New Techniques and Quality Control Find Success in Enhancing Productivity and Minimizing Proppant Flowback

Abstract

Introduction Hydraulic fracturing has yielded successful stimulation results inhydrocarbon producing reservoirs for over 40 years. In certain reservoirs, however, hydraulic fracturing does not always achieve the desired results. Insome cases, due to excess production of proppant or excess water production, the fracture treatment can cause proppant or excess water production, the fracture treatment can cause operating problems. A paper published by Robinsonet at. discussed the merits of flowing back a well on a small choke to minimize the closure stress on the proppant. In that paper, a recommendation was made to monitor the tubing pressures after the fracture treatment, and if closure timesappear to be excessive, then one should initiate a low rate flowback of the fracture fluid to assist fracture closure. Approximately 4 years ago, the initial treatment designed to use the"forced closure" technique was conducted on a Canyon Sand well in westTexas. The fracture treatment was successful, but the most surprising aspect of the procedure was that significantly less proppant was produced after the treatment when compared to other proppant was produced after the treatment whencompared to other wells in the area. In the last few years, the forced closuretechnique been used on several hundred wells in many different geologichorizons. The forced closure technique, alone, may not be the reason for success. However, the use of forced closure combined with the use of aggressive proppantscheduling and the application of "intense quality control" can lead todramatic improvements in stimulation success. Intense quality control involvesfield testing of fracturing fluids at reservoir temperature prior to pumping operations. In this paper, field results have been included to illustrate how the forced closure technique, coupled with high proppant concentrations andintense quality control, can proppant concentrations and intense qualitycontrol, can significantly increase the productivity of low permeability oiland gas wells. Most of the early applications of the forced closure technique involved theuse of foam fracturing fluids or polyemulsion fluids. As more was teamed about the procedure, forced closure was used regardless of the fracturing fluid beingused during the treatment. Experience indicates that the forced closuretechnique will work even when crosslinked fluids are pumped. By flowing the well back immediately at a low controlled rate after the pumping stops, the excess pressure in and around the fracture can help to clean up the fluids. The forced closure technique has been used in formations ranging from the tight Devonian Shales in Appalachia to the high permeability coal seams in the San Juan Basin. Table I presents a permeability coal seams in the San JuanBasin. Table I presents a list of formations that have been stimulated and then produced back using the forced closure technique. ADVANTAGES OF HIGH PROPPANT CONCENTRATIONS The advantages of using high proppant concentration has been well documented in the petroleum literature. Recent publications have shown that higherconcentrations are needed to minimize the effects of damage to the proppantpack caused by gel residue, fines and excess closure pressure. Experiencesuggests that aggressive proppant schedules will be beneficial because highsand proppant schedules will be beneficial because high sand concentrations will result in a very viscous slurry. By using an aggressive pumping schedule, much higher sand concentrations have been successfully put away than those previously pumped in similar wells. Fig. 1 is a graph that illustrates the effect of sand concentration upon the viscosity of a sand-liquid slurry. Notice that when the proppant concentrationis only 2-4 ppg, the slurry viscosity is only 10–20% larger than the liquidviscosity. However, at a concentration of 10 ppg, the slurry viscosity can be 10 times larger than the liquid viscosity. Realistically, a 50 cp fluidcarrying 2-4 ppg of sand is not a very effective fracturing fluid. The same 50cp fluid carrying 8–10 ppg will be a thick, viscous, efficient fluid. The sandis actually a viscosifier when suspended in fluid. Under certain conditions, the use of smaller mesh proppants (20–40 mesh)will provide better stimulation than achieved with larger (12–20 mesh)proppants. When smaller mesh proppants are used, they can be transported betterand pumped deeper into the fracture. Also, after pumping, the smaller mesh proppants will stay suspended for a longer period of time. Experience indicates that for low permeability reservoirs, high quality, smaller mesh proppants will normally provide optimum stimulation results. P. 889