|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.
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.
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.
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.
Offshore UK, Total E&P UK (with 80% operating interest) and Dong E&P (20%) are nearing the final production on their US$5.5 billion (£3.3 billion) Laggan and Tormore gas and condensate project, located northwest of the Shetland Islands in about 1968ft of water. The field will be developed as a long subsea tie-back to the new Shetland gas plant, which is being built at Sullom Voe. The plant will include eight subsea wells and one subsea production system each for Laggan and Tormor and two six-slot production manifold templates. The total field reserves are expected to exceed 1Tcf ofgas and condensates. Total says production capacity is 90,000boe/d, with peak production listed at 500MMscf/d of gas and condensate. Ode and its majority owner Doris Engineering won the contract for basic engineering of the field development, including the subsea infrastructure, gas treatment plant, and the export pipeline. FMC Technologies will supply the field subsea production systems. First production is expected by late 2014.
Offshore the Shetland Islands, operator Chevron (40% interest) is reassessing its 3700ft deep Rosebank oil and gas field. Its partners are OMV (60% interest), OMV (20%) and Dong Exploration & Production (10%). A drilling program was expected in 2015, followed by first production in 2017; however, Chevron announced last year that the JV’s focus is on making the right decisions, not on schedules and timelines.
Offshore Norway, Statoil is developing its 4265ft-water depth Aasta Hansteen gas field in blocks 6706/12 and 6707/10 in the Norwegian sector of the North Sea in production license 218. ExxonMobil (15%) and ConocoPhillips (10%) hold interests in the reservoir.
The field is estimated to contain up to 60Bcm of gas and 5.6MMbbl condensate. It will be developed with a spar platform (OE: March 2014) featuring a processing facility, a single vertical cylinder, two sub- sea templates with four wells on each, and a satellite template with one well, as well as condensate and gas storage facilities.
Aker Solutions and Technip won the FEED contract, which includes design, planning, procurement, construction, and transportation of a spar hull and the mooring systems. Work also includes the design of the steel catenary risers. First gas production is expected by late 2014.
Royal Dutch Shell is working on its Cardamom oil and gas field in block 427 of the Garden Banks in the Gulf of Mexico (GOM). The field, in 2720ft water depth, is under development with a $2.5 billion price tag. This was the first project to be approved since the lifting of the moratorium on deep drilling in GOM following the Macondo spill in 2010.
Cardamom will eventually produce 50,000b/d at peak production. The development plan includes subsea tiebacks to the Auger tension leg platform sited about 9200ft west of Cardamom. The new subsea system will include five well expandable manifolds, a dual flowline, and eight well umbilicals. A contract for the subsea and topside systems was awarded to FMC Technologies, which will supply five 15,000psi subsea production trees, control equipment, and manifold and tie-in equipment. DUCO, a subsidiary of Technip, won the contract to construct the umbilicals. First oil is expected in late 2017.
Also in the GOM, Anadarko and its partners continue to develop the Heidelberg field offshore Louisiana in 5310ft water depth. The field includes Green Canyon blocks 859, 860, 903,904, and 948. Heidelberg is estimated to contain about 200MMbo. The Heidelberg development was sanctioned in 2Q 2013, with production expected in 2016. A truss spar will be used as the drilling and production platform.
Technip was contracted for the engineer- ing, construction, and transport, and the detailed hull design and fabrication will be conducted in Pori, Finland. Technip sub- contracted First Subsea to supply the sub- sea mooring connectors for the Heidelberg truss spar platform. FMC Technologies received the contract to supply subsea equipment, including five enhanced horizontal subsea trees, tree-mounted con- trols, and two manifolds. Subsea 7 holds the contract for engineering, fabrication, and installation of risers, pipelines, and flowlines. The offshore work is expected to start year-end 2014 and will utilize the Seven Borealis pipelay vessel.
The Chevron-operated Jack-St Malo deepwater project (51%) is also under- way. Its partners include Petrobras (25%), Statoil (21.5%), ExxonMobil (1.25%), and ENI (1.25%). The Jack field lies in Walker Ridge blocks 758 and 759 in 7000ft water depth. The St Malo field lies in Walker Ridge Block 678 in 2100ft water depth.
Cameron was awarded a $230 million contract to supply subsea equipment, engineering, and project management services, and will provide 12 subsea trees with 15,000psi along with manifolds and related connection systems. Wood Group company Mustang conducted the FEED and will produce a detailed design for the topsides. Saipem will transport and install the crude oil export pipeline, and Wood Group will commission the facility. McDermott International will fabricate and install subsea equipment, including umbilicals, jumpers, and control systems, and KBR will provide detailed design services. Production start-up is expected in late 2014.
Elsewhere, ExxonMobil (50%), along with partner Statoil (50%) and future oper- ator Chevron, are moving forward with the Julia oil field in the GOM. The first phase of the field’s development began in May 2013, with a capital spend of $4 billion. Julia’s first production is expected in 2016 with an initial production capacity of 34,000b/d. FMC Technologies will provide six subsea trees, a manifold, and associated tie-in equipment.
Petrobras is developing its Iara oil field in the Santos Basin off Rio de Janeiro. The light oil field near the Lula field sits in 2230ft of water.
Aker Solutions will supply 40 subsea trees for the Iara and associated Sapinhoá field. The project will include 40 vertical subsea trees, subsea control systems, and 17 complete tool sets to be installed by late 2014. Engevix Engenharia won the EPC contract worth $3.5 billion for eight hulls for FPSOs to be used in blocks BM-S-11 and BM-S-9 of the field. A total of six vessels will be allocated to block BM-S- 11, including the Lula, Iracema, and Iara discoveries, and the rest will be dedi- cated to block BM-S-9, which includes the Sapinhoá and Lapa discoveries. The subsea production from Iara is expected by 2017.
Going forward, global offshore E&P companies continue to see deepwater developments, and their associated high production rates, as viable economic opportunities for the foreseeable future.