TORP Conference Features Ideas At Work In Kansas Fields

(Tech Connections Column, June 2005, American Oil and Gas Reporter)

The 30-year-old Tertiary Oil Recovery Project at the University of Kansas continued tradition with its 16th biennial Oil Recovery Conference in April in Wichita, Ks. Topics were widely varied, both in subject area and stage of development. Technology was a common theme.

Since 2000, operators have treated 500 Central Kansas Arbuckle wells with polymer gel water shut-off (WSO) treatments. Compared to pre-1997 treatments, operators today use improved polymer gel systems and pump larger volumes–from 1,500 to 5,000 barrels today versus a few hundred barrels then. Benefits come from increasing oil and decreasing water production in a majority of wells. A majority of treatments are economically successful, paying out in weeks to a few months. In general, increased oil production is the gravy driving economics.

Selecting good candidate wells for WSO treatments is always a concern. PTTC has captured insights about candidate selection online at http://www.pttc.org/solutions/sol_2004/536.pdf that two experts, Bob Sydansk and Randy Seright, shared in a Texas workshop. TORP field work (SPE 89464) shows that pretreatment pressure buildup data can help identify wells that do not have sufficient injectivity. Decreases in reservoir pressure seen in some wells in post-treatment buildup analyses were interpreted as confirming shut-off of a pressure source: the strong water channel.

TORP has developed a WSO treatment Web site accessible through www.torp.ku.edu where data can be accessed by location, operator or service provider. Treatment reports, well data and annotated production history plots are available. Economic results for a sample of treatments performed by the three major service providers (Gel-Tec, TIORCO and Polymer Services LLC) have been calculated using common underlying assumptions, confirming that payouts longer than six months are rare.

The jury is still out on the feasibility of carbon dioxide floods in the Lansing-Kansas City Formation in the Central Kansas Uplift. Carbon dioxide has been going in the ground in a Department of Energy-supported test since December 2003. The pilot is a 10-acre, half of a five-spot pattern with injection into the Lansing-Kansas City “C” zone. Through February, a little more than 40 percent of the planned CO₂ volume had been injected. Counting for surface losses and estimated CO₂ loss outside the pilot, this equates to 24 percent of pore volume contacted by CO₂ that is produced by pattern producers.

The good news is that CO₂ channeling is not evident and water-alternating-gas injection has not yet been required. The bad news is that response has been slow, with only the latest data showing a measurable increase in oil production. A CO₂ injectivity test in January showed that injection is being confined to the C zone with 86 percent going into low permeability zones in the C2/C3 intervals. This or the greater than expected areal heterogeneity is believed to have caused the delayed response. Data are still coming in on whether 4-D seismic monitoring of CO₂ movement will work in this application. Five of 11 planned surveys have been completed.

It has long been known that there are vast shallow, heavy oil reserves in western Missouri and eastern Kansas–up to 2 billion barrels. Historical attempts at steam flooding, intermittent steam injection, and a reverse fire flood were not economically sustainable. Shari Dunn-Norman of the University of Missouri, Rolla, reported on a DOE-supported project that explored whether horizontal fracturing and microbial treatment might be the key. Although wells have demonstrated a strong gas response, there has not really been oil recovery. Tilt meter monitoring of hydraulic fractures in two wells did confirm horizontal fractures. Other insights have been gained about performance of surface geochemical monitoring and electrical resistivity tomography.

Although small compared to some U.S. coalbed natural gas basins, Cherokee Basin CBG activity is significant to Kansas. Kansas CBG activity is now more than 450 completions a year, and 2004 production reached 13.5 billion cubic feet. This volume represents 55 percent of the decrease in production seen from the Kansas Hugoton Field. A few more years of development, and maybe coalbed gas can offset Hugoton declines.

More than 70 percent of Kansas CBG development has occurred in Wilson, Neosho, Montgomery and Labette counties. Composite curves from wells that averaged more than 50 Mcf a day for at least three years point toward recovery of 100 million, 200 million-plus and 400 million-plus cubic feet of gas within the first 10 years, respectively, for “worst,” “average” and “best” wells. Three-fourths of the development is in the Weir Pitt and Riverton coals.

Those pursuing Kansas CBG must be aware that coals are not necessarily continuous, and gas content can vary widely. Local geology is required. Looking beyond conventional CBG operations, the Kansas Geological Survey is exploring enhanced CBG/CO₂ sequestration from landfill gas and cement calcination operations.