When oil containing organic acids is flooded with alkaline water, the result can be a high oil recovery efficiency, provided a bank of viscous oil-in-water emulsion forms in situ. The amount of additional oil recovered depends on the pH and salinity of the water and the type and amount of organic acid it contains, as well as on the amount of fines in the porous medium. Introduction The method described in this paper is based on the fact that organic acids, naturally occurring in some crude oils, will react with alkaline water to produce soaps at the oil/water interface. The soaps thus formed lower the interfacial tension between crude oil and flood water by a factor of several hundred, and under the proper conditions of salinity, pH, and temperature, they change the wettability of the porous medium to preferentially oil-wet. When the proper alkaline water and acidic oil flow simultaneously in a porous medium, a viscous oil-external emulsion is formed. The flow properties of this type of emulsion permit a high, nonuniform pressure gradient to be permit a high, nonuniform pressure gradient to be generated across the narrow region in the vicinity of the emulsion front. The pressure gradients are sufficient to overcome the reduced capillary forces and displace the oil from the pore space. The displacement efficiency can be much improved over ordinary waterflood efficiencies. Other techniques of flooding with alkaline water to increase oil recovery have been reported in the literature. Almost 50 years ago, Nutting, proposed flooding an oil reservoir with alkaline sodium carbonate solutions, after it was observed that those solutions could remove oil from glass and silica surfaces by decreasing the wetting of the surface by oil. In more recent years, Leach et al. have reported the use of alkaline water to cause a reversal of wetting conditions in some naturally oil-wet reservoirs. Reisberg and Doscher also used alkaline water containing a surface-active chemical in some of their tests. The alkaline waterflooding method described in this paper differs in several ways from the other processes just mentioned. In this process, the alkaline water must be saline rather than fresh. The use of saline water causes the sand to be made oil-wet in the presence of the alkaline water. High salinity also leads to the formation of a water-in-oil type of emulsion, which does not form in the other processes. The alkaline water process can be considered primarily in reservoirs where the crude oil contains primarily in reservoirs where the crude oil contains organic acids. The most common organic acids in crude oil are naphthenic acids., The acid content of a crude oil tends to be higher when the base composition of the crude is high in naphthenic compounds. in cases where acid concentration is low, a bank of oil containing organic acids could be injected into a reservoir and followed by alkaline water. Mechanism of Displacement by Alkaline Water The mechanisms active at the front where alkaline water is displacing acidic crude oil includea drastic reduction of oil/water interfacial tension,wetting of the matrix grains by oil,formation of water drops inside the oil phase, anddrainage of oil from the volume between alkaline water drops to produce an emulsion containing very little oil. JPT P. 1365
The fluid conductivity of a hydraulic fracture is critical in determining the effectiveness of the fracturing treatment. Two factors considered here can greatly affect that conductivity. First is the reservoir environment; for example, the presence of hot brine can reduce the permeability of brittle proppants under stress. The second is deviation from Darcy flow, or turbulence. Introduction Fracture conductivity limits the amount of stimulation achieved from the fracturing of many wells. (Fracture conductivity is defined as the width of the fracture multiplied by the apparent permeability of the proppant pack.) In recent years, improved fracturing fluids have made it possible to prop longer fractures, which increases the need for proppants that maintain higher permeability. Theoretical predictions of results from fracturing demonstrate the important relation between stimulation achieved and fracture conductivity.' For example, for long vertical fractures, a tenfold increase in fracture conductivity can lead to a predicted increase in stimulation from two-fold to almost sixfold. For fracture stimulation of wells with initially high productivity, high fracture conductivity is critical to achieving any appreciable stimulation. In the past, fracture conductivity has been measured by placing proppants between slabs of reservoir rock or different metals, applying mechanical stress to the proppants to stimulate the stress that exists in the earth at various depths, and flowing a fluid through the proppant to measure fluid conductivity. 2, 3 Results of those tests are used routinely by industry in designing fracture treatments. Most experiments were performed at room temperature and the fluids were performed at room temperature and the fluids were nitrogen, oil, or water. None of the past work has considered how different fluids contacting the proppant affect conductivity under stress, nor have the proppant affect conductivity under stress, nor have the effects of flow rate on conductivity been investigated. This paper presents data on two phenomena that have not been discussed in the literature but that appear to be very important in determining fracture conductivity with brittle proppants. The first is the effect of the environment (the fluid present and the temperature) on the conductivity of a brittle proppant under stress. The second is the effect of proppant under stress. The second is the effect of flow rate (deviation from Darcy's law) on the flow resistance of proppants. Consideration of these two phenomena is important to improving the design of phenomena is important to improving the design of fracture treatments, to understanding better the incentive for improving proppants, and to properly testing proppants in the laboratory. proppants in the laboratory. The experimental approach of investigating thick layers of proppant was taken here to separate some of the variables important in fracture conductivity from the even more complex problem of the flow in packed fractures between various types of reservoir packed fractures between various types of reservoir rock. This approach has proved advantageous. Hence, the present work applies directly only to vertical fractures packed with several layers of brittle proppant. Multiple layers result when the fracturing proppant. Multiple layers result when the fracturing fluid viscosity is low enough to allow the proppant to settle to the bottom of the vertical fracture during the injection of fluid. Multiple layers also result when the fluid is viscous enough to suspend the proppant, provided the concentration of proppant is proppant, provided the concentration of proppant is high enough and the fracture is wide enough during injection. JPT P. 1101
Several types of fracturing fluids were tested for potential adverse effects on fracture conductivity. A predictive method based on the volume of residue in a fluid after it degrades was developed that describes the local effect of fluid residue on fracture conductivity. Introduction Fracturing fluids containing water normally are increased in viscosity by adding water-soluble polymers to the water phase. The fluids are designed to decrease in viscosity after the treatment is complete to facilitate fracturing fluid recovery and to allow greater production rates from the well soon after the treatment. The viscosity decrease results from thermal degradation of the polymers or from chemical "breakers" in the water that polymers or from chemical "breakers" in the water that degrade the polymers. The degraded polymer consists of smaller, water-soluble molecules and any residue that is not made water-soluble by the breaker. The polymer most commonly used to increase the viscosity of fracturing fluids is guar gum, a natural product extracted from the guar bean. Degraded guar gum product extracted from the guar bean. Degraded guar gum is not completely water soluble; Fig. 1 shows the residue left after guar polymer solution was degraded. Another polymer (less commonly used because it is more expensive polymer (less commonly used because it is more expensive than guar) is modified cellulose. The amount of residue left by this polymer is much less than from guar. A third type of water-soluble polymer sometimes used for fracturing fluids (mainly high-temperature applications) is polyacrylamide, a completely synthetic polymer that leaves polyacrylamide, a completely synthetic polymer that leaves no residue after degradation. A fracturing fluid commonly used in many fields is an emulsion of brine and hydrocarbon; it contains about one-third by volume brine phase and two-thirds by volume oil phase. This polymer emulsion is widely accepted because of phase. This polymer emulsion is widely accepted because of its lower cost and its desirable viscosity behavior for a wide range of applications. The emulsion can be used with any of the three types of water-soluble polymers added to the aqueous phase, but guar gum is the polymer that is normally used. During a fracturing operation it is desirable to minimize loss of fracturing fluids from the fracture into the reservoir. This is accomplished by adding finely divided solids, called fluid-loss additives, to the fracturing fluid. The function of these materials is to plug the pore spaces of the rock at the faces of the fracture. plug the pore spaces of the rock at the faces of the fracture. Some questions concerning the use of these additives naturally arise: Do they have a significant effect on the permeability of the proppant in the fracture? Are they displaced off the face of the fracture after being deposited there? Are they mobile and free to move through the fracture when the well is put on production? A recent papers reported that fluid-loss additives do cause very large decreases in sand permeability. It should be noted, however, that the tests were not performed under conditions that simulated stress on a fracture. For a given fracture geometry, fluid conductivity of the fracture determines the amount of stimulation that is achieved. In gas wells, turbulent flow normally decreases conductivity, and this significantly increases the importance of avoiding damage to conductivity by the fracturing fluid. This paper describes a theoretical model that can be used in evaluating the effect of fracturing fluids on fracture conductivity, gives results of experiments in which fluids were tested in simulated fractures, compares model predictions with results of the laboratory experiments, predictions with results of the laboratory experiments, and discusses implications of the results. JPT P. 1273
Summary To investigate the causes of fluid migration behind the casing after primary cementing, pressure and temperature measurements were made in the annulus of seven wells during cementing operations. Sensors were attached to the outside of the casing as it was run into each well; in this way data were obtained from several depths. A logging cable, also clamped to the casing, was used to bring data from the sensors to the surface. In some of the wells these annular measurements were continued during subsequent completion or work over operations. The pressure data could be used to determine conditions that either prevented or allowed fluid entry into the wellbore. Generally, pressure in the cement column began to decrease shortly after the cement was pumped. The success of the cementing operation depended on the cement attaining sufficient strength to exclude pore fluids from the cement before the pressure somewhere in the cement column declined to pore pressure at that depth. Pressure in the cement generally appeared to decline to the pore pressure in adjacent formations after the cement had set. In one well, however, pressure in the cement opposite a "tight streak" steadily declined to far less than a water hydrostatic gradient as the cement set. Fluid did not enter the wellbore and migrate to the surface soon after cementing in any of the wells investigated, but in one well fluid flow between zones behind the casing was indicated when the pressure in the cement decreased to pore pressure before the cement set. Before perforating was performed, annular flow was confirmed by a noise log in this well. The pressure sensors allowed other observations to be made both during and after cementing, including the effects of annular pressure applied at the surface during curing of the cement, and communication behind the casing during perforating, acidizing, and squeeze cementing. The temperature measurements in the annulus were used to monitor the setting of the cement, which is accompanied by evolution of heat. The cement generally set from the bottom of the wellbore toward the top. These field data confirm laboratory data that show a pressure decline in a cement column as the cement cures. pressure decline in a cement column as the cement cures. Conditions more likely to lead to annular fluid migration before the cement sets and steps that can be taken to decrease the likelihood of these occurrences can be identified from the field results. The pressure loss in a cement column before the cement cures is believed frequently to be responsible for vertical fluid flow behind the casing. The acronym FILAP is suggested for the phenomenon of "flow induced by loss in annular phenomenon of "flow induced by loss in annular pressure." pressure." Introduction The importance of achieving successful primary cementing of a well is hard to overemphasize. If there is a failure to seal the annulus outside the casing or liner, pressure may appear at the surface of the well from pressure may appear at the surface of the well from migrating gas (which is called "annular gas flow"), a liner top may leak, or fluids may flow between zones behind the casing in the well. Flow between zones can cause the loss of valuable hydrocarbons, the failure of stimulation treatments, and other problems. JPT P. 1429
The electrokinetic effects streaming potential, streaming current, and electro-osmotic pressure were studied by applying and measuring sinusoidal variations of hydrodynamic pressure and electrical voltage. Phenomenological relations between the effects were investigated, and an improved experimental method for measuring the electrokinetic coefficients, hence the zeta potential, was used. Saxen's law was verified within 6% at frequencies of 20, 100, and 200 cycles per second. The systems studied were restricted to glass-water and glass-salt solutions. The advantages and disadvantages of using sinusoidally varying quantities for electrokinetic measurements are discussed.
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