Oil companies preparing for more carbon constraints

March 20, 2006
Oil and gas companies are working to address climate change concerns while developing strategies to extract value from the management of carbon dioxide emissions.

Oil and gas companies are working to address climate change concerns while developing strategies to extract value from the management of carbon dioxide emissions.

They are preparing for a world of increasing carbon constraints imposed in response to forecasts of rising emissions of greenhouse gases (GHG), such as a projection from the US government that world CO2 emissions will reach 38.8 billion tonnes/year in 2025 (Fig. 1).

Click here to enlarge image

One method for slowing the growth of the atmosphere’s CO2 concentration is to capture and bury emissions. Because of rising interest in so-called sequestration, scientists are monitoring existing CO2 storage sites while lawmakers consider what storage regulations may be needed.

Oil companies’ expertise with CO2 injection for enhanced oil recovery will make them attractive partners for power plants and heavy industries looking for ways to stash CO2 emissions.

Mutually beneficial relationships could develop, especially for oil companies facing regional bottlenecks to pipeline deliveries of CO2 for EOR projects.

Two markets are emerging: a commodity market for CO2 for use in EOR projects and a trading market for credits created by governments in programs to reduce GHG emissions

Government policies

Multinational oil companies operating in Europe must participate in the European Union’s Emissions Trading Scheme (ETS), launched last year. UK Prime Minister Tony Blair said he is working with other EU leaders to extend the ETS beyond its expiration date of 2012.

In Europe, the Kyoto Protocol has prompted European industrial companies to implement emissions-reduction projects.

Gardiner Hill, BP PLC manager of group environmental technology, said European power companies are examining carbon capture and storage technologies. “Forward-thinking” US utilities are doing the same in anticipation of future air quality restrictions, he said.

“Companies are starting to think about that,” Hill said. “Really, what is missing is the long-term view of how policy will shape out in the US. That makes it quite difficult for companies to plan investments at this time.”

Numerous states are crafting GHG emission regulations, either individually or as part of regional pacts.

US Senate Energy and Natural Resources Committee Chairman Pete V. Domenici (R-NM) and Sen. Jeff Bingaman (D-NM), are contemplating a national market-based GHG regulatory system.

They circulated a white paper in February saying the committee wants to move forward on GHG legislation that would maintain US competitiveness and economic prosperity.

“We recognize that there are many ways to structure such a regulatory program, and that there are entirely different approaches that might include a carbon tax, technology incentives, and voluntary programs,” Domenici and Bingaman said.

Michael E. Moore, director of markets for CO2-Global (US) LLC, a developer of CO2 technology, said, “A spider web of interlocking activities is influencing the future of CO2 management.”

The general expectation is crude prices will remain high, driving two parts of the evolving business involving CO2. Companies are looking at CO2 as a commodity and for GHG emission reduction credits, he said.

“Everybody believes the US will have to work with carbon issues more aggressively than we are today,” Moore said. “Companies are planning in the event that in 3-5 years carbon management will be something that they will have to do.”

Capture and storage

Oil companies have used CO2 floods for enhanced oil projects for decades. Various other industries have expressed interest in carbon capture and storage (CCS), but action depends on economics and policies.

“The issue is that there is no infrastructure between the CO2 sources and the places that can use it,” Moore said. “We haven’t gotten to the point where people are building capture technologies at the source point. The pipeline people are not laying the pipes. The EOR community is there, ready and waiting, but this just hasn’t quite jelled into action.”

Companies deal with CO2 emissions as a health, safety, and environment issue. If the CO2 stream is large enough, emitters can sell the gas as a commodity to EOR projects.

“You see all kinds of activity developing with nontraditional players,” Moore said. “For example, the visible stuff is how CO2 captured from an industrial plant can make its way to an EOR project. The not-so-visible piece is the companies acquiring existing rights-of-way for a future CO2 transport line.”

Various companies are contemplating how future US CO2 regulations could impact their daily operations.

So far, many power and oil companies are hesitant to openly discuss potential CO2 management strategy on Capitol Hill because climate change remains contentious in Washington, DC, said Moore.

New alliances

One capture technology involves producing from coke a gas that is predominately hydrogen and CO2, and extracting the CO2 for storage. Hill said this technology could provide “low-carbon” hydrogen to fuel cars and generate electricity.

BP PLC and Edison Mission Group are studying the feasibility of building a $1 billion hydrogen power plant next to BP’s 247,000 b/cd refinery in Carson, Calif. Petroleum coke produced at the refinery would be converted to hydrogen and CO2.

Petroleum coke would be put into a hot chamber with steam and a controlled amount of oxygen for gasification. Both the fuel and the water give up hydrogen atoms to form hydrogen gas and carbon monoxide, which is converted to CO2, giving off heat to sustain the reaction.

The CO2 would be separated and moved via pipeline to an oil field for EOR. BP is talking with Occidental Petroleum Corp. about which of Oxy’s fields would be best suited for CO2 flooding.

Oxy produces a net 120,000 b/d of oil equivalent from giant Elk Hills field in the San Joaquin Valley, the THUMS operation at Long Beach, and other fields in the Sacramento Valley (OGJ, Feb. 27, 2006, Newsletter).

“What we will do for the first time is integrate the whole value chain by taking fossil fuel, decarbonizing it to produce hydrogen, producing power with almost no CO2 emissions or very low CO2 emissions, taking that CO2 for EOR, and eventually storing it underground,” Hill said.

The Carson project is BP’s second proposed hydrogen power project. BP, Royal Dutch Shell PLC, ConocoPhillips, and Scottish & Southern Energy PLC are looking into the feasibility of a £330 million CCS scheme involving a 350 Mw power plant to be built near an existing power station in Peterhead, Scotland.

That project envisions converting natural gas to hydrogen and CO2, using oxygen and a steam reformer. The hydrogen would fuel the new power plant. CO2 would be exported to BP’s Miller oil field in the North Sea for EOR and storage.

Engineering and design costs for the Peterhead project are being estimated. A final decision is expected by yearend. Planners believe the energy plant could be operating by late 2009. BP plans to make a final investment decision on the California proposal by yearend 2008.

The BP-Edison-Oxy proposal is an example of climate change concerns prompting companies to form untraditional partnerships.

“That is the first, and there are more of these to come,” Moore said. “That BP announcement opened the door for some other utilities to start looking for similar partnerships,” which could involve petrochemical, cement, and fertilizer companies.

Companies able to move quickly will get the best returns for CO2 outputs, Moore said, adding that a finite volume of oil reserves are suited to CO2 floods.

Shell and Statoil ASA are studying the feasibility of building a gas-fired power plant and methanol production facility at Tjeldbergodden, Norway, providing CO2 to Draugen and Heidrun fields. Power from the plant also will be provided to the fields, holding CO2 and nitrogen oxide emissions from these installations to nearly zero.

Tor Fjaeran, Statoil senior vice-president of corporate health, safety, and education, said the proposed project could store 2-2.5 million tonnes/year of CO2.

“This is an integrated CO2 value chain with CO2 capture from the power plant, electrifying the platforms offshore, and using the CO2 for EOR purposes,” Fjaeran said. “This will, if we are successful, be in operation about 2010 or 2011.”

He noted that a final decision hinges upon the Norwegian government’s providing financial incentives.

“It can be through tax systems, it can be through direct financing, it can be through all kinds of elements,” Fjaeran said. “It’s also critical for us to get area industrial users of electricity involved,” through commitments to buy the power.

Sequestration

The practice of storing CO2 in depleted oil and gas reservoirs, saline aquifers, and coal beds is apt to be widespread within 20 years, said Peter Cook, chief executive of the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) of Canberra, Australia.

Click here to enlarge image

“CO2 has been injected into deep geological formations [800-1,000 m] since the late 1980s as part of storage projects,” Cook said. “For instance, 1 million tonnes/year is injected at Sleipner, Norway, and 2 million tonnes/year is injected at Weyburn, Canada.”

Sleipner field, 250 km off Norway, was the first CO2 commercial storage project. Statoil operates the North Sea natural gas field, which produces gas containing 9-10% CO2-well above the 2.5% limit for natural gas sales.

The gas platform separates CO2 and reinjects it into the Utsira reservoir 3,800 ft below the seabed. Sleipner has stored 1 million tonnes/year since 1996 and expects to do that for many years to come, Fjaeran said.

Statoil’s Snøhvit gas field in the Norwegian Barents Sea has a high CO2 content. The proposed development includes piping the field gas to an onshore facility where CO2 will be separated before transport via pipeline offshore for injection into a sand aquifer under the gas field. The methane will be converted to LNG at the onshore facilities. Snøhvit is expected on stream in 2006.

Another field that stores CO2 is central Algeria’s In Salah field, operated by BP with Statoil as a partner.

The complex is expected to produce about 10 billion cu m/year of gas. The fields are linked by pipeline to Hassi R’Mel, and the gas is marketed to southern Europe (OGJ, July 12, 2004, Newsletter).

About 10% of the gas is CO2. Although the accepted practice on other projects of this type is to vent the CO2, the In Salah facility compresses the CO2 and injects it, in wells 1,800 m deep, into a lower level of the gas reservoir filled with water. Hill said 1 million tonnes/year is injected, which BP calls the equivalent of taking 200,000 cars off the road.

A third proposal for Statoil is Gorgan gas field off Western Australia, operated by Chevron Corp. The plan is to pipe gas with CO2 content above 12% to LNG production facilities on Barrow Island and reinject the CO2 into a deep aquifer. Gorgon is to come on stream in 2009.

UK North Sea oil and gas fields also are storage candidates. Last year, 11 companies founded the Carbon Capture and Storage Association. BP’s Hill was named CCSA’s chairman. Founding members include BP, ConocoPhillips, Shell, Schlumberger Oilfield UK, and some power companies.

Total storage capacity in the UK North Sea alone is estimated at over 15 billion tonnes, CCSA said. UK Sec. of State for Environment and Rural Affairs Margaret Beckett promised government consideration of economic incentives for CCS projects.

“For industry to respond to the challenge of large-scale delivery of this technology, there must be technical and commercial collaboration between businesses and an ongoing dialogue with government at the national and international level,” Beckett said.

In Australia, CO2CRC plans a sequestration trial in the onshore Otway basin of western Victoria (OGJ, Mar. 13, 2006, Newsletter). Subject to Australian regulatory approvals, the pilot gas injection, storage, and monitoring program is expected to begin by yearend.

Researchers hold 100% interest in leases covering Buttress CO2 field and depleted Naylor gas field. They will own both the CO2 source and the storage reservoir.

The pilot project is expected to produce 3 MMcfd of CO2 from Buttress, pipe the gas 1.75 km to Naylor, and inject it into the Cretaceous Waarre reservoir via a well to be drilled this year. The injections are expected to last for 2 years.

In Germany, Shell is working in association with the Geo-Research Center and other partners on a CO2 sequestration field near Berlin to provide details about CO2 subsurface movement. The CO2 in this project will be generated from combustion of biomass.

Migration concerns

An area of major concern for CCS is storage integrity-the ability of reservoirs to keep injected CO2 from migrating. Researchers are developing monitoring and mapping techniques to track CO2 injected deep underground.

Amine contactor towers in the BP PLC-operated In Salah gas processing complex in the Algerian desert separate CO2 from natural gas. The CO2 is compressed and sequestered underground. Photo from BP.
Click here to enlarge image

“Much remains to be done to quantify the volumes that can be stored in various locations, and to satisfy ourselves the gas will stay where it is put,” Cook said. The CO2CRC pilot will involve elaborate CO2 monitoring.

Regarding Sleipner, environmental activists question how long CO2 will stay in the reservoir. An international consortium of geological experts is studying the project’s storage effectiveness.

Statoil’s Fjaeran said, “We are continuously monitoring the surface, shooting seismic surveys, and using pressure monitoring.”

All major oil companies are involved in the Carbon Capture Project (CCP), an organization founded in 2000 that examines technologies to lower the cost of capturing CO2 from the combustion of fossil fuels. CCP also studies processes to store CO2 safely and permanently.

BP’s Hill said CCP has strong support from the US Department of Energy, as well as the UK and Norwegian governments.

Robert H. Socolow, a Princeton University professor of mechanical and aerospace engineering, said permitting uncertainties are an important issue for sequestration proposals.

He is one of two principal investigators with Princeton’s Carbon Mitigation Initiative, supported by BP and Ford Motor Co. The initiative focuses on global carbon management, the hydrogen economy, and fossil-carbon sequestration.

“One decision that lies ahead is how long will CO2 storage have to be assured for credit to be given for the effort,” Socolow said. “In a CO2 cap and trade system, once carbon capture and storage is included in the trading, there will need to be a procedure that results in storage being accepted as an alternative to using an emissions credit.”

Sequestration site candidates are depleted oil and gas fields and brine formations. Planners say storage sites need to be at least 800 m deep, well below drinking-water sources. The ambient pressure at that depth is 80 times the atmosphere and high enough that pressurized, injected CO2 is nearly as dense as the brine it replaces. CO2 is buoyant in brine and rises until it hits caprock.

Socolow noted two types of risk exist for every candidate storage site: gradual and sudden leakage. Gradual CO2 leaks return some gas to the air. Although gradual leaks pose little danger to life, any seepage threatens sequestration goals.

“Regulators of storage permits will want assurance that leaks cannot migrate to below-ground confined spaces that are vulnerable to sudden release,” Socolow said.

For instance, a sudden CO2 leak in 1986 asphyxiated 1,700 people at Lake Nyos, Cameroon. The lake sits in a volcanic crater, and CO2 of volcanic origin collected on the lake bottom. Unexpectedly one night, massive volumes of CO2, which is heavier than air, left the lake within a few hours and flowed through valleys into villages.

The possibility of CO2 leaks through old wellbore cement has the attention of service company researchers. Veronique Barlet-Gouedard, Schlumberger Ltd. project manager, said well integrity technology must ensure that CO2 remains sequestered “for several hundred years and beyond.”

Schlumberger tests indicated exposure to CO2 can cause Portland-based cement to lose more than 65% of its strength after 6 weeks. Although efficient for production wells, the cement becomes thermodynamically unstable and loses long-term durability when exposed to CO2, Barlet-Gouedard said in a paper presented during a February drilling conference in Miami hosted by the International Association of Drilling Contractors and the Society of Petroleum Engineers.

Weyburn storage

EnCana Corp.’s Weyburn oil field in Saskatchewan is being studied for long-term CO2 storage. It is the largest CO2 EOR project in Canada and the world’s largest geological sequestration project.

Weyburn is the site of the International Energy Agency’s Greenhouse Gas Research and Development Program. Results from the first of two phases of the research project concluded long-term CO2 storage in an oil reservoir is viable and safe.

Scientists are working with EnCana and its partners to develop measurement, monitoring, and risk assessment techniques. Discovered in 1954, the field has been on waterflood since 1964. Oil is produced from two zones in the Mississippian Charles formation.

Waterflooding recovered most of the oil from the Vuggy zone. In 2000, EnCana began injecting CO2 to boost oil recovery from the less permeable Marly zone. The zones are 1,400 m deep.

Current production is 30,000 b/d, compared with 10,000 b/d if the CO2 flood had not proceeded. Total incremental oil recovery is estimated at 155 million bbl for a recovery factor of 40%. Cumulative production of 389 million bbl as of late 2005 reflected a 28% recovery factor.

Weyburn originally contained an estimated 1.4 billion bbl of 25º-34º gravity crude in place. As of Mar. 10, the field had 646 producing wells and 289 injection wells. During the fourth quarter of 2005, production reached a 30-year high of more than 30,000 b/d.

Currently, EnCana injects 2 million tonnes/year of CO2. Total injected CO2 is expected to reach 30 million tonnes, the equivalent of taking 6.7 million cars off the road for 1 year.

“Researchers independent of EnCana have found that 99.8% of the injected CO2 will stay in place for at least 5,000 years,” said Marty Hewitt, Encana lead for long-term development.

IEA’s research project is in its final phase. Cosponsors include Natural Resources Canada, the US Department of Energy, Apache Corp., Chevron, Saskatchewan Industry and Resources, and the Alberta Energy Research Institute.

“The final phase is geared toward practical protocols for guiding CO2 sequestration projects,” Hewitt said. “It can be a guide that can be applied not only to Weyburn but to other projects around the world.”

Hewitt calls CO2 storage “a pragmatic technology that helps address CO2 emissions.”

Potential EOR gains

US oil recovery efficiency could be boosted by “state-of-the-art” and “next generation” CO2-EOR technologies, said Vello A. Kuuskraa, president of Advanced Resources International (ARI), which conducted a study of EOR potential for the US Department of Energy.

ARI estimated the 10 basins and areas studied hold a technically recoverable resource of 88.7 billion bbl of oil, based on state-of-the-art CO2-EOR techniques.

Kuuskraa noted that recovering all of the estimated 88.7 billion bbl would require nearly 400 tcf of purchased CO2, of which 80% would remain in the reservoir if abandoned at operating pressure.

“Game-change levels of improvement in oil recovery efficiency are theoretically and scientifically possible,” Kuuskraa said. “Next generation CO2-EOR technologies, plus innovative CO2 flood designs, such as gravity-stable flooding, would greatly expand the CO2 storage capacities of oil reservoirs, should this be an objective.”

Kuuskraa’s assessment for the DOE study included Alaska, California, the Gulf of Mexico coast, Midcontinent, North Central region, Permian basin, Rockies, eastern and central Texas, Williston basin, and the shelf off Louisiana.

“Significant new investments are required in research and technology development...to realize the higher oil recovery efficiencies set forth,” he noted.

Primary and secondary oil recovery produces about a third of the original oil in place (OOIP). Traditionally applied CO2-EOR practices, using small volumes of CO2 injection and limited conformance control, generally have added 5-10% to the recovery rate.

State-of-the-art CO2-EOR technology, now being used in a handful of new or modified field projects, offers the potential boost recovery by a further 15% of OOIP, nearly double the oil recovery efficiencies achieved with past practices, raising overall oil recovery efficiency to 48% in reservoirs favorable to miscible CO2-EOR, he said.

Successful application of next generation CO2-EOR technology could push recovery efficiency over 60% overall and up to 80% in highly favorable reservoirs.

In the Shell-Statoil CO2-EOR project for Draugen field, Shell has said it hopes to increase oil recovery to 85%.

Kuuskraa listed potential CO2-EOR recovery practices as including:

Adopting innovative flood and well designs. This would enable CO2-EOR to contact higher residual oil-saturated (less efficiently waterflood-swept) parts of the reservoir, often containing the bulk of “stranded” oil.

Injecting higher volumes of CO2. The report suggests using up to 150% hydrocarbon pore volume (HCPV) of CO2, which is considerably beyond what has been traditionally used.

Improving the viscosity of the injected water and CO2. This would help improve the mobility ratio between the injected CO2 and water and the reservoir’s oil to reduce viscous fingering of the CO2 through the mobilized oil bank.

Adding miscibility enhancers to extend miscible CO2-EOR. This would enable additional oil reservoirs to qualify for miscible CO2-EOR that otherwise would not qualify or would be produced by less efficient immiscible CO2-EOR.

Measuring emissions

Companies trying to track emissions reductions need ways to accurately measure the emissions, but this is a complicated process that varies greatly from industry to industry.

API, the International Petroleum Industry Environmental Conservation Association, and the International Association of Oil & Gas Producers created petroleum industry guidelines for reporting GHG emissions.

Russell Jones, API research manager and climate change team leader, said API plans to report aggregate GHG emissions for sector-specific segments of the industry. The organization soon will start collecting and compiling data. Jones said results will not be published for 2 years because any new survey takes time to generate reliable data.

“The challenge in defining emissions is a lot different in refining than in exploration and production,” Jones said. “Our current expectation is that we will have a different measure for each segment, and we will try to track each segment. But that is a hypothesis.”

API’s Compendium of Greenhouse Gas Emissions for the Oil and Gas Industry provides companies with methods for estimating CO2 and other GHG emissions.

In addition, API works with the World Resources Institute and the Intergovernmental Panel on Climate Change on developing emissions reporting methods for use worldwide.

Under the Clean Air Act, US power plants already report CO2 emissions. Currently there is no mandatory reporting requirement for CO2 emissions for the oil and gas industry.

“When you look at a petroleum company, there are literally thousands of possible (emissions) sources at every particular refinery. Each wellhead is a potential source,” Jones said. “It’s just a different complexity for our industry than for a lot of others.”

The API Climate Action Challenge focuses on voluntary GHG reductions. API member refiners have committed to improving their energy efficiency by 10% during 2002-12.

“To the extent that you can improve the efficiency of your operations, you are going to be using less energy, and then you are going to have less CO2 emissions,” Jones said.

In addition to contributing to API’s efforts, US-based majors are investing heavily in independent research toward lowering emissions worldwide.

ExxonMobil Corp. agreed to provide up to $100 million to Stanford University’s Global Climate and Energy Project, in which researchers work to accelerate development of energy technologies that can help lower GHG emissions.

While the industry is working on all fronts to manage CO2, some executives wonder if it’s worth the effort. Denbury Resources Inc. Chief Executive Officer Gareth Roberts is among them.

“As a geologist, I’m not very big on the whole idea of global warming,” Roberts said. “I think it is political. Sequestering CO2 is just too small and too late to make any difference. In the next 100 years, fossil fuels will be running out. It’s only a matter of time before emissions of CO2 get reduced anyway.”