Category: Nieuws

BTMS is a platform that integrates, upgrades or completely replaces existing systems. The primary purpose is supervising and managing Terminals, Tank farms and loading/unloading trucks, ships and rails.

BTMS was developed by engineers who have more than 30 years of experience in the oil & gas industry.  BTMS has the task of combining the functionalities necessary for the entire Monitoring and Management System to work in a way acceptable to operators, dispatchers and other business entities. Its task is to enable the exchange of data between SCADA, Tank System, Metering stations and other business and technological processes.  

Also, this software is responsible for inspecting all authorized business entities in the condition of the tank, active and inactive batches and transports (completed and planned) and the preparation and distribution of the necessary business reports, all in accordance with their assigned access rights. 

BTMS is made for: 

• Tank storages
• Terminals

Benefits: 

• Respect legacy

Maximal utilization of existing software’s and hardware’s 

• Open and flexible

Various connectivity options. 

Unlimited number of clients 

• Modular

Customer buys what he needs and when he needs it 

Clients can run on exiting computers 

• Cybersecurity 

Certified methods for cybersecurity, especially for plant and process data 

The BTMS platform can be divided into several modules: 

• Scheduler
• Planner
• Terminal Management
• Infrastructure
• Reports
• Control house (Laboratory)
• KPI

The system architecture follows four main guidelines that allow modularity and scalability of the system: 

• Component-based design – separation into specific independent sections
• Multi-level architecture – allows flexibility and reusability
• Distribution – allows easy scaling 
• Service Oriented Architecture – eases integration with other Systems

Cybersecurity 

BTMS is implemented in companies of strategic value and requires compliance with all network and application security levels. BTMS can be implemented in network infrastructures where the separation of process and business data networks is required. BTMS retains the existing task and functionality in such systems as well, and communication between these networks takes place via data diodes intended for one-way data flow. 

Terminal Management System 

Terminal Management System ensures efficient, accurate, safe, and secure material transfers for tank storage facilities/terminals. This module will help operators to manage and supervise tank farms, loading/unloading trucks, ships and rails. Terminal Manager also offers real-time data monitoring and connection to existing systems. Terminal Manager is a scalable, highly reliable solution that is appropriate for terminals of all sizes. 

Contains a real-time load / unload scheduler. 

Systematically enforces your schedule for accurate and reliable offloads and automatically triggers sample capture. 

Possibility of connecting with quality control laboratories. 

Berth monitoring: 

– sampling system management 

– manage the arrival / departure of ships 

– connection of measuring stations for loading/unloading ships 

Automation from entry to exit allows a facility to operates completely unmanned with site access to product offload handled by drivers. 

Accurate inventory tracking provides the information needed for planning and operations and customer position reporting. 

Easy-to-use, reliable system provides flexibility and supports additional growth as a terminal expands. 

Alarms, reports and balancing 

For more information, please contact us. 

Luvis Projekt d.o.o. 
Phone: +385 1 644 8222 
E-mail: info@luvis-pro.com 
www.luvis-pro.com  

U.S. oil major Exxon Mobil Corp, along with Chevron Corp, is seeking to bulk up in the burgeoning renewable fuels space by finding ways to make such products at existing facilities, sources familiar with the efforts said, as reported by Reuters.

The two largest U.S. oil companies want to produce sustainable fuels without ponying up billions of dollars that some refineries are spending to reconfigure operations to make such products. Renewable fuels account for 5% of U.S. fuel consumption, but are poised to grow as various sectors adapt to cut overall carbon emissions to combat global climate change.

Both Chevron and Exxon have massive refining divisions that contribute heavily to their overall carbon emissions. The companies have been criticized for a less urgent approach to renewable investments than European rivals Royal Dutch Shell Plc and TotalEnergies, and have generally spent a lower percentage of their capital than those companies on “green” technologies.

The companies are looking into how to process bio-based feedstocks like vegetable oils and partially processed biofuels with petroleum distillates to make renewable diesel, sustainable aviation fuel (SAF) and renewable gasoline, without meaningfully increasing capital spending.

Commercial production of renewable fuels is costlier than making conventional motor gasoline unless coupled with tax credits.

A task force was created at Exxon’s request within international standards and testing organization ASTM International to determine the capability of refiners to co-process up to 50% of certain types of bio-feedstocks to produce SAF, according to the sources.

Exxon says it will repurpose its existing refinery units among other strategies to produce biofuels. It aims at more than 40,000 barrels per day of low-emission fuels at a competitive cost by 2025.

“We see the potential to leverage our existing facility footprint, proprietary catalyst technology and decades of experience in processing challenging feed streams to develop attractive low-emission fuels projects with competitive returns,” spokesperson Casey Norton said in an e-mailed response.

Chevron is looking into how to run those feedstocks through their fluid catalytic crackers (FCC), gasoline-producing units that are generally the largest component of refining facilities.

“Our goal is to co-process biofeedstocks in the FCC by the end of 2021,” a Chevron spokesperson told Reuters, to supply renewable products to consumers in Southern California.

The company is partnering with the U.S. Environmental Protection Agency (EPA) and California Air Resources Board (CARB) to develop a path to produce fuel that would qualify for emissions credits.

A source familiar with the matter said if approved by the EPA and CARB, Chevron would be able to produce and generate credits for renewable gasoline. That product is not yet commercially available, but can reduce carbon dioxide emissions by 61% to 83%, depending which feedstock is used, according to the California Energy Commission.

Chevron said on its earnings call earlier this month that in the second phase of its process, it would be the first U.S. refiner to use the cat cracker to produce renewable fuels.

“We did it this way, in part, because it’s very capital-efficient … It’s literally just a tank and some pipes,” Chevron Chief Finance Officer Pierre Breber said on the call.

Congress is considering legislation for tax credits that would further spur refiners to process sustainable aviation fuel commercially.

Some refiners, like San Antonio-based Valero Energy Corp and Finland-based Neste, have ramped up production of renewable fuels from waste oils and vegetable oils to cash in on lucrative federal and state financial incentives. Several U.S. refiners are in the midst of partially or totally converting plants to produce certain renewable fuels, particularly diesel.

If approved, new methods of producing renewable fuels at refineries could allow refiners to avoid lengthy environmental permitting processes. Many of these processes are still undergoing further testing to see which can make renewable fuels commercially, but without damaging refining units.

By BIC Magazine, September 16, 2021

Oil and gas companies have long delivered the fuels that form the bedrock of today’s energy system, but against a backdrop of persistently high global emissions, they are coming under increasing pressure to deliver solutions to climate change.

While these may sound like binary choices, most companies will likely try to do both. In practice, the two are closely interlinked, as most of the financial resources for diversified spending, at least initially, will come from traditional investments in oil and gas supply.

While individual company approaches to the energy transition vary, capital expenditure on clean energy is seeing an increasing share of overall investment. Companies — most notably the large European players — are now actively seeking to ramp up their transition to renewables.

BP says it will increase its annual clean energy investment from USD 500 Mn in 2019 to USD 5 Bn per year by 2030, with an interim goal of USD 3-4 Bn per year by 2025. Total has announced that some USD 2.5 Bn of its planned total investment of USD 12-13 Bn in 2021 will go into renewables and electricity (including gas-fired power). Shell is targeting a 25% share of investment on clean energy capital expenditure by 2025. Eni’s

strategic plan for 2021-24 targets 20% of average yearly capex of EUR 7 Bn to clean energy projects. Additionally, several companies including Saudi Aramco and ADNOC, are exploring possibilities to develop low-carbon hydrogen production, as well as investments in CCUS.

The IEA’s World Energy Investment 2021 report suggests that these commitments are already starting to have an impact. If the current trajectory is maintained for the full year, the share of capital investment going to clean energy investments could rise to more than 4% in 2021 from 1% in 2020.

The Oil and Gas Industry’s Eye for Hydrogen

According to a survey of over 1,000 oil and gas executives by consulting firm DNV GL, the proportion of oil and gas companies intending to invest in the hydrogen economy doubled from 20% to 42% in 2020. Half of senior oil and gas professionals expect hydrogen to be a significant part of the energy mix by 2030, with a fifth of surveyed oil and gas companies already active in the hydrogen market.

For over a century, oil companies have spent tremendous sums of money to deliver fuel to the power and industrial sectors. If hydrogen is supposed to replace petroleum in that equation, no one could reasonably be expected to have better expertise than Big Oil.

As of the end of June 2021, there were 244 large-scale green hydrogen projects planned, according to the Hydrogen Council, an industry group, up more than 50% since the end of January. It estimates tens of billions of dollars have already been earmarked for hydrogen projects.

BP, Shell and Total are all pursuing multimillion-dollar hydrogen projects themselves, often with government support, as they seek to redefine their future role in a world less reliant on fossil fuels.

BP is exploring the use of hydrogen to replace natural gas in industries such as steel, cement, and chemicals, and also as a substitute for diesel in trucks. Overall, BP forecasts hydrogen could account for about 16% of the world’s energy consumption by 2050–if net-zero carbon emissions goals are to be achieved–up from less than 1% today. However, BP doesn’t expect green hydrogen to be a material part of its business until the 2030s, and it has yet to make a final investment decision on any new hydrogen projects.

Shell also is grappling with high costs. This month, the company started up what it said is Europe’s largest green hydrogen plant, to supply its Rhineland refinery in Germany. But that hydrogen is between five and seven times more expensive than the fossil-fuel-based product it predominantly uses.

Shell hopes it can reduce costs by building hydrogen projects in strategic locations alongside customers’ plants, like at ArcelorMittal’s steel mill in the German port of Hamburg, where it can also add hydrogen refueling stations for trucks.

The industry is also getting government support. The European Union paid half the roughly $23 Mn cost of Shell’s Rhineland project and has earmarked funding for hydrogen as part of its pandemic recovery program.

Notably, The EU’s proposed ~$558 bn plan to switch to hydrogen by 2050 is dwarfed in comparison to the typical spending of the oil and gas sector (~US$500 bn) in developing new fields every year. Shifting just a small share of the sector’s spending into hydrogen could be enough to drastically increase the technology’s scale and economics.

Another key expected area of overlap between the current petroleum economy and a hydrogen future is likely to be in midstream infrastructure: pipelines, ships, and storage facilities.

Salt caverns – artificial caves already widely used to store oil and gas, including the U.S. strategic petroleum reserve – are likely to be critical nodes in the hydrogen network. A few are already in use for industrial hydrogen, but many more will be needed. One study conducted in 2020 estimated a capacity to store about 7.3 PWh (1 PWh = 1 billion MWh) of hydrogen in salt caverns near Europe’s coasts, equivalent to nearly two years of the continent’s electricity demand. Depleted oilfields can play a similar role in areas where salt formations aren’t available. No industry understands this geology better than the oil and gas sector.

Engineered infrastructure will also be key. In the Netherlands, a consortium including Shell is planning to put green hydrogen produced by a giant 10 GW offshore wind farm through pipelines serving the declining Groningen gas field, which would otherwise be scrapped. At the port of Rotterdam, another group is hoping to spend about EUR 2 Bn re-powering the local industrial cluster with blue hydrogen instead of conventional fuel.

Critics of Big Oil’s push towards hydrogen

Consultants and oil company executives argue that an interim step to reaching large-scale green hydrogen production is to capture and store carbon generated by making hydrogen from natural gas to reduce emissions–making what is known as blue hydrogen.

Critics contend that the fossil fuel giants have been heavily talking up hydrogen as most of the world’s hydrogen supply is currently produced from natural gas. Blue hydrogen may offer an intermediate step towards green hydrogen. However, it may also end up like coal power with CCS: previously hailed as a promising way of reducing emissions but now seen as a costly dead-end that provided cover for the last burst of coal investments in Asia.

Others argue that oil and gas companies are pouring money into lobbying efforts to direct public investment towards building a hydrogen economy (with considerable success notable in Canada, Germany, and the UK) to delay the transition to electrification. These companies will be key players embedded in the hydrogen value chain if the fuel “works”, and will have slowed the shift to electricity if it does not.

Either way, the scale of the challenge before us is vast. The world will need to produce 80 exajoules (or 660 million tons) of hydrogen a year by 2050, according to the Hydrogen Council. Doing that with electrolyzers, the only viable zero-carbon pathway, would require more electricity than the entire world produced in 2019. That will need about nine times more wind and solar generators than exist worldwide to date.

Whether Big Oil’s advance into the hydrogen economy will help or hinder the global effort to decarbonize the planet remains to be seen.

Power-eng by Danyel Desa, September 1, 2021

Is a barren year for oil industry deal activity finally coming to an end?

So far there’s been $86 billion of takeovers announced, pending or completed, according to data compiled by Bloomberg. If things continue at those rates through December, it will be one of the most lackluster years for energy deal-making in two decades.

Hope is on the horizon. Saudi Arabian Oil Co. is finally growing close to an equity swap with Reliance Industries Ltd. after years of gestation, people with knowledge of the matter told Bloomberg this week.

Meanwhile, BHP Group announced plans Tuesday to merge its oil and gas business with Woodside Petroleum Ltd. in a share-based deal that would see the mining company quit the petroleum sector and roughly double Woodside’s output. With the first valued at an estimated $20 billion to $25 billion and the latter worth about $15 billion at Woodside’s current share price, that would instantly increase the year’s tally by almost half.

Don’t take that for a sign that animal spirits are picking up in the industry. Although crude prices touched a three-year high last month and cash is once again flowing freely, this wave of deal activity doesn’t suggest an industry gearing up for a rally in demand.

With the Intergovernmental Panel on Climate Change last week predicting a world where global warming is advancing faster than previously expected and the International Energy Agency forecasting that renewable power investment will exceed that in oil and gas production for the second year running, this merger boom has a distinctly end-of-an-era feel about it.

Take the Reliance-Aramco deal, which is expected to see the world’s largest oil company swap between 1% and 2% of its equity for a 20% share in the largest refinery. This is hardly the sort of transaction that Saudi Arabia might have made in the past, when it was able to reach into its bottomless cash pile to buy assets at a keen price from needy, low-margin refiners. Instead, Asia’s richest man, Mukesh Ambani, holds all the cards.

The estimated deal value would be double the $10 billion that Reliance reportedly expected for a 25% stake when it was first being offered around in 2019, although the balance-sheet value of the Jamnagar refinery and its earnings haven’t really improved since then. Meanwhile, a Saudi Inc. that was once so cash-rich that it thought little of splashing greenbacks on soccer teams and Leonardo da Vinci paintings is instead having to part with equity so precious that it wasn’t even offered to the kingdom’s own subjects until two years ago.

As a financial transaction, the deal does little for either party. Shares in Indian and Saudi companies aren’t much use as an alternative form of cash, since they’re locked up on illiquid local exchanges. Strategically, though, Aramco gets itself a seat at the table of a company that’s made no secret of its planned turn away from petroleum and toward renewables and a fast-growing telecoms unit.

Jamnagar isn’t going to stop buying crude any time soon, but Aramco’s enthusiasm for a tie-up at any price suggests it’s keen to keep an eye on the situation before it starts to cause problems.

The BHP-Woodside deal isn’t happening on quite such a grand scale. While a combined company would have produced about 649 million oil-equivalent barrels a day in 2019 — enough to put it in the top 30 listed oil producers by volume — Aramco pumps about that amount every hour.

It makes a different sort of sense for the players, though. Every company with assets less spectacular and owners less involved than Aramco has to care about the views of its shareholders and lenders. For BHP, that’s become a problem as the cost of capital for fossil fuel businesses rises and shareholders look to decarbonize their portfolios.

Arch-rival Rio Tinto Group quit its last fossil-fuel assets several years ago and Anglo American Plc sold out of its last thermal coal business in June. While the coking coal used in steelmaking is still a core business for BHP (not to mention iron ore, which can’t be turned into steel using existing commercial technology unless some coal-derived coke is thrown into the mix), selling out of a petroleum business that was always an odd fit for a mining company is a good way to project a cleaner image.

Woodside gets a different sort of benefit. At present it sits toward the lower end of investment grade at major ratings companies, an uncomfortable position at a time when the interest costs on junk energy debt are at a higher premium relative to higher quality bonds than they’ve been in years. By roughly doubling in size, it will get the cashflows and balance sheet to become more self-sufficient in its spending, an important consideration in a market where lenders are increasingly being asked to scrutinize the climate impact of their loan books.

For energy dealmakers looking to expand the fee pool, the signs of green shoots in the energy M&A market will be welcome after a year of drought. Just don’t mistake it for the start of a harvest. With its best years in the past, this field is looking more and more barren.

Washington Post by David Fickling, September 1, 2021

Saudi Arabia’s state-owned oil asset Aramco is on track to consummate an all-stock deal for a stake in the oil refining and chemicals arm of Mumbai-based multinational conglomerate firm Reliance Industries Limited, Bloomberg reported on Monday, citing insiders.

Aramco is holding talks of a buyout in the neighbourhood of 20 per cent interest in the Reliance unit in exchange for $20 billion to $25 billion in its own shares, according to the people who asked not be named given the sensitivity of the subject.

Reliance, backed by Indian billionaire magnate Mukesh Ambani, could close a deal with Aramco in the coming weeks, said the insiders. A jump in Reliance’s share price by 2.6 per cent in Mumbai followed the news.

Reliance will be enabled by the deal to lock in a constant crude oil supply for its enormous refineries and become a stockholder in Aramco, the world’s fifth biggest public company according to Forbes.

If the transaction succeeds, it will take a stake of approximately 1 per cent in Aramco, considering the latter’s market valuation of around $1.9 trillion, making it the biggest energy company in the world.

The terms are still under discussion, and the negotiation could be prolonged or fall apart, said the sources.

A Reliance representative said its firm does not have further comments apart from Ambani’s reaction at a June shareholders’ meeting during which the company appointed Yasir Al-Rumayyan, Aramco’s chair, to the board. The tycoon had hinted at the possibility of entering an investment pact with Aramco this year.

Last week, the Saudi oil producer said it was conducting due diligence on the deal, adding it should be delivered this year

PremiumTimes by Ronald Adamolekun, August 26, 2021

South America continues to feature prominently among petroleum industry headlines.

Offshore Brazil and Guyana have become the focal point of what is shaping up to be the continent’s two biggest oil booms, while Venezuela’s once mammoth oil industry has nearly collapsed.

Ongoing wrangling within OPEC plus over production cuts, with the United Arab Emirates disagreeing with Saudi Arabia at the last meeting, is putting considerable pressure on oil prices.

The international oil price benchmark Brent has lost 16% since soaring to over $78 per barrel in early July 2021 primarily due to uncertainty over OPEC plus production and the impact of the coronavirus delta variant on global energy demand. These latest events, however, are not deterring big oil from investing in South America.

Argentina’s hydrocarbon sector, notably the exploitation of the vast Vaca Muerta shale oil play, is gaining considerable momentum after national oil company YFP, which is leading the charge, narrowly avoided a debt default earlier this year.

Even the latest market ructions have done little to blunt spending and activity in the Vaca Muerta. Earlier this year Omar Gutierrez, governor of Neuquen province, where most of the shale play is located, stated that the Vaca Muerta will attract $3.8 billion of investment.

Such a significant injection of capital will progress the exploitation of the shale formation which Buenos Aires views as a silver bullet for Argentina’s economic woes.

It is national oil company YPF that is spearheading the exploitation of the Vaca Muerta budgeting $1.5 billion in Neuquen province alone to be spent on exploration and development activities to boost oil reserves and production.

Big oil is also investing heavily in the Vaca Muerta, including developing vital energy infrastructure such as pipelines and processing facilities.

This includes energy supermajor Shell which earlier this year committed to drilling 100 wells in the shale formation during 2021 and 2022. The integrated energy company also allocated $80 million to construct a 120,000 barrel per day pipeline connecting its Sierras Blancas block in the Vaca Muerta to the town of Rio Allen.

Shell also commenced a 30,000 barrel per day processing plant on its Vaca Muerta acreage during June 2021. Growing investment in the Vaca Muerta saw Neuquen’s governor announced he anticipates provincial oil production by the end of 2021 of 235,000 barrels per day which represents a 47% year over year increase.

That will further cement Neuquen as being Argentina’s leading hydrocarbon producing province which for the first half of 2021 pumped 36% of the Latin American nation’s crude oil and 55% of its natural gas.

Momentum is even picking up in Colombia where the economically crucial oil industry has suffered a series of setbacks since the March 2020 oil price crash. Recent nationwide anti-government protests, an emerging security crisis, growing political uncertainty, and the pandemic have all impacted the beaten-down hydrocarbon sector hard.

Investment during 2020 fell by 49% year over year to $2.05 billion while annual crude oil production declined by nearly 12% to an average of 781,300 barrels per day. By June 2021 petroleum output had plunged to an average of 694,151 barrels per day, the lowest level in over a decade, because of heightened political turmoil and nationwide anti-government protests.

Despite these problems and a sharp decline in production the national government in Bogota as well as the leading industry body, the Colombian Petroleum Association (ACP – Spanish initials), are optimistic regarding the future of Colombia’s economically vital oil industry.

The ACP stated in early (Spanish) 2021 that investment in Colombia’s beaten down petroleum industry could reach up to $3.45 billion or a notable 68% greater than a year earlier. Even recent anti-government protests and an emerging security crisis will not deter that significant uptick in investment, particularly with the international benchmark Brent trading at over $65 per barrel well above Colombia’s average breakeven price.

Earlier this year Colombia’s hydrocarbon regulator, the National Hydrocarbon Agency (ANH – Spanish initials) unveiled its 2021 bid round (Spanish). A total of 32 hydrocarbon blocks comprised of 23 onshore and 9 offshore contracts are being offered. Colombia’s energy minister Diego Mesa believes this will attract much-needed investment to boost urgently required oil reserves and production.

Bogota is focused on promoting offshore drilling in the Caribbean Sea to offset aging onshore oil fields with high decline rates where production is regularly interrupted by community blockades and pipeline outages, usually caused by acts of sabotage.

For those reasons, Mesa expects Colombia’s oil production to rebound and average around 790,000 barrels per day during 2021. While that appears ambitious, if drillers aren’t roiled by the latest decline in oil prices, it is feasible with output averaging 729,808 during the first six months of 2021 and the rig count steadily rising to 19 operation drill rigs at the end of July.

The Guyana-Suriname basin is attracting considerable attention with new offshore oil discoveries being since the start of 2021. The former British colony of Guyana is on track to become a leading regional oil producer with Exxon and its partners Hess and CNOOC experiencing outstanding success in the offshore Stabroek Block.

Exxon has identified around nine billion barrels of recoverable oil resources and late last month made its 21st discovery in the Stabroek Block at the Whiptail-1 well. The energy supermajor’s Liza Phase One operation reached full capacity pumping around 130,000 barrels per day during March 2021. Exxon is in the process of developing Liza Phase 2 and the Payara projects which will see it pumping around 750,000 barrels per day from the Stabroek Block by 2026.

The former Dutch colony of Suriname is fast becoming one of South America’s hottest offshore drilling locations. TotalEnergies, which is the operator, and partner Apache has made five quality medium-to-light grade crude oil discoveries in offshore Block 58.

The latest being the Sapakara South-1 well 4 kilometers south-east of the Sapakara West-1 discovery. Next for TotalEnergies is targeting the Bonboni prospect in Block 58. It is estimated that Block 58 contains up to 6.5 billion barrels of recoverable oil resources and production will commence in 2025 with Suriname’s crude oil output expected to hit 650,000 barrels daily by 2030. Suriname’s national oil company and industry regulator Staatsolie recently awarded three shallow-water contracts with Chevron winning block 5 and TotalEnergies with partner Qatar Petroleum being awarded blocks 6 and 8.

That will generate further investment and exploration activity in offshore Suriname.

Brazil, Latin America’s largest oil producer, should not be forgotten. In the space of a decade, the region’s largest economy has expanded its oil output by nearly 40% from 2.17 million barrels per day in 2011 to 3.03 million barrels daily during 2020. Brazil’s oil production continues to expand at a steady clip as national oil company Petrobras and foreign energy majors ramp up investment.

Toward the end of 2020, Petrobras announced plans to invest $55 billion from 2021 to 2025 to develop Brazil’s subsalt oil fields with the company estimating that oil production will reach 2.7 million barrels per day by 2025.

Key to that plan is developing the 210,000-acre Buzios oilfield which has an installed capacity of 600,000 barrels per day and is pumping around 569,648 barrels of sweet medium grade crude oil daily.

Demand for Buzios grade crude oil has grown at a rapid clip since the introduction of IMO 2020 in January last year significantly reduced the sulfur content of marine bunker fuels. This has seen it become particularly popular among refiners in China, which is a major global shipping hub.

The low carbon intensity of Brazil’s sweet medium and light crude oil grades makes the country’s offshore pre-salt fields particularly attractive for energy majors, especially in a world where there is growing pressure to decarbonize the global economy. TotalEnergies, which holds a 20% interest, announced in early August 2021 that along with its partners Petrobras (40%), Shell (20%), and CNOOC (10%) it was proceeding with the development of the Mero 4 project in the Libra Block.

On completion of the Mero project in 2024, the Libra Block will have an installed capacity of 720,000 barrels per day. For these reasons, Brazil is now one of the top global destinations for investment in crude oil projects. That, according to energy minister Bento Albuquerque, will see Brazil pumping 5.3 million barrels per day by 2030, which is 75% higher than 2020, making Latin America’s largest economy the world’s fifth-biggest oil exporter.

South America is fast emerging as one of the world’s hottest drilling locations with offshore exploration and projects in Guyana, Suriname and Brazil set to drive reserves and production higher. The high-quality low sulfur content oil found in offshore South America is particularly attractive to oil majors seeking to reduce their carbon footprint and reach emissions goals to please investors.

The continent, even if Venezuela’s oil industry fails to recover, could be pumping more than nine million barrels per day by the end of this decade, with Brazil the leading producer.

Oil Price by Matthew Smith, August 26, 2021

A slower and steadier trickle of midstream consolidation has continued since the upstream buying spree that began last autumn, but energy executives and analysts warn there are still too many pipeline companies in a North American industry that is now producing less crude within an overbuilt infrastructure environment.

After a race to build long-haul pipelines and gathering and processing systems in recent years, the effects of both the coronavirus pandemic and a stricter regulatory administration have brought most new pipeline and terminal projects grinding to a halt in the last 18 months or so.

“Consolidation has been happening, but it’s a slow process,” said midstream analyst and CBRE Clarion Securities portfolio manager Hinds Howard, adding that CEOs are essentially daring their peers to make moves.

The biggest recent headline deals include Energy Transfer buying Enable Midstream, which is facing more regulatory scrutiny ahead of closing, and the Canadian bidding war for Inter Pipeline in which Brookfield Infrastructure Partners has seemingly outbid Pembina Pipeline.

Counting crude-by-rail shipments, there was also an ongoing fight between Canadian National Railway and Canadian Pacific to win Kansas City Southern.

Otherwise, only smaller deals have taken place, such as master-limited partnership rollups of TC Pipelines by TC Energy and Noble Midstream Partners by Chevron. BP is currently planning to fold up BP Midstream without even offering a premium, and analysts wondered if Shell will soon do the same with Shell Midstream.

There are also individual asset sales and joint ventures. Plains All American Pipeline has won recent praise for its new JV to combine its Permian Basin assets with Oryx Midstream and have operating control over the resulting Plains Oryx Permian Basin JV without spending much money.

US crude output has rebounded back to 11.2 million bpd, but that is still well down from a pre-pandemic record high of nearly 13 million bpd. S&P Global Platts Analytics projects US production to grow to more than 11.5 million bpd by the end of 2021 and to 12.4 million bpd exiting 2022.

By Tanknewsinternational, August 26, 2021