Operators have been optimistically poking around in the onshore and shallow waters of East Africa since the 1950s.
The big discovery occurred in 2011 when Eni E&P drilled the Mamba South 1 well, tapping into the supergiant Mamba gas resource.
During several of those decades, exploration activity resulted in a few onshore natural gas discoveries, which were non-commercial at the time.
The absence of oil finds is thought to have figured prominently in the ensuing drop-off of enthusiasm for further investments in exploration. The offshore basins were essentially unexplored.
Fast forward to the early years of the 21st century.
The area became intriguing once again, spurred in large part by the prospect of using LNG technology to export gas to expanding Pacific markets and elsewhere.
Rekindled exploration efforts, spurred by advances in technology and models based on a new reading of the region’s geology led to a recent ginormous natural gas find.
That Big One occurred in 2011 when Eni E&P drilled the Mamba South 1 well, tapping into the supergiant Mamba gas resource in the Rovuma Basin offshore Mozambique.
The discovery unlocked an estimated potential of 80 TCF in place for the Mamba area.
Eni was one of the first E&P players to enter the essentially unexplored Rovuma deepwater basin when it was awarded License Area 4 in Mozambique in 2006.
This was not the company’s first foray into the basin. In 1982, Agip (now Eni) discovered the Mnazi Bay gas field onshore Tanzania. Mnazi remained the only discovery in the Rovuma until 2010.
One of the geological ideas that companies began evaluating around 2004 delved into the possibility to find oil in the Rovuma.
“Many of the companies began to re-evaluate whether the deepwater could be more oil prone even if all of the discoveries onshore were gas,” said AAPG member Marco Orsi, exploration manager for Mozambique at Eni. “Some geological models suggested this possibility.
“When we took the block in 2006, we thought it might be possible there would be two plays – one oil, one gas,” he said. “When we acquired more data, we realized it was most likely that the Mamba area was a gas prospect, so we drilled the first well looking for gas only, and not oil.
“All of the discoveries in deepwater to date,” he added, “have been gas.”
Experience Pays Off
Experience garnered from the much earlier exploratory work in Tanzania, along with data acquired from other operators in Mozambique, had provided the Eni geologists with the convincing evidence that license Area 4 was situated in the sweet spot in the Rovuma.
Orsi noted that the huge potential of the Tertiary gas play became evident following the first reconnaissance 2-D seismic survey acquired in 2008.
This was followed in 2010 by a high quality 3-D survey recorded over the main prospect, Mamba, allowing detailed definition of the geological model and de-risking of the prospect.
The validity of the pre-drill geological model and the great potential of the discovery were confirmed in 2011 when the Mamba South 1, the initial well, was drilled by Eni and partners Galp, Kogas and ENH.
The well encountered approximately 300 meters of gas pay in Eocene and Oligocene reservoirs, having outstanding quality and thickness, according to Orsi.
This discovery well was followed by an aggressive drilling program.
Eni successfully drilled and tested the Mamba South 3 appraisal well earlier this year in Mozambique Area 4, the ninth well drilled in the exploration permit.
The well reached a total depth of 4,948 meters and was drilled in water depth of 1,571 meters. It tapped into 214 meters of gas pay in excellent quality Oligocene and Eocene reservoirs – the same as the initial Mamba well.
The discovery proved the presence of hydraulic communication with the same reservoirs of Mamba South 1, Mamba South 2, Mamba North East 1 and Mamba North East 2 wells.
“We are now moving fast toward the development phase, the FID for the first development phase is expected in 2014,” Orsi said.
“We are currently drilling an exploration prospect, the Agulha 1, in the southern part of Area 4,” he added, “in order to assess the hydrocarbon potential of untested deeper plays in Area 4.”