Summary The use of crosslinking agents to improve viscosity in polysaccharide polymer fluids is a widespread practice in hydraulic fracturing. The viscosity obtained from the use of a particular crosslinking agent depends entirely on the parameters of the in-situ chemical reaction to be performed at the wellsite. The major parameters encountered, such as concentration of polymer and crosslinking agent, pH, temperature, and shear regimen, will dictate the apparent viscosity of the product generated by the reaction. A mechanistic model for this crosslinking reaction is presented along with a description of the general effects of concentration, pH, temperature, and shear levels. Macroscopic observation of an ideal "complexed" gel is discussed using the most significant reaction parameters. Data show that the rheological properties of a crosslinked fracturing fluid are time-dependent and vary widely, depending on the reaction parameters to be encountered at the wellsite during a fracture treatment. Introduction Since their introduction as stimulation fluids to the industry in 1968, the use of crosslinked fracturing fluids has grown steadily. Today, they account for approximately 35% of the total volume of aqueous gels used in stimulation treatments. These fluids provide several advantages over non-crosslinked gels:greater viscosity per pound of polymer,friction reduction,wider fractures,better sand transport,more viscosity in high-temperature applications, andversatility and adaptability to a wide variety of treatment conditions. Before a comparison between various crosslinked fluids can be made, it should be recognized that the rheological data are highly dependent on the experimental conditions under which they were obtained. One of our primary objectives is to emphasize the importance of some of the experimental conditions. There are many water-soluble polymers that can be crosslinked with a variety of crosslinking agents to form fracturing fluids. However, only a rather limited number of polysaccharide gelling agents have found extensive commercial application in fracturing fluids. Table 1 shows the many chemical elements that have been used successfully to crosslink polysaccharides materials. Each element has its own unique pH. oxidation state, and concentration range for optimal crosslink formation. Although many metals require specific salt and/or chelated derivatives as the delivery form, the resulting crosslinked gels exhibit many common properties. This paper is restricted to the natural polysaccharides (cellulose and guar gum) and their nonionic derivatives (Fig. 1). We use examples of crosslinking agents from Table 1 to illustrate the effect of shear, pH. temperature, and type of coordination on the general properties exhibited by crosslinked fluids. Experimental Procedure Viscosity measurements were made on a Model 50 or Model 39 Fann viscometer using a variety of bob and sleeve combinations as described in Ref. 10. The crosslinking reactions were performed by first prehydrating a 0.48 to 0.72 wt% solution of the base polymer (40 to 60 lbm/1,000 gal) in a blender for 30 minutes in the presence of an adequate buffer concentration to control pH. The ph-control agents used as buffers include fumaric acid, hydrochloric acid, acetic acid, formic acid, sodium bicarbonate, sodium carbonate, and sodium hydroxide. JPT P. 315^

Resin coated proppants (RCP's) have been used to prevent proppant flowback for several years in the hydraulic fracturing of oil and gas wells. Proppant flowback problems, however, still exist with the commercially available RCP's and several operators report failures around the world under a variety of well conditions. To date, a clear explanation of the RCP failure mechanisms and the conditions under which failure occurs has not been presented in the industry. A correlation between the unconfined compressive strength (UCS) of RCP materials and the proppant flowback potential has been previously presented by Vreeburg, et al. This paper will present the results of a study on a variety of factors which effect the proppant flowback of a number of commercially available RCP materials. These factors include 1) the effect of fluid pH (7 to 12) and fluid type (KCL, seawater and a HPG/Borate fracturing fluid), 2) the effect of fluid/proppant slurry shear, 3) the effect of closure pressure during RCP curing, 4) the effect of stress cycling and 5) the effect of downhole flow conditions on proppant flowback. Introduction Since the introduction of proppant fracturing in 1949, it has become a tool widely used by operating companies to increase both oil and gas well deliverability and ultimate hydrocarbon recovery in a number of reservoirs around the world. Technological advancements in hydraulic fracturing which have taken place over the years have allowed the practitioner to increase the utilization of this tool to a broader scope of application than was originally envisioned. A case in point is the recent utilization of hydraulic fracturing in high permeability reservoirs which had only ten years earlier been thought to be very poor candidates for hydraulic fracturing based on both treatment problems anticipated (i.e., well screenouts during treatment due to excess fluid loss) and low productivity improvement following the treatment. The development of modern hydraulic fracture design programs, mixing equipment with the capability of pumping high concentrations of sand and new high efficiency fracturing fluids have contributed greatly to these successful hydraulic fracture treatment results in high permeability reservoirs. There are still several remaining technical advancements which are being addressed in hydraulic fracturing to allow this tool further utilization in the industry. P. 171

In hydraulic fracturing, the temperature at which a polymer is to be used determines the break mechanism and the breaker used for its degradation. The polymers most commonly used in fracturing were degraded under a variety of conditions and their resulting flow impairment characteristics were measured in 20/40 mesh sandpacks. Enzyme breaker was used for the low temperature tests (120°F), oxidizing breaker was used for the intermediate temperature tests (180°F) and thermal degradation processes were used for the high temperature tests (275° – 400°F). The polymers evaluated were derivatized cellulose (0% w/w residue), derivatized guar gum (1-2% w/w residue), intermediate residue guar gum (5-6% w/w residue) and guar gum (8-10% w/w residue). The relative residue volumes for these polymers were determined and compared to their actual flow impairment values. The effect of polymer loading on the relative flow impairment was also determined for these polymers as a function of break temperature.

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The relative reduction in both formation permeability and fracture flow capacity caused by the residue remaining after water based fracturing fluids are broken is often very important in the final selection of a fracturing fluid.Therefore, it is important to understand some of the factors which can affect the amount of residue produced from the gelling agents and the changes in relative flow which may result.One of the most important factors in determining the amount of residue produced is the type of gelling agent used as a viscosifier. In general, the following order is commonly used as a guideline to determine the relative residue content of a number of gelling agents: guar gum > derivatized guar gum > derivatized cellulose.Test results have shown that this relative order Can be changed by varying the break time, breaker concentration, cross1inker and pH of the fluid system. For example, data has shown that a cellulose fluid can potentially cause more reduction to both fracture flow capacity and formation permeability than commonly used derivatized guar gelling agents.The information which will be presented in this paper will contain results of an investigation into the effect of breaker concentration, breaker type, break time, crosslinker and pH of a fluid system on the relative flow reduction caused by a variety of water based fracturing systems. Fluids prepared with standard guar and cellulose gelling agents broken at low temperatures in a variety of porous media have been investigated. The importance of evaluating an entire fracturing fluid system and not just the specific gelling agent to determine which fluid should provide the optimum production increase from a hydraulic fracturing treatment will also be presented.References and illustrations at end of paper.