In 2010 the Deepwater Horizon oil spill released an estimated 4.2 million barrels of oil into the Gulf of Mexico – the largest offshore spill in U.S. history. The spill caused widespread damage to marine species, fisheries and ecosystems stretching from tidal marshes to the deep ocean floor.
Emergency responders used multiple strategies to remove oil from the Gulf: They skimmed it from the water’s surface, burned it and used chemical dispersants to break it into small droplets. However, experts struggled to account for what had happened to much of the oil. This was an important question, because it was unclear how much of the released oil would break down naturally within a short time. If spilled oil persisted and sank to the ocean floor, scientists expected that it would cause more extensive harm to the environment.
Before the Deepwater Horizon spill, scientists had observed that marine bacteria were very efficient at removing oil from seawater. Therefore, many experts argued that marine microbes would consume large quantities of oil from the BP spill and help the Gulf recover.
In a recent study, we used DNA analysis to confirm that certain kinds of marine bacteria efficiently broke down some of the major chemical components of oil from the spill. We also identified the major genetic pathways these bacteria used for this process, and other genes, which they likely need to thrive in the Gulf.
Altogether, our results suggest that some bacteria can not only tolerate but also break up oil, thereby helping in the cleanup process. By understanding how to support these natural occurring microbes, we may also be able to better manage the aftermath of oil spills.
Finding the oil-eaters
Observations in the Gulf appeared to confirm that microbes broke down a large fraction of the oil released from BP’s damaged well. Before the spill, waters in the Gulf of Mexico contained a highly diverse range of bacteria from several different phyla, or large biological families. Immediately after the spill, these bacterial species became less diverse and one phylum increased substantially in numbers. This indicated that many bacteria were sensitive to high doses of oil, but a few types were able to persist.
We wanted to analyze these observations more closely by posing the following questions: Could we show that these bacteria removed oil from the spill site and thereby helped the environment recover? Could we decipher the genetic code of these bacteria? And finally, could we use this genetic information to understand their metabolisms and lifestyles?
To address these questions, we used new technologies that enabled us to sequence the genetic code of the active bacterial community that was present in the Gulf of Mexico’s water column, without having to grow them in the laboratory. This process was challenging because there aremillions of bacteria in every drop of seawater. As an analogy, imagine looking through a large box that contains thousands of disassembled jigsaw puzzles, and trying to extract the pieces belonging to each individual puzzle and reassemble it.
We wanted to identify bacteria that could degrade two types of compounds that are the major constituents of crude oil: alkanes and aromatic hydrocarbons. Alkanes are relatively easy to degrade – even sunlight can break them down – and have low toxicity. In contrast, aromatic hydrocarbons are much harder to remove from the environment. They are generally much more harmful to living organisms, and some types cause cancer.
We successfully identified bacteria that degraded each of these compounds, and were surprised to find that many different bacteria fed on aromatic hydrocarbons, even though these are much harder to break down. Some of these bacteria, such as Colwellia, had already been identified as factors in the degradation of oil from the Deepwater Horizon spill, but we also found many new ones.
This included Neptuniibacter, which had not previously been known as an important oil-degrader during the spill, and Alcanivorax, which had not been thought to be capable of degrading aromatic hydrocarbons. Taken together, our results indicated that many different bacteria may act together as a community to degrade complex oil mixtures.
Neptuniibacter also appears to be able to break down sulfur. This is noteworthy because responders used 1.84 million gallons of dispersantson and under the water’s surface during the Deepwater Horizon cleanup effort. Dispersants are complex chemical mixtures but mostly consist of molecules that contain carbon and sulfur.
Their long-term impacts on the environment are still largely unknown. But some studies suggest that Corexit, the main dispersant used after the Deepwater Horizon spill, can be harmful to humans and marine life. If this proves true, it would be helpful to know whether some marine microbes can break down dispersant as well as oil.
Looking more closely into these microbes' genomes, we were able to detail the pathways that each appeared to use in order to degrade its preferred hydrocarbon in crude oil. However, no single bacterial genome appeared to possess all the genes required to completely break down the more stable aromatic hydrocarbons alone. This implies that it may require a diverse community of microbes to break down these compounds step by step.
Back into the ocean
Offshore drilling is a risky activity, and we should expect that oil spills will happen again. However, it is reassuring to see that marine ecosystems have the ability to degrade oil pollutants. While human intervention will still be required to clean up most spills, naturally occurring bacteria have the ability to remove large amounts of oil components from seawater, and can be important players in the oil cleanup process.
To maximize their role, we need to better understand how we can support them in what they do best. For example, adding dispersant changed the makeup of microbial communities in the Gulf of Mexico during the spill: the chemicals were toxic to some bacteria but beneficial for others. With a better understanding of how human intervention affects these bacteria, we may be able to support optimal bacteria populations in seawater and reap more benefit from their natural oil-degrading abilities.
Postdoctoral Fellow, University of Texas at Austin
Assistant Professor of Marine Science, University of Texas at Austin
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline