In a quest to see if existing plays in Africa and South America could be extended, two operators combined creative thinking and seismic technology to unlock prospective areas – revealing successful discoveries with tremendous potential.
Sharing their strategies and innovative ideas at the Discovery Thinking forum at the recently held International Meeting for Applied Geoscience and Energy in Houston, their presentations aimed to inspire a new wave of discoveries around the globe.
“Discovery Thinkers are fascinated by developments in Namibia, where play fairways may offer world-class opportunities and golden lanes,” said Charles Sternbach, AAPG past president, co-chair and originator of the Discovery Thinking forum. “The question becomes, ‘Where next?’ These are all topics designed to help explorers stamp their passports to global exploration.”
Namibia
Ten years ago, had a geoscientist seen a composite 2-D seismic line of the Northern South Africa Orange Basin off the coast of Namibia, its prospects would have looked dim. Divided by the Outer High basement ridge, the basin appeared to have a cold oceanic crust; no known generative source rocks over the oceanic crust; and no oil-mature source rocks south of the Walvis Volcanic Ridge. There was no known potential in the passive volcanic margins; a thin overburden; and the basin was more than 150 kilometers from the shore – too far from a good quality reservoir.
Yet in 2022, Shell and TotalEnergies announced major discoveries in this basin outboard of the Outer High. Venus is estimated to have 1.5 to 2 billion barrels of oil, and Graff is estimated to have 700 million barrels.
“This was the grand finale of a longstanding debate in which model and data fought a hard battle,” said Karyna Rodriguez, vice president of Global New Venturers at Searcher Seismic.
Today, as seismic data continues to advance, it has entered the realm of derisking prospects, and it is giving data the upper hand over models in new frontiers.
Before moving into the basin, the Searcher team used seismic data for the first time to derisk the Orange Basin’s Aptian source rock, which supplies both the Venus and Graff plays. “Let’s try it, and let’s try it in Namibia because we have wells that have encountered the source rock and we can do some calibration,” Rodriguez said. “The data was screaming, ‘Here I am! I am full of hydrocarbons!’ But the models were saying, ‘No, that’s not possible.’”
So, what was the lesson learned?
“It is important to look at our data,” she said.
“When you are in a frontier area, there are three things we look at: No. 1 is source rock. No. 2 is source rock. No. 3 is source rock,” she said. “If there is source rock in the basin, we enter because the rest will fall into place. We can always find structures and we can always find reservoirs.”
Before entering, derisking the Aptian source rock was a crucial step, Rodriguez said. This included plate tectonic reconstruction and analysis of the tectonostratigraphic evolution to identify suitable depositional environments.
Conjugate margin evidence was key along with data from wells that encountered a thick interval of the Aptian. Geochemical seabed sampling, coring results and naturally occurring oil seeps also were considered, she said.
Yet the strongest information came from seismic data that identified a regional high amplitude soft kick event associated with an amplitude versus offset Type IV anomaly, calibrated with all the wells in the basin and considered to be a positive source rock character, Rodriguez noted. All strongly indicated the presence of a world-class source rock.
The evidence that suggested the Aptian source rock extended out over oceanic crust defied all existing models for hydrocarbon generation. “However, the seismic data available in this deepwater setting, when converted to depth to correct the geometry at depth, not only showed the Outer High as a structurally high feature, but also pointed to turbidites in huge counter-regional dipping traps,” Rodriguez said.
The Venus basin play exceeded all expectations, finding two fan sequences with significant net pay. Graff, a slope play, was the first to confirm that the Aptian was a world-class source rock, and that all of the elements in the Venus petroleum play were present.
After the two discoveries, Galp, in partnership with Custos Energy and state-owned NAMCOR, began looking at what it was hoping would be the third play in the Orange Basin: Mopane.
A “very high quality” off-the-boat, fast-track, post-stack time migration 3-D dataset acquired in 2022 indicated that the world-class Aptian source rock extended to the east and inboard of the Outer High. The seismic event, inferred to be a source rock, was interpreted as a regional AVO Type IV high amplitude anomaly. The trapping mechanism was observed to be structural and stratigraphic, Rodriguez said.
At a 2023 conference in Namibia, Galp announced the results of the two wells it drilled. “Every single sand they encountered was full of hydrocarbons. And they even had sub-seismic resolution sands, which they did not expect to find,” Rodriguez said. “This is a huge, huge discovery. It’s really going to change Namibia together, with Venus and Graff.”
Galp estimated earlier this year that accumulations are in order of 10 billion barrels of oil equivalent or higher. If confirmed, Mopane would be one of the largest offshore discoveries.
A 2023 3-D survey covering part of the Mopane “channel complex” clearly indicates anomalies associated with the proven accumulations, Rodriguez said. In fact, the Aptian source rock and its associated play type can be “confidently” extrapolated into a very large area extending all the way into South Africa, she added.
Seismic data strongly indicates a potential second source rock: the Barremian. Both the Aptian and Barremian “light up” on the seismic data, indicating that there could be another play type below the Aptian source rock.
“This, together with anomalies seen in the fold and thrust belt, could be secondary objectives when they drill the Mopane extension,” she said.
Rodriguez also showed that the Mopane play has potential in Uruguay. “We can see the extension and continuation of the Mopane play into the Punta del Este Basin,” she said, hinting that it is being targeted by Chevron, Shell and APA.
“We have heard that Guyana has been called the ‘Golden Lane’. That’s proven. It’s got billions of barrels of oil. But here (in the Orange Basin), we have three future Golden Lanes and each of these is already proving to have billions of barrels of oil,” she said. “This is going to be an interesting area to watch because we will hear of a lot more success here.”
Suriname
Following the 2015 oil discovery of Liza in Guyana by ExxonMobil, TotalEnergies and APA Corporation came together to explore this play extension into Suriname. Determined, they drilled a total of 14 exploration and appraisal wells in four years that resulted in five discoveries.
While they credit their discovery of approximately 700 million barrels of oil to effective communication with stakeholders, integrated work across multidisciplinary teams and a robust geological and geophysical dataset, the ultimate key to their success was the innovative thinking that pushed them out of their comfort zones and into Suriname’s first deepwater project.
“Our goal from the beginning was to swiftly unlock a developable project, which we did,” said TotalEnergies’ Suriname Exploration Manager Leonardo Caixeta. “We acquired key information as early as possible. This allowed us to accelerate decisions and planning. When you are trying to accelerate projects with a compressed timeline, you tend to discard information that you don’t understand. But to achieve success, all information needs to be integrated, and sometimes the learning process is uncomfortable.”
In 2015, APA entered the 5,800-square kilometer Block 58 in Suriname, which is 120 kilometers offshore in water depths from 80 to 2,000 meters. TotalEnergies joined the venture in 2019, just before the first offshore oil Discovery on the block, Maka Central-1. The team went on to drill 13 additional wells in an “intense drilling campaign” that confirmed the presence of a prolific petroleum system, stratigraphic traps and good reservoir quality, Caixeta said.
Lacking structural elements, they had to derisk the prospect and determine the nature of its traps, the depositional environment of the basin, and its complex overburden.
Finding the limits of the sand deposits in the stratigraphic traps was crucial.
To assess subtle traps, they relied heavily on the integration of diverse data. They looked at amplitudes, direct hydrocarbon indicators, and inversion products. All proved helpful to a point – but the team needed to see how the reservoir was behaving dynamically. This required an extensive collection and integration of well and seismic data, Caixeta explained.
“Drilling 14 wells in four years is a lot of data to digest. So, integration needed to be taken on a case-by-case basis,” he said. “Every time we drilled a well, we updated our models to better understand the basin. It was all about learning. Costly learning. Every reprocessing effort made it into our data.”
Yet, there is a limit to how much data can be integrated, and the team wanted the clearest understanding of the geology. They needed to ensure their models would be predictive. “The devil is in the details, especially with stratigraphic traps,” Caixeta said.
Another result of the exploration and appraisal campaign is that “we were pushed to innovation,” he said. For the first time, they turned to machine learning and AI-based inversions. “Machine learning products showed to be very robust. It put us in a different context, and we were able to process a wealth of seismic and well log information,” Caixeta said.
At first, the team used data from 12 wells, more than 100 seismic attributes and more than 11,000 observations from well logs. “This gave us a lot more processing power, and the result was more predictive. We could see better definition of the sands and a better position of the petroleum system,” he said. “Machine learning predicted reservoir presence better than conventional approaches.”
Between 2019 and 2023, five discoveries were made, including the two main discoveries of Sapakara South in 2021 and Krabdagu in 2022 in Block 58. A successful appraisal program followed and delineated sufficient resources to launch front-end engineering and design studies for development.
Wood Mackenzie has projected that by 2030, Block 58 will make Suriname the sixth-largest deepwater liquids producer in the world. “This is a big change for the country that was producing onshore 16,000 barrels per day,” Caixeta said.
“We have our hands on enough information now to keep things moving,” he added. “We will use machine learning in our screening in the future.”
TotalEnergies has since acquired Blocks 6, 8 and 64 to extend the play. Because of the knowledge acquired on Block 58 and newly developed AI technology, Caixeta said, “we can be more assertive in nearby exploration, and we are moving more and more into a frontier play. We are investing in the region to make the best out of it.”