‘Innovation Now’ was the over arching theme of the 11th GE Oil & Gas annual meeting held in Florence early February.Meg Chesshyre was among the 930 industry attendees from 69 countries.
GE Oil & Gas’ Drilling & Production division confirmed the first order for its new VetcoGray SVXT S-series subsea tree at the Florence meeting. GE is supplying Shell UK with the new SVXT tree. Alongside earlier FEED work undertaken on behalf of Shell UK and NAM, this order was awarded under GE’s existing regional frame agreement with Shell. The SVXT will be delivered to Shell 4Q 2010 and installed 1Q 2011. It is estimated that Shell may require six to 12 trees under the frame agreement.
Jan Duinhoven, SWEEP project manager for Shell NAM, said: ‘Reliable, more compact and cost effective solutions are required in the mature Southern North Sea, to be able to profitably develop the remaining gas accumulations.’
The SVXT merges horizontal and vertical tree technology and is intended for harsh, shallow water fields, predominantly in the North Sea but also for global export. The streamlined SVXT design reduces tree weight by over 20%, significantly decreases height and delivers essential functionality in a preengineered, pre-configured ‘modular’ approach. Low-cost installation of the new SVXT is achieved through a design that enables deployment using standard offshore jack-up drilling rigs. Additional SVXT design features include smaller tree and fisher-friendly wellhead protection structures, as well as an innovative barrier approach that removes the need for a separate tree cap.
Manuel Terranova, global regional leader, GE Oil & Gas explained: ‘The tree has been designed in a way that allows us to expand into other markets. In particular we are bidding the product in Asia Pacific. If we need to fabricate locally in places like Singapore, we can, and that will make it more cost effective to compete in those markets.’
GE intends to launch its deepwater horizontal tree (DHXT) at OTC this year. The DHXT has been engineered for up to 15,000psi and 10,000ft, and has been optimised to minimise weight and can fit through a 5.5m moonpool. It will have three primary configurations – standard, enhanced and gas lift.
Another possible launch is the twin-screw multiphase subsea pump, used for enhancing and increasing oil production, which is in test at the moment. Terranova said it has already generated considerable interest and he expects to be in a position to bid the pump starting at OTC for delivery in late 2011.
GE has a launch customer, Pride, for a drilling innovation, the Spider automated riser hook-up system, which makes hookup simpler and safer and can potentially lead to cost savings of 40% in time or, with rig rates at $500,000 a day, $1 million per well.
GE also announced at the Florence meeting the successful conclusion of a VetcoGray technology retrofit to existing subsea trees in Chevron subsidiary, Cabinda Gulf’s Lobito Tomboco field. The deepwater scale squeeze operation was conducted through the choke body, a very economic intervention method, said Terranova, adding that ‘scale squeeze and other intervention techniques are a great way to extend the production of an asset for a small amount of incremental operating expenditure’.
New GE equipment supplied for the project included scale-squeeze inserts for short- and long-term operations, a fluid cap, a choke insert with full functionality with an additional port for chemical injection and a chemical line with landing skid. The use of a VetcoGray choke interface, a port in the subsea tree, allows choke inserts (the pressure/flow controlling element) to be removed and replaced as required during the life of the field.
The project marks the first time that a retrofit technology has been used in deepwater scale-squeeze. This type of system has now been extended for deepwater scale squeeze operations up to 1850ft with further plans to extend the technology to 3500ft in similar projects for the region.
Operational updates
A number of operators offered operational updates at the Florence meeting. It was important that key suppliers were brought in early for megaprojects such as Australia’s Gorgon, Michael Illane, president and general manager of Chevron Project Resources, told attendees. GE Oil & Gas was one of the Gorgon gas project’s largest suppliers with $2.2 billion in orders associated with the project, including $900 million for rotating equipment, $800 million for subsea equipment and control systems, and $500 million for aftermarket services.
Operated by Chevron (47.75%) in joint venture with ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%) and Tokyo Gas (1%), Gorgon is the largest all-subsea LNG development ever, in the deepest water depth and with the second longest tieback to date (OE April 2006).
‘For megaprojects you need an exaggerated emphasis on project execution planning,’ said Illane, and that involves the engagement of key suppliers early on. VetcoGray was selected early during the FEED phase, and participated in the FEED validation work. Chevron adopted a similar approach to a number of licence providers for the LNG plant. He said that for projects on this scale the drilling and completions design also needed to be started early.
‘We know that we have to get the best out of our project delivery systems,’ Illane concluded. ‘We need our vendors, our suppliers and our contractors to do the same thing. We know that only by working together collaboratively in a transparent way will we be able to manage the risk that will lead to a reliable performance on megaprojects.’
Local content growth in services and supplies will be a key element of the development of the Brazilian pre-salt reserves, Marina Barbosa Fachetti, general manager of Petrobras’ Rio business unit, told the conference. Local industry supplied around 75% of current demand, she said. There would be a need for new companies to establish themselves in Brazil and to increase their local content. The size of the prize is considerable with Petrobras expecting to double production in the next 10 years.
The pre-salt was being developed in three phases. The current phase, phase 0, relates to knowledge acquisition. Phase 1A will consist of two pilots and eight FPSOs, achieving a significant production in 2017. Phase 1B will depend on the previous phase. Two FPSOs will be chartered for phase 1A, and eight FPSOs are under design with a high local content (OE June 2009).
The phased development will help to mitigate the risk and uncertainties about all the technical issues. The first pre-salt discoveries are in 2000m water depth, 300km from Rio de Janeiro and 350km from Sao Paulo, posing logistical challenges. Fachetti added that Petrobras was planning a major investment in offshore exploration over the next five years. Almost 350 new wells will be drilled in the areas off the country’s south and southeast coasts.
GE’s Oilfield Technology (OFT) business, a technology innovator in the design and manufacture of wireline and drilling measurement solutions for the oilfield services segment, has been realigned from GE Energy Services to GE Oil & Gas. Headquartered in Yateley, Hampshire, UK, OFT builds on the 30-year product line heritage of the Tensor, Reuter Stokes, Geolink and Sondex businesses. Today, with over 500 employees, OFT has grown to a global footprint of 14 facilities, including manufacturing sites in North America and Europe, and sales offices in China and India.
OFT has had some recent successes in the North Sea with its downhole cutter, explained COO Jim Junker. The cutter makes a precision cut from the inside, like a lathe, eliminating the use of potentially damaging chemicals previously used. Another focus is high temperature electronics. OFT is working with GE’s global research centre as well as the US’s DOE on equipment for up to 300ºC, as opposed to a current ceiling of 175ºC.
Sam Aquillano, vice president for drilling and production, stressed the importance of the business being part of the ‘big GE’.
‘I think some of our recent wins are proof positive that we are the only company that can bring topside, turbomachinery, compressor capability and upstream subsea equipment to the industry,’ claimed Aquillano, citing as examples Chevron’s Gorgon gas project, where GE is providing both subsea equipment and turbo machinery (see panel, "Operational updates", right), and ExxonMobil’s Kizomba C satellites, where GE is again providing both subsea equipment and turbo machinery (OE October 2009). Aquillano also welcomed the arrival of OFT to the drilling and production division, adding technology in terms of smart wells to the business.
One of the drilling & production division’s strengths is its investment in R&D facilities. Compared with just $7 million in 2006, this year’s budget for subsea R&D is $35 million, to which can be added another $12 million if customer funding, joint industry programmes and some government funding is included. However, the real story is the leverage, noted Manuel Terranova. ‘The $35 million, or $47 million, is really a fraction of what we are able to leverage in terms of intellectual property portfolio, and advanced manufacturing techniques from the big GE.’ On the twin-screw pump the diamond-like coating was qualified by the aviation business for $70 million. The Semstar5 subsea electronics module has benefited from development qualification by GE Wind – qualifying it separately would have cost $7 million.
Some $3 million is currently being invested in a valve qualification facility in Houston, tripling capacity. This facility is being used to test larger bore valves for gas service. The SmartCenter in Nailsea in the UK will have a new over-sized hyperbaric test chamber in operation in April. This will not just be for qualifying controls, but will also be available to the Aberdeen operation to qualify over-sized chokes.
There is a super computing cluster being developed near Oslo, which allows GE’s flow assurance experts to run computational fluid dynamic models leveraged from other parts of GE. Empirical data gathered by remote monitoring can then be analysed to determine whether a choke might need to be replaced early, for instance due to sand generation. There is also a new high voltage testing facility coming online outside Oslo, at Drammen.
Optimistic about 2010
2009 was a challenging year for the business, Claudi Santiago, GE Oil & Gas president and CEO, told attendees. Demand for hydrocarbons had softened, spare capacity had increased and economic volatility had its impact on new project decisions. However, the prospects for 2010 were more encouraging, he added. Hydrocarbon demand is expected to return to 2007 levels with the oil price stabilizing above $70/bbl. The rig count was recovering – up 37% in the US since mid 2009, and E&P spending was up about 10%.
Oil and gas recovery would come from emerging economies. China and India will consume 100% of the current Saudi Arabian oil production by 2020, and five times Saudi’s production would be needed in 10 years to meet world demand. There would also be strong growth in the demand for gas as a bridge fuel. This would create a requirement in 10 years to create four times the current production of Russia.
‘Upcoming reservoirs are increasingly challenging and require a new level of innovation,’ said Santiago. The GE strategy is to move closer to customers, doubling the service centre network over five years with more local resources. It has about 1370 field engineers, 80% locally-based, and is expanding the company’s footprint through partnerships and joint ventures. OE
Subscribe
