(Tech Connections Column, May 2007, American Oil and Gas Reporter)

The University of Kansas’ Tertiary Oil Recovery Project hosted its 17th biennial Oil Recovery Conference in April. Many lessons have been learned and shared through the years, and the process continues. Readers are encouraged to contact KU’s Rodney Reynolds (reynolds@ku.edu) for information.

More than 1,000 chromium(III)-carboxylate/acrylamidepolymer gel water shut-off (WSO) treatments have been applied during the past six years in Kansas Arbuckle wells. Most of these are significantly higher volume (thousands of barrels of gel) than early gel treatments. Although decreasing water production and associated operating costs are important, the primary business driver has been incremental oil production. Whether fractures or karst features control fluid flow, wells that are in good pressure and fluid communication with the underlying aquifer make the best WSO candidates. Bob Sydansk, Sydansk Consulting Services LLC, offered some intriguing thoughts on the mechanisms for these treatments.

Gel treatments are primarily placed in treated fractures (or possibly other high-permeability reservoir anomalies) and only minimally leak into matrix rock. The gel blocks water coning through the fractures. Sydansk maintains that some gravity segregation of the gel within the fractures occurs. This provides a flow path for oil from the far well-bore region. Accordingly, adjusting the crude oil over-displacement process “on the fly” may be as important as adjustments while placing the gel. There also is consensus that more aggressive pretreatment acidizing correlates with higher incremental oil production. Acidizing targets the fractures and not the matrix.

TORP’s Paul Willhite presented results on a few field treatments that tested disproportionate permeability reduction concepts. Following a conventional gel treatment with limited post-treatment flush, the well is shut in for a couple weeks and then a small volume of crude oil is injected at low rates and pressures to dehydrate the emplaced gel and create oil flow paths. Results were inconclusive.

Brett Davidson with Wavefront described its Powerwave fluid-flow enhancement technology. This is an injection technology where a volume of liquid is forced into the reservoir with each impulse at high acceleration by a downhole device. Repetitious impulses create extremely high mixing in the near well-bore environment, and the injected fluids will be dispersed in the porous medium. The displacement front progresses much more uniformly, reducing viscous fingering and allowing fuller reservoir contact. The process can be used short term for well stimulation or long term in injectors to improve injectivity. It is a proven technology with more than 175 single-well applications and six field-scale applications since it was introduced in 1998.

Operational factors include amplitude, rise time, displacement efficiency, fluid injection rate and stroke recurrence rate. Regarding amplitude, one should not significantly exceed the local fracture pressure. Rise time must be optimized for a given permeability. It is best to use the pulse frequency at which a pore liquid initially begins to behave incompressibly. This is affected by liquid and solid properties. Wavefront is using Powerwave in its Rogers County, Ok., project, which produces from the Bartlesville formation. Tests there indicate a two- to threefold improvement in injectivity, but it is too early for fieldscale results.

A presentation by Kent Pennybaker of River City Engineering highlighted another Kansas hydrocarbon resource: low quality natural gas. Nearly a third of Kansas fields have high enough nitrogen and helium concentrations to lower Btu content below 950 Btus an Mcf. Nitrogen-to-helium ratios in the Hugoton area, where largescale helium recovery occurs, are generally constant at 40-to-1. Operators should note that data show other producing trends in Kansas exhibit similar, relatively constant but much higher nitrogen- to-helium ratios of 10-to-1. This higher ratio persists from the Central Kansas Uplift to the Oklahoma border. This represents an opportunity for producers since experience has shown that smallscale nitrogen facilities (1 million cubic feet a day or less) can be economic with gas prices above $1.50-$2.50 an MMBtu.

There are five general technologies available: cryogenic, adsorption, membrane, absorption, and raw use. Cryogenic facilities are proven but capital costs are high and the plants are complex. Adsorption–commonly referred to as pressure swing adsorption processes–can trap the nitrogen while allowing the methane to pass or vice versa. Extremely small-scale applications down to 100 Mcf a day are possible.

Very small facilities also are possible with membrane plants. Absorption utilizes a chilled circulating fluid that absorbs methane in a contactor tower and releases the methane during regeneration. Like cryogenic plants, capital costs are high and the plants are complex. For many situations, raw use such as generating electricity can be the most economic option. There are gas engines and gas turbine-driven generators that will burn very low-quality gas.

What participants took from the Oil Recovery Conference is that there is more than one way to profitably recover hydrocarbons in mature basins, but one has to work at it.