Hydraulic fracturing has been used by the oil and gas industry as a way to boost hydrocarbon production since 1947. Recent advances in fracturing technologies, such as multistage fracturing in horizontal wells, are responsible for the latest hydrocarbon production boom in the US. Linear or crosslinked guars are the most commonly used fluids in traditional fracturing operations. The main functions of these fluids are to open/propagate the fractures and transport proppants into the fractures. Proppants are usually applied to form a thin layer between fracture faces to prop the fractures open at the end of the fracturing process. Chemical breakers are used to break the polymers at the end of the fracturing process so as to provide highly conductive fractures. Concerns over fracture conductivity damage by viscous fluids in ultra-tight formations found in unconventional reservoirs prompted the industry to develop an alternative fracturing fluid called "slickwater". It consists mainly of water with a very low concentration of linear polymer. The low concentration polymer serves primarily to reduce the friction loss along the flow lines. Proppant-carrying capability of this type of fluids is still a subject of debate among industry experts. Constraints on local water availability and the potential for damage to formations have led the industry to develop other types of fracturing fluids such as viscoelastic surfactants and energized fluids. This article reviews both the traditional viscous fluids used in conventional hydraulic fracturing operations as well as the new family of fluids being developed for both traditional and unconventional reservoirs.

In naturally fractured reservoirs, oil recovery from waterflooding relies on the spontaneous imbibition of water to expel oil from the matrix into the fracture system. The spontaneous imbibition process is most efficient in strongly water-wet rock where the capillary driving force is strong. In oil- or mixed-wet fractured carbonate reservoirs, however, the capillary driving force for the spontaneous imbibition process is weak, and therefore the waterflooding oil recoveries are low. The recovery efficiency can be improved by dissolving low concentrations of surfactants in the injected water to alter the wettability of the reservoir rock to a more water-wet state. This wettability alteration accelerates the spontaneous imbibition of water into matrix blocks, thereby increasing the oil recovery during waterflooding. Several mechanisms have been proposed to explain the wettability alteration by surfactants, but none have been verified experimentally. Understanding of the mechanisms behind wettability alteration could help to improve the performance of the process and aid in identification of alternative surfactants for use in field applications. Results from this study revealed that ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface are the two main mechanisms responsible for the wettability alteration. Previous researchers observed that, for a given rock type, the effectiveness of wettability alteration is highly dependent upon the ionic nature of the surfactant involved. Our experimental results demonstrated that ion-pair formation between the charged head groups of surfactant molecules and the adsorbed crude oil components on rock surface was more effective in changing the rock wettability toward a more water-wet state than the adsorption of surfactant molecules as a monolayer on the rock surface through hydrophobic interaction with the adsorbed crude oil components. By comparing two anionic surfactants with different charge densities, we propose that wettability alteration processes might be improved through the use of dimeric surfactants, which have two charged head groups and two hydrophobic tails. Gemini surfactants where the molecules are joined at the head end are likely to be effective when ion-pair formation is the wettability alteration mechanism, and bolaform surfactants, in which molecules are joined by the hydrophobic tails, should be more effective in the case of surfactant monolayer adsorption.

A capacity to reduce water permeability much more than oil permeability is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. Although several researchers have reported polymers and gels that provide this disproportionate permeability reduction, the explanation for the phenomenon was unclear. In this paper, we examine several possible explanations for why some gels reduce water permeability more than oil permeability. Our experimental results indicate the disproportionate permeability reduction is not caused by gravity or lubrication effects. Results also indicate that gel shrinking and swelling are unlikely to be responsible for the phenomenon. Although wettability may play a role in the disproportionate permeability reduction, it does not appear to be the root cause for water permeability being reduced more than oil permeability. Results from an experiment with an oil-based gel suggest that segregation of oil and water pathways through a porous medium (on a microscopic scale) may play the dominant role in the disproportionate permeability reduction. However, additional work will be required to verify this concept. Experimental Procedures Gelants Studied. The study included four types of gels: (1) resorci-noVformaldehyde, (2) Cr(II1) acetatelpartially hydrolyzed polyacrylamide (HPAM), Marcit supplied by Marathon Oil Co., (3) glyoxaV cationic polyacrylamide (CPAM), Floperm 500 supplied by Pfizer Chemical Co., and (4) 12-hydroxystearic acid/Soltrol 130 (an oilbased gel)-2% 12-hydroxystearic acid obtained from Johnson Wax Co. Two formulations of the oil-based gel were examined. Table 1 lists the compositions of these gelants. The HPAM had a molecular weight of = 2 million daltons and a 2% degree of hydrolysis. The other chemicals used in this study were reagent grade. Coreflood Sequence. In each coreflood, the core was saturated with brine and the porosity and permeability determined. Then, the core went through a cycle of oilflooding followed by waterflooding (Flow Direction 1). The endpoint oil and water permeabilities were determined at the irreducible water saturation after the oilflood and at the irreducible oil saturation after the waterflood, respectively. A constant pressure drop was maintained across the core during the process. To simulate the "pump-in, pump-out" sequence during gel

Straightforward applications of fractional-flow theory and material-balance calculations demonstrate that, if zones are not isolated during gel placement in production wells, gelant can penetrate significantly into all open zones, not just those with high water saturations. Unless oil saturations in the oil-productive zones are extremely high, oil productivity will be damaged even if the gel reduces water permeability without affecting oil permeability. Also, in field applications, capillary pressure will not prevent gelant penetration into oil-productive zones. An explanation is provided for the occurrence of successful applications of gels in fractured wells produced by bottomwater drive. With the right properties, gels could significantly increase the critical rate for water influx in fractured wells. Introduction Coping with excess water production is always a challenging task for field operators. The cost of handling and disposing produced water can significantly shorten the economic producing life of a well. The hydrostatic pressure created by high fluid levels in the well also is detrimental to oil production. The two major sources of excess water production are coning and channeling. Water coning is common when a reservoir is produced by a bottomwaterdrive mechanism. Fractures and high-permeability streaks are the common causes of premature water breakthrough during waterfloods. Polymer gels have been applied to many wells to reduce excess water production without adversely affecting oil production. l-6 Moffitt reported that polymer gels are particularly effective in suppressing water coning. In many cases, however, gel treatments have not been successful. Part of the reason for the sporadic success was problems with gel placement. During gel placement in production wells, much of the gel formulation will enter zones responsible for the excess water production. However, some of this fluid may enter and damage oil-productive strata. The objectives of this study are to model gel placement in production wells mathematically and to examine the potential effect of gelant invasion into oil-producing zones. Particular attention is paid to the importance of two phenomena. The first is hysteresis of oil/water relative permeability curves during the "pump-in, pump-out" sequence used during gel placement in production wells. The second phenomenon is that gels (or polymers) can reduce the relative permeability to water more than to oil. Sensitivity studies covering most known field and laboratory applications are discussed. In particular, we study permeability contrasts from 1 to 1000, oil/water viscosity ratios ranging from 0.1 to 100, endpoint water relative permeabilities ranging from 0.1 to 0.7, water saturations ranging from 0.2 to 0.8, and fractured and unfractured wells. Therefore, our conclusions should be applicable to most field applications of gels in production wells. Examples are provided to illustrate and contrast situations where gels are or are not expected to damage oil productivity. In these example...

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