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The oil companies share a lot of similarities.

ExxonMobil (XOM -0.89%) is a global oil and gas industry behemoth. It’s a leading hydrocarbon producer. It also boasts a globally integrated business, enabling it to maximize the value of the hydrocarbons it produces. Meanwhile, Exxon has an emerging low-carbon business.

Occidental Petroleum (OXY -0.59%) shares many of those same features, albeit on a smaller scale. However, the company has grand growth ambitions – it beat out oil giant Chevron (CVX -0.62%) to acquire Anadarko Petroleum in 2019. Here’s a look at whether it could eventually become a mega-cap oil stock like Exxon.

How Occidental stacks up against ExxonMobil

ExxonMobil is currently the largest U.S. oil company by market cap:

As that chart shows, Exxon is over seven times the size of Occidental Petroleum, which currently ranks as the 6th largest U.S. energy company.

Exxon has a much larger global production base. The company produced an average of 3.8 million barrels of oil equivalent per day (BOE/d) during the first quarter. For comparison, Occidental Petroleum produced 1.2 million BOE/d during the period. 

However, oil and gas production is only part of Exxon’s story. The company’s integrated operations also feature a large-scale downstream business of refining, chemicals, and marketing assets. Exxon’s downstream business is a big value driver. The company generated over $4 billion in energy products earnings during the first quarter to go along with nearly $6.5 billion of upstream production earnings. 

Occidental Petroleum isn’t nearly as integrated as Exxon. It has some midstream assets, including owning a stake in Western Midstream (WES -0.50%). It also has a chemicals business, OxyChem. However, they’re not big earnings drivers for the company. OxyChem produced $472 million of income in the first quarter, while the company’s midstream and marketing business only generated $2 million of income.

Add in its oil and gas earnings, and Occidental Petroleum’s total earnings were only $1.1 billion in the first quarter. Exxon’s profits were almost 10 times higher at $11.4 billion. 

What can Occidental Petroleum do to bridge the gap?

The quickest path for Occidental to join Exxon as a mega-cap oil stock is to continue making needle-moving acquisitions like Anadarko Petroleum. It could pursue a merger of equals transaction with a rival like Pioneer Natural Resources (PXD -2.39%), which would boost its market cap up into the triple digits. However, it would have competition since Exxon has already set its sights on acquiring Pioneer to beef up its presence in the Permian Basin.

If it wanted to become more like Exxon, the company could seek to build a more integrated platform by acquiring a refiner like Phillips 66 or Marathon Petroleum. Both refiners used to be part of an integrated oil company (ConocoPhillips and Marathon Oil , respectively).

However, those formerly integrated oil companies spun off their refining and midstream assets over a decade ago so that each company had the freedom to independently pursue growth opportunities.

While Occidental may eventually pursue another needle-moving acquisition, its main focus is organically growing its oil and gas production and carbon capture and storage (CCS) platform. CCS could be a major growth driver. Occidental estimates CCS could eventually become a $3 trillion-$5 trillion global market. The company believes that one day it could generate as much earnings from CCS as it currently makes from producing oil and gas. 

The company is investing heavily to build out its CCS capabilities. Occidental is spending more than $1 billion to build the first of what it hopes will be many direct air capture plants to pull carbon dioxide out of the air. It’s also working to develop sequestration hubs. 

However, Occidental isn’t alone in seeking to capture the CCS opportunity. Exxon is also working to capitalize on what it believes will be a multibillion-dollar revenue opportunity for the company. Exxon thinks CCS could eventually supply it with steadier revenue to help offset some of the volatility of its oil and gas business.

Occidental Petroleum has a long way to grow

Occidental has shown it wants to become a big oil company by wrestling Anadarko away from Chevron a few years ago.

However, to become the next Exxon, it would either need to become more integrated by acquiring a refiner or show it can go toe-to-toe with Exxon in capturing the emerging CCS opportunity. While Occidental could eventually boast an Exxon-sized market cap, it has a long way to grow to catch up to that oil behemoth.

The Motley Fool by Matthew DiLallo, May 23, 2023

The Hong Kong liquefied natural gas or LNG project, whose trial operations started on Sunday, is expected to significantly optimize the energy structure of the Guangdong-Hong Kong-Macao Greater Bay Area while ensuring domestic energy security, industry experts said on Monday.

The LNG project, which includes a dual-berth offshore LNG receiving terminal, an onshore LNG receiving terminal and two submarine pipelines, is the largest offshore energy infrastructure construction project in recent years in Hong Kong, according to its operator China Offshore Oil Engineering Co Ltd or COOEC.

The core of the LNG project, the receiving terminal is the world’s first offshore all-steel double-berth structure, said COOEC, a listed company controlled by China National Offshore Oil Corp or CNOOC.

It is capable of accommodating two of the world’s largest FSRUs — floating storage and regasification units — or LNG transport ships for berthing and operation at the same time, COOEC said.

According to Liu Zhigang, deputy director of the COOEC Hong Kong Offshore LNG Terminal EPC project, the designed service life of the terminal is 50 years, more than twice that of conventional offshore LNG receiving terminals.

Lin Boqiang, head of the China Institute for Studies in Energy Policy at Xiamen University, said CNOOC has, in recent years, formed a complete LNG engineering construction capability, ranging from liquefaction to regasification onshore and offshore. Its assets and capabilities now rank among the world’s top modular, super large LNG storage tanks and LNG receiving terminal construction expertise.

“The company has been strengthening the key core technology research and development of clean energy engineering over the years, which has in turn promoted China’s energy structure transformation and the realization of the dual-carbon goals,” Lin said.

The operation of the Hong Kong LNG project will provide stable and clean power generation fuel to Hong Kong via submarine pipelines and substantially increase the proportion of clean energy generation in the Hong Kong Special Administrative Region, he said.

Oil and gas production of CNOOC reached a record high of 120 million metric tons of oil equivalent last year, with domestic crude oil and natural gas production up by 3.39 million tons and 2.7 billion cubic meters year-on-year, respectively. The increase in crude oil production accounted for over 60 percent of the country’s total increase, it said.

CNOOC imported 26.69 million tons of LNG last year. Overseas oil and gas production rose to 46.24 million tons of oil equivalent so far in 2023 as the company continuously strengthens international energy cooperation while optimizing asset layout in countries and regions participating in the Belt and Road Initiative, it said.

CHINADAILY by Zheng Xin, May 23, 2023

After years of delays and massive cost overruns, Nigeria is set to finally see a 650,000 barrels per day (bpd) oil refinery commissioned later this month.

The Dangote Refinery, built by the group of the same name of Africa’s richest person, Aliko Dangote, is expected to be inaugurated by Nigeria’s outgoing President Muhammadu Buhari on May 22, Nigerian outlet THISDAY reported on Sunday, quoting a source at the refinery.  

Construction at the refinery has been completed, and tests are being carried out, the source told THISDAY.

The Dangote Group has previously said that it aims to commission the refinery before President Buhari leaves office at the end of May after serving the maximum of two consecutive terms per the constitution.

It looks like this time the timeline will be kept, as a presidential spokesperson told Reuters on Sunday that the refinery near Lagos is set for inauguration on May 22.

The refinery has cost around $20 billion, up from initial cost estimates of between $12 billion and $14 billion.

The huge refinery will be able to meet domestic fuel demand and even have some part of the fuel left for exports.

The Dangote refinery expects to export diesel to customers in Europe, as well as gasoline to Latin American and African markets.

Nigeria, OPEC’s top crude oil producer in Africa, has had to rely on fuel imports due to a lack of enough capacity at its refineries, some of which had to undergo refurbishment in recent years.

At the end of last year, the then oil minister Timipre Sylva said that the country expects to stop importing petroleum products starting in the third quarter of 2023.

A refurbished refinery in Port Harcourt in the Niger Delta is expected to be producing 60,000 bpd of refined crude oil per day, and the new Dangote refinery is expected to come online in 2023, Sylva said at the end of November.

OilPrice.com by Tsvetana Paraskova, May 12, 2023

Marathon Petroleum dedicated the bulk of its first-quarter 2023 capex to advancing its balanced approach of optimizing traditional crude oil refining operations while furthering low-carbon projects.

Marathon Petroleum Corp. (MPC) dedicated the bulk of its first-quarter 2023 capex to advancing its balanced approach of optimizing traditional crude oil refining operations while furthering projects in preparation for a low-carbon future in line with the global energy transition.

Of the total $430 million in capital expenditures and investments during the first quarter, MPC dedicated $421 million—up $177 million compared with first-quarter 2022—to ongoing traditional and renewables refining projects, the operator said on May 2.

In its quarterly earnings report to investors, MPC confirmed that it has completed its South Texas Asset Repositioning (STAR) program at the 593,000-b/d Galveston Bay refinery in Texas City, Tex., which included works to further integrate the operator’s former Texas City refinery into the adjacent Galveston Bay refinery to improve the site’s efficiency and reliability by increasing residual oil processing capabilities, upgrading the crude unit, and integrating logistics (OGJ Online, Aug. 2, 2022).

Officially started up in April and scheduled to ramp up throughout second-quarter 2023, the Galveston Bay STAR project, upon reaching full operation, aims to add 40,000 b/d and 17,000 b/d of incremental crude and resid processing capacity, respectively, at the site, MPC said.

Alongside unidentified projects designed to help reduce future operating costs and improve the competitive position across the operator’s US refining assets, MPC said other first-quarter capex covered expenses related to an emissions-reduction program are under way at the 363,000-b/d Los Angeles refinery, as well as furthering second-phase works for the conversion of the former Martinez, Calif., conventional crude refinery into a renewable fuels production site (OGJ Online, Feb. 6, 2023).

Part of its Martinez Renewables LLC 50-50 joint venture with Neste Corp., MPC confirmed Phase 1 of the Martinez conversion project reached its full production capacity for renewable diesel of 260 million gal/year during the first quarter, as planned.

With construction activities currently on schedule for Phase 2 and pretreatment capabilities for renewable feedstocks at the site due online during second-half 2023, MPC said it expects Martinez Renewables to reach full nameplate production capacity of 730 million gal/year by yearend.

Oil&GasJournal by Robert Brelsford, May 12, 2023

The government says that proposed onshore terminals could one day be converted to produce clean hydrogen. But that technology is in the embryonic stage, stirring worry that the terminals will simply prolong the use of fossil fuels.

In the steel-gray North Sea waters of the port of Wilhelmshaven floats an impressively long tanker, the German government’s answer to the nation’s energy crisis.

The Höegh Esperanza, sprawling the length of three football fields, is what’s known as a Floating Storage and Regasification Unit. It’s a modified tanker ship that sails to different countries where it converts liquefied natural gas, or LNG, from transport ships back into a gaseous state. This gas can then be injected into natural gas pipelines. 

In an effort to get by without Russian pipeline gas, cut off after Russia’s invasion of Ukraine, Germany is turning to LNG imported from countries like the United States. To some climate advocates, however, this amounts to investing in fossil fuel infrastructure when Germany is trying to move toward a carbon-free future. 

The worry is that this could further bind Germany to fossil fuels and the greenhouse gas emissions that are accelerating climate change. Europe’s largest energy consumer, Germany has made a commitment to becoming greenhouse gas neutral by 2045.

German leaders have promised that the new infrastructure will eventually be used to import hydrogen fuel, which does not emit greenhouse gases, as part of a transition to a decarbonized energy sector. But some clean energy experts question the feasibility of such a conversion.

Germany plans to rent at least six floating terminals. The Esperanza, the first, arrived in Wilhelmshaven in December. The German government has leased it for 10 years, according to a statement from Höegh LNG, the company that owns the ship.

“Today we are making a very important step towards energy security in Germany,” Robert Habeck, the German vice chancellor and minister for economic affairs and climate action, declared when the Esperanza arrived. “This shows how much Germany can get done within only a few months when it is necessary.”

The leased terminals can sail elsewhere once they are no longer needed. The crux of concern is that Germany also plans to build several permanent onshore LNG terminals.

These could become prematurely obsolete if Germany stops using them in favor of renewable energy, said Rainer Quitzow, a political scientist at the Research Institute for Sustainability in Potsdam. 

The alternative, he said, is that “the powers that be put so much pressure on the government that rather than creating a stranded asset and devaluing that asset for the owners, they just continue using it [to process LNG] anyway,” Quitzow said.

If that happens, he warned, it could cause Germany to remain dependent on fossil fuel longer than planned, in a so-called “lock in” effect.

Katharina Grave, a spokeswoman for Germany’s Ministry for Economic Affairs and Climate Action, said the permanent terminals are necessary because the government believes the floating terminals alone will not make up for the cutoff of Russian gas.

“There are not endless amounts of them, and they are quite expensive to hire,” Grave said. “So for the future, those FSRU ships will be step by step replaced by LNG ships that feed into fixed terminals, and then these terminals will also be used to get hydrogen into the system.”

Hydrogen fuel can be used to store and transport energy. There are multiple ways of producing it, including by partially combusting fossil fuels. But under Germany’s National Hydrogen Strategy, adopted in 2020, the government regards only “green hydrogen,” generated with renewable energy, to be sustainable in the long term. 

Green hydrogen is created by using renewably generated electricity to split water molecules in a process known as electrolysis. This hydrogen can then be combined with oxygen in a fuel cell to generate electricity, which produces only harmless water vapor as a byproduct. 

Germany ultimately plans to use hydrogen to power industries that are otherwise difficult to decarbonize, including shipping, aviation and emission-intensive industrial processes. 

“Hydrogen is such a precious thing,” said Franziska Müller, a professor of political science at the University of Hamburg who studies the social and environmental risks of hydrogen production. “In Germany, it’s sometimes called the champagne of the energy transition because it’s so difficult to produce, and so expensive also.” 

The authors of the National Hydrogen Strategy note that Germany will likely have to import much of the hydrogen it will need from abroad.

Grave said the permanent LNG terminals would be constructed to be “hydrogen ready,” but when asked what percentage of the facilities’ components would need to be adjusted, she said she was unsure. She did not give a target date for the switch to hydrogen, saying that Germany was still working on that part of its strategy.

Simon den Haak, a spokesman for the Dutch energy company Gasunie, said that LNG terminals can easily be converted if they are built with hydrogen in mind. Gasunie is a partial owner of a planned onshore LNG terminal in Brunsbüttel, Germany. “Some valves may need to be replaced, but the basic construction of the terminal can be easily adapted,” den Haak said in an email.

But a study published last year by the Fraunhofer Institute for Systems and Innovation Research in Karlsruhe highlights several major barriers to converting LNG terminals to hydrogen terminals. 

Liquefied hydrogen is extremely difficult to transport. It must be kept at minus 253 degrees Celsius to remain a liquid, and to date only one prototype liquid hydrogen import terminal has been built, in Kobe, Japan.

The study found that many parts of an LNG terminal would have to be replaced for it to be capable of handling liquid hydrogen. Even if its storage tank, the most expensive part of the terminal, were built from hydrogen-compatible steel, the study found, components comprising only 50 percent of the initial investment in an LNG terminal could be reused in the conversion.

Another option is to import synthetic natural gas, or SNG, which is made by combining hydrogen with carbon dioxide. Because SNG is chemically identical to conventional natural gas, LNG terminals can be used to import it without any significant alterations.

The synthetic fuel can then be used the same way natural gas is or turned back into hydrogen. 

But to be carbon-neutral, the carbon dioxide used to produce the SNG must come from a non-fossil fuel source like organic waste or be captured from the air. The Fraunhofer study says that carbon-neutral SNG is currently “entirely hypothetical” because of the high costs associated with those processes.

A third option is to import a hydrogen derivative like ammonia, which is produced by adding nitrogen to hydrogen.

The ammonia can then be turned back into hydrogen, used to make fertilizer or burned as its own carbon-free source of power.

Inside Climate News by Christina van Waasbergen, May 12, 2023

The oil industry is currently experiencing a somber atmosphere due to falling refining margins, which are a significant indicator of profitability for refiners.

This is in contrast to the record boom seen last year when strong refining margins and high oil prices led to reports of refiners preparing massive performance bonuses to share profits with employees, prompting calls for a windfall tax on refiners.

In 2022, the four major refiners — SK Innovation Co., GS Caltex Corp., HD Hyundai Oilbank Co. and S-Oil Corp. — posted trillions of won in operating profits, with cumulative operating profits of between 2-4 trillion won (US$1.50-3.00 billion) by the third quarter.

However, the refining industry’s first-quarter earnings are expected to not only sharply decline from the same period last year, but also worsen in second quarter.

Refining margins have fallen to around $2 for the first time in about six months, standing at US$2.50 as of March 19, the lowest level in a year.

Last year, the refining margins soared to an average of $29.50 in the fourth week of June, following the onset of Russian aggression in Ukraine.

Refining margins are equal to the price of the final petroleum product minus the cost of raw materials, including crude oil, with between $4-5 generally considered as the threshold for profit.

However, at the current $2 refining margin, running a plant means losing money.

The industry is concerned as international oil prices and refining margins are moving in opposite directions.

The recent announcement of the Organization of the Petroleum Exporting Countries (OPEC) Plus’ production cuts resulted in an increase in oil prices, while refining margins decrease.

Industry insiders have attributed the decline in refining margins to the prolonged global economic downturn, which has decreased the demand for petroleum products.

The refining industry needs increased demand to raise refining margins, but with only supply decreasing, demand is not rising.

The current situation of production cuts and rising oil prices amid a recession is not favorable for the refining industry and could result in negative outcomes for both refiners and chemical companies, as they must pay for crude oil but earn nothing.

Higher oil prices can be a “boomerang” effect that further depresses demand.

It is unclear how long weaker refining margins will last in the face of a prolonged recession.

The move to replenish the U.S. Strategic Petroleum Reserve and the arrival of the summer vacation “driving season” could be positive factors for the recovery of oil demand.

By The Korea Bizwire, May 4, 2023

The technology and knowledge base of the E&P sector is poised to play a major role in the newer, lower-carbon energy economy.

The term “new energy economy” broadly refers to the transition to a low-carbon future for sustaining human development while reducing CO₂ emissions.

Such a shift is considered to be the third energy transition of the modern era, after the shift from biomass to coal as the primary source of energy in the early 1900s, followed by oil overtaking coal’s dominant position in the 1960s–1970s.

This trend towards decarbonization (i.e., diversification from carbon-intensive fossil fuels to sustainable greener energy feedstocks and carriers) is motivated by the understanding that emissions need to be reduced to moderate the potential impacts of global temperature rise on future climatic changes.

Strategies common to proposed decarbonization pathways include

• Improving energy efficiency (i.e., slower increase in energy demand compared to GDP/population increase).
• Increasing energy supply from renewable sources (i.e., wind, solar, geothermal, nuclear) coupled with hydrogen underground storage (HUS) as a way of storing surplus electrical energy.
• Switching to low-carbon energy carriers (i.e., hydrogen) for end‑use applications in transportation, buildings, and industry.
• Removing carbon emissions, via carbon capture, utilization, and storage (CCUS), from fossil-fuel-fired power plants and hard-to-abate industrial sources.

The key takeaway for readers is how the two subsurface-oriented decarbonization strategies—CCUS and HUS—are relevant for application/adaptation of expertise from the exploration and production (E&P) sector of the oil and gas industry.

Their rise will be built upon decades of experience with CO₂-EOR, gas injection, produced-water disposal, and underground natural gas storage (NGS).

Carbon Capture, Utilization and Storage (CCUS)

As shown in Fig. 1, CCUS involves capturing CO₂ from a fossil-fuel-fired power plant or industrial facility and processing it to a practically pure form, transporting it to a nearby geologic storage site using pipelines, and injecting it into saline aquifers for long-term sequestration or depleted oil/gas fields for enhanced oil recovery (EOR) and associated storage.

Research and field demonstration projects over the past few decades have demonstrated that CCUS is a viable technology for curtailing atmospheric CO₂ emissions buildup.

Some of the key elements of CCUS projects and their overlap with corresponding E&P expertise are summarized below.

Storage resource assessment. This step involves an estimation, especially during the pre-injection appraisal and permitting phases, of the quantity of CO₂ that can be stored in the target formation. It is important to distinguish between (a) volumetrics-type approaches appropriate for deep saline aquifers which can be regionally extensive and hence, akin to infinite-acting reservoirs, and (b) voidage-replacement type approaches appropriate for depleted oil/gas fields which are essentially closed reservoirs.

Also, SPE has recently developed the CO2 Storage Resources Management System (SRMS), analogous to the Petroleum Resources Management System (PRMS), to provide an accepted and recognized system for quantifying, categorizing, and classifying storage resources.

Reservoir characterization. The goal is to understand the spatial extent, boundaries, flow barriers, and rock/fluid properties of the target storage formation. In addition, geotechnical properties of the caprock and overlying seals, location of underground sources of drinking water (USDW), and presence of conductive fractures and faults that could act as leakage pathways or trigger injection-induced seismicity are also important for CCUS projects.

The challenge of data sparsity is generally a concern for saline aquifers, as projects will typically have data only from one dedicated site‑characterization well and perhaps a handful of legacy wells (from oil and gas exploration and/or subsurface waste injection).

Pressure propagation and CO₂ plume modeling. As with E&P projects, static and dynamic reservoir modeling are fundamental to operational management of CCUS projects. The metrics of interest are (a) pressure buildup in the injection well, caprock, and storage formation, (b) CO₂ plume migration extent, and (c) delineation of the Area of Review, i.e., a region surrounding the injection well where USDW may be endangered because of injection-induced excess pressure buildup.

Conventional geologic modeling and simulation workflows/tools from the oil and gas industry have been adapted and applied for CCUS projects, along with simplified approaches such as sharp-interface models and fractional-flow models, which may be more appropriate for project developers and/or regulators. However, the impact of data sparsity is an important constraint, especially for history matching of models to observational data collected from a limited number of monitoring wells.

Monitoring of reservoir performance. Regulatory guidance for geologic sequestration wells generally stipulates more involved monitoring of system evolution and storage integrity compared to E&P injection wells. Required detailed surveillance involves geophysical surveys, geochemical sampling, geomechanical measurements, and dynamic pressure and temperature sensing in the storage reservoir and caprock. Also, detailed documentation of monitoring, verification, and accounting is needed for receiving tax credits or trading carbon permits.

Hydrogen Underground Storage (HUS)

Fig. 2 depicts the hydrogen value chain, which includes (a) production of green hydrogen from renewable sources or blue hydrogen from fossil-fuel-based sources in conjunction with CCUS, (b) storage in physical containers or underground geologic formations, and (c) end use in industry, transportation, and energy sectors. HUS is particularly attractive for managing the intermittency of renewable power generation and is similar in concept and execution to active underground NGS storage projects in aquifers, depleted oil/gas fields, and salt caverns.

Some of the key elements of HUS projects and their overlap with corresponding E&P expertise are summarized below.

Reservoir characterization/development. The characterization needs for saline aquifers is the same as was discussed earlier, whereas depleted oil/gas fields will have a pre-established database for reservoir characterization. The construction of salt caverns via brine circulation for HUS would be similar to that for NGS, albeit with the needs for better geomechanical characterization and modeling of salt creep, cavern integrity, and fluid leakage.

Well deliverability. The productivity of a hydrogen well can be evaluated using standard NGS well-deliverability equations that include both Darcy and non-Darcy flow components—adjusted for hydrogen properties. Similarly, the common equations for wellbore pressure and temperature changes during injection/production need to be adapted for hydrogen-specific conditions. HUS projects can also benefit from the application of standard workflows from inflow performance and nodal analysis for integrating surface, wellbore, and subsurface elements.

Dynamics of fluid withdrawal. Dynamic modeling of HUS can build on NGS and CCUS tools and experience, but complications caused by high mobility of hydrogen (i.e., gravity segregation, viscous fingering) need to be addressed in simulation design and operational planning. Another challenge is the modeling and management of water up-coning (from aquifers) and hydrocarbon recovery (from depleted oil/gas fields) during hydrogen production. Also, the high levels of hydrogen diffusivity and reactivity (with rock, in situ fluids and bacteria) require assessment of reservoir and caprock integrity using coupled compositional flow and bio‑geo-chemical reactive transport models.

What Skills Need Updating?

We believe that the foundational preparation for the subsurface science and engineering aspects of both CCUS and HUS should come from traditional petroleum engineering and geoscience curricula via core courses in reservoir characterization, wellbore hydraulics, and reservoir engineering. In addition, several specialized courses would be required to address the CCUS and HUS industry-specific needs, as follows.

Foundations of CCUS. CCUS rationale, CO₂ capture, pipeline transport, geological storage basics, aquifers vs. depleted oil/gas fields, monitoring, risk analysis, permitting, and global status/outlook.

Foundations of HUS. Hydrogen usage rationale, pipeline transport, geological storage options (salt caverns, depleted gas/oil fields, aquifers), cavern engineering, geological characterization, well deliverability, reservoir mechanics, and risk analysis.

Advanced reservoir science and engineering for CCUS and HUS. Storage resource estimation, source-sink matching, monitoring, verification, and accounting (MVA), well deliverability, injectivity and plume migration models, and pressure and rate transient analysis.

Risk analysis and permitting for CCUS. Risk source identification, consequence analysis, risk management and mitigation, regulatory framework (EPA class VI permitting, EU CCS directive), regulatory compliance, and MVA documentation.

These courses can be incorporated into existing petroleum engineering and/or geoscience curricula as specializations and/or certificate programs.

They can also be introduced in the continuing education marketplace through providers such as training consortia or university extension programs. Some key aspects of CCUS and HUS as compared to typical E&P operations are summarized in Table 1.

Future Prognosis

The pace of the current energy transition will depend on (a) availability of low-carbon technologies deployable at scale, and (b) societal demands linked to cost-benefit considerations.

Given the magnitude of capital inflows required and the complex restructuring of the supply chain, existing oil and gas companies can play a major role from both techno-economic and human capital perspectives.

To that end, we have discussed how relevant E&P expertise can be leveraged to meet the needs of the nascent CCUS and HUS marketplace.

We strongly believe that the capabilities of oil and gas professionals are readily adaptable for such projects with appropriate re-education and training, and our industry can contribute not just with technology but also with skilled manpower.

On a related note, petroleum engineering skills are already being applied to geothermal energy, another emission-free and fully dispatchable power and heat source that will also play a critical role in the energy transition.

In closing, we recognize that the aspirational goals set forth in most decarbonization plans and net-zero scenarios would require a significant switch from fossil fuel to low-carbon sources.

However, with the continued increase in energy demand to improve quality of life (especially in developing countries), energy transition in the near term will most likely reduce to energy diversification as a pragmatic solution.

A variety of energy sources including renewables and fossil fuel (primarily natural gas) will most probably be utilized in conjunction with CCUS and HUS, with CO₂-EOR used as a bridge technology in the interim.

As such, the technology and human resource base from the E&P sector is poised to play a vital role in the new energy economy—regardless of the trajectory of low‑carbon pathway adoption.

JPT Journal of Petroleum Technology by Srikanta Mishra, May 2, 2023