Malaysia’s Prime Minister Opens Inaugural OTC Asia
The first Offshore Technology Conference Asia exceeded attendance expectations while providing in-depth panel and technical sessions on the increasingly important Asian energy sector as well as other globally significant upstream trends and technology applications. The conference was held from 25 to 28 March in Kuala Lumpur.
Malaysia’s prime minister, the Hon. Dato’ Sri Mohd Najib Tun Haji Abdul Razak, cited the importance of the Asia Pacific region in future global energy activity during his keynote address at the official opening of the first OTC Asia. He was joined at the opening ceremony by YBhg Tan Sri Dato’ Shamsul Azhar Abbas, chairman of the OTC Asia Advisory Committee and group chief executive officer (CEO) of Petronas, and Edward Stokes of Chevron, chairman of the OTC Board of Directors.
“These are exciting times for the Asian oil and gas industry, and that is why it is apt that the first OTC Asia is being held in Malaysia,” he said.
“Asia is a continent with a voracious appetite for energy,” he said, noting the region’s projected 2.5% annual growth in consumption and the fact that Asia will account for more than 60% of total global energy demand in 2030.
The region’s rising consumption is not being met as local hydrocarbon supplies are in decline and some countries that once were exporters of energy are now importers. “The easy oil is indeed gone,” presenting challenges, but also opportunities, for the oil and gas industry, the prime minister said.
“We are embarking on a new era of innovation” to help unlock new resources in hard-to-reach places, he said. “We are going further and deeper both literally and with the technology we use.”
Malaysia has “the perfect mix of ingredients to be a regional energy hub,” the prime minister said, because of its location, resources, technical capability, world-class infrastructure, and legislative framework, which is business friendly. He noted the success of risk-service contracts that were introduced in 2011 and the growth during the past 2 years in Malaysian domestic hydrocarbons output. “This success is no accident,” he added.
The prime minister congratulated Petronas, which is celebrating its 40th birthday this year, for its achievements over the past 4 decades, “which have been extraordinary.” Petronas is the most profitable company in Asia and has become a true international player on the oil and gas world stage, he added.
Shamsul Azhar Abbas, president and CEO of Petronas, outlined his company’s aggressive exploration and production (E&P) strategy that it has undertaken over the past 4 years to unlock new resources and increase domestic production. Especially important has been its enhanced oil recovery (EOR) initiatives offshore, including its first large-scale project to boost production from the Tapis oil field by up to 35,000 B/D. The project is using water-alternating-gas injection to increase ultimate recovery. This technology, if proved successful, could be applied at other fields, he said.
Another initiative is to encourage new investment in smaller and marginal fields that were deemed uncommercial just a few years ago. A third measure involves offshore work in the Sabah area. Petronas and Shell announced the discovery of oil from the Limbayong well in the area on 17 March.
Fourthly, Petronas has expanded its research and development activity with the opening of Asia’s first state-of-the-art visualization center and increased training measures. “We will continue to push the boundaries to unlock new resources,” he said.
In his remarks, Stokes noted that, after more than 40 years of successful conferences in Houston, OTC recently began to expand its presence internationally, with new conferences highlighting the Arctic, Brazil, and now Asia. OTC promotes new ideas, innovation, networking, and industry best practices, he said.
Given Asia’s growing importance in global energy, it is fitting that the first OTC Asia would be held in Malaysia, Stokes said, adding that Petronas, the event’s corporate supporting organization, “has been an ideal partner.”
National Oil Companies
The maturing resource base at home has forced many national oil companies (NOCs) to look outside their borders for reserves replacement, where they have to reshape and make decisions quickly to compete with international oil companies (IOCs), said panelists at one of the conference’s plenary sessions, titled “The Easy Oil Is Over: How NOCs Are Reshaping to Stay Fit in the New Normal.”
Traditionally, the role of NOCs has been to promote exploration and development of domestic resources, in addition to providing domestic energy security at reasonable price and providing a robust and steady supply to their government. But, during the past decade or more, many countries have seen the flattening or decline of domestic production, which, coupled with ever-growing domestic energy demand, creates significant challenges to the typical NOC’s ability to fulfill these traditional roles.
Amid these changes, NOCs have had to reshape themselves to compete in the international marketplace for opportunities. “To compete outside of their domestic backyards, NOCs have had to accept exposure to competition with IOCs, new levels of political risk, more costly new operating environments, and a broader range of technical skills and risk,” said Michael Rodgers, vice president of Asia Pacific at IHS PFC Energy.
The difference between more and less successful NOCs will depend on how they are able to cope with these new risks away from home. “As the NOCs move to compete for international deals, they have had to develop expertise in play types, which differ from their core area of expertise,” Rodgers said.
NOCs are playing an increasing role on the international level, and now account for about 80% of the international deal flow. “Reserve Capex (capital expenditure) accounts for nearly one-third of the global E&P spending. This is driven by the need to expand their portfolios with international assets,” Rodgers said. “Half of the top 10 spending companies are NOCs,” he added.
As the NOCs move to compete for international deals, they are faced with the reality that they are, for all practical purposes, faced with the same access challenges that IOCs have faced for years. “The priority access advantage that NOCs have at home largely disappears when they compete internationally,” Rodgers said.
Just like the IOCs, NOCs going international have to go where they can access material opportunity. “They will have to take the risk and go for unconventional resources, deepwater and sand oil,” Rodgers said.
The ability to be agile, to make deal decisions quickly, and to think and behave commercially is what ensures success for an NOC. “NOCs that do not have operational and strategic autonomy are disadvantaged in global competition for reserves and production,” he added.
NOCs are also faced with the reality that we are in a world of shrinking returns. Once NOCs decide to become international, they must compete with IOCs that are structured to move quickly; but, for many NOCs, their own government oversight makes it impossible to move quickly.
Panelists said that, in order to build material international reserves, NOCs must build capabilities and move into technologically more challenging and risky play types. “Significant growth by pursuing conventional onshore and shallow water isn’t enough,” Rodgers said. “They must have a realistic view of its targets, the cost of deals, the balance of exploration vs. acquisition, and its operating experience.”
Dato’ Wee Yiaw Hin, executive vice president of exploration and production at Petronas, said that NOCs have taken a leading role in developing their resources, and hence have moved to compete with IOCs. “Petronas has transformed over the years through strategic operational autonomy, commercial mind-set, and governance,” Wee said.
NOCs should play the role of regulator and enabler in terms of effective resource management. “We should enable companies around us, including oil and gas companies and service companies,” Wee said. “What we need to succeed as NOCs in this changing world is integration, scale, technology, as well as capability,” he said.
New Technology Needs
In the midst of another conference plenary session, titled “Game-Changing Technologies in Offshore Exploration and Production,” a cost-control discussion took over. Price is always a consideration when something new hits the market, but it is becoming an increasingly thorny issue.
During the past 4 years, while oil prices have hovered around USD 100/bbl, the cost of increasing reserves is rising by an average of 12% a year, said David Lesar, chairman and CEO of Halliburton.
“This has been a main concern that is putting at risk the businesses of the operators and the contractors,” said Thierry Pilenko, chairman and CEO of Technip, during the session.
Margin squeezes are not a new experience. Veterans in the business going back to the 1990s remember the extended string of lean years when spending was hemmed in by oil prices around USD 30/bbl. And then oil prices surged in the early 2000s. With increased exploration, the costs of hardware and services used to find oil and gas increased.
The treatment for anemic margins, according to the panel, is not a simple cost-cutting exercise. National oil companies in Asia are judged on their ability to fuel exploding growth in the region, where the aspirations of so many depend on more oil and gas.
“The problem is not in the resource. It is the cost,” said Ryan Lance, chairman and CEO of ConocoPhillips.
Reaching potential reserves presents problems that require new tools to coax more out of large, old formations, to economically produce from pockets of oil and gas that once would have been passed over as too small or too difficult, and to produce from deeper waters.
The winning strategy for meeting those demands involves addressing the cost per barrel, by cost cutting or by finding a way to produce significantly more over time, which could require spending considerably more in the short run.
Lesar’s laundry list of critical technology needs began with an emphasis on better reservoir analysis during the exploration and development planning stage. It was a reminder that not spending can be costly in the long run.
“Exploration is expensive. But that pales in comparison to the cost if you develop a reservoir wrong,” Lesar said. The options offered for doing better included using advanced modeling software, downhole fluid sampling and testing while drilling, and faster data communication and big data analysis.
Technology can help, but controlling costs will also demand a tough-minded evaluation of the habits acquired during the past decade.
“Are we not adding layers of procedure, one on top of another, and increasing the time and cost of developing fields?” said Tan Sri Dato’ Seri Shahril Shamsuddin, president and group CEO of SapuraKencana Petroleum.
Cost can be reduced by taking “more time on the conceptual and front-end engineering and design stage,” with engineers working closely with operators, Pilenko said.
Longer memories offer an argument for not scrimping. Maarten Wetselaar, acting upstream international director at Shell, noted that a number of fields produce considerably more than what was expected during planning and development.
“We should be cautious about reducing costs up front,” he said. “Spending more could mean more production over time.”
Global LNG Market
The Asia Pacific region is a critical market for the global liquefied natural gas (LNG) market, according to the panelists at one of the conference’s panel sessions, who also said that the LNG market is interconnected and can switch from one market to another easily when necessary.
Daniel Fobelets, global strategy and portfolio manager of integrated gas at Shell, said that the global LNG market is approaching a period of change brought on by recent significant developments. These developments include shale gas, east Africa gas, revised positions on nuclear power, and the changing dynamics between the traditional and new global LNG supply and demand points as markets mature.
“From the supply point of view, Australia is set to take the lead as the world’s largest LNG producer by the end of this decade, overtaking Qatar,” Fobelets said. “In addition to Australia, Qatar, east Africa, and Russia are also among the main supplier of LNG,” he said.
Qatar is currently the largest LNG producer after completing massive investment projects in 2010.
Adnan Zainal Abidin, vice president of global LNG at Petronas, said that his company currently operates eight LNG trains producing 25.7 MTPA of LNG, making it one of the leading LNG players in the world. “Our combined LNG sales including production and trading volumes in 2013 reached 28.9 million tons,” he said. “Currently, we are No. 2 in the LNG world, and we intend to maintain our position despite the competition.”
Petronas is also boosting its LNG production capacity and has several projects in the pipeline, either through LNG or floating LNG (FLNG) facilities. “Our LNG Train 9 is set to be operational by the end of 2015, early 2016, and produce 3.6 MTPA to the Bintulu complex’s existing 24 MTPA capacity,” Zainal Abidin said.
Petronas’ first FLNG facility will be among the world’s leading FLNG vessels, scheduled for deployment in 2015. With a 1.2 MTPA capacity, it is expected to operate at Kanowit gas field, 180 km offshore Bintulu. Meanwhile, the FLNG 2 facility will be located at the Rotan field in Block H, with a liquefaction capacity of 1.5 MTPA, and is scheduled for startup by early 2018. “Work on our Gladstone LNG in Australia has reached 75% and is set for startup in 2015; while our Pacific Northwest LNG project in Canada is set to produce 12 MTPA of LNG with commercial operations expected in early 2019.”
Michael Culligan, manager of LNG technology and licensing at ConocoPhillips, said that North America is poised to become a net LNG exporter, thanks to the shale gas revolution. “Global LNG demand and competing supplies will restrict the number of projects built,” he said. “In the Asia Pacific region, Australia and Malaysia are taking the lead in terms of FLNG projects.”
Phillip Hagyard, senior vice president of gas monetization at Technip, the French EPC contractor, said that Asia is central to the future of LNG, where gas reserves can be produced economically through the use of offshore technology. “Modularized onshore projects, deepwater gasfield production, and floating LNG are examples of how we can produce gas economically, where Asian yards hold the key to these large projects,” he said.
Hagyard also said that the Asia region has new sources of LNG supply, citing FLNG from Australia, east Africa, and east Mediterranean; modularized sources from Alaska, British Columbia, Australia, and the Russian Arctic, in addition to deep to shore LNG sources and low offshore content from the Mediterranean, east Africa, and US Gulf of Mexico.
The LNG Paradigm Shift was the theme of the presentation of Henry Aldorf, president of Pacific LNG Operations, who said that LNG was an integrated business held by few players, with business chain separation caused by supply and technology change resulting in lower costs, enabling smaller players and many entrants in the LNG space.
“Demand basis is rapidly changing and growing, pushed by new markets and buyers, technology, economics, and low CO2 emissions,” Aldorf said. “This also led to the emergence of LNG trading hubs,” he added.
EOR projects should be regarded as industrial projects rather than E&P activities, and they pose business model issues rather than technology issues, according to panelists speaking at a session, titled “Energy Policy in the Asian Region: From EOR Technologies to Fiscal Incentive to Increase Recovery Factors.”
Historically, EOR projects have been driven by oil price; however, in the current cycle, maturing fields around the world are also a major factor. “As oil and gas reserves are decreasing and energy consumptions keep on increasing, we should move to EOR,” said Ignatius Tenny Wibowo, president director of Indonesia’s Pertamina Hulu Energi.
In Indonesia, 90% of oil fields are mature with very limited major oil discoveries. The majority of oil fields are still in primary recovery, with a recovery factor of 15% to 30% and a high potential from the remaining oil in place, because there has been no secondary recovery/EOR efforts in the past 40 years. “Currently, available EOR technologies allow for various and fit-for-purpose implementation, where the success of EOR projects highly depends on technology selection and high fiscal terms,” he said.
Pertamina operates more than 300 fields in Indonesia, of which 85% are mature fields, most having passed peak primary production. “About 40,000 B/D (or about 20%) of our production comes from secondary recovery EOR,” he said. “Several fields were identified as suitable for CO2 injection, with more than 30 fields indicated to have potential for EOR (including chemical injection, CO2, polymer, and thermal/steam injections,” he said.
Indonesia intends to encourage investors to take part in EOR projects through favorable fiscal terms and incentives to allow them to access smaller field sizes. “This includes higher profit spilt for EOR/tertiary reservoirs, where contractors could get up to 25% profit share for oil fields (vs. 15% conventional) and up to 40% share in gas fields (vs. 30% conventional),” he said.
In Malaysia, EOR projects are well under way, and Petronas has sanctioned 10 EOR projects, according to Adif Zulkifli, vice president of petroleum management at Petronas.
Zulkifli said that increasing recovery factor to 40% or 50% could increase Malaysia’s oil reserves by almost 2 billion bbl, where EOR is essential to increasing the life of the operating fields. “Increasing recovery factor is the key to sustaining Malaysia’s oil production, as our production is declining by almost 10% while our average recovery factor from EOR/IOR (improved oil recovery) is about 5%,” he said.
Petronas has taken actions to drive EOR activities in Malaysia despite the technical and commercial challenges. “All our fields are offshore, which adds more complexity to our EOR activities. Added to that the technology maturity and, most of the time, EOR projects go beyond the existing production sharing contracts (PSC) contract duration,” he added.
To address these challenges, Petronas set strategies based on innovative solutions that ensure that the most innovative methods and technologies are being disseminated and deployed to reduce capital and operating costs. Also, Petronas seeks to ensure that companies with specialized EOR expertise are aware of the opportunities and are attracted to operate in Malaysia.
Malaysia also worked on its fiscal terms and designed incentives to motivate investors to undertake EOR projects. “We manage to harvest some achievements from our EOR projects with 900 million bbl reserve addition from EOR projects in the past decade, with an estimated total investment of about USD 14 billion,” Zulkifli said. “Success of EOR projects in the pipeline will position Malaysia to be amongst the leaders in the industry with the first full-field offshore chemical EOR and the largest offshore WAG (water alternating gas) injection. We continue our efforts to increase recovery factors,” he added.
Ken Tubman, vice president of geosciences and reservoir engineering at ConocoPhillips, said that EOR challenges lie in planning and execution, geological complexity, and temperature and salinity.
Subsurface capability is particularly important for the future success of EOR projects, because every scale of subsurface is relevant and may pose a challenge. Cross discipline and functional integration is usually a challenge and, in the case of EOR, it is magnified. “Interactions between EOR chemicals and oilfield additives are also among the challenges the industry faces when implementing EOR projects, added to logistics, weather, and environmental constraints,” Tubman said. “Better technology and economics are the main enabler of EOR projects.”
Most EOR production comes from the United States, but this could change in the coming years as countries are looking for more oil production and introducing new fiscal incentives to encourage investors to take part of EOR projects. “Opex (operational expenditure) can be a significant part of life cycle costs. Managing supply chain costs is critical for EOR projects,” said Farooq Qureshi, vice president at Schlumberger.
In the PSC environment, dealing with EOR can be complex, given the dynamics of EOR projects, which are very different from E&P projects. “EOR projects could have drivers different to traditional E&P projects and the fiscal system needs to cater for that difference,” he said.
Qureshi said that EOR is different from the normal E&P processes, because it is all about increasing the pie rather than exploiting the pie in the most optimal manner. “Therefore, the risks are higher, especially in offshore EOR, where pilots may not be an option,” he said.
Malaysia’s Prime Minister Opens Inaugural OTC Asia
01 May 2014
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13 May 2019
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