PTTC Gathers Info On Some Recent Advances In Well Fracturing

(Tech Connections Column, April 2001, American Oil and Gas Reporter)

In its survey of independents published in the January issue, The American Oil & Gas Reporter indicated more than half of respondents noted fracturing/stimulation technologies had “the most beneficial impact on their operations.” Accordingly, PTTC began looking for the industry’s fracturing advancements, culminating in a mini state-of-the-art summary accessible through PTTC’s Web site, http://www.pttc.org. Several of these are highlighted here.

Hydraulic Fracturing Diagnostics. Both microseismic fracture mapping and tiltmeter fracture mapping can provide key diagnostic information by imaging hydraulic fractures as they are created. The FRACSEISSM microseismic fracture mapping service developed by the Gas Technology Institute and Pinnacle Technologies Inc. uses seismic receivers in one or more offset wells to detect and map microseisms generated during treatment.

Tiltmeters, another fracture mapping option, have been used to map treatments in multiple basins. A new variant developed by Pinnacle places the tiltmeters in the treated well itself, eliminating the cost of shutting in offset producers. However, use of this approach is limited to clear fluids (water fracs, acid fracs or minifracs). Through January 2001, Pinnacle has run the new array in California diatomite wells and also during an acid frac in Oklahoma’s Hunton with good results. Signals are 1,000 times greater than those obtained with tiltmeters in offset wells.

Mixing Proppant and Fluids Downhole. A Department of Energy project in New Mexico has shown that mixing proppant and fluid at the bottom of a well may lead to better, safer, lower-cost treatments. Real Time Zone Inc. (RTZ), of Roswell, N.M., used its downhole mixing technique in a 12,300-foot Morrow gas well. RTZ reports treating pressure, which would have averaged close to 10,000 psi during a conventional procedure, was dramatically less (6,000 psi tubing, 5,000 psi casing). The well, which had been scheduled for abandonment, has been producing 200-250 Mcf/d since being treated.

Water Frac Success Depends on Reservoir Selection. Since the mid 1990s, industry has experienced success with water fracs (Mitchell Energy in the Barnett Shale, Union Pacific Resources in the Cotton Valley and Austin chalk, and Anadarko in the Bossier Sand), lowering costs while achieving equal or better performance. But water fracs are not universally applicable. Experienced operators apply water fracs in the most marginal, lowest-permeability areas first and then proceed to better areas. Naturally fractured, “stiff” rocks in normal stress environments are good candidates, but optimization should be field specific.

Selecting Restimulation Candidates. GTI is finishing a multiyear study in tight gas fields on the best way to select restimulation candidates. Results indicate 15 percent of the wells represent 85 percent of the restimulation potential. After analyzing 200-300 wells in each area, GTI refraced two wells in the Mesaverde Formation in the Piceance Basin of Colorado, four wells in the Frontier Formation of Wyoming’s Green River Basin, and three wells in the Cotton Valley Formation in East Texas. Seven of the nine restimulations were considered successful.

GTI developed and tested three distinct processes for selecting restimulation candidates. Process one looked at production data and selected wells that were underperforming relative to their offsets. Process two selected wells where “less-than-best” practices were employed, using detailed well data, pattern-recognition and neural networks. Process three employed type-curve matching.

Process one identified underperforming wells, but overlooked productive wells that were good candidates. Process two provided some insights, but needs more development. Process three, while the most reliable method for identifying high-potential restimulation candidates in multilayered tight gas reservoirs, was very labor intensive.

Advanced Resources International is testing the methodology further in the Codell gas-condensate reservoir in Colorado’s Wattenburg Field. There, Patina Oil & Gas Corp. selects restimulation candidates using an algorithm that considers a weighted average of such factors as formation porosity-feet, gas-oil ratio, peak production, cumulative production, expected ultimate recovery, and differences in the ultimate recovery from offset wells. ARI will test their candidate selection methodology using only pre-restimulation data from Patina’s wells. The selections will then be compared with the actual results of Patina’s program.

The Strategic Center for Natural Gas at DOE’s National Energy Technology Laboratory is funding similar analyses that aim to provide methodologies for selecting stripper gas wells for remediation. Three projects have been initiated in the Appalachian and Mid-Continent basins based on decline curve analysis, offset well performance, and type curve analysis.

Biological Option for Removing Polymer Damage. Polymer gels used in hydraulic fracturing fluids can cause significant reservoir damage when chemical agents (breakers) don’t work as designed.  A new strategy for repairing such damage uses biological culture products specifically targeted to degrade the gel polymeric structure. One such product produced by Micro-Bac International, called Gum-Bac™, is specifically designed to degrade the carbohydrate backbone of guar gels. Micro-Bac cites an example in Southwest Texas where gas production could not be restored following an acid fracture that incorporated a complex copolymer. After treatment with Gum-Bac, the well produced over 16 MMcf during the first month, and has since leveled off to 6 MMcf a month.