Introduction

The discovery of Crude Oil, in the Nineteenth century, fortuitously coincided with the invention of the internal combustion engine and its deployment in automobiles, industrial engines and aircraft. These developments propelled the industrialized world from the era of Coal dependency to the modern Petroleum-fueled era. Over the past 150 years, Crude Oil has become a critical global commodity, earning the sobriquet “black-gold’’ [1]. Crude Oil has governed the geo-economic and geo-political calculus of Superpowers vying to control this resource.

Today, even as the world is transitioning away from fossil fuels, Crude Oil, along with Coal and Natural Gas, caters to more than 80 % of global energy demand. Crude Oil cannot be utilized directly but must be distilled and converted into various refined products that are used as transportation and industrial fuels, and as raw materials in the Petrochemical Industry. Examples of refined fuels are Gasoline, Diesel, LPG, Furnace Oil and Aviation Turbine Fuel; Petrochemical raw materials include Liquefied Petroleum Gases, Naphtha, Benzene, Toluene, Xylene, while Petroleum-based products include Lubricants, Paraffin Wax, Petroleum Coke and Bitumen.

The global production of Crude Oil in December 2022 was 100.8 million barrels per day, while global Refinery throughputs reached 82.3 million barrels per day [2]. Total annual production of refined Crude Oil products in 2022 was 4303 million tonnes, which is about 30 billion barrels of oil equivalent (Mboe). The growth of the Crude Oil refining sector is illustrated in Figure 1, which also shows that Crude Oil is the dominant source of global energy today, constituting 30% of the energy basket. It can also be observed that the Crude Oil refining industry has grown by 30% since 1990, with Asia leading and driving growth rates, while USA and Europe are the other two dominant Crude refining regions [3].  In Asia, large economies like China and India will continue to rely on Crude Oil as their main source of energy for many years to come.

Figure 1

Crude Oil prices are influenced by the fact that most consumers maintain significant inventories of Crude Oil, considering price stability, availability and strategic aspects. Crude Oil is withdrawn from inventories to be processed in refineries, depending upon market demand for various refined products. The global refined Petroleum products market, which was $2,311.84 billion in 2021, has been growing at a compound annual growth rate (CAGR) of 13.1% [4].

It is apparent the Crude Oil refining Industry is one of the key growth engines of the global economy. The health of this industry has a bearing on the economic well-being of the world.

The Decarbonization Imperative

Notwithstanding its dominant role today, the Crude Oil refining industry is threatened by the winds of change sweeping through the energy sector, under the impetus of the global sustainability and decarbonization movements. Crude Oil refining is estimated to account for about 6–8% of all global industrial energy consumption [6]. Most of this energy consumption involves direct combustion of fuels in Heaters and Boilers, which generates a lot of Carbon Dioxide. Hence Crude Oil refining is one of the biggest industrial emitters of Greenhouse Gases.

The International Energy Agency (IEA) has recommended that fossil fuels must be reduced from the current levels of four‐fifths of global energy supplies, to about one‐fifth by 2050, with Crude Oil production reducing by 75%, to 24 million barrels a day by 2050. The IEA had, in fact, proposed a ban on new Oil and Gas field developments starting from 2021 [5]. This, of course, has not happened and many new Oil and Gas developments have been announced in the recent past. While there is no immediate existential threat to refineries, the growth of renewable energy and electrical vehicles will undoubtedly diminish the market share for refined Petroleum products. Furthermore, ESG compliance pressures from influential investors, societal activism, and potential Carbon taxes are inexorably forcing the Crude Oil refining industry to reduce its Carbon footprint.

What are the options for the Crude Oil refining Industry to reduce its Carbon footprint? This article examines the Crude Oil refining process and identifies the unit operations and processes which contribute significantly to the emissions burden. Potential mitigation strategies targeting these emissions are then discussed, with examples. The focus is on Scope 1 and 2 emissions, as depicted in Figure 2, conforming to the GHG protocols of World Resources Institute and World Business Council for Sustainable Development [7].

Figure 2

For purposes of this discussion, it is convenient to consider a single Crude Oil refinery  with complex configuration, which partially generates the required utilities onsite and purchases some utilities from offsite suppliers. This is a common operating model in the refining industry. Emissions from all onsite operations would be Scope 1 and emissions linked to offsite utilities categorized as Scope 2. The various other supply chain  elements, including raw materials and products which are Scope 3, are excluded from this analysis. The Scope boundaries are shown in Figure 3 and the items considered for this article are listed below:

Scope 1: Direct emissions

  • Emissions from Refinery Unit Operations and Processes.
  • Emissions from Generation of electricity, heat, steam or cooling systems within the refinery boundary.
  • Emissions from the combustion of fuels in vehicles within the refinery boundary.
  • Emissions from Flares, Vents, leaks, fugitive emissions.

Scope 2: Emissions From Purchased Energy

  • Purchased Electricity
  • Purchased Steam
  • Purchased Natural Gas

Figure 3

Crude Oil Refining Process Overview

Petroleum refining involves physical separation of Crude Oil into gaseous and liquid distillate fractions of varying boiling point ranges, which may then be subjected to catalytic and thermal reaction processes, to produce refined products with the desired specifications. Refineries are generally configured to process a variety of different Crudes and the yield of each product depends on the Crude being processed. The operations that can be performed in a refinery depend upon its configuration, which can range from basic distillation and blending functionality, to extremely complex configurations with the ability to crack or reform various distillate and residue fractions into higher value products. Based on their configurations, ranging from basic to complex capabilities, Crude Oil refineries can be placed into the following categories [6]:

Topping Refineries:

These have the simplest configuration, comprising only the minimum storage and processing infrastructure to separate Crude Oil into Petroleum Gases and liquid fractions, by atmospheric distillation. Facilities in Topping refineries are limited to Storage tanks, Atmospheric Crude Distillation Unit (CDU), LPG recovery unit and Utilities. The products from a Topping Refinery primarily serve the industrial fuels market or are used as feedstock for  Petrochemicals manufacture.

Hydro-Skimming Refineries:

Hydro-Skimming operations extend the capabilities of Topping refineries, enabling treatment of  light distillates from the Crude Distillation Unit, to produce fuels suitable for the automotive market. Hence, they include operations like  hydrotreating, reforming and blending. They can produce desulfurized liquid distillates and high-Octane Gasoline.

Conversion Refineries:

These refineries are much more complex than the Topping and Hydro-Skimming Refineries. They incorporate Catalytic and Thermal cracking processes to convert Distillates and Residues into a variety of value-added products. Conversion refineries can be configured for medium or deep conversion, depending on the boiling range of Distillates that are targeted for processing. Medium conversion refineries utilize operations such as Fluid Catalytic Cracking (FCC) or Hydrocracking (HC) to upgrade medium and heavy-distillate fractions into Gasoline, Olefinic gases, and other Petroleum products. Deep conversion refineries go beyond this, to tackle the heavier residue fractions from the Vacuum Distillation Unit (VDU). These are heated to high temperatures and cracked to  recover lighter fractions for blending into the gaseous and  liquid fuels pool.

Major Unit Operations and Processes

Figure 4 is a flow sheet illustrating the various refinery process units and the related feeds products and blending streams in a typical complex, deep conversion refinery [8,9]. A brief description of these units is provided in the following paragraphs.

Desalting:

Some Crudes contain excessive Salt, which leads to fouling and corrosion in processing equipment. In general, Crude Oils that contain more than 10 lb salt /1000 barrels of Oil will require desalting. In an electrostatic Desalter, Crude oil is washed with Water at temperatures of 90 oC to 150 oC, under sufficient pressure to avoid boiling of Water and volatile hydrocarbons. After free Water is removed, the remaining emulsion is subjected to a high voltage electrostatic field that breaks the emulsion and separates dehydrated Crude Oil and Water phases.

Figure 4

Crude Distillation Unit (CDU):

This is an essential operation in all Crude Oil refineries. Crude Oil, after desalting, if necessary, is heated to a temperature of 315 oC to 425 oC in a fuel gas fired heater. The partially vaporized Crude is fed to a distillation column, operating at a pressure slightly higher than atmospheric (1.4 to 2.4 bara). The distillation tower typically contains between 30 and 50 fractionation trays, which enables separation of Crude Oil into various fractions, based upon boiling points. The lowest boiling fractions, comprising petroleum gases leave as overheads, while liquid fuels such as Naphtha, Kerosene, light Gasoil, and heavy Gasoil  are tapped from the column as middle distillates. The Gasoil fractions largely contain molecules in the Diesel boiling range. The bottom product is Heavy Oil, termed “atmospheric tower residue” which is then sent to the Vacuum Distillation Unit (VDU). The residue can also be directly blended into the Fuel Oil pool.

Vacuum Distillation Unit (VDU):

The intent of vacuum distillation is to recover liquid fuels from the atmospheric tower residue stream, which is fed to the VDU after heating in a fired heater upto 400 oC to 415 oC. The VDU operates under vacuum (0.03 to 0.07 bara), which allows boiling of high molecular weight hydrocarbons without decomposition. Generally, steam-jet ejectors are used to maintain vacuum. The middle distillate from the VDU, called Vacuum Gasoil contains hydrocarbons in the Diesel boiling range, as well as higher boiling components. This fraction is therefore fed to catalytic cracking processes such as Hydrocracker or Fluid Catalytic Cracker for further conversion. The vacuum column residue is sent to be thermally cracked or to the deasphalting unit.

Hydrotreating:

The main purpose of Hydrotreating is to remove organic Sulfur compounds by reacting them with Hydrogen in a fixed bed catalytic reactor. Sulfur levels must be lowered to meet specifications for automobile fuels (Gasoline and Diesel). Naphtha must be desulfurized before processing in the Catalytic Reformer or when used as feedstock for Hydrogen production in Steam Reformers. Sulfur is also a catalyst poison in various catalytic units. In Hydrotreaters, Sulfur compounds react with Hydrogen to form H2S which is subsequently removed.  Diesel is also desulfurized in “Diesel Hydrotreaters”. The required quantity of Hydrogen may be completely produced onsite or purchased from offsite suppliers.

Catalytic Reformer:

The Catalytic Reformer is a reactor that converts Naphtha fractions into compounds that are blended into Gasoline, to increase its Octane number.  The reactions include isomerization and cyclization of low-Octane Paraffins into branched Alkanes (iso-paraffins) and cyclic Naphthenes. Partial dehydrogenation of these products results in aromatic hydrocarbons that increase the Octane number of Gasoline. Due to the dehydrogenation reaction, the catalytic Reformer produces significant quantities of Hydrogen for use elsewhere in the refinery.

Fluid Catalytic Cracker (FCC):

The process is used to convert higher molecular-weight hydrocarbons from the VDU into lighter, value-added fuels by catalytic cracking at high temperature (480 oC to 540 oC). It uses a powdered catalyst that is kept fluidized during the cracking reactions. The design allows for continuous regeneration of spent catalyst, which has Coke deposits that are burned off in the regenerator. This keeps the catalyst hot and enables cracking of Oil molecules. The products from an FCC are usually Gasoline, light Fuel Oils, and light Olefins.

Hydrocracker (HC):

The Hydrocracker is a reactor in which catalytic cracking is conducted at temperatures of 290 oC to 400 oC and pressures of 8.3 to 13.8 bara, in the presence of Hydrogen. The difference with FCC is that, in addition to cracking reactions, hydrogenation of unsaturated hydrocarbons and removal of Sulfur compounds also occurs. Heavy distillates are  converted into lighter products such as Naphtha, Jet fuel and Diesel Oil.

Coking:

This is a severe thermal cracking process that is used to convert VDU residue into lighter distillates and Coke. There are different types of Cokers which are used, depending upon whether the desired product is Coke or liquids. Delayed Coking is used to produce commercial Coke. It is a semi-batch process that uses two Coke drums, a Coking furnace and distillation tower. The yield of liquid products such as Naphtha  and Diesel is low.

An alternative type of Coker is Exxon Mobil’s proprietary Flexicoker, in which heated Vacuum Residue at (315 oC to 370 ºC) is sprayed onto hot fluidized Coke (recycled internally). The Coke bed temperature ranges from (510 oC to 540ºC), causing thermal cracking. Vapors  are condensed and fractionated to give gaseous and liquid products, with a low yield of Coke.

Visbreaking:

This is a mild thermal cracking process that is used, as the name suggests, for viscosity breaking. The temperature conditions are controlled, and thermal cracking is interrupted by quenching. The intent is to break larger molecules to the extent that viscosity is reduced to meet Fuel Oil specifications. Other product streams are: Fuel gas, Naphtha, Light Gasoil and Heavy Gasoil.

Alkylation:

The Alkylation process can be termed the reverse of Cracking, since it catalytically combines light Olefins (Alkyl groups) with iso-Butane, resulting in branched chain compounds. This helps to increase the Octane number of Gasoline. Several designs are possible, using Hydrofluoric acid or Sulfuric acid as catalysts.

Isomerization:

The isomerization process converts paraffinic compounds, primarily Pentane  and Hexane into their branched chain isomers. It is a catalytic process, and the products help to increase the Octane number of Gasoline.

Solvent deasphalting process (SDA):

The SDA process extracts the heavier components of Vacuum Residual Oil, called Bitumen, using Light Paraffin solvents. This is used in the manufacture of Asphalt and as a component in the refinery Fuel Oil pool.

Gas Processing Unit:

Light gases produced in various processes are sent here for recovery of valuable LPG, Pentane and Hexane components. The unit comprises several distillation, absorption and stripper columns to separate  and recover pure components.

Solvent Dewaxing Unit:

This unit separates wax from Heavy Vacuum Gas Oil and de-asphalted Oil, to obtain petroleum Wax and Lubricating Oil Base Stock (LOBS). Wax separation raises the pour point of lubricating oil. The Solvent Dewaxing Process involves stage-wise refrigeration of feedstock to sub-zero temperatures after mixing with solvent. Examples of solvents are Methyl Ethyl Ketone (MEK) and Liquid Propane (which is also a refrigerant). The Wax is crystallized in a crystallizer and separated in a Rotary drum filter. Catalytic dewaxing technologies can be used in lieu of Solvent based processes.

Hydrogen Plant:

Refineries generally produce a substantial portion of their Hydrogen requirements from an onsite Hydrogen plant. The Steam Methane Reforming process is normally employed, using Naphtha, Natural gas or Fuel Gas as feedstock. The process involves desulfurization of feedstock, after which it is then mixed with Steam and reformed catalytically in a gas fired reforming furnace at about 800 oC and 25 to 30 bara, to produce Hydrogen-rich  Syngas. The Syngas is further processed to remove Carbon Monoxide and Carbon Dioxide, to get pure Hydrogen.

Other Process Units:

There are other important processes, for example, Bitumen Blowing Unit for Asphalt production, Sulfur recovery unit, Aromatics (BTX) recovery. Providing these units is  a refinery specific decision.

Utilities

From an emissions perspective, refineries generally have units such as Steam Boilers, and Captive Power Plant which utilize Fuel gas, Coke, Fuel Oil or Natural Gas as energy sources. Flare systems are also major emission sources.

Other utilities include Cooling Water and Chilled Water systems, Refrigeration units, Instrument air, Nitrogen system, Effluent treatment system, Firewater system, Water treatment plant, which however, do not contribute much to the Carbon Dioxide burden.

Carbon Dioxide Footprint of Crude Oil Refining

Crude Oil refining is considered to be among the most energy intensive industries in the global manufacturing sector. It has been estimated that 6-8% of all global industrial energy consumption can be attributed to the Crude Oil refining sector [6].

The reason for its high energy intensity lies in the fact that most Crude Oil refining processes, including distillation, cracking, reforming, and treating, operate at high temperatures, generally ranging from 200 oC to 850 oC. This requires extensive use of  thermal energy, which is obtained from direct combustion of fuels or by use of Steam. Approximately 90% of onsite fuel use in refining is for process heating [11].

The high temperatures needed to vaporize, react and crack high boiling and complex hydrocarbon molecules in Crude Oil, are achieved in Furnaces known as Fired Heaters. It is common to see numerous Fired heaters in a refinery complex, associated with various Process units. The fuel for these furnaces is usually Fuel Gas from the refinery off-gas pool or Natural Gas that is obtained from offsite suppliers. Each Fired Heater stack is a point source of Carbon Dioxide emissions, in addition to other Greenhouse gases. It has been estimated that about 73% of  Carbon Dioxide emissions from a typical refinery come from Fired Heaters [10]. Utility units such as Steam Boilers, Power plants and Flare stacks are also major sources of Carbon Dioxide emissions from direct combustion of fuels.

Apart from direct combustion of fuels, Carbon Dioxide is also produced from chemical reactions happening within some refinery processes such as Steam Methane reforming and Coking.

A study of Crude Oil refineries in 83 countries (corresponding to about 93% of global Crude Oil refined in the year 2015), reported the following observations [6]:

  • Emission intensities vary depending upon the Crude grades that are processed, the region in which the refinery is located as well as their type and age.
  • The reported Scope 1 and Scope 2 emissions ranged from 13.9 to 62.1 kg CO2/boe  across countries and 10.1 kg CO2/boe across Crude grades, with an average of 40.7 kg CO2/boe (Note: “boe” stands for “barrel oil equivalent”).

Figure 5 illustrates the key findings of the emissions study.

A direct correlation can be observed between the patterns of energy use in refineries and their Carbon footprints. A study of all the Crude Oil refineries in the USA was conducted by  Oakridge national Laboratory in 2006 and some updates were done in the year 2012 [11]. The study mapped the complete energy use pattern for the sector, starting from primary input from fuels, electricity, and steam. It was observed that for refineries in the USA, about 58% of energy inputs are from direct fuel use (combustion), with Steam being the next major energy source, followed by electricity.  It is apparent that direct fuel use and steam generation can be directly correlated with Scope 1 and 2 Carbon Dioxide emissions. Accordingly, Figure 6 summarizes the fuel use pattern and CO2 emissions on an aggregated basis, for USA refineries [11].

Figure 6

Mitigating the Carbon Footprint of Crude Oil Refining

Having examined the scope, extent and sources of Carbon Dioxide emissions in Crude Oil refineries, this section focuses on potential mitigation measures. In this context, it may be noted that most Global Oil and Gas majors have already committed to achieving “net-zero” emissions by 2050 [12]. Given that these are integrated hydrocarbon majors, the commitments encompass their Crude Oil refining operations. The refining industry as a whole, globally, has no option but to follow the lead given by the majors, as the international investment community is driving these changes. The time available to achieve these goals is limited, since the year 2050 is not very distant. It is apparent that any proposed decarbonization strategies must be implementable on a fast-track mode, while ensuring techno-economic viability.

The IEA Roadmap to Net-Zero [5] provides a conceptual framework for developing decarbonization strategies around several key pillars. From the near-term perspective of implementation ease within the Crude Oil refining industry, the following four pillars are considered the most promising:

  • Energy efficiency
  • Electrification
  • Hydrogen and Hydrogen‐based fuels
  • Carbon Capture Utilization and Sequestration (CCUS)

Using these concepts to guide strategy development, and based on Industry experiences shared in published literature, the following paragraphs explore proven and emerging methods for Crude Oil refinery decarbonization.

Energy Efficiency:

The topic of energy efficiency acquired great importance after the 1970s due to the  “Oil shock” leading to a proliferation of energy conservation initiatives and studies. This enabled the evolution of energy-efficient Crude Oil refinery technologies. There is a direct correlation between energy efficiency and Greenhouse gas emissions in refinery operations, since energy requirements are largely in the form of process heat, which is supplied  through direct fuel consumption and Steam. Though modern refineries are extremely energy-efficient compared to their older counterparts, they still have a significant Carbon Dioxide footprint, as highlighted in section 4.0 of this article.

In formulating mitigation strategies, it makes sense to  target the “worst performers” with respect to energy efficiency and related Carbon Dioxide emissions. So, which are the refinery operations that fall into this category?

Refinery operations consume energy in three forms, namely, fuel, Steam and electricity. Table 1 lists typical energy consumption and emissions data for individual process units within a refinery. Each of these is a high temperature operation. This means that feedstock must be heated by Fired Heaters, which results in flue gases containing Carbon Dioxide.

Accordingly, the following refinery units can be prioritized, to achieve targeted energy efficiency improvements and consequently reduce Carbon Dioxide emissions:

  • Steam Methane Reformers (Hydrogen plants)
  • Crude and Vacuum distillation
  • Catalytic Reforming
  • Hydrocracking
  • Thermal cracking/Visbreaking

Unit-specific energy optimization and emission mitigation opportunities for each of these are elaborated in the following paragraphs. The emphasis is on proposing solutions that have been successfully implemented and documented in the literature. Additionally, there are energy optimization concepts that are generic in nature and find wide applicability across multiple refinery operations. These generic solutions are discussed at the end.

Steam Methane reforming:

It may be noted from Table 1, that Carbon Dioxide emissions from Steam Methane Reforming are significantly higher than from the other operations. This is because Steam Methane Reforming is an endothermic reaction, occurring in catalyst packed tubes within the Reformer furnace, with heat supplied by direct combustion of fuel gases. The Reforming process produces Syngas, containing Carbon Dioxide, which is subsequently vented, along with Carbon Monoxide and residual Hydrogen, as tail-gases from the PSA unit. The tail-gases are burnt along with supplementary fuel gas in the reformer burners. So, the Reformer flue gases contain process Carbon Dioxide as well combustion products from the Reformer burners.

Some successful energy conservation strategies for the Steam Methane Reforming unit are summarized below [9,13].

Integration of Gas Turbine with Steam Methane Reformer:

It is known that pre-heating of combustion air increases the efficiency of any combustion process. When waste heat sources are utilized for this purpose, the energy savings are enhanced. Emissions are automatically mitigated on account of fuel savings. Following this principle, “pre-coupling” of a power generating gas turbine with a Steam Methane reformer has been tried out to increase overall energy efficiencies. This project was implemented successfully at a large Hydrogen plant (100 MMSCFD Hydrogen) adjacent to the Port Arthur refinery in Texas, USA. In this scheme,  the hot exhaust gases from a gas turbine were used as combustion air in the Steam Methane Reformer. The concept works because the hot exhaust stream from the gas turbine contains about 15 % Oxygen (O2) on a moisture-free, or dry, basis and about 13 % O2 on a wet basis, i.e., including the combustion moisture. An additional feature, which  is standard  practice for Steam Methane Reformers, is the flue gas Heat Recovery Steam Generator (HRSG) located in the convection section of the Reformer, which is used to generate Steam for the reforming reaction [13].

Another demonstrated method of integrating gas turbine exhaust with a Steam Methane Reformer is to send the hot Gas turbine Flue gas to the HRSG installed in the convection section of the Reformer. This has been done at a refinery in the USA located on the West Coast. They have a 16 MWe gas turbine from which the flue gases are routed to the convection section of the Steam Methane reformer, This increases the total HRSG steam generation. The excess Steam is then used to generate power using a 20 MWe Steam turbine [9].

Incorporate Adiabatic Pre-Reformer:

An adiabatic pre-Reformer is a reactor in which Steam reforming reactions are partially completed at a lower temperature range (350 oC to 550 oC) than the main Reformer. The pre-Reformer, which contains Nickel-based reforming catalyst, utilizes waste heat in the convection section of the main Reformer to heat up feed gas to the required reaction temperature.

Excess Steam generated in the main Reformer HRSG is also used in the pre-Reformer. In addition to energy savings, a pre-Reformer reduces coking in the main Reformer and also increases the overall production of Hydrogen.

Reputed vendors who license and supply pre-Reformers, include Haldor-Topsoe, Süd-Chemie, and Technip-KTI [9].

Crude and Vacuum Distillation:

Optimize Reflux Ratio:

The reflux ratio of any distillation columns has a great influence on column liquid and vapor flows and consequently the reboiler and condenser duties. It is also important for achieving the required purity. Optimizing the reflux ratios in the Crude and Vacuum Distillation columns can produce significant energy savings. Often, the feed characteristics are different from the original design case, hence new calculations must be done to derive the optimum conditions. Operating data such as Steam and fuel consumption can be correlated and compared with reflux ratio, product purity, to develop a systematic methodology [9].

Leverage Winter Cooling Water Temperature to Optimize Column Pressure:

The temperature of Cooling Water fixes the condensation temperature and pressure of overhead vapors going to condenser. A reduction in Cooling Water temperature allows condensation at lower temperatures and pressures. This allows the distillation column to operate at lower pressure and reduces the boil-up energy required at the reboiler. Typically Cooling Water temperatures are lower in Winter than in Summer especially in cold climates. This energy saving measure does not require any investment, just a seasonal adjustment in the column pressure and temperature.

Use Liquid-Ring Vacuum Pump Along with VDU Steam Ejector.

It has been shown that if the third stage in a three stage Ejector system attached to the VDU is replaced by a Liquid Ring Vacuum Pump, then Steam consumption is reduced. This was demonstrated at Valeros’ refinery located at Houston, Texas, USA [9].

Catalytic Reformer:

Reduce Reformate Stabilizer Temperature by Waste Heat Powered Refrigeration:

Waste heat from the flue gases of a Catalytic Reformer can be used to drive a Vapor absorption refrigeration system. This can generate Chilled Water for use in the condenser of the Reformate stabilizer, increasing recovery of light ends and saving energy [9].

Hydrocracker

Incorporate Power Recovery Turbine

The pressure difference between the Reactor and fractionation stages of a Hydrocracker can be used to recover power via a power turbine. As an example, the Zeeland Refinery in Netherlands has a power recovery turbine of 910 kw instead of a throttle valve. The Hydrocracker capacity is approximately 45000 barrels per day, operating at 160 barg. The power recovered from the turbine is about 7.3 million kwh per annum.

Thermal Cracking/Visbreaking

Thermal Cracking and Visbreaking are very old processes, which have been mostly replaced by Fluidized Catalytic cracking (FCC ) as the main cracking process [14].

Energy conservation and  emission reduction in these units follow the general strategies that are applicable to all Fired Heaters, namely [9]:

  • Improving heat transfer characteristics
  • Enhancing flame luminosity,
  • Installing recuperators or air preheaters
  • Improved controls

Generic Solutions

The following are solutions that can be applied to all units and equipment in a Crude Oil refinery, to improve energy efficiency and consequently mitigate the Carbon footprint:

  • Use of electronic monitoring and advanced process control systems for energy management. Today the developments in sensors, coupled to Internet of Things and Artificial intelligence are creating new capabilities that can achieve optimization that was not possible in the past.
  • Use of digital twins to help accurately model plant processes and simulate various strategic options for optimizing energy efficiency
  • Replacement of damaged insulation to prevent unnecessary heat losses.
  • Use of process control and flare gas recovery systems to avoid unnecessary flaring.

Electrification:

In view of the significant growth of renewable energy, there is a lot of academic interest, as evidenced by published literature, on replacing combustion-based heating equipment such as Furnaces and Boilers by Electric Heaters and Boilers. Some candidate technologies for electrical industrial heating that have been proposed for use in refinery processes are resistance heating and arc-heating [8]. From a decarbonization perspective, the core idea is to use Green Power to achieve these objectives. Unfortunately, except perhaps for Nuclear Power and Hydroelectric Power, it is unlikely that any other low Carbon or Zero Carbon source of electricity will be able to economically deliver the scale of process heating energy that a typical refinery requires. Furthermore, all refineries have freely available Fuel Gas which is vented from various process units and generally meets the bulk of fuel energy requirements.

There is however one area where electrification can be considered immediately for implementation and that is to replace Steam tracing by electrical heat tracing. This would reduce he low grade Steam requirements, as well as wastage of Steam Condensate.

Hydrogen and Hydrogen‐based Fuels:

The concept, which holds a lot of promise for reducing the Carbon footprint of Crude Oil Refineries, is to replace the hydrocarbon gases used in Fired Heaters and Boilers by Hydrogen or by Hydrogen-enriched Fuel Gas. This is technically feasible, though it will require modifications to hardware, due to Hydrogen’s higher flame  speed, additional NOx formation and to address safety concern. Refineries already deal with Hydrogen on a large scale, so the operational experience exists for this transition. Ideally, for decarbonization, the Hydrogen to be supplied would be Green Hydrogen, but this is currently not economically feasible. Grey Hydrogen and Blue Hydrogen can be competitive with Natural Gas under certain scenarios.

Figure 7 shows eight different price scenarios involving Hydrogen addition to the fuel gas supplied to a fired heater, considering different penalties for Carbon Dioxide emissions. The pricing considered for this analysis was 2.50-6.80 USD/kg for green hydro-gen, blue hydrogen at 1.40-2.40 USD/kg and grey hydrogen at 1.00-1.80 USD/kg. This study was done for a single fired heater of 50 MMBtu/h duty [10].

Figure 7

Carbon Capture Utilization and Sequestration (CCUS)

One of the quickest ways to reduce Carbon Dioxide emissions is to capture it at the points of release and either chemically fix it into a useful product or permanently sequester it in subsurface reservoirs. The technology of Carbon Dioxide capture is well established and the utilization of Carbon Dioxide in the manufacture of products like Urea and Methanol is well-known. The Oil and Gas industry has been using captured Carbon Dioxide in Enhanced Oil Recovery for many decades.

 

In the context of Crude Oil refineries, the problem is the scattered nature of emission sources. There are  numerous fired equipment within a refinery complex and it would not be economical to try and capture emissions from each stack. It may be more practical to look at a few large emitters, where there are possibilities of economically capturing Carbon Dioxide at higher pressures and concentrations. Various studies have analysed costs for CO2 capture in Crude Oil refineries and the estimates of Carbon Capture alone have exceeded $100/tonne CO2 [9]. This exceeds the current price of Carbon Credits, where limited Carbon trading markets exist. It is also beyond the maximum tax credit offered currently by any government. Hence there is no commercial driver for refineries to adopt CCUS. This has not stopped demonstration projects from going ahead. In the USA, CCS has been demonstrated for the IGCC plant located at ConocoPhillips’ Refinery at Houston, Texas, a Hydrogen plant at the BP refinery in Denbury, Texas, and a Steam Methane Reformer located at Valero’s Port Arthur refinery [9],

References

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3.0 Enerdata World Energy & Climate Statistics-Yearbook 2023; Refined Oil Products Production | World Refined Oil Statistics | Enerdata.

4.0  Refined Petroleum Products Global Market Report 2022, www.globenewswire.com; Refined Petroleum Products Global Market Report 2022 (globenewswire.com)

5.0 Net Zero by 2050-A Roadmap for the Global Energy Sector, IEA, May 2021; Net Zero by 2050: A Roadmap for the Global Energy Sector – Event – IEA

6.0 Decarbonizing the oil refining industry: A systematic review of sociotechnical systems, technological innovations, and policy options, by Steve Griffiths et al., Energy Research & Social Science 89 (2022) 1025-42;

https://linkinghub.elsevier.com/retrieve/pii/S2214629622000494

7.0 The Greenhouse gas Protocol: A Corporate Accounting and Reporting Standard, March 2004 (Revised Edition). ghg-protocol-revised.pdf (ghgprotocol.org)

8.0 Decarbonization options for the Dutch refinery sector C. Oliveira, K.M. Schure (2020), PBL Netherlands Environmental Assessment Agency and TNO Energy Transition, The Hague.

9.0 Energy Efficiency Improvement and Cost Saving Opportunities for Petroleum Refineries, February 2015, An ENERGY STAR® Guide for Energy and Plant Managers,by Ernst Worrel et al., US EPA  Document Number 430-R-15-002; Energy Efficiency Improvement and Cost Saving Opportunities for Petroleum Refineries | ENERGY STAR

10.0 Carbon dioxide emissions from fired heaters, by Matthew Martin, XRG Technologies, www.digitalrefining.com, June 2021; Carbon dioxide emissions from fired heaters (digitalrefining.com)

11.0  US DOE publication extract:  PETROLEUM REFINING SECTOR (NAICS 324110)

Manufacturing Energy and Carbon Footprint: Petroleum Refining (NAICS 324110)

12.0 Big Oils Separate Paths to decarbonization, The Edge, Wood Mackenzie, 12 March 2021, Big Oil’s Separate Paths To Decarbonisation | Wood Mackenzie

13.0 Use of SCR in a Hydrogen Plant Integrated with a Stationary Gas Turbine, Case Study: The Port Arthur Steam-Methane Reformer, by Robert G Kunz et al.,www.cormetech.com,

Use of SCR in a Hydrogen Plant Integrated with a Stationary Gas Turbine – Case Study: The Port Arthur Steam-Methane Reformer (cormetech.com)

14.0 “Thermal Cracking”, Section 5.3.1, by David Bosworth, Volume II / Refining And Petrochemicals, www.treccani.it; 239-244 INGLESE (treccani.it)

 

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