The oil and gas industry continues to develop new technologies and adapt others to keep pace with the rising need worldwide for energy. Diversified energy supplies, energy security, market uncertainty, and the recent strength of oil and gas prices all have played a part in fueling these “Waves of Change”the theme of the Offshore Technology Conference in Houston May 5-8.
Industry continues to search for resources in deeper waters, speakers at OTC said. The Gulf of Mexico’s deep water (to 400 m) and ultradeep water (deeper than 1,600 m) continue to be a vital part of the gulf’s total production, providing about 72% of the oil and 38% of the gas in the region, said the US Minerals Management Service in a report released May 6 at OTC.
At the end of 2007, there were 130 producing projects in the deepwater gulf, up from 122 at the end of 2006, said Lars Herbst, MMS regional director for the gulf’s Outer Continental Shelf. Fifteen deepwater fields, including Atlantis, Shenzi, and several associated with Independence Hub, began production last year.
Production from the Independence Hub in the eastern Gulf of Mexico exceeded expectations in the quarter ended Mar. 31, averaging 841 MMcfd, said operator Anadarko Petroleum Corp. However, a leak from a stainless steel o-ring gasket located on the flex joint that connects an export pipeline to the platform in about 85 ft of water forced the shutdown of operations in April, pending repair. When Independence Hub reaches full capacity, Herbst said, it will represent more than 10% of the total gulf gas production.
Proved deepwater fields now number 125, representing a 44% increase from the end of 2006. For the first time in history, all 20 of the highest producing blocks in the gulf were in deep water.
Ultradeepwater activity
According to Randall Luthi, MMS director, more than a dozen new ultradeepwater rigs, capable of drilling in 12,000 ft of water, are expected to enter the gulf in the next few years. “Continued advancement into this deepwater frontier is important to our nation’s energy security,” Luthi said. “The Gulf of Mexico is a key energy producer, and the safe and environmentally responsible development of our resources is vital to the economy and our way of life.”
In 2007, 54% of all gulf leases were in 1,000 ft of water or deeper, the report said. In the two lease sales that year, Western Gulf Lease Sale 204 and Central Gulf Lease Sale 205, nearly 70% of the tracts receiving bids were in deep water.
This year saw a record-setting lease offering in Central Gulf Sale 206, which attracted $3.7 billion in high bidsthe largest sum since federal offshore leasing began in 1954 (OGJ Online, Mar. 19, 2008). About 67% of the blocks receiving bids were in deep water with about 34% in ultradeep water.
“As we look at the data, it’s clear that deepwater advancement is occurring in all areasleasing, drilling, and production,” Luthi said. By yearend 2007, he said, there were 130 producing projects in deepwater, double the amount from 5 years ago.
Energy security
Energy security must incorporate social acceptance of technology, available diverse energy sources, and environmental sustainability, said speakers in a May 6 panel discussion at OTC.
Robert Fryklund, IHS Inc. vice-president of industry relations, said society in general, including the oil and gas industry, is working to achieve a balance between energy security and climate security. “Unfortunately, this puzzle has a couple missing pieces,” Fryklund said, “There is a lot that we know, but there is a lot that we don’t know. In the corporate world, we ask how much is it going to cost? As individuals, we ask how much more are we going to have to pay at the pump?”
Amy Jaffe of Rice University’s Baker Institute, Houston, said the concept of energy security varies over time and geography. Europeans generally talk about natural gas when they discuss energy security while US citizens generally talk about gasoline. “So, different parts of the world are not even talking about the same commodity,” Jaffe said.
The definition of energy security also changes with perceived threats to energy supplies. Such threats include political instability and civil unrest in some producing countries, severe storms, and work stoppages. “On top of that, we have to worry about a new producer climate. National oil companies feel empowered by oil supply shortages, and this will tempt them to flex their geopolitical muscle,” Jaffe said.
Not all types of energy are well received, she added, noting that oil sands are perceived by some as being good for energy security but bad for climate security. Saying that she does not view energy security and climate security “as two sides of the same coin,” Jaffe acknowledged “a growing sense of urgency about climate change and security of supply.” New fuel efficiency standards will reduce US oil demand and emphasize greater fuel diversity, she said.
Trade offs will have to be made when determining the future energy mix, and Jeffe questioned whether many people yet realize the ramifications of such decisions. “If we move to greater use of natural gas, what is that going to mean for US energy security,” she asked. “In a carbon-constrained scenario, LNG becomes quite more dramatic. It makes the US more dependent on imported LNG.”
MMS view
MMS Director Luthi said environmental security needs to be considered along with energy security and climate security. “The price of gasoline is only part of our energy equation,” Luthi said. “Without increased domestic production, imports will have to increase.”
US energy production must be increased from all sources, including alternative and renewable energy, he said. “We do have to look at all possibilities: new sources of energy as well as more efficient use of existing sources,” Luthi said. “It needs to be a worldwide effort. The US is a key part, but other emerging economies need to be a part as well.”
Kevin Leahy, Duke Energy Corp.’s managing director for climate policy and economics, said climate change will rework the energy supply and distribution system in the US, particularly for transportation fuels. He said the power sector is going to drive carbon dioxide prices in a global carbon-trading scenario and natural gas prices, too.
Regarding the future role of hydrocarbons, Leahy said, “I could see where electrons would become energy carrier for wealthy countries, and liquid fuel would still provide the energy in countries with emerging economies.”
Key considerations for expanding the role of clean energy involve more than cost, said Robert LaCount of Cambridge Energy Research Associates, Massachusetts. Other factors are scale, reliability, timing, integration, and unintended consequences. “When we look over the next couple decades, we would recommend keeping our eye on many different aspects” to see how acceptance of different energy sources develops, LaCount said.
International perspective
Fatih Birol, chief economist for the International Energy Agency, Paris, sees a “new world energy order” with some new actors coming into the picture, and some actors exiting.
China and India are transforming global energy markets, Birol said, adding those two countries are expected to contribute almost half of the increase in global energy and 60% of carbon dioxide emissions by 2030. China’s oil imports are expected to reach 13 million b/d in 2030, and car ownership there is forecast to jump to 140 vehicles/1,000 people compared with 20 vehicles/1,000 people today.
“Carbon capture and storage would be good for energy security and climate security, but we are not yet there,” Birol said.
Carbon dioxide
Both onshore and offshore sequestration options are under study to find large capacity storage for CO2 emitted from the use of fossil fuels, said participants at another OTC panel. Sally M. Benson of Stanford University said improved understanding of multiphase flow and trapping in CO2-brine systems is needed to predict the storage capacity of saline aquifers.
Daniel P. Schrag, a professor at Harvard University’s Department of Earth and Planetary Sciences, believes deepsea sediments in 3,000 m of water could provide permanent offshore storage by gravitational trapping.
Sequestration of CO2 would keep it out of the atmosphere, where it could contribute to global warming, scientists say. Benson is studying monitoring methods “to provide a quantitative assessment of the fate and transport of injected CO2” over time. Physical and chemical properties of the storage reservoir and seal are key to the permanent containment of sequestered CO2, she said.
Performance standards regarding leakage have yet to be established, Benson said. Detection methods include seismic monitoring and atmospheric flux monitoring. A recent experiment proved releases of sequestered CO2 are detectable and can be measured. More testing is pending, she said.
The public demands a better understanding of what might happen to CO2 injected into a saline aquifer, she said, calling monitoring a key element of any sequestration project. “This interest is driven in part by concerns about long-term stewardship and liability. After the injection phase of the project is completed, and the wells have been abandoned, there are unanswered questions,” Benson said.
Benson said unanswered questions include:
- How long and how much monitoring is required?
- What can be done to stop a detected leak?
- Who is responsible for monitoring and potential remediation?
- Can long-term liability be transferred to a shared risk pool?
- Will state or federal governments assume long-term liability?
Offshore sequestration
Schrag is evaluating the potential for subsea CO2 storage in deepsea sediments. “At high pressures and low-temperatures common in deepsea sediments a few hundred meters below sea floor, CO2 will be in its liquid phase and will be denser than the overlying pore fluid,” he said. “The lower density of the pore fluid provides a cap to the denser CO2 and ensures gravitational trapping in the short term.”
Thermal modeling and laboratory calculations show injected high-density liquid CO2combined with its potential to form CO2 hydrateswill impede upward migration. Schrag has yet to do field tests on his calculations but is working with Shell Oil Co. to develop a system that could be field-tested. Schrag believes his proposed offshore sequestration will prove to be “essentially a leak-proof method.”
Heavy oil
In an earlier OTC session, David Bairrington, general manger of nonconventional resources at ConocoPhillips, said water management in developing heavy oil resources is a bigger problem than handling carbon emissions. Bairrington told delegates May 5 his company uses 2.5 bbl of water and 1 Mcf of gas to obtain 1 bbl of bitumen when applying the steam-assisted gravity drainage process. About 30,000 b/d of production is typical under this method.
Production of heavy oiltouted as the future of the industryproduces a high volume of carbon emissions because of the intensive techniques required to develop it, and regulators are pressuring operators to reduce the emissions to address climate change. About 63% of the world’s heavy oil resources is in North and South America. It is only within the last 5 years that its production has become economically viable, with heavy oil operators breaking even at a market price of $50-55/bbl for conventional oil.
Meanwhile, operators in Abathasca, Canada, report development costs have soared.
“It is a high cost resource from the production standpoint, so we’re looking at using solvents to accelerate the viscosity,” Bairrington said. Other upgrading options include thermal cracking, removing carbon, and hydrogen additions. “Carbon taxes and dealing with CO2 emissions will be a burden to the industry as a whole,” he said, stressing that carbon capture is problematic.
Scale in developing unconventional petroleum resources is crucial in managing costs, said Timothy Parker, chief executive officer at HighMount Exploration & Production LLC. HighMount operates the Sonora field in West Texas, which has 20 tcf of gas originally in place. Parker criticized the industry for focusing on repeatability as a key success factor, stressing that this may not be the criteria for success in tomorrow’s operating environment.
He said HighMount regularly carries out controlled experiments to identify areas where costs can be slashed and other improvements made. Compared with its peers, he said, the company has drilled identical wells for 70% of the cost others incur. HighMount has 15,000 development locations and plans an aggressive drilling program in the field to sustain gas production over the coming years.
Replacing equipment
The oil and gas industry will need to invest $50-100 trillion to rebuild its ageing infrastructure within the next 7 years to stave off a serious drop in oil and gas production, said Matt Simmons, chairman of Simmons & Co. International, May 5 at OTC. In a worst-case scenario, Simmons said, oil and gas output could fall by 10-20% by 2013 if industry does not replace its rusting, corroded assets. Spare capacity has run out because earlier cheap prices for oil and gas precluded upgrading and construction of new facilities.
The average age of offshore rigs is 25 years, and oil companies have not addressed the problem because of low energy prices during the past few decades. “The industry’s tool kit for corrosion is old, and painting over rust creates an illusion. Few parts of oil infrastructure have been replaced,” said Simmons. Leaks, stains, oil streaks, metal fatigue, and brittle steel are all signs of ageing pipelines, platforms, wells, and other assets.
However, the upward trend in prices can help pay for the rebuilding of the energy system, Simmons stated. Still, he said, “There is no blueprint in place, and this is a global problem. The longer the blueprint is postponed, the more acute the crisis will get.”
The reconstruction problem is compounded by the shortage of skilled engineers to carry out the work and the scarcity of raw materials.
“Peak oil is a reality. In 2005 we had peak production and this fell by 265,000 b/d in 2007. There is a high likelihood that production will continue to fall,” Simmons said. He forecast oil prices could hit $200/bbl as global demand increases. That same day in New York, Goldman Sachs Group Inc., the world’s largest securities firm, predicted crude costs could escalate to $150-200/bbl within 2 years. The front-month price for benchmark US crudes soared past $120/bbl in intraday trading May 5, up from $62/bbl a year ago. On May 6, the intraday price hit a new high of $122.73/bbl before closing at a record $121.84/bbl.
Mexico
With subsalt plays and poor recovery efficiency for existing fields, Mexico needs improved oil recovery and innovative technology to extend the productive life of its reservoirs, said Mexican Petroleum Institute Chief Executive Heber Cinco Ley on May 5 at OTC. Operators are finding Mexico’s fractured reservoirs challenging because they are difficult to characterize, model, and simulate. “We need a new generation of reservoir simulators,” Ley said.
The country’s oil and natural gas industry is crucial to its economy, accounting for 40% of Mexico’s federal budget. But production is on the wane: oil output is 3.1 million b/d, and gas is 6 bcfd. Cantarell, Mexico’s largest oil field, generates half of the output of state-owned oil company Petroleos Mexicanos (Pemex). Cantarell had been producing an average of 1.58 million b/d, but production began falling last November to 1.3 million b/d, and it is expected to drop to 600,000 b/d by 2013. Ley said the challenge with Cantarell is accessing oil that is trapped under the gas cap.
Onshore Chicontepec field will require $14.5 billion to develop. Pemex expects to drill 5,421 development wells in the field by 2012. Oil production is expected to hit 1 million b/d. However, according to Ley, Chicontepec has a primary recovery factor of only 5-7%.
Deep water will be the future source of oil production in Mexico, but expertise is needed in flow assurance, control pipelines, subsea systems, and other areas, Ley added. Pemex has assembled its first deepwater asset team, Coatzacoalcos, which hopes to produce 400 MMcfd of gas under a $40-70 billion investment program. The company also has contracted three semisubmersible drilling rigs for deepwater activity. Two of the rigs can drill in water as deep as 2,100 m, and the third can work in water 3,000 m deep.
Water management from producing reservoirs is another major challenge, as it takes 3 bbl of water to produce every barrel of oil, Ley added. “We need to predict this accurately, as it can affect hydrocarbon production. We need to develop efficient drilling at lower costs.”
Angola
Angola has prequalified 40 oil companies under its latest licensing round, which lists 10 blocks as available, Syanga Abilio, vice-president of Sonangol, told OGJ in an exclusive interview May 6 at OTC. The qualified candidates include majors Royal Dutch Shell PLC and ExxonMobil Corp., independent oil companies, and private Angolan firms.
As so many Angolan companies have applied for licensing permits, the government needs more time to evaluate them, Abilio said. So the country has postponed the previous deadline for companies to submit proposals for blocks. “A new deadline has not yet been given, but we plan to announce that shortly,” Abilio said.
About 200 companies participated in the licensing round, which offers both deepwater and ultradeepwater blocks. “We don’t know what kind of interest the prequalified companies had in the blocks as they had not yet given us a plan for the ones that they wanted,” Abilio said.
The government invited companies to bid for onshore blocks Cabinda Centro in the Cabinda Centra basin and KON11 and KON12 in the Kwanza basin. In shallow water, Block 9 was offered. Three blocks, 19, 20, and 21, are in deep water and Blocks 46, 47, and 48 are in ultradeep water.
Angola’s recent admission into the Organization of Petroleum Exporting Countries should not dissuade potential investors from coming to the country, Abilio said. “We joined the institution that works to protect price, and it was important to be part of that; we were an observer at OPEC for a long time. We have a quota of 1.9 million b/d but that does not bind us on further exploration and production. We had our oil infrastructure destroyed during our civil war, and there is nothing to fear with future investment.”
Sonangol aims to become a fully integrated petroleum company by 2010. It bought a 20% stake in Societe Ivoirienne de Raffinage’s 64,000 b/d refinery at Vridi, Abidjan, in Ivory Coast. Abilio declined to give the value of the investment.
“We are also building a new refinery in Lobito, which will cost about $7 billion,” he said, adding, “It will have a 200,000 b/d capacity and we may seek technical partners in the future. For now, we are doing the project by ourselves.”
Sonangol originally planned to develop the refinery with China’s Sinopec, but talks broke down last year following disagreement on what products the refinery would make. It will process heavy acidic oil (such as Kuito and Dalia) and have a high conversion with crude, vacuum, fluid cracking, and delayed coking units. Construction of the refinery will start by yearend and operations in 2010.
Nigeria
Nigeria is seeking $20-25 billion of private investment to build natural gas pipelines, processing plants, and other infrastructure under its gas master plan, which has just been approved by the federal council. The plan will help Nigeria become a major gas consumer and monetize its 182 tcf of proved gas reserves, said David Ige, group general manager at Nigeria National Petroleum Corp. Ige told OTC on May 6 the plan would help connect the resources to Nigeria’s domestic and export markets.
“The US Geological Survey puts undiscovered reserves at 600 tcf, and our gas reserves are those found so far in exploring for oil. We have not had any gas exploration program on its own,” Ige added. “The commercial framework and the lack of infrastructure have made it difficult to bring the resources to market.”
The plan anticipates an aggressive demand increase of 20-25% in the midterm because of domestic projects such as methanol plants, gas-to-liquids plants, fertilizer plants, independent power projects, and other LNG export plants such as Brass LNG.
Nigeria aims to have a market-driven gas sector by 2014 where the domestic and export market will come together, Ige said. “We did the mistake with oil where exports were preferred over the domestic market and we don’t want to make that mistake with gas.” President Umaru Yar’Adua has called on companies to set aside gas production for local use and Ige told OGJ that the new domestic market supply obligation launched in February would see 1 bcfd of natural gas directed to consumers in Nigeria. This would rise to 4-5 bcfd over the next 5 years.
By January 2011, Nigeria hopes to see a commercial domestic market and commercial pricing for gas to power. By January 2013, it expects to have a GTL market. Nigeria will give presentations in May in Abuja, London, and Singapore to provide more details on how investors can become involved in its gas development.
This report was reported and written by Paula Dittrick, senior staff writer, and Uchenna Izundu, international editor.
