the flare system.

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Safety Valves - Safety valves are normally provided on a central collection drum. A drum connection to the safety valve release and blowdown header is provided. Insulation and Heating - To assure effective liquid disengaging the central collection drum is not normally insulated and no steam coil is provided. However, insulation should be considered depending on ambient conditions and gas composition. ➧

Location - The central collection drum should be located immediately adjacent to the units producing or consuming the largest flowrates of fuel. This will tend to minimize the runs of larger size piping, and locating the the drum outside process unit battery limits allows the drum operation to be unconstrained by process turnarounds or upsets. •

Fuel Gas Superheater Application - Superheaters are normally required in fuel gas systems containing sizable quantities of butane or heavier components that may condense under normal operating conditions. They may also find application immediately downstream of the LPG vaporizer. Exchanger Type - A shell and tube type exchanger is normally used for this application. Refer to DP Section IX, “Heat Exchange Equipment". Heat Duty - The heat duty is based on providing 100°F (55°C) of superheat to the gas; i.e., raising the fuel gas from its normal minimum temperature to a temperature 100°F (55°C) above the fuel gas dew point at operating conditions. A temperature controller located downstream of the superheater that regulates steam flow to the heater maintains the temperature.

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Number of Exchangers - Only one exchanger is usually required. Consider providing a bypass to allow taking the exchanger out of service for maintenance. Location - The superheater should be located downstream of, but as close to the central collection drum (or LPG vaporizer) as practical.

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Fuel Gas Knockout Drum Application - Knockout drums are required in the fuel gas system if the following conditions exist: 1. A fuel gas source could introduce liquid into the fuel gas system; e.g., liquid carryover from a process vessel due to a system upset and a central collection drum is not provided. Even with a central fuel gas collection drum, groups of adjacent consumers (furnaces or boilers) are typically provided with a common KO drum. 2. Any combination of fuel gas properties and/or operating conditions could result in condensation in the fuel gas system. The same criteria also apply to pilot gas systems. Drum Type - Knockout drums may disengage entrained liquid by gravitational separation alone, or with the assistance of a mechanical device. DP Section V–A provides additional information regarding options for drum internals. Drum Size 1. Vapor Disengaging Space - See DP Section V, “Drums." The disengaging space is normally sized for 100% of critical velocity at normal vapor rate. For calculation of critical velocity, use the density of butane for the liquid component in the absence of better information. Also a crinkle wire mesh screen (CWMS) is typically used when the drum is in a furnace/boiler service. For more critical application (e.g. gas turbines or fuel gas compressors) a second layer of CWMS is used. 2. Liquid Holdup - See DP Section V. If the fuel gas system has a central collection drum, only liquid holdup equivalent to a 20 ft (6 m) slug of liquid applies. The HLL point in the drum should be as close to the bottom tangent line as practical and an LHA should be specified. A level gage should be provided to cover the full operating range. The gage should allow adjusting the set point of the LHA as well as providing the operator with knowledge of the actual level while the drum is being blown down. Number of Drums - A knockout drum may serve several consumers. The piping run from the knockout drum to the most distant consumer should be minimized and meet the requirements of GP 03-04-01.

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Safety Valves - Unless required by local codes (or special fuel gas source overpressure situations), safety valves are not normally provided for knockout drums. A drain connection to the safety valve release and blowdown header is provided. ➧

Insulation and Heating - Knockout drums are not normally insulated and traced. A steam coil should not be provided to vaporize condensed liquid. However, for cold climates consider tracing and insulating the piping downstream of the knockout drum based on the ambient conditions and the gas composition. Location - The knockout drum should be located as close as practical to the consumer(s), subject to the minimum spacing requirements defined in DP Section XV–G, “Equipment Spacing." •

Fuel Gas Collection/Distribution Network Layout - Network piping should connect all fuel gas sources and consumers in the most direct manner permitted by the plant layout, while meeting the following criteria: 1. The network must be arranged so that all fuel gas sources enter the system upstream of the first takeoff to a consumer. This insures that variations in composition of the fuel gas will be minimized. In a system with a central collection drum, all fuel sources are sent to the drum before the gas is distributed to the consumers. If there is no central collection drum, the distance between the entrance of the last source and the takeoff to the first consumer should be a minimum of 50 pipe diameters. 2. The pipe routing must take into consideration the turnaround areas in the plant. The network layout should preclude the necessity of having in–service gas lines passing through an area that is being turned around. 3. Consumers such as hydrogen plant furnaces and gas turbines that are sensitive to changes in fuel gas composition should be so located on the network that variations will be minimized. This may require a modification of the criteria described in paragraph 1, above. The takeoff may be located so that critical consumers are preferentially supplied from sources that have minimum change in composition. Valves and Blinds - Valves with “spectacle" or “figure 8" blinds should be provided in the network to isolate individual consumers and fuel sources from the system. Valves with “figure 8" blinds should also be provided to isolate individual headers supplying separate turnaround areas.

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Line Sizing 1. Design Basis - The network is sized so that fuel gas is delivered to the most distant consumer at a pressure equal to the required process design pressure. 2. Flow Rate - Each segment of the network is sized for the maximum simultaneous flow that occurs in the segment under any operating condition. 3. Line Sizing Basis. The distribution system should be sized with the guidelines established in DP Section XIV, "Fluid Flow". 4. Equivalent Length Factors. Equivalent length factors are used in pressure drop calculations for sizing the distribution system. The piping length scaled from the plot plan is multiplied by an equivalent length factor to compensate for piping elbows, expansion loops, and other piping variations. The equivalent length factors are selected based on the expected variation from a straight piping run. Typical equivalent length factors suitable for planning purposes for different piping applications are as follows: Equivalent Length Factors

Type of Piping

1.2 to 1.4

Long piping runs (> 1000 ft, (300m))

1.5 to 2.0

Onsite and boiler plant distribution piping

For design purposes, the actual piping layout should be evaluated to insure that the equivalent length factors are applicable to the specific situation. Particular attention is required for revamp work. ➧

Tracing and Insulating - Any segment of the network must be heat traced and insulated if any combination of fuel gas properties and operating or ambient conditions could cause condensation. One ambient condition which is known to cause problems is heavy rain on the distribution piping. The resulting condensation can cause a severe pressure drop in the fuel gas system, causing users to trip on low supply pressure as well as potentially creating a liquid slug in the distribution piping. The impact can be minimized by routing the fuel gas piping at lower levels of the pipe rack so that it is shielded and by insulating exposed sections. Steam is the preferred tracing medium. For unsaturated hydrocarbons such as acetylene, the temperatures from steam tracers may cause polymerization resulting in potential system plugging problems. In such a case, it would be preferable to use electric tracing to obtain better temperature control. LOW BTU/JOULE FUEL GAS SYSTEM COMPONENTS •

Low Btu/Joule Gas System Superheater Application - In extreme cold climates, insulation and heating may be required to limit condensation within the distribution system. LBG condensate is not a pure CO2 - water system. LBG also contains ammonia that reduces the corrosivity of the condensate. To date, FLEXICOKING Unit locations have not required a gas heater. Carbon steel lines having a 1/4" (6 mm) corrosion allowance have proven to be adequate. Heat Duty - The heat duty is based on providing for the heat losses in the distribution system plus approximately 30°F (17°C) of superheat minimum to the furthest consumer under winter conditions. Because of thermal expansion considerations with large diameter piping, it is important to limit the design temperature of the system as much as possible while still meeting the winter design requirements. A temperature controller located downstream of the superheater regulates steam flow to the heater. Number of Exchangers - Provide one exchanger. Location The superheater should be located in the vicinity of the LBG/LJG source.

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Low Btu/Joule Gas Distribution Network Layout - Since the LBG/LJG piping is very large, both the placement of the producer with respect to the users and piperack routings are often major factors in the overall plant layout development. 1. The piping layout should be given top priority at an early stage to avoid impractical runs. The large diameter piping required, low pressures available, and sloping requirements are important factors in planning such a system. 2. The distribution piping should be sloped to the users and provided with condensate pots at the low points. 3. To date, condensate from the knockout pots has not required special handling and treatment and is therefore routed to sewer. 4. Knockout drums are not provided at the user furnaces and boilers. Line Sizing 1. Design Basis - The network is designed so that the LBG/LJG is delivered to the most distant consumer at a pressure equal to the required process design pressure. Typically, the piping is sized to deliver gas at the consumer's battery limit at 6 to 8 psig (41 to 55kPa) minimum. In developing the LBG/LJG production rate, establish the design volume both dry and wet since dry volumes are often quoted but wet volumes must be handled. 2. Flow Rates - Each segment must be examined for the maximum flows based on furnace and boiler design capacities (often using 100% LBG/LJG firing). 3. Pressure Drop - The basis for sizing the LBG network should generally be