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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

University of Wisconsin-Madison chemical engineers have developed a model of how catalytic reactions work at the atomic scale. It should be an advance considered a breakthrough in computational chemistry research. The understanding could allow engineers and chemists to develop more efficient catalysts and tune industrial processes – potentially with enormous energy savings, given that 90% of the products we encounter in our lives are produced, at least partially, via catalysis.

The team published the news of their advance in the journal Science.

Catalyst materials accelerate chemical reactions without undergoing changes themselves. They are critical for refining petroleum products and for manufacturing pharmaceuticals, plastics, food additives, fertilizers, green fuels, industrial chemicals and much more. There are two brief motion videos available in a zip file at this link on the Science abstract page.

Scientists and engineers have spent decades fine-tuning catalytic reactions – yet because it’s currently impossible to directly observe those reactions at the extreme temperatures and pressures often involved in industrial-scale catalysis, they haven’t known exactly what is taking place on the nano and atomic scales. This new research helps unravel that mystery with potentially major ramifications for industry.

In fact, just three catalytic reactions – steam-methane reforming to produce hydrogen, ammonia synthesis to produce fertilizer, and methanol synthesis – use close to 10% of the world’s energy.

Manos Mavrikakis, a professor of chemical and biological engineering at UW-Madison who led the research said, “If you decrease the temperatures at which you have to run these reactions by only a few degrees, there will be an enormous decrease in the energy demand that we face as humanity today. By decreasing the energy needs to run all these processes, you are also decreasing their environmental footprint.”

Mavrikakis and postdoctoral researchers Lang Xu and Konstantinos G. Papanikolaou along with graduate student Lisa Je developed and used powerful modeling techniques to simulate catalytic reactions at the atomic scale.

For this study, they looked at reactions involving transition metal catalysts in nanoparticle form, which include elements like platinum, palladium, rhodium, copper, nickel, and others important in industry and green energy.

According to the current rigid-surface model of catalysis, the tightly packed atoms of transition metal catalysts provide a 2D surface that chemical reactants adhere to and participate in reactions.

When enough pressure and heat or electricity is applied, the bonds between atoms in the chemical reactants break, allowing the fragments to recombine into new chemical products.

Mavrikakis explained, “The prevailing assumption is that these metal atoms are strongly bonded to each other and simply provide ‘landing spots’ for reactants.

What everybody has assumed is that metal-metal bonds remain intact during the reactions they catalyze. So here, for the first time, we asked the question, ‘Could the energy to break bonds in reactants be of similar amounts to the energy needed to disrupt bonds within the catalyst?’”

According to Mavrikakis’s modeling, the answer is yes. The energy provided for many catalytic processes to take place is enough to break bonds and allow single metal atoms (known as adatoms) to pop loose and start traveling on the surface of the catalyst.

These adatoms combine into clusters, which serve as sites on the catalyst where chemical reactions can take place much easier than the original rigid surface of the catalyst.

Using a set of special calculations, the team looked at industrially important interactions of eight transition metal catalysts and 18 reactants, identifying energy levels and temperatures likely to form such small metal clusters, as well as the number of atoms in each cluster, which can also dramatically affect reaction rates.

Their experimental collaborators at the University of California, Berkeley, used atomically-resolved scanning tunneling microscopy to look at carbon monoxide adsorption on nickel (111), a stable, crystalline form of nickel useful in catalysis. Their experiments confirmed models that showed various defects in the structure of the catalyst can also influence how single metal atoms pop loose, as well as how reaction sites form.

Mavrikakis says the new framework is challenging the foundation of how researchers understand catalysis and how it takes place. It may apply to other non-metal catalysts as well, which he will investigate in future work. It is also relevant to understanding other important phenomena, including corrosion and tribology, or the interaction of surfaces in motion.

“We’re revisiting some very well-established assumptions in understanding how catalysts work and, more generally, how molecules interact with solids,” Mavrikakis said.

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Its well worth a read of the press release as there are 6 paragraphs of credits for collaborators, and support of funding and resources. It looks like this is a much bigger project than a press release can describe in a few paragraphs.

This work looks like something that time will prove to be very significant. Eight metals were tested in the work and collaboration was running experiments for model confirmation. It looks like a very well thought through program of research.

When this level of importance comes along there is one thing that seems is always missing in the press releases. One does wonder about the hypothesis mentioned above, was that what set this program in motion? If it was, the team got very far along, indeed.

OilPrice.com by Brian Westenhaus, April 25, 2023

Port of Gothenburg and Inter Terminals Sweden (ITS) will develop a methanol storage facility for bunkering by the end of 2023.

ITS will rebuild tanks and other related infrastructure in Gothenburg. The management of the gases from methanol when loading into ships is a challenge that will be handled through a Vapor Recovery Unit (VRU), ITS said.

In January, ship owner Stena Line bunkered its ferry Stena Germanica with methanol in Gothenburg via ship-to-ship transfer. Previously, Stena Germanica received methanol from trucks when berthed at the port. The methanol was supplied from methanol producer Methanex.

Northwest Europe grey methanol was pegged at $775/t average in March, or 42pc premium to very low-sulphur fuel oil (VLSFO), Argus data showed. Northwest Europe bio-methanol was assessed at $2,680/t or 4.9 times higher than VLSFO.

Grey and bio-methanol do not contain sulphur, which makes them compliant with the 0.5pc sulphur cap on marine fuels imposed by the International Maritime’s Organisation (IMO) starting in January 2020.

IMO requires that vessels reduce their CO2 emissions 40pc by 2030 and 70pc by 2050 from 2008 base levels. Grey methanol combustion lowers CO2 emissions by only 7pc compared to VLSFO. By comparison, bio-methanol could be carbon natural, if produced from sustainable biomass.

Argus by Deyzhah Knox and Stefka Wechsler, April 24, 2023

Abu Dhabi-owned Cepsa said it plans to build a 500,000 t/yr second-generation hydrotreated vegetable oil (HVO) plant in southern Spain in partnership with Bio Oils, the Spanish subsidiary of Singapore-based palm oil producer Apical.

The plant will be located near the city of Huelva, where Cepsa operates a 220,000 b/d refinery and Bio Oils runs a 500,000 t/yr fatty acid methyl ester (Fame) biodiesel facility. Cepsa is Bio Oils’ main customer and the pair share port installations and vessels in Huelva. Cepsa announced plans for an HVO facility at Huelva last month, putting the cost of the project at €1bn ($1.05bn). That investment will now be shared with Bio Oils.

Feedstock supply for the new plant has been secured through a long-term contract with Apical, which operates eight palm oil refineries, four biodiesel facilities and two palm kernel crushing facilities worldwide. Apical sold over 11mn t of palm oil products in 2021. Cepsa said it will source “organic waste such as agricultural residue” and used cooking oil (UCO) from Apical and this will make up most of the plant’s feedstock.

Cepsa expects the HVO plant to come on stream in the first half of 2026, taking the firm towards its target to produce 2.5mn t/yr of biofuels by 2030, including 800,000 t/yr of sustainable aviation fuel (SAF). Cepsa’s existing biofuels production capacity at Huelva and its other Spanish refinery — the 244,000 b/d Algeciras complex — had increased to 705,000 t/yr by the end of 2022 from 578,000 t/yr a year earlier.

Cepsa is focusing on biofuels and renewable hydrogen to achieve a target to reduce its scope 1 and 2 CO2 emissions by 55pc in 2030 and to become carbon neutral by 2050. The firm recently announced an acceleration of its renewable hydrogen capacity rollout in Huelva, where it now expects to have 400MW of electrolyser capacity on line in 2026, up from 200MW previously. This will be in time to supply the new HVO plant with renewable hydrogen for the hydrotreatment process.

Cepsa, which is controlled by Abu Dhabi sovereign wealth investor Mubadala, has said that the 1GW of hydrogen electrolysis capacity it expects to have on line at Huelva in 2030 should be enough to decarbonise its own fuels and petrochemicals business as well as the fertilizer business of Fertiberia, one of its partners in Huelva.

Argus by Jonathan Gleave, April 24, 2023

If you think, as we do, that U.S. crude oil production is likely to increase by 1.5 to 2 MMb/d over the next five years, almost all those barrels will be light-sweet crude that needs to be exported, and exporters will overwhelmingly favor the marine terminals that can accommodate Very Large Crude Carriers (VLCCs), it would be hard to ignore the game-changing impacts that Enterprise Products Partners’ planned Sea Port Oil Terminal could have.

SPOT, which could be completed as soon as 2026, will have robust pipeline connections from the Permian and other shale plays and be capable of fully loading a 2-MMbbl VLCC in one day, enough to handle virtually all the incremental exports we’re likely to see over the next five years. In today’s RBN blog, we discuss the fast-increasing role of VLCCs in U.S. crude oil exports and the potentially seismic impacts of the SPOT project.

RBN’s middle-of-the-road “Mid” forecast sees U.S. crude oil production increasing to 14 MMb/d by 2028, about 2 MMb/d higher than the 2022 average, with three-quarters of that incremental output coming from the Permian and most of the rest from other shale plays that also produce high-API-gravity, low-sulfur oil — see The Price You Pay for more (and a downloadable MS Excel version of that forecast).

Given that U.S. refineries’ ability to economically process light-sweet crude is essentially maxed out, it’s a good bet that almost all those incremental barrels will be bound for export terminals along the Gulf Coast.

And, as we said in Calling the Shots, it’s just as likely that, on their way to overseas refineries, as many of those barrels as physically possible will be headed through terminals like the Enbridge Ingleside Energy Center (EIEC) and South Texas Gateway (STG) — both in the Corpus Christi area — whose docks can receive and load VLCCs with minimal reverse lightering, the most cost-effective way to move massive volumes of oil to Europe and Asia.

But crude oil pipelines from the Permian to Corpus are nearing capacity, more oil is being diverted toward Houston-area export terminals across Magellan’s pipelines, the Midland-to-ECHO pipeline system and other pipes — see Sooner or Later and Houston Bound for more on that — and Enterprise continues to advance its plan to build SPOT in 115-feet-deep waters about 30 nautical miles off the coast of Freeport.

Enterprise has estimated that it will have a full license for the project in hand by September 2023, and that it will take about 30 months to build the facility. In What It Takes, we explained that SPOT will have two single-point mooring buoys (purple-and-white-striped diamonds in Figure 1) and the ability to simultaneously moor two VLCCs and load one per day — providing an extraordinary level of cost- and time-efficiency.

Crude will flow to SPOT on a pair of 36-inch-diameter pipelines from two Enterprise storage-and-distribution terminals: the existing ECHO Terminal (orange tank icon southeast of Houston; 8.4 MMbbl of tank storage) and the proposed Oyster Creek Terminal (orange-and-white-striped tank icon north of Freeport; 4.8 MMbbl of planned capacity) in south-central Brazoria County.

RBN Energy by Housley Carr, April 19, 2023

This week, OPEC+’s surprise output cuts made it even stronger.

Key markers in the Dubai crude market — the benchmark for Middle Eastern grades — leapt higher after the Saudi-led decision. The most active timespread for Dubai swaps jumped to above $1 a barrel in backwardation, according to data from PVM Oil Associates Ltd, outperforming the Brent curve.

While OPEC+’s production cuts will take effect only next month, Dubai’s strength reflects expectations that the reductions will strengthen an already-robust market for Middle Eastern supplies.

Saudi Arabia, Iraq, the UAE and Kuwait pledged to cut a combined 980,000 barrels a day of output, with generally heavier and more sulfurous crude as the bulk of their production.

That’s likely to lift the relative value of Dubai crude — which is both a proxy for Middle Eastern oil markets as well as medium-sour oil varieties — against global benchmarks such as Brent even further, a shot in arm for long-haul cargo flows from the Atlantic Basin and Americas into Asia.

Even prior to the OPEC+ cuts, traders were already bullish on Dubai versus other crudes, as red-hot Chinese demand hoovers up the region’s supplies and lackluster European consumption weighs on Brent.

“Given the bulk of the cuts stem from medium and heavy Middle Eastern producers, we would not be surprised to see Dubai trade at a premium to Brent in the coming months, particularly as China looks to ramp imports,” RBC analysts including Mike Tran and Helima Croft wrote in a report.

For months, the Middle Eastern oil market has been among the tightest in the world as regional exporters support Asia’s recovering demand. This week, OPEC+’s surprise output cuts made it even stronger.

Key markers in the Dubai crude market — the benchmark for Middle Eastern grades — leapt higher after the Saudi-led decision. The most active timespread for Dubai swaps jumped to above $1 a barrel in backwardation, according to data from PVM Oil Associates Ltd, outperforming the Brent curve.

Bloomberg by  

Many private Chinese refiners in the Shandong province are buying increasing volumes of Iranian crude as competition for Russian oil from China’s major state-held refiners and from Indian buyers has made Moscow’s barrels relatively more expensive.

China’s private refiners, the so-called teapots, are estimated to have imported 800,000 barrels per day (bpd) of Iranian crude oil and condensate in March, up by 20% compared to February, Emma Li, an analyst with Vortexa, told Bloomberg.

Imports from Iran into the Shandong province—home to most of the private refiners in China—could continue to be robust in the coming months, according to the analyst.

There isn’t official data on Iranian imports into China, so the market relies on tanker-tracking companies that aim to capture the true picture of how much of Iran’s oil, sanctioned by the U.S. and going to very few destinations these days, is being shipped to China.

The private refiners in the world’s top oil importer are now betting more on cheap Iranian crude, as Russian supply is going to the state-owned Chinese majors and to India’s refiners. Russia’s crude is also cheaper compared to international benchmarks, but heightened competition has driven up prices in recent weeks.

Russia was the single largest crude oil supplier to China in January and February, overtaking Saudi Arabia, which was the number-one supplier of oil to China last year, according to Chinese customs data from last month.

As China accelerated the buying of cheap Russian crude oil at discounts to international benchmarks, Chinese imports of crude from Russia jumped by 23.8% year over year to 1.94 million barrels per day (bpd) in January and February 2023.

India, for its part, is also boosting imports of Russian oil to record levels. In February, Russia remained India’s top oil supplier for a fifth consecutive month.

Both India and China are not abiding by the G7 price cap as they seek opportunistic purchases of cheap crude.

OilPrice.com by Tsvetana Paraskova, April 11, 2023

Saudi Aramco’s joint venture Huajin Aramco Petrochemical Co (HAPCO) earlier this week broke ground on a $10 billion integrated refinery and petrochemical complex in Panjin city in China’s Liaoning Province.

HAPCO is a joint venture between Aramco (30%), NORINCO Group (51%) and Panjin Xincheng Industrial Group (19%).

Aramco announced earlier that the complex was expected to be fully operational by 2026. The Saudi firm will likely supply up to 210,000 barrels per day (bpd) of crude oil feedstock to the facility.

The complex will combine a 300,000 barrels per day refinery and a petrochemical plant with annual production capacity of 1.65 million metric tons of ethylene and 2 million metric tons of paraxylene.

In another major announcement, Saudi Aramco signed agreements to acquire a 10% stake in Shenzhen-listed Rongsheng Petrochemical Co. for $3.6 billion, fortifying its presence in China’s downstream sector.

NORINCO Group’s general manager said that the project will play an important role in “deepening economic and trade cooperation between China and Saudi Arabia, and achieving common development and prosperity.”

By Oil&Gas, April 11, 2023