CO2 has been successfully pumped into northwestern Colorado's Rangely Field for 20 years. The still-flourishing enhanced-recovery project offers lessons for the present and future.



These days, the Rocky Mountain region is heralded for its profusion of unconventional gas reservoirs. But the region is also home to huge, aging oil fields. One of the largest is Rangely, a giant accumulation that sits in Rio Blanco County, Colorado, astride the Douglas Creek Arch, a broad structural rise that separates the prolific Piceance and Uinta basins.

Chevron U.S.A. Inc. operates the massive field, the only one that achieves giant status in Colorado. It's a classic- tremendously thick, high-quality Weber sands drape across a gargantuan asymmetrical anticline. The Permian- to Pennsylvanian-age aoelian Weber is a reservoir engineer's dream: Rangely's oil column is 820 feet thick and its average reservoir thickness is 520 feet. The Weber, which is found at depths between 5,500 and 6,500 feet, holds original oil in place (OOIP) of 1.9 billion barrels.

During some six decades of production, Rangely has produced 863 million barrels of oil and natural gas liquids (NGL). And it's far from played out: as one of the largest and longest-running enhanced oil-recovery operations employing CO2, Rangely continues to make some 14,500 barrels of oil and 1,400 barrels of NGL per day. Indeed, the field has already produced nearly 100 million barrels of incremental oil and NGL from its CO2 flood, and Rangely has tens upon tens of millions of barrels to go.

"Overall recovery, just on the plan that we are on now, will be 51% of the 1.9 billion barrels of OOIP," says Jeff Roedell, Chevron's Rangely technical team leader. That will push Rangely's cumulative recovery to 965 million barrels. "We are 35 million barrels away from being a billion-barrel field, which is an elite class. We are certainly looking for additional opportunities to take us over a billion."



Modest beginnings

Rangely's first years weren't exactly predictive of its present world-class status. Oil was initially discovered in this remote corner of Colorado in 1901 in the shallow Cretaceous Mancos Shale, at a depth of about 700 feet. During the next three decades, more than 100 shallow wells tapped fractured shale at depths down to 1,700 feet. Through 1955, they produced about 4.5 million barrels of oil, a respectable but hardly awe-inspiring volume.

The immense treasure in the Weber was not found until 1933, when California Oil Co. (now Chevron) struck pay at 6,335 feet in its Raven A-1 test. Nothing was done with the isolated deep find until World War II, however, when the nation suddenly needed all the oil it could pump.

Development began in earnest at Rangely in 1944. In addition to California Oil, the early owners included Stanolind, Texaco, Continental Oil and Phillips Petroleum. By the close of 1945, more than 180 wells had been drilled into the Weber. By 1949, the 20,000-acre field supported nearly 480 wells on 40-acre spacing. In 1950, gas reinjection was started to maintain reservoir pressures.

Rangely was developed as individual leases until 1957, when through a great deal of effort a federal unit was pulled together. The impetus to form the Rangely Weber Sand Unit was the field operators' desire to waterflood the reservoir. Chevron was elected operator, and it started waterflooding operations in 1958. Expansions continued, along with pattern adjustments and other enhancements, to 1983. Also, between 1963 and 1985, much of the field was put on 20-acre spacing. Ten-acre wells were also tried, but were not economically feasible at that time.

Primary and secondary methods together were expected to retrieve 42% of the OOIP, which would close out the field at just under 800 million barrels.



EOR begins

But, a much bolder move was in the works. Chevron designed a miscible CO2 project for the great field. Then, as is the case today, most CO2 floods in the U.S. were in the Permian Basin. Major operators in West Texas had built a network of pipelines to bring CO2 from natural-source fields in New Mexico and southern Colorado south to their mature oil fields.

Chevron had an industrial source in mind for its project, however. The company wanted to use CO2 from Exxon's Shute Creek processing plant on the Moxa Arch in southwestern Wyoming. To get the gas into Rangely's Weber reservoir, it had to be transported from Shute Creek, near LaBarge, 48 miles to Rock Springs. Beginning in 1984, Chevron built a 129-mile pipeline that picked up CO2 from that point and moved it to Rangely. It also constructed recompression and NGL-extraction facilities at the field.

Just as Chevron kicked off CO2 injections in 1986, oil prices nose-dived. The partners drastically slashed operating costs, but persevered with the project. "The company and the working-interest owners had a vision where they thought the CO2 process would be best for Rangely, and they stuck with the plan even through hard times," says Roedell.

"And it's paid off. The project has been a technical and an economic success."

The main part of the field was put under CO2 flood, and the flood was gradually expanded. By 1992, nearly all the interior of the field was on CO2, and field production began to decline at around 8.5% per year.







WAG technique

Chevron uses a water-alternating-gas (WAG) process at Rangely. In this technique, slugs of water and CO2 are alternately injected to the reservoir.

Natural gas is produced along with oil and water, but the gas in the recycle stream is highly contaminated with CO2. Chevron extracts NGL and reinjects gas into the reservoir.

Today, Chevron has 391 active producers and 263 active injectors at Rangely. The majority of the injectors are WAG, and have special material considerations. They feature stainless steel in the wellheads and portions of the meter runs. Tubulars and downhole equipment are typically coated either with fiberglass lining or plastic coating. Special O-rings and packer rubbers are used that will not be degraded by the CO2.

In 1986, Chevron was purchasing 75 million cubic feet of CO2 per day to put into Rangely. That was scaled back from its original plan to inject 200 million per day. "Through time, when oil prices hit a bottom, one of the levers that we pull to help control costs is the volume of CO2 that we purchase," Roedell says.

Rangely CO2 purchases peaked at 150 million cubic feet per day in 1991. Because CO2 is miscible, it goes into solution with the other fluids in the reservoir. About 40% of the cumulative CO2 that has been injected is retained in the Weber reservoir. At present, Chevron purchases about 40 million cubic feet of CO2 per day, and injects 180 million of purchased and recycled CO2 into the Weber.

The company picked the WAG process for Rangely for several reasons. The approach helps limit both the volumes of water and recycled gas that are produced. "In the WAG process, produced water is put back into the reservoir in alternating slugs with the gas. And, by injecting the slugs of water, we can control the volume of gas we produce on the other side," he says.

Also, the process addresses the problem of premature CO2 breakthrough. The water slugs act as diversions and help to improve the sweep of the CO2 flood.



Operating challenges

While CO2 floods can recover many millions of barrels that would otherwise be left in the ground, they are extremely complicated, long-term processes, and not for the faint-hearted. These tertiary projects are high-maintenance. Reservoir engineers must continually manage where gas is injected and how oil is recovered. "Continuing to get those extra couple of percent of recovery is our challenge."

Companies running CO2 floods have to monitor injection volumes and run injection profile surveys to find out where their CO2 is going. "We need to know where it's going in the Weber, and to make sure it's not going anywhere but the Weber," says Roedell. Floods are under high surveillance, so any problems that develop can be identified early.

CO2 floods also carry high operating costs. This type of recovery is very energy-intensive, and plentiful horsepower is required to recycle the water and gas. "We're very sensitive to costs for electricity and expenses such as severance taxes," he says.

One of Chevron's biggest challenges is controlling the injection vertically. Rangely's thick Weber reservoir is stratified sandstone that has up to six discreet producing layers. Vertical permeability barriers can play havoc with a recovery plan.

The company has applied many approaches to overcome this issue through the years. It drilled horizontal production wells, which it determined were not as economic as vertical producers. It converted some horizontals to injectors, however, and this has turned out to be fairly successful.

Gel treatments were also employed. Gels are pumped from the surface, and they block off high-permeability zones or streaks. "In that program, we attacked the worse wells first, but as the program went along, we ran out of strong candidates and the economics declined."

It has also worked heavily with selective injection (SI) equipment, in which a series of packers and mandrills are run into the wellbore. Chokes are set and fluids can be forced into various zones. The equipment works well, but problems arise as time goes on.

"It's expensive to run and it's even more expensive to get out of the wellbores later." Now, Chevron reserves the use of SI equipment for simple applications.

"There are a lot of ways we try to tackle vertical injection, and there are advantages and disadvantages to all of those. Some may be cheaper up-front but don't last as long; others may be more effective but they have more costs down the road."



A rejuvenation

While the trend in some mature CO2 floods is to expand injection vertically, to pick up reserves in unswept transition zones, this isn't the case at Rangely. "Our transition zone is not very thick, and we're already injecting through most of it. We don't have a big opportunity in this approach."

Instead, Chevron is pushing the areal reach of the flood. In 1998, the major stepped out into regions around the edge of the field, mostly in its northwest periphery. Since then, it has been focusing on expansions in the north, northwest and western side of the field. The projects have noticeably shallowed out Rangely's production decline.

In 2005, the company also drilled 16 wells to increase density to 20 acres in some previous expansion areas that had remained on 40-acre spacing. It drilled another dozen infill wells in its CO2 expansion areas.

Current work centers on the west flank, where it is driving the flood clear out to the unit boundaries. "We're also doing an expansion right now in the northwestern corner, along the northern edge out to the unit boundary."

And Chevron is still injecting into some of the more mature parts of the field. The eastern part is a lot slower to process because the rocks are much tighter. "Incremental oil will be coming out of that area for many years to come," he says.

At present, the recovery factor for the CO2 flood is 5.3%. "Overall, we're expecting ultimate incremental recovery will be 7% to 7.5% from the CO2 flood. We have more expansion projects in mind and a good deal more oil to get out."

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