Green Oil

?Precision Drilling Rig #275 drills #04-33-005-13 W2M, a horizontal well in Weyburn Field, for EnCana Corp.

?Carbon dioxide (CO2) is a waste gas, thrown off by automobiles, airplanes, power plants, factories, and myriad assorted components of our modern, energy-dependent lifestyles. Its rising concentration in the Earth’s atmosphere deeply concerns scientists, politicians and citizens alike.

So, CO2 is bad. Except if you operate an old oilfield. In that case, you might be very interested in obtaining large volumes of CO2 and prepared to pay considerable sums for it. That’s because CO2 can be an effective solvent for oil, and pumping it into wells can boost crude recoveries nicely.

Herein lies oil’s great green opportunity—operators can take CO2 emitted from industrial sources and put it to commercial use. Afterward, the aged oilfields are ideal containers that can permanently store the gas.

Of course, although the potential synergies are alluring, carbon capture and storage and subsequent use of the CO2 in enhanced-oil-recovery (EOR) operations are emerging processes fraught with challenges.

Size of the prize
CO2 flooding is one of an arsenal of EOR methods used to coax oil from worn fields. Thermal strategies, such as steam injection, are popular in low-gravity crudes. Injections of CO2 or nitrogen work with lighter gravities.

At present, some 643,000 barrels of oil a day are pumped from EOR projects in the U.S. That’s down from peak levels achieved in 1992, when 761,000 barrels were made each day. The drop comes from the decline in oil produced from thermal methods, which has fallen from 480,000 barrels a day in 1986 to around 273,000 a day in 2008.

The method on the rise is CO2 miscible flooding. Its production has been swelling steadily, and volumes expanded to some 240,000 barrels a day in 2008. That’s a nearly nine-fold increase from 28,000 barrels a day in 1986. A sliver of oil is also made by immiscible CO2 floods, some 9,000 barrels a day.

West Texas’ Permian Basin has been the proving ground for CO2 flooding, and the region accounts for more than half of all such production. The first applications of CO2 for EOR were in the mid-1960s, when Atlantic Richfield injected flue gas from a processing plant into a test field in West Texas. In the early 1970s, Chevron built a 230-mile pipeline to bring CO2 from gas-processing plants in the Val Verde Basin to Kelly-Snyder Field, the Permian’s first large-scale tertiary project.

After the method proved effective, great natural-source fields at McElmo and Bravo domes and Sheep Mountain were developed. Webs of pipelines were laid to carry CO2 from southern Colorado and northern New Mexico, and CO2 flooding spread rapidly across the oil-rich Permian. In the southeastern U.S., CO2 from Jackson Dome was brought to Mississippi fields.

Although operators in other regions certainly had oilfields that would benefit from this EOR technology, they largely lacked access to CO2.

Now, worldwide interest in climate change has thrust CO2-EOR into the spotlight. Governments are looking for ways to reduce levels of greenhouse gas (GHG) emissions, and researchers are investigating wide arrays of technologies to capture and sequester such gases. Subsurface sequestration is possible in coal beds, salt beds, saline aquifers and depleted oil and gas reservoirs. Of these potential sites, depleted oil and gas fields are the only repositories that can also put CO2 to economic use.

For oil operators, the future lies in the development of technologies to strip CO2 from industrial sources and deliver that gas to fields distant from natural supplies. And, beneficial use of CO2 that would otherwise be vented into the atmosphere is a winning proposition, both economically and environmentally.

Truly, CO2 capture and storage is considered critical technology to reduce world GHG emissions. The Intergovernmental Panel on Climate Change (IPCC) has estimated that CO2 capture and storage could provide up to half of all emission reductions necessary to stabilize GHG levels in the atmosphere.

On the economic side, according to the U.S. Department of Energy (DOE), an astonishing 89 billion barrels of additional oil could be technically recovered from U.S. oilfields if state-of-the-art CO2-EOR technologies were applied. This would require staggeringly large volumes of CO2, from such sources as cement, fertilizer and ethanol plants and coal-gasification and power-generation facilities.

Is this wild-eyed optimism? No doubt, but it underscores the immense size of the target. When economics are introduced into the calculations, numbers are still gigantic. A new DOE study, by consulting firm Advanced Resources International, reports that between 39- and 48 billion barrels of incremental oil are economically recoverable via CO2-EOR technologies.

At present, some 2.6 billion cubic feet (Bcf) of CO2 is injected each day into North American reservoirs. Of that total, just 20% comes from industrial sources. To supply all the candidate oilfields with sufficient CO2 for EOR processes, the U.S. alone would require another 141 trillion cubic feet (Tcf ) over a 30-year period. That comes to an average rate of around 13 Bcf a day.

Challenging technology
Make no mistake; CO2-EOR is no cakewalk. Tertiary recovery projects are high cost and high maintenance. Quite an infrastructure must be laid to run a CO2 flood, including injection wells, pipelines, gas- and water-handling facilities and recycling machinery. Because CO2 reacts with water to form carbonic acid, the equipment must be resistant to corrosion.

Use of industrial-sourced CO2 for enhanced oil recovery is growing. Two prime success stories are Wyoming's Salt Creek Field and Saskatchewan's Weyburn field. Both have responded strongly to CO2 flooding. Facing page, an injection well receives CO2 in Anadarko Petroleum's Salt Creek Field.

The floods are tricky to manage: Injection volumes are continuously monitored, and the path of CO2 is closely tracked, at times by 4-D seismic. Reservoir heterogeneity must be overcome. Permeability barriers can interfere with the sweep of gas and water, and operators use approaches that include horizontal drilling, gel treatments and selective injections to even out movements. Finally, operating costs are hefty, due to the horsepower required by constant injection and recycling of water and gas.

Recovery factors on CO2 floods range between 7% and 25% of original oil in place, and typical floods fall around 10%. For miscible floods, in which CO2 mixes with oil and forms a more moveable fluid, amenable reservoirs hold light oils at relatively low temperatures and at depths generally greater than 3,000 feet. As a rule-of-thumb, recovery of each barrel of incremental oil requires net injection of some 6,000 to 7,000 cubic feet of CO2. Immiscible floods, in which CO2 acts as a mechanical force but does not combine with the oil, are a tiny but growing sector of EOR.

Of course, the great environmental benefit of CO2 flooding is the eventual sequestration of the gas in the depleted reservoirs. Efficient CO2 floods are carbon neutral, storing about the same amount of CO2 as that given off by use of its recovered oil.

But, old oilfields could also serve as sites for sequestering considerable volumes of CO2 beyond those needed for oil recovery. Hence, the term “green oil,” which can be applied to oil from fields where more CO2 is sequestered than is released by burning of its incremental production. Since retired CO2 floods would already have injection wells, gas-handling facilities and pipelines, their use as storage sites could be quite reasonable.

And yet, although CO2-EOR is a well-known and accepted technology, there’s uncertainty as to how viable CO2 sequestration is in the short run. That’s what governments, research institutes and companies are scrambling to answer.

World-scale project
“There is a huge challenge and a huge opportunity within the North American energy sphere to try and address the demand for cleaner fuels,” says Jason Tolland, counselor and program manager, environment and energy section, Canadian Embassy in Washington, D.C.

Canada has set an ambitious goal of reducing its GHG emissions in absolute terms by 20% by 2020, and has put in place new regulations to that effect. At the same time, the Canadian government is committed to meeting demand growth for oil and gas, and it is matching that growth with significant investments in mitigating technologies.

That relates to carbon capture and sequestration projects in particular. “We hear the words ‘untested’ and ‘unproven’ with respect to these technologies, and that’s simply not true,” says Tolland. “There are projects that are up and running, and that’s important to recognize.”

Canada’s marquee project is EnCana Corp.’s Weyburn Field, in the Williston Basin in southern Saskatchewan. Weyburn is the world’s largest full-scale, in-the-field study of CO2 storage in a commercial EOR operation. To date, more than 10 million metric tons of CO2 have been injected underground, and more than 30 million metric tons will be stored in total when the project is finished. (That’s equivalent to taking 6.7 million cars off the road for an entire year.)

Weyburn is a massive, 70-square-mile field that contains 1.4 billion ba­­­­­­­­rrels of original oil in place. Discovered in 1954, Weyburn made 370 million barrels of oil from primary and secondary methods. Its reservoirs are two zones in the Mississippian Midale formation. The highly permeable Vuggy zone responded very well to waterflood, but the tighter Marly zone did not. In 2000, Calgary-based EnCana started a CO2 flood in the Marly to boost oil recoveries. It calculates that it will recover another 155 million barrels of crude from the tertiary effort.

Currently, Weyburn makes just below 30,000 barrels of oil per day, and 20,000 barrels of that is attributed to the CO2 flood. “We have about 700 producing wells and 300 injection wells, and we use a variety of horizontal and vertical wells,” says Darcy Cretin, EnCana operations superintendent, Weyburn business unit. Weyburn’s CO2 development will eventually cover 92 nine-spot patterns. To date, 46 patterns receive CO2.

The CO2 for Weyburn’s flood comes from the Great Plains Synfuels Plant in Beulah, North Dakota. The coal-gasification plant produces a steady stream of CO2 as part of its industrial process, some 250 million cubic feet per day. About 60% of that is able to be captured in sufficient quantities and purities for EOR. The owner of the plant, Dakota Gasification Co., built a 180-mile pipeline to move CO2 to Weyburn. Initially, volumes were contracted at 95 million a day, and later increased to 125 million a day.

Nearby, Apache Corp., Houston, runs a smaller CO2 flood at its Midale property, which adjoins Weyburn. The company began injections in fall 2005. The 40-square-mile field, geologically continuous with Weyburn, has original oil in place of 515 million barrels. Its oil recovery pre-CO2 flood was 154 million barrels, and another 67 million is expected as a result of the flood; currently production is some 6,500 barrels per day. Some 10 million metric tons of CO2 will ultimately be sequestered in this field.

Separately from the commercial EOR projects, the fields are the host sites of an international research project on CO2 sequestration, the Weyburn-Midale CO2 Monitoring and Storage project. The Petroleum Technology Research Centre, based in Regina, led Phase I and manages the technical research of the final phase. Sponsors include an impressive variety of international governments, oil companies, power companies and even automakers.

The $80-million, eight-year project focuses on measuring and monitoring CO2. It is the first project to study whether CO2 injection and underground storage in depleted oilfields makes environmental sense.

“From a research perspective, Weyburn was very attractive because it offered the opportunity to collect all the baseline information on the reservoir before any CO2 was introduced,” says Cretin. “And, the field is very accessible to researchers from around the world.”

The research project included time-lapse seismic to track CO2 movement within the reservoir, extensive and detailed well sampling, and repeated testing of surface soils for possible microseepages of CO2. (None were found.) “We’ve also given more than 200 tours, to groups from every continent,” he says.

The Weyburn-Midale project’s initial phase, completed in 2004, determined that storage of CO2 in an oil reservoir was safe and effective over the long term. The final phase, still in progress, is devoted to protocols and completion of a best-practices manual to guide future CO2 storage projects.

“The project is a significant economic and technical success,” says Floyd Wist, executive director, energy policy, Saskatchewan’s Ministry of Industry and Resources. “It injects enough CO2 to offset 30% of the GHG emissions from all the vehicles in Saskatchewan, and it demonstrates large climate-change benefits combined with commercial gains with little or no expense to governments.”

U.S. picture
The U.S. is also home to a couple of major EOR projects that use industrial CO2. Anadarko Petroleum Corp., based in The Woodlands, Texas, runs such a flood at 100-year-old Salt Creek Field in Wyoming’s Powder River Basin. Salt Creek is one of the largest oil fields in the region, with original oil in place of 1.7 billion barrels.

Anadarko acquired the field in 2002 as part of its purchase of Howell Corp., says Craig Walters, general manager, Rockies enhanced oil recovery. “When we bought Salt Creek, it had been producing for 40 years under waterflood. Its average oil cut was 0.5%, and it made 5,500 barrels of oil per day.”

Since the field’s discovery in 1908, it has produced more than 660 million barrels of oil. At present, it covers 20,000 acres and has 3,000 producing and injection wells. It’s an immense structure, productive mainly from Wall Creek 2, a sand within the Cretaceous Frontier formation. Typical field wells are about 2,200 feet deep, and up to 10 intervals from Niobrara to Tensleep are productive on the anticline.

Salt Creek’s potential for CO2 flooding had been studied for years by previous operators, but had not been implemented. One of the knotty technical challenges was that the reservoir temperature in Wall Creek 2 seemed too elevated to attain miscible pressures. That’s because the waterflood used Mississippian Madison water, which was fairly hot.

Anadarko believed that it could attain miscibility, however. The company started a CO2 pilot in 2003 to capture reservoir data and determine possible recovery factors. Results were promising, and the firm built a 125-mile pipeline to pick up CO2 generated by ExxonMobil’s Shute Creek gas-processing plant in western Wyoming. This plant, which processes natural gas from massive LaBarge Field on the Moxa Arch, currently sells 220 million cubic feet of high-pressure CO2 per day.

Shute Creek CO2 has been used for EOR in the Rockies for more than two decades. It’s the source for CO2 used in Chevron Corp.’s giant Rangely Field flood in Colorado. One of the world’s largest and longest-running CO2-EOR operations, Rangely has been under CO2 flood since 1986, and has already produced 100 million barrels of incremental oil and natural gas liquids from its tertiary effort. Shute Creek CO2 is also piped to two smaller floods at Lost Soldier and Wertz fields in the Red Desert Basin, operated by Merit Energy Co., Dallas.

Anadarko extended the CO2 line from Baroil, Wyoming, to Salt Creek and started injection in January 2004. The first response was lightening fast, in just four months.

“Salt Creek is not a typical CO2 flood,” says Walters. “Our wells are tightly spaced and our reservoir quality is quite good, so we see quick response.” Indeed, reservoir pressures are high enough that the producers actually flow.

“We are minimizing surface disturbance by refurbishing and using existing wellbores. So far, we have worked over more than 1,200 wells and drilled fewer than 40 new wells.” The company currently has some 200 active producers. Unneeded wells are plugged, and previously plugged wells are evaluated and often plugged again with modern techniques. The project encompasses 16 phases, and timing of the phases is driven by the volumes of CO2 the company has available. Each phase, typically comprising 40 injectors spread across 800 acres, is expected to produce for 25 to 30 years. Between 20% to 25% of the field has been flooded to date, and five phases are on line. Currently, Anadarko purchases 125- to 130 million cubic feet of CO2 a day. Total injection, including recycled CO2, runs 300 million a day.

The response has been phenomenal. In just four years, total production has rocketed to an average of more than 8,500 barrels a day, and incremental oil attributed to the CO2 flood has passed 7,000 barrels a day. Anadarko expects to increase net production in the field, in which it owns a 98% working interest, to around 20,000 to 25,000 barrels a day, launching Salt Creek into the ranks of the top-producing fields in the onshore U.S.

“We’re expecting recoveries around 10% of original in-place oil from the CO2 flood,” says Walters. “Overall, we think we will recover 150 million barrels of incremental oil over 30 years. That’s a tremendous resource for our nation and for Wyoming.” Already, Salt Creek has helped Wyoming record its first increase in oil production in more than 20 years.

Excellent economics, clearly. And, Salt Creek will ultimately store some 40 million metric tons of CO2. “As a benefit, Salt Creek will be one of the largest geological sequestration projects of its kind in the world. Over its lifetime, Salt Creek will sequester enough CO2 to offset emissions of more than 5 million average U.S. homes for one year,” says Walters.

There’s more on Anadarko’s plate as well. The company runs another CO2 flood at its Monell Unit in Patrick Draw Field, Sweetwater County, Wyoming. It purchases 25 million cubic feet a day from Shute Creek for this project. Oil production has grown from nothing in 2003 to 3,500 barrels a day. Additionally, the company has completed a pilot project in the Tensleep reservoir in Sussex Field, 10 miles north of Salt Creek. “Sussex is definitely on our horizon. We’re completing some additional technical work and will move that project forward when sufficient CO2 becomes available.”

New sources
Indeed, that’s the dilemma most operators face. While CO2 levels are alarmingly high in the atmosphere, what oil operators need are high-quality, 95%-pure CO2 volumes delivered at steady rates for many years. And, natural-source fields have limited potential to satisfy future demand. Some people also believe that natural sources should not be expanded, as their use compounds overall GHG emissions.

Certainly, CO2 byproducts from amine-separation systems have been collected for years and used in EOR. The tough nut to crack is how to tap useable CO2 from many of the other emitting sources.

“Our mission is to develop the most economic, efficient, effective and versatile methods for CO2 capture,” says Malcolm Wilson, director of the office of energy and environment, University of Regina. Wilson, a member of the IPCC and one of the recipients of its recent Nobel Prize, heads the International Test Centre for CO2 Capture. Research ranges across pre-combustion and post-combustion capture, and includes retrofitting of conventional facilities and new capture-ready industrial concepts.

“Our technologies are designed to reduce GHG emissions by capturing CO2 from industrial gas streams and turning it into a marketable commodity,” he says. The ITC’s facilities include a pilot plant that captures one metric ton of CO2 per day, and a demonstration plant on a coal-fired power station that captures four metric tons per day.

Plainly, capture technologies are in their early stages. Cost is a tremendous issue: typical prices for natural-source CO2 run between $1 and $2 per thousand cubic feet in the Permian Basin, while CO2 capture cost with current technologies is around $8 per thousand.
Still, industrial-sourced CO2 injection is growing, says Steve Melzer, president of Midland-based Melzer Consulting and CO2 conference director. “It’s driven by both the growing shortage of natural CO2 and, to a lesser but growing degree, by environmental concerns. And it’s happening voluntarily without climate-change legislation, at least for sources that are easy to capture.”

And, as the price of natural gas increases, operators are looking more toward development of contaminated natural gas, some of which can actually have higher concentrations of CO2 than methane.

SandRidge Energy Inc., Oklahoma City, and Occidental Petroleum Corp., Los Angeles, recently announced such a project in West Texas. SandRidge will drill, produce and deliver natural gas contaminated with CO2 to an 800-million-cubic-foot-per-day processing plant, funded by Occidental, Los Angeles. The latter firm will use the CO2 for EOR projects in West Texas, and SandRidge will retain 100% of the methane.

The Century plant will be built in Pecos County, and facilities will include a 160-mile CO2 pipeline. The deal helps both entities. Sand­Ridge has been drilling wells in the West Texas Overthrust area that contain methane and high concentrations of CO2, and the new plant will allow it to increase its current gross production from 135 million cubic feet a day (33 million net methane) up to 1.1 Bcf a day (270 million net methane) by late 2011.

Occidental, for its part, will recover around 450 million cubic feet of CO2 per day, enough to eventually develop as much as 500 million barrels of incremental oil from fields it currently owns.

“Increasingly, the flaring of CO2 is seen as a future liability, so operators are looking for subsurface homes for what was waste CO2,” says Melzer. “It’s an evolution in thinking, and a growth area for EOR.”

Another project is Houston-based Enhanced Oil Resources Inc.’s proposed development of St. John’s Field in Arizona and New Mexico. The field is the largest undeveloped accumulation of helium and CO2 in North America. It holds 15 Tcf of in-place gas, of which 30 Bcf is potentially recoverable helium and 6 Tcf is potentially recoverable CO2.

“What we need immediately are in-place policies on concurrent storage of CO2 during EOR activities,” says Melzer. “The Environmental Protection Agency is getting involved, and trying hard to accommodate commercial activity. But what we’re concerned about is having possibly difficult regulations put in place that would make the use of industrial CO2 unattractive for oil operators.”

The coal and EOR industries also must push forward on demonstration projects that will help improve next-generation technologies and reveal the economics of capturing CO2 from commercially challenged industrial sources.

“It’s time for the rubber to meet the road,” says Melzer.

The potential for new EOR floods using industrially sourced CO2 is enormous, agrees Lance Cole, Tulsa-based operations manager, Petroleum Technology Transfer Council. “The question is the timing, and how the carbon trading market will evolve. We also need to know when and what incentives the federal government will put in place.”

Only a certain percentage of the sources will be in areas convenient to oilfields that are amenable to tertiary recovery. “From a producer’s standpoint, tying into the carbon-capture market will be a way to offset some of the costs of CO2 floods,” says Cole.

On a wide scale, the practice of capturing carbon from power plants is not yet practical. “But, within the next 10 years, this should fall into place,” he says. One likely scenario is that a new group of midstream companies will emerge and take on the tasks of capturing carbon, navigating regulations and delivering CO2 to eager operators.

The PTTC aims to help operators, especially smaller independents, by publicizing the efforts of companies that use new technologies, including CO2-EOR, says Susan Nash, PTTC business development.

One such success story is privately held Chaparral Energy. The Oklahoma City-based independent has CO2-EOR recovery operations in the Camrick and Perryton units in the Oklahoma Panhandle’s Beaver and Texas counties, and in the Velma area in the southern part of the state. It owns interests in more than 50 properties in Oklahoma and Texas that appear promising for EOR recovery, has invested in several pipelines and is actively working to secure additional CO2. It currently picks up some of its supply from a fertilizer plant in Enid, Oklahoma.

“We can help facilitate technology transfer from an operator like Chaparral to others through white papers and workshops,” says Nash. “We see extreme interest among companies with assets located close to potential CO2 sources.”

PTTC’s goal is to be a clearinghouse for ideas and technologies, says Cole. “If we get the right components in the cooking vat, with some producers with needs, researchers with ideas, and service companies with products, some great things can happen.”

“We’re very excited about the future of these ‘green’ petroleum technologies,” says Nash.

Capturing emissions
Back in Saskatchewan, efforts are afoot to launch just such a creative demonstration project. The province hopes to encou­rage the petroleum industry to purchase large volumes of CO2 from SaskPower, the provincial electric utility, use it for EOR, and then store the CO2 in the depleted reservoirs.

“In this way, SaskPower would receive a revenue stream to offset its CO2 capture costs, the increased oil production would generate incremental revenues, and large volumes of CO2 would be permanently stored,” says Wist.

Saskatchewan is attempting to push the process forward through a C$7.2-million initiative to establish a market for CO2 that could be supplied from future clean-coal facilities or other industrial sources. “Saskatchewan will also help industry assess and address policy, technical, economic and legal barriers which inhibit EOR projects,” says Wist.

The inaugural effort is an integrated carbon-capture and sequestration demonstration project at the Boundary Dam electric power facility, near Estevan, Saskatchewan. Sask­Power operates six coal-fired generating units there, and it proposes to replace one of the older units with a clean-coal unit.

The seven-year effort would capture CO2 per year and make it available for EOR. “It will be one of the first projects to develop and demonstrate CO2 capture at a coal plant on a commercial scale,” says Wist.

The Canadian government has pledged C$240 million to the project, and SaskPower will commit C$750 million. The oil industry would have to contribute roughly C$400 million for oilfield-related activity, making total project cost approximately C$1.4 billion.

Power demand in Saskatchewan has been expanding at unprecedented rates. Industries, from oil operations to potash mines, are all asking for more power. “On supply, we are looking at a huge increase in demand,” says Max Ball, manager, SaskPower clean-coal project.

SaskPower thinks that a 100-megawatt demonstration plant at Boundary Dam could capture 1 million metric tons a year of CO2 emissions, and that CO2 could be used to produce 3 million barrels of oil. The electricity is worth about C$70 million, but the incremental oil is worth C$300 million. “The economic driver that makes this possible is the oil,” says Ball. “We have to work very closely with the oil companies to be sure we create the correct amount of CO2 for the EOR market.”

So, instead of designing a plant with its sole focus on optimum electrical-power generation, SaskPower is designing a plant to make and sell both electricity and pure CO2. This is a notable change from business-as-usual.

In addition to Weyburn and Midale, which already have contracted CO2 volumes, SaskPower has identified nearby oil reservoirs with the capacity to take up to 40 million metric tons of CO2. It has a potential partner, not yet named, interested in using the CO2.

If the project proceeds as currently envisioned, the clean-coal unit could be producing electricity and CO2 within five years of regulatory approvals. “We need to have all the pieces in place, ready to go, and we’ll decide in 2010 if we’re really going to build this thing.”
The demonstration project will be the first time a power company treats the full flue-gas stream from a generating plant.

“We also suspect it will be the first such project where EOR is integrated with sequestration,” says Ball. “We will begin with EOR, and then it will become a sequestration project.”

That will be some bright green oil. And it’s the future.