This paper presents a method to control fracture height growth through the selective placement of artificial barriers above and below the pay zone. These barriers are created prior to the actual treatment by pumping a mix of different size and density proppants with low viscosity carrying fluid, that allows fast settling of these proppants or, if desired, flotation to the top of the fracture channel or both. Typically a viscous pad is pumped to create a fracture channel. This pad is followed with 5-10 cp fluid slurry carrying a mix of heavier proppant that settles to the bottom of the fracture channel and a light proppant that rises to the top of the fracture channel. The proppant slurry is allowed to bridge at the top or the bottom tip of the fracture inhibiting further growth of these tips. The actual treatment following this barrier placement is thus focused through these barriers confining itself within the barriers and resulting in a longer extension within the pay zone. Such controlled fracture height allows further optimization of fracture length by reducing or increasing the amount of proppant as the design calls for. Two case studies are presented in this paper from two formations known to suffer from fracture height growth. This method is universally applicable to any formations where height growth at the cost of extension is suspected. Introduction For optimized well performance, adequate fracture half length and fracture conductivity are the two most important parameters. Generally, the importance of fracture half-lengths prevails over that of fracture conductivity in low permeability formations. it is quite well established that the lower the permeability, the longer is the fracture half length requirement. Although for low permeability formations if the reservoir pressure is high, the fracture conductivity may also need to be improved. This paper discusses the problems related to the fracture extension due to height growth and a very effective method of mitigation of this problem within some practical limitations. Warpinski, et al. (1980) showed the predominant influence of barrier in-situ stresses in the containment of height growth of induced hydraulic fractures. Recently with the emergence of three dimensional fracture models, other authors also confirmed Warpinski, et al.'s conclusions. It can be said that in the absence of adequate stress barriers, hydraulic fractures grow uncontained into the barriers at the cost of extension. Two dimensional fracture geometry models often undermine the effects of height growth resulting in an erroneous prediction of fracture length. Production performance or post fracture build-up tests often indicate this severe curtailment of fracture half lengths from designed. The problem is quite prevalent in some of the prolific hydrocarbon-producing formations in the Rocky Mountain region such as Codell, Frontier, Dakota, Mancos, etc. to name a few. Thus, an effective method of mitigation of unwanted height growth problem can be very useful in the optimization of fracture half length for maximum return on the stimulation investment. Fracture height containment has been studied for more than two decades by different authors.

A study was made of stimulation treatments being conducted in the Frontier Formation, southwestern Wyoming. The purpose of the study was to determine why some treatments were successful while others resulted in inadequate production increases. production increases. The initial step was to gather as much data as possible from treatments previously pumped. Although this information helped to pinpoint trends in previously pumped. Although this information helped to pinpoint trends in the field, it was of little value in determining the cause of stimulation failure. In an effort to get more information, minifracture treatments were pumped on new wells to determine fracture parameters. Bottom-hole pressures were also monitored during all pumping operations. Applying pressures were also monitored during all pumping operations. Applying current technology to these data led to a better understanding of how the fracture was propagating. On previous jobs, post-fracture temperature logs consistently indicated "in-zone" treatments, which could not be supported by the interpretation of bottom-hole treating pressures. The assumption that fractures were confined in the pay zone was also disproved by post-fracture, pressure buildup tests. These tests indicated that post-fracture, pressure buildup tests. These tests indicated that effective propped fracture lengths were far shorter than calculated fracture lengths. The key to successful stimulation was found to be controlled fracture height throughout the fracture. Our goal was to build an artificial barrier the length of the fracture using 100-mesh sand. Other techniques applied included lower pump rates, lowering breakdown pressures to avoid unwanted fracture geometry, and gut shooting the pay zone to predetermine the point of fracture initiation. Production results to date show a definite increase in the percentage of Production results to date show a definite increase in the percentage of successful stimulation treatments. Introduction A field study was performed to evaluate fracture stimulation treatments. After-fracture production rates were unpredictable and future drilling in the field was questionable from an economic viewpoint. The procedure to analyze the problem can be divided into three steps:analyzing old well-treatment data and charting production rate and treatment information by location within the field,applying proven completion techniques in the field to new wells that were ready to be completed andusing analysis methods presented by Nolte and Nolte and Smith, to determine how the fracture was propagating, and also to determine if changes in treatment design were yielding the desired effects. HISTORY OF PREVIOUS TREATMENTS The field had gone through a natural evolution in fracture treatment design over a period dating back to 1975. Early treatments were performed using a prepad of alcohol and carbon dioxide, followed by a prepad of linear gel prepad of alcohol and carbon dioxide, followed by a prepad of linear gel led water and carbon dioxide. The main fracture treatments consisted of up to 500,000 gal of high-pH, crosslinked, gel led water using a guar-gum gelling agent, and 100-mesh and 20–40 mesh volumes approaching one million pounds total sand. To date (1982), most of these early treatments still pounds total sand. To date (1982), most of these early treatments still maintain the highest production rate in the field. Later treatments (1976 to 1978) utilized a modified guar-gum gelling agent (HPG). Both prepads, along with the 100-mesh sand, were phased out. Other treatments evaluated included gel led oil fractures and emulsion fractures. Production results were less than favorable and, by 1979, activity in the Production results were less than favorable and, by 1979, activity in the field had slowed. After reviewing these treatments and completion techniques, observations included the following.