Chemical breakers are used in hydraulic fracturing fluids to reduce the molecular weight of guar polymers which reduces fluid viscosity and facilitates the flowback of residual polymer providing rapid recovery of polymer from the proppant pack. Ineffective breakers or misapplication of breakers can result in screenouts or flowback of viscous fluids both of which can significantly decrease the well productivity.Breaker activity of low to medium temperature range oxidative and enzymatic breaker systems was evaluated, including ammonium persulfate, sodium persulfate, calcium and magnesium peroxides, and galactomannanase enzyme in linear gel fluids at temperatures from 75 o F-300 °F. Low temperature and high temperature viscometers were used to generate linear gelbreak curves with time at desired temperature. The amount of unbroken gel and residue, generated at different temperatures and breaker concentrations, was also determined using a "residue-after-break test (RAB)," for two oxidizers and one enzyme breaker, all used for similar temperature applications in the field.Viscosity measurement showed that reduction in the gel viscosity depends on both the breaker concentration and temperature. Also, increasing breaker concentration does not necessarily mean more reduction in viscosity. This paper provides a guideline of oxidative and enzyme breaker optimum use concentrations for specific temperatures in the form of breaker activity "S" curves. Enzyme breakers were found to provide a more homogeneous break and generate less residue compared to the oxidztive breakers in the resdiue-after-break (RAB) tests. IntroductionGuar is a naturally occuring polymer used as a gellant in hydraulic fracturing fluids to increase fluid viscosity. This viscosity is required to carry the porppant into the fractue after the frature has been created in order to keep it open when the pumping is stopped. Once the poppant is delivered into the fracture, the fluid viscosity needs to be reduced so that it is easy to flow back and clean-up the formation.

A field study in east Texas showed that formation water production influences polymer recovery from hydraulic fractures. This study was conducted on 10 wells located in the Cotton Valley Taylor formation. A typical fracture stimulation design included between 9,000 to 14,000 bbl of zirconium crosslinked guar gel. Detailed chemical analysis of flowback samples was used to identify the effect of formation water on polymer recovery. Polymer and chloride concentrations were measured. Water produced during flowback averaged 52 5% of the fluid pumped on the jobs, while polymer recovery during flowback averaged 35 + 6% of the amount pumped. Polymer concentration in the flowback fluid from all the wells declined over time, as chloride concentration increased. This is attributed to the production of formation water. Flowback rate has a minimal effect on polymer recovery from these wells. The results of this study are compared with those previously obtained from another low permeability formation, specifically the Codell formation in Colorado. Flowback analysis is an important tool to determine how specific reservoir conditions influence fracture cleanup. Introduction Understanding how hydraulic fractures clean-up is essential for improving well stimulation. Residual gel can damage fracture conductivity, shorten effective fracture half- length, and limit the productivity of the well. The drive to develop fluids, additives, and procedures that minimize this damage continues to be a dominant theme in fracture fluid development programs. For example, reduced-polymer and viscoelastic surfactant (VES) fluid systems minimize damage by reducing or eliminating the polymer required to execute a treatment. Fluid additives have been developed to improve polymer recovery, including encapsulated breakers and aggregate dispersants. Aggressive procedures using fibrous material to maintain proppant flowback control have also been developed to maximize fluid recovery. Still, our understanding of the fundamental physical and chemical processes governing fluid recovery from hydraulic fractures is immature. Fracture cleanup is a complex problem, and many parameters - fluid system, job design, flowback procedure, and reservoir conditions - can influence polymer and fluid recovery efficiencies. Often specific products and methods that work well in one reservoir have little effect in other situations. Well productivity is the ultimate measure of treatment effectiveness. However, it does not provide direct information on fracture cleanup. A well with poor cleanup in a relatively rich pay zone may give superior performance compared to a well which had excellent cleanup but was in a relatively poorer pay zone. Additional information besides well productivity is needed to determine how the various reservoir and treatment parameters influence fracture cleanup. Systematic analysis of fluid and polymer returns after a treatment is completed is the only method to quantify fracture cleanup. In this paper this is referred to as flowback analysis. Water production and polymer returns are determined as a function of time and/or flowback volume. The concentration of other chemical species, such as chloride ions, is also determined to provide data on the mechanisms of fluid recovery and on fluid/formation interactions. Considering this is a basic approach, surprisingly little information is available in the published literature on actual flowback analysis field studies. Only load water recovery is commonly recorded after a fracturing treatment. However, as will be discussed below, load water provides insufficient information to quantify fracture cleanup, especially if the formation produces water. P. 531^

Summary Successful fracturing treatments in ultralow-permeability reservoirs require combining the most recent innovations in fracturing technologies. Viscoelastic surfactants, foams, and ultralightweight proppants (ULWPs) have specific properties that when combined offer the unique performance required in fracturing these reservoirs. Viscoelastic-surfactant foams are particularly suited for treating ultralow-permeability reservoirs because they minimize the interfacial tension and minimize the amount of water used in the fracturing fluid. This significantly reduces the permanent retention of water and the amount of water trapped in the near-wellbore region that would impair the ability of gas to flow (Gupta 2009). Inexpensive, logistically simple, polymer-free viscoelastic surfactants provide exceptionally high viscosity under low-shear conditions required for proppant transport. They also provide excellent cleanup characteristics. Foamed viscoelastic surfactants provide increased viscosity for frac width, provide better leakoff control, and further improve fluid cleanup characteristics, particularly in low-pressure reservoirs. ULWPs provide excellent transport properties in conventional fracturing fluids with minimal viscosity, which ensures desired effective propped-fracture conductivity. Use of these ULWPs in foamed viscoelastic fluids provides fracturing treatments with optimum proppant placement and excellent cleanup. As with all successfully applied fracturing fluids, the fluid systems must be optimized. These combined systems require significant laboratory testing to characterize and optimize the fluid system successfully for the demands of ultralow-permeability reservoirs. This paper focuses on small- and large-scale laboratory testing performed to optimize these viscoelastic foamed systems in an effort to test the technical limit of this new technology for future field developments.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTo conventionally drill, complete and produce horizontal and multilateral wells with zero skin is not an easy undertaking. Much attention has been given to "best oil field practices" in both drilling and production processes, but the reality is that formation damage will often have to be addressed sometime during the life time of the well.Formation damage due to drilling and scale formation is common problem in carbonate reservoirs that can be remediated using chemical means. The success of any treatment however, requires a complete understanding of the problem and a solution that will address the majority of the damage. The solution evolves with time and experience. Extended reach intervals with variable permeability complicate the process. Reservoir and fluid characteristics, cleanup fluid chemistry, and operational considerations must always be considered.The acidizing experience and an improved understanding of how to effectively treat long and heterogeneous intervals in carbonate formations is rapidly evolving in Saudi Arabia. Water injectors, oil producers and wastewater disposal wells have been treated and are reviewed in this study. These wells have different configurations including: vertical, horizontal, extended reach, and multilateral with open hole and cased completions. Several acid placement and diversion techniques have been applied and a specialized treatment package was developed based on the latest coiled tubing and chemical diversion technologies. Laboratory studies, lessons learned and specific design guidelines from both successful and less than expected well treatments are highlighted in this work.

Summary Fracturing fluids are commonly formulated with pond water to ensure reliable rheology. However, pond water is becoming more costly, and in some areas, it is difficult to obtain. The use of produced water in hydraulic fracturing has gained increased attention in the last few years, because it could solve freshwater-acquisition difficulties and reduce disposal costs. A major challenge, however, is its high content of total dissolved solids (TDSs), which could cause formation damage and negatively affect fracturing-fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of produced water with the fracturing-fluid system and the effect of salts on the fluid rheology. Produced-water samples were analyzed to determine concentrations of key ions. The fracturing-fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay stabilizer, scale inhibitor, and pH buffer. Compatibility tests of the fluid system and its components were conducted at different ion concentrations. Apparent viscosity of the fracturing fluid was measured with a high-pressure/high-temperature (HP/HT) rotational rheometer. All rheology tests were conducted at 300 psia and 180°F with a 3-hour test duration. Further investigations to study the effect of adding chelating agents to the fluid system were also carried out. Results indicate the potential of untreated produced water to cause precipitates and, hence, formation damage. Precipitates were successfully prevented by diluting the produced water with fresh water. Divalent cations were found to be the main source of precipitation, and reduced amounts of each ion were determined to prevent precipitations. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Regardless of the concentration of monovalent cations, divalent cations reduced fluid viscosity by up to 100 cp. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. The use of chelating agents has reduced the precipitation of divalent cations and enabled the formulation of fracturing fluid at higher Ca and Mg concentrations. Some chelating agents showed the ability to complex with the boron ion and/or reduce the system's pH value; consequently, viscosity measurements indicated the breaking of the fluid viscosity after the addition of the chelating agent. This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic-fracturing operations. Maximizing the use of produced water could reduce water-disposal costs, mitigate environmental impacts, and solve freshwater-acquisition challenges.