June 2022

Carbon Capture/CO2 Mitigation

Overview of decarbonization pathways for the oil and gas and petrochemical industries—Part 2

This article is the continuation of an article detailing the seven pathways to decarbonizing the oil and gas and petrochemical industries. Part 1, published in the May issue of Hydrocarbon Processing, covered sustainability and reviewed the following three pathways: green and blue hydrogen (H2); biofuels, renewable fuels and e-fuels; and the circular carbon cycle.

Buehler, J., Petrogenium, Buehler Consulting

This article is the continuation of an article detailing the seven pathways to decarbonizing the oil and gas and petrochemical industries. Part 1, published in the May issue of Hydrocarbon Processing, covered sustainability and reviewed the following three pathways: green and blue hydrogen (H2); biofuels, renewable fuels and e-fuels; and the circular carbon cycle. This article will discuss the first four pathways to decarbonizing the oil and gas and petrochemical industries:

  1. Energy efficiency/stopping methane leakage
  2. New technologies
  3. Electrification
  4. Carbon capture, utilization and storage (CCUS) technology.

Additionally, as detailed in Part 1, renewable power is also key to generating green H2 by electrolysis.

Pathway 1: Energy efficiency/stopping methane leakage

Improving energy efficiency and stopping methane leaks is the cheapest way to reduce CO2e emissions and CO2e intensity. If plants do not burn or leak the fuel to atmosphere, CO2e is not produced and the organization saves on the cost of the fuel (i.e., a win-win situation).

Some energy projects will have a negative cost of CO2 capture, after considering the capital expenditure cost, and the variable and operational costs. Capital energy projects can have less than a 2 yr–3 yr payback, while maintenance projects can achieve payback in just 2 mos–3 mos.

Conduct an energy and greenhouse gas (GHG) study at your plant. Operators should use their internal company specialists, or an outside energy process consultant, to obtain an independent review of the facility for a fresh look toward identifying any possible overlooked energy/GHG reduction opportunities. This study should be structured using process unit-specific checklists, and should identify opportunities, conduct a high-level estimate of potential energy/GHG savings, estimate the cost of projects, and develop a prioritized list of energy/GHG improvement opportunities. Quick-win projects, along with projects that could be accomplished during the next turnaround, should be flagged for early implementation. Savings from quick-payback projects can be used to fund additional energy projects.

An energy and GHG reduction study should focus on the following items: process optimization, equipment performance and utility system optimization.

Process optimization. Process optimization includes the following focal points:

  • Distillation: Optimize pumparounds, avoid over refluxing, utilize advanced process control to meet specifications and minimize product giveaway, and optimize column pressure and feed temperature.
  • Reactions: Optimize H2:oil ratios and yield vs. energy vs. run length, and catalyst selection.
  • Heat recovery: Use pinch analysis to identify opportunities to recover process heat lost to air or cooling water. Use a heat pump to upgrade low-temperature waste heat to a useable heat source—this process can recover 2–3 times the energy required by the heat pump. Use an organic Rankine cycle to convert waste heat to electricity.
  • Stop methane leakage by conducting surveys and fixing leaks. The use of drones can help with inspection work.
  • Use online, real-time monitoring of energy key performance indicators (KPIs) available to operators. Monetize the financial gap between the current operation and the previously demonstrated best performance. Operators should use advanced process control, optimizers and digital twins.
  • Stop continuous flaring, and revise procedures to minimize flaring during startups and shutdowns.

Equipment performance. The following steps can be taken to enhance equipment performance:

  • Improve fired heater efficiency by monitoring stack temperatures and excess air, adjusting burners, cleaning the convection section and repairing air preheaters. A 2% oxygen reduction in stack flue gas equals a 1% efficiency improvement. A 20°C reduction in stack temperature (with reasonable excess air) equates to a 1% efficiency improvement.
  • Monitor vacuum improvements on condensing turbines. An improvement of 1.2 in. Hg (0.6 psia) equates to a 5% improvement. On a large 250,000-lb/hr condensing turbine, a 5% improvement saves more than $850,000/yr in fuel cost (natural gas at $6/MMBtu, boiler efficiency of 85%).
  • Calculate steam turbine isentropic efficiency (steam temperature in vs. temperature out). Consider replacing small, inefficient (30% efficiency) steam turbines with motor drives.
  • Minimize compressor recycling by using suction throttling, inlet guide vanes, variable frequency drive motors, reciprocating compressor variable pocket unloaders and re-rotor compressors. In addition, personnel should check the inlet temperature to the compressor stages and clean interstage heat exchangers.
  • Optimize the operation of parallel compressors to avoid having excess recycle—this can occur in LNG and gas processing plants.

Utility system optimization. The following recommendations can help optimize a plant’s utility system:

  • Utilize a steam header ladder diagram to obtain an overview of steam demand at each pressure level, which utility boilers and turbines are operating, and steam letdowns (high pressure to medium pressure to low pressure). In addition, optimize the use of steam letdown turbines to recover mechanical energy lost through pressure control letdown valves.
  • Eliminate low-pressure steam venting by replacing pump turbine drivers exhausting to the low-pressure steam header with motor drives. If a motor is in critical service, keep a spare turbine on hot standby with its casing and inlet/outlet lines hot.
  • Remember that a steam trap/leak program can pay for itself in less than 6 mos. Operators should also fix air header/air compressor leaks and shut down rental diesel air compressors.
  • Consider installing a cogeneration unit if more steam is needed or if old boilers need to be replaced.

Pathway 2: New technologies

When it is time for a major maintenance turnaround or debottlenecking project, plant owners should consider using the latest technologies. This can range from re-rotoring compressors and upgrading turbines to using higher-capacity trays in columns or higher-efficiency heat transfer equipment. The following is a partial list of technology items to consider:

  • For new grassroots projects, seek new technologies that provide higher yields and reduced energy consumption, instead of replicating an existing, older, less-efficient design.
  • For revamps or new units, use new improved catalysts to increase yield and reduce recycle, thus reducing energy and GHG intensity.
  • For the electrification of compressor drivers on offshore platforms, use offshore wind or onshore green power.
  • Install once-through steam generators (OTSGs) on open-cycle gas turbines to recover gas turbine exhaust heat. The light weight and small footprint of OTSGs allow for retrofitting.
  • Use a divided wall column (which uses one distillation column instead of two columns) for reduced capital and operational expenditures.
  • Install heat pumps on columns separating close boiling temperature components (e.g., ethylene/ethane splitter, propylene/propane splitter).
  • Using a low-emissions cracking furnace designed to shift more fired duty into process heating in the firebox and generate less steam in the convection section, can reduce fuel requirements by 30%. Reduced steam production provides the opportunity to replace condensing steam turbines with efficient motors using renewable power.
  • Use new monoethylene glycol (MEG) technology, such as a proprietary MEG processb that reduces steam usage by 20%.
  • Utilize new propylene oxide (PO) processes, such as a proprietary PO processc that reduces energy usage by 35% and wastewater by 70% vs. existing PO technologies.
  • Use new ethylene processes (e.g., methanol-to-olefins, oxidative coupling methane).
  • Utilize the Allam-Fetvedt cycle for power generation (e.g., an oxy-fired gas turbine using a super-critical CO2 cycle, where CO2 offtake is ready for CO2 pipelines). This creates clean power with no net carbon to atmosphere.

Pathway 3: Electrification with renewable power

In 2020, electrical generation in the U.S. accounted for 32% of CO2 emissions from the burning of fossil fuel. Electrification of process equipment and transportation vehicles using renewable power will be critical to reducing CO2 emissions. Renewable power has no CO2 footprint, and includes solar photovoltaic (PV) systems, as well as concentrated solar, onshore and offshore wind, hydroelectric and geothermal systems. Nuclear power also has no CO2 footprint. One MWh of electricity will power approximately 200 homes on a hot summer day.

According to the Center for Climate and Energy Solutions, approximately 29% of global electricity generation was produced via renewables in 2020. Also in that year, electric power in the U.S. was generated from natural gas (40%), renewables (20%), nuclear (20%), coal (19%) and miscellaneous (1%)—and that year was also the first year in which renewable power constituted a larger market share than coal power (FIG. 4). In 2021, most of the installed utility-scale power generation in the U.S. from renewable sources was wind (46%), followed by hydro (31%), solar (14%) and biomass (7%) (FIG. 5). Future installed power generation will be predominately solar and onshore/offshore wind. Renewable power can be used in an electrolyzer to convert water to green H2 and oxygen. H2 is another key decarbonization pathway, which was discussed in Part 1 of this article.21

FIG. 4. U.S. power generation by source,  2020. Power generation totaled 4.12 T KWh. Source: U.S. EIA.
FIG. 4. U.S. power generation by source, 2020. Power generation totaled 4.12 T KWh. Source: U.S. EIA.
FIG. 5. U.S. utility-scale electricity generation by renewable sources, 2021. Total renewable power generated was 826 B KWh. Source: U.S. EIA.
FIG. 5. U.S. utility-scale electricity generation by renewable sources, 2021. Total renewable power generated was 826 B KWh. Source: U.S. EIA.

Renewable power is not available at a constant supply rate, so power grids must be upgraded to accept fluctuations in renewable power supply. Solar is not available at night, and is reduced on cloudy days. Wind also varies between day and night, and from summer to winter. Hydro varies with the seasons. Over a year, the utilization of installed capacity for solar was 20%–28%, for wind 35%–40% and for hydro 35%–45%.22

Energy storage is required to stabilize the grid and maximize the use of renewable energy. Batteries can store excess renewable power during the day and then release this power into the grid at night. Significant research in battery energy storage systems is ongoing. Challenges include the amount of power that can be stored (which is limited by battery size and weight), and the amount of the dispatch rate of the power back into the grid when there is sudden demand. Lithium-ion batteries are most used in electric vehicles (EVs). Flow batteries are an emerging technology being developed for storing renewable energy. Flow batteries contain a water-based electrolyte liquid that flows between two separate tanks within the battery. When charged, a chemical reaction occurs that enables the energy to be stored and subsequently discharged.

In addition to batteries, other methods for storing excess renewable power when grid demand is reduced include the following:

  • Compressing air in underground storage domes for later use to drive turbines
  • Pumping water to elevated storage, to be used later to drive hydropower turbines
  • Utilizing molten salts for thermal storage
  • Using electrolyzers for green H2 generation.

It will be imperative to upgrade and expand the U.S. electrical grid to supply remotely generated renewable power to urban areas that need power. To minimize line loss (which can be 2%–4%), high-voltage direct current cables can be used. Reduced transmission line loss will decrease capital expenditures and improve efficiency. Smart power grids will provide real-time knowledge of power generation status, along with consumption balance and the impact of this power on the grid. They will also enable operators to instantly optimize available resources to stabilize the grid.

The cost to install solar and wind generation technologies has dramatically reduced. Capital expenditures for utility-scale solar and wind power are competitive with gas-fired combined-cycle power plants. Utility-scale renewable power has a large footprint requiring a lot of land. Solar PV systems need approximately five acres of land to generate 1 MW of electricity (18% efficiency).23

A land-based wind farm would require approximately 60 acres to generate 1 MW of power. Only 3% of the land is occupied by turbines, leaving the rest of the land for farming and grazing. The layout of the wind turbines is critical to avoid secondary air from nearby turbines.24 Land-based wind turbines presently have a capacity of 3 MW, which will increase to 6 MW as technology improves. With more favorable winds, offshore wind turbines will have a higher capacity that can be scaled up to 17 MW by 2030.25,26 An offshore wind turbine can have a rotor diameter of 170 m. Large offshore wind farms are being developed in the North Sea and are planned for installation off the northeast coast of the U.S. (i.e., Massachusetts, New Jersey and New York). One beneficial factor is that offshore oil/gas platform technology can be applied to offshore wind. Integrated oil and gas companies are investing in both solar and wind generation.

Solar PV systems and wind turbines are unable to supply all the green power required, so there will still be a role for nuclear power after 2035. Development work on the next generation of nuclear reactors is ongoing. For example, NuScale is developing a small modular nuclear reactor, which is a light water reactor that does not need pumps for circulating reactor cooling water. TerraPower is developing its Natrium reactor, which is a sodium-fast reactor combined with molten sodium salt heat storage.

Oil companies are moving into the generation and direct sale of renewable electricity to customers. Electrification of transportation vehicles—such as cars, trucks and trains—is a key pathway for reducing Scope 3 emissions resulting from the burning of gasoline and diesel. In the U.S., the Biden administration has set a goal for half of all new vehicles sold in 2030 to be zero-emissions vehicles, including battery electric, plug-in hybrid electric, or fuel cell electric vehicles (FCEVs). By 2035, General Motors plans to stop making internal combustion cars. The installation of electric charging stations along major highways, and at homes and workplaces, will be necessary to achieve these goals—and accomplishing this will constitute a major capital expenditure.

According to the U.S. Environmental Protection Agency (EPA), 1 gal of gasoline contains 33.7 kw of energy and, when burned, generates 8.87 Kg CO2.27 If one person drives 20,000 mi/yr with a 35-mpg car, they will generate 5 tpy of CO2. If a subdivision has 200 EVs using renewable power, CO2 can be reduced by 1,000 tpy. Note: If green power is generated and converted to H2 for use in an H2 FCEV, CO2 is reduced by only 42% vs. using green power directly in a battery EV. A battery EV will average 3.5 mi/kWh. If a person drives 35 mi, 10 kWh of electric power is used. If power costs $0.13/kWh, this equates to $1.30. Driving 35 mi in a gasoline vehicle would use 1 gal of gasoline at a cost of approximately $3/gal. In this example, using an EV would save the driver $1.70.

TABLE 1 shows the CO2 reduction impact of using renewable power vs. three current methods of electrical generation. Using 100 MW of renewable power will reduce CO2 emissions by 248,000 tpy vs. a combined-cycle power plant; 466,000 tpy vs. a natural-gas-fired, open-cycle gas turbine peaking plant; and 911,000 tpy vs. a coal-fired plant. The impact of phasing out coal and open-cycle natural gas plants (which have no gas turbine heat recovery) with renewable power is clear. Blending 20% H2 (vol%) into natural gas as fuel for a combined-cycle plant will reduce CO2 emissions by approximately 7%.

Industrial opportunities for electrification to reduce Scope 1 and Scope 2 CO2e emissions include:

  • Switching condensing turbines to electric drives, considering the impact on steam and fuel balances
  • Replacing old and inefficient steam turbines that cause low-pressure steam venting with electric drives
  • Using electrically driven heat pumps to upgrade unusable low-level heat to a higher usable level
  • Switching medium-temperature fired heaters to electric power, and switching out larger heaters to use green H2 as a fuel
  • Replacing open-cycle gas turbine drives in LNG plants with large electric drives
  • Replacing the gas turbines on offshore platforms with electric motors that use renewable power from offshore wind turbines and land-based renewable power
  • Electrifying ethylene plants, using motor-driven cracked gas and refrigeration compressors.

Ethylene crackers are a large source of CO2 emissions. Replacing the large thermally inefficient condensing steam turbines with electric drives reduces the need for steam generation. The cracker furnaces are the primary source of CO2 emissions in an ethylene plant. Adding air preheat and redesigning the furnace to recover more of the heat in cracking coils and to produce less steam in the convection section can reduce furnace fuel usage by 30%.28 Work is ongoing to replace steam cracker furnaces with electrically heated furnaces. Earlier this year, pilot-scale testing began of a roto dynamic reactor that could replace the cracking furnace. The roto dynamic reactor uses electrically powered rotor blades that transfer mechanical energy into thermal energy in just nanoseconds, thus reducing the reactor residence time—this can, in turn, increase ethylene yield.29

Renewable electricity can also be used to produce green H2, which can be used to hydrogenate biofeedstocks to produce biofuels. Green H2 can also be used to make synthetic fuels or e-fuels with a low carbon footprint through the e-chemistry of Power-2-X (P2X) conversion technology. P2X technology reacts green H2 with CO2 to produce gaseous fuels [H2, methane (CH4)] or liquid fuels [methanol, synthetic fuels, sustainable aviation fuel (SAF)] and chemicals [ammonia (NH3)]. The reaction of green H2 with captured CO2 to produce syngas for use in Fischer-Tropsch chemistry to make e-fuels was discussed in Part 1 of this article, which was published in the May issue of Hydrocarbon Processing.

Pathway 4: CCUS technology

Another pathway to decarbonization is through CCUS. This technology plays a key role in decarbonizing H2 produced by steam methane reforming (SMR) to produce blue H2. Carbon capture is also key to capturing CO2 in processes (such as natural gas, ethylene oxide, ethanol and H2 production) that produce streams of high CO2 concentration. Additionally, CCUS is instrumental in reducing CO2 emissions in the hard-to-decarbonize steel and concrete industries.

The oil and gas industry is a leader in developing and deploying CCUS technology. In 2020, global anthropogenic (human-made) CO2 emissions totaled 34 gigatons, with only 40 megatons (0.12%) being captured.30 Oil and gas operations captured 70% of the CO2 emitted. The oil and gas industry has the capability to implement CCUS on a large scale. Depending on the success of implementing the other decarbonization pathways, the International Energy Agency (IEA) estimates that CCUS may be needed to capture as much as 7.6 gigatons/yr of CO2 to meet 2050 global net-zero goals.

In the U.S., the 45Q tax credit provides an incentive to install CCUS at $35/t for CO2 used for enhanced oil recovery (EOR) and at $50/t for CO2 that goes into storage. These incentives are not large enough for capturing CO2 in diluted CO2 streams. Depending on oil prices, drillers may pay $20/t–$30/t for CO2 used in EOR. CO2 capture cost ranges from $30/t–$40/t for streams with high CO2 concentrations and can cost $60/t–$90/t for CO2 captured from fired heater flue gas, where CO2 content is only 8%–10%.

The cost to capture CO2 in natural-gas-fired power generation ranges from $60/t–$90/t. Adding carbon capture and storage (CCS) to a combined-cycle power plant derates net power output by 12%–15%. Derating is the result of the heat required to regenerate CO2 absorber solvent (2 Gj/t CO2) and power for CO2 compression (200 kWh electricity/t CO2). Note that 2 Gj/t CO2 is roughly equivalent to 1 t steam/1 t CO2.31,d There are three primary methods of CO2 capture from combustion:

  • Post-combustion: This method includes burning fuel (CH4 is used in examples) and capturing CO2 in a fired heater stack. Flue gas contains 8%–9% CO2, 70% nitrogen, 18% water and 2%–3% oxygen at atmospheric pressure. Note: A gas turbine’s exhaust without duct burner firing contains only 3%–5% CO2. Post-combustion capture uses chemical solvents, such as hindered amines. Net CO2 removed from flue gas capture is about 90% of the actual CO2 captured, since absorber solvent regeneration and CO2 compression have a CO2 footprint that reduces the actual CO2 removed from the atmosphere.
  • Oxy-firing system: This system involves burning CH4 fuel with oxygen (supplied from an air separation unit) in a fired heater. Flue gas contains CO2 and water but no nitrogen. No CO2 capture unit is required. Compressing flue gas removes water to produce a pure CO2 stream. Personnel must seal leaks in the convection section to keep it from sucking in air, which will add nitrogen in the flue gas, leading to the captured CO2 being off specifications.
  • Pre-combustion: If H2 is burned in a fired heater, the flue gas contains no CO2; therefore, no CO2 capture is required for the heater. The fuel is sent to a reformer, followed by a water-gas shift reaction to convert the fuel into H2 and CO2. The CO2 is then captured at the reformer outlet (higher % CO2 and higher pressure makes CO2 easier to capture than from flue gas) by using a physical solvent in an absorber (see “A” in FIG. 6). The process, with the CO2 removed, proceeds from the reformer’s outlet to a pressure swing adsorption (PSA) unit that recovers pure H2. The PSA tail gas goes to the fuel system. Reforming is an endothermic reaction requiring heat. In an SMR unit, 60% of CO2 is generated by the reformer/water-shift reaction, and 40% is from the reformer’s firebox, which generates the heat required for the reaction. The CO2 absorber on the reformer’s outlet will recover approximately 60% of the produced CO2. To recover the remaining amount, a second CO2 absorber (marked “B” in FIG. 6) on the firebox flue gas stream would need to be added to obtain a 90% CO2 capture. An alternative is to fuel the firebox with H2—which produces no CO2 but reduces H2 production. Installing a single, large CO2 absorber on the firebox flue gas (B) may be more cost effective. An alternative to the reformer is to use an auto thermal reformer (ATR) to produce H2. An ATR oxidizes (burns) part of the CH4 feed in the reactor to generate the required reaction heat, thereby eliminating the need for a firebox. The ATR uses oxygen from an ASU as an oxidant, so there is no nitrogen in the outlet of the reactor. The remainder of the ATR outlet is H2 and CO2, which can be separated like a basic reformer, using a CO2 absorber or a PSA unit. Using partial oxidation of methane with carbon capture is another route to produce H2 for fueling a fired heater. FIG. 6 shows a high-level schematic of the three methods to capture CO2 from combustion.
FIG. 6. Three methods to capture CO<sub>2</sub> from combustion.
FIG. 6. Three methods to capture CO2 from combustion.

CO2 is captured and removed from process streams by either chemical absorption or physical separation. Chemical absorption involves a chemical reaction between the amine solvent and CO2, and requires the regeneration of the solvent—1 t steam/1 t CO2, which is equivalent to 2 Gj/t CO2. Physical separation can include either adsorption, absorption, cryogenic separation, or dehydration and compression. Physical adsorption uses solid surfaces like zeolites, metallic oxides, alumina or activated carbon. After the CO2 is captured by the physical adsorbent, the CO2 is then released by cycling temperature in temperature swing adsorption (TSA), pressure in a PSA unit, or vacuum in vacuum swing adsorption. Physical absorption utilizes liquid solvents that are regenerated by flashing the solvent to a lower pressure in the regenerator, which does not require steam, thus resulting in less energy being used.32

Significant research is being conducted to reduce CO2 capture costs in CCUS. The U.S. Department of Energy’s Carbon Negative Shot initiative seeks to reduce the cost of CO2 removed from the atmosphere to less than $100/t by 2030 via either direct air capture or by helping forests, agriculture and energy crops capture and store CO2. Additional ongoing CCUS research includes:

  • Absorption with chemical solvents (hindered amines) to lower costs by reducing the energy required in the solvent regenerator for aqueous solvent regeneration
  • Absorption with physical solvents, which can be regenerated with vapor flashing and without requiring steam (resulting in lower energy usage)
  • Utilization of other non-aqueous or water lean solvents to reduce the energy required for regeneration
  • Adsorption onto solids, hydrated solid sorbents and metals with thermal or vacuum swing adsorption (solid adsorbents can withstand higher gas temperatures than solvents and can avoid solvent degradation)
  • Direct air capture, as the low CO2 concentration in air at 420 ppm (0.042%) vs. flue gas at 9% is a challenge (direct air capture requires processing 214 times larger volume of air to remove the same amount of CO2 as flue gas capture, requiring large air contactors, like cooling tower units with air flowing up through packing where it contacts a solvent or solid adsorbent)
  • Cryogenic separation of CO2 from H2 on the outlet of a steam methane reformer
  • A process for growing algae to absorb CO2 from air (photosynthesis), and then converting algae oil to biofuels.

Large-scale CCUS installations using chemical solvent absorber technology are proven to be effective with 1-MMtpy to 3-MMtpy CO2 capture trains [e.g., Boundary Dam in Saskatchewan, Canada; Petra Nova in Houston, Texas (U.S.); QUEST in Alberta, Canada on a H2 steam methane reformer (1.1 MMtpy); and LaBarge, Wyoming (U.S.) in a sour gas treating plant (6 MMtpy). CO2 must be compressed to 100 bar for pipeline and underground storage. To prevent carbonic acid corrosion in CO2 pipelines, there are tight specifications on oxygen at 50 ppm and on water at 20 ppm. Because of the high capital expenditures of CO2 capture units, pipelines and CO2 storage areas, a “hubs and clusters” concept is necessary to obtain sufficient CO2 volumes for an economically efficient project.

There will be a need for regional CO2 pipelines to collect CO2 and then to either provide it as a feedstock or deliver it to storage. This activity will see competitor companies working together to jointly reduce their CO2 emissions. Several CCS pipeline projects have been announced in the UK and near Rotterdam/North Sea. In the U.S., discussions are ongoing for a CCS network to be developed in the Houston Ship Channel to capture up to 100 MMtpy of CO2 by 2040 and to store it offshore in the Gulf of Mexico. Additionally, Talos Energy has announced plans to develop CO2 pipelines and storage along the Mississippi River corridor in Louisiana and on the Texas Gulf Coast.

CO2 storage can include underground saline reservoirs, depleted oil and gas reservoirs, porous rock, subsea or basalt. When CO2 is stored, the operator must measure, monitor and verify the CO2. No CO2 leakage can occur to atmosphere or into adjacent underground structures. For any new grassroots facility, a study should be done to identify potential nearby CO2 storage locations.

Some uses for CO2 include EOR (which uses 0.3 t CO2/bbl–0.6 t CO2/bbl), along with processes for freeze drying of food, carbonization of beverages, production of urea to make fertilizer and enhanced photosynthesis in greenhouses. Growing biofuel feedstocks (energy crops) are an effective way to remove CO2 from the atmosphere and to produce low-carbon biofuels.

Captured CO2 can be reacted with green H2 made from renewable power to produce synthetic fuels with a low CO2 footprint (i.e., P2X or CO2 e-chemistry).

Nature captures CO2 from the atmosphere by photosynthesis, which converts CO2 and water to oxygen and glycose by electron transfer. Research is ongoing to develop electrochemical cells that will replicate and accelerate this electron transfer by using electrolysis to produce synthetic fuels and chemicals. In an electrochemical cell, a catalyst embedded in the cathode will reduce CO2 to carbon monoxide or other products on one side of the cell. On the other side, the anode oxidizes water from the electrolyte to produce oxygen. This is a promising path for using renewable power and captured CO2 to produce chemicals and fuels.32


The oil and gas industry is rebranding itself as an energy provider, and is transitioning to selling low-carbon-intensity energy products that include renewable wind and solar power, green and blue H2, low-carbon LNG, biofuels, renewable diesel, e-fuels, e-gasoline and SAF.

Improving energy efficiency and stopping methane leakage are the cheapest ways to reduce CO2 emissions. For new facilities or major plant expansions, project developers should consider incorporating new technologies that have better energy efficiency and lower carbon intensity. For major turnarounds requiring catalyst changeouts, operators should consider newer formulated catalysts for higher yields and lower energy intensity.

The pathways to reduce Scope 1 and Scope 2 CO2 emissions include:

  1. Energy efficiency/stopping methane leakage: Improving efficiency in existing and new facilities by maintaining energy recovery equipment, stopping or minimizing routine flaring (such as minimizing flaring on startups and shutdowns), and identifying and stopping methane leakage
  2. New technologies: Using new process technologies and catalysts to improve yields and reduce energy intensity
  3. Electrification: Electrifying process equipment; using renewable electric power (e.g., wind, solar, hydro and nuclear power); and investing in battery storage, and in using and selling renewable power
  4. CCUS: Incorporating cost-effective CCUS technology, joining regional CCUS networks and using captured CO2 in e-chemistry to produce e-fuels
  5. Green and blue H2: Producing, utilizing and selling low-carbon H2, as well as using H2 as an energy carrier and to produce e-fuels.

Pathways to reduce Scope 3 emissions for the oil and gas industry include producing and selling energy products with low-carbon intensities, such as:

  1. Biofuels, renewable fuels and e-fuels: This includes producing renewable diesel, SAF, synthetic fuels, e-gasoline, low-carbon LNG and renewable electricity, as well as green and blue H2.

The seventh pathway will help reduce Scope 3 emissions from petrochemicals production:

  1. Circular carbon pathway: This pathway includes recycling plastics by either mechanical reprocessing or chemical means (pyrolysis, gasification); using renewable feedstocks like bio-naphtha, hydrogenated vegetable gasoil (diesel) and plastic pyrolysis oil to produce the base chemicals ethylene and propylene; and producing synthetic chemicals, such as ethanol and methanol, by using renewable H2 and captured CO2.

The good news is that the oil and gas and petrochemical industries have the technology and assets needed for offshore wind turbines, blue/green H2 production, and CO2 capture and storage. They also have the refinery units and technology to produce renewable fuels. These industries are prepared for the journey to complete this crucial energy transition to a lower-carbon world. HP


Shell’s OMEGA process

BASF and Dow Chemical Co.’s hydrogen peroxide to PO (HPPO) technology

According to Buehler Consulting, a 15% reduction is based on 2 Gj/t CO2 to regenerate solvent, and on 200 kWh electricity/t CO2 for compression


21  U.S. Energy Information Administration (EIA), “What is U.S. electricity generation by energy source?” online: https://www.eia.gov/tools/faqs/faq.php?id=427&t=3

22  Statista, “Capacity factors for selected energy sources in the United States in 2020,” online: https://www.statista.com/statistics/183680/us-average-capacity-factors-by-selected-energy-source-since-1998/

23  Yacoubou, J., “Solar farm land requirements: Top 7 tips for farmers, ranchers, and landowners,” GreenCoast, December 5, 2021, online: https://greencoast.org/solar-farm-land-requirements/

24  Gaughan, R., “How much land is needed for wind turbines?” Sciencing, May 10, 2018, online: https://sciencing.com/much-land-needed-wind-turbines-12304634.html

25  Patel, S., “Changing winds: Emerging wind turbine technologies,” Power, June 1, 2021.

26  Proctor, D., “Winds of change revitalize West Texas,” Power, September 1, 2021.

27  U.S. EPA, “Code of Federal Regulations: Part 98,” June 13, 2017.

28  Boekel, T. V. and P. Oud, “Low-emission ethylene furnace,” AIChE Spring Meeting and Global Congress on Process Safety, April 19, 2021.

29  Coolbrook, “Coolbrook makes petrochemical industry more sustainable with innovative pilot,” July 28, 2021, online: https://coolbrook.com/news/2021/coolbrook-makes-dutch-petrochemical-industry-more-sustainable-with-innovative-pilot/

30  IEA, “Net zero by 2050: A roadmap for the global energy sector,” May 2021, online: https://iea.blob.core.windows.net/assets/deebef5d-0c34-4539-9d0c-10b13d840027/NetZeroby2050-ARoadmapfortheGlobalEnergySector_CORR.pdf

31  IEA, “Energy Technology Perspectives 2020: Special report on carbon capture utilization and storage,” October 19, 2020.

32  Boerner, L., “How can we convert CO2 from threat to asset?” Chemical and Engineering News, October 11, 2020.

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