At a time when only a paltry number of significant projects are getting the go ahead, Egypt has seen global majors such as BP and Eni buck the trend and take a committed long-term approach to the country’s offshore sector.
The willingness of these majors and others to sink substantial investments into the North African country’s upstream sector—both onshore and offshore—also has seen them opt unhesitatingly to use the latest deepwater production systems, mostly long-distance subsea and tieback solutions. The latest example of this is what will become the world’s second longest subsea step-out, a distance of more than 150 km (93 miles).
As a result, Egypt has become the undisputed leading light in the Mediterranean.
The country’s energy sector as a whole has come a remarkably long way in five years, recovering from those unstable and unpredictable times to become energized by giant finds such as Eni’s Zohr discovery and Apache Corp.’s success in the Ptah and Berenice onshore fields.
At the Offshore Technology Conference in Houston earlier this year the country’s petroleum minister, Tarek El-Molla, said, “Egypt has a huge exploration potential, large undeveloped reserves and new strategies to overcome current challenges and boost upstream activities and secure sustainable energy supply.”
More flexible upstream agreements, a willingness to negotiate over gas prices and fewer international oil company (IOC) arrears—which have fallen from $6.3 billion to about $3 billion within 2.5 years—is helping to build momentum and encourage new exploration, he said.
The country remains busy with a program to expand and upgrade its infrastructure as it accelerates development of several projects, with the goal of adding about 170 MMcm/d (6 Bcf/d) within the next five years and with investments of more than $35 billion already committed, according to El-Molla.
He also said more recently that IOCs were expected to invest about $8.5 billion during the fiscal year 2016- 2017 on exploration and development activities in the petroleum and natural gas sectors.
Zohr Raises The Bar
Eni’s Zohr discovery, of course, has hugely raised the bar in terms of expectations for the country’s already established deepwater sector, where BP and BG in particular have previously established solid producing assets via deepwater subsea tiebacks to shallower water platform facilities for the past decade and more.
The field, located in the Shorouk Block, has progressed rapidly since the discovery well was drilled by the Saipem 10000 drillship in mid-2015 and announced in August that year. Despite the industry downturn, it was sanctioned by the Egyptian authorities by February of this year.
The Italian major sees Zohr as a global flagship project and is pushing the schedule hard, with startup expected by year-end 2017 and a three-well drilling program currently underway following a successful appraisal well that delivered up to 1.2 MMcm/d (44 MMscf/d) of gas during a production test.
OneSubsea’s $170 Million
EPC Earlier this year Schlumberger’s OneSubsea clinched a $170 million engineering, procurement and construction (EPC) contract from Petrobel to supply the subsea production systems on Zohr.
The workscope will see OneSubsea supply six horizontal SpoolTree subsea trees, intervention and workover control systems, landing string, tie-in, a high-integrity pressure protection system, topside and subsea controls and distribution, water detection and salinity monitoring provided by the AquaWatcher water analysis sensor, and installation and commissioning services.
The contractor said the FasTrac program comprises a strategic inventory capability with the flexibility to configure the system to customer needs and deliver on a fast turnaround.
“Zohr is one of the largest gas fields discovered in the Mediterranean Sea to date and is also the world’s second longest step-out, [with] a distance greater than 150 km. This step-out will be enabled by OneSubsea controls systems with fiber-optic communications technology,” said Mike Garding, president of OneSubsea, in a press statement. “Our supplier-led approach to the field development coupled with our FasTrac program capability and our integrated offering that includes flow assurance, subsea production system and landing string capabilities will help Petrobel meet its first gas commitment.”
OneSubsea already had carried out an accelerated FEED study in which a multidisciplinary team collaborated with Eni and Petrobel to develop the subsea equipment architecture and control system to validate handling of high gas volumes, considering reservoir characteristics and subsea equipment specifications.
Petrobel, a joint venture between Eni and Egyptian General Petroleum Corp., also awarded Eni’s Italian compatriot Saipem an EPC and installation (EPCI) contract for the accelerated startup of Zohr.
The award entails EPCI work for an initial six-well development, installing the umbilical system and installing a 26-in. gas export trunk line as well as 14-in. and 8-in. service trunk lines. Work is underway and is due to be complete by year-end 2017.
Saipem plans to mobilize a fleet of vessels, including the ultradeepwater pipelay unit Castorone, the semisubmersible pipelayer Castoro Sei, the trench/pipelay barge Castoro 10 and other specialized vessels.
Eni also has its Baltim South West gas find in the East Nile Delta offshore Egypt some 10 km (6 miles) north of the producing Nooros gas field. The Baltim South West 1X well encountered about 120 m (394 ft) of gross gas column and 62 m (203 ft) of net pay sandstones of Messinian age with excellent reservoir properties, the company said earlier this year, adding that it also is considering developing it as a fast-track project with its partner BP using existing infrastructure. The Greater Nooros area is estimated to hold 70 Bcm to 80 Bcm (2.4 Tcf to 2.8 Tcf) of gas in place, according to Eni.
Atoll on a roll
Ahead of it in terms of progress is BP’s Atoll Field, also in Egypt’s Mediterranean sector, where the operator and its partner sanctioned the first phase of the deepwater development just over a year after making the discovery. With first gas expected in 2018, this will see Atoll go from discovery to production in less than three years.
Up to 8.4 MMcm/d (300 MMcf/d) of gas from the field will feed Egypt’s domestic gas market, which had to start importing LNG in 2015 to meet rising demand. Located in the North Damietta Offshore concession in the East Nile Delta, Atoll is estimated by BP to contain about 42.4 Bcm (1.5 Tcf) of gas and 31 MMbbl of condensate. The original discovery well drilled by the sixth-generation semisubmersible rig Maersk Discoverer hit about 50 m (164 ft) of gas pay at a well depth of 6,400 m (20,998 ft) and followed on from BP’s Salamat discovery made two years earlier.
Atoll will consist of two phases. In addition to recompleting the existing exploration probe as a producing well, the first early production system phase includes drilling two development wells tied back to existing facilities operated by Pharaonic Petroleum Co. (BP, 25% interest as operator; Eni, 25%; and EGPC, 50%).
The wells will be drilled by Ensco’s DS-6 drillship, which was expected to start drilling in August for up to two years. Depending on the results of the first phase, there could then be further investment in a Phase Two full-field development.
Production from Atoll will flow via the Taurt pipeline, which is part of the Ras El Barr concession (BP, 50% as operator and Eni, 50%) and land at the PhPC West Harbour gas processing facilities.
$3.8 Billion Spend
BP will reportedly invest $3.8 billion in the field development, with $1 billion earmarked for its initial phase. Like Eni with Zohr, BP’s decision to approve its investment in Atoll came at a time when the majority of the upstream industry continued to drastically rein in its capex. The fact that both of these fields lie in deep water is particularly significant as that sector of the development market has been the one hit hardest by the industry’s elongated downturn. A recent report by analyst Wood Mackenzie showed spending on deep- and ultradeepwater projects was cut by nearly 40% for the 2016-2017 period.
BP’s Atoll decision also followed a much bigger one it made last year when it sanctioned the $12 billion West Nile Delta project, where production is anticipated to reach up to 33.9 MMcm/d (1.2 Bcf/d) with first gas next year from the 141-Bcm (5-Tcf) field in the North Alexandria and West Mediterranean Deepwater concessions.
Onshore Shines For Apache
Egypt’s onshore sector continues to produce the goods for other companies, too. Egyptian resources make up 19% of Apache Corp.’s overall reserves and 17% of its production.
CEO and President John Christmann said, “In a sub- $50/bbl world, the international portfolio really, really shines through. In Egypt, we have high-quality stacked pays. We have significant exploration potential as we’ve seen with our Ptah/Berenice fields. One of the big things here is that the production-sharing contract arrangement provides a buffer to low price environments.”
But the big thing for Christmann is the attractive returns, even in today’s environment. Egypt’s share of Apache’s $1.4 billion to $1.8 billion capital program for 2016 is 23%, although that is down 40% from 2015. However, it is not as harsh as the 60% reduction in its North American operations.
“As a percentage of our dollars today, we are spending more internationally than we were in 2014,” Christmann said, noting Apache has five rigs running in Egypt now compared to four in North America. “We expect to drill 60 to 70 wells and average about six rigs for the year,” he said.
Apache is the largest acreage holder in the Western Desert and has operated in Egypt for more than 20 years, with average production in 2015 hitting about 352,000 boe/d.
According to Matthew Loffman of analysts Douglas- Westwood, Egypt’s oil production is forecast to drop below 600,000 bbl/d by 2022; however, gas production is set to leap from 900,000 boe/d to 1.5 MMboe/d by 2022. The firm also foresees the country’s offshore production growing, with Zohr contributing to mediumterm growth.
Contact the author, Mark Thomas, at firstname.lastname@example.org.