It’s Miocene again in America. Offshore America, anyway. BP brought the Gulf’s deepwater Miocene play back into the headlines with its Far South oil discovery, announced in April. The Green Canyon-area well was drilled about 120 miles offshore Louisiana, in 4,092 feet of water.
Both the discovery well and a subsequent sidetrack found “high-quality Miocene reservoirs” with potentially commercial hydrocarbons, according to BP. Chevron also has a stake in the well.
Far South is the latest example of a play that explorers have pursued and had success with for years, in multiple areas of the Gulf. Eni reported a significant Miocene-Pliocene oil discovery last July with its Yopaat exploration well in the Sureste Basin, offshore Mexico. That find holds a resource potential of 300-400 million barrels equivalent of oil and associated gas, according to the company.
Now the industry’s Miocene attention has shifted to Talos Energy and its Daenerys prospect – the Mother of Dragons gets her own exploration well. Daenerys is projected to spud by July, in the Gulf’s Walker Ridge area. Talos calls the well “a high-impact subsalt project that will evaluate the regionally prolific Middle and Lower Miocene section,” with an estimated gross resource potential between 100-300 MMBoe.
Miocene Momentum
Several factors make the Miocene play attractive for oil and gas exploration, including porous sandstone reservoirs and salt-related traps. Some of the same characteristics helped turn the Gulf into a long-time U.S. superbasin playground, second now only to the Permian.
Richard Denne and Michael Sweet are co-program directors for the Gulf Basin Depositional Synthesis program at the University of Texas Institute for Geophysics. The industry-supported project conducts an ongoing, comprehensive study of the Gulf’s deep-basin fill.
“One of the great things about the Gulf is that in almost all of it there’s an active source rock present,” Denne noted
“Almost anywhere you drill, there’s a source rock sitting underneath you,” he said.
In addition to those underlying source rocks, both the Gulf’s sedimentary fill and its history of salt tectonics and salt deformation count as attractive advantages.
“You also have a very thick and quite young sedimentary section, up to 50,000 feet, with very high permeability and porosity. There’s also a thick salt layer that has deformed over time, resulting in a plethora of structural traps,” Sweet commented.
The Gulf offers “everything in a large quantity – some carbonate reservoirs, some clastic reservoirs,” he said.
Through the decades, the Gulf usually has been a politically advantaged place for the industry to drill, Sweet noted, “where commercial terms, tax terms are quite favorable. You’re near a large commercial market. There is a very transparent form of leasing.”
And much of the world’s current offshore oil and gas technology came out of work in the Gulf. It has racked up numerous firsts in offshore platforms, floating production units and subsea infrastructure. That history of innovation proved especially important to today’s deepwater exploration.
“It’s where the technology developed, so the industry has moved progressively into deeper waters,” Sweet said.
By the 1980s, offshore exploration capabilities had pushed past 2,000 feet of water depth and the Gulf was starting to see a renewal of interest. Shell identified a Mississippi Canyon deepwater prospect it called Mars and secured leases on the area in 1985.
It eventually turned out to be the biggest Gulf discovery in more than 25 years. The 1989 discovery well – drilled in almost 3,000 feet of water – reached a total depth of 18,420 feet and found more than 440 net feet of oil pay in seven intervals of Miocene-Pliocene sediments.
“A lot of big, important (Gulf) discoveries back in the 1990s, like Mad Dog and Thunder Horse, were Miocene or Pliocene. Some of the Paleogene discoveries, the industry struggled to commercialize, as they required very expensive completions,” Sweet noted
“The big plus for the Miocene compared to other plays is reservoir quality. It’s a pure quartz sandstone. The Paleogene has been a real challenge because you get much lower reservoir quality,” he said.
Mostly, the Gulf Miocene benefited from timing. Paleogene sediment supply following the Laramide orogeny, the uplifting of the Rocky Mountains, was followed by the proto-Mississippi River bringing Appalachian sediments into the basin.
“During the Miocene, renewed uplift of the Appalachians resulted in another source of quartz-rich sediment,” Denne observed.
“The Paleogene sands, instead of being quartz-rich like the Miocene, are full of rock fragments and feldspars that break down to clay minerals during burial. These diagenetic clay minerals can block pores and reduce permeability,” Sweet said.
Salt, a critical contributor to the Gulf’s development potential, turned out to be a blessing and a curse for the industry. The challenge of subsalt imaging daunted Gulf geophysics for years.
“You’ve got these salt canopies in the Gulf. When I started at Exxon back in the early 1990s, you couldn’t see underneath them,” Denne recalled.
Phillips Petroleum, with partners Anadarko Petroleum and Amoco Production, confirmed the viability of subsalt exploration with its Mahogany discovery in 1993, which produced from Upper Miocene. Afterwards, subsalt geophysics steadily advanced.
“Now, from what we’ve heard, the industry has been able to use ocean-bottom nodes for improved seismic imaging below salt,” Sweet said.
Salt movement, crustal tectonics and clastic deposition created what explorers call “minibasins” in the Gulf, anywhere in size from a dozen square miles to 100 square miles or more.
“Bringing a regional picture into a minibasin can be tough. If there is not good well control, it can be difficult to determine the age of sedimentary fill and the timing of salt deformation from seismic alone,” Denne noted.
Also, Sweet said, “there’s always the question of when those structures are forming compared to when the source rock gets into the oil and gas window.”
“You can have thousands of feet of sediments deposited over hundreds of thousands of years,” he said.
Denne recalled a Gulf exploration project he was involved with in which the basin modeler identified a lower, below-target structure – one that would have had to fill before the target structure could contain hydrocarbons. In the end, nothing was found.
“There are some things you can never know until you drill it,” he observed.
“You can have a thick Middle Miocene section in one minibasin and not that many miles away in another minibasin, there’s almost no Middle Miocene section because of the timing of salt deformation. Each minibasin has its own history of salt deformation,” Sweet said.
A Shallower Future?
Following its Far South discovery, BP announced that it expects to deliver roughly 1 million barrels of oil equivalent per day from U.S. onshore and offshore regions by 2030. It pledged to ramp up its exploration program, drilling around 40 wells over the next three years, 10-15 of those by the end of 2025.
While Gulf production is expected to increase in the near term, “all basins eventually mature,” Denne observed.
Both he and Sweet question how much further Gulf exploration can be pushed. With so much ultradeep drilling in the Gulf, it can’t be pushed much deeper. And in water depth, Denne thinks the future might lie closer to shore rather than farther away.
In the Gulf, “while it’s been a great run, I really wonder what the future is for new plays, at least in deep waters,” Sweet said.
“The question is,” Denne said, “can we use the new technologies to go into shallower waters?”