Progress in IOR technology, economics deemed critical to staving off world's oil production peak

Aug. 4, 2003
Progress in improving oil recovery rates is critical to helping stave off the day when global oil production enters into permanent decline.

Fourth in a series of six special reports on Future Energy Supply

Progress in improving oil recovery rates is critical to helping stave off the day when global oil production enters into permanent decline.

Improved oil recovery (IOR) encompasses enhanced oil recovery techniques as well as other methods to expand the volume of recoverable oil from a reservoir. But in a larger sense, improving oil recovery can entail the application of horizontal drilling techniques, the implementation of smart wells, hydraulic fracturing, advanced reservoir characterization, and a myriad of other methods to help boost the flow and recovery of liquid hydrocarbons. In an even broader view, IOR can include the many, often mundane-seeming, efficiencies introduced in daily operations that improve the economics of oil recovery.

New technology has spawned a bounty of incremental oil and gas supply, doubling the volumes of hydrocarbons developed per well in the US since 1985, according to the US Department of Energy's Office of Fossil Energy. OFE estimates that US reserve additions achieved in the late 1990s have been acccomplished with 22,000 fewer wells than would have been required under 1985-era technology.

The potential resource target for IOR is huge. That's why IOR has become a key issue in the debate over a postulated imminent peak in global oil production. Detractors of the so-called Hubbert's peak theory in world oil output often point to its theorists' overlooking the phenomenon of reserves growth contributing to what the former see as a long-term plateau in oil production (OGJ, July 14, 2003, p. 18). In fact, over the long term, reserves growth—in the sense of expanding the volume of reserves in existing fields beyond the estimate given at discovery—has made a bigger contribution to replacing production in the US than have new discoveries.

And improvements in IOR have come hand in hand with improvements in industry's efforts to preserve the environment. In fact, one of the fastest-growing EOR techniques, carbon dioxide flooding, also could yield substantial benefits in addressing concerns over purported global warming by marrying it to an ambitious CO2 sequestration program.

Sustained higher oil prices are spurring the oil and gas industry to focus more on pressing the envelope on IOR and related technologies. This push is being furthered by industry consolidation and—especially in the US—a lack of access to new prospects. Also, as more companies merge and as more asset portfolios are optimized, thus causing those assets to change hands, it becomes increasingly important for companies to spare no effort to bolster recovery of oil from newly acquired or high-graded assets. And those assets take on even greater importance as the list of attractive, economic new exploration prospects shrinks worldwide.

But further technological progress is just as important to IOR advances as is the outlook for oil prices. And the two reinforce each other. Higher oil prices underpin an acceleration of IOR efforts. And the "knowledge creep" that comes with that acceleration, in turn, improves the economics of oil recovery to a lower threshold than once thought sustainable.

So as companies shift their emphasis increasingly to bolstering their stock values over the long term vs. a prior emphasis on growth through big additions to reserves, some will seek to obtain greater value from their existing assets vs. the risk of disproportionately emphasizing exploration. If in the interim oil prices also remain attractive, that can only bode well for IOR's future.

However, the oil industry's continued progress in advancing IOR efforts is hampered by its severely lagging efforts at research and development. IOR R&D outlays by government and by industry have shrunk in the past decade or so.

Industry experts canvassed by OGJ see a need for a sustained strong effort by operating and service companies, government, and academia working together to boost IOR R&D efforts.

Progress in IOR will be buttressed by advances in digital technology, such as remote sensing, visualization, intelligent drilling and completions, automation, and data integration. According to a recent study by Cambridge Energy Research Associates, Cambridge, Mass., expanding the use of new-generation digital technologies could potentially increase world oil reserves by 125 billion bbl in the next 5-10 years.

Consider the size of ultimate recoverable resources of oil in the world—whether one accepts the Hubbert's peak defenders' estimates or much larger ones, such as the US Geological Survey's. Consider also the relatively low level of current recovery rates and its potential for appreciation. Then it becomes apparent how big the potential contribution IOR offers for future global oil production.

Definitions

While this report focuses on the broader sense of improving oil recovery, it is nonetheless important to clarify what is meant, in a more technical sense, by the terms IOR and EOR.

A workable definition is needed to help clarify terms for estimating a company's or country's reserves as well as for avoiding confusion and conflict in determining contract details and government fiscal and regulatory parameters.

In a paper scheduled to be presented at the Society of Petroleum Engineers' International Improved Oil Recovery Conference in Kuala Lumpur Oct. 20-21, petroleum consultants George Stosur, J. Roger Hite, Norman F. Carnahan, and Karl Miller recommended a formal effort to better define such terms.

The SPE authors noted that, historically, EOR denoted tertiary oil recovery processes such chemical, thermal, and gas miscible processes, among others.

"The IOR term followed, but without definition, and was frequently used interchangeably with EOR," they wrote.

Stosur et al. argued that all secondary and tertiary oil recovery methods depend on the introduction of added recovery or displacement energy to the reservoir, usually through liquid or gas injection.

Efforts such as reservoir characterization are independent of the recovery process itself and should not be considered in assessing EOR and IOR results, the SPE authors contend.

"EOR is tantamount to tertiary recovery processes, and IOR comprises all but primary recovery technologies," they wrote.

IOR can include EOR and secondary recovery such as waterflooding and gas pressure maintenance, as well as efforts to increase reservoir sweep, such as infill drilling, horizontal wells, and polymers for mobility control or improved conformance, the SPE authors recommended. But they proposed excluding reservoir characterization or simulation as "supporting activities" that, while essential in everyday practice, are not part of IOR.

Stosur et al. called for an industry-wide effort to resolve uncertainties in the definitions.

Reserves growth

Even the broad appellation of "reserves growth" has come under fire as an inadequate description of how estimates of recoverable volumes from reservoirs and fields can increase substantially over time. The growth usually is attributed to the extension of proved reservoir areas, in-field discovery of new reservoirs, and other factors, such as better mapping of the subsurface.

In an article written for the US Energy Information Administration's Natural Gas Monthly in July 1997, EIA's David F. Morehouse notes that it is this phenomenon, rather than the discovery of new fields, "that accounts for the majority of both current (US)-sourced oil and gas supplies and current additions to domestic proved oil and gas reserves."

Morehouse opts for the term "ultimate recovery appreciation (URA)" vs. what he dubs the "colloquial label" of "reserves growth."

"Knowledge of how the domestic 'inventory' of oil and gas is likely to change over time is a critical input to future energy-related decisions that will be mde by individuals, industries, and government policymakers," he wrote. "For that reason, the US Geological Survey considers analysis of URA 'arguably the most significant research problem in the field of hydrocarbon resources assessment.'"

He distinguishes URA from "estimated ultimate recovery (EUR)," which he defines as "the sum of the estimate of proved reserves at a specific time and cumulative production up to that time." URA he defines as "the generally observed increase of EUR over time."

These are critical distinctions in the peak-oil debate. Hubbert's peak defenders generally use a static number for EUR, and their critics contend that this practice misses the URA phenomenon. And deciding which approach is best helps one gauge whether global oil production will peak and then decline precipitously in the near term or reach a plateau that could be sustained for decades.

Morehouse points out that the record shows growth in URA over time for most reservoirs, the vast majority of fields, and the entire world overall.

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"EIA's proved reserves data indicate that URA is still occurring at low rates in some (US) fields that were found more than a century ago," he wrote. "Most significantly, from 1977 through 1995, approximately 89% of the additions to US proved reserves of crude oil and 74% of the additions to proved reserves of dry natural gas were due to URA rather than to the discovery of new oil or gas fields" (Fig. 1).

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Fig. 2 further illustrates this fact, representing additions to proved US crude oil reserves as a ratio of new-field discoveries to URA. Except for the 1970 booked discovery of Prudhoe Bay oil field, in no other year does the ratio exceed 0.21 for oil.

"Looked at another way, 93% of crude oil reserves additions and 86% of natural gas reserves additionsUwere due to URA rather than to the discovery of new fields, excluding Prudhoe Bay," Morehouse wrote.

Morehouse also noted, in a comparison of the 1977 and 1993 EURs of the 200 largest US oil fields, that while EUR had decreased for 23% of the fields by 1993, it had increased for the other 77%, "and many times over for 32% of them.

"These data also reflect and confirm the essential conservatism of both the definition of proved reserves and the manner in which it is applied in the United States."

Thomas Ahlbrandt, world energy project chief with the Us Geological Survey in Denver, has put reserve growth estimates "commonly" at multiples of four to nine. He reckons that the potential additions to reserves from reserves growth to be nearly as large as estimated undiscovered resource volumes.

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One concrete example of this phenomenon was the increase in US proved crude oil reserves in 1997—the first time that had occurred in a decade (Fig. 3). EIA attributed that to "surprisingly large revisions in some of California's old, heavy oil fields," which accounted for half the increase. EIA estimated that its Indicated Additional Reserves category rose to 3.207 billion bbl that year, owing mainly to IOR efforts on Alaska's North Slope and in California, Texas, and Louisiana.

That phenomenon "implies that significant upward revisions to crude oil proved reserves may continue in the future," EIA said. "However, in a low-price environmentU, large reserve additions from upward revisions in old fields will be difficult to obtain."

EOR production

Low oil prices similarly affect production from EOR.

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Even with the volatility in oil prices that produced severe collapses in the mid-1980s and late 1990s, production from EOR has remained a noteworthy contributor to US and world oil output.

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According to OGJ's 2000 biennial EOR survey, EOR contributed 748,000 b/d, or about 12%, to US oil production that year (OGJ, Mar. 20, 2000, p. 39). Excluding cold production in Venezuela's Orinoco oil belt and Canadian oil sands mining, EOR production outside the US totaled 1.25 million b/d in 2000. There was a decline in California steamflood production represented in OGJ's 2002 EOR survey (OGJ, Apr. 14, 2002, p. 43)—ostensibly reflecting the impact of low oil prices in 1998-99—that pulled the US total down to less than 700,000 b/d (Fig. 4). A substantial number of the active US EOR projects that disappeared between the two surveys resulted from operators consolidating and eliminating some projects (Fig. 5).

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As early as 1977, EOR's large potential for contributing to US reserves and production was apparent. A study by the US Office of Technology Assessment that year estimated that EOR techniques, at what was then a world oil price of $13.75/bbl in 1976 dollars, could add 11-29 billion bbl to US reserves (Table 1). The OTA study projected that incremental production from US EOR could be 500,000-1 million b/d by 1985 and 700,000-1.7 million b/d in 1990. However, at a price of $22/bbl (1976 dollars), the potential OTA foresaw jumped to reserves of 25-42 billion bbl and production of 900,000-1.3 million b/d in 1985 and 1.8-2.8 million b/d in 1990. Noting that responsiveness of EOR to increases in real oil prices drops off beyond $22/bbl (1976 dollars), OTA capped the ultimate recoverable resource from EOR in the US at 51 billion bbl.

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The resilience of higher-cost EOR is remarkable in light of the enormous potential target resource for URA growth via all IOR methods. In the US alone, the Department of Energy's Office of Fossil Energy (OFE) in 1998 pegged that target resource at 351 billion bbl, more than five times the resource target for exploration (Fig. 6).

According to OFE, more than two thirds of the US conventional and unconventional oil endowment of 603 billion bbl remains untapped. Given the disparity in resource targets for IOR vs. exploration, that would argue for industry emphasizing more investment in improving recovery rates.

Recovery potential

What is the upper limit on oil recovery rates? According to several sources, the global average is 35%. But that reflects still-low recovery rates in many of the world's producing areas that are much less mature than the US's.

Some of the peak-oil theory defenders don't place great stock in IOR yielding sizable enough increases in recovery rates to alter their imminent-peak outlook.

Citing Iran's example, A.M. Samsam Bakhtiari, senior expert with National Iranian Oil Co., noted that primary recovery in Iranian oil fields is 10-35%, "depending on the field's natural conditions and complexities.

"Naturally, secondary and tertiary recoveries could enhance these percentages, but (this) depends on EOR projects being physically implemented," he told OGJ. "Finally, technology improvements could also pull their weight, but every single percentage point (in recovery rate) will be very difficult to come by.

"Hence, seasoned Iranian experts seriously doubt anything near 50% could be achievable on most fields, even with all the technological paraphernalia made available, added to secondary and tertiary recoveries."

Another prominent peak-oil theorist, who declined to be identified, put average recovery rates worldwide at 30%, which "varies from field to field and represents the best possible assessment, given the geological and technical conditions."

Such conditions pertain to Saudi Arabia's famed supergiant Ghawar, the world's largest oil field, he noted, which is claimed to have an ultimate recovery factor of 60%, thanks to horizontal drilling and EOR.

Olivier Appert, chairman and CEO of the Institut Français du Petròle, pegs the average world recovery rate at 35%.

"Increasing oil recovery represents a key target both for industry and governments in the framework of sustainable development," he told OGJ. "For example, Norway has set up a target of 50%."

Appert estimates that each increase of 1% in the oil recovery rate worldwide also increases oil reserves by 2 years of current consumption.

"In the short term, the oil recovery rate is more a function of economics. But in the longer term, technology is playing a major role," he said.

"The recovery factor is clearly dependent on reservoir characteristics and fluid properties; it is in the range of less than 10% to more than 70%, depending on the field. Improvements in the recovery factor is a key issue for heavy oils and nonconventional oils, where it is usually rather low."

US Deputy Asst. Sec. for Fossil Energy James A. Slutz, while reluctant to estimate a number for oil recovery limits, did note that "the US will have 377 billion bbl of oil remaining after economic production ceases. Ten percent of that oil is a conservative goal that would more than double our current 23 billion bbl of reserves."

For Robert W. Watson, associate professor of petroleum and natural gas engineering and geoenvironmental engineering at Penn State University, it isn't just a question of whether technology or economics is the driving factor in determining the upper limit of recovery, but both.

"Recovery can almost always be improved by utilizing not only new technologies but by increasing the well density," he told OGJ.

"The controlling factor for the implementation of new technologies is potential return on capital," he said. "In terms of lifting cost, the balance is between labor and automation and climate. The willingness to operate marginal wells again is a function of economics: If I pump my well once per month and can make money at $20/bbl, I might be willing to pump my well twice per month at $25/bbl."

In any event, Watson puts the upper limit for any oil recovery at near 80% of OOIP, leaving the field wide open for estimates of how much incremental reserves IOR could add to the world's total proven reserves.

IOR economics vs. technology

Slutz noted that the rate of incremental production from IOR "is more a function of economics than technology, although the two are tied together closely.

"Economics has proven effective for short-term increases in production. However, at present, we have technology that is not fully utilized. Technology shows the greatest promise in finding economic methods to increase the total domestic reserve base and is the key to unlocking new resources in mature oil provinces."

Slutz contends that oil price instability plays the biggest role in production by independents and in their ability to utilize the latest technology.

"I do not think lifting costs will have to go much lower; rather, the crude oil price will have to stabilize near where it is today. Today's prices are probably sufficient to attain near full utilization of technology; however, price uncertainty is as much of a key to production as price itself. As independents feel comfortable with price stability, they will spend money on technology to produce more of the oil."

Slutz cited DOE's own work with independents to reduce the up-front risk of using new technology through technology-transfer efforts.

"Technology transfer and 'best practices' demonstrations impact domestic production by providing the large number of independents in the US with the information they need to keep wells producing as long as possible. DOE's Stripper Well and PUMP (Preferred Upstream Management Practices) programs are focused on this technology-transfer aspect and have been very successful in combination with efforts from the Petroleum Technology Transfer Council, which DOE also funds."

Favored technologies

Experts canvassed by OGJ cited some of the IOR technologies and methods that show the greatest promise for bolstering production and ultimate recovery.

"Infill drilling utilizing technology to hit the 'sweet spots' offers great promise in existing fields for accessing bypassed resources; however, access and development cost will have to be reduced," Slutz told OGJ. "Heat management is the key to reservoirs containing heavier oil. For example, development of seismic technologies (3D and vertical seismic profiling) will allow the exact placement of the faults and boundaries for accurate reservoir modeling, proper heat application for drive energy, and thus increased recovery rates. Expanded use of VSP to improve definition of deep gas targets will be essential to unlocking effective approaches to deep gas exploration.

"All these technologies have the common theme of better reservoir definition for exploration and development; however, data acquisition costs will have to be reduced. If this occurs, new reserves will be developed, and sustained oil recovery rates will be possible.

IFP's Appert contends that IOR technologies "should be adapted on a case-by-case basis, depending on the characteristics of the field and the fluids."

He noted several IOR focus areas that are gaining increasing attention.

"Simultaneous water and gas injection is developing rapidly. For heavy oils and nonconventional oils, thermal technologies such as SAG-D (steam assisted gravity drainage), or vapor extraction, where hydrocarbons are replacing steam," are seeing growing use.

"There is also a renewed interest for polymer flooding in the case of smart wells and completions."

Penn State's Watson contend that "the implementation of horizontal well drilling is probably the most promising technology, given its impact on the depletion of the reservoir; moreover, multiple wellbores can be drilled using the same upper well bore.

"Other technologies that can help include the use of membrane-generated gas for the repressuring of the reservoir."

Horizontal wells

Perhaps no technology has made a bigger impact on the IOR scene in recent years than horizontal drilling. Although the basic technology has been around for decades, new efficiencies and improved economics have led to an explosion in activity.

In the US alone, 600-1,000 horizontal wells/year were drilled during 1990-2000, rocketing from a handful in the 1980s, according to an SPE paper by Khosrow Biglarbigi and Hitesh Mohan of Intek Inc., DOE's Robert M. Ray, and D. Nathan Meehan of Union Pacific Resources Inc. (now part of Anadarko Petroleum Corp.) presented at the SPE/DOE Improved Oil Recovery Symposium in Tulsa in April 2000.

The SPE authors concluded that 541-965 million bbl of additional oil reserves are economically producible through the implementation of horizontal well technology in the Lower 48 at oil prices of $16-24/bbl. These estimates pertain to future horizontal wells in known fields only. The resulting incremental production could be 50-85 million bbl/year by 2004, Biglarbigi et al. projected, declining 8%/year thereafter.

Given that more than 20,000 horizontal wells have been drilled worldwide and that the vast majority of those wells have been drilled in the US, the incremental reserves and production potential from expanded worldwide use of horizontal well technology alone could represent a significant new supply.

More than 2,700 horizontal wells/year are being drilled, according to OFE, and horizontal drilling now accounts for 5-8% of the land well count at any given time.

A 1995 DOE study found that horizontal drilling could increase potential US reserves by 10 billion bbl, nearly 2% of US OOIP.

The increasingly favorable attitude toward horizontal well technology is evinced by its economics. Production from carbonate reservoirs (which account for 30% of US oil reserves and 90% of all horizontal drilling in the US) is nearly 400% greater in horizontal projects than with vertical wells, yet costs are only 80% greater, OFE noted. And average production is 3.2:1 for horizontal wells vs. vertical wells, offsetting a higher average cost ratio of 2:1; the average increase in reserves with use of horizontal wells vs. vertical wells is 9%.

And advances beyond conventional horizontal well technology have accelerated apace. Now industry is drilling multilateral wells that effectively create a network of interconnected wellbores that are making economic reservoirs that have small or isolated accumulations in multiple zones, pay zones in lenses, and are steeply dipping.

Other IOR

Hydraulic fracturing is another technique that has gained wide acceptance as a means of improving oil recovery. While the technology has been in use for more than 50 years, its use has grown dramatically in recent years. Each year, 25,000 oil and gas wells are hydraully fractured. OFE estimates that frac jobs have enabled production of 8 billion bbl of oil in North America that otherwise would not be recovered.

And operators have been able to extend the practice to more-complex reservoirs and hostile environments. They also have advanced the technology through the use of air, underbalanced drilling, and new frac fluids to reduce formation damage and accelerate well cleanup. Advanced breakers and enzymes that minimize the risk of formation plugging from large-volume frac jobs are helping to increase ultimate recovery.

In a promising new advance, the use of CO2 in frac jobs is proving to be a cost-effective approach and has gained broad acceptance in Canada. This process involves blending proppants with liquid CO2 in a closed-system, pressurized vessel at 0º F. and 300 psi. Nitrogen is used to force the mix through the blender to the frac pumping units and then downhole.

According to OFE, with CO2-sand frac treatments, while higher in cost than conventional treatments, the costs are offset by savings resulting from the elimination of swabbing rigs and disposal costs associated with water-based systems.

A major problem for producers, in terms of environmental costs as well as in improved recovery is water breakthrough. Apart from improvements in reservoir characterization and produced water treatment, the concept of separating water downhole shows promise for light oil wells with high flow rates. By improving or altering water flow distribution in the reservoir via downhole separation, the operator can increase production and ultimate recovery rates.

On the horizon for heavy oil recovery improvement, Mariano Gurfinkel, assistant director for energy technology development, integration, and deployment at the Center for Energy and Technology of the Americas at Florida International University, envisions the day when the combination of downhole sensors, intelligent completions, and increased materials resistance allows operators to effectively upgrade heavy crude in situ to produce a lighter oil.

CO2 sequestration

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Thermal methods still dominate the EOR production scene worldwide and in the US, but that may change soon for the US. A 1999 study conducted by Advanced Resources International Inc. (ARI), Arlington, Va., for the Electric Power Research Institute, forecast that US thermal EOR (TEOR) production will decline significantly in the coming decade under even the best-case scenario (Fig. 7).

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However, there remains considerable potential for future TEOR development, the study concluded, especially in the heavy oil giants of California (Table 2).

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ARI's more-recent research has focused on CO2 flooding, the fastest-growing EOR technique (Fig. 8).

CO2 flooding has broad appeal for its effectiveness as well as for its improving economics. CO2 flooding can increase oil recovery by 7-15% of OOIP and can be sustained for 10-30 years. Improvements in computer simulation of CO2 flood performance and in cost savings stemming from greater experience in handling the CO2-water mix are contributing to its proliferation.

And there is a new twist for CO2 floods: the environmental and economic benefits from related CO2 sequestration efforts.

ARI Pres. Vello Kuuskraa claims that "the greatest opportunity for EOR in the US will be the joint operation of CO2 EOR and CO2 sequestration, particularly once incentives are offered to encourage industry's voluntary participation in mitigating emissions of greenhouse gases.

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"I could see this joint CO2-EOR and sequestration effort providing 1 million b/d of additional domestic oil production by 20 years from now while storing 150-200 million tons of CO2 annually, making contributions to domestic energy security while significantly reducing (greenhouse gas) emissions (Fig. 9).

Kuuskraa contends that fiscal incentives combined with R&D on joint EOR and sequestration will be the key to getting started.

"Having looked closely at this topic, it seems quite possible to structure a set of incentives of $50/ton of carbon stored, equal to about $14/ton of CO2 stored, that would be both revenue-neutral to federal and state budgets while providing industry considerable motivation to get on with the job. By revenue neutral, I mean that the additional revenues from federal and state royalties, production taxes, and corporate income taxes on the additional oil that would not otherwise be produced would pay for the incentive.

R&D efforts, incentives

While the number of IOR projects and volumes of production have grown, the level of commitment to IOR R&D by companies and by government has not been commensurate.

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A task force commissioned by DOE, in a June 1995 report, found that federal energy R&D outlays had been cut by 75% since the late 1970s. Since then, fossil fuels research has taken the brunt of further cuts (Fig. 10).

But the decline in R&D funding for IOR is worldwide, say various experts.

For an R&D-oriented organization such as IFP, Appert said the focus must be on developing "solutions to solve the long-term issues."

"IOR is one of those solutions, and we consider that a special focus has to be put on IOR, which will play an increasing role for the oil industry in the future."

Appert voiced concern about the "significant" decline in petroleum industry funding for R&D over the past 20 years.

"In the 90s, a lot of R&D labs have been leaving the oil sector to focus more on other issues, such as groundwater pollution. It's also becoming increasingly difficult to attract young scientists to work on energy issues and more specifically on oil," he said.

"So it appears very important for governments to promote and support R&D in order to ensure that adequate technologies will be available in the future to cope with an increasing demand of petroleum products driven mostly by transportation.

Kuuskraa specifically cited the low level of technology progress seen for EOR in general in the past decade.

"The one exception is oil sands development in Canada," he told OGJ. "But, in the US, I can point to little in the way of significant advances since the rather active and promising field tests and improved technologies of the 1980s.

"The problem likely stems from the sharp drop in industry's emphasis on EOR R&D and the severe cuts and volatility in the federal R&D budget. Technology progress has made other difficult-to-produce resources, such as coalbed methane, commercial. It offers promise to do this for EOR."

Slutz maintains that government R&D funding "must be spread among all the energy sectors: renewable resources, coal, and power, as well as oil and gas.

"Our (fiscal year) 2004 Congressional Request budget includes $15 million for oil technology and $26.6 million for natural gas technologies. These figures may seem small compared to past appropriations; however, we believe this level of funding will allow us to play a vital role in assisting independents turn resources into reserves and maintaining domestic production.

"We are currently taking a hard look at how to enhance our oil and natural gas program performance and effectiveness, focusing on results that will help ensure our nation's energy security. Our oil and gas R&D programs focus on maintaining and improving existing domestic production as well as aggressively pursuing advanced technologies."

Penn State's Watson also takes industry to task for not doing enough to support IOR R&D and suggests the creation of R&D consortia as a viable method for funding research. "Industry involvement is crucial if meaningful and applicable research is to be accomplished," he said. "The industry must have a stake in undertaking this research."

Fiscal incentives

Slutz took note of the importance of using fiscal incentives to support IOR R&D.

"Since independents produce most of this oil, some incentives have allowed them to spend money on upgraded technology to better produce the oil," he told OGJ. "The federal government has promoted IOR-type projects for a number of years. The federal tax code provides tax credits for qualifying (EOR) projects and direct tax relief for stripper wells, while heavy oil projects on federal lands also pay lower royalty rates on the sale of that oil. These financial incentives have provided real support for these enhanced and heavy oil projects and have proven effective for short-term production increases."

Slutz also sees scope for emerging technologies that might benefit from being able to qualify for such incentives.

"For example, incentives, such as government cost-shared field demonstrations, might focus on reducing the risk of trying existing technology that is new to a field or type of reservoir. Technologies such as smart wells, expandable tubulars, and real-time well monitoring via high-speed communication drill pipe are slow to be commercialized primarily because they are seen first as risk rather than opportunity.

"We look at making advanced technologies more accessible to these producers. One example of DOE reducing the risk of new technology is the Pru Fee property in (California's) Midway-Sunset field. This property was abandoned in 1987 with 90% of original oil in place. In 1995, a DOE project test site on 40 acres proved a better steam injection interval for oil recovery. Since that time, more than 1 million bbl of oil have been produced from the site, and 80 million bbl were added to proven reserves in this field. This technology is shared with all operators. That is one type of incentive that not only has put oil in the tank but has paid for the government investment many times over in the royalties from the new production alone."

Appert sees a need for fiscal incentives to support IOR R&D across the board, not just for the smallest operators and stripper wells, "but more generally in mature regions where the oil industry is faced with the challenge of a decline in the level of production.

"A flexible fiscal regime both for exploration and production should be implemented in order to promote higher recovery," he told OGJ. "In some countries, such as Norway, a CO2 tax or mandatory regulations on flaring are implemented and represent huge incentives to increase IOR."

Watson sees one area of fiscal incentives supportive of IOR efforts that would have a major impact: the return of the depletion allowance.

"Is there justification? I am not sure. Certainly, we are importing our liquid hydrocarbons to an extent beyond that of the (1973) Arab embargo. The simple reality is that our society has chosen 'the cheap fuel' alternative of imported energy and refined products.

"Moreover, the environmental community sees the declining availability of crude as a way to wean the country from the burning of hydrocarbons (out of concern for) global warming and climate change."

In fact, Watson counters that IOR fiscal incentives offer a politically viable alternative to the more-contentious approach of opening sensitive areas to exploration and development.

But Slutz contends that it's "not an either-or deal" and that efforts must be continued to keep existing fields producing as well as opening new lands for E&D.

"Financial incentives are part of the portfolio of important options the government considers as it looks to stimulate additional domestic oil and natural gas production to meet the nation's growing needs for these fuels," he said. "The advances in technology have given us the ability to produce larger amounts of resources from smaller surface areas while greatly enhancing environmental protection. Technological advances have dramatically shrunk the footprint of oil production activities and increased the efficiency of exploration and production. The result is fewer dry holes and a cleaner environment.

"No single option can solve all our energy concerns and meet all our needs. All of these options must be utilized to promote efficient domestic energy production and use. That is why the president's National Energy Policy is a comprehensive strategy that finds ways to maximize all of our nation's energy resources in a responsible fashion."