Analysis:Houston-based Anadarko Petroleum recently paid some $265 million in cash and assumed debt for Howell Corp., also of Houston. The transaction expanded Anadarko's total exposure in the Rocky Mountain area considerably, particularly in the Powder River Basin (PRB) of Wyoming and Montana.
At the same time—late September—Anadarko also agreed to acquire the right to purchase significant quantities of carbon dioxide (CO2) in southwestern Wyoming, plus the exclusive rights to sell and transport it by pipeline northward into the PRB. That agreement, with still another Houston company, Petro Source Investments Inc., is valued at about $3 million plus future commissions on total sales.
Together, the two transactions put Anadarko in the enhanced oil recovery (EOR) business in a pretty big way.
EOR? CO2 flooding? A process that back in the late 1980s—when oil prices were expected to exceed $50/barrel or more—was considered as a way to get more squeak from the aging domestic oil "pig"? When oil prices plummeted in the early 1990s, didn't the industry eighty-six the process as too expensive, particularly if the injection gas had to be pipelined over any serious distance to target fields? Yep. That and a lot more. But in Anadarko's case, there's more to it. Step back a bit in time.
In 2000, Anadarko paid a whopping $4.3 billion for Union Pacific Resources (UPR). Among other domestic properties, it snared UPR's drilling rights to nearly 10 million acres of Union Pacific railroad right-of-way that cuts straight through the heart of the Rocky Mountain oil and gas watermelon. The result, combined with its existing leaseholds in the region plus those connected with the recent Howell acquisition, has made Anadarko one of the biggest leaseholders in the inter-mountain west. Today, it's moving full-tilt to develop oil, gas, and even coalbed methane all across that area.
But Anadarko also has joined a growing list of out-of-the-tank thinking companies who refuse to accept that CO2 injection is applicable only in the Permian Basin of West Texas/southeastern New Mexico. There, it got a foothold back in the 1980s due to big economies-of-scale bucks paid by major oil companies coupled with reasonable proximity to huge underground CO2 reserves in New Mexico and eastern Colorado.
Actually, a recent report shows that there are more than 70 active CO2 projects ongoing in the U.S. today. Most are in the Permian Basin, but others dot the landscape from the Rockies to the Deep South, and some use waste CO2 from industrial processes, rather than from underground reservoirs.
Very generally, CO2 injection is much like waterflooding in practice. A number of injection wells are placed around a producing well. Oil and water don't mix, so even when water is used to push oil from the injection wells through the reservoir to the producing well, it leaves significant residual oil behind. With CO2 flooding, CO2 and oil do mix—above a pressure known as the minimum miscibility pressure (MMP). At or above the MMP, the CO2 acts as a solvent, cleanly sweeping the reservoir, leaving only a small oil residue behind. At pressures below the MMP, CO2 assists oil production by swelling the oil and reducing its viscosity.
It's much more technical than that, of course. But since the 1990s, smaller companies, including some major independents, have been programmed to regard CO2 injection as too expensive and too risky for most domestic fields, given volatile oil price fluctuations since then.
And that could be true. Geological characteristics of producing oil reservoirs differ widely. Some formations won’t give up their oil even to secondary recovery processes like waterflooding, much less tertiary EOR. And, of course, many fields are simply too small and economically marginal even under primary recovery.
But other, sufficiently larger, fields will respond. So, some companies, armed with empirical knowledge both of reservoir response and lower initiation costs—gained from the study of CO2 injection both at home and abroad—have crunched the technology advances along with the numbers. As a result, they seem convinced that with an ample source of CO2 relatively near fields that respond well, they can wrest more production from the ground profitably via injection programs.
But back to Anadarko in the PRB.
The company plans to apply experience with EOR projects in the Permian Basin and Oklahoma and miscible gas projects in Alaska and Algeria to similar projects in Wyoming. From Howell, it received producing properties in the Salt Creek field in the PRB, located about 40 miles north of Casper. That field is one of the most famous oil-producing parcels of land in the nation. It has been producing since 1889 and still contains recoverable oil. It is related geologically to a number of large, mature fields in the Teapot Dome area near Casper.
As its injection gas source, Anadarko plans to use byproduct CO2 from ExxonMobil's LaBarge gas processing facility in southwestern Wyoming. To get the gas upstate, the company plans to exercise its right—gained from Petro Source—to build a 127-mile, 250 mmcf/d CO2 transmission line from LaBarge to the Salt Creek area. Estimated cost is about $27 million. Initially, Anadarko plans to inject about 125 mmcf/d, and then evaluate delivery of additional CO2 to other operators in the area.
In a recent company bulletin, Anadarko President and CEO John Seitz said the Salt Creek field is one of the largest remaining EOR opportunities in the Lower 48 states, adding there was potential beneath Anadarko's acquired properties to hold more than 500 million barrels of additional oil.
During the next four years, the company plans to invest some $200 million for projects associated with the Salt Creek properties to add at least 150 million barrels of new reserves. The project will include drilling new wells and installing gathering and flow lines, natural gas treatment plants, and compressor stations. Anadarko hopes to hike net production in the area from about 5,300 b/d currently to as much as 35,000 b/d by the end of 2006.
Although a number of fields in the U.S. Rockies area could benefit from such a development, it was a Canadian operator's successful use of Western U.S. off-gas CO2 to enhance recovery from a field in Saskatchewan that probably helped get the ball rolling.
In 1997, Calgary-based PanCanadian Petroleum (now Encana) earmarked some US$720 million to build a 200-mile pipeline from the U.S. to its Weyburn Unit properties in the Canadian portion of the Williston Basin about 78 miles southeast of Regina. The source CO2 is a byproduct of coal gasification at Dakota Gasification Co.’s Great Plains Synfuels Plant near Beulah, ND.
Encana says that project, in phased operation since 2000, will add 25 years to field life and increase recovery by an additional 120 million barrels. The company estimates increased daily production from the 1997 total of 18,000 barrels to some 30,000 barrels by 2008, and then holding that rate until 2011.
At peak, Encana will be injecting about 95 mmcf/d of CO2 at the field, which would make it the largest project of its kind in Canada and the sixth largest in the world (that is, if you leave out Anadarko's planned program at Salt Creek, which likely would kick the Weyburn flood to seventh place).
But CO2 injection for EOR is growing elsewhere, as well. Current oil price levels, if they stay in the $20-$25 range, might help stimulate even more growth.
In the Permian Basin, a unit of Houston-based Kinder Morgan Energy Partners L.P. has spent the last two years building a bigger base of CO2 supply from source fields and through pipelines it purchased from Shell back in 2000. The company continues to provide nearly all the CO2 being used in current Permian floods, and is expanding slowly east and south into other parts of the Permian and other nearby basins.
What's more, Kinder Morgan CO2 Co. (KMCO2, as the unit is called) has carried forward with Shell's participation in an Energy Dept.-sponsored pilot program that is looking at bringing CO2 from New Mexico/Colorado source fields into the Mid-Continent area, including Oklahoma (where one field already draws CO2 via a separate pipeline) and Kansas. The Mid-Continent area still contains billions of barrels of oil that only more expensive secondary and tertiary processes could bring to the sales line. There might be a way to do so profitably with CO2.
Also under consideration is moving CO2 from Arizona, where a Canadian company has developed large reserves of it in recent years, either east to Texas and the Mid-Continent or west to California heavy oilfields.
It's not all sleepy time down south, either. Dallas-based Denbury Resources Inc. has rather quietly but unswervingly built a growing oilfield CO2 recovery, pipelining, and reinjection program in Lower Tuscaloosa oilfields located in southwestern Mississippi. Denbury, now the largest oil and gas operator in the state, acquired the source gas field and pipeline from Shell back in the 1990s, but has since added more fields to the system, both on its own and through acquisitions. The company recently estimated that about 60 to 70 million barrels of net oil reserves, including potential from two recently acquired fields currently under waterflood, might be available there, including some fields that Denbury "does not currently own." Look for them to own some of them.
So, while major operators and many large independents continue to spend huge bucks to develop brand-new—but increasingly smaller—reserves of new oil in the Gulf of Mexico, as well as overseas, some producers still hold that EOR technologies like CO2 injection will help them wring incremental oil production from mature reservoirs in a number of new areas of the country. And in an age of supply uncertainty made doubly so by the existence of international terrorism, any new domestic source of oil has to be a welcome one.
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