Introduction to Energy-saving Technologies and Energy Consumption Evaluation Methods in Foreign Refineries

Thread Content

Introduction to Energy-Saving Technologies and Energy Consumption Evaluation Methods in Foreign Refineries. Energy consumption costs account for a large proportion of the cash operating costs in refineries; the effectiveness of controlling these costs directly influences the level of such costs, making them one of the key controllable expenses in refineries. At uniform price levels, energy consumption costs account for around 50% of the cash operating costs in domestic refineries, while this figure is about 40% in foreign refineries. Compared with their foreign counterparts, most domestic oil refining companies still have significant gaps in terms of energy consumption. At the same time. It can also be seen that oil refining companies are energy-intensive enterprises with significant potential for energy savings. To this end, gaining a thorough understanding of energy-saving technologies, principles, and foreign energy-saving evaluation methods holds great practical significance for further promoting energy-saving efforts in domestic oil refining enterprises. 1. Energy-saving technologies and advanced practices in foreign refineries: Energy consumption is the largest single operating cost for refineries. Based on Solomon’s Energy Intensity Index (EII) in the United States and KBC’s Best Technology Index (BTI), the overall energy efficiency of refineries is not high; the average energy consumption of refineries is roughly twice that of refineries operating using \"best technology\". Therefore, the energy consumption systems in refineries hold great potential for energy savings, even in those with high energy efficiency. The oil refining industry is characterized by low profits and fierce competition; companies use similar production technologies to manufacture similar products. Apart from differences in scale, management, and products, the main difference between them lies in energy utilization efficiency (abbreviated as energy efficiency). Therefore, one might assume that management’s attention and investment will primarily focus on energy efficiency projects. However, this is not the case; according to foreign sources, investment in energy efficiency projects across the entire oil refining industry accounts for only about 5% of total capital expenditure. Over the past 10 years, the energy efficiency of refineries with higher efficiency improved by about 6%, while that of refineries with lower efficiency increased by 12%. Given that the energy consumption of these less efficient refineries is 2.5 times that of the best available technologies, 12% is clearly not a very high figure. The contradiction between great energy-saving potential and relatively low actual investment has its historical reasons. The formation of the world’s major oil refining companies took place in the 1970s and 1980s, a period when these companies were highly profitable. After the two world energy crises, the oil refining industry gradually became a sector with slim profits, and efforts to improve efficiency focused on things such as economies of scale and larger-scale processing facilities. At that time, there was not much awareness of energy conservation; the development of energy-saving technologies and equipment progressed slowly, and the theories related to energy conservation were also not very well-developed. Therefore, since the main refineries in the world were established early on, those refineries were primarily organized around separate units, with large intermediate storage areas. The material flow generally went from low temperatures to high temperatures during processing, and then back to low temperatures before entering the storage areas, a process that repeated many times; as a result, the efficiency of utilizing exergy was very low, and there were numerous inefficiencies in energy use. Even the energy-saving measures and technologies adopted at that time were only partial in nature. Recently, there has been a growing realization that energy-saving efforts are highly beneficial for enhancing the competitiveness of oil refining, particularly as process energy savings within refineries, heat integration between units, and the use of heated feedstocks help to reduce significant heat exchange losses, thereby improving energy efficiency. Most oil refineries built in the 1990s saw significant improvements in their design approaches; they shifted from a design pattern that featured separate processing units as independent zones to one that involved constructing large integrated complexes. Energy-saving technologies and equipment were widely adopted, resulting in a substantial increase in energy utilization efficiency. Currently, the average energy consumption of refineries around the world is roughly twice that of refineries using \"best available technology.\" This clearly shows that it is crucial to prioritize energy savings from the initial stage of plant construction; once a facility is built, it is very costly to address issues related to low energy efficiency. Furthermore, for existing oil refining companies, although there is a drive to reduce energy costs, adopting energy-saving measures and technologies in their processing facilities requires significant investment; if only superficial energy-saving efforts are made without major improvements, it often results in energy savings that do not lead to cost savings. Generally, improvements in the energy efficiency of refineries are primarily related to the efficiency in the following three areas: thermal integration and efficiency of units and systems ； Power generation and power input ； Heating furnace efficiency. 1. Development of energy-saving technologies in refineries 1.1 Heat integration The sharp rise in energy prices in the 1970s, along with the emergence of methods for analyzing and optimizing preheating processes, led many refineries to make significant improvements to their heat integration processes in the early and mid-1980s. Thermal integration is not only an energy-saving measure but also a way to reduce the capital investment in new installations. Designers have been employing a degree of thermal integration, such as recovering heat from the cooling process of process streams to preheat streams that require heating. Thermal coupling replaces separate heating or cooling heat transfer through heat recovery. Appropriate parameters (such as the pinch temperature) are used to determine the degree of recovery, thereby minimizing the total capital investment in heat transfer equipment (including heaters and coolers). This also applies to bottleneck removal upgrades. Previous heat recovery processes were relatively simple, resulting in low heat recovery efficiency and high amounts of heat lost to the air and water coolers. Designing the minimum number of heat exchangers in the system simplifies piping and layout, yet the approach of increasing the system’s heat recovery rate by reducing the temperature driving force without altering the design results in a worse heat exchanger factor, thereby missing out on the opportunities offered by later narrow-point technologies to improve heat recovery while simultaneously reducing total capital costs. The scale of the device also affects the heat exchange process. For a crude oil distillation unit with a capacity of 10 million tons per year, a three-stage reflux system offers higher energy efficiency than a single-stage reflux + overhead condenser system, as the former can provide high-temperature heat. Another factor to consider is the degree of integration with other devices. In the past, a set of equipment was designed and operated as an independent system, usually with a separate control room. This not only increases infrastructure costs (due to the addition of heat transfer equipment) but also leads to energy losses. On the contrary, using high-temperature, atmospheric-pressure heavy oil directly as the feed to the vacuum tower can improve the overall energy efficiency. Now, the crude oil heating process recovers the heat from the vacuum tower reflux and the product, heat that was previously used to preheat the feed to the vacuum tower. In the past, the crude oil preheating temperature in independent crude oil distillation units rarely reached 250°C; it was usually only slightly above 200°C. It generally requires a total temperature driving force of 60°C for the entire system. The narrow-point design technique requires only that the narrow-point heat exchangers use the lowest temperature driving force, rather than requiring all heat exchangers to use it. To achieve the same energy performance goals, narrow-point technology is characterized by a minimum temperature drive force of over 60°C. Compared to previous designs with separate units, the design using narrow-spot technology offers higher energy efficiency; the heating furnace load can be reduced by 18%, while the total area of the heat exchangers is 150% that of the former design. 1.2 Cogeneration: The energy efficiency of refineries depends heavily on the method used to supply them with electricity. Compared to thermal energy, electric energy accounts for a larger share in energy consumption due to its high quality and high cost. Refineries are particularly suitable for cogeneration. Cyclic power generation requires a heat absorber to absorb the excess heat that cannot be converted into electrical energy thermodynamically. Refineries can provide this “useful” heat source (i.e., steam); after absorbing heat, the steam can be used in the refining processes without having to be discarded. This results in a high potential efficiency for the entire system. Figure 1 shows the relationship between the achievable power generation efficiency and the ratio of on-site electricity/heat demand. In a configuration that combines a gas turbine, a high-pressure boiler, and a backpressure steam turbine, the efficiency in generating the electrical power required by the entire plant can reach about 80%. That is, the internal power generation cost per unit of energy is only slightly higher than the fuel cost; on the other hand, the cost of purchased electricity is always much higher than the fuel cost, typically 4 to 5 times the fuel cost. Why are there still many refineries that do not generate power internally and instead purchase electricity? This is mainly related to the relative price of fuel and electricity, PEE (the equivalent price efficiency of input electricity, which refers to the price ratio of the same unit of fuel to electricity). The fuel and electricity prices in Europe and North America can be divided into three distinct periods: the first was before 1973, characterized by low fuel costs, low electricity costs, and low PEE ； Secondly, from 1973 to the late 1980s, high fuel costs, high electricity costs, and high PEE ； Third, from 1990 to the present, medium fuel costs, high electricity costs, and medium PEE. Before the first oil crisis in 1973, refineries enjoyed high gross profits and low energy costs, with electricity prices accounting for a relatively small share. Moreover, the only technology available for cogeneration at that time was the steam turbine, which had limited potential (limited power generation under backpressure and low efficiency of condensing turbines). During the first oil crisis, although both fuel and electricity prices were rising, the increase in electricity costs was slower than that of fuel, resulting in electricity costs being lower compared to fuel costs. Many refineries have taken measures such as modifying the preheating and heat recovery processes, upgrading heating furnaces, and saving steam, while few refineries have invested in cogeneration processes due to their high capital costs. In the 1990s, the situation was favorable for cogeneration (fuel prices were falling while electricity prices remained high), and industrial gas turbine technology had matured (with thermal efficiency in combined power generation systems reaching around 50%). However, at that time, refineries faced issues such as excess refining capacity, low gross profits, as well as concerns related to clean fuels and environmental protection, which prevented them from investing more in cogeneration and energy conservation measures. However, in recent years, as the power industries in various countries have been gradually deregulated, combined heat and power generation has once again attracted attention. Some **(such as Spain and the Netherlands) even encourage refineries to generate electricity. Although the installation of CHP units increases local emissions, the benefits to the global environment far outweigh these drawbacks. Since 1973, the energy efficiency of ExxonMobil’s refineries and chemical plants around the world has improved by 35%, which equates to approximately 1.8 billion barrels of oil saved – roughly equivalent to two years’ worth of fuel consumption for vehicles in Europe. Most of them come from cogeneration. Currently, cogeneration accounts for over 30% of its total power generation. The company’s cogeneration capacity was approximately 600 MW in 1980, reached 1500 MW in 1990, and reached 2900 MW in 2000. 1.3 Heating furnace efficiency and heat recovery options Similar to cogeneration and power generation options, the driving forces for installing heat recovery facilities and improving the efficiency of open-flame heating furnaces also change over time. Even the best choice for heat recovery solutions (air preheaters or waste heat boilers WHB) is changing. In the 1960s, the choice between the two was not a significant issue, as their energy-saving efficiencies were roughly the same; however, the WHB approach typically had lower costs, was more practical, and had less impact on the manufacturing process. However, with the development of cogeneration, the old WHB approach has become an obstacle to carrying out effective system upgrades. To generate as much power as possible, refineries want all the steam to be high-pressure steam. Any WHB that produces low-pressure steam will reduce power generation. During the 1980s, when fuel prices were high, the simple payback period for projects to upgrade heating furnaces and install air preheaters was 3 to 4 years ； Later, as fuel prices dropped and equipment costs continued to rise, by the end of the 1990s, the simple payback period had reached 6–7 years. 1.4 Plant Integration Recently, pinch technology has been extended to the process and utility facilities across the entire refinery, enabling the evaluation of the connections between all processes and utilities as well as energy integration. Attention should be paid to the synergies between process and utility facilities, especially those among steam, electricity, and process heat sources. Recent numerous energy research findings indicate that most high-return opportunities are typically achieved by optimizing these systems. In the case of multiple process units, it is unnecessary to conduct a detailed analysis of each individual unit to determine the optimal solution; in such situations, the processes can be connected directly through heat exchange or indirectly through a steam system. Plant optimization requires taking into account many different, and sometimes even conflicting, parameters, such as the selection of utility systems, the choice of process integration routes, and whether the plant will be put into operation or not. 1.5 Energy cooperation: Some utility companies have realized that if excess heat can be supplied to industrial consumers, it is possible to reduce power generation costs, and they are seeking cooperation in this area. For industrial consumers as well, this represents a very attractive business opportunity. Utility companies are not only willing to offer long-term electricity price discounts but also provide funding for energy-saving projects, particularly in the form of cogeneration facilities near refineries and petrochemical plants, thereby reducing operating costs for consumers. The degree of integration between the processes and operations in the two is crucial. KBC believes that both parties involved in an energy cooperation scheme will benefit from a highly integrated approach from the outset, one in which utility companies should be fully involved in the energy optimization of refineries. The most effective cooperation strategies go far beyond simply building a utility facility, such as a co-generation unit next to an oil refinery and supplying it with electricity and steam. Optimal cooperation requires optimizing the collaborative operations, as well as the long-term expansion and energy efficiency planning of both parties’ facilities, on a daily basis. A method recently explored by KBC is a \"resource sharing\" approach, which involves a \"neutral expert\" leading the establishment of an energy joint venture composed of refineries and investment partners. Investment partners can be chosen publicly; they are usually utility companies, but credit institutions or venture capital firms are also possible. 2. Some general measures adopted by high-energy-efficiency refineries: Design practices evolve with the drive to build high-energy-efficiency facilities and the available technologies. For the current optimal design, the refinery to be designed is required to meet all its own power needs through internal power generation, with a power generation efficiency of 80%; the efficiency of open-flame heaters is around 92%. The preheating process is optimized using narrow-point technology, and the process and utility systems are integrated in accordance with an overall plant optimization plan. At the same time, other energy-saving process measures should be adopted, such as energy recovery in catalytic cracking (FCC) units, hydroprocessing and high-temperature separators in hydrocracking units, optimized quenching, efficient internal components for towers, optimized reflux rates, optimal insulation, and condensate recovery. Furthermore, equally important are best practices. Although improving existing inefficient designs is costly and usually not economical, adopting best practices requires only minimal investment (such as instruments and monitoring tools) as well as changes in procedures and organization. Although the organizational structures of advanced refineries vary, in terms of energy efficiency they generally share the following common features: (1) Organizational structure and ownership: There is a full-time energy manager with clear responsibilities and authority, who makes decisions regarding issues that affect energy costs. Energy performance degradation and financial losses resulting from poor operation should be reported to management, and actions should be taken to address them. Operators are aware of the on-site energy targets and improvement plans, and they should participate in efforts to improve efficiency. Regular energy training programs are carried out, and periodic energy audits are conducted to identify opportunities for improving energy efficiency and to develop implementation plans. (2) Steam and power systems: Real-time steam and power prices are used for calculation to determine the operational objectives for maintaining an optimal steam and power balance, including generator/turbine switching, load reduction, and reactive power control. This generates a real-time steam balance for the refinery, including condensate recovery, as well as a real-time power balance for the refinery, with details of its outputs/inputs and consumption/production. The boiler operates in accordance with procedures and objectives that include sludge discharge optimization, excess air, soot blowing frequency, burner configuration, and cleaning. Real-time monitoring of the efficiency of large process turbines, alternators, gas turbines, and engines. The optimal load and cleaning frequency are determined based on this monitoring activity. For maintenance, regular inspections are carried out on steam leaks throughout the plant, the performance of steam traps, and condensate recovery; maintenance plans are developed, and the order of repairs is determined. To maintain an accurate steam balance, the flow meter should be zeroed and checked regularly. (3) Fuel system strategy: The results of real-time marginal fuel price calculations are used as input values for the calculation and operation strategies of steam and electricity prices. Real-time monitoring includes the fuel balance for all gaseous and liquid fuels (the total value should be greater than 97%). Torch loss is monitored as part of the refinery’s fuel balance and reported as a loss in revenue. Zero the flow meter in the steam system, conduct regular inspections, and calibrate the analyzer periodically. (4) Open-flame furnace: Set the furnace output and excess air to target values. Regularly check the burner configuration and clean it periodically. The operators can skillfully locate air leaks and carry out repairs. The real-time efficiency calculation results of the heating furnace are displayed on-site, reported on a monthly basis, and any deviation from the target value is reported as revenue loss. The analyzer is calibrated regularly. (5) Preheating process: The preheating process is modeled and monitored regularly, along with the monitoring of fouling in the heat exchanger. This model is used to optimize the cleaning cycle. The impact on distillation should be considered when setting the optimal reflux load and flow rate. 3. Trends in energy-saving efforts in refineries To meet the expected product specifications, refinery processes will change in the future, which will lead to a significant increase in the energy consumption (fuel and power) of refineries. It is estimated that at present, the energy consumption for internal use in a refinery based on catalytic cracking units is about 6% of the crude oil processed, while this figure will reach around 10%–12% by 2010. Therefore, in the near future, optimizing the energy used by refineries will be even more crucial for reducing refining costs. Ways to improve energy efficiency in the future include: (1) improving the utilization of unit heat energy within the process equipment; for example, the concept of progressive distillation can be applied to the distillation section ； Improve flue gas waste heat recovery ； Optimizing heat exchange processes using narrow-point technology, etc. (2) Thermal integration between process units: This avoids the cooling and heating of process streams between consecutive units, by feeding the hot products from upstream directly into downstream units, thereby improving thermal integration between units that generate heat energy and those that consume it. (3) Improve process technology for energy savings: Improve catalysts to enable the hydrogenation unit to operate at lower hydrogen partial pressures ； Increase the hydrogen content in the recycled hydrogen. (4) Adopt advanced process equipment and select high-efficiency heat exchangers ； Use a turbine to recover the energy from the high-pressure fluid flow. (5) Use of cogeneration: By employing cogeneration technology, gas turbines are used to generate electricity while the flue gases are utilized to heat the process streams, thereby reducing CO2 emissions and fuel consumption. Replace the conventional high-load main heating furnace in the process unit with an on-site cogeneration unit ； A combined heat and power unit is used to supply all the heat required by the entire process plant. (6) The energy efficiency of technologies such as combined cycle (IGCC, TGCC) is significantly higher than that of the conventional utility systems in most existing refineries (by about 80%). Through the above 6 improvements, the proportion of energy consumption for the refinery’s own use relative to crude oil processing volume can be reduced by 2%–3%, saving the refinery significant costs. Second, the results of the literature search on evaluation methods for energy consumption in foreign refineries show that there is very little available in the form of published studies and materials regarding current evaluation methods for energy consumption in such refineries. Based on the information provided by domestic technical personnel who have gone to foreign refineries for training and inspections in the past, the following summaries and organization are presented. The methods used to calculate energy consumption in refineries generally fall into the following categories: One category is based on the average energy consumption of existing refineries (derived from operational records) to determine a baseline value for energy consumption; methods belonging to this category include Amoco’s refinery energy factor method, Nelson’s complexity coefficient method, and Shell’s energy consumption coefficient method. Our country is also using this type of method at present. Another category relies on the premise of advanced technology and economic Rationality to \"artificially\" establish energy consumption benchmarks. Exxon in the United States uses this approach, and the energy density index method, which is widely applied today, also employs a similar strategy. Such methods determine standard energy consumption values for various processing units, calculate and compare the gap between actual energy consumption and these standard values, thereby guiding energy-saving efforts and determining the direction in which improvements should be made. 1. The refinery energy factor method: This method was proposed by Thomson of the American company Amoco in the 1980s, and its key points are as follows. (1) Based on the average energy consumption of the process units in U.S. refineries. The energy consumption of the crude oil distillation (at atmospheric pressure) unit is 287,500 kcal/ton, resulting in an energy factor of 1. (2) The average power consumption, steam consumption, and heat energy consumption of each process unit are based on the data published by Nelson (see Table 1). The thermal efficiency for steam and heat consumption is 80%, with the electricity conversion standard being 2520 kcal/kWh. (3) The energy factor of other processing units is determined by comparing the energy consumed per barrel of feed oil processed by that unit with the energy consumed per barrel of crude oil processed by the crude oil distillation unit, with the energy factor of the crude oil distillation unit being set at 1. Detailed data can be found in Appendix 1. (4) The method for calculating the energy factor of a refinery is as follows: Where: Ci – the actual processing volume of each unit; Fi – the energy factor of each unit; Ct – the actual processing volume of the atmospheric distillation unit. (5) To calculate the actual energy consumption of a unit, multiply its actual processing volume by its energy factor. When calculating the overall energy consumption of the plant, the actual processing volume of the atmospheric distillation unit is multiplied by the plant’s energy factor. The average energy consumption and energy factor of each typical device are detailed in Table 2. The advantage of this method is that it simplifies the concept of energy consumption, making it easy to compare energy consumption among various units as well as between different refineries. The disadvantages are: the benchmark is not strict enough, and changes in the main process conditions of the device cannot be reflected or adjusted through the energy factor. Table 1: Comparison of Complexity Coefficients and Utility Consumption for Major Units
| Unit Name | Complexity Coefficient | Electricity | Steam | Heat | Crude Oil Distillation | 1 | 1.0 | 1.0 | 1.0 | 1.0 | Alkylation | 117.0 | 21.6 | 3.6 | 6.8 | Delayed Coking | 5.5 | 2.0 | 2.1 | 2.8 | 2.5 | Catalytic Cracking | 63.3 | 6.0 | 1.1 | 3.7 | Hydrocracking | 616.0 | 0.5 | 2.3 | 2.7 | Hydroprocessing | 1.7 | 1.5 | 0.6 | 0.6 | 0.6 | Hydrodesulfurization | 32.7 | 0.5 | 0.7 | 0.7 | Catalytic Reforming | 52.7 | 1.5 | 3.0 | 2.7 | Vacuum Flashing | 10.8 | 1.3 | 0.7 | 0.9 | Lubricant Production | 642 | 5.0 | 89.0 | 8.5 | 23.1 |

Table 2: Energy Factors for Major Process Units
| Unit Name | Average Energy Consumption (10³ BTU/barrel) | Energy Factor |
| Unit Name | —— | —— |
| Atmospheric and Vacuum Distillation | 1871.2 | —— |
| Atmospheric Distillation | 1541.0 | —— |
| Catalytic Cracking | 5033.3 | —— |
| Delayed Coking | 3962.6 | —— |
| Hydrorefining | 900.6 | —— |
| Hydrocracking | 4042.6 | —— |
| Residue Hydroprocessing | 2441.6 | —— |
| Hydroprocessing | 950.6 | —— |
| Alkylation | 9406.1 | —— |
| Catalytic Reforming | 4322.8 | —— |
| Aromatic Units | 4002.6 | —— |
| Solvent Deasphalting | 4072.6 | —— |
| Lubricants | 304419.8 | —— |

2. Energy Consumption Coefficient Method Used in Refineries
The energy consumption coefficient method employed by Shell Group is similar to the energy factor method used by Amoco. The key points of this method are as follows:
(1) Convert various forms of energy consumption into standard refinery fuel:
Standard fuel: High calorific value of 10,300 kcal/kg.
Steam: 12 tons of steam = 1 ton of standard fuel.
Electricity: 3,000 units of electricity = 1 ton of standard fuel.
Both unit-level energy consumption and overall plant energy consumption are expressed as a percentage of the feed volume. (2) Determine the energy consumption coefficients for each process unit and those for utility systems based on the average data from the group’s refineries. For each process unit: Feed rate × energy consumption coefficient = theoretical energy consumption; ∑Theoretical energy consumption = total theoretical energy consumption of the plant. Actual energy consumption / Theoretical energy consumption = energy consumption index. If the energy consumption index is greater than 100%, there is an issue with the energy consumption. If the energy consumption index is < 100%, it indicates that energy-saving efforts are effective. (3) The theoretical value of processing loss can also be calculated using a similar method, namely: loss coefficient × feed amount = theoretical processing loss. The energy consumption coefficients and loss coefficients of the main process units in Shell Group’s refineries are shown in Table 3. Table 3: Energy consumption and loss coefficients of the main process units in Shell Group’s refineries. Unit name, Energy consumption coefficient (% of feed), Loss coefficient (% of feed): Atmospheric pressure unit – 1.9, 0.3; Vacuum unit – 1.8, 0.2; Platinum reforming – 5.6, 0.2; Diesel hydrogenation – 2.5, 0.2; Oxidized asphalt – 4.4, 0.5; Gas treatment – 2.6, 0.3; Sulfur recovery – 2.5, 12.2; Lubricant blending – 1.2, 0.2. 3. Complex coefficient method: This method was proposed by Nelson in the United States. This method uses the level of operating costs as an indicator to measure the complexity of a process unit. Operating costs are directly related to energy consumption. The key points of the complexity coefficient are as follows: (1) Set the complexity coefficient of the atmospheric distillation unit in an average-sized U.S. refinery to 1. The factor by which the operating cost per barrel of raw material processed by another type of unit is higher than that of an atmospheric pressure unit per barrel of crude oil processed is used to indicate how many times more \"complex\" that unit is compared to the atmospheric pressure unit; in other words, it represents the complexity coefficient of that unit. For example, in the United States in 1975, the cost per barrel of crude oil processed by an atmospheric distillation unit in an average-sized refinery was 104 dollars, while the cost per barrel of feedstock processed by a coking unit (with a capacity of 15,400 barrels per day) was 570 dollars. Thus, the complexity coefficient for the atmospheric distillation unit was 1, whereas the complexity coefficient for the coking unit was 570/140 = 5.5. (2) The refinery complexity factor represents the multiple by which the operating cost of the entire refinery per barrel of crude oil processed is compared to the operating cost of the atmospheric distillation unit per barrel of crude oil processed. Assuming that a refinery has only atmospheric and coking units, the feed volume to the coking unit accounts for 18% of that to the atmospheric unit. The operating cost per barrel of crude oil incurred by the coking unit is 0.18×570 = 102 dollars, and the increase in the complexity factor is 0.18×5.5 = 0.99. Thus, the operating cost per barrel of crude oil processed by the entire refinery is 1.99 times that of the atmospheric unit; in other words, the overall complexity factor for the refinery is 1.99. (3) The complexity coefficients of the main process units in the refinery are shown in Table 4. The method for calculating the complexity coefficient for the entire plant is as follows: C = ∑Ci×Fi + Ct. Here, Ct is the complexity coefficient for the atmospheric-pressure unit, which is 1.0; Ci represents the complexity coefficient of each secondary processing unit, and Fi is the percentage of the feed volume to each secondary processing unit relative to the feed volume of the atmospheric-pressure unit. The relationship between the complex coefficient of the entire plant and the average energy consumption is shown in Table 5. Table 4 Complexity coefficients of various major process units
Unit name – Complexity coefficient
Atmospheric pressure units: 1; Fluidized coking: 5; Pressure-reduction units: 2; Delayed coking: 5; Thermal cracking: 3; Hydrogen production: 1.2; Catalytic cracking: 5.5; Solvent deasphalting: 5; Catalytic reforming: 4; Solvent extraction: 4.5; Hydrocracking: 6; Alkylation: 9; Hydroprocessing: 3; Isomerization: 3; Hydrofining: 4

Table 5 Relationship between the overall complexity coefficient of a plant and its average energy consumption
Overall complexity coefficient – Average energy consumption (Mbtu/barrel): 6.05, 25.70, 60.08, 67.59, 76.01, 100.85.
It is clear from this complexity coefficient approach that the more secondary processing units a refinery has, the higher the energy consumption of those units, and thus the greater the overall complexity coefficient of the plant. The advantage of this method is that it provides an understanding of the overall complexity of a refinery, facilitating energy consumption comparisons among refineries of the same type. The drawback is that the energy consumption of the atmospheric-pressure equipment cannot be reflected in the overall complexity factor of the plant. 4. Energy consumption benchmark factor method: This method was proposed by the American company Exxon. It assumes that the device must make effective use of the heat supplied to it; although the device inevitably experiences low-temperature heat losses or other processing-related heat losses, such losses must also be reasonable. This method takes the advantages of the Thomson energy factor method and avoids its disadvantages. This method first establishes unified valid operating and utility conditions for various units, with the main contents as follows: (1) For 42 process units such as those for atmospheric pressure operations, reduced-pressure operations, and catalytic cracking, standard energy balances are developed separately, and the key process parameters (such as the yield of heavy oil at atmospheric pressure, catalytic