One portion of the Golden Triangle – the Gulf of Mexico – has slipped a notch in its dominance of the global deepwater play while activities in the other two corners – West Africa and Brazil – amped up. In addition, a new region has joined the report this year. Jennifer Pallanich looks at projects in various stages from near sanction to newly producing in water depths exceeding 1500ft.
Africa is hopping. That is, at least, if you’re in the deepwater offshore oil & gas business. Project levels off West Africa have jumped, and there is now a project in the design phase offshore East Africa.
The diversity of projects and operators in the deep waters off the coast of West Africa translates into a variety of development solutions. Several operators remain focused on continuing to develop projects in proven blocks.
One such example is Total, which brought its Pazflor development offshore Angola onstream last year in block 17 and is hard at work on its CLOV development in the same block. Similarly, BP is working on its PSVM development in block 31 offshore Angola and is considering development of block 31 SE. Eni has at least two projects under development in the deep waters offshore Angola – East Hub and West Hub, both in block 15/06.
Since OE’s last report, three major developments – that is, those with significant investment in surface facilities in addition to the subsea infrastructure – offshore West Africa have begun development: The Noble Energy-operated Aseng project and Pazflor and Usan, both operated by Total.
Shifting to the other side of the continent, early exploration efforts off Mozambique by Anadarko have turned up sizable gas discoveries. The US-based independent has an LNG project off the coasts of Mozambique in the design phase.
Petrobras remains on track to invest heavily in its pre-salt deepwater play offshore Brazil. The operator has a series of both pre-salt and post-salt developments in progress. While other operators do have expansion projects – read subsea – ongoing in the deepwater arena off Brazil, Petrobras looks to be the only operator with significant new surface facility investments sanctioned for installation in the near future.
The operator is adhering to its plan of running extended well tests to learn more about the reservoirs at its various deepwater pre-salt fields. Petrobras has said it is using the data resulting from these tests to refine its development plans for the various pre-salt fields. As such, fields with ongoing EWTs are listed as still under development, rather than in the production phase.
This year’s report covers only eight projects in the deepwater Gulf of Mexico. Again, this is surface facility investment only, not subsea-only projects. It appears the 2010 Macondo spill could still be affecting operations in the Gulf of Mexico, given the long lead time associated with the industry.
Since the 2011 report, only two Gulf fields from last year’s report have begun production – Petrobras’ long-delayed Cascade-Chinook FPSO project and the Who Dat development by indy LLOG.
Five projects in the Gulf of Mexico are under development, and one other project seems near sanction.
Western Europe entered the roundup last year with the Laggan-Tormore subsea project, groundbreaking for its depths. This year, a second deepwater project – this time a spar in the form of the Luva development – has joined the ranks.
Many of the projects in the Asia-Pacific region involve subsea installations in deepwater feeding back to surface facilities in shallower water or onshore, such as with Husky Energy’s Liwan development off China and Chevron’s Gorgon development off Western Australia.
Finally, both of the highlighted projects in the Middle East this year are of the subsea variety.
This year’s report drops a couple of projects that had lingered in limbo between appraisal and planning; should they move into firm plan or development status, they will be returned to the project-by-project summary at that point.
In the pages that follow, OE updates projects from last year’s report and provides details on new projects that have been added. Where information hasn’t been provided by operators or contractors, the data comes from publicly available information and analysis. The updates pick up where last year’s report (OEApril 2011) left off and include projects that began production, received sanction, are under development, or are near a final investment decision.
- This report features deepwater developments around the world in depths exceeding 1500ft, with the exclusion of subsea tieback developments in the Gulf of Mexico, which OE will report on later this year.
Arafura Sea, Indonesia
FEED contracts are expected out this year for the Abadi Masela FLNG project in the Arafura Sea, offshore Indonesia. The development – which received Indonesian government approval in late 2010 – calls for a floating LNG facility to produce 2.5mtpa during the first phase.
Shortly after government authorities okayed the FLNG development, Inpex teamed up with Shell, which sanctioned its Prelude FLNG project offshore Western Australia in May 2011.
Inpex has said it anticipates making a final investment decision on the project no earlier than 2013. First gas would be 2018 at the earliest. The field is thought to hold over 10tcf of natural gas reserves.
The Masela block is along Indonesia’s international water boundary with Australia. The Abadi-1 exploratory well in 2000 marked the first discovery of crude oil and natural gas in the Indonesian sector of the Arafura Sea.
Inpex operates the Masela block in 2300ft water depth with 60% interest on behalf of partners Shell (30%) and PT EMP Energi Indonesia (10%).
Espírito Santo Basin, Brazil
Petrobras expects first oil at its Baleia Azul field in the Espírito Santo Basin offshore Brazil in 3Q 2012. The operator is relocating the former FPSO Espadarte, now the FPSO Cidade de Anchieta, to the pre-salt Baleia Azul field in 4590ft water depth. The FPSO has seen modifications and upgrades, so that it can handle its new duties in the deepwater field. Modifications include revamping the hull for an additional 18 years of operation, changing out the gas compression and treatment system, upgrading the injection system, adding a sulfate processing unit, replacing pipes, and modifying the turret for increased capacity. It is slated for mooring in 3Q 2012 in over 4000ft of water.
The FPSO will be connected to five producing wells and two water injection wells. Cidade de Anchieta will be able to produce 100,000b/d of oil and compress 3.5mmcm/d of gas.
Petrobras discovered pre-salt oil at this field in November 2008. The field is in an area known as Parque das Baleias, which also contains the Jubarte, Baleia Franca, Baleia Ana and Cachalote fields.
AsengBlock I, Equatorial GuineaNoble Energy
The Aseng field began production to the FPSO Aseng on 6 November 2011. Noble Energy’s deepwater field in block I offshore Equatorial Guinea went onstream seven months ahead of the scheduled mid-2012 startup at 13% under budget. It is the oil company’s first operated project in the region.
The company sanctioned the $1.3 billion Aseng project in July 2009; formerly called Benita, the field was discovered in 2007 to hold gas and condensate with a later well finding oil. The development plan for the field calls for five subsea production wells flowing to the FPSO Aseng. There, the production stream is separated, with oil stored on the vessel and the natural gas and water reinjected into the reservoir to maintain pressure and maximize recovery. The plans call for three water injectors and two gas injectors.
FPSO Aseng in 3281ft water depth can process 120,000b/d of liquids, including 80,000b/d of oil, and can inject up to 150,000b/d of water. It can also handle 170mmcf/d of gas. It has storage capacity of 1.6 million barrels of oil, including up to 500,000 barrels of condensate.
The Atwood Hunter and Pride South Pacific drilled and completed the wells. The field holds 10 subsea trees. InterMoor provided the design, engineering, procurement and installation services for preset moorings in 3445ft of water.
In August 2011, Delmar Systems supplied an eight-leg preset mooring system for use in Noble Energy’s Aseng development. Delmar delivered the mooring equipment, including Delmar’s OMNI-Max anchors and Delmar Subsea Connectors.
Technip handled engineering, supplying, installing and pre-commissioning the 30km of flexible pipe system, including six flexible risers, flexible flowlines and jumpers.
Keppel began converting the VLCC M/T Bauhinia in 2Q 2010 into the FPSO Aseng in Singapore. Keppel’s work included refurbishment and life extension works, upgrading the accommodation facilities, installing and integrating the topsides as well as fabricating and integrating the internal turret.
Champion Technologies won the chemical management services contract for the Aseng field. The five-year deal announced in May 2011 is Champion’s first deepwater chemical management services contract in West Africa. Champion plans to build a base in Luba’s Freeport Zone. The base will include office space, a fit-for-purpose laboratory, warehouse, and a blending facility.
Champion said it will assist Noble Energy in tackling the challenges faced in producing, storing and transporting crude oil that has a high pour point, using some of key products from its flow assurance portfolio.
Noble Energy says it expects to produce gross hydrocarbon liquids of 100-120 million barrels plus an estimated 450-550bcf of gas resources that will be produced as part of an integrated gas monetization project once the pressure maintenance phase is completed over the life of the project.
The operator plans to use the FPSO as a liquids hub for future developments in the area. Noble Energy says the Alen field development – on schedule for first production in late 2013 – will be the first project tied back to the FPSO Aseng.
SBM has turned over the FPSO to operator Noble Energy, which has a 15-year contract for provision, lease and operation of the vessel. SBM Offshore owns and operates the FPSO Aseng with 60% on behalf of joint venture partner Compania Nacional de Petroleo de Guinea Ecuatorial (GEPetrol), the state oil company of Equatorial Guinea, with the remaining 40%.
Noble Energy operates the Aseng field with 38% interest on behalf of partners Atlas Petroleum (27.55%), Glencore Exploration (23.75%), PA Resources (5.7%) and GEPetrol (5%).
WR29, US Gulf of Mexico
About a year after the December 2010 sanctioning of its $4 billion Big Foot deepwater development in the Gulf of Mexico, Chevron said the project was about 20% complete. The field, located in the Walker Ridge block 29 area, is expected to begin production in 2014.
Chevron is developing the field, which has an estimated production life of two decades, with an extended TLP (ETLP) installed in about 5200ft of water.
In July 2011, GE Oil & Gas’ Drilling & Production business won a $45 million contract to supply and service the ETLP marine riser tensioner systems for the Big Foot field. GE is making design modifications to develop ‘push-up’ style marine riser tensioner equipment to enable the Big Foot ETLP to deal with the wave and current movement conditions where it will be moored.
2H Offshore announced in October 2011 it had won the contract to handle the detailed design and procurement management of the Big Foot riser systems, which will comprise two high pressure drilling risers, 15 production/ water injection top tensioned risers and oil and gas export steel catenary risers. Its Houston office will house the entire Big Foot riser team, combining 2H and Chevron engineers in a single space for the duration of the project.
BMT is creating a simulation facility in Houston to train marine personnel involved with inshore platform towing from Texas yards. The November 2011 announcement came after Hereema Marine Contractors awarded a contract to BMT Fluid Mechanics and BMT Argoss to provide tow simulation services for the inshore tow of the Big Foot production platform.
FloaTEC won the FEED for the ETLP hull design. KBR carried out the topsides FEED and won the topsides detailed design. Alliance Engineering carried out the topsides pre-FEED.
Enbridge is constructing a $250 million oil pipeline to serve Big Foot and the nearby Jack/St Malo development under a deal announced in 2009.
The Chevron-operated Big Foot ETLP will be installed at Walker Ridge block 29 in 5200ft of water beginning in November 2012, with first oil expected in 2014. The ETLP will have an on-board drilling rig and a production capacity of 75,000b/d and 25mmcf/d.
Discovered in 2006, the Big Foot field is estimated to contain total recoverable resources exceeding 200 million boe. Primary pay sands are Middle to Upper Miocene ranging from 19,000ft to 24,000ft and lie below a salt canopy ranging from 8000ft to 15,000ft thick. Chevron operates the field with 60% on behalf of Statoil (27.5%) and Shell (12.5%).
Shell’s Nigerian arm has submitted an updated field development plan for its Bonga SW/Aparo fields. In late 2011, the company wrapped up concept selection phase for the development. The company says it expects to begin front-end definition and tendering activities after 2012.
The original development plan called for an FPSO producing in OPL212 in about 4000ft of water beginning in 2010. That FPSO conversion was expected to have a storage capacity of 1.5 million barrels, production capacity of 150,000b/d and 175mmcf/d and an injection capacity of 240,000b/d of water. Nearly 30 trees were expected in the subsea system serving the Bonga Southwest and Aparo fields.
Shell has not disclosed the revised plans for the project. Opec has estimated the field will begin production in 2016 and add 200,000b/d to Nigeria’s production levels.
Bonga SW was discovered in 1995. Its neighbor, Bonga, went onstream in 2005, producing oil and gas to an FPSO with the capacity to produce over 200,000b/d and 150mmcf/d. Bonga was shut in briefly at the end of 2011 after oil was found to be leaking. The leak originated at one of the loading lines linking the Bonga FPSO in OML118 to an intermediate buoy, which is linked to a loading tanker.
Santos Basin, Brazil
Earlier this year, the extended well test at Carioca Nordeste was interrupted after a rupture of the production riser serving the FDPSO Dynamic Producer. The EWT had been in progress at the Dynamic Producer since October 2011. Petrobras said in early February it had wrapped up oil collection work; an estimated 160 barrels is said to have been released.
Petrobras says it will request approval to resume the Carioca Nordeste EWT after an investigation has been completed. The rupture took place in the pipeline connecting the well to the platform, and no oil leaked at the well, which was closed automatically after the pipeline broke.
In March 2011, the Dynamic Producer was shut down during the EWT of Guará (now Sapinhoa), another deepwater pre-salt field in block BM-S-9 in the Santos Basin.
|Cascade/ ChinookWR206/469, US Gulf of MexicoPetrobras|
In late February, Petrobras’ long-delayed Cascade/Chinook development delivered first oil. The Cascade 4 well had the honors of being the first to flow to the BW Pioneer, located in the Gulf of Mexico in 8200ft water depth.
Petrobras’ project had been expected to begin production in mid-2010. In early 2011, the US Bureau of Ocean Energy Management, Regulation & Enforcement gave Petrobras the final approval it needed to begin production at the Cascade/Chinook development in the deepwater Gulf of Mexico.
The is the first FPSO to begin production in the US sector of the Gulf of Mexico. Moored in Walker Ridge block 205, BW Pioneer can process 80,000b/d of oil and 500,000mmcm/d of gas. The FPSO has a disconnectable turret-buoy so it can move off location during a hurricane or tropical storm. BW Offshore has a contract to operate the FPSO on the Cascade and Chinook oil fields, with a firm period of five years and additional options for up to three years.
Production will travel through the five freestanding hybrid riser towers and link to the vessel through jumpers to a disconnectable turret. The use of the riser towers, transportation via shuttle tanker, electrical submersible pump-based subsea boosting system, and torpedo pile vertical loaded anchors are other firsts Petrobras brought to the Gulf of Mexico.
The Cascade 4 subsea production well was drilled and completed to 26,246ft vertical depth into the Lower Tertiary play.
BMT Scientific Marine Services has a five-year contract to provide support maintenance and repair for the free standing hybrid riser tower monitoring system. The company supplied the monitoring system in 2010 to monitor the stabilizing uplift forces on five riser towers and record riser, turret buoy and FPSO position, motion and mooring data.
Jumbo Offshore and Technip installed the five free standing hybrid risers for the Walker Ridge block 206/469 development. FMC supplied four enhanced horizontal subsea trees and three manifolds in addition to other subsea equipment. Aker provided power cables and carbon fiber rod umbilicals. Alliance Engineering verified engineering of the FPSO’s topsides.
Petrobras operates Cascade with 100% and Chinook with 67.7% on behalf of Total (33.3%).
In early 2011, Petrobras reported finding 26°API oil with the Carioca Nordeste well in 7057ft of water. The follow-up Carioca Sela well discovered 27°API oil in a similar water depth earlier this year. Based on exploratory results, the Petrobras-led group asked the ANP to delay a declaration of commerciality for the field until end-2013. During the extension, the group will drill up to three additional exploratory wells and carry out an EWT.
An FPSO is expected onstream in the field in 2014.
Petrobras operates block BM-S-9, holding both Carioca and Saphinhoá (formerly Guará), with 45% interest on behalf of partners BG (30%) and Repsol (25%).
Block 15/06, Angola
Eni is developing a pair of hubs in its deepwater block 15/06 offshore Angola. The West Hub project in 4590ft water depths is under development, and the East Hub project in 1550ft water depths received its final investment decision in late 2011. Both are expected to begin production in 2013.
Eni operates the block with 35% working interest on behalf of Sonangol E&P as the concessionaire and partners Sonangol Pesquisa e Produção (15%), SSI Fifteen (20%), Total (15%), Falcon Oil Holding Angola (5%), Petrobras International Braspetro (5%) and Statoil Angola Block 15/06 (5%).
The Egina project offshore Nigeria, now in the FEED stage, could be launched this year, according to operator Total. The field, in 5000ft water depth, would be served by an FPSO under the current development scenario. Total believes it could see first oil around 2016 from the project.
Total discovered the field in 2003. The French operator previously considered developing the field as a subsea tieback to Akpo. The number of discoveries however suggested a standalone development would be suitable.
Total operates OML 130 with 24% interest.
Makassar Strait, Indonesia
Chevron expects to reach a final investment decision on its Gendalo-Gehem development offshore Indonesia by the end of 2013. The project is on Chevron’s books as being in the design phase with no estimated date of first production. The project, which would tap fields in 3500-6600ft water depths in the Makassar Strait offshore East Kalimantan, Indonesia, calls for two hub developments, one named Gendalo, the other Gehem. The hubs would serve five fields: Bangka and Gehem in the Rapak concession and Gandang, Gendalo, and Maha in the Ganal concession.
Both hubs would feature a floating production unit, as well as subsea drill centers and export gas and condensate pipelines. The project also includes an onshore receiving facility.
In late 2010, Chevron awarded FEED contracts to Technip for the hull, topsides, mooring system and steel catenary risers for the FPUs, Worley Parsons for the subsea and flowline system and export pipelines, and Singgar Mulia for the onshore receiving facility.
Chevron expects maximum production to reach 1.1bcf/d of natural gas and 31,000b/d of condensate. It operates the project with 55% interest.
Block 17, Angola
First steel was cut for the CLOV FPSO in mid-2011. Total sanctioned the CLOV development in mid-2010 and the Cravo, Lirio, Orquidea and Violeta fields in block 17 offshore Angola – in waters of 3610-4594ft – is expected to begin production in 2014.
Daewoo Shipbuilding & Marine Engineering is fabricating the FPSO hull. The 305m long, 61m wide FPSO will weigh 110,000 tons and have capacity for 160,000b/d of oil and 6.5mmcm/d of gas. DSME is due to deliver the FPSO in May 2013. The FPSO’s topsides modules are being fabricated in Angola.
Bardex is supplying the mooring system. Under the order, Bardex will provide 16 BarLatch Fairlead Stoppers rated to hold the 17,347kN break strength of the 147mm mooring top chain, four moveable chain jacks providing a 3960kN stall capacity, two messenger winches each having 2750kN stall capacity, two 480kW HPUs and an associated package of deck handling equipment, controls and instrumentation.
FES International is supplying 19 diverless bend-stiffener connectors on the CLOV FPSO. Veolia Water Solutions & Technologies subsidiary VWS Westgarth is designing, supplying and delivering an ultrafiltration system and a sulphate removal package system for the vessel. The ultrafiltration unit, which is the pre-treatment step to the SRP, will have a capacity of 391,288b/d of water, and the sulphate removal package will treat 374,230b/d of water.
The development concept calls for 19 subsea production wells and 15 subsea water injection wells, eight manifolds, and one multiphase pump system, which is a first for Total in the subsea world. Additionally, there will be 38km of production flowlines, 57km of water injection lines, 32km of gas export lines, two riser towers for production and water injection, a single hybrid riser for the gas, and an umbilical network of 84 km.
FMC is manufacturing and supplying 36 subsea trees, wellheads and controls, eight manifolds, two workover systems and associated tooling and equipment. Deliveries were to begin earlier this year. Framo is to deliver the multiphase pump system in 2013. Technip will supply 76k of dynamic and static production and water injection umbilicals. The equipment will be manufactured at the Angoflex plant in Lobito, Angola, with delivery expected in 2013. Subsea 7 is expected to begin offshore installation later this year.
GE will supply gas turbines and compressors for the CLOV development.
The V&M plant in Dusseldorf is carrying out the subsea line pipe manufacture for the water injection, oil production and gas export lines. The first offshore installation campaign was planned for 2Q 2012, with the drilling campaign following.
Total discovered Lirio in 1998. Cravo followed in 1999. Total initially expected to tie the fields, which hold 32°-35°API oil in Oligocene reservoirs, back to Girassol, in the same block, but discovered Orquidea in 1999 and Violeta in 2001 and decided a standalone development would be viable. The Orquidea and Violeta fields hold 20°-30°API oil in Miocene reservoirs. CLOV is Total’s fourth development in block 17, following Girassol, Dalia and Pazflor.
Total operates block 17 with 40% interest on behalf of partners Statoil (23.3%), Esso (25%), and BP (16.7%).
Greater Gorgon Area, Australia
In January, Chevron called the Gorgon project a little over one-third complete and on-track for a planned 2014 startup offshore Western Australia. The three-train LNG facility is expected to see maximum daily production of 2.6bcf/d of natural gas and 20,000b/d of condensate.
The Greater Gorgon area, which lies in waters of about 4300ft, is expected to produce about 40tcf. The project is expected to have four decades of economic life once it starts production. The project calls for production of the subsea wells to flow back to onshore facilities at Barrow Island.
Module fabrication for train one has begun.
Chevron has said it expects to drill 20 to 30 wells in the Gorgon area over three decades but warned that the number of wells would depend on gas demand. Two subsea pipelines with a combined length of 240km will carry the gas from the Gorgon and Jansz fields to facilities on Barrow Island.
Subsea 7 won a $440 million subsea contract for the installation and tie-in of heavy lift structures at the Gorgon and Jansz fields. Contract work includes the engineering, spools fabrication, transportation, installation and pre-commissioning of 20 subsea structures and foundations, 15 heavy spools, 48 tie-in spools, 39 electrical and 18 hydraulic flying leads, and five infield umbilicals and two associated distribution units. Offshore operations are scheduled to begin in 2013 with the Sapura 3000 and Subsea 7construction vessels.
Subsea 7 also won an $80 million contract to transport and install subsea umbilicals and structures from Barrow Island to the Gorgon and Jansz fields. The Gorgon and Jansz umbilicals are 59km and 135km in length respectively. Up to 70km of trenching is expected to stabilize and protect the umbilicals.
CB&I won a $2.3 billion contract for mechanical, electrical and instrumentation work. The contract covers the structural, mechanical, piping, electrical, instrumentation and commissioning support for the construction of three LNG trains. It also includes the associated utilities and a domestic gas processing and compression plant. Work is expected to be completed in 2015. CB&I had previously won a contract for the engineering, procurement, fabrication and construction of the project’s two 180,000m3 full containment LNG tanks, four condensate tanks and the associated utilities.
AusGroup subsidiary AGC Industries will manufacture pipe spools for Gorgon. The A$50 million contract covers receiving material, fabrication, storage, coating and testing of 8200 pipe spools of various diameters, weighing 7500t.
Aker is supplying 264km of steel tube umbilicals that will connect the subsea production system to the onshore LNG plant at Barrow Island. Final deliveries were expected in 2Q 2012.
McDermott had a contract to fabricate subsea structures including various eight-slot, six-slot and four-slot manifolds, pipeline termination structures, pipeline end terminations, spools, well jumpers, and subsea pig launchers/receivers. Work is scheduled to be completed late this year.
JFE Steel and Marubeni-Itochu Steel are providing line pipe. GE Oil & Gas is providing subsea equipment and support services, including 20 VetcoGray subsea trees. Aker Solutions is providing the MEG system. Emerson Process Management provided Roxar subsea Wetgas meters.
KBR’s Kellogg JV Group – a consortium of Clough, Hatch and JGC – won the A$2.7 billion EPCM contract for the LNG downstream and logistics portion of Gorgon. The JV will construct the LNG facility and its three 5mpta trains at Barrow Island.
Hyundai Heavy Industries is fabricating and delivering 48 modules for the Barrow Island LNG plant. HHI will deliver the modules this year and next.
Construction of the Gorgon project began in 2H 2009. The field is named after the SS Gorgon, which played a role in the development of the northwest coast of Western Australia in the early 1900s.
Chevron operates the project with about 47%. ExxonMobil and Shell each hold 25%, and gas purchasers Osaka, Tokyo and Chubu hold the remaining stake in the project.
Santos Basin, Brazil
Petrobras expects to begin an extended well test at the pre-salt Iara field in the Santos Basin later this year and follow that up with a pilot in 2014. The field, in about 7300ft of water, is located north of the Lula (ex-Tupi) field within the same block. Petrobras has estimated the field holds estimated recoverables of 3 to 4 billion barrels of 26°-30°API oil and natural gas.
Aker Solutions is supplying 26 subsea trees for Iara.
Petrobras operates block BM-S-11 with 65% interest on behalf of partners BG (25%) and Galp Energia (10%).
WR758, US Gulf of Mexico
In December 2011, Chevron called its Jack/St Malo project in the deepwater Gulf of Mexico about 20% complete. The twofield development, sanctioned in 4Q 2010, is expected to begin producing oil in 2014 from the Lower Tertiary reservoirs. Chevron estimates the Jack and St Malo fields, which are about 25 miles apart from each other in the Walker Ridge area of the Gulf, contain over 500 million boe of recoverables. Chevron is developing the two fields with three subsea centers tied back to a deep draft semi production facility in about 7000ft of water.
The semi will have an initial design capacity of 177,000boe/d and 42.5mmcf/d. The project is expected to have a 30-year production life. Chevron estimates the initial phase of development will run to $7.5 billion.
Nexans will design, manufacture and supply a total of 42km of power umbilicals and terminations for the project. Nexans’ Norwegian facility in Halden will design and manufacture the power umbilical in two separate lengths, together with the associated umbilical termination heads. On completion, the power umbilicals will be delivered to the newly constructed carousel in Mobile, Alabama, in 2013, where they will be held in storage until called-off by Chevron for installation.
Parker Hannifin’s Energy Products Division will provide 311/2 miles of polyester mooring rope, accessories and field support services for the mooring of the Jack/St Malo unit. The semi will be moored in 7042ft water depth. Under the contract, the company will handle design, production and delivery of polyester mooring line as well as offshore field inspection support services during installation.
First Subsea will supply the mooring connectors for the Jack/St Malo semi. Under the contract, First Subsea will provide 16 Ballgrab connectors.
GE Oil & Gas won the contract to supply three customized aeroderivative gas turbine-generator modules to provide electric power the semi. The three LM2500+G4 gas turbine generator modules will each be mounted on a three-point support base plate, designed with marine corrosion-resistant materials to overcome footprint restrictions and withstand pitch, roll and acceleration forces anticipated for a floating production unit operating in deep waters. GE was slated to begin shipments in December 2011.
Wood Group won a 42-month contract covering the planning, managing and field execution of commissioning for the Jack/St Malo semi. DSI, Wood Group PSN’s commissioning services business, will perform the commissioning at a South Texas fabrication yard where the topsides will be fabricated and integrated with the hull, and offshore, during final installation and start-up.
Mustang is conducting detailed design for the semi’s topsides facilities and the integrated control and safety systems, and JP Kenny is performing detailed design for the deepwater oil export pipeline.
Aker Solutions is providing three subsea production control umbilicals.
Aker’s umbilical facility in Mobile, Alabama, will carry out the engineering, project management and production of the 40 miles of electro-hydraulic steel tube production umbilicals.
KBR will provide design and engineering support through fabrication for the semi, including hull, deck box, accommodations, appurtenances, equipment foundations; mooring system design; and anchor suction piles. KBR’s Granherne and GVA will collaborate on the execution of this phase of the project. KBR carried out the conceptual engineering and design, pre-FEED and FEED for the Jack/St Malo project.
McDermott’s Morgan City, Louisiana, facility will fabricate 21 rigid jumpers for the project. Installation is slated to begin in early 2014 using McDermott’s North Ocean 102 and DB 16.
Technip landed the flowlines contract, which includes engineering, fabrication and subsea installation of over 53 miles of 10.75inOD of flowlines, steel catenary risers, pipeline end terminations, manifolds, pump stations and tie-in skids. Technip pipelay vessel Deep Blue is slated to complete installation in 2013.
KBR’s GVA handled the hull FEED. Wood Group Kenny won the FEED and detailed design for the oil export pipeline.
Amberjack Pipeline’s Jack/St Malo deepwater oil export pipeline is a 136-mile 24in pipeline that will originate at the Jack/St Malo semi and connect to Shell’s Boxer A fixed platform at Green Canyon block 19. Saipem will transport and install the pipeline using the Castorone pipelay vessel, beginning in 1Q 2013.
Chevron operates Jack in Walker Ridge blocks 758/759 with 50% interest on behalf of partners Maersk (25%) and Statoil (25%). Chevron operates St Malo in Walker Ridge block 678 with 51% interest on behalf of partners Petrobras (25%), Statoil (21.5%), ExxonMobil (1.25%) and Eni (1.25%).
Gumusut/ KakapBlock J/K, MalaysiaShell/Murphy
The joint Shell/Murphy deepwater project offshore Malaysia – Gumusut and Kakap – looks like it may reach first production in 2013. Sanctioned in 2008, the project developing the block J and block K fields is expected to produce about 135,000b/d from 19 subsea wells to a semisubmersible.
Oil will be exported via a pipeline to a new oil & gas terminal in Kimanis, Sabah. Natural gas will be re-injected into the reservoir for improved oil recovery.
Water depths in block J field reach 3940ft. FMC is providing eight trees are for production wells, one tree as a spare, four trees for water injection wells and two trees for gas injection wells.
Malaysia Marine & Heavy Engineering fabricated the semi hull. Ten riser porches riser porches and five pull tubes are allocated for the initial development in the pair of blocks. Technip engineered the topsides. Shell is leasing the semi from MMHE’s parent company, MISC.
Shell operates block J with 33% on behalf of partners ConocoPhillips (33%), Petronas Carigali (20%), and Murphy Oil (14%). Murphy operates the Kakap field, which straddles blocks J and K.
Block 32, Angola
Total’s block 32 offshore Angola could see production as early as 2016. This development, now in the study phase, could rely on a pair of FPSOs. Block 32 deepwater discoveries include Gindungo, Canela, Cola, Gengibre, Mostarda, Salsa, Caril, Manjericao, Louro, Cominhos, Colorau and Alho.
The Kaombo project would serve the central southeastern portion of the block. The Alho find was drilled in 5270ft water depth.
Total estimates production for the development will reach 200,000b/d and 180mmcf/d.
Block 206/1a, 205/5a & 4b, UK West of Shetland
Offshore installation has been underway at Total’s Laggan-Tormore development northwest of the Shetland Islands. The project is expected to begin production in 2014, ultimately producing about 90,000boe/d. Total estimates reserves of 230 million boe.
The development stretches over blocks 206/1a, 205/5a and 205/4b in 1970ft of water.
Laggan was discovered in 1986 and Tormore in 2007. The partners sanctioned the project in early 2010.
Development plans call for nine wells. Hydrocarbons will flow to the Shetlands through a pair of 143km 18in import flowlines. Processed gas will be exported via the 234km 30in SIRGE system pipeline to the existing Frigg-UK pipeline.
Total estimates the project will run to £2.5 billion, including building a gas transportation and processing facility with a processing capacity of 500mmcf/d and export pipeline of 665mmcf/d.
Allseas’ DP Audacia pipelay vessel has been laying the landfall sections of the dual import pipelines.
Allseas has the contract for design, engineering and installation of the two 18in, 145km import pipelines, including inline tees and flowline end terminations, with associated overtrawlable protection structures, and of the 30in diameter, 234km export line.
Allseas anticipates completing the contract this year.
The flowlines will connect the subsea production facilities to the onshore processing terminal at Sullom Voe.
The two flowlines require protection structures at the Tormore starting point and at the Laggan tie-in location.
Jumbo’s DP2 Fairplayer heavylift vessel installed four subsea protection structures for production flowlines in 1970ft water depth.
Petrofac has been tapped to develop the Shetland Gas Plant at Sullom Voe. Seadrill’s West Phoenix will carry out drilling.
FMC will supply nine subsea trees, eight wellheads, two six-slot manifolds and other subsea equipment for the project.
Heerema is lined up to install the subsea production system.
Corus Tubes supplied the 18in and 30in pipeline. Subsea 7 is installing the MEG system and service line, and is procuring and installing the umbilicals.
A joint venture between Offshore Design Engineering and Paris-based Doris Engineering won a contract to carry out basic engineering.
Total operates the field with an 80% interest. DONG Energy holds the remaining 20%. Kizomba satellites
Block 15, Angola.
ExxonMobil’s Kizomba satellites project offshore Angola is on track for production mid-year. The block 15 project in 4000-4430ft water depth represents the second subsea tieback to the Kizomba A FPSO and the first subsea tieback to FPSO Kizomba B . The satellites project will produce the supermajor’s Mavacola and Clochas fields. The plans call for connecting the two fields using a looped subsea pipeline between Kizomba A and Kizomba B.
GE Oil & Gas is providing the subsea production equipment for the satellites project. AMEC won a contract for follow-on engineering and is responsible for procurement and logistics support services.
Esso operates the block with 40% interest on behalf of partners BP (26.7%), Eni (20%) and Statoil (13.3%). Sonangol is the concessionaire.
Husky Energy sanctioned its $6.5 billion Liwan deepwater gas project in the South China Sea in September 2011. The project represents the first deepwater development in the South China Sea.
The Calgary-based company said it aims for first gas from the Liwan 3-1 field in 4Q 2013 or 1Q 2014. The project, which will initially develop the Liwan 3-1 and Liuhua 34-2 fields and the Liuhua 29-1 field in 2014/2015, will see production levels of 500mmcf/d when all three fields are online, Husky says. The fields lie in about 4300-4900ft water depth.
Development will see eight subsea wells in the Liwan 3-1 field and one subsea well in the Liuhua 34-2 field and six or seven subsea wells in the Liuhua 29-1 field flowing through flowlines from a series of deepwater subsea manifolds to a shallow water central platform.
Cameron is supplying the three production manifolds as well as subsea trees, connectors and controls and the MEG modules.
CNOOC is overseeing the engineering and design for the central platform. The jacket and topsides are expected to be fabricated in Qingdao, with work in progress. The onshore gas processing plant is expected to be constructed in Gaolan. Shallow water pipeline installation is slated for this year.
Under an EPCI contract, Saipem will carry out engineering, procurement, construction and installation of two 22in diameter 79km-long pipelines, umbilicals and the transport and installation of a subsea production system linking the wellheads to a processing platform. Deepwater installation is slated to begin this year or early next.
Husky targets all installation activities to wrap up by mid-2013.
A gas sales agreement for production from the field is in place. Under this, the Liwan 3-1 field will supply the Guangdong province natural gas grid from an onshore gas plant at Gaolan Island, Zhuahai.
Discovered in 2006, delineation drilling was completed in 2009 with three wells. The deepwater drilling rig West Hercules spudded the first appraisal well in 2008. In 2009, West Hercules drilled and tested the third appraisal well in 4760ft of water.
Husky operates block 29/26, which spans 2230km2, with 49% interest on behalf of partner China National Offshore Oil Corporation (CNOOC). Husky is operating the deepwater activities. CNOOC operates the shallow water central platform, 270km of subsea pipeline to shore and the onshore gas processing plant.
Block 14, Angola/ Haute Mer, Congo
Chevron has moved its Lianzi development offshore Congo and Angola into the design phase and expects to make a final investment decision on the project mid-year.
The project, which straddles block 14 offshore Angola and the Haute Mer Permit offshore the Republic of the Congo, had been expected to see project sanction last year.
The operator has not pegged an onstream target date, nor an expected production rate for this project in 2980ft water depth.
Chevron and its partners discovered oil with the Lianzi prospect in 2980ft of water on the same stratigraphic trend as Landana, a block 14 find from 1998, and Tombua, a block 14 discovery in 2001.
Those two fields began production in 2009. The Lianzi field will reportedly feature three subsea production wells and three injection wells in 2700-3500ft of water. The field is in a unitized zone that includes portions of the block 14 license offshore Angola and the Haute Mer Permit offshore the Republic of Congo.
Chevron operates the field with 31% interest.
Block 14, Angola
Chevron expects FID on its Lucapa field by the end of 2013. The field, discovered in 2006, lies in waters of 2625-6560ft near the Congo River Canyon.
Alliance Engineering handled the topsides pre-FEED work for Doris. Doris’ scope covers preliminary engineering of an FPSO and a subsea tieback-based development. Chevron said it is evaluating development scenarios for the Lucapa field. It operates block 14 with 31% on behalf of partners Sonangol (20%), Eni (20%), Total (20%) and Galp (9%).
KC875, US Gulf of Mexico
Anadarko sanctioned a truss spar development for its Lucius project in the Keathley Canyon area of the deepwater Gulf of Mexico in December 2011. The Lucius spar, to be sited in 7100ft of water, will have about 80,000b/d of oil and 450mmcf/d of natural gas capacity. Anadarko estimates Lucius holds over 300 million boe in ‘relatively shallow and highly productive reservoirs’.
ExxonMobil’s nearby Hadrian South discovery will produce that field’s hydrocarbons to Lucius via a subsea tieback.
Technip’s Pori, Finland, facility is constructing the spar, which will be installed in Keathley Canyon block 875. The spar will be 110ft in diameter and 605ft long. The initial topsides payload is expected at 15,000 tons and the hull will weigh 23,000 tons.
Dockwise will transport the spar from Pori to the Gulf of Mexico. Mustang Engineering won the detailed engineering, procurement support and equipment inspection for the Lucius topsides. Detailed engineering is scheduled to be completed in 3Q 2012. Mustang carried out conceptual and front-end engineering design for the project.
Aker Solutions will provide eight steel tube umbilicals. Under the contract, Aker will take care of project management, design, engineering and manufacture of two electro/hydraulic dynamic production umbilicals, two gas lift dynamic umbilicals, three electro/ hydraulic infield umbilicals and one gas lift infield umbilical, including all associated ancillary equipment required for installation and interface with the existing development. Aker’s Mobile, Alabama, facility will engineer and manufacture the umbilicals, with final deliveries set for 3Q 2013.
FMC Technologies will provide subsea systems and life-of-field services for Lucius. FMC’s scope includes five subsea production trees and two manifolds. It will supply the equipment out of Houston with deliveries expected to begin in 4Q 2012. Technip also has a contract from ExxonMobil, operator of the Hadrian South development that is being tied back to the Lucius spar. Under the contract, Technip will provide project management, procurement and installation of two seven-mile long flowlines and associated jumpers, and install a nine mile umbilical. Technip’s Mobile, Alabama, spoolbase will weld the flowlines. Technip’s Deep Blue pipelay vessel will install the subsea equipment in 2013.
An extended well test at Lucius flowed at equipment-constrained rates exceeding 15,000b/d of 29°API oil. The operator says the test ‘provided additional confidence in Anadarko’s previous resource estimates and indicated that Lucius can be developed with a minimal number of wells’. Anadarko plans an active drilling program beginning this year.
The unitized Lucius project combines other blocks in the area, including Keathley Canyon blocks 874, 918 and 919. Anadarko estimates the project – expected to see first production in 2014 – will cost about $2 billion gross. The development plan calls for subsea tiebacks, with six planned Lucius wells.
Anadarko operates Lucius with 35% interest on behalf of Plains E&P (23.3%), ExxonMobil (15%), Apache (11.7%), Petrobras (9.6%) and Eni (5.4%). Under the unitization deal, Hadrian South co-venturers will pay to the Lucius interest owners a production-handling fee and reimburse the Lucius group for any required facility upgrades to process the natural gas from Hadrian South.
Santos Basin, Brazil
Petrobras began an EWT at the northeast area of the block BM-S-11 Lula pre-salt field (formerly known as Tupi) last April. Operator Petrobras has placed recoverables from the field at 6.5 billion boe of 28°API oil. BW Offshore’s FPSO Cidade de São Vicente, in 6955ft of water, has been receiving the EWT production from Lula Nordeste since April 2011.
Petrobras and its partners will use information obtained during the EWT to develop the final design of the second production system to be installed at Lula. The Lula Nordeste Pilot will produce to the FPSOCidade de Paraty beginning in 2013.
The Modec-supplied FPSO Cidade de Angra dos Reis, moored in 7050ft of water, the first permanent system in the field, received first oil from Tupi as the Lula Pilot in October 2010. Petrobras says it expects the Cidade de Angra dos Reis to produce 100,000b/d in 2012. Its production capacity is 100,000b/d of fluids and 5mmcm/d of gas and it can store 1.6 million barrels of oil.
SBM is providing the second permanent system, the FPSO Cidade de Paraty, for the Lula Nordeste Pilot under a 20-year deal. To be moored in 6890ft of water about 18km from the original Tupi find, this FPSO will have the capacity to produce 150,000b/d oil and 5mmcm/d of gas and inject 150,000b/d of water. The FPSO is expected to serve as the field’s second pilot and accept first production in 2013. SBM and QGOG in a consortium with Nippon Yusen Kabushiki Kaisha and Itochu will own and operate the FPSO under a 20-year charter.
Lula has also been producing via an EWT from the Tupi Sul well to the FPSO BW Peace.
Technip provided 90km of risers and flowlines, with deliveries to be complete by year-end 2012. It is slated to provide 24km of 6in gas injection flexible lines for both the Lula Nordeste and the neighboring Sapinhoá (formerly Guará) fields under a lump sum contract. Technip says it will manufacture the pipelines and deliver them in two batches, one this year and the other in 1Q 2013.
Saipem has an EPIC contract to transport, install and pre-commission the two export lines at Sapinhoá and Lula Nordeste. A 22km-long 18in line will connect the Lula Nordeste FPSO to a subsea gathering manifold in the Lula field.
Aker Solutions is providing subsea trees for the field. Subsea 7 awarded Parker Hannifin a contract to supply the steel wire tether system for Sapinhoá and Lula Nordeste submerged buoys. Under the deal, Parker will provide 34 sheathed tethering lines each measuring over 6000ft. Parker Hannifin will engineer and construct the mooring lines at its Tønsberg, Norway, facility.
In all, the partners in blocks BM-S-11 and BM-S-9 indicate they expect to procure 13 FPSOs to develop the Carioca, Sapinhoá, Iara, Iracema and Lula fields.
Petrobras operates block BM-S-11 with 65% interest on behalf of partners BG Group (25%) and Galp Energia (10%).
Lula (Iracema area)
Santos Basin, Brazil
The FPSO BW Cidade de São Vicente saw first oil in early March. The FPSO, connected to the RJS-647 pre-salt well in the Iracema area of the Petrobras operated block BM-S-11, is expected to serve this well for about six months as part of an extended well test.
The FPSO is moored in about 7260ft of water in the Santos Basin. The well is expected to produce at a restricted rate of about 10,000b/d during the EWT. Petrobras will gather technical data on the behavior of the reservoirs and the oil flow in the subsea lines and use the information gathered to support the development of the final production system. That phase is expected to start operations in the area at the end of 2014 with the installation of the FPSO Cidade de Mangaratiba MV24.
Modec is supplying the FPSO Cidade de Mangaratiba MV24 for the southern section of the development. Cosco’s Dalian yard is converting the VLCC Sunrise J into the FPSO with delivery planned 3Q 2014. Modec has a 20-year charter on the FPSO.
In September 2011, Petrobras supplied a letter of intent to Modec for an FPSO to be moored in 7545ft of water. The Schahin Group and Modec are here partnering for the second time. The partners are responsible for the engineering, procurement, construction, mobilization, and operation of the FPSO, including topsides processing equipment as well as hull and marine systems. Sofec will design and provide the spread mooring.
The FPSO Cidade de Mangaratiba MV24 will be capable of processing 150,000b/d of oil and 280mmcf/d of gas and has storage for 1.6 million barrels of total fluids. It will be deployed in block BM-S-11 in the Santos Basin. It will have eight producers and seven injectors connected to it. Oil will be transported by shuttle tankers, with gas being delivered to the mainland through a pipeline to Cabiunas.
Petrobras and its partners declared the field commercial in late 2010 and changed the name of the field from Iracema to Cernambi. Later, Petrobras stopped using the name Cernami and started referring to the project as Lula field, Iracema area.
The Iracema area holds an estimated 1.8 billion boe of recoverable 30ºAPI oil. Petrobras operates block BM-S-11 with 65% interest on behalf of partners BG (25%) and Galp Energia (10%).
Statoil is developing its deepwater Luva field in the Norwegian Sea with a spar, the first on the Norwegian continental shelf.
The company’s development concept for the PL218 field features two subsea templates with four wells on each and one satellite template with one well. The platform will house accommodation quarters for a permanent crew, a storage unit for condensate, and a gas processing facility with a capacity of 23mmcm/d.
Last month, Technip won the lump sum contract for the FEED of the Luva spar, to be moored in 4265ft water depth. The contract covers the design and planning for procurement, construction and transportation of the spar hull and the mooring systems as well as the design of the steel catenary risers. The award builds on study work (including pre-FEED) that has been ongoing since early 2010 to document the suitability of a spar in Norwegian waters.
A 480km, 30-36in pipeline will transport gas from Luva to the onshore processing facility at Nyhamna. The pipeline will also be connected on to the Linnorm field and tied in to the Zidane field. In addition, connection to Åsgard Transport via the Kristin platform will be possible, and there are plans for tying in other fields and discoveries. The concept includes the expansion of the Ormen Lange field’s Nyhamna gas plant with the intention of converting it into a gas terminal.
Statoil estimates total investment cost for the Luva project at NKr34 billion.
The field includes block 6706/12 and 6707/12 and consists of Luva, Snefrid South and Haklang. First production is expected in 2016 with about eight years of production expected. Statoil says its preliminary drilling concept involves drilling seven subsea production wells.
‘This development may represent the start of deepwater production in the Norwegian Sea, and it will enable the tiein of other discoveries in the same area,’ says Ivar Aasheim, SVP for NCS field development at Statoil.
Discovered by BP in 1997, the field (along with Haklang and Snefrid South) holds estimated recoverables of 40-60bcm, and it is lean gas with a low carbon content. Statoil became field operator in 2006. It holds 75% interest in the fields. ExxonMobil has 15% interest and ConocoPhillips has 10%.
Marlim Sul P-56
Campos Basin, Brazil
Petrobras’ Marlim Sul P-56 semi platform began production in mid-August 2011. In February, the P-56 surpassed the 124,000b/d mark, a month after exceeding its designed nominal capacity of 100,000b/d. This makes it the largest oil-producing concession in Brazil, according to Petrobras.
The Campos Basin field has a total of 10 producer wells and 11 water injectors connecting to the semi. The semi, installed in 5480ft of water, can process 100,000b/d of oil and 6mmcm/d of gas. It sends produced oil to the P-38 FSO about 20km away. While the oil in the Marlim Sul field ranges from 13°-25°API, Module 3 targets oil that is 16°API. BrasFels built the semi. FMC supplied 17 vertical subsea trees and three horizontal subsea trees.
Petrobras discovered the field in 1987 and brought Module 1 onstream in 2001. Module 2 began production in January 2009. A few years ago, the Brazilian operator also found oil in carbonate layers, and that oil began producing in 2010.
Petrobras has not yet sanctioned a fourth module. If it does, it is thought that it will target production of 13-14°API oil.
MC807, US Gulf of Mexico
Shell aims to begin production from the Mars B project at the Olympus TLP in 2015 at a rate of 100,000boe/d. The Mars B expansion is intended to enhance recovery from the Mars field in 2952ft of water, as well as provide process infrastructure for the recent West Boreas and South Deimos discoveries. Shell sanctioned the Mars B project in September 2010.
The Olympus TLP facility will be installed in in Mississippi Canyon block 807 in nearly 3000ft of water in the Gulf of Mexico. In all the TLP will accept production from eight blocks in the area: MC762, 763, 764, 805, 806, 807, 850 and 851. The TLP is being designed to accommodate future tiebacks. The Olympus TLP is intended to have a processing capability of 100,000b/d and over 100mmcf/d of gas. It will be located about 4km away from the original Mars TLP (which began production in 1996) and will export production to a platform at West Delta block 143C.
Samsung Heavy Industries will fabricate the hull in Korea, and Kiewit has the contract to construct the topsides at its Ingleside, Texas, yard. It will be the first four-column TLP to be built under new storm criteria implemented after hurricanes Rita and Katrina in 2005.
McDermott will fabricate the deck, jacket, piles and bridge for West Delta 143C. McDermott’s New Orleans group will handle detailed construction engineering and load-out analysis for the 10,120 tons of structures. McDermott’s Morgan City, Louisiana, fabrication facility will perform all construction engineering, procurement, fabrication and onshore mechanical completion of the deck. McDermott will also assist in commissioning the platform. The deck is expected to sailaway in 1Q 2013.
Duco will handle engineering, project management and construction of 20,000ft of umbilicals for West Boreas. Duco’s Houston facility will manufacture the umbilicals, delivery slated for this year.
For West Boreas, in water depths to 3150ft, Subsea 7 will install the umbilical and subsea distribution hardware.
Subsea 7’s Houston office will handle project management and engineering. Skandi Neptune will carry out the installations.
Aegion subsidiary The Bayou Companies will coat 80 miles of 16in and 18in diameter oil and gas pipelines for the Mars B project. The coating as well as concrete weight coating and anode and buckle arrestor installation for the project was slated to begin in January.
FMC Technologies has a contract for six subsea trees rated to 15,000psi, with deliveries scheduled to begin in the 3Q.
Dril-Quip is supplying drilling and production equipment for the TLP under a $27 million contract. The contract covers the provision of subsea wellhead equipment, production riser tieback connectors and drilling riser components for the Olympus TLP.
Delmar delivered mooring services and preset mooring systems for development drilling.
Shell operates the Mars B project with 71.5% interest. BP holds the remaining 28.5%.
Santos Basin, Brazil
Petrobras brought Mexilhão onstream in April 2011, producing to the Mexilhão platform in the Santos Basin offshore Brazil. The field is capable of producing up to 15mmcm/d.
Discovered in 2003, Petrobras is developing the field in waters of 1050-1800ft with seven subsea production wells. The Maua Jurong shipyard in Niteroi near Rio de Janeiro built the fixed platform, which was installed in shallow water.
Gas produced in Mexilhão is offloaded via a 34in gas pipeline to the Monteiro Lobato Gas Treatment Unit in Caraguatatuba, on the northern coast of São Paulo state. Global Industries used the DLB Iroquois to lay 22km of the 34in pipeline in the Mexilhão field. FMC supplied six trees to be located in 1640-1970ft of water and two manifolds, among other subsea equipment. Nexans supplied two 22km umbilicals and seven umbilicals totaling 15km.
Offshore Area 1, Mozambique
Anadarko has been picking up steam with its exploration program in the deepwaters offshore Mozambique. The US-based operator has since transitioned its series of gas discoveries – Windjammer, Camarao, Barquentine and Lagosta – into the development phase of an LNG project.
The company expects to sanction its Mozambique LNG project in late 2013 with an aim of reaching first production in 2018. The two-train LNG project would tap an estimated recoverable resource base of 15-30tcf, and Anadarko has identified 15 additional exploration prospects on its block.
Earlier this year, Anadarko said its Lagosta-2 appraisal well – its seventh discovery offshore Mozambique – had encountered 777ft of net pay. Bob Daniels, Anadarko’s SVP for worldwide exploration says the information from the Lagosta-2 appraisal will be ‘incorporated into our models to help determine the optimal subsea development plans for the complex’.
Anadarko’s activities are expected to see an uptick as there are now two drillships – the Belford Dolphinand the Deepwater Millennium – on Anadarko’s offshore area 1 of the Rovuma Basin. The Belford Dolphin drilled the Lagosta-2 well in 4813ft of water.
Anadarko operates offshore area 1 with 36.5% interest on behalf of partners Mitsui E&P (20%), BPRL Ventures (10%), Videocon (10%) and Cove Energy (8.5%). Empresa Nacional de Hidrocarbonetos’ 15% interest is carried through the exploration phase.
Campos Basin, Brazil
Petrobras’ Papa Terra field remains on track for first oil in 2H 2013. The field, located in 4000ft of water in the Campos Basin, is to produce 14°-17°API oil with the P-61 tension leg wellhead platform and P-63 FPSO. Petrobras sanctioned the $5.2 billion project in early 2010.
The P-61 TLWP will serve 11 risers. It will be the first TLWP connected to an FPSO offshore Brazil (OE April 2010). The floating dry tree unit designed by FloaTEC will have little processing capacity. A multiphase pump will send production to the P-63 FPSO 350m away. A tender-assist unit will handle development drilling.
Dril-Quip is supplying the drilling and production equipment for the P-61. Late this year, Dril-Quip will begin providing surface production tree systems, production riser systems and a drilling riser system to the project. Dril-Quip also won the contract to supply subsea wellhead systems for the project, with deliveries continuing through 1Q 2013.
The BrasFels yard in Angra dos Reis, Brazil, is constructing the P-61. J Ray McDermott is fabricating the tendons, temporary buoyancy modules and piles at its Morgan City, Louisiana, facility. The FloaTEC Singapore joint venture is supplying risers, well systems and tendon components, and J Ray is installing the facility in the field using DB 50. J Ray will also provide topsides engineering and procurement services.
BW Offshore is converting the ULCC BW Nisa into the P-63 in China. Amec is handling basic engineering for the topsides. The FPSO will have about 16 topsides modules and weigh over 14,000t. The topsides facilities will include three oil processing modules, one gas compression module, three electrical power generation modules, two water treating and injection modules, one electrical building module, three utilities modules, one flare system module and two manifold modules. In addition, a pipe rack over 650ft long will incorporate a material handling trolley.
The FPSO will be designed to process 140,000b/d of crude oil, 35 mmcf/d of gas and 325,000b/d of produced water. Facilities to inject approximately 340,000b/d of seawater are also included.
BW and QGOG will operate the FPSO for three years, gradually handing it over to Petrobras; FloaTEC will operate the TLWP under a similar set-up.
ABB is supplying the power supply infrastructure, systems and equipment for the P-63.
InterMoor won the contract to install the drilling and production conductors for the Papa Terra project. There are 15 conductors, 36in in diameter, that were to be installed in 3936ft of water beginning late last year using DOF Subsea’s Skandi Skolten. InterMoor fabricated the conductors at its Morgan City, Louisiana, yard.
Petrobras discovered Papa Terra in 2005 and estimates the field holds 700 million to 1 billion boe. Papa Terra is expected to produce 140,000b/d when it goes onstream next year.
Petrobras operates with 62.5% on behalf of partner Chevron.
Block 17, Angola
Total saw early first oil at its Pazflor field offshore Angola. The FPSO development in water depths of 1970-3940ft began production in August 2011. Total expected the block 17 field to ramp up to full production of 220,000b/d over the next few months. It went online several weeks early and within budget. Total has estimated 2P reserves of 590 million barrels at the field. The project saw investment of about $9 billion.
Pazflor’s vast subsea gathering network includes 180km of lines tying in 49 subsea wells, 10,000t of subsea equipment and the Pazflor FPSO. Sixteen subsea mooring connectors hold the 325m long, 62m wide, 120,000t FPSO in position in 2500ft water depth. The FPSO can store up to 1.9 million barrels of oil, which is exported to tankers via an offloading buoy. Associated gas is reinjected into the reservoir, but could also be exported to the Angola LNG plant once the latter becomes operational, Total says.
About two-thirds of Pazflor’s reserves are heavy, viscous oil from three Miocene reservoirs named Perpetua, Zinia and Hortensia, while the fourth – named Acacia – is light oil from the Oligocene. The oil ranges from 17°-22°API in the Miocene and 35°-38°API in the Oligocene.
The subsea production system for Pazflor’s three Miocene reservoirs includes three subsea separation units. Each one consists of four retrievable packages: a gas-liquid separator, two hybrid pumps to boost the liquids, and a manifold to distribute the effluents to the separator and pumps. Hybrid pumps designed for Pazflor combine multiphase stages, compatible with the presence of gas in the liquid, and a centrifugal stage, to improve efficiency.
Shortly after the project began production, the first subsea separation unit was successfully commissioned.
Total discovered Perpetua in 2000, and in 2002 and 2003 discovered Hortensia, Zinia and Acacia. In December 2007, Total approved the Pazflor project. In March 2009, development drilling began. Subsea installation began in summer 2010. The FPSO left the DSME yard in South Korea in January 2011 and arrived at its installation site offshore Angola in May.
The Pazflor oil field was discovered in 2003. It lies in the same block as Total’s CLOV development (Cravo, Lirio, Orquidea and Violeta), due onstream in 2014.
Total operates block 17 with 40% interest on behalf of partners Statoil (23.3%), Esso (20%),and BP (16.7%). Sonangol is the block concessionaire.
Woodside expects to begin LNG production from Pluto this month. The project, offshore Western Australia, was sanctioned in 2007. It is to produce gas from the deepwater Pluto and Xena gas fields, which hold an estimated 4.8tcf of dry gas and 250bcf of contingent resources. The fields lie in 3280-13,120ft of water.
The initial phase sees gas flowing to a shallow-water platform. Initially, the platform, in 280ft water depth, will see production from five subsea wells at Pluto. A 180km trunkline will send gas to the onshore facility on the Burrup Peninsula with a production capacity of 4.3mtpa.
The first Pluto discovery came in 2005, and Woodside made its final investment decision on the $11.2 billion project in 2007.
Woodside operates the project with 90% interest with Kansai Electric and Tokyo Gas each holding 5%.
GC468, US Gulf of Mexico
Hess, which had aimed to sanction its Pony project last year, has pushed the decision back to sometime this year. Hess is in talks with Nexen – operator of the Knotty Head field in the block due south of Pony – to jointly develop the two subsalt fields. A letter of intent has been signed, and the pair put a data transfer agreement in place.
Although Hess expects to sanction Pony this year, Nexen has indicated it does not expect to sanction the Knotty Head development in 2012 as the company is still working out commercial and operational details.
Given these developments, the deepwater Gulf of Mexico project remains in the engineering and design phase. The delay has also bumped back expected first oil from the subsalt field from 2013 to 2015. Subsea infrastructure is under development, Hess says.
Hess says the Pony field, in Green Canyon block 468, holds about 200 million boe of net resource. Hess found oil at the field, in about 3500ft of water, in 2005.
Hess operates Pony with 100% interest.
Kevin Reinhart, Nexen’s interim president & CEO, says the company is working with its partners in Knotty Head to ‘plot what’s the best path forward here for the development of our Knotty Head field and whether that includes the block to the north of us or not, is part of that deliberation. So while we’re a little bit frustrated with the time that it’s taking to progress this, I think the caution and the pace that we’re going at will pay off rather than trying to rush this one through and getting the development scenario wrong or perhaps getting the equity split with another partner wrong. Getting that wrong can cost us a lot of value as well.’
Nexen operates Knotty Head in Green Canyon block 512 with 25% interest on behalf of partners BHP, Chevron and Statoil, each with 25%.
Block 31, Angola
Modifications to the detailed field development plan and topsides have combined to push first oil at BP’s PSVM development offshore Angola back from 2011 to later this year. The project, which features an FPSO serving the Plutão, Saturno, Vênus and Marte fields, is expected to begin production in 2Q 2012.
Located in the northeast portion of block 31, PSVM is expected to reach plateau production of 150,000b/d. A converted FPSO, which was undergoing commissioning in late February, will serve 40 production, injection and infill wells. There are 170km of flowlines, 94km of control umbilicals and 15 manifolds and associated subsea kit. BP says PSVM, located in about 6560ft of water, is the largest subsea installation it has completed.
In February, Modec said it was installing the FPSO. Sembcorp converted VLCC Bourgogne into the FPSOPSVM, which has been designed to remain in the field for up to two decades without drydocking. FPSO PSVM has one of the biggest external turrets ever constructed in the oil industry, and the topside modules weigh over 20,000t. The FPSO has processing capacity of 157,000b/d of oil and 245mmcf/d of gas and can store 1.8 million barrels of oil.
Heerema Marine Contractors’ Balder installed 51km of pipe-in-pipe production flowlines, 40km of service flowlines, 17km of vertical risers, 77 structures (FSAs, FTAs, ITAs, BMs, LRAs, BTs and URAs), and nine piles driven at 6660ft water depth over a period of about 15 months.
PSVM is the first of up to three additional developments BP is considering in the prolific block 31, where the operator has announced 19 discoveries, five of them being subsalt. Later development plans include the possibility of creating additional hubs to produce fields in other areas of the block, and BP appears to be well on its way with its block 31 SE project as the company determines the impact of recent discoveries on the early clusters.
Block 31 covers 5349km2 and lies in 4920-8200ft of water.
BP operates block 31 with 26.7% interest. Partners are Esso E&P (25%), Sonangol (20%), Statoil (13.3%), Marathon (10%) and Total (5%).
BP’s block 31 SE development would aim to develop oil from several fields, yet to finalized. Under the current scenario, these fields would likely be subsea developments tied back to a new FPSO.
Block H, Malaysia
Murphy looks like it’s pursuing a floating LNG solution for the Rotan area offshore Malaysia. According to a presentation made earlier this year, the US-based operator aims for first production in 2015.
The company expects to drill two wells in the block H area this year. According to Murphy, phase one gas sales could be around 600bcf and produce at a rate of 180mmcf/d for seven to nine years.
Murphy says the deepwater block H, offshore Sabah, could support the FLNG option. Discoveries in the area include Rotan in 2007, Biris in 2008, and Dolphin in 2010.
Murphy says it ‘is optimistic’ that a FLNG development could be a solution for these discoveries in about 1700ft water depth.
Campos Basin, Brazil
Petrobras’ third module at the Roncador field in the Campos Basin is slated to begin production in 3Q 2013 with the fourth module beginning production in 1Q 2014. The first two modules are already onstream.
Located in 4920-6230ft of water, the field is expected to reach peak production of 543,000b/d in 2014. The P-55 semi, to be moored in 5870ft of water, and P-62 FPSO, to be moored in 5250ft of water, will serve a number of subsea wells. The semi will have a capacity of 180,000b/d of 22°API oil and 6mmcm/d of gas. Petrobras plans to connect 18 wells to the platform, with 11 being producers and the others as injectors.
The P-62 is a clone of the P-54 FPSO, which is already producing in the Roncador field. P-62 will be able to process over 180,000b/d of 18°API oil, inject over 250,000b/d of water, produce 6mmcm/d of gas and store 1.6 million barrels of oil. It is designed to remain at the field for up to 25 years without drydocking. The FPSO will connect to 12 producers and five injectors.
ABB is supplying the power supply infrastructure, systems and equipment for the P-62. Under the deal, ABB will provide a containerized electrical house that includes a 544t electrical room to house the 100MW power system, as well as related power generation and energy distribution equipment, and engineering and installation services. ABB’s delivery also includes energy management systems and power supply protection equipment.
Aker Solutions is supplying the Pusnes offloading systems for the P-62. The spread-moored FPSO will use offloading system at both bow and aft ends. The offloading system includes tanker mooring and crude oil transfer components as well as emergency offloading stations. Crude oil from the FPSO will be loaded on to dedicated DP shuttle tankers. Aker also won a Petrobras contract to provide the Pusnes mooring system for the FPSO.
FMC is supplying five vertical subsea trees, three horizontal subsea trees, a handful of other trees, an early production riser and a number of other subsea pieces of kit. Aker Solutions has a contract to service subsea control systems for several Petrobras fields, including Roncador.
Once all four modules are complete, there will be 53 producing wells and 29 injector wells on the Roncador field.
SBM says it expects to own and operate the unit with a share of somewhere between 49.5% and 62.25% as part of a consortium.
The original field is expected to see an FPSO for that pilot production project to be delivered later this year. Modec, Mitsui and Mitsubishi are working on that FPSO, a conversion from the VLCC Radiant Jewelthat will be renamed FPSO Cidade de Sao Paulo MV23. Production to this FPSO is anticipated at 120,000b/d and 4mmcm/d in 2013. In February Modec said that topside integration was ongoing at BrasFels.
Technip is slated to provide 24km of 6in gas injection flexible lines for both Sapinhoá and the neighboring Lula Nordeste fields under a lump sum contract. Technip says it will manufacture the pipelines and deliver them in two batches, with one batch delivered this year and the other in 1Q 2013.
Saipem has an EPIC contract to transport, install and pre-commission the two export sealines at the Sapinhoá and Lula Nordeste fields. A 54km long, 18in line will connect the FPSO to a subsea gathering manifold in the Lula field. Subsea 7 awarded Parker Hannifin a contract to supply the steel wire tether system for Sapinhoá and Lula Nordeste submerged buoys. Under the deal, Parker will provide 34 sheathed tethering lines each measuring over 6000ft. Parker Hannifin will engineer and construct the mooring lines its Tønsberg, Norway, facility.
Aker Solutions is providing 14 subsea trees for the field. Under the contract, Aker will engineer and manufacture the vertical subsea trees destined work in 8200ft water depth plus subsea control systems and tool sets. Aker is slated to deliver the kit over the next four years, with the first tree scheduled for delivery by end 2011.
Petrobras and its partners were to submit a development plan to the ANP in 1Q 2012.
The EWT began in late 2010, producing to the FDSPO Dynamic Producer.
Petrobras operates block BM-S-9 with 45% interest on behalf of partners BG Group (30%) and Repsol Sinopec (25%).
Matan block, Israel
Noble Energy’s Tamar development offshore Israel is expected to reach first gas in 2013. Sanctioned in 2010, plans for the fast-track project in the Matan block see five subsea wells producing 200-250mmcf/d of gas. Gas from the wells, in 5495ft water depth, will flow via a pair of 16in flowlines to a new platform near the existing Yam Tethys platform in the Mediterranean Sea.
Noble Energy’s $3 billion development lies in the Levantine Basin. The platform will be installed in 800ft of water and be able to process 1.2bcf/d of gas. Noble Energy intends to produce the gas with subsea wells connected to the platform via 150km of flowlines. The planned single-lift topsides facility will have four deck levels and will weigh nearly 10,000 tons when completed.
Last year, Noble Energy and its partners in the Tamar and Dalit fields offshore Israel opted to evaluate floating LNG for exporting natural gas from the two deepwater fields. Under the November 2011 heads of agreement with DSME and D&H Solutions, the parties will carry out preliminary engineering design work to define the technical parameters required for the detailed design. If the project progresses further, FEED negotiations would follow. The following month, DSME awarded Höegh LNG the FEED contract. Under the deal, Höegh LNG and partners would own and operate the LNG FPSO; DSME would be the EPCIC contractor.
Wood Group’s Alliance Engineering has the contract for detailed engineering and design services for the Tamar project. The contract, announced in May 2011, includes the topsides facilities and deck structure. Expro will provide specialist well testing and subsea services and equipment, including a high flow rate well testing package and large bore subsea safety systems, under a $27 million contract.
Delmar Systems has the contract to install five subsea trees using its Heave Compensated Landing System and Transocean’s Sedco Express. Project commissioning is expected this year.
EMAS AMC’s Aker Marine Contractors won the contract to install about 200 miles of umbilicals and subsea hardware and associated equipment. The contract also covers delivery of subsea suction piles and subsea jumpers. EMAS estimated it would begin installation in 2Q 2012. Aker Solutions won the contract to supply 105km of steel tube subsea umbilicals. Alliance Engineering got the contract for detailed design of topsides.
MC725, US Gulf of Mexico
Hess sanctioned its Tubular Bells deepwater oil & gas development in the Gulf of Mexico in October 2011. The initial development plan calls for three subsea production wells and two water injection wells from two subsea drill centers tied back to a spar. Drilling is scheduled to begin this year with initial production slated for 2014.
Hess expects annual gross production to peak at 40,000boe/d to 45,000boe/d. Total estimated recoverable resources for the field are estimated at over 120 million boe. The development is estimated to cost $2.3 billion, with additional commitments for production handling, export pipeline, and oil and gas gathering and processing services.
Williams Partners will provide the Gulfstar FPS for Tubular Bells. Williams said it expects Gulfstar to serve as a central host facility for other deepwater prospects in the area. The spar-based floating production system uses a traditional three-level topsides mated to a classic spar hull. According to Williams, this design approach will allow customers to reduce cycle time from discovery to first oil.
Williams issued a letter of award to Gulf Island Fabrication to construct the hull in Corpus Christi, Texas. Williams Partners expects to select and award the topsides portion of the Gulfstar FPS to a Gulf Coast fabricator, making this the first spar-based floating production system to be built entirely in the US Gulf Coast area.
Wood Group’s Alliance Engineering will carry out the detailed engineering and design of the topside facilities and deck for the spar. The wet-tree platform will be installed in 4300ft of water.
The topsides will have three deck levels and include processing equipment, seawater injection equipment, utilities, an accommodation building with helideck, and pumping and compression equipment to export the treated oil and gas through departing pipelines. The completed deck will weigh approximately 7000 tons. Initial production is scheduled to start in 2014.
Under a lump-sum contract, Technip will design, engineer, fabricate and install over 28 miles of flowlines, steel catenary risers, pipeline end terminations, piles and structures. Technip’s Houston facility will manage the project. The Mobile, Alabama, spoolbase will weld the flowlines and risers. Technip’s Deep Blue pipelay vessel will handle offshore installation in 1H 2013.
InterMoor has the contract to design and fabricate the suction piles for Tubular Bells spar. Under the contract, InterMoor will design and fabricate at its Morgan City, Louisiana, facility the ten suction piles, each 16ft in diameter and 97ft long, that are to be used as anchors for the project. The piles will be pre-set in 4300ft of water to anchor the spar in Mississippi Canyon block 768.
The Gulfstar FPS will be able to process 60,000b/d of oil and 200mmcf/d of gas. Hess discovered the field in 2003 in waters of 4300-4600ft. It operates Tubular Bells with 57% interest on behalf of partner Chevron. BP is no longer a partner in this field.
The Total-operated Usan field offshore Nigeria began production in late February. The FPSO has a storage capacity of 2 million barrels and can handle 180,000b/d of oil; gas is being reinjected. The 320m long, 61m wide FPSO will ultimately be connected to wells in a 70km-long subsea network. In all, 42 wells – 23 producers, 10 gas injectors and nine water injectors – are serving the field’s highly compartmentalized and heavily faulted reservoirs lying in 2460ft water depth.
The Usan project has relied on an unprecedented level of Nigerian local content, with over 500,000 engineering man-hours and 14 million construction and installation man-hours performed in Nigeria. FPSO construction included an offshore integration of 3500 tons of locally fabricated structures. In addition, large-scale training and capacity building programs were put in place, raising the skills of the local workforce to the benefit of future projects.
Sea Trucks’ Jascon 30 was used during hook-up, commissioning and start-up of the FPSO Usan as a custom portable accommodation block for the Usan project.
Hyundai Heavy Industries fabricated the $1.7 billion FPSO which can accommodate 130 personnel during normal operations and up to 180 at maximum capacity.
Designed with future expansion in mind – the field is expected to produce for a quarter century – the FPSO can accommodate seven single hybrid risers that handle both production and injection. It serves 35km of 10in insulated production flowlines in 2 loops, 20km of 10in water injection flowlines, 10km of 8in gas injection flowline and 70km of control umbilicals. Nigerdock handled part of the FPSO’s topsides.
The Usan is the first FPSO in Nigeria to use the wash-tank process to simplify the dehydration, desalting and stabilization of the oil, says Total.
Bardex designed, manufactured and supplied the mooring system for the FPSO. Aker supplied the offloading system; Saipem installed the subsea umbilicals, flowlines and risers; and Nexans manufactured the umbilicals.
Cameron provided subsea wellheads and vertical trees, manifolds, support structures and foundations, and well jumpers, as well as all installation tooling and intervention equipment and systems engineering.
Total operates the field with 20% interest on behalf of partners Chevron (30%), Esso (30%) and Nexen (20%).
Block 15/06, Angola
Eni expects West Hub, one of its block 15/06 developments offshore Angola, to begin production next year. The project, in 4590ft of water, will use SBM Offshore’s FPSO Xikomba, which was under contract with ExxonMobil offshore Angola from 2003 through 2011. To prepare for installation at West Hub, the FPSO went to the Paenal yard in Angola for an upgrade.
The FPSO is expected to serve the Ngoma, Sangos and Cabaca Norte discoveries under a 12-year lease and operate agreement.
Eni operates the block with 35% working interest on behalf of Sonangol E&P as the concessionaire and partners Sonangol Pesquisa e Produção (15%), SSI Fifteen (20%), Total (15%), Falcon Oil Holding Angola (5%), Petrobras International Braspetro (5%) and Statoil Angola Block 15/06 (5%).
Santos Basin, Brazil
In December 2011, Petrobras and its partners in the Guará field declared the project commercial and changed the field’s name to Sapinhoá, which is a type of marine mollusk. The partners in the pre-salt field have estimated recoverables of 2.1 billion boe.
As of the end of 2011, four wells had been drilled, including one to obtain data on the reservoir. Four formation tests were conducted in three of the wells, and a five-month extended well test (EWT) confirmed ‘its excellent output potential’.
The flow was maintained throughout the entire test period and the test produced relevant information on the carbonate reservoirs for optimizing the development plan, according to Petrobras. The field holds 30°API oil.
In mid-2011, before the declaration of commerciality, the partners in the block provided SBM Offshore with a letter of intent for an FPSO for use in developing Sapinhoá Norte. Expected to begin production in 7550ft water depth in 2014, the FPSO will have processing capabilities of 150,000b/d of oil, 6mmcm/d of gas treatment and water injection of 180,000b/d. To be named Cidade de Ilha Bela, it will be moored in the northern area of the field. Under the initial schedule, SBM was to deliver the FPSO in 35 months.
MC503/547, US Gulf of Mexico
In late 2011, LLOG’s Who Dat field started producing oil in Mississippi Canyon block 503/504/547 in 3000ft of water. LLOG discovered the Who Dat field in December 2007 and followed up with two wells in 2010 to test additional targets. The Opti-Ex semi, which Exmar built on spec (OE October 2009) and sold in June 2010 to LLOG, has a production capacity of 60,000b/d of oil, 150mmcf/d of gas and 40,000b/d of water. The subsea system is capable of handling up to a dozen wells. Three subsea manifolds connect to the semi via flexible risers.
The semi was installed in MC547. Samsung built the hull in Korea and Kiewit built the deck in Ingleside, Texas. The mating was performed at Kiewit in May 2009, where it had remained until LLOG purchased it.
FMC Technologies won the contract to design, manufacture and supply the subsea production systems for the project in a deal valued at $40 million to FMC. FMC’s scope includes seven subsea production trees and control systems. FMC’s Houston operation is supplying the equipment, set to begin deliveries this year.
Delmar installed the preset mooring systems and facility connection operations last summer. Louisiana-based Delmar preset all 12 suction anchor mooring systems using a single conventional AHV. Delmar provided project engineering for anchor/mooring system design, fabrication oversight, installation engineering, operation procedures, and installation services for the installation. Delmar also assisted LLOG and the facility designer/builder Exmar in certification verification authority review and regulatory approval for the mooring system. Once the Who Dat semi arrived on location, Delmar connected the facility to the preset mooring systems using two conventional AHVs and supported by a field ROV support vessel.
Enterprise Products’ has the contract to transport Who Dat production via the Independence Trail. Pinnacle Engineering, Exmar Offshore, 2H Engineering and Stress Engineering had engineering contracts for the project. Global Industries installed the pipelines, risers and other subsea equipment. Wellstream provided the flexible risers. Wilson provided the linepipe. Duco provided the control umbilicals. Oil States Industries provided some of the subsea pipeline connectors. Cameron provided subsea valves. Wood Group Production Services has the contract for O&M and management.
West Nile Delta
West Mediterranean Deepwater, Egypt
BP expects to begin production on its $13 billion West Nile Delta project offshore Egypt in 2015. The $13 billion includes about $9 billion in phase one. The development, in the West Mediterranean Deep and North Alexandria concessions, is expected to produce up to 1bcf/d and serve five core offshore fields. Included in that number are the Raven and Giza discoveries in 2130-2200ft of water. The other three fields are Fayoum, Taurus and Libra. Estimated plateau is expected at 900mmcf/d.
BP signed an agreement in 2010 with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation to develop the resources in the pair of concessions. The first development phase targets an estimated 5tcf of gas and condensate via a subsea development feeding a new gas plant onshore Egypt.
Development drilling is expected to begin 1H 2013. BP expects a tender for the development rig to go out later this year and has indicated it expects to drill about 18 development wells.
BP’s development will use subsea wells and associated gathering systems flowing to an onshore reception and processing terminal for treatment. Sales gas shall be exported into the Egyptian National Transmission Systems (NTS). The condensate separated from the gas will be exported via an existing third party pipeline to Tanta, before being transferred to refineries.
BP operates the North Alexandria concession with 60% on behalf of partner RWE Dea. BP operates the West Mediterranean Deepwater concession with 80% on behalf of partner RWE Dea. OE
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