In an effort to highlight the creativity and evolving technology used by explorers to make significant discoveries around the globe, the Discovery Thinking forum highlighted some of the most impressive discoveries at the recent International Meeting of Applied Geoscience and Energy. Areas of focus included the eastern Mediterranean, the North Slope, Namibia and the Black Sea.
“Our goal was to integrate geology and geophysics to highlight case studies of success,” said Charles A. Sternbach, AAPG past president and chair of Discovery Thinking. “The speakers told captivating discovery stories.”
Eastern Mediterranean
Andrea Cozzi, head of the Exploration Strategic Evolution Unit of Eni, spoke about the last 70 years of exploration in the eastern Mediterranean Basin that have led to multiple rejuvenation phases and the discovery of giants. Throughout its exploration history, the eastern Mediterranean Basin has seen more than 600 wells drilled, approximately 200 discoveries and 150 trillion cubic feet of gas finds. In fact, in a testament to patience and perseverance, Cozzi said that the largest discoveries came in the last two decades, emphasizing the importance of never giving up. The majority of discoveries have been offshore in the Nile Delta in the Oligocene and Lower Miocene formations.
The Messinian play is the longest-lived play – beginning in 1967 with the giant Abu Madi discovery made by Eni, the first commercial discovery in the Nile Delta – and going through several rejuvenation phases with 146 exploration wells drilled until its most recent discovery, Nooros in 2015. Approximately 2.5 billion barrels of oil equivalent have been discovered in the Messinian play to date.
The Plio-Pleistocene play was opened with the 1997 Denise discovery made by Eni – the first Pliocene gas discovery in the East Nile Delta. The Ha’py and Sapphire discoveries followed. The years 1997 to 2006 marked the “golden age” of Pliocene exploration, Cozzi said, with 35 trillion cubic feet of recoverable resources found.
The Oligo-Miocene (Levantine) pre-salt play produced gas and gas condensate from clastic reservoirs in structural and stratigraphic traps. Approximately 145 exploration wells were drilled from 1967 to 2007 and from 2009 to 2023, and 60 trillion cubic feet of recoverable resources were discovered. Some of the giant Levantine discoveries occurred from 2009 to 2011 and include Aphrodite with 3.5 trillion cubic feet, Leviathan with 21 trillion cubic feet and Tamar with 10 trillion cubic feet. Many of these discoveries changed the economic fate of Israel, allowing the country to transition from a gas importer to an exporter for the first time, Cozzi said.
Exploration of the Mesozoic Carbonate Play has spanned from 2015 to current day and has shown a “very high rate of success,” with the play opener Zohr discovery made by Eni in 2015 with 30 trillion cubic feet, the largest ever made in the eastern Mediterranean Basin, which targeted a carbonate build-up on an intra-basinal high.
“Zohr came like a meteor strike out of the blue,” Cozzi said, “demonstrating that giants can continue to be discovered in the eastern Mediterranean when new plays are pursued.”
Following Zohr, the discoveries of Onesiphoros in 2017, Calypso in 2018 and Cronos and Zeus in 2022 were made.
Exploration in the eastern Mediterranean has not been without challenges, though. For example, exploration in the Pliocene was delayed by a lack of a gas market in Egypt; exploration in the Levantine was delayed for geopolitical reasons; exploration in the Oligocene was delayed because of operational challenges and geopolitical complexity; while exploration in the Mesozoic was delayed because of pure “lack of imagination” Cozzi said.
“The exploration of the eastern Mediterranean is poli-cyclic, controlled by the discovery of new exploration plays,” Cozzi explained. “The basin creaming curve is still emerging after 60-plus years of exploration, with a stepped gradient. The largest discoveries have been made 50-plus years after the beginning of exploration, and the water depth beyond 1,000 meters remains poorly explored.”
“Exploration concepts that today might look obvious took decades of exploration before commercial success was achieved,” he added. “The eastern Mediterranean basin was considered a mature basin many times in this 60-plus years of exploration history. However, it was rejuvenated several times by new exploration concepts and ideas.”
Alaska
While Prudhoe Bay on Alaska’s North Slope might go down in history as the largest, onshore, conventional oilfield in the United States, Bill Armstrong, president, CEO and founder of Armstrong Oil and Gas, Inc. said a succession of new fields being discovered could, in aggregate, compete for that title.
While Prudhoe Bay is a combination structural-stratigraphic trap, new fields are being found in multiple stratigraphic traps in the Nanushuk formation – holding billions of barrels of oil, he said.
In a fairway north of the Brooks Range and south of the Beaufort Sea, stretching from the National Petroleum Reserve Alaska in the west to the Arctic National Wildlife Refuge in the east, hundreds of clinoforms and subclinoforms are all but unexplored.
Recalling the Armstrong/Repsol Pikka discovery in a Nanushuk topset in 2013, Armstrong said the available 2-D and 3-D seismic data at the time of the discovery had a difficult time imaging the trap. Geologists relied on regional geology and shows from nearby updip wells drilled by other operators to identify the opportunity. The Pikka wildcat well hit a clinoform shelf margin that dramatically expanded into a thick oil-saturated sandstone with “great porosity and permeability,” he said.
Following the discovery, Armstrong/Repsol reprocessed vintage 3-D data and shot new high effort 3-D seismic focusing on the Nanushuk interval. Once integrated with the new well information, the Nanushuk pay sand could be seen using amplitude versus offset analysis, Armstrong said.
The Qugruk 3 Pikka discovery well was followed up with a 21-mile stepout, the Horseshoe No. 1 well, which found the same Nanushuk oil-saturated sand in the same pool as Pikka. Following multiple delineation and appraisal wells, the current limits of the Pikka discovery are roughly 40 miles long by 10 miles wide. It is poised to become the third largest oilfield in the history of the United States with 3.3 billion barrels of recoverable oil, he said.
Modern seismic data is leading the way in finding subsequent new discoveries including the 750-million-barrels-of-oil Willow Field by Conoco Phillips in 2016, and the 900-million-barrels Mitquq Field and 600-million-barrels Stirrup Field – both in 2020 by Oil Search/Repsol.
“Since we discovered Pikka, the industry is 31 out of 34 on wildcat/appraisal wells,” Armstrong said, “with a 94-percent success rate in the Nanushuk.”
The recent discoveries are all located in a relatively small portion of the overall Nanushuk fairway. Modern seismic, when properly processed and interpreted, allows for the “direct detection” of oil on seismic – something rarely seen, Armstrong said.
Namiba – Gulf of Mexico
These days, finding sizeable discoveries in mature basins is becoming increasingly challenging, prompting the need to step into remote settings and be more creative with geological and geophysical development concepts, said Bill Langin, senior vice president of Exploration Deep Water for Shell.
“Continuously challenging ourselves to look across the integrated solution space will be crucial to unlocking the next large discoveries,” he said.
Such a notion took Shell to offshore Namibia, where it has made four recent discoveries in the Orange Basin in partnership with QatarEnergy and Namibia’s national oil company.
“Early results in Namibia have proved a working petroleum system,” he said. “It will take a combination of robust geological and geophysical thinking with creative engineering solutions to ultimately deliver profitable outcomes.”
(It is publicly speculated that the combined discoveries total an estimated 1.7 billion barrels of oil equivalent.)
In the Gulf of Mexico, the operator is relying on new technology to make exploration more cost effective and efficient.
In particular, 4-D seismic technology prompted the operator to cancel plans for three wells in the Ursa field after the data revealed they would likely not be economical, Langin said.
Furthermore, utilizing low-offset/low-frequency seismic has enabled the unlocking of new, deepwater Gulf of Mexico projects, and using ocean bottom node technology for early appraisal work has enabled “higher quality” decisions to be made, Langin said. Referring to the Leopard discovery in the Gulf in 2021, he said the cost of OBN technology was about one-sixth the cost of a well.
“The geology of opportunities is increasingly complex, requiring better and earlier imaging to impact business decisions,” Langin explained. “Legacy seismic cycle time is too long, and the tightness of the market is increasing seismic acquisition and processing costs.”
Collaborating with Amazon Web Services has allowed his team to have flexible access to cloud-scale computational power at similar costs to in-house solutions without long-term commitments.
In addition, by utilizing strategic contracts – such as a two-year contract with PXGeo, a seismic acquisition vendor that enables access to seismic vessels at half the current market rate – operators can actively identify their data needs and obtain critical data faster, Langin said. This allows them to react quickly to discoveries if more data is needed or to apply for a license to operate. Other important technology includes novel seafloor seep detection and sampling technology, which allows for the accurate detection of natural seeps and the collection of flowing hydrocarbons for rapid analysis. The fluids collected have a higher quality than cores, Langin added.
“It’s all about driving technology,” he said. “Advanced in-house imaging is significantly improving the definition of opportunities in the Gulf of Mexico, Brazil and other frontier areas, such as Namibia.”
Black Sea
The Black Sea has long been considered an underexplored basin, but recent discoveries of hydrocarbons, particularly the Sakarya Gas Field, are changing the region’s energy landscape, said Derya Demirci, a geological and geophysical team lead for the Sakarya Gas Field Development Project with the Turkish Petroleum Corporation.
“The Black Sea has always been as isolated basin where exploration activities are limited,” she said. “Having straits between the Mediterranean and Black seas with several bridges causes mobilization and logistic issues. Therefore, without having a major discovery in the basin, it has always been hard to catch enough attention to further exploration.”
However, the Sakarya Field – discovered in 2020 – has become a “game-changer” for Turkey, as it is the largest discovery (405 billion cubic meters) in the Black Sea and holds the potential to reduce the country’s dependence on energy imports, Demirci said. The subsequent and significant discoveries of the Amasra and Çaycuma fields in the Black Sea launched a renewed interest in the region’s untapped hydrocarbon potential.
The Tuna-1 exploration well, drilled in 2020 based on the biogenic gas concept in the Mio-Pliocene aged deep-sea submarine fan deposits, was the first well drilled in the Turkish sector of the Black Sea and responsible for the Sakarya discovery.
The Tuna discovery revealed the overall potential of Plio-Pleistocene and Late Miocene unconsolidated, thin-bedded and laminated turbitidic systems. It also reveals the biogenic potential of the Turkish Sector of the Black Sea Basin.
High-quality 3-D seismic data allowed for the identification of all submarine fan elements and their potential as source and reservoir rocks, as well as potential trapping mechanisms, Demirci explained.
However, the presence of shallow hazards and mass transport complexes presented challenges in the exploration process.
“State-of-the-art seismic processing techniques, such as full waveform inversion, were utilized to overcome these challenges and improve imaging and rock property identification,” she said.
The knowledge of depositional geometries of the submarine fan reservoirs, which were identified in the seismic, and reservoir fluids and possible acoustic responses, which were elaborated by quantitative seismic interpretation and neural network studies, led to the Amasra and Çaycuma discoveries as part of the biogenic gas concept.
It is anticipated that further discoveries within the same concept will be made, Demirci said.
She added that the coverage area of the submarine fan of the Paleo Danube in the Turkish sector of the Black Sea has provided further exploration targets in Mio-Pliocene deposits.