This paper discusses the theoretical advantages of ultra high sand concentrations (UHSC) in hydraulic fracturing treatments. Results from several treatments are presented. For comparative purposes, results from conventional, lower sand concentration treatments are presented.
Mechanical aspects of handling ultra high concentrations of sand (10 lb/gal and greater) at injection rates from 40 co 70 BPM have been a major consideration in conducting these treatments. Sand concentrations, at these rates, have been unattainable in the past partially due to sand handling problems. The capability of handling sand under these conditions has been developed and is discussed.
It has been well establishedl,2,3,4 in the area of hydraulic fracturing that a high sand concentration in the created fracture has many advantages. These advantages relate to more complete fracture fill-up, higher fracture flow capacity, greater sand crushing resistance, greater sustained fracture flow capacity and ultimately, a potentially higher production increase and higher sustained production.
One of the problems with attaining high sand concentrations in the fracture can be the ultra high sand concentrations required in the fluid at the surface. Due to equipment and fluid "limitations in the past, many fracturing treatments were limited to maximums of 3 to 4 lb/gal for short periods of time. However, with new developments in fluids and the ability to mechanically handle sand. the ultra high sand concentrations of 10–15 lb/gal at injection rates of 40 to 70 BPM are being achieved.
This paper discusses the theory behind the use of ultra high sand concentrations, presents a comparison of conventional treatments versus ultra high sand concentration treatments, and briefly discusses the mechanical aspects of handling sand at high concentrations and injection rates.
Production increase equations have been developed5,6 which allow the prediction of the production increase expected from a given hydraulic fracturing treatment. The equation of Thinsley et al 5, indicate that the post frac production increase is controlled by the conductive fracture height in relation to the net pay interval, the conductive fracture length in relation to the drainage radius and the fracture-formation relative capacity. As shown on Figure 1, the relative capacity is a function of fracture flow capacity as compared to the formation permeability 5. A high relative capacity is desired for greater production increase for a given fracture length and also for a more sustained production increase. As reported by Coulter and Rells 2, the fracture flow capacity is related to the sand concentration in the fracture, Figure 2, and a small amount of fines (60–100 mesh size particles) from the formation or other sources can be drastically reduce fracture flow capacity, Figure 3. These results also indicated that the higher the proppant concentration in the fracture, the less effect fines would have on the fracture flow capacity, Figure 3. Also, as show in Figure 4, the present of sand crushed under given conditions is related to the concentration of the sand in the fracture 2. A higher fracture flow capacity than initially required may be necessary to main the required fracture flow capacity throughout the life of the well.
