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Figure 1: Lorenzo Simonelli, new CEO of GE Oil & Gas, briefed attendees on industry trends[/caption]
The annual GE Oil & Gas meeting took place in Florence, Italy in February. The number of customers attending (over 1,000, up from just over 900 last year and 700 back in 2009) parallels the growth trajectory of the oil & gas market.
Lorenzo Simonelli (Figure 1), the new President and CEO of GE Oil & Gas (p. 30), noted that this year marks the 20th anniversary of GE’s purchase of Italian centrifugal compressor manufacturer Nuovo Pignone. Since then, the company has expanded its scope from purely turbomachinery to one spanning almost every aspect of the upstream and downstream value chain. This includes subsea drilling, refining, offshore platforms, condition monitoring, analytics and more.
“This year’s conference is all about redefining what’s possible,” said Simonelli. “To achieve that in real terms, we have to engage in meaningful collaboration across the industry.”
That collaboration theme was picked up by speaker after speaker and reinforced in a series of panels and keynotes featuring: Farsheed Mody, Manager Global Research and Technology, Apache Corp.; John A. Broman, Vice President, International Operations, Anadarko; Michel Hourcard, Senior Vice President of Development, Total; Jackie Mutschler, Head of Upstream Technology BP; Craig Jarchow, Managing Director of private equity firm Pine Brook (New York); Greg Morris, Strategy Business Development of Additive Technology, GE Aviation; Jean-Marc Ollagnier, Group Chief Executive, Accenture; and Manny Gonzalez, Manager of R&D Alliances at Chevron.
Gonzalez explained some of the logic behind his company’s alliance with GE (see article here ). “New technology is not necessarily always coming from within the oil & gas sector,” he said. “We are developing a mud system, for example, that originated from a laser specialist at Los Alamos National Labs.”
With GE being able to leverage developments from different industries operating within its portfolio, Chevron expects to benefit from oil & gas breakthroughs from unexpected places such as aviation. By becoming involved early in the new product cycle, the petroleum major hopes to avoid the early adopter bugs that can plague complex technology.
“We are putting new technologies into the field to purposefully break them so we know the problems and can fix them before they are placed into full-scale operation,” said Gonzalez.
Esperança Bias, Mozambique’s Minister of Mineral Resources, continued the collaboration message. In a keynote address covering the challenges and opportunities of an emerging gas producer, she called upon industry suppliers to partner with governments to balance project economics with social benefits by investing in programs that upgrade the local community.
“Our policy is to ensure mineral resources are used to boost our economy while eradicating poverty and improving the quality of life in our country,” said Bias.
In a country of 23 million which is well endowed with natural resources, and now possesses the geological information to exploit its vast coal and natural gas potential, Mozambique is sure to attract plenty of candidates willing to fall into line with this policy. Its annual output of gas in one year is 183 million gigajoules (one billion joules) and proven reserves are 150 trillion cubic feet.
One major infrastructure project on the horizon will be using GE compressors and turbines for between two and four Liquefied Natural Gas (LNG) trains. Feasibility studies are ongoing. “We anticipate the first LNG cargo to sail by the end of 2018 or early 2019,” said Bias.
Russian oil & gas producer Rosneft is another GE collaborator. The company is partnering with GE on the construction of facilities for the Russian manufacture of GE 6FA turbines. This is part of a localization strategy. “We are cooperating with GE in science, technology and engineering,” said Andrey Shishkin, Vice President of Energy, Environmental Health and Safety at Rosneft (Figure 2). “As part of this partnership, we are building a joint R&D center in Saint Petersburg.”
Figure 2: Andrey Shishkin of Rosneft provided a keynote at this year’s event[/caption]
Rosneft is a vast upstream and downstream company that operates in 16 countries. It runs 11 refineries in Russia and has stakes in seven others abroad. It produced 240 million tons of oil equivalent (MTOE) in 2103.
Its pièce de resistance is tapping into the fossil-fuel rich Arctic region. As well as outrageous surface conditions, ice and permafrost extending to great depths and a window of only 45 days per year for drilling, developers must address high environmental sensitivity due to the presence of large populations of marine mammals and migrating birds.
“With temperatures of minus 60°C and wind speeds of 15 meters per second, this is comparable to the space program in terms of technology development in the face of challenging conditions,” said Shishkin.
Rosneft has already cut its teeth in the not-quite-so-inhospitable Sakhalin-1 LNG project off the coast of eastern Siberia. The company expects to begin exporting about 5 MTPA of LNG by 2018. Shishkin said Rosneft is looking at a possible second train there in the near future.
GE boasts an installed base of more than 4,000 centrifugal compressors, over 8,000 reciprocating engines and over 19,000 high-speed reciprocating compressors, on top of its fleet of 5,000 steam and gas turbines, and 2,000 turboexpanders. Recent GE news would add to its tally. Subject to obtaining regulatory approvals, the company is acquiring Cameron’s reciprocating compressor manufacturing business, which are high-speed compressors used in natural gas applications.
GEs Oil & Gas’ existing High-Speed Reciprocating (HSR) business, focuses on lower horsepower units that are used predominately in gas lift applications. Cameron’s Reciprocating Compression division portfolio complements GE’s business by adding higher horsepower models used in gas gathering, processing and transmission.
Mike Hosford, General Manager of Distributed Gas Solutions at GE Oil & Gas, provided clarification on the market nuances that currently separate GE’s highspeed reciprocating compressor line from the Cameron units.
Cameron possesses high-speed reciprocating compressors as well as a range of centrifugal compressors. GE is only taking over the former group, which are machines built to ISO 13631 (formerly API 11P). There is little overlap between GE’s high-speed Gemini and Cameron high speed models, said Hosford. The Gemini units are more used for work at 400 hp and less. Cameron recip compressors, on the other hand, are primarily running at 400 hp and above. Some, he added, operate beyond 3,000 hp.
“Cameron is heavily focused on the exploration and production side; its recip group was not a core business,” said Hosford. “But its high-speed recip business was considerably bigger in footprint and service capabilities than ours and can help us grow in that space.”
He laid out the numbers: Cameron has 900 employees in high-speed reciprocating compressors and three manufacturing facilities and 17 sales and services centers for high-speed recips compared to GE’s one in Houston and another recently opened in China.
“Shale gas is really going to spur growth of high-speed compressors,” said Hosford. “As shale develops overseas, we’ll also see more activity in this area.”
Cameron’s recip compressors also align well with GE’s existing Waukesha gas engines that are a part of its new Distributed Power business in GE Power & Water. These engines are used for gas compression, oilfield power generation and pipeline and unconventional gas gathering applications.
In addition to overseeing recips, CNG and LNG fall within Hosford’s distributed generation zone. He believes that the U.S. is on the verge of adopting natural gas in transportation in a big way (see "Turbine-Driven Truck" here). Hence, he thinks GE’s CNG In A Box system is set for major expansion in the U.S., China and Russia.
“Countries that have gas resources available yet are importing diesel can see the value of using that gas internally rather than sending it overseas via LNG,” said Hosford.
Meanwhile, the LNG In A Box system is still in its pilot phase with a market that has yet to be properly defined. The concept being touted by GE is the “virtual pipeline.” This solves the problem of how you move gas from one location to another when there is a lack of an established pipeline infrastructure.
Small-scale LNG can range in size and is basically all about diesel replacement, said Hosford. This technology is already generating interest at a government level. Indonesia, for example, has a lot of gas but is a land divided into countless numbers of islands. As pipelines are not a realistic approach, smallscale LNG virtual pipelines might be a more viable alternative. Africa is another area of potential for this technology as it lacks a pipeline infrastructure.
But GE remains committed to its GT drivers for mechanical drive. Last year, it was announced that the company was working on the mechanical drive version of the LMS100. Luca Maria Rossi, Product Management General Manager for Turbomachinery Solutions at GE Oil & Gas, said this is still being worked on as the market is very interested in that solution. “It will be the perfect fit for largescale and medium-scale LNG,” said Rossi. “We are beginning to be commercially active with a mechanical drive LMS100 and are expecting to receive our first order in the next year or so.”
He added that large frame machines such as the Frame 7 or Frame 9 are currently used in such applications. The Yamal LNG project in Russia and the Dominion project in the U.S. are just two examples of sites that opted for the Frame 7. Rossi noted that the Frame 7 often makes sense when harsh conditions are present such as Yamal’s Arctic environment.
“Frame 7 maintenance is typically done on site, so the shutdown window tends to be longer than aeroderivatives, but the Frame 7 has to be shut down on fewer occasions,” said Rossi.
Alternatively, some projects prefer to use multiple smaller units such as the LM6000 or LM2500. There are already hundreds of LM2500 units functioning in mechanical drive. The first use of the LM6000 in mechanical drive is at Chevron’s Wheatstone LNG facility in Australia.
Full load string testing was accomplished successfully in the last few months at GE’s Massa testing plant in Italy. Twelve LM6000 units have now been shipped to Wheatstone to make up two large LNG trains. Statoil has also ordered one LM6000 for use in offshore gas compression.
Rossi stated that the LMS100 will introduce more flexibility and performance in a smaller footprint. Maintenance personnel can swap out the Super Core in less than two days. Further benefits, he cited, included fuel savings, and the highest efficiency for any turbine in simple cycle.
“Our Yamal customer preferred the robustness of the Frame 7 versus the performance of the LMS100 as they were already comfortable using it,” said Rossi. “The LMS100 could also cope with very cold and hot environments, with minimal impact to performance output.”
A panel at this year’s Annual Meeting centered upon project economics. David Andrews, Managing Director of Deutsche Bank, predicted a rising interest rate environment and warned the audience to expect the continuance of shareholder activism which would place constraints on margins.
“Oil & gas companies now have demanding shareholders so management has to be more cautious of investments and overall responsibilities,” said Andrews.
Marco Annunziata, Chief Economist at GE, said to look for moderate growth in the U.S. He said lower energy costs and technology developments will boost the U.S. economy over the next two years. He also looked for strong advances in sub-Sahara Africa from countries such as Mozambique and others.
Christof Rühl, Chief Economist at BP, gazed into the crystal ball at the year 2035, forecasting changes in trading patterns for oil and gas. For example, North America is making the transition from energy importer to exporter. Asia, on the other hand, will have to import about 80% of its energy. And supply disruptions due to political upheavals such as the “Arab Spring” are likely to continue, he surmised.
Rühl also cast aspersions at initiatives to curb CO2 emissions. He cited negative gains in overall planetary emissions despite a fortune being spent on these programs. But he also showcased good news that might have escaped the attention of some: the recent resurgence in U.S. oil and gas production was actually the second largest such ramp up in history, with only Saudi Arabia having brought more oil online in a similar time frame.
“Shale gas will contribute 21% of global gas by 2035, yet that is not the most important component of growth,” said Ruhl. “We will see greater expansion in emerging market from conventional gas resources over the next twenty years.”
Andrews explained why the shale gas revolution in the U.S. has not taken hold elsewhere. In point of fact, there are more heavy oil resources existing in places such as Venezuela and China. But the lack of a competitive energy sector and a different political climate means that exploitation of these fields will take longer.
“Shale growth is largely disappointing in other countries,” said Andrews. “The U.S. has a very entrepreneurial atmosphere which is a big driver of shale expansion.”
In another keynote, Giuseppe Recchi, Chairman of ENI, touched upon delays in Engineering, Procurement and Construction (EPC) projects in oil & gas which cannot be attributed wholly to the sheer size of projects undertaken. According to his figures, total delays in 2013 were about 2 years and 6 months higher than in 2012. This included about 50% of greenfield projects with more than a combined total of one year’s worth of delays (Figure 3).
Figure 3: Average delays in projects for 2013[/caption]
His answer, like many others at the event, was greater cooperation among those involved. He announced a strategic partnership with GE.
“Collaboration is vital as it can take years before a useful piece of technology matures,” said Recchi. “It requires service companies and oil & gas producers working together to enable timely project delivery, profitability and efficiency.” This sentiment was echoed by Lars Christian Bacher, Executive Vice President of Development & Production International for Norwegian firm Statoil. But his emphasis was on public and private partnerships to ensure projects do not become derailed.
Such an approach could prove vital in the coming years if Statoil’s plans for a subsea factory come to fruition. Bacher said this breakthrough could dispense with the need for surface rigs, bring about a major drop in costs and facilitate access to newer resources (Figure 4).
Figure 4: Statoil’s subsea factory concept. All functions formerly placed on surface rigs will be redeployed to the sea floor[/caption]
“We plan to have our first subsea factory on the seabed by 2020,” said Bacher. “It will contain all elements that are on a platform today.”
The Annual Meeting often features a view of the global oil and gas picture; this year’s was presented by Maria van der Hoeven, Executive Director of the International Energy Agency (IEA). As usual, the IEA unveiled some startling statistics.
Case in point: today’s share of total energy provided by fossil fuels stands at 82%, the same as it was 25 years ago. IEA forecasts that even a strong surge in renewables will only reduce this number to 75% by 2035.
The future also holds a sharp fall in production from existing fields as the amount taken from tight oil and other unconventional sources mushrooms. But while van der Hoeven appeared to be a supporter of environmental initiatives in general, she noted the benefits of coal in emerging markets.
“Coal is powering the Asian economic miracle,” she said. “The main eradicator of energy poverty at this time is coal. All the solar panels in the world produce 1% of China’s coal energy.”
She followed that with a word of caution. Van der Hoeven believes that the gas industry tends to underestimate coal, yet its expansion in growth in China has been four times more than the current gas boom in the U.S.
Further, she called for an end to largescale gas flaring. This is done in high volume in regions where there is energy poverty among the local population. The industry needs to find ways to translate an excess of unwanted gas into power production for those in need.
That said, there was plenty of good news for gas. IEA expects natural gas production to increase significantly in every region of the world except Europe by 2035.
“Gas plays an increasingly crucial role in electricity generation due to lower emissions and greater flexibility,” said van der Hoeven. “It will become the dominant fossil fuel by 2035.”
As regards environmental concerns about fracking, she advocated responsible best practices and taking problems seriously, even though some claims may be exaggerated. She cited a raft of delays in carbon capture and storage (CCS) projects around the world as local residents and government agencies feared the consequences of pumping CO2 underground.
One particular project in The Netherlands was particularly personal for her. As a member of the Dutch government, she had been a supporter of a plan for a huge CCS reservoir in her home country. Local opposition halted the project at the eleventh hour.
“Managing public opinion is difficult,” said van der Hoeven. “The Netherlands’ CCS project failed due to not engaging the public from the very beginning.”
Additionally, van der Hoeven warned the audience about resting on their laurels. She reminded them about a company named Baldwin from the 19th century which dominated steam production in that century. But its stubborn refusal to countenance the latest electricity technologies led a small startup named General Electric to send Baldwin to join the dinosaurs. It was up to today’s established oil & gas enterprises to continue to innovate, avoid the fate of Baldwin, and bring electricity responsibly to the entire planet.
“Everyone, even the 1.3 billion who don’t have electricity, wants to turn the light switch on, and it’s you who provide the switch,” said van der Hoeven.
Erik Bonino, Executive Vice President of Project & Engineering Services, Shell Global Solutions, agreed that gas was in a position to displace coal and reduce the global carbon footprint. However, much of that gas is in difficult places, has unwanted content such as H2S and has to deal with fracking acceptance challenges among the wider population.
Shell is going after stranded gas, for example, below the ocean floor far off the northwest coast of Australia. Its Prelude floating LNG (FLNG) project includes two GE steam turbine-driven centrifugal compressor trains as part of the liquefaction process to cool natural gas to a liquid state.
The Prelude facility will measure 488 meters from bow to stern and will weigh around 600,000 tons when fully loaded. It will contain 260,000 tons of steel, and its deck area will be longer than four football fields.
It will be moored about 200 kilometers off Western Australia’s Kimberly Coast. Once operational, Prelude will produce at least 3.6 million metric tons per year of LNG.
Like van der Hoeven, Bonino was a realist when it came to anti-fracking and pipeline protests. “You can’t cry about them as they are a reality,” he said.
His call to action on collaboration was more of a request for help. He sees huge promise in gas-to-liquids technology, compressed natural gas (CNG) and smaller-scale LNG for use in transportation. But that will take the creation and management of a distributed network of small hubs that encompass skill sets and technologies well beyond Shell’s core competencies. “We are reliant on GE and others to bring that technology to bear,” said Bonino.
Kim Hatfield, President of Crawley Petroleum (Oklahoma City), ended with a history lesson. Not so long ago, the oil & gas fields of Texas and other parts of the U.S. contained abundant shale resources that could not be exploited. This meant that billions of barrels of oil and trillions of cubic feet of gas were bypassed as they did not come in “well-behaved containers.” As the industry lacked the tools to harness these fields, developers wasted a lot of time sifting through resources figuring out which deposits they could use.
That all changed when a developer named George Mitchell made the Barnett shale viable by figuring out the technology of fracking. “It took Mitchell almost 20 years and we all thought he was crazy,” said Hatfield. “When Barnett became a success, the game was on. As lots of different techniques were tried, this quickened the pace of innovation.”
He closed his talk by requesting that same level of innovation in other areas to increase drilling efficiency. For example, limitations in gas pumping and lifting techniques mean that drillers are still abandoning shale plays long before they are depleted.
During conference breaks, attendees visited an exhibit featuring GE Oil & Gas products and services[/caption]