Italian major Eni has found what could be the biggest gas deposit in the Mediterranean and the company is eager to develop it. Jerry Lee reports.
Egypt Nile Delta. The Zohr discovery, in the Shorouk block, offshore Egypt. Image from Eni.
Italian major Eni made waves when it announced what could be the largest discovery in the Mediterranean Sea, the 30 Tcf lean gas deep water Zohr field offshore Egypt.
For a country that has seen much turmoil in recent years, the news was welcome. For an operator who has been present in Egypt for over 60 years, Eni’s commitment could pay off and then some.
The project could be a beacon of hope in today’s cash-strapped, low-budget industry. Analysts Wood Mackenzie expect Zohr to be the biggest project sanctioned globally in 2016, with an estimated budget of over US$14 billion.
At the time of the initial Zohr discovery last August, Eni CEO Claudio Descalzi said: “This historic discovery will be able to transform the energy scenario of Egypt in which we have been welcomed for over 60 years.”
Eni’s Zohr discovery lies in the Nile Delta basin off Egypt in the Block 9 (Shorouk block), close to Cypriot waters, however, a previous operator missed its opportunity to make the discovery.
“Royal Dutch Shell previously operated this acreage, under the North East Mediterranean (NEMED) licence,” Joseph Gatdula, GlobalData’s senior upstream analyst told OE. “Shell looked at the Oligocene, Pliocene and Upper Messinian (Upper Miocene) areas, but focused on the clastic sands that comprised the known plays. They also drilled well Kg-70-1 in the southwest corner of the Shorouk license, which did not provide compelling evidence to continue exploration.”
Shell completed extensive 2D/3D seismic campaigns, and drilled nine wells in the area, but the play proved uncommercial. “They relinquished the block because they completed studies, which did not consider the Miocene carbonates where Zohr was found,” Gatdula says.
However, following a string of recent giant gas discoveries in neighboring countries, including the Leviathan and Tamar fields, offshore Israel, and Aphrodite, offshore Cyprus, Eni became interested in similar geological models in Egyptian waters, wrote Marco Alfieri in a blog post for Eni’s website.
The starting point
“Eni’s explorers [began looking] for similar structures with the same “play concept,” on the assumption that the oil system discovered in the Eastern Mediterranean might also extend to Egypt,” Alfieri wrote in a blog post for Eni’s website. “However, on the basis of the evaluation work made by the IEOC (International Egyptian Oil Co., an Eni subsidiary) team in Egypt, and with the lack of available seismic data, what emerged was an area in block 9 where there appeared to be a 'high regional' situation: not the classic theme in Miocene sands like Leviathan, Tamar and Aphrodite or the Nile Delta, but a huge bio-structure. A 'reef,' as geologists call it.”
With previous successful exploration activities in similar play structures (Venezuela’s Perla field and Kazakhstan’s Kashagan field), the company developed the Zohr play concept, said Eni in a September 2015 presentation.
Eni submitted its bid for the Shorouk block in February 2013, as part of Egypt’s 2013 Bid Round, and was notified of its success that summer. Shorouk, 100% operated by IEOC, spans 3752sq km with water depths ranging from 1200-1700m.
Eni and Egypt signed the lease on Block 9 in January 2014, and, despite having only reprocessed the available 2D seismic data, and having failed to find a partner for the project, a decision to drill was made. The Saipem 10000 drillship was brought out to the field in June 2015, spudding the Zohr-1X NFW exploration well on 3 July 2015, three years ahead of an original schedule; simultaneously, 2942sq km of 3D seismic was also acquired, two years ahead of schedule.
Drilled in 4757ft (1450m) water depth to the target depth of 13,553ft (4131m), the well hit a 2067ft (630m) hydrocarbon column with 430m of net reservoir pay, and a gas-water contact at 4055m. The reservoir was found to have excellent reservoir characteristics, and initial estimates placed the reservoir potential at up to 30 Tcf of lean biogenic gas in place (5.5 billion boe), Eni said in October 2015. The Zohr discovery displaced Noble Energy’s Leviathan field, offshore Israel, in the Levantine Basin, as the largest gas field in the Mediterranean. According to Wood Mackenzie, Zohr was one of the largest discoveries in 2015, with some 3960 MMboe recoverable.
After the discovery was announced, Eni put into motion its plan to appraise the field and fast track the development. In February, Eni announced that it has been granted the Zohr development lease and the firm’s target is to bring the field online in Q4 2017 – just two years after discovery.
The Saipem 10000. Photo from Saipem.
The first appraisal well on Zohr, the Zohr-2FX NFW well, was spudded in January, again using the Saipem 10000, 1.5km southeast of the Zohr discovery well. It is in 4800ft (1463m) water depth, downdip from the discovery well on the flank of the Zohr structure.
It was drilled to 13,684ft (4171m), where a 1614ft (455m) hydrocarbon column was found, along with 305m of net pay. Formation evaluation confirmed the same gas-water-contact as well as connection to discovery well Zohr-1X NFW, confirming Zohr as a single massive natural gas tank.
Production tests from the appraisal well delivered some 44 MMcf/d of gas, constrained by the surface equipment, from 120m of the reservoir, Eni said in early March. This would enable Eni to achieve up to 250 MMscf/d (46,000 boe/d) production, the firm said. Eni plans to drill a further three appraisal wells this year, to fully delineate the field.
“The flow test seems to really validate that Eni is working with a substantial resource with excellent flow characteristics,” says Andrew Jackson, market research and database manager, Quest Offshore.
Eni says its fast-track development will take the form of a subsea tie-back, thanks to the production system simplicity enabled by Zohr’s lean gas.
A multiphase development plan is likely when taking into consideration Eni’s aggressive fast-tracked development plan, Jackson says.
“The quick realization of such a large project will be possible through cooperation with Petrojet, Enppi and Saipem contractors,” announced Eni in a 21 February 2016 release.
Jackson says the field will be tied back 130km to the Temsah platform, operated by Petrobel (Belayim Petroleum), an IEOC and Egyptian General Petroleum joint venture. From the platform, the gas will be transported onshore, via existing export pipeline, to utilize existing facilities, as well as a gas treatment plant currently under construction.
According to Quest’s projections, phase 1 of Zohr’s field development program will initially begin with the start-up of 4-6 wells in Q4 2017, producing an estimated 700 MMscf/d to 1 Bscf/d by the end of 2017, and gradually ramp up, with the aim to produce 2.7 Bscf/d by 2020, Jackson says.
In order to meet Eni’s 2020 production goals, phase 2 of the development would need to see additional wells come online.
“We believe that this phase 2, which is really more of a ramp up on the existing fast-track, rather than a distinct second phase, will encompass up to 18 further production wells and further step out of infield flowlines and umbilicals from the phase 1 drill center,” Jackson says. “Currently, phase 2 models estimate an additional 30km of infield flowlines and subsea production umbilicals may be required, and make use of the existing 130km tieback infrastructure. We are likely to see phase 2 startup in 2H 2018.”
If five wells are initially brought online in 2017, Quest estimates that Eni would need to bring online approximately 4-6 wells each year to reach the 2.7 Bscf/d target.
According to Wood Mackenzie, Eni plans a fast-track phased development with around 800 MMscf/d of production in the first phase, from late 2017, ramping up to 2.6 Bcf/d by 2019. But, the firm warns: “Meeting this ambitious timeline will be challenging.”
By Q4 2015, no awards for subsea production equipment have been given, however, awards are projected to come in 1H 2016 to meet Eni’s schedule for Q4 2017 production.
“There is a potential for the contracts for subsea production systems, as well as subsea production umbilical manufacturing and installation activities, for phase 1 and 2 to be awarded all together,” Jackson says.
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