New data enable targeted policy to lessen GHG emissions
A comparison of hydraulic fracture performance during the initial development of the Moxa Arch Frontier sandstone in southwestern Wyoming (1975Wyoming ( to 1985 through infill development in 1989 to 1991 (320-acre spacing) and 1992 (160-acre spacing) is presented. The evaluation includes 3D hydraulic fracture modeling of reflected bottomhole pressures measured on 36 wells completed in 1992. In addition, in-situ stress test results from two wells are integrated with 3D fracture modeling and reservoir simulation of postfracture well performance to evaluate the evolution of fracture treatments over 17 years of development.The results from over 200 fracturing treatments were used to quantify the effect of treating fluid and proppant type on well performance. Detailed 3D fracture modeling illustrates the effects of insitu stress and leakoff properties on fracture geometry. The results from 3D fracture modeling of 33 mini-fracs indicates vastly different fluid-loss behavior from well to well and a variation of in-situ stress within the Moxa Arch. The performance of 1992 infill wells stimulated with guar-based gels (borate and zirconium crosslinked) and sand is similar to initial development wells stimulated using guar-based crosslinked polymers and sand. However, 1989 to 1991 infill wells stimulated using CO 2 foam and intermediate-strength ceramic proppants (ISP) did not perform as well as the water-based fluids and sand treatments. Fracturing net pressure data are presented that illustrate excess pressures owing to "proppant effects" and breakdown of stress barriers during fracturing that occurs in many treatments.
Fracturing treatments using treated water and very low proppant concentrations ("waterfracs") have proven to be surprisingly successful in the East Texas Cotton Valley sand. This paper presents field and production data from such treatments and compares them to conventional frac jobs. We also propose possible explanations for why this process works. Introduction Hydraulic fracturing is the key technology to develop tight oil and gas reservoirs. Although millions of research dollars have been spent to date, much controversy remains about optimizing fracture design. Rock mechanics and fluid transport phenomena in hydraulic fracturing are still poorly understood. The processes are very complex with a host of unknowns. Measuring even one critical value such as net fracture treating pressure constitutes a difficult problem. Hydraulic fracture research and development has put a lot of effort into effective placement of propping agents to provide and maintain fracture conductivity. For this purpose the service industry has developed sophisticated fracturing fluid systems and an extensive recipe of chemical additives. The fluid system is engineered to change viscosity during its journey from the surface to the fracture and afterwards during fracture cleanup. The sole reasons for these fluid designs is to place proppant, minimize formation damage and ensure proper cleanup. In turn, the proppant has no function other than maintaining a conductive fracture during well production. What would happen though if the fracture actually retains adequate conductivity with very little or no proppant?–Rock fractures often have rough surfaces. After the fracture closes, the residual aperture distribution can be very heterogeneous in all three dimensions forming a very conductive path even at high closure stresses. - Proppant along with gel residue could actually impair fracture permeability and its ability to cleanup.–Fracture extension and cleanup is easier to achieve with low viscosity fluids. Fracture extension is the key design parameter in tight reservoirs. The above points may have a tremendous impact on the fracturing operation. Gelling agents, proppant and associated chemical additives comprise a large part of fracturing costs. In early literature, "self-propping" and "partial monolayers" of fractures has been discussed. In general though, the industry has discarded the idea. In the naturally fractured Austin Chalk the so-called "waterfrac treatments" are pumped with no propping agents. They are very successful. Why it works is still generally unknown. The hydromechanical response of natural fractures has been addressed in rock mechanics literature. It is an extremely important issue in the field of underground nuclear waste disposal. The effect of normal stress and shear stresses on a fracture (natural and artificial) dictate its conductivity. The ramifications of these forces on fracture propagation are just now beginning to be investigated (multiple fractures). Description of "Waterfracs" The following outlines the general pumping schedule (from here on, the treatments will be referred to as "waterfracs"). P. 457
So called "water-fracs" have obtained excellent results in the Austin Chalk formation of Giddings field. This inexpensive treatment uses high volumes of water but no proppant. The reasons the treatment is successful include imbibition, gravity drainage, skin damage removal, and repressurization of the reservoir to enhance recovery. Union Pacific Resources Co. (UPRC) has treated about 250 vertical and 150 horizontal wells with very high economic success rates. Incremental recoveries from horizontal well water fracs alone exceed 5 million bbl of oil equivalent (6 Mcf= 1 bbl). Introduction The Giddings (Austin Chalk) field is a large oil field located primarily in Brazos, Burleson, Lee, and Fayette counties in southeast Texas. Austin Chalk production occurs along a fairway extending from Mexico through Louisiana. The reservoir has low matrix permeabilities ranging from 0.005 to 0.02 md. The low permeability matrix is often enhanced by sparse to abundant fracturing. Natural fractures rarely extend throughout the formation vertically; subtle variations in lithology cause significant changes in fracture abundance. Thin shaly intervals or styolites can terminate small aperture fractures with most fractures stopped by shaly intervals as little as one foot thick. Gross Austin Chalk formation thickness varies from 50 to over 500 ft over the field. The best production is encountered in intervals where natural fracturing is most intense. The field has encountered various "boom" like development periods characterized by intense drilling activity followed by a sharp decrease in interest. The vast majority of Giddings (Austin Chalk) completions are located in Texas Railroad Commission District 3. As of September, 1993, there were 2,834 producing wells in the Giddings (Austin Chalk-3) field with 252 operators. Horizontal wells constitute 29% of this total with 816 wells, up from 427 wells in June, 1992. Horizontal well production constitutes more than 70% of field production. Field production declined from 92.7 MBO/D in 1981 to 25.6 MBO/D in 1987. Horizontal well activity began in 1988, increasing 1990 production to 26.4 MBO/D. Extremely active drilling has increased field production in June 1993 to 81 MBO/ D and 365 MMcf/D.
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