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(Journal of Petroleum Technology) As ExxonMobil announced discovery after discovery offshore Guyana, it sounded easy.

Beginning with the Liza-1 discovery well, the giant oil company announced 16 successful exploration wells. There were four or five successful wells per year from 2017 through 2019, ending with news of its 16th find in January—pushing its estimated oil in the ground to 8 billion bbl.

For those who found the oil, the evidence they used to pick those drilling targets was hardly clear cut, and it took more than 90 years to get to that point.

“In retrospect it wasn’t obvious, and that was why it took so long,” said Maria Guedez, exploration manager for Guyana and Suriname for ExxonMobil.

While a timeline of the Guyana project includes “initiated oil and gas exploration activities in Guyana in 2008,” the story ExxonMobil presented at the recent AAPG SuperBasins 2020 conference covered exploration starts and stops going back to 1928 by the company’s predecessor, Standard Oil Co.

One slide showed a typewritten report from the 1930s noting the test wells were “salted,” giving the impression of a rich reservoir, even though “there is no evidence of oil.”

But ExxonMobil and other oil companies kept coming back. There were dry holes in the 1970s off nearby Suriname—the eastern extension of the play. They saw some positive signs, but the source rock was judged to be not mature enough to fill the conventional oil deposits needed to justify development.

Finally, in the 1990s ExxonMobil geoscientists looking for new exploration opportunities used what had been learned, plus advanced seismic imaging, a better understanding of the movements of tectonic plates, and some simple analysis to outline a plan that ultimately led to the discovery.

Guedez showed a picture of a simple chart evaluating the pros and cons of the basin with handwritten notes, and a geologic cross section in which a geologist hand-counted layers in shallow and deep waters to identify the elements of a productive play.

“New data and technologies often trigger key insights, but you need to ask the right questions,” Guedez said. “Sometimes you don’t need massive amounts of data to make a difference.”

Executing the concept required developing the ability to drill wells in water 8,000 ft deep and high resolution to seismic that allowed interpreters to see the subtle signs of hydrocarbon-rich stratigraphic traps.

“The places where you have structure, it was hard [to spot anomalies]. Stratigraphic traps are normally just really difficult to explore. It was going to be difficult to hit without ­having some sort of high-resolution 3D seismic,” Guedez said.

These anomalies are never easy to spot, but she said that compared to her experience in offshore Africa, signs of traps off Guyana were “remarkably subtle.”

So far, they have hit on 89% of the wells drilled. “Once the eyes of the team got fine-tuned to that, they did a good job spotting them,” Guedez said.

Super Basin?

Guyana and Suriname are at the top of the list of the hottest exploration plays. Robert Fryklund, vice president and chief upstream strategist for IHS Markit, predicts reserves will reach 10–12 billion BOE—off Guyana, as ExxonMobil and ­others continue to drill.

It does not qualify for AAPG’s strict definition of a super basin—5 billion BOE produced and the ability to produce 5 billion more—but it is likely to get there.

Just to the west is Venezuela, which is home to multiple super basins. Oil companies are chasing far smaller targets off Guyana because Venezuela is lacking critical ingredients needed to facilitate development. It has shut out international oil companies, and the economy is in such a state of disarray that the national oil company is struggling to continue producing oil, much less look for more.

Still, Venezuela’s potential is dumbfounding. Potential resource estimates of its super basins are often in the tens of billions, including deepwater plays and an area with an estimated 67 billion bbl in hydrocarbons in the ground that has hardly been drilled, said Jairo Lugo, a former PDVSA geoscientist whose consulting firm is LatAm Oil and Gas.

Other countries are willing but not able to attract interest from an industry which is not in a rush to go hunting internationally for oil. Chastened by investors who demand profits over growth, the industry in general is cautious. Some operators are betting big on unconventional production and are focused on finding a way to generate significant profits from it.

“Ten years ago, how we do exploration changed—some of that is due to unconventionals, but a lot of it was the challenge of what should exploration be doing,” Fryklund said.

As a result, Hess, which is an ExxonMobil partner in ­Guyana, shrunk its global operations to the US Gulf of Mexico, the Bakken, and Guyana.

“People are not roving all around the world anymore,” Fryklund said. Countries seeking to attract international oil companies need to offer terms that balance the risk with the rewards.

Guyana’s terms are inviting. Critics say the country should be gaining more financial benefit, while ExxonMobil points out that the terms reflect the risks at a time when the industry is shunning frontier plays. And the long-lived wells produce mostly oil, in a world where the giant finds have tended to be less-valuable gas.

“We are still very good at ­finding gas but not so good at finding oil,” Fryklund said.

Financial Juggling

ExxonMobil’s partners include Hess, an independent whose Guyana discoveries will be “transforming,” but there are big bills to pay first. Development costs over the next decade may total $15 billion for Hess, according to a recent estimate by Rystad, which said ExxonMobil would need to spend $23 billion.

Profitable transformation is a good “problem” to have, but a challenging one at a time when oil prices crashed as demand evaporated, forcing deep cuts in exploration and production budgets at Hess and ExxonMobil, which have not touched their Guyana development program.

The startup of the first production platform in Guyana’s Liza field late last year, which is expected to produce more than 100,000 B/D, will help alleviate some of that pressure.

“It was four years from discovery to first oil, thank goodness we have a great operator,” said Barbara Lowery-Yilmaz, senior vice president for exploration at Hess, during a speech at the conference.

But that will not cover the cost of a plan to produce 750,000 B/D by adding four more floating production platforms in 2025. Hess’ plan for paying the bill requires executing a series of exploration and production steps, she said.

That plan will need to be revised.

Hess had planned to use cash flow from the Gulf of Mexico to fund a rapid expansion in production from its Bakken operation, which would then have been used to pay for the Guyana development.

The deep price drop will reduce the offshore revenue and prompted Hess to cut its Bakken operation from six rigs working to one.

On the upside, the scale of the Guyana discoveries is expected to deliver inexpensive barrels. Hess estimates that the interlocking operations provide a sufficiently large scale to reduce the cost of a talented team plus seismic to less than $2/bbl, and in which the risks associated with exploring and development are manageable. “It is important for us to explore in a disciplined manner,” Lowery-Yilmaz said.

Source: Journal of Petroleum Technology

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