Audrey Leon takes a look through some of the industry’s biggest ongoing projects by capex in 2017. Five of the 10 biggest projects by capex were offshore projects in 2017, led by Inpex’s Ichthys LNG project offshore Australia.
Ichthys: Making progress
The Inpex-operated Ichthys LNG project hit some major milestones in 2017. The floating production, storage and offloading facility (FPSO) was moored in August this year at the Ichthys Field, 220km off the north coast of Western Australia.
The 336m-long FPSO, named Ichthys Venturer, is longer than three soccer fields and is designed for 40 years of operations without dry dock. It also has a storage capacity of 1.12 MMbbl of condensate.
“Completing the complex operation of connecting 21 pre-installed mooring chains, weighing more than 15,000 tonnes, from the seabed to the FPSO is testament to the well-coordinated work of our personnel, including contractors and subcontractors from around the globe,” said Louis Bon, managing cirector of Ichthys Project, this August.
The Ichthys Venturer FPSO is moored 3.5km from Ichthy’s central processing facility, the Ichthys Explorer, which was moored at the field in late May.
In September, Wood Group was awarded a new, five-year contract to provide subsea engineering services for the integrity of the Ichthys project. The operations of all subsea assets and the gas export pipeline will be supported under the contract, which includes two, one-year extension options.
The Ichthys LNG Project is expected to produce up to 8.9 MTPA of LNG and 1.65 MTPA of LPG, along with approximately 100,000 b/d of condensate at peak.
In November 2017, Inpex won an exploration permit for Release Area WA-532-P, close to its Ichthys LNG development,
On the fast-track: Eni's Zohr
2017 has been a busy for the Eni-operated Zohr mega-discovery. In February, BP bought 10% interest in the Shorouk concession, offshore Egypt, which contains the Zohr gas field, for US$375 million. In October, Russia’s Rosneft then closed a US$1.13 billion deal to acquire 30% stake in the concession from Eni.
Zohr, discovered in 2015, lies in the Nile Delta basin off Egypt in the Block 9 (Shorouk block), close to Cypriot waters, about 190km north of Port Said in 1500m water depth. Its acreage covers about 230sq km, with its in-place reserves exceeding 850 Bcm.
Andrew Scutter, of the EIC, wrote for OE in June that “Eni’s 30 Tcf Zohr discovery, offshore Egypt, is a game changer in the region that has the potential to convert Egypt from a net importer back to the LNG exporter that it was 10 years ago.”
IHS Markit said that Zohr holds in-place resources of 32 Tcf of dry gas, with possible recoverable resources of about 20 Tcf. A development plan for the field was approved in 2016.
The two-phased, fast-tracked project is targeting first gas by the end of 2017, by drilling six wells this year and tying them into existing nearby infrastructure, Scutter said in June. Zohr is slated to be one of the longest subsea tiebacks in the world.
In July, Saipem was awarded a $900 million engineering, procurement, construction and installation (EPCI) contract for Zohr.
Saipem said the scope of work includes the installation of a 30in-diameter gas export pipeline and an 8in-diameter service pipeline, as well as EPCI work for the field development in deep water (up to 1700m) of four wells and the installation of umbilicals. Work is due to be completed by the end of 2018.
In September, Baker Hughes, a GE company (BHGE) won a subsea contract for Zohr’s second phase. BHGE will provide project management, engineering procurement, fabrication, construction, testing and transportation of a subsea production system, including seven manifolds, tie-in systems, long offset subsea and topside control systems, SemStar5 high integrity pressure protection systems, workover systems and tools, and will support the installation, commissioning and start-up operations.
King in the North: Johan Sverdrup
Statoil’s Johan Sverdrup project is simply a giant. Like the others on this list, it is massive, two-phased project, 160km west of Stavanger, Norway, in water depths ranging 110-120m. Statoil believes will be one of the most important industrial projects in Norway of the next 50 years.
Resource estimates for Johan Sverdrup are 2-3 billion boe. Phase 1 is underway – 60% complete as of September 2017), with first oil to follow in late 2019.
Phase 1 of the field included the development of four platforms, three subsea installations for water injection, power from shore, export pipeline for oil (sent to Mongstad) and gas (sent to Kårstø). Statoil estimates the capital expenditure for phase 1 at NOK 92 billion.
In March, Statoil and it partners expressed their intent to proceed with phase 2 of Johan Sverdrup, with investment decision and submission of the plan for development and operation to come in H2 2018.
In anticipation of phase 2, Statoil awarded FEED contracts to Aker Solutions (processing platform), Kværner (jacket) and Siemens (power supply from shore).
Phase 2 will build on infrastructure from phase 1, adding another processing platform, which the Norwegian major says will result in a processing capacity of 660,000 bo/d. Expected to come on stream by 2022, Statoil says 28 new wells will be drilled for the phase 2 development.
According to Statoil, capital expenditures for Phase 2 are estimated at between NOK 40-55 billion, halving the estimate since the PDO was submitted for Phase 1 of Johan Sverdrup.
Statoil operates Johan Sverdrup with 40.0267% interest. Its partners on the massive development are Lundin Norway (22.6%), Petoro (17.36%), AkerBP (11.5733%) and Maersk Oil (8.44%).
Shah Deniz 2
In September, the second topsides unit for the BP-operated Shah Deniz Stage 2 project, the 15,800-tonne production and risers (PR) platform, was installed in the Caspian Sea.
The installation of the first unit, the quarters and utilities (QU) platform topsides was completed in early-July.
Shah Deniz, discovered in 1999, is 70km southeast of Baku, Azerbaijan, in 50-500m water depth. The field, which sits on the deepwater shelf of the Caspian Sea, spans some 860sq km, and is about 70km offshore Baku, Azerbaijan, in 50-500m water. The field holds about 40 Tcf of natural gas in place, making it one of the world’s largest gas-condensate fields, and one of BP’s largest discoveries to date.
The project consists of Shah Deniz Stage 1, with the capacity to produce some 10 Bcm/yr of gas, and about 50,000 b/d of condensate; Shah Deniz Stage 2, which will add an additional 16 Bcm per year of gas production; and the Southern Gas Corridor pipeline system that will help deliver 6 Bcm/yr of gas to Turkey and a further 10 Bcm/yr of gas to markets in Europe.
The Shah Deniz Stage 2 concept calls for two new bridge-linked offshore platforms; 26 gas production wells, which will be drilled with two semisubmersibles; 500km of subsea pipelines, which will link the wells with the onshore terminal.
The Shah Deniz consortium consists of: operator BP (28.8%), TPAO (19%), Petronas (15.5%), AzSD (10%), Lukoil (10%), NICO (10%) and SGC Upstream (6.7%).
This summer, Statoil’s US$7 billion Mariner heavy oil development took a major step forward. The Mariner A platform’s nine modules were installed on the Mariner A jacket using the Saipem 7000 crane vessel, about 150km east of Shetland on the UK Continental Shelf (UKCS).
The Safe Boreas flotel then moved alongside to support some 480 of the up to 750 staff that will be working on the 38,000-tonne platform hook up and commissioning project over the next year or so.
First oil is scheduled for 2H 2018. Mariner, a heavy oil field development, is one of the largest projects currently under development on the UK Continental Shelf.
The field contains an estimated 250 MMbo reserves with an average plateau production expected at about 55,000 b/d.