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.

To maximize return on investment, many operators choose to re-fracture existing wells as an economic alternative to drilling new wells. While it may improve ultimate recovery, re-fracturing of wells with multiple producing zones can be challenging. Several techniques are available in the market place; each having its own limitations and benefits. The technology discussed in this paper, already implemented in the Western Hemisphere, uses a guar-based gelled fluid for temporary zonal isolation in the annulus. The need for a cost-effective solution for re-fracturing, without using a packer or other downhole isolation tool was identified in the Changqing oilfield in China. The objective was to prove the concept of using a gelled annular isolation technology for re-fracturing in this oilfield for applicability in the Asia Pacific region. Two candidate wells were selected for re-fracturing based on previously completed methodologies and observed production declines. A two stage vertical well was selected for proof of concept. The original completion used a 5 ½-in. casing, applying multi-stage sand jetting fracturing. The application of the gelled polymer system for re-fracturing utilized the 5 ½-in. casing as an outer tubing and implemented a 3 ½-in. inner string to create an annular space for isolation. The gelled fluid was pumped into the annular space between the inner tubing string and the original casing to isolate existing perforations in the two stages. After the re-fracturing treatment was completed, the gel was broken down and the inner string removed. Before the job was pumped, laboratory testing and simulation concluded that the gelled fluid would be placed within the pump time of the job and hold for the expected time frame of the fracturing operations. This testing provided detailed operational guidelines on placement time, pump rate, fluid shear rate at bottom hole temperature within the constraints of the wellbore architecture before committing to pump the job. The fluid was successfully placed and maintained isolation during fracturing stages. The inner string was removed from the hole following the breaking of the isolation fluid. The novelty of this work included the application of using a guar-based gelled fluid as a temporary annular isolation pill in a re-fracturing application in China. In addition, this work proved that an inner completion string could also be temporary and therefore removed after the job was completed to ensure that maximum access to the reservoir was achieved. Finally, this is the first cost effective and simple re-fracturing methodology introduced to this area of the Asia Pacific region.