E&P companies are ramping up exploration of deepwater and ultra-deepwater reservoirs, encouraged by attractive oil prices. New developments spread across offshore Africa, Asia Pacific, Europe, Middle East and North and South America. Jeannie Stell showcases a few projects in water depths exceeding 1500ft.
Deepwater developments continue to increase, as operators delve into deeper and more complex formations from which to produce oil and gas. Although the sector sees significant long-term opportunities, taking on deepwater subsea challenges is not for the faint of heart.
Deepwater projects are capital-intensive, bringing economic and technical challenges along with soaring revenues for international E&P companies and oilfield service and equipment vendors. According to a February 2013 report by energy advisory firm Douglas-Westwood, more than $232 billion will be spent on deepwater excursions between now and 2020.
For decades, developments offshore Africa provided a wealth of oil and gas reserves and production, and the hits keep coming. The area is one of the most significant deepwater regions in the world. Nigeria and Angola lead the region with estimated reserves reaching more than 45 billion boe.
In addition to Africa’s West Coast activity, its East Coast is emerging as an area of interest to E&Ps. New resources are being sought in Kenya, Tanzania, Mozambique, and Madagascar.
Total likes its chances in Africa. Total E&P Angola continues work on its CLOV find, an integrated development comprised of Cravo, Lirio, Orquidea and Violeta. There, a new purpose-built FPSO will be constructed by Daewoo Shipbuilding & Marine Engineering. Expected delivery is May 2013.
Meanwhile, Total continues to explore its options at its ultra-deep offshore Block 32. Appraisal work is continuing and first production could come from the central-southeastern portion of the block in the Kaombo project. Total is considering a pair of FPSOs for the project.
On March 22, the operator announced its final investment decision (a whopping $10 billion) and EPC contract awards for the Moho Nord development off Congo. The Moho Nord project will target additional reserves, estimated to be about 485MMboe. The project is the latest step in developing the license, following on the success of Moho Bilondo Phase 1E.
For Moho Nord, 17 subsea wells targeting Miocene reservoirs will be drilled and tied back to a new FPU and 17 more subsea wells targeting Albian reservoirs will be developed from a newbuild TLP. Before being exported by pipeline to the onshore Djeno Terminal, the new production will be processed on the FPU, which will have a capacity of 100,000b/d.Total expects first oil in 2015 with output reaching 140,000b/d in 2017. Total E&P Congo operates 10 of the 22 fields developed, accounting for nearly 60% of national output.
Offshore Nigeria, Total is working its Egina oil field and hopes to deliver first oil in 2015. In March, Total Nigeria awarded a $3.1 billion FPSO vessel contract to Samsung Heavy Industries. The vessel will be based in the Egina field, in OML130 near the Akpo field. The FPSO will measure 330m in length, 61m in width and 33.5m in depth, have a gross dry weight of 34,000 tonnes, and will store about two million barrels. Egina has reserve potential of more than 550MMboe, and will bring in first oil in 2015. The project is expected to show a projected peak production of 150,000b/d.
Offshore Ghana, Tullow Oil Plc is working its Jubilee and Tweneboa, Enyenra and Ntomme (TEN) developments. Work for Jubilee Phase 1A was approved by the Government of Ghana in early 2012 and development started later that year with the spudding of the first production well. During 2013, about $1.1 billion capital spend will pay for five new producing wells, three new water injection wells and an expansion of the subsea network.
In March, Tullow signed a five-year contract with FMC Technologies for offshore and onshore technical services including maintenance, refurbishment, and inspection of equipment and tooling for the Jubilee field.
For now, the field is producing 110,000b/d. The combination of Phase 1 remediation work and additional Phase 1A wells is expected to ramp up production to more than 120,000b/d by yearend 2013.
Also offshore Ghana, Tullow is continuing development of its TEN project, which is being designed with sufficient flexibility to allow both TEN resources and nearby discoveries to be tied into an FPSO.
The data from appraisal activity in the first half of 2012 resulted in updated subsurface models for the TEN fields. The combined resources range is from 200MM - 600MMboe, with likely resources of 360MMboe million BOE, of which 70% is oil.
Malaysia continues as the go-to region for deepwater developers; Shell is working on its Gumusut-Kakap and Malikai projects.
The Gumusut-Kakap project includes joint development of two ultra-deepwater discoveries. Sabah Shell is the operator of Gumusut and Murphy Oil is the operator of the Kakap field. Field development is underway, and an average production of 135,000b/d is expected.
The oil project will be developed with 19 subsea wells tied back to a FPS that will weigh more than 40,000 tonnes and have a processing capacity of 150,000b/d. Produced crude will be exported through a pipeline to a new processing facility being built at Kimanis, Sabah province. Processed gas will go to the Petronas LNG Complex in Bintulu, Sarawak province, and some produced gas will be re-injected to enhance oil recovery.
The project will use a modular-tree concept to enable versatility for production, water injection, and gas injection tree styles. Three production manifolds will be included with dual 8in. headers and 6in. branches for production, water injection, and gas injection configuration. The manifold valves will be controlled by a manifold-mounted subsea control module. The jumper connection systems will use connector systems with integral hydraulics and metal-to-metal gaskets.
In March, Shell Malaysia and its partners announced their final investment decision to develop the Malikai oil field. Shell Malaysia and Conoco Phillips hold 35% interest each and Petronas Carigali holds 30%. The field will be operated by Sabah Shell Petroleum Co.
Development will include 17 wells drilled from a TLP—the first of its kind to be fabricated and installed in the country. Engineering, procurement and construction contracts for the TLP have been awarded.
Technip was awarded the pipelines contract, which includes transportation, installation and pre-commissioning of an 8in.-diameter, 32mi. natural gas pipeline and a 10in.-diameter, 35mi. liquid pipeline, as well as steel catenary risers. The pipelines will connect the Malikai TLP to the Kebabangan platform. Technip’s contract is scheduled to be completed by 3Q 2015. Offshore installation will be done by Technip’s flagship S-Lay vessel. Dril-Quip Asia Pacific Pte Ltd. will supply subsea wellheads, tensioner systems, risers, production and injection trees, and tieback connectors through its local representative UMW Petrodril (Malaysia) Sdn. Bhd. Delivery of that equipment is scheduled to begin in 2014.
Murphy Oil is busy working to develop its Siakap North-Petai project off Malaysia. Murphy is operator with 32% interest. Its partners include Petronas with 26%, and ConocoPhillips and Shell with 21% each. The Petai-1 well was drilled in 2007 with an oil discovery and more drilling occurred in 2008. Unitization of Petai and the Siakap North Field in Block K was completed in 2011. First production is expected in third-quarter 2013.
McDermott won the subsea contract, from Murphy Sabah Oil Co., to execute deepwater engineering, procurement, construction, transportation, installation and commissioning activities. The field is near the existing Kikeh field, northwest of Labuan Island, Malaysia, in waters measuring 3,900ft to 4,900ft deep.
McDermott’s field architecture will include two rigid, insulated, pipe-in-pipe production flowlines, one rigid water injection flowline, and one main umbilical system. The umbilicals will connect eight new manifolds and subsea distribution units to existing riser slots on the Kikeh FPSO. The development includes five water-injection and eight production wells, drilled from the manifolds at each of the four drill-centers.
Murphy awarded Aker Solutions the contract for the 13 subsea trees, eight manifolds, well jumpers, engineering for topside controls, and life-cycle support services.
In China, Husky Energy is focused on advancing the development of three major natural gas fields in Block 29/26 in the South China Sea. The company’s deepwater Liwan 3-1 gas field is considered a cornerstone development for its Liuhua 34-2 and Liuhua 29-1 fields, which will share infrastructure. Husky partnered with CNOOC to develop the fields.
First gas production is anticipated in late 2013, ramping up through 2014 from its Liwan 3-1 natural gas project. Husky will operate the deepwater portion of the Liwan 3-1 field, including development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow water platform. CNOOC will operate the shallow water infrastructure, including the platform, subsea pipeline to shore, and the onshore gas processing plant. Field development will include a subsea production system connected by flow lines and manifolds to a central shallow water platform, which in turn will be connected by pipeline to an onshore gas plant.
The Liuhua 34-2 field will be developed in parallel with the Liwan 3-1 field. Gas production from the Liuhua 29-1 field will share common gas processing and transportation infrastructure with Liwan 3-1 and Liuhua 34-2 and is expected to be onstream in 2014.
Off western Australia, Shell and Chevron (operator) continue to focus on the Gorgon project. The development is one of the largest natural gas projects in the world and includes five fields: Gorgon, Chrysaor, Dionysus, West Tryal Rocks, and Spar.
The Gorgon field has eight wells. First gas is expected in 2014, and is intended to supply Osaka Gas, Tokyo Gas, GS Caltex, Chubu Electric, and Nippon Oil Corp. The project is 55% complete and is expected to produce 15.6MM tonnes/year to feed liquefied natural gas into the markets by 2015. The project also includes the world's largest carbon capture and storage project.
Off the Shetland Islands lies the Rosebank oil and gas field in Blocks 213/26 and 213/27 of production license 1026. Chevron is the operator of the field with 40% interest; partners include Statoil (30%), OMV (20%), and Dong Exploration & Production (10%).
Rosebank is considered one of the biggest prospects in the UK Continental Shelf and Chevron plans to invest about $7 billion in its development.
The project is currently in the front-end engineering and design (FEED) stage. A final investment decision for the project is expected in 2013, followed by a drilling program in 2015. First production is expected in 2017. Chevron North Sea Ltd. awarded WorleyParsons and its INTECSEA subsidiary a FEED contract for new facilities associated with Rosebank field. The project will include an FPSO and subsea infrastructure. Exploration efforts off Norway continue to please operators. Statoil is preparing to install a platform at the Aasta Hansteen gas field, formerly Luva, in Blocks 6706/12, 6707/10, about 186mi. (300km) offshore in 4,265ft (1,300m) water-depth. The deepwater platform will be the first of its kind on the NCS with a production capacity of about 800MMcf/d. Earlier this year, Italian energy company Eni secured a license to explore new acreage in the Barents Sea. The license covers about 160sq mi in the Barents Sea, east of Eni’s Goliat field. Also, Statoil and its partners Eni Norge and Petoro drilled a discovery well on the Havis prospect in the Barents Sea, estimated to hold at least 200MMboe.
In the Middle East, Noble Energy couldn’t be more pleased with its developments off Israel. In March, the company reported results from its second Leviathan appraisal well in the Rachel license. At its discovery, the Leviathan gas field was the most prominent field ever found in the (evidently under-explored) Levantine Basin. Production is expected to begin in 2017.
The Leviathan #4 appraisal well, drilled to a total depth of 16,992ft, encountered 454 net feet of gas pay in multiple intervals—the thickest net pay of any well drilled to date at Leviathan. This led to an increase in the estimated recoverable gross mean resources of the field to about 18Tcf. Assessment of pre-FEED is in progress, with initial production likely to begin in 2016.
In April, Noble announced that its Tamar natural gas field off Israel was successfully brought online with all five subsea wells producing at stable rates, totaling 300MMcf/d. When combined with existing Mari-B volumes, the total current sales are nearly 500MMcf/d and are expected to average 700MMcf/d through 2013. Initial sales began on March 31 as natural gas flowed from the field to the Tamar platform, and then onward to the Ashdod Onshore Terminal. The development is designed to deliver natural gas rates up to 1Bcf/d. The Tamar development includes five subsea wells capable of flowing 250MMcf/d each. Natural gas will flow from the field through the longest subsea tieback in the world, more than 90mi. long, to a platform near the existing Mari-B structure. The Tamar platform is tied into the existing pipeline that delivers natural gas to the Ashdod onshore receiving terminal.
Offshore Egypt, BP wants to close the gap of the domestic gas demand by covering 100% of Egypt’s needs with its West Nile Delta development. West Nile Delta includes the North Alexandria, where BP holds 60% and is operator. RWE Dea owns the remaining 40%. In the West Mediterranean Deep Water license, BP is the operator with 80% working interest and RWE Dea has 20%. The West Nile Delta project has been planned to begin commercial operations by 2015.
KBR has been selected by BP to undertake the second stage of concept selection and definition for the onshore terminal and export pipelines for the resource. The scope of work includes developing a technical definition package for an onshore terminal that will process 1,000MMcf/d of natural gas and condensate. The award follows the execution of the project's first stage by KBR, and builds upon the feasibility work completed by KBR's consulting subsidiary, Granherne.
Deepwater drilling and production activities in the Gulf of Mexico began to increase at the end of the drilling moratorium instituted in 2011. Several projects are under development.
Chevron is working on its Jack/St. Malo, Big Foot, and Tubular Bells projects. Jack/St. Malo (Walker Ridge Blocks 758 and 759) is about 55% complete and Big Foot (Walker Ridge Block 29) is about 65% complete. First production for all three projects is expected in 2014.
Hess, the operator of Tubular Bells in Mississippi Canyon Block 725, holds a 57.14% interest in the field. Chevron holds 42.86%. Hess and Chevron will spend $2.3 billion on the project, which will include three subsea production wells and two water injection wells, drilled from two subsea drill centers that will be tied back to the Gulfstar FPS, owned by Williams Partners. According to Williams, the FPS will be the first spar-based floating production system with major components to be built entirely on the Gulf Coast.
Williams Partners will provide production handling, export pipelines, gathering pipelines, and gas-processing services for the development. Initial production from the discovery is expected in 2014. Current estimates indicate peak production at nearly 45,000b/d, as the field could have about 120MMboe of reserves.
Anadarko Petroleum is working two major developments in the Gulf. Its Lucius project development is 230mi. offshore in Keathley Canyon Blocks 874, 875, 918 and 919, in 7,200ft of water. The project will be developed using a truss spar with the capacity to produce 80,000b/d and 450MMcf/d from six subsea wells.
Anadarko is also developing the Heidelberg field in Green Canyon Blocks 816, 859, 860 and 903. It tapped Technip to build and deliver a truss spar hull for Heidelberg. The spar will have a capacity of 80,000b/d and 81MMcf/d.
In March, Anadarko signed an agreement with an undisclosed party to enter into a carried-interest arrangement for a portion of Anadarko's ownership in the Heidelberg project. Anadarko will be carried for $860 million, representing its expected capital requirements until mid-2016 when the company expects the project to come onstream. In exchange, Anadarko will convey a 12.75% working interest in the Heidelberg development. Anadarko will continue as operator with a 31.5% working interest.
In the Atwater Foldbelt, BHP Billiton’s Mad Dog Phase-2 project is underway. Operated by BP in southern Green Canyon, the project will include a second spar and subsea production and injection wells. First production is scheduled for 2018.
ExxonMobil is progressing with its 2008 Julia discovery in Walker Ridge. Julia is the first well drilled under the 2005 agreement between StatoilHydro and ExxonMobil to explore the deepwater Gulf of Mexico, and is believed to be the largest find in the Gulf of Mexico since BP proved up the Thunder Horse field in 1999.
LLOG Exploration has awarded contracts for its Delta House project in Mississippi Canyon Block 254. Hyundai Heavy Industries will build a semisubmersible hull in Ulsan, South Korea, to house a floating production system (FPS). The OPTI-hull design by Exmar is the second commissioned by LLOG. The first is serving LLOG’s Who Dat field. Topsides for the Delta House FPS will be fabricated at Kiewit Offshore Services yard in Ingleside, Texas.
Offshore Brazil continues to be a prolific region for Petrobras. Industry experts believe the region holds an estimated 31 billion boe of reserves in deepwater, pre-salt fields. As a result, Petrobras plans to build 24 pre-salt production systems by 2020.
Petrobras began oil production from its Baleia Azul, Jubarte and Pirambu fields in the Campos basin using the Cidade de Anchieta FPSO. Peak production is expected to reach 100,000b/d by second-quarter 2013. The Sapinhoá field will be produced by the Cidade São Paulo FPSO. Lula NE will be produced by the Cidade Paraty FPSO. The company will charter another FPSO for its Iraceme Norte field in 2016. There, eight production and eight injection wells will by tied back to the FPSO.
In its Carioca project, Petrobras completed drilling Carioca Norte in the pre-salt layer of Santos Basin. Results obtained confirm the presence of light oil that had already been confirmed by wells 1-BRSA-491-SPS, Carioca Nordeste, and Carioca Sela.
At the Iara project, Petrobras confirmed oil in well 3-RJS-706 in Block BMS-11 in March, the fourth well drilled in the play. Further drilling will define the parameters of the field.
Petrobras moved forward on the Lula development in March, announcing that negotiations are underway with consortium partners Queiroz Galvão Óleo e Gás S.A. and SBM Offshore. The contracts are for two FPSOs at Lula Alto and Lula Central, in the pre-salt cluster of the Santos Basin. Each facility will be tied to 18 wells (10 production, 8 injector). Each FPSO will have a processing capacity of 150,000bo/d and 6,000,000cu m/d of gas. The FPSOs are expected on site in 2015 for Lula Alto and in 2016 for Lula Central. Production is planned to begin in January 2016 at Lula Alto and in March 2016 at Lula Central.
For the Papa Terra project, construction of the Petrobras P-63 FPSO is nearing completion at Cosco's shipyard in China. The project will include three power modules with two 18-cylinder, 50DF dual-fuel engines per module, to be powered by treated well gas, crude, or marine grade diesel. Final commissioning of the engines will take place in late 2013 once the vessel is on location.
Clearly, deepwater oil and gas developments continue to be an integral part of the world’s energy mix. As legacy onshore reservoirs are depleted, E&Ps are turning to deeper and more complex subsea developments, with many engineering and technical challenges. Subsea reservoirs challenges include hard rock, thick salt, and tightly-packed sands.
Such developments now account for more than 6% of global oil production. According to a recent statement by BP plc, that estimate is expected to rise to 9% by 2030. All indications are that E&P companies, service and supply providers are up to the task. Look for an update of this report in 2014. OE