Nova Scotia’s offshore energy industry has just achieved two significant milestones.
First, the Deep Panuke N-79 Production Field Center is en route from the Abu Dhabi ship yards to offshore Nova Scotia. Natural gas from Encana Corporation’s one-Tcf Deep Panuke Field is expected to flow during the fourth quarter of 2011.
Second, Nova Scotia’s department of energy in June released a two-year, $15 million geological and geophysical study, tripling offshore resource estimates, explaining historical dry holes and reducing exploration risk in the Scotian Basin.
In a bid to compete against other global jurisdictions and to lure the oil and gas industry back to the Scotian Basin, more than 80 international academic, governmental and industry experts contributed to the massive, state-of-the-art Play Fairway Analysis (PFA). Managed by London-based RPS Energy Ltd., this independent study calculated Nova Scotia’s offshore resource potential (unrisked) at 121 Tcf of natural gas and eight billion barrels of oil.
Building upon the momentum of the study, the Canada-Nova Scotia Offshore Petroleum Board is expected to launch a call for bids before year-end.
Despite the projected economic benefits of Deep Panuke – the production platform is designed to produce up to 300 million cubic feet of sales gas per day – Nova Scotia has seen its offshore exploration licenses shrink from 59 in the mid-2000s, to just four today. A spate of dry holes during the past decade – including some deepwater wells chasing an elusive turbidite play – turned the industry from hot to cold on the Scotian Basin.
“We’d never seen royalties higher, yet we were losing exploration licenses,” said Sandy MacMullin, director of petroleum resources with Nova Scotia’s department of energy and a petroleum engineer by training. “In a sense, we were burning the candle at both ends.
“We needed to know sooner rather than later whether oil and gas would continue to be part of our economic future,” he added.
Offshore Nova Scotia has proven, in-place reserves of two billion barrels of oil equivalent. From 1992 to 1999, Cohasset-Panuke, Canada’s first offshore oil field, produced 44 million barrels of high gravity crude before the economic life of the field was reached.
The Sable Offshore Energy Project (SOEP) led by ExxonMobil, commenced natural gas production in 1999. Since then, Nova Scotia has collected $1.6 billion in royalties from SOEP. Producing about 300 million cubic feet of raw gas per day from five satellite fields, SOEP contains an estimated three Tcf of recoverable gas.
After onshore processing and liquids removal, sales gas is shipped via the Maritimes & Northeast Pipeline to markets in Nova Scotia, New Brunswick and the northeastern seaboard of the United States.
“What we heard from industry,” MacMullin explained, “was that the risk associated with the offshore geology was undercutting the economics.”
Moving quickly and decisively to address industry concerns, the government of Nova Scotia and the Halifax-based Offshore Energy Technical Research Association, initiated the industry-standard Play Fairway Analysis.
“We’ve addressed the geological risks, head on,” MacMullin said, “and we’ve de-risked the front-end decision-making process for the oil and gas industry.”
The study involved a trans-Atlantic team of more than 80 oil and gas specialists from Canada, Germany, France and England who met regularly in Halifax and Paris to integrate concepts and data.
“Team work was integral to the success of this multilateral project,” said AAPG member Hamish Wilson, program director of the PFA study and principal adviser with RPS Energy Ltd., Henley-on-Thames, England.
Investigators carved up the Scotian Basin – comprised of the shallow water continental shelf and the adjacent deep water regions – into six geographical zones. The study involved the following themes:
MacMullin described the multifaceted study as a geoscience gap analysis:
“We took the conjugate margins of Nova Scotia and Morocco, put them back together, and then rifted and drifted them apart over a 200-million-year period,” MacMullin said. “We added in the sedimentary strata, cooked them and generated, migrated and cracked the hydrocarbons. Then, we migrated the hydrocarbons – again, both laterally and vertically.
“We’ve demonstrated that we’ve got a world class petroleum system,” he continued. “The general belief, previously, was that – from a hydrocarbon perspective – we were fairly lean, with primarily Cretaceous gas.”
Before embarking on the Play Fairway Analysis, he explained, “We didn’t fully understand that there was a deeper, Lower Jurassic petroleum system.”
MacMullin’s enthusiasm is echoed by Wilson.
“We’ve got a new tectonic story for the basin that’s conducive to source rock development in the Lower Jurassic.”
AAPG member David Brown is a senior geologist with the Canada-Nova Scotia Offshore Petroleum Board, one of the organizations involved in the Play Fairway Analysis.
Brown described the study’s international team of investigators as “world class biostratigraphers and geoscientists.
“Whenever industry drilled into deepwater sand reservoirs having adequate porosity, they were gas charged,” Brown said. “A working petroleum system was confirmed, but we had a dated understanding of our margin and basins and of the shelf to slope distribution system for sand deposition – and that was crippling.
“The findings of the Play Fairway Analysis,” he added, “bring us up to a modern understanding of the Scotian Basin.”
AAPG Honorary Member G. Warfield “Skip” Hobbs is president of Ammonite Nova Scotia Corporation, an independent E&P company that holds two of the four existing exploration licenses on the Scotian Margin.
A SOEP natural gas pipeline crosses Ammonite’s Eagle Block, and Hobbs is anxious to exploit this existing infrastructure.
“The Play Fairway Analysis,” he said, “represents an independent review of the offshore potential, and proves the existence of multiple working petroleum systems in Tertiary, Cretaceous and Jurassic strata.
“The perception, by the international E&P industry, is that there’s nothing left to find offshore Nova Scotia, that all the discoveries have been made, and that there are just little scraps left,” said Hobbs, who also is current president of American Geological Institute.
Ammonite is seeking drilling partners for Eagle and Penobscot, its shallow water exploration licenses, which contain structures with four-way dip closures mapped on 3-D seismic data and historical wells that tested oil and gas.
Reprocessing of the 3-D seismic data, to modern pre-stack time and pre-stack depth versions with amplitude attribute analyses, has revealed the existence of a deeper, previously undetected reef – similar in age and appearance to Deep Panuke – with interpreted porosity.
“Offshore Nova Scotia is a great place for entrepreneurs,” Hobbs said, citing favorable provincial royalties, the existence of oil and gas infrastructure and access to digital G&G data, including wells, cores, samples, seismic, industry reports and maps.
Hobbs pointed, as well, to the depth of local technical expertise in governmental agencies and at the earth sciences departments of St. Mary’s and Dalhousie universities, all of whom participated in the Play Fairway Analysis study.
“It’s somewhat self-serving,” Hobbs said, “but we think that we’ve got one Tcf of natural gas at Penobscot, in a Deep Panuke look-alike.
“The scraps in the Scotian Basin, by the way, are structures (on Ammonite’s licenses) with the mean risked recoverable resource potential of 200 bcf to 1.0 Tcf and 30 million barrels of oil,” he said.
“How many viable prospects have been bypassed in an area (larger than the Gulf of Mexico) that only has 127 exploratory wells?”
The Cohasset-Panuke Field, located 41 kilometers southwest of Sable Island, was Canada’s first commercial offshore oil field. From 1992-99, 44 million barrels of high gravity crude were produced before the field’s economic life was reached.
Underlying the depleted production at Cohasset-Panuke, however, is a new exploration play in the Scotian Basin, and a one-Tcf discovery called the Deep Panuke Field. The reservoir, an Upper Jurassic dolomitized carbonate reef in the Abenaki Formation, was discovered by PanCanadian Petroleum Ltd. (now Encana Corporation) in early 1998.
AAPG member David Brown, a senior geologist with the Canada-Nova Scotia Offshore Petroleum Board, waxes poetically about the hydrocarbon potential of the virtually unexplored eastern margin of North America.
“Imagine a carbonate bank fairway that extends several thousand kilometers from Nova Scotia clear to Florida, that’s been tested by less than 20 exploration wells off Nova Scotia and only two wells on the U.S. Outer Continental Shelf,” Brown said.
Deep Panuke represents the second natural gas field development on the Atlantic margin of North America – the other development is the Sable Offshore Energy Project, also located in the Scotian Basin.
♦ Design capacity of the Deep Panuke N-79 Production Field Centre is 300 million cubic feet of sales gas per day.
♦Start-up production is 200 million cubic feet of sales gas per day from four wells – each well is capable of producing up to 85 million cubic feet of sales gas per day.
♦Productive field life ranges from eight to 18 years, with mean risked recoverable reserves of 632 Bcf over 13 years.
♦Original gas in place 1.0 Tcf.
♦Hydrogen sulfide and carbon dioxide stripped from the gas at the Deep Panuke N-79 Production Field Centre, and injected in a dedicated disposal well.
♦Sales-ready gas shipped from the Deep Panuke N-79 Production Field Centre via the pipeline to Nova Scotia.
♦ Pipeline is 175 kilometers long, including a 172-kilometer-long subsea section and a three-kilometer-long onshore section to interconnect with the Maritimes & Northeast Pipeline.
♦Production from Deep Panuke being sold to Repsol YPF for the life of the field.
♦Deep Panuke N-79 Production Field Centre was constructed in Abu Dhabi, and is owned by SMB Offshore.
– SUSAN R. EATON