Efforts to tap oil shale’s potential yield mixed results

April 25, 2005
A huge resource, much of it in the oil-hungry US, sustains efforts in the US and elsewhere to find a way to produce shale oil economically.

Second of two parts:
A huge resource, much of it in the oil-hungry US, sustains efforts in the US and elsewhere to find a way to produce shale oil economically. The efforts, spanning many years, have received intermittent help from governments attracted by the enormous potential supply of oil (OGJ, Apr. 11, 2005, p. 22).

Yet realization of that potential, even with oil prices at recently elevated levels, continues to await technology able to make production of shale oil commercial.

One recent project has stalled in Australia. But another project, in the resource-rich US West, has made technical progress that keeps hope for shale oil alive.

Past effort

A March 2004 report by the US Department of Energy noted that it has been nearly 2 decades since the federal government last initiated an oil shale policy with financial incentives. Since then, it said, “Technology has advanced, global economic, political, and market conditions have changed, and the regulatory landscape has matured. As America considers its homeland security posture, including its desired access to diverse, secure, and abundant sources of liquid fuels, it is both necessary and prudent to reconsider the potential of oil shale in the nation’s energy and natural resource portfolio.”

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The vast extent of US oil shale resources has been known for a century. In 1912, President William Howard Taft established by executive order the Naval Petroleum and Oil Shale Reserves, a program that has overseen US strategic interests in oil shale since that time. The huge resource base has stimulated several prior commercial attempts to produce oil from oil shale able to compete with conventional crude. All failed. With oil demand now straining production capacity and lifting prices, the competitiveness of shale oil is poised to improve.

Oil shale timeline

Man has been recovering hydrocarbons from shale containing kerogen for at least 600 years. US pioneers heading west fueled campfires with shale oil and used the residue to grease wagon axles. A few learned of oil shale’s energy potential when chimneys built of oil shale caught fire and burned down cabins.

Small amounts of shale oil were produced in the eastern US in the 1850s, but the combination of a lack of technology, prohibitive processing costs, and inexpensive competitive fuels doomed it as a fuel source.

In 1909, the US government withdrew from sale some lands containing oil shale in western Colorado to create the US Naval Oil Shale Reserve. However, there were few attempts to develop shale oil until World War II. The first Anvil Points facility on US Naval Oil Shale Reserve land west of Rifle, Colo., received $18 million for experimental oil and gas technologies in 1944 under the US Synthetic Liquid Fuels Act. The US Anvil Points mines opened in 1949 in the area of Mahogany Ledge, and retorts of three types were built. Some high-cost oil was produced before the project closed in 1956.

In 1955-61, Union Oil Co. of California built and operated an oil shale plant north of Parachute, Colo. The plant operated for 18 months and produced as much as 800 b/d of shale oil before it closed due to operational problems and price uncertainties.

In the mid-1960s, there was talk of detonating a 50-kiloton atomic device underground in the Piceance Creek basin to recover oil from shale, but it was never done.

The Oil Shale Co. (Tosco), in partnership with Standard Oil Co. of Ohio and Cleveland-Cliffs, in the mid-1960s built and operated the Colony oil shale plant 17 miles north of Parachute. The facility produced 270,000 bbl of shale oil by 1972.

In the early 1970s, Shell did research on in situ steam injection in oil shale and nacholite formations along Piceance Creek in Rio Blanco County, Colo., but eventually abandoned the process. About the same time, Occidental Petroleum Co. conducted the first in situ oil shale experiment along Logan Creek, north of De Beque, Colo. Six retorts of various sizes were built, and some oil was produced before the project proved too costly and was shut down in 1982.

In 1980, Congress approved $14 billion for synthetic fuels development, creating a cottage industry of experimental projects to get oil from shale, coal, and other alternative sources. Those efforts generally ended in 1982 when oil demand dropped and prices plummeted. In 1985, Congress abolished the synthetic liquid fuels program after spending $8 billion over nearly 40 years.

Shell’s progress

In 1996-97, Shell Exploration & Production Co. resumed experiments with a small field test at its Mahogany oil shale property in Rio Blanco County, using in situ heating to separate oil and gas from the shale formation beneath the surface. That work eventually was postponed because of economic conditions.

Shell Exploration & Production Co. is testing an in situ conversion process for shale oil at its Mahogany project in Colorado.
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Shell returned to the property in mid-2000 with an expanded research program for in situ heating. Construction for the latest phase began in April 2000; the heating process began in November that same year and is slated to continue for several years as the company evaluates “several different tests.”

Shell officials said they expect “far more oil and gas may be recovered in a given area since early indications show oil can be produced at far greater depths.” They said, “It is also anticipated that there will be less water usage than in conventional oil shale surface mining techniques.”

Shell now is researching an in situ enhanced shale oil recovery process-known as the in situ conversion process (ICP)-that began more than 20 years ago in its Houston laboratories. Compared to previous processes, this new technology is considered more environmentally friendly since it does not involve traditional open-pit mining, minimizes water usage, and generates more oil and gas from a smaller surface area.

The process involves drilling vertical holes into the oil shale zones and then gradually heating the zones with electric heaters to temperatures of 650-700° F. Light fractions of oil and gas are then recovered with traditional methods. “We get two-thirds oil and one-third gas,” said Shell representative Jill Davis. The oil is a 37 gravity condensate, the gas a hydrocarbon easy to upgrade to gas pipeline specifications.

“The main products we get are diesel, naphtha, and jet fuel,” Davis said. The fluids are produced underground with minimal surface upgrading.

“It’s as if we leave the heavy ends of the carbon chain in their original solid state,” she said. “The light ends break off due to the gradual heating. We have made some product.”

While technical challenges remain, Davis said, “We are increasingly encouraged by the field test results in northwestern Colorado. The field research has shown that ICP produces high quality transportation fuels that are estimated to be economical at oil prices in the mid-$20s/bbl.”

She acknowledged, “We’ve had some steps back and some steps forward in our research over the years, and we’re continuing to test the viability of the technology. We’ve not made any commercial decision, and we don’t plan to make a commercial decision until early next decade, probably no sooner than 2012 because between now and then, we need to do another test-a more integrated test, more of a pilot-sized test-where we can see how the things we’ve tested so far work together.”

As for possible government subsidies for shale oil, Davis said, “We’ve gone it alone all of these years. We’re committed to working this through and seeing if it is viable. So far, we’ve been willing to do that on our own.”

Australia’s experience

Recent efforts to develop shale oil resources in other parts of the world have not succeeded.

In December, Queensland Energy Resources Ltd. ended the environmental impact statement (EIS) process for the proposed Stage 2 development of the former Stuart Oil Shale Project in Australia.

Accordingly, the Stage 2 proposal is no longer a declared “significant project” under the State Development and Public Works Organization Act of 1971.

Officials said it is possible a new Stage 2 proposal may be submitted to the Queensland government in the future, at which time a new environmental impact assessment process may be initiated. But as of early March, there was no indication that such a move was contemplated.

Opponents claim it has cost more than $360 million (Aus.), including tens of millions of dollars of taxpayers’ money.

According to company officials, Stage 1 was a $250 million research and development project that involved mining and on-site processing of about 6,000 tonnes/day of oil shale to produce 4,500 b/sd of oil products. The original $600 million Stage 2 proposal was to demonstrate commercial viability of the processing technology by means of expanding mining and processing activities to produce 19,000 b/sd of oil products.

However, work on the Stage 2 environmental assessment process was suspended for almost 2 years to concentrate on problems encountered in the commissioning of Stage 1. The process was reactivated in late 2001.

In April 2004, new owners of the Stuart resource, Queensland Energy Resources, requested that the government defer evaluation of the Stage 2 EIS material until additional investigation and analysis of potential environmental impacts could be completed. The government granted this request subject to a number of conditions relating to information exchange.