Summary Fracturing fluids are used for transport and placement of proppants in hydraulic-fracturing operations. In the case of conventional reservoirs, sufficient fluid viscosity is needed to transport proppant. An ideal fracturing fluid should possess enough viscosity to suspend and carry proppant. After the proppant placement, the fluid viscosity should drop to facilitate an efficient and quick fracture cleanup. This ensures adequate fracture conductivity. Most of the fracturing fluids used in these operations are dependent on crosslinking reactions between polymers and crosslinkers. Breaker technologies such as oxidizers, enzymes, fluoride compounds, oxides, vitamins, and decrosslinking agents are used to break the crosslinked polymer-based gels. These materials are added as components of the initial fracturing-fluids recipe. This paper will focus on the available breaker technologies used for degrading and cleaning up fracturing fluids used for conventional reservoirs. Each breaker has its own operating mechanism and window of application in terms of temperature and pH. The design and selection of a breaker package will first require an understanding of how the fracturing fluid forms. The current review reveals the crosslinking mechanisms of various fracturing fluids. These include the crosslinking of biopolymers with borates, the crosslinking of synthetic and biopolymers with metals, and the crosslinking of phosphate esters with metals. In the acidizing of carbonate reservoirs, the use of viscous fluids is needed to allow diversion of acid to lower-permeability paths. Moreover, the high viscosity retards the reaction between the acid and the rock, and this ensures deep penetration of the stimulation fluid. In this application, the viscosity develops as a response to the change in pH. Hydrocarbon fluids are used for hydraulically fracturing water-sensitive formations. Each of the aforementioned fracturing fluids has its own suitable breaker technology. For borate-crosslinked biopolymer gels, breakers such as oxidative and enzyme breakers can be used to reduce fluid viscosity by degrading polymer chains. An alternative approach to reduce viscosity of this type of fluid is the use of acids that lower the pH and decrosslink the fluid. A third route to reduce this fluid viscosity is by use of chelating agents and complexing agents. Lowering fluid viscosity alone may not sufficiently guarantee adequate proppant-pack and formation cleanup. It has been proved that low-viscosity fluids may still contain high-molecular-weight (MW) polymers that could severely damage formation and proppant pack. These high-MW polymers should be further broken into low-MW fragments with oxidizers or enzymes to achieve better production numbers. When metals are used to crosslink biopolymers and synthetic polymers, breakers such as oxidative breakers can still be effective. Acid fracturing fluids use fluoride-based breakers that can complex with the zirconium (Zr) and hence decrosslink the gel. When fracturing high-temperature wells, breakers can prematurely degrade the gel viscosity. This leads to less proppant placement and possibly screens out the proppant. As a result, the propped fracture becomes shorter and the well productivity will be less. To avoid this, breakers are encapsulated with materials that act as barriers between the breaker and fluid. The dissolution of the encapsulating material gives additional time for the gel to place the proppant. This paper reviews more than 100 papers and patents to summarize the experience and available knowledge in the area of using breakers for cleaning up fracturing fluids.

Shale has certain characteristic features that make them difficult to evaluate in a traditional laboratory setting. The unique characteristics of shale formations include low permeability, existence of micro fractures, and sensitivity to contacting fluids. Advances in the testing of shale has remained relatively stagnant, which has led to the fact that many current shale fracturing practices and technologies are mainly determined by fracture model simulations, and experiences drawn from the stimulation of conventional formations. Therefore, the objective of this study is to develop an experimental setup to measure the hydraulic breakdown pressure associated with the development of fractures in shale cores, and to use this setup to study the effect of different parameters on the breakdown pressure, fracture shape development, fracture direction, from various fluid types and characteristics, injection rates, shale bedding directions, acid injection, and other variables in different systems. Shale cores from a Mancos formation outcrop were evaluated in this study. Based on the experimental results, breakdown pressures in shale cores have a strong exponential relationship to fluid viscosity, where increasing fluid viscosity increases the breakdown pressure. Increasing the injection rate will reduce the pressure needed to breakdown the shale formation. Fracture complexity will increase by reducing the viscosity of the fluid. A shale core drilled in the parallel bedding direction was fractured at a lower pressure with a faster propagation compared to a shale core drilled in the perpendicular bedding direction. Additionally, a relationship between closure stress and breakdown pressure has been experimentally established and verified with existing mathematical models. Closure stress increases the breakdown pressure by a factor of 2.8.

Summary In-situ-gelled acids have been used extensively in matrix acidizing and acid fracturing for acid diversion and reducing the leakoff rate, respectively. A few studies investigated the rate of dissolution of calcite in polymer-based acids, yet none has addressed in detail the in-situ-gelled acids. Therefore, the aim of this work is to examine the mass transfer and the kinetics of the reaction of 5 wt% HCl in-situ-gelled acids with calcite and determine the effect of Fe crosslinker on the rate of calcite dissolution. The rate of reaction of 5 wt% HCl in-situ-gelled acid was measured using the rotating-disk apparatus. Rock samples of 1.5in. diameter and 1-in. length were used. The effect of temperature (100-250°F) and disk-rotational speed (100-1,800 rev/min) was investigated using Pink Desert limestone rock samples. Calcium concentration was measured in the collected samples and was used to determine the acid-reaction rate. Experimental results showed that the rate of calcite dissolution at 150°F was controlled mainly by the rate of mass transfer of the acid to the surface up to a disk rotational speed of 1,000 rev/min and by the rate of the surface reaction above this value. On the basis of the results obtained, the diffusion coefficient of 5 wt% HCl in in-situ-gelled acid at 150°F; the activation energy; and the reaction rate constant at 150, 200, and 250°F were determined for the first time. A power-law kinetic model was used to determine the kinetics parameters. The presence of Fe3+ crosslinker had a significant effect on the rate of dissolution in comparison with reactions with gelled acid (no crosslinker) at the same condition. The reaction rate decreased by a factor of 2.2 and by a factor of 1.4 when the reaction was conducted at 100 and 1,500 rev/min, respectively. A gel layer, formed on the surface, acted as a barrier between the acid and the rock, which reduced the rate of calcite dissolution.

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Hydraulic fracturing has become an increasingly important completion method to allow reservoirs to become economically producible and to improve the rate of hydrocarbon production. Crosslinked polymer fluids have been the most commonly used fracturing fluid. These fluids exhibit exceptional performance to initiate and propagate a fracture and carry proppant into the reservoir during a treatment. However, crosslinked polymer fluids can leave a significant amount of polymer in the fracture once a treatment is completed. Decades of improving oxidative, enzyme and other breakers for the polymer fluids has only marginally improved the amount of polymer residue left within the fracture. The result has been wells with subpar hydrocarbon recovery rates and in many geographic areas the return of large volume waterfracs. Over the past two decades surfactant-based fluids have been developed as a low-damage alternative. However, surfactant-based systems have had major limitations for hydraulic fracturing. This paper will introduce improved fluid technology that uses nanoparticles, internal breakers and low molecular weight surfactants to achieve the performance of crosslinked polymer fluids but leaves little to no gel residue. Nanoparticles have been found that uniquely associate thread-like micelles into 3-deminsional network that imparts wall-building leak-off control and fluid efficiency. The system also utilizes internal breakers that reside within the micelles and go wherever the fluid goes to insure complete viscosity reduction. The nanoparticle enhanced surfactant-based fluid technology may allow a wide range of hydraulically fractured reservoirs to produce at higher sustained rates than presently achievable, particularly for wells highly sensitive to fracture conductivity damage. This paper will present laboratory data that shows how uniquely charged nanoparticles improve surfactant-based fluid rheology and leak-off control properties. The mechanisms for the observed performance enhancements also will be discussed.