A series of tools has been introduced that effectively extends reservoir life by using fluid dynamics technology to eliminate flow interruptions caused by liquid slugging in the system. In many cases, implementation of the technology has eliminated the requirement to routinely pig the lines to remove liquid accumulations from low spots, saving considerable expense. A variation of the technology has been extended to downhole completion systems and has been found to reduce bottomhole flowing pressure, thereby increasing ultimate recovery of oil and gas from the reservoir.

The technology, introduced by Vortex Flow LLC of Denver, Colo., has recently resulted in the company being recognized as "Newcomer of the Year" by Platt's Global Energy, citing "revolutionary fluid dynamics technology that will extend reservoir life and potentially save customers millions of dollars."

Spin cycle

Eight different tool systems use the technology, which imposes a swirling or spinning motion to the flow stream that persists over great lateral distances to force liquids outward into a vortex, (or whirlpool effect) that hugs the circumference of the flow line while creating a clear path for gases down the center of the vortex. The applications of the technology range from surface lines to downhole tubing installations, and in addition to flow improvement have a beneficial effect in reduction of paraffin accumulation. More than 600 systems have been shipped throughout North America, and recently orders have been fulfilled from overseas clients.

The vortex flow pattern prevents liquids from dropping out of the flow stream and accumulating in sumps or low spots in the line. The result of these accumulations can be costly. Besides creating slug flow conditions, the stagnant liquid can act as a corrosion cell, creating severe localized corrosion of the line's inner surfaces. But the slug flow is the chief concern because it causes high back-pressure on the well or pump that can even translate to the reservoir itself and, at the downstream end, can damage compressors or separators or impair their efficiency.

In the well, Vortex Flow DX and DXR tools can be installed in the completion as deep as 13,000 ft (3,963 m). The DXR tool can be installed through tubing via slickline, meaning that it can be retrofitted to an existing well without the need to pull tubing.

Field experience

Early successes were recorded in the western United States. In Wyoming, Lario Oil & Gas Company had a 2-mile (3.2-km) flow line that produced 6 bw/d, 70 bo/d and 1.1 MMcfg/d. The company had to pig the line regularly, as wellhead pressure would increase quickly from 600 psi to 800 psi when slugs formed in the sumps. In winter, the problem was exacerbated by the cold weather, which caused the sumps to freeze. After installing a Vortex Flow SX tool, the line cleaned up, eliminating the need to pig it and allowing wellhead pressure to stabilize at 500 psi.

In a 10-in. gathering trunk line in Wyoming's Powder River Basin, Marathon Oil Company installed an SX tool 2.33 miles (3.7 km) upstream from a scrubber. Immediately following installation, water produced at the scrubber increased dramatically. Six weeks later, water produced at a second scrubber farther downstream also increased significantly. Field pressures have been reduced, and production gains attributed to the SX tool average 800 Mcfg/d. Thomas Smith, Marathon's senior petroleum engineer, said, "Within a couple of days after installation, we saw more than 100 bw/d at the scrubber. Over the next 2 months, average wellhead pressure was reduced 8 psi while production throughput was increasing from 3.4 MMcfg/d to 4.4 MMcfg/d."

Even complex systems benefit. A 2-mile (3.2-km) gathering lateral served four wells, also in Powder River. Two, 4-in. SX tools were installed on a line that typically displayed a 12 psi pressure drop. The wells were being produced using electrical submersible pumps (ESP) to pump off produced water using the tubing. Upstream wellhead pressure was 30 psi with gas producing up the casing/tubing annulus and subsequently into the gas gathering network. The gas had entrained water vapor that collected in natural sumps in the line. Problems were experienced almost 9 months of the year. In fall and spring, cyclic air temperature changes caused high water dropout rates. In winter, the sumps froze solid. Within a month after installation of the two SX tools, wellhead pressure dropped to 23 psi while production increased 100 Mcfg/d

In the Michigan Basin on the Bart Starr project in the Antrim Shale, water was evacuated from a trunk line and several gathering lines by installing one 6-in. SX tool and three 4-in. SX tools. The lines were experiencing significant pressure drop, and stagnant liquid sumps were suspected. Immediately upon completing the installation, large quantities of water were displaced from the line. Within a few days, however, water production stabilized at a much lower rate than previously experienced, indicating that the lines had been cleared of stagnant water.

Installation strategies

By far, the simplest installation is one where a Vortex Flow tool is substituted for an existing pig launcher. The tool requires no power, has no moving parts and uses the natural flow stream energy to create the spinning action. Tools can also be installed at the wellhead or anywhere in the line where flow boosting is needed to prevent liquid accumulations or slugging.

Duke Energy was pigging its lines in the Denver-Julesburg (DJ) Basin weekly to remove fluid accumulations. In addition to corrosion risk, the lines would occasionally freeze in winter. The company installed a 3-in. SX tool just after the sales meter and upstream of a 15,000-ft (4,573-m) flowline run. After a straightforward installation that took only 3 hours, the company experienced dramatic results. First, the requirement for weekly pigging was eliminated - the line has not been pigged since, an 18-month period. And line pressures have fallen 16%, from 240 psi to 200 psi.

Future developments

Presently, the company is expanding into new areas. This will include tool development for offshore and subsea gathering line, jumpers and tieback applications, as well as for pipelines. Demand for the downhole, through-tubing DXR tool has grown, according to Vortex Flow's Rick Davis. "The greatest pressure loss in oil and gas production operations is in the vertical column," he said. "The effect of lowering flowing bottomhole pressure is felt throughout the reservoir, ultimately increasing the amount of recoverable reserves."