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SECTION 1-INTRODUCTION 1.1 PURPOSE This recommended practice provides information on electrical installations in petroleum facilities. Petroleum processing requires specialized equipment that continually processes, often at high rates and elevated temperatures and pressures, liquids, and gases that...

SECTION 1-INTRODUCTION 1.1 PURPOSE This recommended practice provides information on electrical installations in petroleum facilities. Petroleum processing requires specialized equipment that continually processes, often at high rates and elevated temperatures and pressures, liquids, and gases that undergo both chemical and physical changes. Consequently, it is necessary that electri- cal installations and equipment in petroleum facilities be designed to prevent accidental ignition of flammable liquids and gases. To maintain safety and operating continuity, requirements for the electrical systems in petroleum facilities are more stringent than those for most other manufacturing facilities. This recommended practice addresses specific requirements fos those electrical systems. 1.2 SCOPE This recommended practice is limited to electrical installa- tions in petroleum facilities. It provides a basis for specifica- tions included in engineering and construction contracts. Electrical equipment test standards are excluded from the scope of this recommended practice. Operation and mainte- nance are addressed only insofar as they affect electrical sys- tem design and electrical equipment selection. The subject of energy conservation is reviewed. SECTION 2-CLASSIFIED LOCATIONS OR ELECTRICAL EQUIPMENT 2.1 PURPOSE This section briefly reviews the classification of flammable liquids and gases, the classification of locations where fire or explosion hazards may exist due to flammable gases or vapors, or flammable liquids, and the application of electrical equipment in classified locations. 2.2 SCOPE This section discusses only the general guidelines pertain- ing to the classification of locations. A more detailed discus- sion of the classification of locations can be found in API FP 500, Recommended Practice for Classijïcation of Loca- tions for Electrical Installations at Petroleum Facilities Clas- siJied as Class I, Division 1 and Division 2 and API RP 505, Recommended Practice for ClassiJication of Locations for Electrical Installations at Petroleum Facilities Classijïed as Class I, Zone O, Zone 1, and Zone 2. 2.3 CLASSIFICATION OF FLAMMABLE AND COMBUSTIBLE LIQUIDS AND GASES Note: Classifications used for defining liquids and gases should not be confused with the NFPA 70 classifications used for hazardous (classified) locations. 2.3.1 Definition of Flammable Liquids As defined by NFPA 30, flammable liquids are liquids that have a flash point below 373°C (100°F) and a vapor pressure not exceeding 276 kilopascals absolute (40 pounds per square inch absolute) at 373°C (100°F). These liquids are divided into the following general classes: a. Class IA includes the liquids that have flash points below 223°C (73°F) and boiling points below 373°C (100°F). b. Class IB includes the liquids that have flash points below 223°C (73°F) and boiling points at or above 373°C (100°F). c. Class IC includes the liquids that have flash points at or above 223°C (73°F) and boiling points below 373°C (100°F). 2.3.2 Definition of Combustible Liquids As defined by NFPA 30, combustible liquids are liquids that have flash points at or above 373°C (100°F). These liq- uids are also divided into general classes: a. Class II includes the liquids that have flash points at or above 37.8“C (100°F) and boiling points below 60°C (140°F). b. Class Ill includes the liquids that have flash points above 60°C ( 140”F), and Class III liquids are subdivided as follows: 1. Class IL4 includes the liquids that have flash points at or above 60°C (140°F) and boiling points below 93.3“C (200°F). 2. Class IIIB includes the liquids that have flash points at or above 93.3”C (200°F). 2.3.3 Flammable Gases-Lighter-than-Air Lighter-than-air gases that commonly are encountered include methane and a mixture of methane with small quan- tities of low-molecular-weight hydrocarbons, the mixtures generally being lighter-than-air. Hydrogen must be given a special mixture consideration because of its properties: a wide flammable (explosive)-mixture range, a high flame- propagation velocity, a low vapor density, a low rninimum- ignition-energy level, and a relatively high ignition tempera- ture [585“C (1085”F)I. 2.3.4 Flammable Gases-Heavier-than-Air Liquefied petroleum gases include propanes, butanes, and mixtures of the two having densities from 1.5 times to approximately 2.0 times that of air. Vapor pressures of these gases exceed 276 kilopascals absolute (40 pounds per square inch absolute) at 37.8"C (100°F). 2.4 CLASSIFICATION OF LOCATIONS The National Electrical Code, NFPA 70, has established criteria for classifying locations that do or may contain flammable gases or vapors, flammable liquids, combustible dust, or ignitable fibers or flyings. Once a location has been classified, NFPA 70 specifies equipment requirements for each particular classification. The major effort involved in classifying a location is determining whether flammable gases are likely to exist in the location to be classified and, if they may exist, under what conditions and for how much of the time. A Class I location is a location in which flammable gases or vapors are or may be present in the air in quantities suffi- cient tö produce explosive or ignitable mixtures. NFPA 70 recognizes two systems for the classification of Class I loca- tions, the Division system and the Zone system. In the Divi- sion system, Class I locations are subdivided into Division 1 and Division 2. Division 1 indicates that a flammable mix- ture may be present under normal operating conditions, and Division 2 indicates that a flammable mixture may be present only in the event of abnormal operating conditions or equipment malfunction. In the Zone system, Class I loca- tions are subdivided into Zone O, Zone l, and Zone 2. In a similar manner to the Division system, NFPA 70 contains criteria for defining Zones based on the possibility of releases. In both systems, locations that are not classified as Division 1, Division 2, Zone O, Zone 1, or Zone 2 are termed unclassified. Once the existence and degree of ignitable substances in an area has been determined, the physical boundaries of the classified location must be determined. The most important factor to consider is that flammable gas or vapor alone will not produce an ignitable atmosphere; flammable gas or vapor must mix with a sufficient amount of air to become ignitable. Other factors to consider are the quantity and physical characteristics of whatever substance might be lib- erated and the natural tendency of gases or vapors to dis- perse in the atmosphere. Once established, a location’s classification and boundaries can be drawn on a plot plan of the process equipment for a given area. Such a drawing is a convenient reference source when selecting electrical equipment for and locating it in the classified area. The classification is incomplete until the dimensions around a source of liquid or gas are defined and documented. Typical height, width, and length dimensions are available in API RP 500 and 505 as well as NFPA 497. API RP 500 and 505 are practical guides that specifically apply the NFPA 70 classification criteria to electrical installa- tions in petroleum facilities. The recommended practices cover the factors that must be considered in area classifica- tion; they provide a questionnaire-type procedure for deter- mining the proper classification of a location; and they illustrate methods for establishing the degree and extent of a location to be classified. Sound judgment must accompany the use of the recommen- dations in API RP 500 and RP 505. When, in the opinion of a qualified person, particular conditions are better or worse than average, the pertinent recommendations should be modified accordingly. 2.5 ELECTRICAL EQUIPMENT FOR CLASSIFIED LOCATIONS Each location in a petroleum facility that is classified must be carefully evaluated to ensure that proper electrical equip- ment is selected. Most classified atmospheres in petroleum facilities are Class I, Group D; however, certain areas may involve other classes and groups: in particular, Class I, Groups B and C and Class II, Group F. (See NFPA 70 and NFPA 499 for further discussion of Class II locations. See’ NFPA 70 and 497 for the correlation of material groupings for Division and Zones) To comply with NITA 70, electrical equipment suit- able for the specific area classification must be used. One indication that electrical equipment installed in clas- sified locations is suitable for the defined locations is that it is approved by a Nationally Recognized Testing Laboratory (NRTL). Certain electrical equipment, such as induction motors for installation in Division 2 and Zone 2 areas, are specifically permitted in NFPA 70 and do not require spe- cific markings or NRTL approvals for use in classified areas. 2.6 ALTERNATIVE DESIGN IN CLASSIFIED LOCATIONS For applications where it is necessary to install equipment that is not suitable or available for the classification, the fol- lowing alternative designs may be utilized. These applica- tions may be desirable because equipment is not suitably manufactured for a particular classification, it is more cost effective to secure the alternative equipment, or design prefer- ence prohibits such equipment. 2.6.1 Physical isolation Physical isolation is an effective, and perhaps the most commonly used, method for installing electrical equipment not otherwise suitable for classified locations. For example, where motors are located in a classified location, the motor starters and control equipment can be installed outside the classified location. This permits the use of less expensive equipment in locations that are more convenient for main- tenance. 2.6.2 Pressurized Rooms and Enclosures According to NFPA 70, classified locations may be reduced or eliminated by adequate positive-pressure ventila- tion. Authoritative information on design criteria is provided in NFPA 496. Positive-pressurization and purging are based on the principle that an enclosure or room located in a classi- fied location can be purged with clean air or inert gas at suffi- cient, continuous flow and positive pressure to reduce the original concentration of flammable gas or vapor to a safe level and to maintain this level. There are three types of purging, each having specific design requirements: a. Type X purging reduces the classification within an enclo- sure from Division 1 to unclassified. b. Type Y purging reduces the classification within an enclo- sure from Division 1 to Division 2. c. Type Z purging reduces the classification within an enclo- sure from Division 2 to unclassified. 2.6.3 Intrinsically Safe Installations One approach to the application of electrical equipment in classified locations is to use intrinsically safe devices and wir- ing methods: This method is used primarily for instrumenta- tion and process control. Intrinsically safe equipment and wiring are incapable of releasing the electrical or thermal energy necessary, under normal or abnormal conditions, to ignite a specific hazardous atmospheric mixture in its most ignitable concentration. Information ’on the design and evalu- ation of intrinsically safe equipment and wiring to be used in classified locations is provided in UL 913. Intrinsically safe installations should comply with NFPA 70 Article 504. 2.6.4 Other Alternatives 2.6.4.2 Adequate ventilation methods and the use of com- bustible gas detection, as defined in API RP 500 and RP 2’6’4’1 70 describes Other pro- 505, are techniques that may allow the reduction of the area tection techniques for electrical equipment and installations in classified areas. These include: oil immersion, nonincen- dive, and hermetically sealed. 3.1 PURPOSE This section reviews energy efficiency as it applies to the selection of electrical equipment for petroleum facilities and to the application of the equipment in those facilities. 3.2 SCOPE Electrical efficiency is discussed as a part of the broader concept of energy conservation. The definition of efficiency is given, and design considerations are reviewed for specific . types of equipment. Economic evaluation is addressed. Other efficiency related topics, such as power factor and demand control, are briefly discussed. Useful definitions and conver- sion factors are provided at the end of the section. 3.3 THE ROLE OF ELECTRICAL EFFICIENCY a. Electrical systems provide an important opportunity for energy conservation. The electrical losses in the distribution and utilization equipment of a refinery power system can range as high as 20%. For a 60 megawatt (MW) facility oper- ating 8,000 hours per year and paying $0.07 per kilowatt-hour (kWh), the cost of these losses would exceed $6.5 million per year. -A similar plant using an energy efficient electrical design could have 1.5% fewer losses and save $1 million per year compared to the less efficient design. In addition to the direct benefits of increased electrical effi- ciency, there are also some indirect benefits. Reduced losses in electrical equipment can result in lower operating tempera- tures and prolonged equipment life. For indoor applications, reduced losses also decrease the heat load on air conditioning equipment. When considering electrical efficiency, it is also useful to recall that, due to losses in the generation, transmission, and distribution of electricity, a 1 kWh reduction in electrical usage saves the equivalent of 4 to 5 kWh of raw fuel. 3.4 DEFINITION OF EFFICIENCY Efficiency is defined as the ratio of power output to power input or energy output to energy input: Efficiency = Power output Energy output Power input Energy input or (1) Power output can be related to power losses in equipment by the following: Power output = Power input - losses (2) Therefore, efficiency can also be defined in terms of losses and power input Efficiency = Power input - losses losses or=1- Power input Power input (3) or in terms of losses and power output: Efficiency = 1 - losses Power output + losses (4) All the above formulae can be applied to energy by substi- tuting kWh for power. In either case, higher efficiency is achieved by reducing operating losses. 3.5 SPECIFICATION CONSIDERATIONS The specification of electrical equipment should include consideration for energy efficiency. The operating points for which efficiency data are desired should be specified. Usually ‘h, 1/4, and full load data are requested. For large equipment, an efficiency curve should be requested. Guaranteed effi- ciency values, rather than nominal or average values, should be specified. An economic evaluation factor (in dollars per kwh) should be included in the specification. See 3.6. Any economic pen- alty clauses should be clearly stated, and the operating point at which efficiency will be evaluated should be specified. The testing method to be used for determining efficiency should be stated. Witnessed testing is recommended if eco- nomic penalty factors are involved. Payment terms that are to be contingent on receipt of the test results should be clearly stated. 3.6 ECONOMIC EVALUATION 3.6.1 Evaluation Factors Competitive pressures to reduce the cost of processing have provided an incentive for adding capital investment that can cut the energy cost per barrel processed. The cost of adding new equipment, or replacing inefficient equipment must be offset by future energy cost savings. An economic evaluation is necessary to determine if the equipment costs will be offset by the future energy savings. Energy efficient electrical equipment normally demands a premium price. It is useful to develop a dollar-per-kilowatt factor to determine the value of saved energy for projects at a specific site. Sev- eral different methods for developing a $/kW factor are cov- ered in the following sections. 3.6.2 Simple Payback h = hours of operation per year, The least complex dollar-per-kilowatt factor is based on N = number of years in evaluation period, simple payback, which does not account for the dèpreciated value of future savings: T = income tax rate paid by the user, i = effective interest rate $kW = ChN (1 -T) (5) - - 1=– . 1+R, 1 +R, 1 (81, where $1 kW = profit to the user for reducing power usage by R1 = anticipated annual escalation rate for cost of 1 kW, electricity, C = cost of electricity, in dollars per kwh, R2 = desired annual rate of return on investment.’ h = hours of operation per year, N = number of years in evaluation period, Using the example,of equation 5 along with a 15% rate of T = income tax rate paid by the user. return and an 8% power cost escalation rate, the dollar-per- kilowatt evaluation factor would be calculated as follows: The use of the factor is demonstrated in the following example. Assume a piece of electrical equipment operates 1 ’ =– 1 = 0.0648 continuouszy at a location where the cost of electricity is $O.OSkWh, and the desired payback period is 5 years. Income is taxed at a 40% rate. The factor would be calculated C 1 + 0.08 (9) as follows: $/kW = (I-0.40)~ 1 + O.064SJ - 1 0.0648 (1 + 0.0648) 5 (10) $/kW=- $005x8760hx5yrx(l-0.40) - = $1,314/kW (6) kWh yr = $1,093 I kW This factor is the expected cost for continuously operat- ing a load of one kW for 5 years. This cost factor is then This equation is a useful way to include the time value of compared to the ratio of the price premium for high effi- money, and is suitable for most economic evaluations of ciency equipment divided by the loss reduction. If the ratio energy efficiency improvements. For very large projects it may is less than $1,314, then it pays to spend the money for the be desirable to use an evaluation method which further refines high efficiency equipment. For example, if an energy effi- the preceding equations to allow for such factors as deprecia- cient transformer costs $4,000 more than a standard trans- tion, tax investment credits, and variable escalation rates. former, and it reduces the losses by 5 kW, the incremental cost is ($4,00015 kW) or $SOOkW. The energy efficient unit 3.7 COGENERATION AND ENERGY RECOVERY should, therefore, be selected. 3.6.3 Time Value of Money Power costs can be reduced by investing in-plant genera- tion. The generation normally is added in the form of cogen- eration. Cogeneration means using the waste heat from a Equation 5 does not take into account the time value of power generating cycle for process heating; or conversely, money. Future savings should be adjusted for increases in using waste heat from a plant process to generate power. power costs and the required cost of capital. The following The generation cycle thermal efficiency thus can be equation provides a dollar-per-kilowatt factor that allows for increased from about 25% (typical industrial generating power cost inflation and desired rate of return on investment. efficiency) to about 70% when waste heat is recovered. Power generated in the cogenerating mode is normally less expensive than purchased power and results in direct sav- (7) ings to the plant. Typical utility generating units operate at 35% efficiency, so the higher efficiency of cogenerating can make it an attractive option. where One of two power cycles are used for cogenerating, depending on the plant processes used to absorb the waste heat. The Brayton cycle includes a gas turbine to generate power, and a waste heat boiler to generate steam from the hot C = cost of electricity, in dollars per kwh, 500°C to 600°C (= 950°F to 1100°F) exhaust gases. In some $IkW=Ch(l-T) l+iN-1 i(1 +i>* $1 kW = profit to the user of reducing power usage by 1 kW, Three examples of direct heating with turbine exhaust are: reducing the viscosity of products in transport pipelines; heating process feeds to process units; and supplying thermal energy for absorption refrigeration cycles. Heating viscous products will lower viscosity and reduce the pumping energy required to transport the products through pipelines. Fired heaters are normally used for this. When gas turbines are sometimes used as generator drives to provide power for the transport pump motors, or are used to drive the pumps directly, the exhaust can be passed through an exchanger to heat the product, instead of using a fired heater. Using the waste heat from the gas turbine’s exhaust will save the cost of the fuel used for a fired heater. In process plants, gas turbine exhaust is used to heat feed stocks to processes, or to preheat combustion air for the pro- cess furnaces. This displaces much of the fuel that would oth- erwise be consumed. The absorption refrigeration cycle uses a heat source to change the state of a refrigerant. The hot exhaust from a gas- turbine generator can be used with an absorption cycle to pro- vide cooling. Absorption cycle equipment manufacturers can provide pre-engineered system elements to match the exhaust flow conditions of a number of gas turbines. Sometimes there are opportunities to recover energy from process or utility streams. One method of energy recovery is the power recovery turbine, which is often used on catalytic cracking units to recover energy from the regenerator flue gases. The flue gases are directed through an expander which drives the unit’s air blower, and an electric generator. The out- put of the generator is usually in the range of 5 megawatts to 10 megawatts {MW). Typically, an induction generator is used for this service. A high-pressure fuel gas feed to a petroleum facility can also be used as a source of electric power by dropping the line pressure to plant utility pressure through an expander instead of a let-down valve. The expander is used to drive an induc- tion generator adding power to the electric system. The majority of the gas flow goes through the expander, while a pressure control flow goes through a parallel control valve. 3.8 DESIGN CONSIDERATIONS 3.8.1 Transformers Transformer efficiencies vary, depending on transformer characteristics. High-efficiency units can be purchased that provide efficiencies in excess of 99%. The importance of transformer efficiencies is that all power received from utili- ties (and ’much, if not all, received from in-plant generation) is transformed one or more times to reach utilization voltage levels; thus, the 1 or 2% losses occurring in transformers are applied to large blocks of power. Transformer losses consist of no-load losses and load losses. No-load losses are losses resulting from energizing the primary winding at rated voltage with the secondary winding open-circuited. These losses include eddy current losses, hys- teresis losses, dielectric losses, and losses due to the resis- tance of the primary winding to excitation current. The eddy current and hysteresis losses are the most significant compo- nent of no-load losses. Because these losses occur in the core of the transformer, no-load l