Cocaine, Guns And Gushers: Colombia’s Oil Industry Struggles To Reactivate

By Matthew Smith - Dec 26, 2021

• Rising security risk and rural violence, which is mostly fueled by the vast profits generated by the cocaine trade, is a key deterrent to attracting onshore oil investment in Colombia.
• 
  
• According to the UN, Colombia’s cocaine production during 2020 increased by 8% compared to a year earlier, despite a 7% decrease in the volume of land used for coca cropping. 
• 
  
• Despite the risks associated with operating in onshore Colombia, the Andean country’s 2021 bid round found some success.

Despite the groundbreaking 2016 peace deal between the Colombian government and the largest guerilla group the Revolutionary Armed Forces of Colombia (FARC – Spanish initials) there are fears that conflict is escalating once again. Colombia, which is Latin America’s third-largest petroleum producer and the world’s largest manufacturer of cocaine for nearly a century, has been caught in a simmering low-intensity asymmetric conflict that reached boiling point during the 1980s. The primary flashpoint for the civil conflict, which currently engulfs Colombia and failed to end with the 2016 FARC peace accord was the April 1948 assassination of Liberal Party leader Jorge Gaitan in Bogota. That sparked the Bogotazo, days of violent rioting that swept across Bogota resulting in up to 3,000 deaths, which eventually evolved into a vicious 10-year civil war between the Colombian Liberal and Conservative parties known as La Violencia. While that brutal struggle ended in a 1958 power-sharing agreement between Colombia’s leading political parties, it sowed the seeds for the current low-intensity multiparty asymmetric conflict.  In 1964 the Colombian Communist Party formed the Revolutionary Armed Forces of Colombia (FARC – Spanish initials) after a military attack on the community of Marquetalia, a Communist peasant enclave established during the of La Violencia. That event saw the communist FARC emerge as the most powerful left-wing anti-government armed group during the conflict. The guerillas eventually cut ties with the Colombian Communist Party and increasingly relied upon kidnapping, extortion, and cocaine trafficking to fund their operations. Prior to these events, which cast Colombia into what appears to be a never-ending low-intensity asymmetric multiparty civil conflict, oil was discovered in 1918 at the La Cira-Infantas field in the Middle Magdalena Basin near the city of Barrancabermeja. Even after additional petroleum discoveries in the Middle Magdalena Basin, it was not until the giant Caño Limon, Cusiana, and Cupiagua oilfields were discovered between 1983 and 1993 that Colombia embarked on becoming a major oil producer. Those mega discoveries and a notable increase in foreign energy investment, as well as petroleum production, occurred despite violence surging because of the tremendous influx of profits from the booming cocaine trade.

Even the tremendous escalation of violence, homicides, kidnappings, and attacks on energy infrastructure which escalated in the late-1980s, lasting well into the early 21st century, had little material impact on Colombia’s hydrocarbon sector. By 1991 Colombia was pumping over 400,000 barrels per day, more than double its output in 1985, despite becoming the world’s murder capital with a homicide rate of 84 intentional killings per 100,000 people. That was more than eight times greater than the U.S. which reported 9.8 homicides per 100,000 head of population, 7-times higher than neighboring Venezuela’s murder rate of 12 and 8-times larger than Ecuador’s 11 homicides per 100,000 people.

Heightened insecurity and violence remained a persistent problem in Colombia, even after the collapse of the Medellin and Cali cartels, as the FARC and National Liberation Army ELN (Spanish initials) ramped-up operations as vast revenue flowed in from the drug trade. By 2000, after President Andres Pastrana’s peace negotiations with the FARC had failed, the leftist guerillas controlled a 42,000 square mile territory in southeastern Colombia and kidnappings had surged to a record high of 3,500 for the year. Even those events failed to have any material impact on Colombia’s oil boom. A combination of soaring oil prices and rapidly improving internal security during the early 2000s, because of Plan Colombia and President Alvaro Uribe’s military campaign against the FARC, saw foreign energy investment and hence crude oil production growth.

During 2003 when Brent averaged $28.83 per barrel, a 15% increase over 2002, Colombia pumped an average of 550,000 barrels of crude oil per day. When Brent had soared to over $140 per barrel during 2008, annual petroleum production averaged 600,000 barrels daily and kept growing to peak at a yearly record of just over 1 million barrels per day by 2013. Since 2016 Colombia’s petroleum output has been in terminal decline impacted at first by the late-2014 oil price crash, sharply rising violence, and finally because of the fallout from the COVID-19 pandemic. Even the 2017 demobilization of the largest leftist guerilla group the FARC, after a 2016 peace agreement was struck with the government of President Juan Manuel Santos, has done little if anything to arrest Colombia’s production decline. That in part can be blamed on current President Ivan Duque’s reluctance to fully implement the peace deal, contributing to an increase in violence and civil unrest in regional Colombia.

Related: Southeast Asia’s Oil And Gas Output May Never Recover To Pre-COVID Levels

During 2020, the crisis-driven Andean nation only pumped on average 781,300 barrels of crude oil per day as the COVID-19 pandemic, related national quarantine lockdown and sharply weaker oil prices impacted investment as well as production. More worrying, is that despite the pandemic lockdown ending by September 2020 and energy investment increasing, average petroleum output only reached 734,231 barrels per day for the first 10 months of 2021 which is 6% less than the full year 2020. That disappointing decline occurred because of heightened civil unrest with anti-government protests sweeping across Colombia during late- April 2021 lasting into May and early-June 2021. Falling crude oil output can also be attributed to rising insecurity in regional areas, where petroleum industry operations are concentrated, fueled by a marked uptick in violence related to the activities of illegal armed groups and cocaine production.

It is the cocaine trade that is an enduring problem for Colombia. The tremendous profits that the trade generates are responsible for fueling what is a near-perpetual low-level asymmetric conflict where only the illegal armed actors change as the various groups fragment and reform. Estimates vary, but Colombia’s government believes the civil conflict has claimed up to 260,000 lives and displaced at least 9 million people. According to the UN Colombia’s cocaine production during 2020 increased by 8% compared to a year earlier, despite a 7% decrease in the volume of land used for coca cropping and an 18% increase in seizures. The scale of massive profits generated by cocaine is highlighted by former finance minister Juan Carlos Echeverry’s estimate (Spanish) that the drug trade generates $8 to $12 billion annually, which is equivalent to 5 to 4% of Colombia’s gross domestic product. Using Echeverry’s numbers the cocaine trade is contributing the same amount, if not more, to Colombia’s GDP than the oil industry which based on DANE data (Spanish) for the first 3 quarters of 2021 was responsible for 3% of GDP.

Rising security risk and rural violence, which is mostly fueled by the vast profits generated by the cocaine trade, is a key deterrent to attracting onshore oil investment in Colombia. A combination of security risks and mature assets saw Occidental Petroleum, in October 2020, sell its Colombian onshore petroleum assets in an $825 million deal, although the company retained its offshore exploration blocks. Despite the risks associated with operating in onshore Colombia, the Andean country’s 2021 bid round found some success. Seven companies made offers for 30 of the 53 blocks (Spanish) on offer with initial investment expected to exceed $148 million. Five of the offers came from national oil company Ecopetrol or its subsidiaries and 21 from intermediate energy companies with existing operational presence in Colombia, Parex Resources, Frontera Energy, and Canacol Energy. This indicates that Colombia is struggling to attract foreign onshore energy investment because of the heightened security risks coupled with high breakeven prices and elevated carbon content of the sour heavy crude oil produced.

By Matthew Smith for Oilprice.com

Burning Questions: Is hydrogen destined to be Alberta's next great energy export?

For Alberta, producing more hydrogen offers a way to manage the energy transition

Author of the article: Gabriel Friedman

Publishing date:Dec 28, 2021 

In April, $2 million in joint-government funding was announced to help kickstart the Edmonton region hydrogen hub. 

PHOTO BY ALBERTA'S INDUSTRIAL HEARTLAND ASSOCIATION/SUNMEDIA FILES


The Financial Post takes a look at some of the biggest issues Canadians have about business and investing in 2022 in our latest Burning Questions series.

This November, Alberta proclaimed that hydrogen “can be the next great energy export that fuels jobs, investment and economic opportunity across our province,” and published a strategic road map to develop this market.

It’s a claim made by others many times in the past. For decades, a rotating cast of venture capitalists, energy executives, environmentalists and scientists have latched onto hydrogen — the most abundant element on earth — as the clean fuel of the future.

But hydrogen has never gained momentum as a fuel, always dragged down by the high cost of production, lack of infrastructure and other obstacles. As Alberta embarks on what is believed to be a multi-year, multibillion effort to produce hydrogen as its next energy export that will require taxpayer and federal support, is there any reason to believe it could succeed where previous newcomers have failed?

“This is kind of the third big push (for hydrogen),” said David Layzell, energy systems architect in Alberta at the Transition Accelerator, a non-profit that advises Canadian governments on a low-carbon economy. “This time feels different — this time is different.”

This time feels different — this time is different

DAVID LAYZELL

What’s different now, Layzell said, is that many of the world’s largest economies are committed to reaching net zero emissions by 2050, so the demand for fossil fuels is expected to decline in coming years. Meanwhile, technology to support hydrogen as a fuel , which releases no greenhouse gas emissions when burned, has improved.

The strategic road map that Alberta released in November envisions huge growth in global hydrogen consumption, from an estimated 90 million tonnes today, to 700 million tonnes by 2050, a market worth more than $700 billion. That’s about 800 per cent growth from current levels.

Alberta is already one of the largest hydrogen producers in the world, with around 2.4 million tonnes annually, nearly all of which is used by the oil industry to crack bitumen, or turned into ammonia so it can be used as a fertilizer.

For Alberta, producing more hydrogen offers a way to manage the energy transition: the province boasts ample natural gas reserves, which it plans to use to produce hydrogen. That process releases greenhouse gas emissions, but proponents say Alberta’s geology makes it well-suited to carbon dioxide storage, and that, if paired with investment in emissions capture technology, the carbon emissions released to make the product could be dramatically reduced.

Such hydrogen, produced from fossil fuels in combination with carbon capture and storage, is considered ‘blue’ hydrogen, whereas hydrogen produced from renewable energy sources, such as solar or wind power, is considered ‘green.’

Alberta Premier Jason Kenney said while he is “agnostic” about the colour of hydrogen, the industry executives he speaks to believe green hydrogen is a “pipe dream,” and not economic to produce without massive subsidies.

“In the real world, where real private sector money has to be put at risk to produce lower emitting forms of energy, it is going to go to what you are calling blue hydrogen,” Kenney told a group of National and Financial Post journalists last week.

Alberta Premier Jason Kenney announced a strategy to grow and expand the natural gas sector last year, which included expanded use of hydrogen.

 PHOTO BY CHRIS SCHWARZ/GOVERNMENT OF ALBERTA FILES

It’s a bold bet: while it is currently cheaper to produce hydrogen using fossil fuels than to use renewable energy, that advantage is expected to reverse over the next decade. As more so-called green hydrogen — produced using wind and solar power — comes online, the price for hydrogen is expected to fall, and hydrogen produced using fossil fuels is not expected to be economic by around 2030.

“We expect to see a steep fall in the cost of green hydrogen in the coming years, making it cheaper than grey hydrogen and blue hydrogen by 2030 in optimal locations,” analysts at Sanford C. Bernstein & Co. wrote in a 253-page report this past summer.

Still, proponents of hydrogen say Alberta has natural advantages, including existing infrastructure.

The big prize in the next ten years, the short term, is to replace diesel

DAVID SANGUINETTI

“That whole cost question of whether it’s more economic to produce blue or green hydrogen, that’s an important question,” said David Sanguinetti, a vice president at Foresight Canada, a clean technology accelerator that is supporting hydrogen companies.

Sanguinetti argued that even if blue hydrogen is only economically viable for the next ten or 15 years, that’s long enough to pay down the capital costs of projects that begin now.

He said hydrogen is necessary for large trucks and buses, the ships that carry cargo from Canada to Europe and Asia and for planes — none of which can run purely on batteries at the moment, but contribute significantly to emissions.

Layzell said “the low-hanging fruit” for Alberta is to start by retrofitting diesel buses and trucks so they can run on a blended fuel that contains diesel and hydrogen. This can be done at low cost, he said, and will support the build out of hydrogen production and infrastructure, including fueling stations at select high-traffic corridors.

The next step is fuel-cell trucks that run entirely on hydrogen, he said. Eventually, the larger market would be to begin blending hydrogen into the natural gas used to heat homes, and export it as ammonia — which is far cheaper and safer than shipping it as hydrogen — to markets such as Japan, Korea and Germany that could use it in place of natural gas.

“The big prize in the next ten years, the short term, is to replace diesel,” said Layzell.

Last December, Canada released its federal hydrogen strategy: as part of the pathway to net-zero emissions by 2050, it calls for hydrogen to supply 30 per cent of the country’s energy.

Industry appears to be on board: In Alberta, U.S.-based Air Products and Chemicals Inc. and Suncor Energy Inc. in partnership with utility Atco Ltd. have both announced plans to build hydrogen production facilities.

A new hydrogen fuel cell truck made by Hyundai in Switzerland. 

PHOTO BY DENIS BALIBOUSE/REUTERS FILES

These projects would likely require significant government investment in carbon capture technology.

Meanwhile, natural gas companies also are planning on capitalizing demand for hydrogen, too.

Bill Yardley, president of gas transmission and midstream for Enbridge Inc., told investors earlier this month hydrogen was the “logical” next transition for his industry. In September, the company said it is signed a memorandum of understanding with Royal Dutch Shell Plc. to jointly develop low-carbon technologies, including potential green and blue hydrogen production.

“…Simply put natural gas is the cornerstone of the next several decades of the global energy story,” he said.

So far, in Alberta, the first step that Layzell envisions of transitioning thousands of long-haul trucks that move between Edmonton and Calgary and use hydrogen as fuel, remains years away.

He estimated that 75 per cent of oil produced in western Canada is used as transportation fuel. As automakers to sell more zero-emission vehicles, Layzell noted demand for oil is going to decline and prices will fluctuate wildly as supply adjusts.

That will be rough for Alberta’s economy but could also affect the market for hydrogen — as competing fuel sources grow cheaper, and more competitive.

“It’s going to be a rough ride,” he said.

• Email: gfriedman@postmedia.com | Twitter: GabeFriedz

CPPIB targeting high carbon emitters for long-term investments

By: Staff
December 16, 2021


The Canada Pension Plan Investment Board is pursuing a new strategy that involves investing in businesses with high greenhouse gas emissions and a desire to reduce them.

The strategy, which is published in a new report, aims to identify companies committed to creating value by lowering their emissions in a manner that’s consistent with the CPPIB’s own timeframe. The strategy was devised by Bill Rogers, managing director and head of sustainable energies; Mike Conrad, principal in sustainable energies; and Art Pithayachariyakul, principal in sustainable energies.

“Most current initiatives to tackle the climate crisis do not address strategic sectors that are both essential and high-emitting,” stated the report. “The successful decarbonization of these strategic sectors is not only essential to meet wider net-zero ambitions, but also to sustain economic growth, stability and a responsible transition.”

Read: CPPIB sustainability report shows increased investments in renewable energy

The CPPIB also identified several sectors in which it intends to use the strategy, including agriculture, chemical, cement, power, oil and gas, steel and heavy transportation sectors. It estimated that the decarbonization of each of these sectors will cost between US$100 trillion and US$150 trillion — equivalent to between 15 and 18 months of gross global earnings.

In a press release, Deborah Orida, the CPPIB’s first chief sustainability officer and its global head of real assets, said companies with high carbon footprints that are working to reduce overall emissions offer a significant value proposition to long-term investors. “High-emitting companies that successfully navigate the economy-wide evolution to a low-carbon future will preserve and deliver embedded value for patient long-term investors like CPP Investments.

Read: CPPIB taps Deborah Orida as chief sustainability officer

“This new investment approach complements the fund’s ongoing commitment to investing in companies that have the potential to develop innovative climate technologies around the world and furthers our existing capabilities in technologies that enable the energy evolution.”

In the report, the CPPIB also indicated it would like to see other institutional investors engage with its strategy — as either investment partners or to help support the overall goal of reducing carbon emissions. “As we expand our competency in this space, we hope others will work alongside us to advance the push to identify, fund and facilitate opportunities on the journey toward a sustainable future.”

Read: More standards required for pension funds using ESG data, indices and scores

 

Why this UK-based Oil and Gas Company is Diversifying its Portfolio with Canadian Assets

Jocelyn Aspa, The Market Herald | November 30, 2021

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Canada is undoubtedly one of the world’s largest producers of oil reserves and natural gas, producing on average 3.5 million barrels per day of crude oil and 13.7 billion cubic feet of natural gas.

Since early 2020, however, oil and gas production has suffered not only in Canada but around the world resulting from the COVID-19 pandemic. That being said, in 2021 and is projected to reach a valuation of $310.9 billion by 2035, resulting in growing investments in building Canada’s oil and gas infrastructure.

In line with this, it’s estimated that the production of crude oil in Canada is expected to outpace 2019 levels by the end of the year and continue its road to recovery in 2022.

To that end, companies like i3 Energy (TSX: ITE, LSE: I3E, Forum) are contributing to that growth thanks to its production base in Canada’s most prolific hydrocarbon region — the Western Canadian Sedimentary Basin — as well as appraisal assets in the North Sea.

With its primary headquarters in England, i3 Energy was first listed on the London Stock Exchange in 2017 and has been advancing its portfolio of assets in the United Kingdom since.

In the region, i3 Energy owns a 100 percent interest in Block 13/23c, which includes the Serenity oil field, discovered by i3 in late 2019, and the highly prospective Minos High region.

By late 2020, however, the company dipped its toes into the Canadian market by officially notching a listing on the Toronto Stock Exchange and acquiring Western Canadian Sedimentary Basin assets through a reverse takeover of privately-held Gain Energy and publicly-listed Toscana Energy Income Corporation.

With assets in both the United Kingdom and in Canada, i3 Energy presents itself as a unique oil and gas investment opportunity for investors looking for a company with a diverse portfolio in two well-established jurisdictions.

The Western Canadian Sedimentary Basin

Spanning 1.4 million square kilometres, the Western Canadian Sedimentary Basin (WCSB) is a vast sedimentary basin that spans southern Manitoba, southern Saskatchewan, Alberta, northeastern British Columbia, and the southwest corner of the Northwest Territories.

In a word, the region is considered a mature area for exploration of petroleum with more recent developments trending towards natural oil and gas sands instead of conventional oil — which includes light crude oil and heavy crude oil.

i3 Energy is firmly in control of its destiny in the WCSB with the company operating over 70% of its production across its ~800 (net) long-life, low-risk and low-decline wells, and having a sizeable land base of greater than 625,000 net acres.


(Click to enlarge image)

The company currently has 2P reserves in the country of roughly 130 million barrels of oil equivalent and current production of over 18,000 boepd from large contiguous holdings in the WCSB’s most economic play types.

In an interview with Stockhouse Editorial Graham Heath, CFO of i3 Energy, said the company stands out in the Canadian market thanks to its access to capital in London — and its international focus — he said this has allowed i3 Energy to grow its business “very quickly.”

“A lot of our peers have taken 15 years to get to 20,000 boepd per day, and we’ve been able to do so in 18 months,” he said. “That continued access to capital will give us a strategic advantage to allow us to continue to not only grow organically but continue mergers and acquisitions as opportunities present themselves that fall within our metrics.”

Growing through M&A activity

Majid Shafiq, CEO of i3 Energy, explained to Stockhouse Editorial that part of i3 Energy’s business model is to grow through acquisitions, which it has been able to do thanks to several acquisitions — including the acquisition of all of the assets of Gain Energy in the WCSB.

The company said it is primarily targeting long-life and low-cost proved developed producing (PDP) assets with robust PUD inventories and a focus on distressed, overleveraged, or non-core asset packages of high API-BTU production streams with low-sustaining CAPEX and decom exposure.

In line with this, i3 Energy has been able to make moves and close acquisitions resulting from low oil prices and — in turn — start a drilling program once oil prices recovered.

This also led the company to acquire assets in central Alberta from Cenovus Energy Inc., a Canadian oil and gas producer, for C$65 million.

While oil and gas prices are “much higher” than they were several months ago, Shafiq said this won’t stop the company from continuing to expand its portfolio through M&A.

“We’re still seeing the opportunity to add accretive barrels via acquisition while we continue to grow production through the drill bit,” he told Stockhouse Editorial.

Posting record Q3 results

As part of the company’s continued growth, i3 Energy recorded impressive results during the third quarter, with average production of approximately 13,740 boepd based on net field sales estimates and September alone averaging approximately 18,985 boepd.

Since the company began acquiring Canadian assets in Q3 2020, i3 Energy has successfully implemented a strategy to offset natural field declines through operational attentiveness, the high-grading of low-cost drilling, reactivation, and recompletion opportunities, and through small-scale bolt-on acquisitions.

Heath told Stockhouse Editorial that highlights from the quarter “show the benefits of being bold at the bottom”. He said buying assets for 1.3x cash flow when oil is between $25 and $30 provides a greater margin of safety.

Essentially, Heath said all that needs to be done to turn a profit is for commodity prices to “do what they’ve done” to make those assets valuable. He added that the company is already seeing those benefits, with the company having produced £12.5 million (CAD$21 million) of net operating income (revenue minus royalties, opex, processing, and transportation) during H1 2021 while forecasting an additional £39 million (CAD$66 million) of net operating income during the second half.

Furthermore, Heath points out that they expect to produce almost CAD$150 million of net operating income from their WCSB assets during the coming 12 months – a figure that substantially surpasses what they have paid for their entire Canadian portfolio.

Future milestones

With 2021 ending soon, Shafiq said several key milestones are coming that investors should watch for, including the announcement of its planned 2022 capital budget for its Canadian assets.

In terms of the UK, Shafiq said that the company expects to further appraise its Serenity discovery in 2022, with its continued UK strategy focussed on the development of discoveries located close to existing infrastructure.

“We’re currently going through a farm-out process to bring in some capital and drill an appraisal well on Serenity, which will hopefully prove up the millions of barrels sitting in that field,” he told Stockhouse Editorial.

Additionally, the company has commenced a project with a consultancy to develop a comprehensive ESG strategy and expects to publish its first sustainability report in Q1 2022.

The management team

Majid Shafiq, CEO

Majid Shafiq has over 30 years of experience in technical and investment banking focused on the global E&P sector.

Before joining Argentil Capital Partners as CEO in 2015, Shafiq spent 12 years in energy investment banking with a focus on advising on asset level acquisitions and divestments and corporate M&A and equity financing for private and public companies in the oil and gas sector.

Additionally, Shafiq worked for Mobil Oil Corporation for 13 years in a range of petroleum engineering and commercial roles. Shafiq holds a bachelor’s degree in Nuclear Engineering from Manchester University, a master’s degree in petroleum engineering from Heriot-Watt University, and an MBA from London Business School.

Graham Heath, CFO

Before co-founding i3 in late 2014, Heath worked as VP of Corporate Development and also as interim CFO at Iona Energy.

At his time at Iona Energy, Heath worked with the senior management team, building the company from infancy to 40MMboe of 2P reserves and production above 6,000 boe per day and listing the company on the TSX Venture Exchange.

Between 1998 and 2010, Heath consulted Colt Engineering, Pan Canadian Petroleum, EnCana Corporation, and Cenovus Energy. Between 2002 and 2006, Heath was co-founder and VP of strategic development for The CO2 Hub, which is a marketplace to facilitate the sale and purchase of carbon dioxide and related purification, compression, storage, and transportation services.

Heath has a Bachelor of Commerce from the University of Calgary.

The investment corner

In short, the company presents itself as a unique opportunity to investors thanks to the unprecedented growth i3 Energy has undergone since making its acquisitions in Canada.

What’s more, i3 Energy implemented dividend payments during 2021, with Shafiq saying that the return of capital to investors is “absolutely fundamental to the company,” adding that i3 Energy will return capital to shareholders as it is generated.

Moving into the next year, Shafiq said investors will have plenty to keep their eyes on when it comes to i3 Energy as it looks to begin drilling and delivering good news from both Canada and the UK, which he said should translate to significant share price growth.

No doubt, i3 Energy is an exciting company to watch for — at a current share price of $0.18, investors won’t want to wait for good news to flow before diving in.

FULL DISCLOSURE: This is a paid article produced by Stockhouse Publishing.

Q&A: Cemvita Factory CEO on Whether Oil and Gas Industry Is Moving Swiftly Enough To Capitalize on Future of CCUS

Moji Karimi, CEO of Houston-based startup Cemvita Factory, talks about the status of oil and gas investments in the emergent technology arena of carbon capture, utilization, and sequestration.

December 2, 2021
By Trent Jacobs
Journal of Petroleum Technology

Is time running short for the upstream industry to move faster

 in its embrace of carbon capture and reuse projects?

Cemvita Factory is a Houston-based startup that has developed a suite of bioengineered microorganisms to convert carbon dioxide into chemical feedstocks. The company recently crossed a major milestone after announcing that its Series A investment round in October put its total cash raised to date over $10 million.

This latest fundraising was led by Energy Capital Ventures and 8090 Partners but also included the venture arms of Mitsubishi Heavy Industries and Occidental Petroleum (Oxy), the latter of which made its first equity investment in Cemvita Factory in 2019.

The company’s CEO and cofounder, Moji Karimi, holds degrees in drilling and petroleum engineering and previously worked with Weatherford International and for reservoir diagnostics firm Biota Technology. He has been an advocate for revamping the oil and gas industry's approach to innovation. In this Q&A, Karimi discusses the promising and not-so-promising developments he sees shaping the industry’s future in the CCUS sector.

What keeps you up at night as a former oil and gas professional who is now leading a CCUS startup?

I’m very happy that I’m doing something that I love, so what’s keeping me up at night is now mostly how to speed up our growth.

It wasn’t always like this though. When we started, it felt like I was the guy in that video where he is dancing by himself, and it takes a bit for people to join one by one but finally everyone is dancing. Right now, almost everyone is on the CCUS dance floor, which is exciting.

According to the International Energy Agency, to hold back global warming the world needs to reach a CCUS capacity of more than 7,600 megatons of CO2 per year compared to today’s total of a mere 40 megatons per year. So when we consider what realizing it ultimately requires, is there a risk that the vision of megascale CCUS is in a hype cycle?

I think there is a spectrum.

The different letters of CCUS are at different stages of market hype and technology development.

On one hand, you have CO2 sequestration and EOR which are fully de-risked, and on the other side you have direct air capture and CO2 utilization which are still being developed.

On that note, I also believe that CO2 storage is just a transitional solution until we figure out how to utilize and convert the CO2 into other valuable products. For that reason, at Cemvita we use the term “CCU$” instead. CO2 storage is a cost, but utilization is a new revenue source.

What’s the biggest factor holding back a more rapid approach to CCUS in the upstream oil and gas industry?

I think the main reason is that oil and gas executives have been reactive, and at best, not aggressive enough. In general, it seems the industry is still doing R&D with a business-as-usual mindset or as if energy transition is similar to a downturn, whereas in reality the industry is going through a massive transformation in the next decade or two.

Incremental improvements that we have relied on in the past won’t work for energy transition. We need radical solutions, and radical solutions call for radical leadership.

Some of the technologies that enable a sustainable energy mix in 2050 may not even be invented yet!

The upstream oil and gas industry has long taken a cautious approach to adopting new technologies due to the risks and capital at stake. Are there other heavy industries with similar challenges that you see as providing a template to move faster on R&D?

Tesla was founded in July of 2003 and SpaceX started in May of 2002. These two companies are less than 20 years old yet have transformed two massive industries with many established players.

That’s the type of innovation and execution that upstream oil and gas needs or we’ll be like the former Nokia CEO who said after being acquired by Microsoft, “We didn’t do anything wrong, but somehow, we lost.”

A tangible example is how the industry looks at the subsurface reservoir. Taking SpaceX as a model, the fundamental problem they solved was by making rockets reusable.

Can we make reservoirs reusable? The industry is pretty much doing no R&D on that.

Do you think the concept of lower-carbon oil and gas products—thanks to the offsetting effects of CCUS—will be warmly embraced by consumers and therefore encourage producers to go further despite the added cost CCUS brings?

No, the oil and gas industry had the opportunity to educate the public about the role that oil and gas play in the progress and prosperity that we all have enjoyed and unfortunately, we missed that window. So that led to the notion for keeping fossil fuels in the ground no matter the carbon footprint.

If you ask the average person on the street about methane, they think it’s a greenhouse gas worse than carbon dioxide and not as natural gas for power generation. The public doesn’t know about the interplay of molecules and electrons.

That said, the reality is that the world will continue to need fossil fuels and feedstocks for a long time and molecules with a lower carbon footprint will have an advantage. So, I’d say oil and gas companies don’t have much of a choice at this point not to invest in CCUS.

Whomever can figure out ways to produce the lowest- carbon hydrocarbons to be used either as fuels or feedstock will win.

If the upstream sector does not retain its role as the leader in CCUS, what other industry could take over?

CCUS is an industry sector in and of itself, but it does present an opportunity to the oil and gas industry for taking a leadership role.

That just makes logical sense, leveraging the existing talent and infrastructure in the oil and gas industry and having access to the CO2 sources. I’ve been saying that since 2018. Only a few companies have taken that leadership role with Oxy being in the forefront.

What about hydrogen production? Is this another potential business line, one some argue is verging on the hype cycle, and something that the upstream sector should not be chasing?

There is a lot of hype about hydrogen but again I think it’s all about the economical pathway that’s being considered for the interplay of molecules and electrons.

The downstream sector is already making hydrogen from methane and that can be coupled with CCUS to make blue hydrogen. Upstream sector plays a role for the storage of the CO2 captured from steam-methane reforming plants, but I don’t see it as a long-term value-add role in the hydrogen economy.

At our own company we are working on other pathways that enable the upstream sector to directly produce hydrogen.

Outside of your own developments, what specific energy transition or clean tech are you most excited about?

There are a few, I really like solutions that leverage the existing infrastructure in oil and gas but repurpose them in a sustainable way.

Geothermal, for example, you’ll still need geologists, drilling engineers, etc. Through our work at Cemvita, I also now think and cover a broader spectrum of energy transition technologies; for example I’m very interested in innovations in the mining sector to sustainably increase the recovery of key metals and minerals needed, then, of course, CCUS and downstream of CCUS for sustainable production of chemicals and polymers.



Trent Jacobs
Trent Jacobs has been a journalist and communications specialist for 15 years, most of which have been spent covering the upstream oil and gas industry. He reports from his hometown of Houston and highlights new trends from the SPE’s largest technical conferences in North America, Europe, Middle East, and Asia. Areas of special focus include emerging technologies, advancements in reservoir engineering, and the energy transition. He can be reached at tjacobs@spe.org

Eamon Ryan opens consultation on Ireland’s use of geothermal energy

Licensing system planned for exploration and capture of heat from below Earth’s crust

about 18 hours ago
Laura Slattery

Iceland’s Blue Lagoon: volcanic regions have long used accessible geothermal energy for industry and recreation. Photograph: Dukas/Universal Images via Getty

The Government has opened up a public consultation on the “exciting potential” of geothermal energy for heating and cooling buildings and for generating electricity.

Minister for the Environment, Climate and Communications Eamon Ryan on Tuesday published a draft policy statement on the use of such energy, which is heat from either the Earth’s core or the sun that is stored by rocks beneath the crust of the planet.

Mr Ryan said he wanted the statement to focus attention on the potential of geothermal energy and address “barriers” to its development in the Republic.
Statement

The statement describes geothermal projects as “expensive” and “subject to more initial uncertainty” than other forms of renewable energy, such as wind or solar power, because they involve drilling into the sub-surface to determine the available energy at specific locations.

It notes “an inherent risk” that any drilling exercise will not produce sufficient heat to make the project commercially viable.

The statement proposes that the Geoscience Regulation Office (GSRO) of the Department of the Environment, Climate and Communications will become the Geothermal Regulatory Authority. Any proposed geothermal project above a certain scale will require an exploration licence from the GSRO and later, if the resource is commercially exploited, a “capture lease”.

The department also intends to establish an advisory group, with members drawn from communities, environmental groups, regulatory agencies and those working on geothermal energy projects.

The overall aim is to “give certainty” about the ownership and use of geothermal energy, create a licensing process for its exploration and harnessing and establish a system of reporting on projects.

The Green Party leader said geothermal energy was “a secure, reliable, local, renewable source of energy” and that technological advances over the past decade meant it could play “a significant role” in the State’s transition to a carbon neutral and circular economy.

“Engagement with the public, community groups, industry and academia is critically important to developing our geothermal potential,” he said.

“I would encourage all interested parties to engage in this public consultation. It is an important step in addressing the barriers to the development of geothermal energy in Ireland. ”

Observations on the draft policy statement can be submitted by email to GSPD@decc.gov.ie until March 1st, 2022, with information sessions and other consultative events expected to take place in February.

Advances

While geothermal energy has long been used in volcanic regions such as in Iceland, Italy and New Zealand – where heat from beneath the earth’s crust is easily accessible – new technologies have seen it adopted in non-volcanic countries, including the Netherlands, Belgium, France, the UK and Germany.

Some of these technologies are already being used in the Republic, from small systems to single houses to larger systems used in industrial and retail buildings. But it is believed the more complex systems with higher output that are seen in other countries could help the State reach its climate goals if replicated here.

The department highlighted a need for greater data collection on the State’s geothermal resources as well as further research on the economics of geothermal energy projects. Although the temperature of the earth is estimated to rise 25 degrees for every kilometre beneath the surface of Ireland, the State’s geothermal potential is “not yet fully understood”.

A study by the Sustainable Energy Authority of Ireland found that up to 54 per cent of domestic, commercial and public sector demand for heating in Ireland could be met by district heating systems, with geothermal energy an important source of heat for this.

Geothermal energy can also be used for multiple industrial activities such as drying cement blocks, heating greenhouses, processing dairy products and brewing beer.

Recent Maryland earthquakes have been mild, but in 1886 one made some in Baltimore think their homes were haunted
By FREDERICK N. RASMUSSEN
BALTIMORE SUN |
AUG 26, 2021 AT 5:00 AM

Severe Maryland earthquakes are fairly rare, which ensures that they make headlines whenever one rumbles across the region.

A 2.6 magnitude earthquake rattled the area June 25, followed two days later by a 1.7 aftershock whose epicenter was near the Edmondson Village Shopping Center in West Baltimore, reported the U.S. Geological Survey.

Earlier this month, a 2.1 magnitude quake struck near Clarksville in Howard County. Its epicenter was Heritage Heights Park and could be felt as far north as Eldersburg and southward to Silver Spring.

No injuries or damage resulted from the earthquakes, which were deemed minor. According to the USGS, a 5.3 quake is considered moderate while a quake registering 6.3 on the Richter scale is classified as a strong one.

The Maryland Geological Survey classifies the mid-Atlantic and central Appalachian region as having a “moderate amount of low-level earthquake activity.”

The first reported quake in Maryland occurred April 25, 1758, striking south of Annapolis, but there are no records as to its strength, according to the Maryland Geological Survey. Experts estimate its magnitude was probably a 3.5 or 3.7. The strongest confirmed temblor was a 3.1 that rolled through Hancock in Western Maryland in 1978.

“What accounts for the earth’s rocking and rolling beneath Maryland at times can be blamed on the Marticville line, two rock strata that roughly parallel the Mason-Dixon Line,” The Sun reported in a 1986 article.

The earthquake that Baltimoreans would talk about for years wasn’t even from around here.

It was the great Charleston, South Carolina, earthquake of Aug. 31, 1886, that jangled nerves not only in Baltimore, but as far north as Boston, and westward to Chicago and Milwaukee, and as far south as New Orleans.

The jolts from that quake, estimated to be a magnitude of 7.0, were felt even in Cuba and Bermuda.

Starting at 9:50 p.m., the quake rumbled northward and by the time the shaking arrived in Baltimore at 10:05 p.m., it literally threw residents out of their beds and crashed dishes to the floor from cupboards, prompting the terrified to flee into the street thinking their houses were haunted, The Sun reported.

For an hour after the seismic event unfolded, phones rang wildly in the city room of the newspaper then located in the Sun Iron Building on East Baltimore Street, from the frightened and curious, seeking more particulars on what transpired.


Cracks from the August 2011 earthquake spread in the basement of the Baltimore Basilica, six years after a $40 million restoration of the oldest Catholic cathedral in the nation. A device monitors structural shifts. (Kim Hairston / Baltimore Sun)

“Coming as the shaking did at a time of the year when malaria is supposed to stalk about, it was suggested that, perhaps the earth was having its little malarial attack due to the sudden drop in the thermometer yesterday,” reported The Sun the next morning. “Whatever caused the shock there was a very perceptible tremor of the earth about five minutes past ten o’clock and continued about half a minute.”

At Guilford, which was the summer estate of A.S. Abell, founder of The Sun, the house rattled while the chandeliers swayed to and fro, reported an astonished Abell.

An Oak Street resident telephoned his North Charles Street pharmacy and “received the intelligence that the bottles in the establishment were dancing as if in high glee,” reported the newspaper.
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A man living near the intersection of Broadway and Bank Street thought he was suffering an attack of vertigo as his desk moved from side to side while he was working. Another man sitting in his home was made “giddy” as his chair slid across the room while pictures on the wall bounced up and down from the vibration.

Young women dancing at 146 N. Charles St., stopped as soon as the floor began quivering beneath their feet, and on Barre Street, a Mrs. Buckey’s bed shook so violently that she thought a man was hiding underneath it, reported The Sun.

Frederick County farmers told the newspaper the quake shook for a duration of more than two minutes while reports came in from Cambridge that it had caused “nausea with a number of people who had been sleeping.”

For one Baltimorean, the quake proved to be a good thing. For years, a Mr. Thackermann had been bedeviled by two windows in his Eutaw Street office that he had been unable to close; they suddenly fell with a crash.

The captain of an inbound steamer, the Ewing, a revenue cutter approaching the bay, gave this account to The Sun of the quake’s strike.

“A strong gale came from the north. All at once there was a strange and weird appearance about everything. Nothing looked natural. In the heavens the stars were shooting in all directions, and the breaking seas were charged with phosphorus to such a pronounced degree that no one on board recollected ever seeing such a display,” he said.

While the quake killed 38 Charlestonians, wrecked telegraph lines and railroad tracks and cut the city off from the outside world, damage in Baltimore was mainly confined to broken crockery, glassware, and, in many cases, jangled nerves.


Frederick N. Rasmussen
I am one of The Sun's obituary reporters and have been writing them since the early 1990s. I attended Emerson College in Boston and wrote for Boston Magazine. I also was the author for nearly 20 years of The Sun's Back Story column.

Strange earthquakes in South Carolina traced to man-made lake

Lake Monticello in South Carolina has now caused three earthquake swarms.

Monticello reservoir in South Carolina at sunset.

 (Image credit: Zoonar GmbH / Alamy Stock Photo)

By Stephanie Pappas published November 05, 2021

A series of small earthquakes northwest of Columbia, South Carolina, are caused by a man-made lake built more than 40 years ago, according to geologists.

The tiny temblors — magnitude 2.0 and less — are jangling nerves near South Carolina's Lake Monticello, according to The State newspaper, but the tremors are not unprecedented. The reservoir set off a series of minor earthquakes when it was first filled in the late 1970s. Another small swarm occurred between 1996 and 1999. Since Oct. 25, there have been seven earthquakes detected near the lake, according to the South Carolina Department of Natural Resources.

These quakes are so small that someone standing on the surface might only notice them if they were right over the epicenter and there was no rumbling traffic nearby.
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"We haven't had any large earthquakes at Monticello," said Pradeep Talwani, a professor emeritus of geology at the University of South Carolina who spent his career studying earthquakes caused by man-made lakes. Going all the way back to 1977, all of the quakes in the 

Reservoir-induced seismicity

What's happening at Lake Monticello is called "reservoir-induced seismicity." This phenomenon happens at relatively few reservoirs around the world, Talwani told Live Science. Regardless of location, the physics are always the same: A reservoir is built over rocks that contain fluid-filled fractures. When more water is loaded on top, it seeps into the fractures, causing the fluids to migrate and build up pressure. Ultimately, the pressure causes the rocks to slip and rattle the surrounding earth. This is the same reason that pumping fluids into oil wells for the purpose of fracking can cause earthquakes.

Mostly, these man-made earthquakes are small. Globally, only three reservoir-induced quakes with a magnitude of 6 or higher have ever occurred, Talwani said. (Earthquake damage can vary based on the local conditions and building materials, but magnitude 6 is typically the line at which serious damage occurs.) These damaging quakes occurred at deep reservoirs with more than 328 feet (100 meters) of water, Talwani said. In comparison, Lake Monticello is 89 feet (27 m) deep at its deepest.

"Compared to everything globally, Monticello is a little puddle," Talwani said.

Watching for quakes

It has been, however, a very well-monitored puddle. Researchers first learned about reservoir-induced seismicity in the 1960s in Denver, Colorado. Operators at a chemical weapons facility called the Rocky Mountain Arsenal drilled a deep well and began injecting waste fluid into what turned out to be highly fractured rock, triggering more than 700 earthquakes in five years, according to a 1966 article in the journal The Mountain Geologist.

Thus, scientists knew about the possibility of reservoirs triggering earthquakes by the time Monticello was constructed. Talwani and his team were already monitoring and studying small swarms at reservoirs such as Jocassee near the North Carolina-South Carolina border.

Lake Monticello was constructed in the 1970s as a water source for the nearby Virgil C. Summer Nuclear Power plant. Because scientists already knew that reservoirs could produce earthquakes, the Nuclear Regulatory Commission required careful monitoring of seismicity in the area. Talwani's research group conducted most of this monitoring, which gave them a stunningly detailed view of tiny earthquakes that wouldn't normally be picked up by U.S. Geological Survey equipment.

The lake has been the source of thousands of tiny quakes over the years, most far too subtle to be felt. The initial swarm of earthquakes after the reservoir filled wasn't surprising. But the quakes in the 1990s, 20 years after Lake Monticello was constructed, were a little more mysterious. Thanks to their detailed seismic monitoring, Talwani and his colleagues were able to figure out what had happened. Over time, they found, water from the lake had dissolved mineral "caps" that had been sealing off fractures in the rock. With these new fractures opened, water was able to move into them, again building up pressure and causing the rocks to slip.

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Something similar is probably happening at Monticello now to cause the new earthquakes, Talwani said. However, it's impossible to say because the fine-grain seismic monitoring system is no longer in place. That means researchers can see only the largest quakes, not the miniscule ones that help them localize the origin of the seismicity.

"Now we have no idea what is going on, because we just have one [seismic] station in that area," Talwani said.

Researchers at the University of South Carolina may soon deploy more seismometers in the area, said Scott Howard, a state geologist at the South Carolina Department of Natural Resources. The quakes are likely to peter out or continue at the current levels of magnitude, Howard told Live Science.


Originally published on Live Science.

FRACKQUAKE

Latest quake in top U.S. oilfield to hike scrutiny of drilling waste injections

© Reuters/Angus Mordant

By Liz Hampton

(Reuters) - A magnitude 4.5 earthquake that rattled the Permian basin in Texas on Monday night is likely to add pressure on oil producers in the region to slow or stop underground wastewater injections that regulators believe may cause the tremors.

The quake, the third-largest to hit Texas this decade, occurred near Stanton and was the latest in a surge of temblors linked to the disposal of wastewater, a byproduct of oil and gas production. Wastewater injection can trigger quakes by changing pressures around fault lines.

It also comes shortly after the state Railroad Commission, which regulates its oil industry, halted the injection of water into deep wells in an area northwest of Midland amid the jump in seismicity.

The Commission on Tuesday said it had been in contact with disposal well operators in the affected area of the Permian and was sending inspectors to the facilities.

Monday's earthquake occurred in an area already under investigation by the Commission for increasing seismicity. A suspension of injections around its epicenter could impact some 18 active wells that dispose an average of 9,600 bpd each, according to water data and analytics firm B3 Insight.

The affected area "has a higher utilization of deep disposal - about 50% higher - than other areas in the Permian basin," said Kelly Bennett, CEO of B3.

Permian oil operators are already looking for ways to reduce wastewater injections after the oil regulator began imposing limits. Solutions include recycling the wastewater or trucking it elsewhere.

"If they're not able to do that, they may have no other choice but to shut these wells and choke production," said Thomas Jacob, vice president of oilfield services research for consultancy Rystad, adding that halting production was a last resort.

ConocoPhillips has 15 disposal wells in the region, where injections have been suspended, while rival Pioneer Natural Resources has eight, according to Rystad. Chevron and Coterra have both experienced a reduction of 400,000 bpd or more in disposal capacity as a result of the limits imposed by the Railroad Commission.

Texas regulators are closely watching other regions that have seen a jump in seismicity and could implement additional limits to saltwater disposal, particularly as quakes get stronger, analysts cautioned.

"It will put more pressure on the operators" to find other ways to handle water, said Fredrik Klaveness, CEO of NLB Water, which provides produced water treatment and recycling solutions for the oil industry.

(Reporting by Liz Hampton in Denver; Additional reporting by Marcy de Luna in Houston; Editing by Dan Grebler)