As a producer, Credo Petroleum Corp. is focused on oil and gas plays in the Anadarko Basin of northwest Oklahoma, the Texas Panhandle and along the Central Kansas Uplift. The 30-year-old, Denver-based company operates some 130 wells, owns nonoperated working interests in 314, and has overriding royalty interests in another 1,167.

But that’s just part of the story. Unlike most producers, Credo has a second strategy—to seek old, seemingly played-out gas wells and breathe new life into them with its secret weapon.

In 1997, the small-cap company set out to conceptualize, engineer, develop and patent a fluid-lift technology to recover significant amounts of gas stranded in low-pressure reservoirs. The system, Calliope, is named for the musical instrument that produces sound by sending steam through an arrangement of pipes.

The new generation of fluid-lift technology for loaded-up gas wells has now been used in more than 25 wells in Texas, Oklahoma and Louisiana, with notable results.

“It substantially lowers flowing bottomhole pressure, compared to most other production methods. It does not rely on bottomhole pressure to lift fluids,” says James Huffman, Credo chairman and chief executive.

The technology is particularly competitive on wells deeper than 8,000 feet, where many other fluid-lift systems begin to lose efficiency. It is best suited for deep gas wells that don’t produce large amounts of fluid and for deep wells that are difficult to pump with a pumping or plunger-lift unit.

Plungers require reservoir pressure to operate. When reservoir pressure falls below a certain point, they no longer work. Also, in deeper wells, plungers can be inefficient because fluid gets around the outside of the plunger. By the time the plunger surfaces, substantial amounts of fluid often fall back down into the well.

“Pumping units can gas lock and generally don’t work well unless there is a lot of fluid in the well,” says Huffman. “That often gives us an advantage with gas wells that produce low fluid volumes.”

Gas lock occurs when the plunger of the pump is in the down position and begins to move upward. At this point, the traveling valve within the plunger is closed, but a low-pressure area can form in the void below the plunger. High pressure may then force the standing valve to open. When that happens, the void within the pump is filled with gas instead of with fluid, or part of the fluid entering the low-pressure area within the pump flashes (changes from a liquid to a gas), causing the pump to halt, or lock up.

To work, the fluid-lift system captures fluids inside a set of tubes above a standing valve. The tubes are then pressurized, much like a pellet gun, by using the compressor. The compressed gas is isolated from the reservoir and efficiently lifts the captured fluids out of the well. Virtually all of the fluid is evacuated from the tubes by the gas sweep.

The Calliope equipment is powered by an on-site gas compressor, has a solar panel to power the controls, and employs telemetry for off-site monitoring.

“The system will move as much as 50 barrels of fluid per day,” Huffman says. “Wells that make more fluid than that are generally not candidates unless they have high bottomhole pressure or unusually large casing and tubing.”

Most Calliope applications to date have been on wells that are owned and operated by Credo. As other operators give up on wells as either dead or uneconomic, Credo acquires the wells for rejuvenation.

After installing Calliope, incremental gas reserves on Credo’s non-research-and-development applications have averaged about 1 billion cubic feet (Bcf) per well, and initial production rates average 270,000 cubic feet per day. For those applications, finding and development costs averaged about $0.50 per thousand cubic feet (Mcf) and operating costs averaged $0.50 to $0.60 per Mcf, making the all-in cost of incremental gas delivered into the pipeline about $1 per Mcf.

Case studies

Where Calliope plays, it pays. Take, for example, a three-well Springer reservoir in western Oklahoma. All three wells, the Rowe, Jensen and Bradford, had been productive.

When Credo entered the play in 2001, Rowe was producing about 175 Mcf per day from the best structural position in the reservoir. Jensen was dead with tools left in the well.

Bradford is the structurally lowest well at about 13,000 feet, considerably down-dip from Rowe. To rejuvenate Bradford, the previous operator had used coiled tubing and compression, but all efforts proved to be ineffective. The operator declared the well dead and recommended it be plugged.

Enter Credo. The company purchased Bradford and installed Calliope to rejuvenate it. Credo used the existing 2.875-inch tubing and did not remove the packer. The well immediately began producing commercially. Water saturation near the wellbore was reduced, and the rate steadily improved to 210 Mcf per day.

The well paid out in 24 months and has produced about 500 million cubic feet of post-rejuvenation gas to date. That amounts to about 50% more gas production than from Rowe, despite Rowe’s preferential structural position and initial production advantage.

Elsewhere, in a two-well Morrow reservoir in the Texas Panhandle, Credo acquired the Fee well, which had played out and been dead for two years. The other, structurally higher, well was producing only 75 Mcf per day at the time. Reservoir pressure had depleted to 200 psi in the 11,000-foot-deep target zone.

Credo installed Calliope in the existing five-inch casing and Fee came back to production at 300 Mcf per day. The well paid out within 12 months and has since produced some 400 million cubic feet of gas, about three times more gas than the structurally high, offset well.

“In a third case study, the results are nothing short of outstanding,” says Huffman. In 1998, Credo purchased the Carroll well in central Oklahoma. It had previously produced from the Morrow reservoir at 11,800 feet.

“The reservoir pressure had fallen to 290 psi and the Morrow zone in the Carroll well was stone dead for five years,” says Huffman. “The operator tried to remove liquid with coiled tubing and a compressor. When that failed, he tried to plug off the Morrow formation, by injecting polymer, before attempting a recompletion in the deeper Springer formation.

“The Morrow zone was not only dead, it had been abused,” he says. After the unsuccessful recompletion attempt, the well was scheduled to be plugged. This was after five years of noncommercial activity. “The operator agreed to sell the well to us.”

The dead well was in the same reservoir as the nearby Wilkerson well, which at the time was producing a meager 20 Mcf per day. Credo installed Calliope on Carroll, using the existing tubing with a coiled-tubing transition to fit the 2.875-inch liner.

“We took that old, dead well that nobody was able to do anything with, and used Calliope to return it to production at 650 Mcf per day. The well has made 1.1 Bcf of gas for us since we installed the Calliope system. That ranks it in the top 5% of all the gas wells in the onshore U.S., based only on incremental Calliope-enabled production.”

Since Calliope was installed, the Carroll well has produced about 10 times more than the offsetting Wilkerson, and the meter is still ticking.

Today, Carroll is producing about 200 Mcf per day, while production on Wilkerson has declined to about 10 Mcf per day. Incremental gas reserves on Carroll are now estimated to total some 1.4 to 1.7 Bcf.

“The Bradford, Fee and Carroll wells are all good examples of how this technology can liberate stranded gas from wells that were given up for dead by other operators,” says Huffman. “With Calliope, those wells have produced over 4.4 Bcf and we estimate that they will ultimately produce over 12 Bcf.”

Shale-gas applications

Credo is also looking for opportunities to try Calliope in a horizontal wellbore in a shale-gas play. “I think it would have a great application in those types of wells, but we haven’t tried that yet. All the shale-gas plays are making some water and there are liquid-loading problems.”

Pumping units and plunger lifts generally do not work in the horizontal section of a wellbore, but there is no reason Calliope will not go horizontal, he says. It works with coiled tubing and only one small downhole valve, which moves only a few inches in either direction.

Although for most applications Credo buys wells for its own account and installs Calliope to bring them back to life, the company has used the technology for some joint ventures with privately held operators and is considering proposals to license the technology.

Huffman adds that, in most cases, the fluid-lift system is better installed sooner rather than later. “In our business, people generally lean toward the least expensive options first, which can end up costing a lot more time and money, compared with taking a longer-term view by installing Calliope at the onset of liquid loading.”

For example, an average well with liquid-loading problems, where other rejuvenation options have been exhausted, will produce about 1 Bcf of reserves after Calliope installation.

However, if Calliope is installed as the first rejuvenation method, the well can reasonably be expected to produce an additional 30% of incremental reserves, on top of the 1 Bcf. “When we installed it at the onset of liquid loading, the other steps were unnecessary, so it saved us money and manpower in the long run.”