The thermal, unimolecular elimination of HF from CH3CF3 was studied by three different groups over the temperature range 1000" to 1800°K. While the reported kinetic parameters varied greatly, it is shown here that these data may be satisfactorily correlated in terms of a four-center transition state. This correlation results in AEoOf = 69.2 kcal/mol, and log (k/s-I) = 14.6 -72.6/8. These results may then be combined with the kinetics of the chemically activated elimination of HF from CH3CF3 formed by the recombination of methyl and trifluoromethyl radicals. The data from three different laboratories are shown to be in excellent agreement. These data, combined with extant thermal data, yield as a best value DHoo(CHs-CF3) = 99.6 k 1.1 kcal/mol. This gives the unexpectedly high value of DH29&CH3-CF3) = 101.2 k 1.1 kcal/mol. It is suggested that dipoledipole interactions. primarily in CH $CF $, account for this surprisingly strong C-C bond dissociation energy. These results also yield AH~O (CH,CF~; g, 298) = -178.6 & 1.5 kcal/mol.
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^
Summary. Fluid loss under dynamic conditions, considering such realistic conditions as low-permeability core samples and extreme shear conditions, has been examined and is reported in this paper. Dynamic data of fluid loss as a function of time, pressure, and temperature have been developed. Introduction The leakoff velocity of complexed fracturing fluids is highly dependent on environmental conditions. Previous work has shown that leakoff increases as the shear rate increases. This work examines the combined effects of shear rate. pressure differential, temperature, and time on the leakoff profile in complexed gets. Result have shown that C under simulated reservoir conditions is not proportional to p and t as proposed by classic theory. C was found to be proportional to an average p, as proposed by Nolte. Leakoff velocity follows a t relationship, where m=0.5 to 1.0, depending on shear rate, pressure differential, and time at shear. An equation is presented whereby the leakoff velocity at each increment of the treatment can be calculated on the basis of changing environmental conditions. Experimental work to investigate fluid loss under dynamic conditions has been previously reported. Many of these attempts did not adequately model conditions existing in a fracture. Low-permeability core samples, unrealistic flow profiles, pressures that were too low, and unrepresentative shear conditions were some of the objections raised as to the validity of the test results. This paper describes work where these factors have been taken into consideration during test design. Laboratory data are presented that describe the effects of shear rate, pressure differential, temperature, and time on the leakoff profiles of complexed gels. The relative effectiveness of fluid-loss additives, such as diesel and silica flour, is also present-ed. A comparison is made to other dynamically obtained leakof present-ed. A comparison is made to other dynamically obtained leakof velocities, as well as static data. Although dynamic data have been available, they have not been applied in field fracture design. In this work, a method of converting dynamic data to an effective C that can be entered into today's fracture simulators is proposed and examples are given. Experimental Procedures Core Preparation. A diamond-bit drill was used to cut 0.94-in. [2.38-cm] -diameter stocks from Ohio, Bandera, and Berea sand-stone quarry blocks. The stocks were dried in a vacuum oven for 12 hours at 250 deg. F [121 deg. C). Epoxy was then applied to the stocks and allowed to harden. A diamond-bit saw was then used to cut 1-in. [2.54-cm] -long core plugs from the stocks. The core plugs were dried in a vacuum oven for 12 hours at 250 deg. F [121 deg. C]. A beaker containing core plugs was placed under a vacuum of 0.19 × 10 psi [0.0013 kPa] for 4 hours. At the end of 4 hours, 2 % KCl was introduced to the evacuated container. The cores were allowed to saturate for a minimum of 10 days. The liquid permeability to 2 % KCl was measured on each core at the end of this permeability to 2 % KCl was measured on each core at the end of this period. period. Fluid-Loss Cell. Fig. 1 shows the fluid-loss cell with a 1 × 2.3 × 0. 13-in. [2.54 × 5.95 × 0.32-cm] slot passing over a 1.75 × 1.75 × 1-in. [4.45 × 4.45 × 2.54-cm] core. The slot width can be varied by interchanging heads. Only a 0.13-in. [0.32-cm] slot was used for these experiments. The auxiliary equipment, such as interconnecting tubing and heat exchanger, was sized to provide the same shear rate as produced in the slot. Fluid-Loss Testing. The single-pass system used to conduct the dynamic fluid-loss tests is illustrated in Fig. 2. The complete system contains a test fluid reservoir, a fluid injection pump, a crosslinker injection pump, a heating bath, a dynamic fluid-loss cell, two ballast chambers, and a backpressure regulator. The test fluid was premixed both with and without fluid-loss additives for a minimum of 30 minutes before each test. When needed a delayed crosslinker was added to the suction side of the dual-piston fluid injection pump by a syringe pump. Pumps were preset and tested at the desired flow rates before the test started. The fluid crosslinked as it flowed through 50 ft [ 15.24 m] of coiled 0.37-in. [0.95-cm] -OD copper tubing heated in a hot oil bath at 185 deg. F [85 deg. C]. Heating tape was used to wrap the fluid-loss test cell, and the temperature was set at 175 deg. F [79 deg. C] with a temperature controller. The temperature of the fluid exiting the fluid-loss cell w measured with an in-line thermocouple attached to an electronic display. Two ballast chambers were installed in the test system to maintain constant flow rate and to eliminate any system pulsing. When particulate fluid-loss additives were used, a knockout pot was added to the test system. The knockout pot was inserted directly in front of the backpressure regulator to prevent plugging by the particulate fluid-loss additives. Filtrates exiting the fluid-loss test particulate fluid-loss additives. Filtrates exiting the fluid-loss test cell were measured at various time intervals by continually weighing a collecting vessel containing the eluant on an electronic balance. Data Analysis As Penny et al. described, dynamic fluid-loss data can be analyzed with a plot of log(volume/area) vs. log(time) where slope, m, is an exponent of time and the y intercept, b, is the leakoff rate (cm/min ). For comparison, an equivalent C at t can be calculated from this plot with the following equation: (1) where Z = antilog(log F, - m log t). Substituting m=0.5 and t=36 minutes into Eq, 1, we obtain C at t =0.0164 antilog(log F -0.5 log 36), which further reduces to C at t =0.0164 antilog(log F -0.78). Picking our F values from the plot of various shear rates and pressure differentials and solving Eq. 1, we obtain C (ft/min) values from our dynamic test data, which are shown in Figs. 3 and 4. SPEPE P. 43
Ford, William G.F., SPE, Halliburton Services Summary Dynamic laboratory testing of foamed acid on limestone cores has established the effectiveness of foamed acid as a stimulation fluid. The effects of foam quality, foam stability, and chemical compatibility on fluid loss and fracture flow capacity were investigated. Recommendations are presented for deriving maximum benefits from a foamed acid treatment. Field results are presented that show the effectiveness of foamed acid in the stimulation of both oil and gas wells. Introduction The use of foam in fracturing treatments has gained widespread acceptance in the past few years. Low liquid content, good fluid loss control, and quick cleanup are just a few reasons why foams are being used. The fluid loss properties of foam as a fracturing fluid and the flow of foam through porous media have been investigated by several authors. The use of foamed acid in fracture acidizing has been reported to give the same benefits as foam in hydraulic fracturing treatments. This paper describes work where fluid loss of foamed acid has been measured directly and the effect of foamed acid on fracture conductivity has been studied. This paper presents laboratory data describing the effects of foam quality, foam stability, chemical compatibility, formation permeability, and pressure differential on. fluid loss and fracture flow capacity with foamed acid on limestone. Apparatus and Test Procedure Fluid Loss Tests The system used to study foamed acid fluid loss is illustrated in Fig. 1. The liquid and gas portions of the foam were maintained at a constant volume by separate control mechanisms. A 1,500-mL volume Ampcoloy floating piston cell was used to hold the acid solution. The driving fluid for this cell was supplied by a positive displacement Jaeco pump. Flow rates were set mechanically on the pump and tested to be 20 mL/min at 1,500 psi. The flow rate of nitrogen at 1,500 psi was measured with an integral orifice meter equipped with a digital readout supplied by Fisher Porter with a No. 2 orifice. The meter was calibrated for various nitrogen flow rates at 1,500 psi through the use of a GCA/Precision Scientific wet test meter. The pressure of the system and nitrogen flow rates were adjusted manually by the use of a back pressure regulator for coarse settings and a needle valve for fine settings. Once pressure and flow rate were stabilized at the start of the test, very little adjustment was needed to maintain the proper pressure and flow rate.The foam generator consists of a 180-mL volume Ampcoloy cell and impeller driven at a speed of 2,200 rpm. This type of foam generator was chosen over the wire screen in a pipe type because of the reactive nature of the test solution. With time, the acid would react with and erode the screen, thus limiting the chances of reproducing a foam with the same texture (bubble size) and consistency from test to test.Foamed acid was generated and allowed to pass through two visual flow cells and out to the waste trap through a high-pressure backpressure regulator. The visual flow cells were used to check the condition of the foamed acid before the fluid loss test began, with uniform small bubbles and no gas pockets conditional to a stable foam. Once this condition was reached, a portion of the foamed acid was allowed to flow into the fluid loss cell while continuing to flow foamed acid through the system to the waste trap. JPT P. 7^
Summary A method of calculating acid spending of foams in a fracture has been developed. Experimental data are presented for foamed acid flow in limestone and dolomite laboratory-prepared fracture systems 60 in. [152.4 cm] long at 70 deg. F at [21.1 deg. C]. The surface reaction in an HCl-limestone system is fast compared to the mass transfer to the rock surface. The overall acid spending rate is to a large degree dependent on the extent of fluid mixing in the fracture. This is called a mass-transport- or diffusion-controlled reaction. The surface reaction rate in an HCl/dolomite system is finite compared with the rate of mass transfer to the rock surface. This is called a "kinetic-controlled" reaction. Earlier work showed that whether the acid was gelled or weighted, diffusion control still would be dominant for the HCl/limestone system and kinetic control would dominate the HCl/dolomite system. A method of predicting the penetration of foamed acid is presented based on combining the mass transfer coefficient of the acid in the fracture with the surface reaction that occurs at the fracture surface. Example calculations are presented to show the effect of various variables, Introduction The use of foamed acid in fracture acidizing treatments has gained widespread acceptance in the past few years. Various properties of foamed acid have been investigated and its successful use in stimulation treatments has been reported. Surface reaction kinetics in fracture acidizing have been studied for nonfoamed systems by several authors. This paper describes work where acid spending of foams has been measured directly and the effect of foam on surface kinetics in fracture acidizing has been studied. Laboratory data are presented that describe the effects of foam quality, foam flow rate, and foam stabilizers on the surface reaction kinetics of foamed acid on limestone and dolomite. Mathematical Model A mathematical model describing the spending of foamed acid was developed similar to that presented earlier by Guin and Roberts. The model for foamed acid spending is illustrated in Fig. 1. The foam leakoff velocity, V, is assumed constant over the fracture length. Assuming the foam quality is constant and there is steady-state flow in a vertical fracture, the mass balance equation for foam in a fracture is (1) where u and V represent the foam velocity components in the x and y direction, respectively. Gamma represents the foam quality (volume fraction of N in foam) and C the concentration of acid in the foam. (D+D ) represents the effective diffusivity. Eq. 1 must be solved subject to the following boundary conditions. (2a) (2b) (2c) The velocity components u and V are functions of x and y, satisfying the continuity equation: (3) These partial differential equations can be transformed into ordinary differential equations (Appendix A) to give (4) (5) and (6) Eqs. 4 through 6 were derived by following the procedures proposed by Roberts and Guin for acid penetration for plain acid fracture treatments. JPT P. 89^
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