Global Deepwater Review: Strength in numbers

The Centennial J tanker will be converted by MODEC for Tullow's TEN field. Photo by: Tullow Oil Plc/Joseph Lynch.

E&P companies will continue to invest in deepwater exploration and development, despite shale-based rumoes to the contrary. New developments spread across offshore Africa, Asia Pacific, Europe, and North and South America. Jeannie Stell reviews the highlights of current top offshore projects in water depths exceeding 1500ft.

The rumor: Unconventional onshore shale production is a threat to global deepwater exploration capital spending.

The fact: Not exactly, according to energy advisory firm Douglas-Westwood. Despite industry rumors (based on investment banks and government agencies forecasts) that oil markets will be flooded with shale oil, thus leading to a reduction of deepwater activity, the evidence suggests differently, reports Douglas-Westwood. “If the oil supply increases, then any overhang will be quickly absorbed. That’s what the record shows.”

While the US was first to develop the technology to unlock shale resources, non-US countries are quick to adapt the technology in their own relevant basins. Hence, the global threat. But consider this: In the US, oil demand reached 20MMb/d in January, up a whopping 1MMb/d, or 5.3%, compared to the same period last year. Although the US shale plays “posted a blow-out year,” rising by 1.3MMb/d as a three-month average by November 2013, and Canada added another 0.7MMb/d for a total North American production growth of “an astounding 1.9MMb/d,” Brent oil prices increased to US$111/bbl, reports Douglas-Westwood.

As a plethora of non-US countries begin developing unconventional resources or plan to do so, North American shale play development versus oil demand statistics serve as logical indicators of global onshore-versus-offshore strategies for energy companies.

So despite the rumors, at least $99 billion will be spent on floating production systems (FPS) 2014-2018, a 138% increase compared to the previous five years, according to the research firm. Of that, approximately $68 billion, or two-thirds of total spending, will target deepwater FPS deployments.

The FPS sector recovery is steady, evidenced by some 54 units that were ordered 2011-2013, compared to 23 units ordered throughout 2008-2009. And 2014 is expected to show a significant increase in the value of units deployed.

Meanwhile, utilization of FPSOs owned by leasing contractors has also improved, up 3% to 88%, reports Douglas-Westwood. Clearly, the relatively new onshore shale plays are no threat to deepwater exploration and development.

Africa

Offshore Nigeria, Total continues to develop the Egina oil field. Total Upstram Nigeria (with a 24%interest) is developing the field in partnership with CNOOC (45%), Sapetro (15%) and Petrobras (16%). Egina lies in block oil mining lease (OML) 130 and covers an area of around 500sq mi in 574ft of water. 

Although the partners initially planned to develop the field with a subsea tieback to the Akpo FPSO, new discoveries in the region led to an independent-infrastructure development of Egina. 

The field's infrastructure will include an FPSI and an oil-offloading terminal, subsea production systems, comprising injection flowlines, risers, flexible jumpers, umbilicals, and subsea manifolds, and gas export pipelines.

In June 2013, Total and its partners awarded a $3 billion engineering, procurement, fabrication, installation and pre-commissioning contract to Saipem, and a $1.2 billion engineering, procurement, construction, and commissioning contract for Egina's subsea production systems to FMC Technologies. In January 2014, FMC Technologies subcontracted Aveon Offshore to provide fabrication services for the subsea structures at the field.

Egina is expected to go onstream by the end of 2014 or early 2015. Production from the Egina-5 well is estimated to reach 12,000b/d. The oil field is estimated to reach a peak production rate of 150,000b/d, and a future FPSO will increase production capacity by 200,000b/d. Egina is Total's third deepwater development off Nigeria, with total field production expected by the end of 2017. 

Offshore Angola, BP operates block 31 and holds  26.27% interest, with partners Sonangol E.P. (25%), Sonangol P&P (20%), Statoil Angola (~13.33%), Marathon International Petroleum Angola Block 31 (10%), and SSI 31 (5%).

The Eirik Raude semisubmersible rig operating on the Jubilee Field offshore Ghana. Photo by: Tullow Oil Plc.

The PSVM development in block 31's northeastern sector comprises the Plutao, Saturno, Venus, and Marte fields, all in water depths of about 6560ft. THe four fields are expected to produce 150,000b/d, and production from the first three wells of the Plutao field started in January 2013. For now, the wells are producing about 70,000b/d. The Saturno and Venus field were expected to enter production in 2013, with production at Marte field to follow in 2014. 

The PSVM project utilized a converted tanker with 1.6MMbbl storage capacity. Full project development will see about 48 wells drilled, including gas and water injection, and infill wells, which will be connected to 15 manifolds and associated subsea equipment. About 550ft of flowlines and 300ft of control umbilicals are involved.

ODEC was awarded a frame agreement to supply the PSVM project’s FPSO and, in turn, subcontracted Jurong Shipyard to convert the very large crude carrier (VLCC) tanker, Ex-Bourgogne, to FPSO PSVM.

The pre-front end engineering and design (FEED) studies for the project were carried out by JP Kenny. A $1 billion contract was awarded to Heerema Marine Contractors to lay 160ft of pipe-in-pipe production flowlines, 130ft of service flowlines, 55ft of vertical risers, 77 ancillary structures and nine piles driven at a water depth of 6660ft. Pipeline Technique provided its HALO welding technology, and the design for the umbilical riser flowline was provided by INTECSEA.

Technip supplied 200ft of rigid flowlines, 40 flexible jumpers and 34 umbilicals covering a total length of 140ft through a contract valued at $615 million, while Aker Solutions will supply 150ft of steel tube umbilicals for the project. Halliburton is providing well assembling equipment for the project under a contract valued at more than $600 million. VWS Westgarth, a subsidiary of Veolia Water Solutions Technologies, will supply a single-lift module seawater sulfate-reduction system.

Offshore Ghana, Tullow Oil continues to develop its TEN project. Tullow is the operator of the Deepwater Tano license and holds a 49.95% interest. Partners include Kosmos Energy (18%), Anadarko Petroleum (18%), Sabre (4.05%) and the Ghana National Petroleum Corp. (10%).

At press time, Total announced it made a final investment decision on the $16 bil- lion Kaombo project, in up to 200m water depth, offshore Angola. Two FPSOs, to be converted tankers, are planned. Major contracts awarded to Aker Solutions, Saipmen, Technip and Heerema Marine Contractors. (See page 20.)

The TEN development project includes the collective developments of Tweneboa, Enyenra (formerly Owo), and Ntomme. The three oil and gas fields are found in water depths ranging from 320ft-6561ft, and the development is located 15mi from the Tullow-operated Jubilee field. It is the first deepwater field to be developed in offshore Ghana. First production is expected mid-2016. A peak production rate of 100,000b/d is expected by 2018, with ultimate recovery of about 216MMbbl.

Tullow will jointly develop the three fields using a single FPSO facility. A total of 33 wells are planned, including 15 oil production, 15 water injection, one gas production and two gas injection wells, with another 16 planned depending on production levels.

Three FPSO contractors, including Modec, are participating in the FEED for the vessel, which will have a process- ing capacity of 105,000b/d, and will be spread-moored with an oil offloading buoy. INTECSEA will conduct the FEED for the subsea infrastructure.

Offshore Congo, Total continues devel- opment of its Moho-Bilondo oil field—the first ultra-deepwater offshore field of the Republic of the Congo. The field was found in water depths ranging between 1970ft and 2950ft. Total, via its Congolese subsidiary Total E&P Congo, holds a work- ing interest of 53.5% and is the operator. Chevron and SNPC have working interests of 31.5% and 15%, respectively, in the field. The Moho-Bilondo includes the

Bilondo, Mobim, Moho Nord Marine-1 and 2, and Moho Nord Marine-3 reservoirs.

The Moho-Bilondo’s first project phase targeted the Mobim and Bilondo reservoirs that were brought onstream with plateau production of 90,000b/d. Construction on the second phase, which includes development of northern part of the license, began in 2013 after FEED studies were completed. The project will require an investment of $8 billion and is expected onstream in 2016.

The Moho-Bilondo floating production unit was designed by Doris Engineering and built by Hyundai Heavy Industries (HHI) under a $400 million engineering, procurement, construction, and installation contract. Aker Solutions has been commissioned to deliver the subsea production system.

Asia Pacific

Offshore Indonesia is home to the Abadi gas field in the Masela block in the Arafura Sea. The field lies in 984-3281ft water depth. Inpex Masela, a subsidiary of Japan’s Inpex, operates the field with a 60% interest after transferring 30%

to Shell Upstream Overseas Services in exchange for its expertise in floating LNG (FLNG) technology. PT EMP Energi Indonesia owns the remaining 10%. First production is expected in 2018 with an initial output of 2.5MTPA of LNG and 8000b/d of condensate. The field is esti- mated to contain 10Tcf of gas.

Wood Group’s Indonesia subsidiary will conduct FEED for subsea production facilities, including detailed engineering for subsea, umbilical, riser and flowline works. Phased development plans include the subsea production system and FLNG.

About 18 directional production wells will be drilled from five subsea drilling centers, and initial development will be carried out in the northern portion of the field where most of the reserves are concentrated. In January 2013, Inpex awarded the FEED contract for the FLNG to JGC and PT Saipem Indonesia Group. The EPC contracts are expected to be awarded 2014-2018. According to recent reports, Abadi partners will invest more than $19 billion in the development.

Middle East

Noble Energy continues to develop its Leviathan gas field in the eastern Mediterranean Sea. Leviathan is in 5396ft water depth in the Levantine Basin, offshore Israel. In February, Woodside and the Leviathan joint-venture participants, Noble Energy Mediterranean Ltd, Delek Drilling LP, Avner Oil Exploration LP, and Ratio Oil Exploration LP agreed to convert a previous agreement for an interest in Leviathan into a non-binding memorandum of understanding (MoU). The MoU is a framework for the acquisition of a 25% participating interest in each of the 349/Rachel and 350/Amit petroleum licenses. Woodside would operate any LNG development of the field, while Noble Energy will remain the upstream operator. As of press time, Woodside announced that the project partners have not executed the definitive agreements by the target date of 27 March 2014. Discussions are ongoing between the Leviathan partners and the Israeli Government.

According to US Geological Survey estimates, the Levantine Basin holds about 1.7 billion bbl of oil and 122Tcf of gas. The partners’ plans for the domes- tic gas phase for Leviathan are well advanced, while FEED studies for the second phase will begin in late 2014. A possible final investment decision trigger point should be reached in late 2015. If approved, production is expected to com- mence in 2017.

Offshore Azerbaijan, the Shah Deniz oil field lies in the South Caspian Sea in up to 1968ft water depth. in the south- eastern section. BP, with a share of 25.5% in the project, is the operator. The other PSA partners are Statoil (25.5%), Socar, Lukoil, Total, and Nico (10% each) and Tpao (9%).

Stage two of Shah Deniz will triple the field’s production by drilling 30 subsea wells and constructing two offshore production platforms. Engineering studies on the full-field development are being carried out and first gas from stage two is expected in 2016.