The roles of capillary pressure, wettability and relative permeability in controlling load water recovery following hydraulic fracturing treatments have been examined. It has been found in laboratory studies that the judicious alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid thorough cleanup of permeability can promote a rapid thorough cleanup of injected water. Field applications employing these concepts have resulted in enhanced load water recoveries and higher production due to longer effective frac lengths and/or higher fracture conductivities following cleanup. Introduction Aqueous treating fluids have traditionally been very attractive in hydraulic fracturing treatments. As many as 90% of the fracturing treatments performed today are carried out with water-based performed today are carried out with water-based fluids. The attractiveness of water is due to its low cost and safety compared to hydrocarbon or alcohol based fluids. Furthermore, the chemistry involved in providing a wide variety of predictable fluid properties is much better understood. From a compatibility standpoint, however, the injection of water into a hydrocarbon bearing formation may impair production via formation damage or the retention of water following the treatment. Several chemical additives have been developed to enhance formation compatibility of aqueous fluids. Clay stabilizers to prevent clay swelling and migration, iron and paraffin controls additives, nonemulsifiers, and surface tension reducing agents are routinely incorporated into aqueous fracturing fluids. Even after employing these measures, the problem of load water retention often remains. It is not uncommon to recover as little as 10 to 15% of the load water following a hydraulic fracturing treatment of a tight, gas bearing formation. The impact of water retention on hydrocarbon production has been discussed by several production has been discussed by several investigators. It has been noted that production in tight low pressure gas wells can production in tight low pressure gas wells can completely blocked if the drawdown pressured exceed the capillary pressure of injected water trapped near the fracture faces. Should permeability to hydrocarbon be established in the permeability to hydrocarbon be established in the invaded zone, the existing high water saturation can depress productivity for extended periods. Productivity will increase only as the periods. Productivity will increase only as the water is gradually removed. This work examines the roles of capillary pressure, wettability, and relative permeability in pressure, wettability, and relative permeability in controlling load water recovery. It has been found that the judicious alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid, thorough cleanup permeability can promote a rapid, thorough cleanup of injected aqueous fracturing fluids. Field applications employing these concepts have shown enhanced load water recoveries and higher production due to longer initial effective frac lengths production due to longer initial effective frac lengths and higher fracture conductivities following cleanup. Discussion During a hydraulic fracturing treatment injection pressure and imbibition combine to create an area of essentially 100% water saturation near the fracture face. The effectiveness of drawdown and/or return hydrocarbon flow in displacing the injected water depends directly on the magnitude of the capillary end effects in a gas well and on the wettability when producing oil. The factors influencing load recovery and production in gas and oil wells will be considered separately. Gas Well Cleanup The role of capillary pressure in controlling load recovery from a gas well can be demonstrated with the two phase simulator GAS. WAT. Given the low permeability gas well conditions listed in Table 1, it can be calculated that a maximum of 10% of the injected water will be returned within 7 days at a capillary pressure of 250 psi with no further cleanup. On the other hand, lowering the capillary pressure to zero results in 50% load recovery within 14 days with continued cleanup beyond that point (Figure 1).

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^

Summary. The effects of capillary pressure, wettability, and relative permeability in controlling load water recovery following hydraulic-fracturing treatments have been examined. Laboratory studies have indicated that the alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid, thorough cleanup of injected water. Field applications of these concepts have resulted in enhanced load water recoveries and higher production because of longer effective fracture lengths and/or higher effective fracture conductivities after treatment cleanup. Introduction The impact of water retention on hydrocarbon production has been discussed by several investigators. In a conventional water-wet treatment, water strongly associates with sandstone and limestone surfaces. During cleanup in a water-wet condition, the hydrocarbon tends to break through the water, leaving high water saturation and low relative permeability to hydrocarbon. On the surface, one may see only 10 to 15 % of the treating fluid recovered when the hydrocarbon breaks through; the remaining fluid is held in place by high capillary pressures. If this hydrocarbon break-through is near the wellbore, cleanup of the remainder of the treated area may be slowed or stopped. Posttreatment analyses have indicated effective fracture lengths of less than 100 ft [less than 30 m] when the jobs were designed for 1,000 ft [305 m]. Application of enhanced-load-recovery additives is meant to leave contacted surfaces nonwet. The nonwet surface exhibits a water/hydrocarbon/solid contact angle of nearly 90 degrees [1.6 rad], meaning that neither water nor hydrocarbon strongly associates with the surface. During cleanup in a nonwet state, the hydrocarbon displaces the treating fluid in a piston-like fashion. At hydrocarbon breakthrough, a greater percentage of fluid is recovered, leaving a lower water saturation and a higher relative permeability to hydrocarbon. During fracture cleanup, the nonwet condition minimizes rapid hydrocarbon breakthrough near the wellbore, and load water is displaced by the hydrocarbon. This delay in hydrocarbon breakthrough enhances the chance of the fracture to clean up from the tip. The result is that a greater percentage of water is recovered and the effective fracture length following cleanup is greater. This work examines the effects of capillary pressure, wettability, and relative permeability in controlling load water recovery. Results have shown that alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid, thorough cleanup of injected aqueous fracturing fluids. Field results, where these concepts have been used, have shown enhanced load water recoveries and higher production because of longer initial effective fracture lengths and higher effective fracture conductivities after cleanup. Experimental Flow-Column Preparation. The column was made from stainless- steel tubing of 3/4 -in. [ 1.91-cm] OD. Column length, including the end fittings, was 10 in. [30.48 cm]. Outer female pipe-thread fittings on each end of the column contained a 1/8-in. [0.32-cm] -diameter stainless-steel tube centered in the fitting and cemented into place with epoxy resin. Epoxy resin was also used to fill the remaining void inside the fitting, eliminating dead volume. This resin was poured smooth to the same level as the 1/8-in. [0.32-cm] tube. The tube entrance was then countersunk with a drill bit of diameter larger than that of the tube. Flow channels away from the entrance of the tube were made in a wagon-spoke pattern. This ensured that the flow would enter the sand column in a more uniform pattern, not in a channel-like flow. A screen of approximately 200 mesh was made to place inside each fitting to prevent sand from entering and plugging the small tubing. The sand was a sieved 100/200-mesh Oklahoma No. 1. About 123 g of this sand was used to fill the column on each test. One end of the column was fitted together and the column suspended vertically. The sand was added slowly while the tube was vibrated to cause the sand to contact the sides of the column and to achieve a more uniform packing. Testing Procedure With Oil. Test equipment used to evaluate enhanced-water-recovery compounds in low-permeability sand columns with oil is illustrated in Fig. 1. The complete system contains a digital balance, fluid reservoir, fluid-injection pump, sand column, 0- to 100-psi [0- to 690-kPa] pressure transducer with digital readout, oil-injection pump, and oil reservoir. API standard brine was flowed into the column at 1.0 cm3 /min until the column was saturated. PV was determined by measuring fluid intake into the column. Isopar M TM, a refined oil with a viscosity of about 2.46 cp [2.46 mPa.s], was then flowed in the reverse direction at 1.0 cm3/min to a residual water saturation. Enhanced-water-recovery treating fluid was flowed into the column in the same direction as the API standard brine at 1.0 cm3/min. Injection ceased when the first drop of fluid was eluted. Isopar M was then flowed in the opposite direction of the enhanced-water-recovery treating fluid at rates of 0.5, 1.0, 5.0, and 10.0 cm3/min for 2 hours at each rate or until pressure leveled out. Volume of water recovered and pressure at each rate were recorded. Equilibrium water saturation within the column at each rate and the effective oil permeability were then calculated. It was generally found that 90 to 95 % of the equilibrium water saturation and pressure were reached at each rate within 2 hours. Testing Procedure With Gas. Test equipment used to evaluate enhanced-water-recovery compounds in low-permeability sand columns with gas is illustrated in Fig. 2. The complete system contains a digital balance, fluid reservoir, fluid-injection pump, sand column, visual flow cell, gas flowmeter, pressure gauge, manometer, and regulated nitrogen supply. Nitrogen was flowed through the sand column to determine maximum flow rate and the permeability of the column to nitrogen at a pressure differential of 10 psi [69 kPa]. API standard brine was flowed into the column in the reverse direction at 1.0 cm3/min until the column was saturated. PV was determined by measuring fluid intake into the column. Nitrogen was then flowed in the reverse direction at a pressure differential of 5 psi [34.5 kPa] to 50% water saturation. SPEPE P. 515^