Special Report: 40th OTC highlights world economy, energy policy, and environment

May 11, 2009
The oil and gas industry continues to develop new technologies to explore for, develop, and produce the energy resources needed for growing global demand.

This report was reported and written by Alan Petzet, chief editor- exploration, Guntis Moritis, production editor, Sam Fletcher, senior writer, Paula Dittrick, senior staff writer, and Uchenna Izundu, international editor.

The oil and gas industry continues to develop new technologies to explore for, develop, and produce the energy resources needed for growing global demand. Speakers at the 40th Offshore Technology Conference in Houston May 4-7 highlighted these technologies against a backdrop of worldwide economic uncertainty and changing governmental and environmental policies.

Despite oil prices hovering in the mid-$50/bbl range and a possible swine flu pandemic, attendance at OTC 2009 was expected at presstime last week to reach the 65,000 mark, which would be down slightly from a record high of 75,092 attendees reported last year.

Roundtable discussion

Three energy executives questioned US President Barack Obama’s energy policy in a roundtable discussion of access to oil and gas resources on the US Outer Continental Shelf at OTC May 5.

In prepared remarks, Gary P. Luquette, president of Chevron North America Exploration & Production Co., said, “There are people in positions of power that want the US to move off oil as quickly as possible, and they want us to pay for it through increased taxes and fees.”

Luquette noted Obama’s “aggressive agenda” that could drastically reduce the industry’s ability to explore, develop, and produce oil and natural gas in the US. He said, “This administration—and for that matter, a large sector of the population—think we must abandon traditional oil and gas development for the sake of the environment. This is simply not true.”

Larry Nichols, chairman and chief executive officer of Devon Energy Corp., derided the myth that environmentally friendly and renewable energy sources are imminent. He questioned Obama’s goal of having renewable energy resources provide 20% of US energy production by 2030. Even the Department of Energy’s estimate is for only 11%.

Tim Cejka, president of ExxonMobil Exploration Co., said in prepared remarks, “Oil and gas are indeed finite resources. And alternative energy sources, such as wind, nuclear power, and biofuels, play an important and growing role in meeting global energy needs. But although oil and gas resources are finite, they are far from finished.”

The US Geological Survey estimates more than 3 trillion bbl of conventional oil is ultimately recoverable worldwide. On top of that are huge unconventional resources such as heavy oil and shale oil yet to be developed. By comparison, an estimated 1 trillion bbl of crude has been produced to date in all of human history.

Based on surveys conducted by the US Minerals Management Service, the OCS holds an estimated 85 billion bbl of recoverable oil and 419 tcf of recoverable gas, with almost 18 billion bbl of oil and 76 tcf of gas in the areas previously or still off limits.

Environmentally responsible

Despite the expansion of offshore drilling since 1980, MMS has calculated less than one one-thousandth percent of oil produced in federal waters has been spilled. The energy executives acknowledged any harmful incident “can and will be used against us by those that want to see oil and gas operations cease.” Luquette said, “Let’s not give them anything to work with.”

The oil executives emphasized their industry repeatedly has proven over the last 25 years it has the technical capability and procedures to minimize adverse risks to the natural environment. “We can operate in an environmentally responsible manner and in a way that accommodates joint use of federal lands and waters for other activities,” Luquette said.

Cejka said, “To consumers of our products, the importance of innovation to the oil industry is often not readily apparent. Gasoline may not appear as technically sophisticated as many consumer electronic goods, for example. But…technology is the lifeblood of our industry. Technology infuses the entire supply chain, from the producing reservoirs to the service station. If you just walk around the exhibit floor here at OTC, you can see the incredible depth and breadth of the technology found in the oil and gas industry.”

Major and independent producers have long supported a sustained energy policy that combines conservation and development of alternative and renewable fuels along with expansion of traditional energy sources such as oil and gas.

Luquette defended the Deepwater Royalties Relief Act (DWRRA) that has been attacked as a mere subsidy to offshore oil and gas producers. He said, “Not only was DWRR a success, it was a home run that revitalized production from the Gulf of Mexico. It was passed at a time of historically low crude oil prices as a means to increase domestic production and sustain jobs in a struggling industry.” Because DWRRA provided near-term royalty relief for long-term production, more than 3,000 leases were issued in 1996-2000 in water depths exceeding 200 m. It helped increase deepwater gulf production by 50% in less than a decade.

Since Chevron is one of the largest leaseholders in the gulf, Luquette said, “We are troubled by the Department of Interior’s decision to delay the MMS 5-year plan process, which was designed to address the critical energy concerns facing our nation.” The decision, he said, ignores the fact more than two thirds of the US public have supported in polls the development of domestic resources. He said, “This delay means that development of US offshore resources could be stalled, depriving the nation of tens of thousands of new jobs, billions of dollars in revenues to federal, state, and local governments, and greater energy security.”

Environmental regulations

Separately, a Washington coalition of US oil and natural gas producers released May 6 the findings of a major research initiative that concludes new federal environmental regulations—especially related to hydraulic fracturing—could have disastrous economic consequences and increase US dependence on foreign sources of oil.

“Implementing new federal regulations that threaten domestic energy production and increase costs—without creating any additional environmental benefits—is the wrong policy course for the country, and could cost thousands of hard-working Americans their jobs,” said Lee Fuller, vice-president of government relations for the Independent Petroleum Association of America, one of the coalition organizers.

The coalition said that saddling producers with new, unnecessary, and ineffective environmental regulations could put them out of business, destroy jobs, and increase US dependence on foreign sources of energy. It added that this would be especially true if lawmakers in Congress move forward with plans to target hydraulic fracturing.

Industry’s public image

As the oil and gas industry struggles to manage its public image and progress is made getting legislation passed through Congress, various stakeholders can improve dialogue through expanded forums and televised debates, delegates said May 4 during an OTC panel discussion.

The panelists, who represented energy consumers, academia, oil companies, and government, debated the challenges facing the energy industry and its stakeholders.

Consumers, in particular, are underrepresented in the energy policy debate, some delegates said, and with consumers worried about energy prices and security, politicians are finding it difficult to build an overarching framework for a comprehensive, balanced national energy policy.

“The public is very busy,” said Jason Grumet, executive direction of the National Council on Energy Policy. “There is a limited bandwidth to engage the public, and the price of gasoline matters to them.” He called on industry participants to improve communications among themselves as well as with the public.

The industry is rapidly changing with the cost of carbon dioxide becoming a major factor, the electrification of transportation, the growth of the middle class in emerging economies, and the demise of coal. One panelist, US Senator Lisa Murkowski (R-Alas.), called for increased domestic production in the US, arguing that $1.7 trillion of revenues could be generated if operators could access areas that are currently off limits. “If we don’t produce oil, prices will go up and more jobs [will move] overseas. We need to share revenues with states that allow drilling. There is a scarcity of will to produce our own oil,” she said.

Panelists agreed that stakeholders have more in common that one would think, but that rhetoric continues to undermine these commonalities. “People are talking past each other and there is no constructive debate going on because there are misconceptions on both sides,” added Roger Ballentine, president of Green Strategies Inc.

Jack Gerard, president and chief executive officer of the American Petroleum Institute, said it was important to establish with the public the perceived role that industry would play in supplying future energy resources. He said consumers had failed to understand certain realities: For example, when polled, 67% of the public felt the nation’s energy problems could be solved through conservation and energy efficiency, but when consumers suffered $4/gal gasoline last year, their attitude changed. After the gasoline price spike, 67% of the public then called for development of the country’s resources on the OCS.

“We don’t want the government to pick winners and losers in the power and fuel debate,” said Bill Graves, president of American Trucking Associations. “We need to appreciate the complexity of the transition to different fuels.”

Although there is increasing public pressure to move to renewables to address climate change and sustainability, this alone will not fill the gap in meeting energy demand, delegates said. Different forms of energy are discussed within vacuums, which ignores their interconnectivity. Delegates agreed that expanding US oil and gas production, alternative energy, and nuclear power were the necessary steps over the next 8 years to increase energy supplies.

Grumet said, “We’re in the midst of a transition, and we all want to get there, but the challenge is that we don’t have a long-term goal articulated. Climate change [mitigation] is a step in the right direction, but people are not sure what energy independence means; what does the transition look like? We need to identify goals to have productive dialogue.”

Oil firms’ long-term strategies

Oil and gas companies are becoming more adept at maintaining long-term business strategy in the face of short-term uncertainty stemming from oil price cycles, OTC panelists said May 4.

During a general session entitled “Coping with price volatility: how will it affect major capital projects,” executives discussed cost-cutting measures that include lowering capital budgets and renegotiating contracts.

“We are getting better at going through these cycles,” said Luc Messier, ConocoPhillips senior vice-president. “We must keep our options open as far as assets and properties to develop. We’ve adjusted our operational expenses to…remain competitive.”

Messier said current oil prices remind him of 2004 levels, but he noted that operating costs have doubled since 2004. Consequently, ConocoPhillips reduced drilling in the US Lower 48 as well as Western Canada.

Matthias Bichsel, executive vice-president of Royal Dutch Shell PLC, said the company quietly renegotiated some contracts with suppliers.

A presentation by Petroleo Brasilerio SA (Petrobras) mentioned renegotiating 360 exploration and production contracts. Solange Guedes, Petrobras executive director, prepared the talk but did not attend OTC. Cesar Palagi, Walker Ridge production asset manager with Petrobras America Inc. of Houston, was a substitute speaker for Guedes.

Patrick Pouyanne, Total senior vice-president of business development, said Total’s solid balance sheet enables it to sustain a long-term investment strategy throughout price cycles.

“We want to avoid a stop-and-go policy,” Pouyanne said in reference to massive layoffs that the industry experienced during previous oil-price slumps. “The basics of markets are changing, but it does not affect long-term trends.”

Total is becoming increasingly more internally cost disciplined as it controls daily expenses, Pouyanne said. “We have to continue to believe that cost reduction will come from technology.”

Dominique de Soras of Technip’s subsea division was the only panelists representing an engineering firm. He briefly discussed the cost evolution of floating production, storage, and offloading vessels as well as subsea projects.

FPSO costs last year were twice as high as in 2003, largely because of “escalating raw material” costs, De Soras said. On subsea expenses, he attributed cost increases “very much on the installation side.”

Technip remains committed to quality and continues to invest in research and development, De Soras said. The company boosted its payroll 34% during 2005-08, largely to hire young engineers, he said.

Reforms in Nigeria

Nigeria’s operators are urging that the major industry reforms proposed under the country’s latest petroleum industry bill to be quickly implemented to ensure regulatory certainty.

Speaking May 5 at an OTC topical lunch, Adewale Tinbu, group chief executive of Nigerian oil company Oando PLC, told attendees: “The reforms are good. We want to see more companies like ours being involved in the process as the focus tends to be on the international oil companies and national oil companies.”

Nigeria announced plans in 2004 to break up its national oil company, Nigeria National Petroleum Corp. (NNPC), into smaller separate and autonomous units to end its conflicting roles of operator, regulator, and national assets management. With aspirations to have a similar model to Norway’s StatoilHydro or Brazil’s Petroleo Brasilerio SA (Petrobras), a new, integrated IOC, Nigerian National Petroleum Co. Ltd., will be created. Currently, NNPC has been unable to contribute its share of funding for joint venture projects as the government has not provided enough money.

Tinbu noted that NNPC should give assets to local oil companies under the reforms to help them develop. “We want community relations to be improved in the delta and as a hangover, I believe from colonialism, people look at [IOCs] as ‘pseudogovernments.’ There is a lack of local companies in the area, and we need to see wealth transfer in the area.”

Tinbu said Oando has struggled to secure gas from IOCs in Nigeria for local distribution despite spending $300 million to build domestic pipelines and called on them to allocate it as their contribution to the country.

Faithful Abiyesorhu, NNPC group executive director of engineering and technology, urged industry players to be patient with the restructuring. “We hope to get it right. It will come with pains and gains, but the pains will be transient.”

Mark Ward, lead country manager of ExxonMobil Corp. subsidiary companies in Nigeria, said that technology transfer and developing local people were important in its relationship with NNPC. “We spend $1 billion/year on [research and development] on technology,” he said. “We have done work on 3D seismic; directional, horizontal, and extended-reach drilling; subsea technology; and multizone simulation.” But during this downturn, it was critical to recognize that both parties had a long-term relationship, he said, adding, “National content must be realistic and achievable. We have workforce development, supplier development, and strategic community investment.”

Eyo Ekpo, special advisor on projects in the Cross Rivers state, said it was crucial that the reform process was handled efficiently. “The new agencies need boundaries, resources, and capital and we need to make sure that the reform is not slowed down during the transition process to keep away people who have vested interests.”

Emmanuel Egbogah, special advisor to the president on petroleum matters, told delegates that public hearings are scheduled for the petroleum industry bill in May. The National Assembly has passed the legislation in its first and second hearings.

“The reform also provides for the conversion of all the existing joint ventures into incorporation joint ventures (IJVs). Each IJV will be a corporate entity to be incorporated under the laws of Federal Republic of Nigeria,” Egbogah said. “The incorporation process including capitalization and restructuring will be carried out through negotiations with the respective IOCs during the reform transition period.”

Other highlights of the bill include creation of the following:

  • National Petroleum Directorate, a policy body that will initiate, formulate, and develop policy and be a secretariat for the petroleum minister.
  • National Petroleum Inspectorate, an autonomous technical regulator that will replace the Department of Petroleum Resources.
  • National Petroleum Assets Management Agency, to manage petroleum assets and commercial regulation of the industry to ensure Nigeria derives maximum value from its oil and gas resources. (Will replace NAPIMS).
  • Petroleum Products Regulatory Authority, to focus on the commercial downstream sector (Will replace PPPRA).
  • A research and development center, to focus on capacity-building.
  • Petroleum Training Institute.
  • Establishment of fund organizations, including Petroleum Equalization Fund and Petroleum Technology Development Fund.
  • Frontier Exploration Services, to regulate and stimulate exploration in frontier areas, including the Anambra, Benue Trough, Bida, Chad, Dahomey, and Sokoto basins.

MMS offshore forecast

MMS’s 2009-18 forecast, released May 4 at OTC, shows Gulf of Mexico oil production reaching an average 1.879 million b/d in 2013 compared with the hurricane-affected production of 1.142 million b/d in 2008.

After the 2013 peak, MMS sees oil production decreasing to an average of 1.735 million b/d in 2018.

MMS includes condensate production in its oil production numbers.

In regard to natural gas, the forecast shows production averaging 7.03 bcfd in 2009 compared with 6.43 bcfd in 2008. From a high in 2009, the forecast decreases gas production to 6.22 bcfd in 2012 before starting an increasing trend that results in gas production reaching 8.27 bcfd in 2018.

MMS’s forecast depends on the successful development of announced and undiscovered resources in the gulf.

The forecast shows a continued decrease in shallow-water oil production, reaching 82,000 b/d in 2018 compared with 313,000 b/d in 2008. Likewise, shallow-water gas production decreases to 900 MMcfd in 2018 compared with 3.84 bcfd in 2008.

In 2008, oil and gas operators announced 15 deepwater discoveries in the gulf and seven new projects started production in water deeper than 1,000 ft (see table).

MMS also notes that in 2008, 57% of all gulf leases were in water deeper than 1,000 ft and the gulf had 141 projects producing from deepwater. Additionally, 73% of the tracts receiving bids in the three lease sales held in 2008 were in deepwater areas of the gulf.

Pemex’s deepwater gulf plan

Carlos Morales Gil, Pemex Exploration & Production general director, said Pemex is formulating a plan to ramp up exploration in the deepwater gulf and involve international and national oil companies in the process.

Without discussing specifics, Morales Gil said deepwater participation contracts will be written by mid-2009 that will allow IOCs, NOCs, and service companies to engage in technological collaboration with Pemex and generate value for all involved. Reserves will still belong to Mexico, he noted.

Pemex will put projects out for bids in late summer and award contracts in late 2009 or early 2010, he estimated May 6 at an OTC breakfast.

Overall, Pemex has identified 1,703 exploration opportunities, and 93% of them are onshore or in shallow water, Morales Gil said.

Pemex has identified seismic amplitude anomalies in five deepwater areas. From north to south along the coastal bend, they are called the Subsalt belt, Perdido fold belt, Mexican Ridges, Gulf Salt Province, and off Veracruz the Catemaco fold belt.

South of large oil fields on the US side of Perdido, Pemex has “identified structures that might be transborder resources,” he said. And it plans to shoot wide azimuth seismic to obtain better images in the Catemaco nonassociated gas province.

Pemex has shot extensive 3D and 2D seismic and drilled eight wells in its gulf deepwater basins in 2000-08, discovering two nonassociated gas fields and two extra-heavy oil fields. One of the gas fields, Lakach, is Mexico’s fourth largest, he said.

Deepwater exploratory drilling is to expand northward from Cantarell, and five rigs are to be working by 2012.

Aramco aims for 70% recovery rate

Saudi Aramco wants to improve its oil recovery rate to 70% from 50% over the next 20 years by focusing on enhanced oil recovery (EOR) techniques and other new technologies, said Amin H. Nasser, Aramco senior vice-president, exploration and production.

Nasser told delegates May 4 at OTC that the company wants to expand its resources from 742 billion bbl to 900 billion bbl to address the world’s future energy needs. “In the most optimistic scenario, world oil demand is placed at 125 million b/d and this would require 15-40 million b/d of additional capacity and compensation for declining fields.”

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Increasing Aramco’s reserves will have many challenges, however, particularly developing technologies to enhance production and developing a skilled workforce, which Nasser said in light of the economic downturn was the biggest concern. “We don’t want to see huge layoffs as we did in the ‘80s and we only reacted to that in 2000. There is a big generation gap and it took almost 20 years to restore confidence. We are hiring at Saudi Aramco and putting high school people in universities around the world.”

Nasser said collaboration between service companies, academia, national oil companies, international oil companies, and technology providers was crucial in overcoming the technology hurdle to fully exploit oil resources. These have decreased significantly in size and are difficult to access due to remote locations and complex geology. Nasser estimated that the world has 4.7 trillion bbl of recoverable and potential recoverable bbl, or at least 150 years of production at present levels.

Currently, Saudi Arabia has a spare production capacity of 4 million b/d. Nasser said last year had been an unusual year with the peak of oil prices at $147/bbl. “We told journalists there was enough capacity if needed for buyers of crude.” It will focus on maintaining spare capacity of 1.5-2 million b/d, which is important in stabilizing the world market. “We’re ready for the future if demand picks up,” Nasser added.

He told OGJ that Saudi Arabia is in negotiations with its contractors to reduce prices as costs for materials and construction had dropped. “We think it will drop further, and this will allow us to do more work in the future. We have seen a slight drop of 10-15% in some service providers, but that doesn’t match the going rate in 2005.” He said he would like prices to fall a “lot more,” but declined to give OGJ a target.

“It depends on what kind of contract it is,” he said, adding, “We have excellent relationships with our contractors in Saudi Arabia—those where we haven’t started construction we are negotiating. Others we think the cost should go down to match the crude price these days.”

The company has been particularly successful in its water cut: For example, the Abqaiq Arab-D reservoir, which produces 300,000 b/d, has a water cut of 35%. Oil recovery from the field is expected to increase to 70% without EOR. Ghawar’s water cut is 28% and it produces 5 million b/d of oil, he said. “Horizontal wells and equalizers to reduce the pressure drawdown helped with the water cut,” Nasser said. “We previously had horizontal wells and people are now talking about SMART equalizers. It’s expensive up front, but good over the long term.”

Natural gas development is also a major issue in Saudi Arabia. The kingdom wants to boost gas processing capacity to 9 bscfd from 6.2 bscfd by 2015, which will meet local demand and serve the petrochemicals industry.

Saudi Arabia’s Khurais field

Meanwhile, the giant Khurais oil and gas field in Saudi Arabia is on schedule to start production by the end of June, according to Aramco’s Nasser. The $10 billion project will come on earlier than expected as it was originally slated for completion by yearend.

Khurais is about 90 miles east of Riyadh. The field will produce 1.2 million b/d and is the largest increment delivered in the world, Nasser said. “We have increased capacity by 20% by bringing on major increments onstream between 2004-09.” By yearend, Aramco will have 12 million b/d of production capacity after it has completed all of its major development projects. Khurais, in addition to the 1.2 million b/d, is expected to produce 420 MMcfd of natural gas and 70,000 b/d of condensate (OGJ, May 8, 2006, p. 19).

The project has been challenging because during the boom period when oil prices were soaring; there was a shortage of labor and materials. Now, however, the field will start production in a very different market with oil prices in the $50/bbl range and shrinking demand because of the global recession.

Saudi officials have said Khurais, with at least 12 billion bbl of recoverable oil, is only 1.8% depleted (OGJ, Apr. 5, 2004, p. 18). This is the country’s second-largest oil field and requires 310 wells to deliver the production. The drilling program was expected to take 3 years, but was finished 10 months ahead of schedule on Feb. 10 due to improvements in engineering and operations. It will typically use single horizontal lateral wells equipped with inflow control devices for water production management. Smart electrical submersible pumps also will be installed.

Aramco originally planned to use 16 rigs run by three divisions over 3 years, but this was changed to 12 rigs in two divisions over a 2-year schedule. Drilling days were cut from 40 days to 25 days because of strong communication between the company and its contractors and working alongside each other in the same office.

In November 2008, Aramco inaugurated its central processing facility water injection plant (WIP), which uses combustion gas turbines. This allows 620,000 b/d of seawater injection and more pressure.

The seawater journey starts at the new treatment modules at Qurayyah seawater plant and flows to Ain Dar WIP in a 56-in. quad pipeline. Booster pumps increase the pressure at Ain Dar WIP, forcing water to flow to Khurais in the 60-in. Ain Dar Khurais-1 pipeline. The Khurais project will use five WIP trains that will inject 2.1 million b/d of treated seawater into Khurais, Abu Jifan, and Mazalij fields to maintain reservoir pressure.

Discovered 65 miles west of supergiant Ghawar field in 1957, Khurais began production in 1970 and had yielded 111 million bbl by mid-1979, when output averaged 33,000 b/d. It was later shut in, and the project to restart it began in 2005.