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Drilling fluid management & disposal
Summary At high pH and with surfactant concentrations well above the critical micelle concentration (CMC), the pH-dependent part of adsorption is small. Retention depends especially on the sodium-ion activity and on the type and valence of inorganic anions. As the anionic charge increases, adsorption at a given ionic strength decreases. This behavior correlates with the effect of anions on the sulfonate activity in solution. Introduction Retention of a petroleum sulfonate by sodium kaolinite is investigated at high pH (up to 13) and with surfactant concentrations in alcohol-containing brines well above the solubility, giving rise to suspensions of liquid crystals. Usual alkaline agents, sodium hydroxide, carbonates, silicates, and phosphates are compared in various salt environments. Sulfonate adsorption is determined in batch experiments. Adsorption isotherms show no plateau value after the CMC but a more or less pronounced maximum with a shape that varies with the ionic environment. The pH-dependent part of adsorption, assumed to occur on the charged crystal edge of kaolinite, is small with respect to total retention. Thus, at these surfactant concentrations, increases in pH have practically no effect. On the other hand, adsorption depends both on the sodium-ion activity and on the types and valences of inorganic anions present in the aqueous fluid. As. the anionic charge increases, adsorption at a given ionic strength decreases considerably. It is smaller than that expected with a decrease in sodium-ion concentration alone. The results are correlated with the effect of anions on the sulfonate activity in solution. One major point is that sodium carbonate reduces adsorption more than sodium hydroxide does, although the pH is lower by more than one unit, which helps reduce the dissolution of kaolinite and therefore the consumption of the alkaline agent. Background In EOR by surfactant flooding, one major preoccupation is to maximize the chemicals injected because the profitability of the process depends largely on additive loss. Hence, the degradation of the micellar solution must be minimized, especially by reducing the adsorption of surfactant on the rock surface as much as possible. One way to do this (because anionic surfactants are mostly used) is to increase the pH of the medium with alkaline agents. This technique has been recommended for a long time. An increase in pH reduces the number of positive sites on mineral surfaces (silica, clays) and then decreases the electrostatic attraction of anionic surfactants, particularly in the acidic pH range and around neutrality. Adsorption of surfactants under alkaline conditions has been studied mainly with such relatively water-soluble surfactants as sodium dodecylbenzene-sulfonate at concentrations near the CMC. Furthermore, the pH of investigation used to determine adsorption isotherms was generally 11 or less. This study aims at examining the adsorption of a petroleum sulfonate that is not very brine-soluble by a kaolinite at low to medium salinity and with surfactant liquid-crystal suspensions in alcohol-containing brines. Specific effects of standard alkaline agents, such as sodium hydroxide, carbonates, silicates, and phosphates, are compared in various salt environments and in a pH range from neutrality to around 13. Experimental The results reported here focus on adsorption of the petroleum sulfonate TRS 10-80TM on a homoionic sodium kaolinite at 30°C in the absence of multivalent cations. Kaolinite. The kaolinite used came from Guizengeard (Charentes, France) and contains 86% pure kaolinite [Al2O3, (SiO2)2, (H2O)2]. Excess aluminum and exchangeable multivalent cations, as well as most organic materials, were eliminated with the following procedure. The kaolinite was washed with a concentrated (50 g/L) NaCl brine, a sodium hydroxide solution (pH˜13.5), a 10-g/L NaCl brine up to pH 12, and finally with a 5-g/L NaCl/0.1-N HCl brine up to pH 7. After the resulting suspension was centrifuged, the clay was dried at 45°C and stored. The Brunauer/Emmett/Teller specific surface area was found to be 23 m/g, with the crystal edge area representing about 22 % of the total surface area. 4 Chemicals. Witco Chemical Co. provided the petroleum sulfonate TRS 10-80. Its average molecular weight is 405. The chemical composition is approximately 80 wt% sulfonate (active material), 11 wt% unsulfonated oil, 8 wt% water, and 1 wt% inorganic salts. The petroleum sulfonate was mainly used as received. In fact, no difference in adsorption behavior was observed between the crude sulfonate and the sulfonate purified by deoiling and desalting. Aqueous solutions of TRS 10-80 are slightly alkaline. The sulfonate solution concentration was determined by turbidimetry at 620 nm with Hyamine 1622 as the reagent or, for concentrations less than 100 ppm (with the deoiled sulfonate), by ultraviolet (UV) spectrophotometry at 230 nm. All the sulfonate concentrations mentioned here refer to active material. The inorganic chemicals used were pure-grade reagents. Merck supplied the secondary butanol. Deionized water (pH=6.7) was used. Procedure - Isotherm Determination. The sulfonate solubility was determined at an ionic strength, I, of 0.448 M, corresponding to a (10-g/L NaCl)/(10-g/L Na2CO3 brine), arbitrarily chosen as a reference.Equation 1 where Ci and Zi are the molar concentration and the valence of Ion i, respectively. At this salinity level, sulfonate solubility is very low, a few parts per million. If solubility is exceeded, liquid-crystal suspensions form, especially in the presence of alcohol. With 30 g/L of 2-butanol, sulfonate suspensions up to a sulfonate concentration of 20 g/L are quite stable, with no decantation or heterogeneity in the bulk solution after a I-week storage at 30°C. In 21-g/L NaCl brine and 30-g/L 2-butanol, the CMC was found to be around 7 ppm (Fig. 1). This value corresponds with the CMC values that Salager found. Adsorption was measured in batch experiments. Mixtures of surfactant solution and kaolinite (solid/liquid ratio=0.1) were agitated for 40 hours and then were centrifuged at 1500 g for 20 minutes. The supernatant liquid was filtered through 0.45-µm Millipore Millex HV™. The amount of sulfonate adsorbed was determined by measuring the difference in the sulfonate concentration in the solution before and after contact with kaolinite. In the presence of NaCl and Na2SO4 or Na2SO4, only (i.e., without any alkaline agents), the pH of the supernatant liquid increases from about 6.7 to 7.3 as a function of sulfonate equilibrium concentration. p. 123–127 Kaolinite. The kaolinite used came from Guizengeard (Charentes, France) and contains 86% pure kaolinite [Al2O3, (SiO2)2, (H2O)2]. Excess aluminum and exchangeable multivalent cations, as well as most organic materials, were eliminated with the following procedure. The kaolinite was washed with a concentrated (50 g/L) NaCl brine, a sodium hydroxide solution (pH˜13.5), a 10-g/L NaCl brine up to pH 12, and finally with a 5-g/L NaCl/0.1-N HCl brine up to pH 7. After the resulting suspension was centrifuged, the clay was dried at 45°C and stored. The Brunauer/Emmett/Teller specific surface area was found to be 23 m/g, with the crystal edge area representing about 22 % of the total surface area. 4 Chemicals. Witco Chemical Co. provided the petroleum sulfonate TRS 10-80. Its average molecular weight is 405. The chemical composition is approximately 80 wt% sulfonate (active material), 11 wt% unsulfonated oil, 8 wt% water, and 1 wt% inorganic salts. The petroleum sulfonate was mainly used as received. In fact, no difference in adsorption behavior was observed between the crude sulfonate and the sulfonate purified by deoiling and desalting. Aqueous solutions of TRS 10-80 are slightly alkaline. The sulfonate solution concentration was determined by turbidimetry at 620 nm with Hyamine 1622 as the reagent or, for concentrations less than 100 ppm (with the deoiled sulfonate), by ultraviolet (UV) spectrophotometry at 230 nm. All the sulfonate concentrations mentioned here refer to active material. The inorganic chemicals used were pure-grade reagents. Merck supplied the secondary butanol. Deionized water (pH=6.7) was used. Procedure - Isotherm Determination. The sulfonate solubility was determined at an ionic strength, I, of 0.448 M, corresponding to a (10-g/L NaCl)/(10-g/L Na2CO3 brine), arbitrarily chosen as a reference.Equation 1 where Ci and Zi are the molar concentration and the valence of Ion i, respectively. At this salinity level, sulfonate solubility is very low, a few parts per million. If solubility is exceeded, liquid-crystal suspensions form, especially in the presence of alcohol. With 30 g/L of 2-butanol, sulfonate suspensions up to a sulfonate concentration of 20 g/L are quite stable, with no decantation or heterogeneity in the bulk solution after a I-week storage at 30°C. In 21-g/L NaCl brine and 30-g/L 2-butanol, the CMC was found to be around 7 ppm (Fig. 1). This value corresponds with the CMC values that Salager found. Adsorption was measured in batch experiments. Mixtures of surfactant solution and kaolinite (solid/liquid ratio=0.1) were agitated for 40 hours and then were centrifuged at 1500 g for 20 minutes. The supernatant liquid was filtered through 0.45-µm Millipore Millex HV™. The amount of sulfonate adsorbed was determined by measuring the difference in the sulfonate concentration in the solution before and after contact with kaolinite. In the presence of NaCl and Na2SO4 or Na2SO4, only (i.e., without any alkaline agents), the pH of the supernatant liquid increases from about 6.7 to 7.3 as a function of sulfonate equilibrium concentration. p. 123–127
- North America > United States (0.68)
- Europe > France (0.54)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Summary This paper presents a calculation of the propagation of basic pH in a reservoir rock based on either a kinetically controlled reaction or a thermo dynamic equilibrium assumption. Results demonstrate that the kinetic approach is the only way to analyze the interactions of alkaline chemicals with clayey sandstones properly. Introduction Prediction of alkali consumption is of great importance to ensure Prediction of alkali consumption is of great importance to ensure the success of an EOR process that uses alkaline additives. Two approaches were followed. In the first, reaction times at field scale were supposed to be long enough to reach thermodynamic equilibrium at each point of space and time. This thermodynamic approach, including the formation of a new mineral (the sodium zeolite, analcime), was carried out by use of solubility data. In the second approach, it was considered that dissolution is controlled by kinetic limitations. The key effects of the adsorption of aluminum and silicon species on solid surfaces, which reduces the reactivity of the minerals, and the precipitation of analcime formed during the attack were incorporated into the rate equations used to describe the dissolution. A model was developed to calculate the propagation of pH on the basis of either a kinetically controlled reaction or a thermodynamic equilibrium assumption. Hydroxide consumption by ion exchange was also considered. A direct comparison of the two approaches was made as a function of such different parameters as composition of the alkaline solution, concentration, and slugsize. The data clearly demonstrated that, when considering local thermodynamic equilibria, an alkaline solution cannot propagate be- cause of the complete transformation of clays into analcime under alkaline conditions. The kinetic approach, which gives results in close agreement with published experimental data, is the only way to analyze the interactions of alkaline chemicals with clayey sand- stones. Background Use of alkaline chemicals for EOR has been documented widely. Recently, the use of these chemicals, along with surfactants or polymers, has been suggested to improve the oil recovery performance polymers, has been suggested to improve the oil recovery performance of these processes. Because of the various technical problems connected with the injection of alkali into a reservoir, solid/liquid interactions are considered the most critical factor because they are the main cause of alkali consumption. Rock/alkali reactions involve two different mechanisms: ion exchange and rock dissolution. Several authors have tried to quantify these mechanisms and have proposed flow models that allow better estimates of long-term consumption effects. As far as ion exchange is concerned, the theory of chromatography is well-adapted to calculate the transport of alkaline buffers in reservoir rock. On the other hand, there is controversy about the way to approach the problem of rock dissolution. Some workers assume that, because of the slow propagation rate of the fluids into the reservoir, dissolution can be considered to be at equilibrium. In this respect, mathematical theories, based on the equilibrium postulate, were developed to describe reactive flow involving precipitation/dissolution processes. These theories, including ion exchange, have been processes. These theories, including ion exchange, have been used to model the propagation of alkaline additives. However, the specific mineral transformations that occur in basic pH with the resulting hydroxide consumption were not introduced clearly. Other authors deduced from laboratory experiments that dissolution is kinetically limited. These investigators describe the dissolution rate with empirical relations involving irreversible first-order or pseudo-first-order reactions for silica precipitation/dissolution. Our previous work on rock/alkali precipitation/dissolution. Our previous work on rock/alkali reactions demonstrated the key role of clays in quartz dissolution and that adsorption processes drastically reduce the proper reactivities of each mineral. In this paper, we present a flow model that describes the transport of alkali through a porous medium to evaluate the consumption of the alkaline agent in conditions in which precipitation/dissolution of minerals and hydrogen/sodium ion exchange can occur. The main objectives of the model are to take into account the dissolution of quartz and clays under alkaline conditions to produce analcime and to use kinetic equations based on extensive experimental work on the dissolution mechanisms of sandstones by alkalis. The main advantage of the model is its capacity to compare the behavior of the alkaline agent either when dissolution of minerals is subjected to kinetic limitations or when solid/liquid local thermodynamic equilibria are assumed to exist. The transport equations and the equilibrium relations in solution are written for both assumptions; i.e., thermodynamic equilibrium and kinetic representation. Results of simulations are compared and discussed by considering continuous injection of alkali and a slug injection. The effect of the kinetic factors on the alkaline slug propagation is emphasized in cases of both high- and low-pH chemicals. Conclusions are given on the conditions of pH propagation at field scale. Modeling of Alkaline Dissolution It is assumed that the porous medium is made of a quartzitic sandstone associated with kaolinite. Previous results have demonstrated that, within a large range of experimental conditions covering the field of practical applications, the dissolution of kaolinite and quartz by alkalis leads to analcime precipitation. As a matter of fact, in strongly alkaline conditions and at high Na content, the sodium zeolite, analcime, is stable with respect to other clay minerals. The transformation of kaolinite into analcime occurs with a consumption of alkali according to (1) This is why we considered quartz, kaolinite, and analcime. Two hypotheses can be made to describe the alkaline dissolution/precipitation process: the process either is kinetically limited or is governed by thermodynamics. Other general assumptions include the following:the medium is ID, homogeneous, and of constant porosity; precipitates cannot migrate by entrainment in the flowing phase; species in solution are at chemical equilibrium; and physical dispersion is neglected. All the concentrations of the chemical species, in solution and on the solid surfaces or precipitated, refer to the aqueous phase. Subject to these assumptions, the transport of species through the porousmedium is described with a set of partial-differential equations expressing mass conservation. The system is described with five mass equations relative to aluminum, silicon, sodium, chloride, and carbon (when the alkali is Na2CO3). SPERE P. 151
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.65)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary This paper investigates pore-scale mechanisms of both wetting and nonwettingphase dropout and flow at low interfacial tensions (IFT's) (approximately 0.1to less than 0.01 mN/m) by use of transparent 2D micromodels with a partiallymiscible binary fluid system. Quantification is possible with this liquidsystem because it has uniquely defined physical properties at any giventemperature. Phase dropout and flow physical properties at any giventemperature. Phase dropout and flow behavior at phase saturations of less than10% are emphasized. Wettability effects are dominant, but the fluid/fluidinteractions change as the IFT drops. The ramifications for the relativepermeability curves are discussed. Introduction Hydrocarbon production by pressure depletion leads to phase dropout when aphase boundary is crossed; e.g., retrograde condensation in gas condensateswhen the pressure falls below the dewpoint line and gas release in volatileoils when the pressure falls below the bubblepoint line. Multiphase flow ispressure falls below the bubblepoint line. Multiphase flow is then possibleprovided that the saturation of the emerging phase is sufficient. This criticalsaturation value is, however, currently speculative with estimates ranging from2 to 30%. Often the IFT between the liquid and vapor phases is less than 1mN/m, as Haniff and Pearce show in their data from a novellaser-light-scattering technique for measuring low IFT's. They measured IFT'sin the retrograde region for a retrograde condensate fluid and found that alarge area of the retrograde region (517 kPa × 15C) had IFT's less than mN/m. The phase dropout and flow behavior of such fluids within porous media have notbeen fully investigated, especially the effects of ultralow (less than 0.01mN/m) IFT. The available evidence is conflicting, but strongly suggests thatdifferences exist between low- and high-tension behavior. This paper examineseffects occurring during phase dropout and multiphase flow at IFT less than 1mN/m. Pore-Scale Flow Behavior. Although the evidence for changes in Pore-Scale Flow Behavior. Although the evidence for changes in the flow characteristics oflow-IFT multiphase systems (i.e., reduced residual saturations and increasedrelative permeabilities) is substantial, very little knowledge exists about themechanisms that cause these effects. The black-box nature of core experimentsprevents a full study of the physical processes occurring within the prevents afull study of the physical processes occurring within the core, such as theeffects that the rock, rock/fluid, and fluid/fluid properties (e.g., permeability, wettability, and viscosity ratio) have properties (e.g., permeability, wettability, and viscosity ratio) have on the phase-dropoutbehavior and flow characteristics of a given system. Studying these effects atthe pore scale is the first step to reaching the goal of accurate fieldprediction. Pore-scale mechanisms of both wetting and nonwetting phase flow andseparation at IFT's ranging from 1 to less than.01 mN/m throughout the completewetting-phase saturation range (0 to 100%) can readily be studied with a visualmodeling system. In this paper, experiments are reported for a binary fluidmixture capable of representing both gas-condensate and volatile-oil fluidsystems. Particular emphasis is placed on fluid behavior at phase saturationsrelevant to gas-condensate and volatile-oil reservoirs (i.e., when either thewetting or the nonwetting phase occupies less than 10% of the pore space), andon porous-medium influences (wettability). Wettability controls the positionsof the fluids and hence affects multiphase flow. The effects positions of thefluids and hence affects multiphase flow. The effects of wettability of theporous medium and of fluid flow on the phase-dropout processes are highlighted. The behavior of the emergent phase-dropout processes are highlighted. Thebehavior of the emergent phase, which may be either wetting or nonwetting, andthe phase phase, which may be either wetting or nonwetting, and the phasedropout processes of wetting-layer growth and droplet formation have also beeninvestigated. Approach Micromodels. In this study, etched glass micromodels were used to representthe porous medium. Micromodels are becoming popular for identifying pore-scaleevents, and Dawe describes a number of novel micromodel applications to flow inporous media. The transparent nature of the glass allows direct observation ofphase separation, fluid flow, and displacement mechanisms at the pore scale. The network arrangements may be drafted by hand or by computer and can bedesigned to isolate individual rock properties, such as pore shape, pore size, coordination number (number of pore throats entering or leaving one pore body), or aspect ratio (pore-body/pore-hroat diameter). The network used for thisstudy (Fig. 1) was a combination of pores, some with a coordination number ofeight and some with a coordination number of three. Micromodel construction andproduction are described in Ref. 10. Fluid System. The fluid system used, denoted here as LW, is the partiallymiscible binary fluid system 2,6-lutidine (2, partially miscible binary fluidsystem 2,6-lutidine (2, 6-dimethyl-pyridine) and water. This system has a lowercritical solution temperature (LCST) of 34.1C for a 28 wt% lutidine (i.e., 28wt% lutidine and 72 wt% water) composition (Fig. 2). On heating, a mixture ofany initial composition, Cj, within the range of 5 to 70 wt% lutidine (i.e., asingle-phase fluid) will separate into two conjugate Phases A and B when thephase boundary is crossed. Phase A will be rich in the water component withcomposition C A; Phase B will be rich in the lutidine component withcomposition C B. For a particular temperature, the phase rule dictates that thecompositions of the two coexisting phases will be constant, irrespective of theinitial single-phase composition, and have constant physical properties. Onlythe ratio of Phase A to Phase B will be altered. This makes it possible tocontrol the properties of the system merely by altering the temperature.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
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Summary A laser-light-scattering technique was used to measure a range of interfacial tensions (IFT's) from 1 to 10(-3) mN/m in a methane/propane gas-condensate system. The data were compared with the Weinaug-Katz (WK) and the Hough-Stegemeier (HS) correlations. Results show that the HS correlation performed better when used on the critical isotherm. On other isotherms, the WK correlation gave the better fit. Introduction Low IFT between fluid phases plays a particularly important role in the success of most tertiary recovery processes in hydrocarbon reservoirs. In miscible systems, for example, enhanced hydrocarbon recovery relies on the interaction between the displacing and inplace fluids producing near-zero IFT. Here, mixing and mass transfer take place across the phase boundary, producing changes in fluid properties that lead to thermodynamic miscibility and reduced capillary pressures. This result produces low residual liquid saturation and is the ultimate objective in such processes as miscible and surfactant flooding. In gas-condensate reservoirs below the dewpoint, hydrocarbon fluid separates in the rock formation into its constituent liquid and vapor phases. Here, the EFT between phases varies with pressure. The volume of liquid condensing in the formation is often small, close to the critical saturation. This leads to permanently trapped liquid hydrocarbon. Laboratory experiments with condensate fluids, however, show that fluid flow rates are considerably improved and residual liquid saturations much reduced when IFT is low (less than 0.04 mN/m). These works demonstrate the importance of low IFT in correlating improved flow rates and low residual saturations with fluid composition and hence reservoir pressures. At present, a significant gap exists in experimental work on condensate systems reporting IFT data below 0.04 mN/m, partly because of the difficulty of controlling fluids at high pressures and temperatures. Moreover, when very low tensions are measured, extra care must be taken to avoid extraneous vibrations. Thus, equipment must be mounted on vibration-free tables, adding to the overall cost. Stegemeier appears to be the only one reporting data below 0.04 mN/m. His work is based on the pendant-drop technique, but the method perturbs the fluid system and is subject to errors when fluids are measured close to their critical points. For these reasons, existing correlations are used to extrapolate points. For these reasons, existing correlations are used to extrapolate to values below 0.04 mN/m. Two types of correlations, which are often used at high tension values with pure-component systems, have been shown to be reasonably accurate when predicted values are compared with experimental data:methods that correlate the tension as a unique function of reduced temperature, often called corresponding states correlations, and the method proposed by Macleod and modified by Sugden that uses the parachor. In mixture systems, these methods are modified and empirical mixing equations are introduced. The most widely used correlations in the oil and gas industry for predicting EFT in hydrocarbon fluid systems are the WK correlation and predicting EFT in hydrocarbon fluid systems are the WK correlation and its modified version derived by Hough and Stegemeier. More recently, Lee and Chien derived a correlation based on critical scaling laws that can be used to predict IFT near the fluid's critical point. While these correlations predict high tension values with reasonable accuracy in the absence of good experimental data, their precision at lower values is somewhat uncertain. In this paper, we summarize the results of an experimental study on IFT measurements on a two-component gas-condensate system and compare our results with data derived from the WK and HS correlations. We used a methane/propane fluid system with critical properties similar to those described by Sage et al. and a laser-light-scattering technique as the preferred method of IFT measurements. This measurement technique has preferred method of IFT measurements. This measurement technique has the advantage of being nonperturbative and needs only a small volume of liquid to make measurements. Thus, it is capable of measuring surface properties of a fluid close to its critical point. properties of a fluid close to its critical point.
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- Europe > Norway > Norwegian Sea (0.24)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.54)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
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Summary Pseudoplastic non-Newtonian polymer solutions were examined for theirenhanced oil recovery performance. Detailed results are reported for xanthangum (XAN), Kelzan XCD, and a viscoelastic polyethylene oxide (PEO), PolyoxOF-50. Increases in the power-law coefficient resulted in improved displacementefficiency. Effects were also observed in the injectivity-index parameterresults. Introduction Most polymers proposed for polymer flooding, regardless of their chemicalorigin, display non-Newtonian fluid behavior to some degree. The apparentviscosity of the polymer solution is a function of the shear rate to which itis subjected. At shear rates encountered at reservoir conditions (0.1 to 100seconds), polymers typically exhibit shear thinning or pseudoplastic behavioraccording to tangential shear measurements. Certain synthetic polymers, particularly the PEO type and, to a lesser extent, partially hydrolyzedpolyacrylamides (PHPA), show dilatant- or shear-thickening-type responsesduring flow through porous media, despite demonstrating pseudoplasticity in atangential shear viscometer. Numerous researchers have explained this behaviorin terms of a viscoelastic contribution to the overall non-Newtonian propertiesof these polymers. The displacing-fluid viscosity has been shown to be of majorimportance to the outcome of an immiscible displacement process as quantifiedby the overall displacement efficiency, the product of displacementefficiencies at the microscopic and macroscopic levels. The microscopicdisplacement efficiency attained in a flood is reflected in the residual oilsaturation. Sor, achieved. Correlations for predicting Sor for various porousmedia have shown that increasing the displacing-fluid viscosity can improvemicroscopic displacement efficiency. Macroscopic displacement efficiency islargely a function of the mobility contrast between displaced- and displacingfluid phases and is commonly expressed in terms of the well-known mobilityratio, M, where ........................... (1) When M is less than 1, the displacement takes place in a pseudo-piston-likemanner with a stable displacement front. Under these circumstances, sweepefficiency with respect to the volume of displacing fluid injected is high. Therefore, increasing the displacing-fluid viscosity obviously benefits themacroscopic displacement efficiency. For immiscible polymer flooding, themacroscopic velocity, and hence shear-rate, profiles that develop withinjection/production well patterns influence polymer viscosity and overalldisplacement efficiency because of the non-Newtonian polymer rheology. In thevicinity of injection or production wellbores, fluid velocities are highest, but rapidly decline as the distance from the wellbore increases. In idealhomogeneous reservoirs, velocities also tend to be more elevated along thediagonals connecting injector to producer. For pressure-constrained injectivityoperations, the velocity profiles also will be influenced by the transient flowcharacteristics encountered during the flood. The displacing-fluid injectionrates will vary, depending on the effective mobility of the displacing fluid ata given stage in the flood. Hence, different operating practices for a givenflood-injection flow rates or pressures might yield different performanceoutcomes. The goal of this study was to investigate the effects ofnon-Newtonian displacing-fluid rheology on the oil-displacement process. Oil-displacement experiments involving two polymer types were carried out underconditions representing pressure-constrained injectivity operations. Specifically, the effect of shear rate on the oil-displacement process wasexamined by varying pressure gradients in linear-geometry corefloods. Thepolymer solutions were also characterized in terms of shear stress andinterfacial tension (IFT). Experimental The two polymers examined in this study were a XAN and a PEO. The PEOpolymer was Polyox OF-50 manufactured by Union Carbide Corp. The XAN polymerwas a Kelzan XCD sample supplied by the Kelco Rotary Co. Polymer solutions wereprepared according to recommended procedures provided by the polymermanufacturers. To simulate a realistic aqueous solvent, a brine with acomposition similar to that of the Canadian Pembina field polymer pilot wasused in this study. Polymer solutions were characterized rheologically by useof a Couette viscometer, the Haake Rotovisco RV100/CV100. This viscometer, fitted with a Mooney-Ewart ME 45 coaxial cylinder sensor, is capable ofmeasuring apparent viscosities of dilute polymer solutions over a shear-raterange of 0 to 300 seconds-1 with an upper/lower bound on shear stress of 8000and 10 mPa, respectively. The rheological data obtained in this manner werecharacterized with the well-known de Waele (power-law) function forviscosity: ........................... (2) The displacement experiments were performed on an unconsolidated porousmedium in the form of Grade F75 Ottawa quartz sand. The average sand porositywith respect to the brine was 38.6%. The oil used in this study was a mineraloil with a viscosity of 30 mPa.s and a specific gravity of 0.855-correspondingto 0.85 g/cm3 at 25 degrees C. IFT's of the displacing-fluid/oil systems weredetermined from measurements carried out at 25 degrees C with a Fischer de Nuoytensiometer. Two core holders of Lucite pipe equipped with detachablestainless-steel end sections were used in the linear coreflood experiments. Core Holder 1 was 38.3 cm long and 4.5 cm in diameter, and had a PV of 235 mL. Core Holder 2 was 38.6 cm long and 4.7 cm in diameter, with a PV of 258.5 mL. The equipment layout consisted of a pressurized vessel connected to the linearcore holder from which fluid effluent samples were collected during thedisplacement experiments. A typical coreflood proceeded as follows. First, avibrating shaker was used to wet pack the core holder with sand. The coreholder was then sealed, and the core permeability to brine, k, was determinedby flow-rate/pressure-drop measurements. The core was then saturated with oilto produce an interstitial water saturation, Siw, at which time the corepermeability to oil, ko(Siw), and the oil mobility, Lambda o(Siw), at thissaturation were calculated. The core was then displaced with a polymer solutionat a fixed imposed pressure gradient. Effluent samples were taken periodicallywere taken at the core outlet to determine flow rates and phase compositions. Floods were carried out with polymer solutions at concentrations of 2,500,1,500, and 500 ppm. For comparative purposes. a base-case waterflood also wascarried out. SPERE November 1990 P. 481⁁
- North America > Canada > Alberta > Yellowhead County (0.24)
- North America > Canada > Alberta > Wetaskiwin County No. 10 (0.24)
- North America > Canada > Alberta > Ponoka County (0.24)
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- Geology > Geological Subdiscipline > Geomechanics (0.55)
- Geology > Mineral (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Cardium Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary Two methods are presented for predicting critical oil rate for bottomwater coning in anisotropic, homogeneous formations with the well completed from the top of the formation. The first method is based on an analytical solution where Muskat's assumption of uniform flux at the wellbore has been replaced by that of an infinitely conductive wellbore. The potential distribution in the oil zone, however, is assumed unperturbed by the water cone. The method is derived from a general solution of the time-depedent diffusivity equation for compressible, single-phase flow in the steady-state limit. We show that very little difference exists between our solution and Muskat's. The deviation from simulation results is caused by the cone influence on potential distribution. The second method is based on a large number of simulation runs with a genral numerical reservoir model, with more than 50 critical rates determined. The results are combined in an equation for the isotropic case and in a single diagram for the anisotropic case. The correlation is valid for dimensionless radii between 0.5 and 50 and shows a rapid change in critical rate for values below five. Within the accuracy of numerical modeling results, Wheatley's theory is shown to predict the correct critical rates closely for all well penetrations in the dimensionless radius range from 2 to 50. Introduction Oil production from a well that partly penetrates an oil zone overlying water may cause the oil/water interface to deform into a bell shape. This deformation is usually called water coning and occurs when the vertical component of the viscous force exceeds the net gravity force. At a certain production rate, the water cone is stable with its apex at a distance below the bottom of the well, but an infinitesimal rate increase will cause cone instability and water breakthrough. This limiting rate is called the critical rate for water coning. Muskat and Wyckoff presented an approximate solution of the water-coning problem. For an istropic reservoir, the critical rate may be estimated from a graph in their work. Their solution is based on the following three assumptions:the single-phase (oil) potential distribution around the well at steady-state conditions is given by the solution of Laplace's equation for incompressible fluid; a uniform-flux boundary condition exists at the well, giving a varying well potential with depth; and the potential contribution in the oil phase is not influenced by the cone shape. Meyer and Garder simplified the analytical derivation by assuming radial flow and that the critical rate is determined when the water cone touches the bottom of the well. Chaney et al. included completions at any depth in a homogeneous, isotropic reservoir. Their results are based on mathematical analysis and potentiometric model techniques. Chierici et al. used a potentiometric model and included both gas and water coning. The results are presented in dimensionless graphs that take into account reservoir anisotropy. Also, Muskat and Wyckoff's Assumption 2 is eliminated because the well was represented by an electric conductor. The graphs are developed for dimensionless radii down to five. For thick reservoirs with low ratios between vertical and horizontal permeability, however, dimensionless radii below five are required. Schols derived an empirical expression for the critical rate for water coning from experiments on Hele-Shaw models. Recently, Wheatley presented an approximate theory for oil/water coning of incompressible fluids in a stable cone situation. Through physical arguments, he postulated a potential function containing a linear combination of line and point sources with three adjustable parameters. The function satisfies Laplace's equation, and by properly adjusting the parameters. Wheatley was able to satisfy the boundary conditions closely, including that of constant well potential. Most important, his theory is the first to take into account the cone shape by requiring the cone surface---i.e., the oil/water interface---to be a streamle. Included in his paper is a fairly simple procedure for predicting critical rate as a function of dimensionless radius and well penetration for general anisotropic formations. Because of the scarcity of published data on correct critical rates, the precision of his theory is insufficiently documented. Although each practical well problem may be treated individually by numerical simulation, there is a need for correlations in large-gridblock simulators and for quick, reliable estimates of coning behavior. This paper presentsan analytical solution that removes Assumptions 1 and 2 in Muskat and Wyckoff's theory; practical correlations to predict critical rate for water coning based on a large number of simulation runs with a general numerical reservoir model; and a verification of the predictability of Wheatley's theory. All results are limited to a well perforated from the top of the formation. Analytical Solution The analytical solution presented in this paper is an extension of Muskat and Wyckoff's theory and is based on the work of Papatzacos. Papatzacos developed a general, time-dependent solution of the diffusivity equation for flow of a slightly compressible, single-phase fluid toward an infinitely conductive well in an infinite reservoir. In the steady-state limit, the solution takes a simple form and is combined with the method of images to give the boundary conditions, both vertically and laterally, as shown in Fig. 1 (See the appendix for details). To predict the critical rate, we superimpose the same criteria as those of Muskat and Wyckoff on the single-phase solution and therefore neglect the influence of cone shape on the potential distribution. A computer program was developed to give the critical rate in a constant-pressure square from Eqs. A-6 through A-13. The length of the square was transformed to an equivalent radius for a constant-pressure circle to conform with the geometry of Fig. 1 and the simulation cases. The results of the analytical solution are presented in Fig. 2, where critical rate, qcD, is plotted vs. dimensionless radius, rD, for five fractional well penetrations, Lp/ht, with the definitionsEquation (1) And Equation (2) Numerical Simulation The critical rate was determined for a wide range of reservoir and well parameters by a numerical reservoir model. The purpose was to check the validity of the analytical solutions and to develop separate pratical correlations valid to a low dimensionless radius. A summary is presented here; Ref. 12 gives the details. The numerical model used is a standard, three-phase, black-oil model with finite-difference formulation developed at Rogaland Research Inst. The validity of the model has been extensively tested. It is fully implicit with simultaneous and direct solution and therefore suitable for coning studies.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
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Summary A systematic study is conducted to describe the transient interfacial tension (EFT) behavior of crude-oil/caustic interfaces. The variation in this behavior with variation in the composition of the aqueous phase and other parameters is the focus of this study. It is found that at low pH values, the experimentally observed behavior is similar to that reported earlier. At high pH values, however, a maximum in IFT is observed, followed by a minimum at a late time. Sodium chloride is shown to have no significant effect on the shape of the transient IFT curve, but the absolute values of IFT are at lower NaCl concentrations. Divalent ions dramatically increase the IFT. A chemical model that takes into account the kinetics and the detailed chemistry of the process is used to explain the observed phenomena. The phenomenological surface phase approach is used to phenomena. The phenomenological surface phase approach is used to model the interface. The resultant set of ordinary differential equations is linearized by making certain justifiable, simplifying assumptions. The analytical solution to the set of equations yields the variation of the various concentrations with time. The IFT is then related to the interfacial concentration of the surface-active species, A, by the Gibbs equation. The variation in the transient IFT behavior on changing the kinetic constants, phase volumes, and ionic concentrations is discussed. Finally it phase volumes, and ionic concentrations is discussed. Finally it is shown that the extension of this model to a two-component model would successfully explain all the experimentally observed phenomena. Introduction The lowering of DT at crude-oil/caustic interfaces was observed by Atkinson and Nutting many years ago. This led to the use of caustic solutions as EOR agents. Much work has since been done to elucidate the mechanisms of such a process. It is now well established that the alkali-sensitive components of the crude oil diffuse out to the interface, where they react with the caustic to generate surface-active species. These surface-active species either adsorb at the interface to lower the IFT or diffuse out into the bulk aqueous phase. This sequence of events-convective-diffusion reaction-gives rise to interesting IFT maxima and minima as dictated by the relative kinetics of each step. Such a phenomenon is not restricted to the system studied here. Similar observations may be made in any system involving interphase mass transfer of a solute between two miscible fluid phases accompanied by a chemical reaction. The emphasis in this paper, however, is placed on understanding the mechanisms and kinetics of crude-oil/caustic interfaces, and the experimental results and kinetic models are presented with that objective in mind. From the onset, the chemistry of the process has been the focus of much attention and controversy. Attempts were made by Seifer and Howells, Seifert, Yen et al., Farmanian et al., and Wasan et al. to isolate and identify the surface-active components present at the interface. The interfacial region was shown to present at the interface. The interfacial region was shown to consist mainly of long-chain carboxylic acids with a wide range of molecular weights (- 300 to 400) and chemical structures. Although most of the long-chain acids found were saturated aliphatics, some unsaturated, substituted, and aromatic acids and diacids were also identified. Nitrogen and sulfur heteroatoms were also found to be concentrated at the interface. Dunning et al. showed that porphyrins and porphyrin/metal chelated complexes exhibit strong porphyrins and porphyrin/metal chelated complexes exhibit strong interfacial activity and film-forming characteristics. The presence of other metals like copper, zinc, and nickel in presence of other metals like copper, zinc, and nickel in oil-soluble forms as porphyrin/ metal chelate complexes led Dodd et al. to conjecture that the interfacial films were stabilized by resins, porphyrins, porphyrin ring oxidation products and protein/metal porphyrins, porphyrin ring oxidation products and protein/metal salts. Some recent results show how this complex chemistry might affect the dynamic IFT behavior. They separated the crude oil into three fractions on the basis of differences in boiling points, Fraction 1 being the lowest boiling. Fraction 2 exhibited points, Fraction 1 being the lowest boiling. Fraction 2 exhibited a minimum in IFT with time. Fraction 3, which presumably contained the higher-molecular-weight asphaltic components, however, showed no minima at all. This leads us to believe that more than one species is involved in the diffusion and reaction process occurring at the interface. The overall behavior of the crude oil will therefore be governed by the relative amounts of these species present and by their individual diffusion and kinetic constants. present and by their individual diffusion and kinetic constants. From this brief review, it is evident that the chemistry of the reaction between caustic and crude oil is extremely complex. This fact must be home in mind when certain simplifying assumptions are made later in this paper in developing the kinetic model. Ward and Tordai were the first to describe quantitatively the role of diffusion in the time-dependent IFT behavior of solutions. Later England and Berg 12 studied the same problem of transfer of surface- active solute across liquid/liquid interfaces-no interfacial reactions were involved. Most of the earlier attempts model the transient behavior of solute extraction from the oleic phase as a simple diffusional process where the flux into and out of the interfacial region is represented by Fick's law. This, however, is not the case for the system considered here, as has been demonstrated by many studies on liquid/liquid extraction of a solute from one phase into another. Wei accumulated qualitative data on a wide range of liquid/liquid extraction systems and showed that in almost every instance where either of the two phases contained reacting solutes, there was evidence of localized Marangoni disturbances and convection currents were spontaneously set up. In such systems, as Sternling and Scriven later showed, such interfacial turbulence was more intense whensolute was being transferred out of the phase of higher viscosity, solute was transferred out of the phase of low diffusivity, there were large differences in kinematic viscosity and solute diffusivity between the two phases, steep concentration gradients were present near the inter-face, IFT was highly sensitive to the concentration of solute, both phases had low diffusivities and viscosities, there were no surface-active species present, and the interfaces were of large extent. For our system, all but Condition 7 are met. Indeed, the presence of surface-active species has been shown to dampen out presence of surface-active species has been shown to dampen out interfacial turbulence. For crude-oil/caustic systems, however, such interfacial turbulence is quite pronounced and has even been shown to lead to spontaneous emulsification. In addition to the interfacial turbulence generated by the gradient in chemical potential, the instrument used in this study to measure IFT-the spinning-drop tensiometer-generates its own fluid motions in the external (aqueous) and internal (oleic) phases. The detailed hydrodynamics of this instrument was recently described by Currie and Nieuwkoop, who showed theoretically and experimentally, by use of an n-butanol/water system, that at speeds of revolution less than 5,000 rev/min, the axis of the spinning drop in a spinning-drop tensiometer is displaced from the axis of rotation of the capillary tube because of buoyancy and Coriolis forces. This displacement gives rise to fluid convective movement in both phases. The Eckman cones and the flow-velocity regimes inside and in the vicinity of the drop were observed visually. However, to avoid interfacial deformation from these effects and to ensure no dependence of IFT on speeds of rotation, the IFT was measured at 7,000 rev/min. Even at this speed of rotation, it is conceivable that small convective currents may be present. It is evident from the preceding discussion that modeling the transport of solute from the crude oil to the interface and from the interface into the aqueous phase as a purely diffusional process is clearly a gross oversimplification. process is clearly a gross oversimplification. SPERE P. 228
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Summary. This study has two objectives:to screen and select foaming agents for specific CO2 floods and to determine the effectiveness of foam in improving sweep efficiency in CO2 flooding. Foaming agents were evaluated on their ability to produce ample, lasting foam and to have low loss from adsorption on reservoir rock and decomposition at reservoir conditions. Foaming agents that performed well in shaking, blender, long-term stability, and high-pressure stability tests were selected for core-flow experiments. The stability test results demonstrated that foaming agents are reservoir-specific. The extent of the loss depends on the foaming agent, reservoir fluids, reservoir lithology, and reservoir conditions. The core-flow experiments involved the simultaneous injection of CO2 into two waterflooded Berea cores. The cores were arranged in parallel and had different permeabilities. The test temperature and pressure were constant and above the critical conditions for CO2. Three types of core-flow tests, involving injection of CO2 to displace oil, injection of alternate slugs of CO2 and brine, and injection of foaming agents, were conducted. The foaming agents were injected before CO2 injection and after CO2 had displaced oil from the more permeable core. The results show that in-situ foam generation is an effective method for improving CO2) displacement efficiency. Foam was most effective when the foaming agent was injected after CO2 displaced the oil from the more permeable core. The improved sweep efficiency was caused by the tendency permeable core. The improved sweep efficiency was caused by the tendency of the foam to be generated preferentially in the more permeable core. The foam increased resistance to flow in this core and caused more CO2 to flow through the less permeable core. The second injection method is also more applicable to field implementation. Introduction Laboratory experiments and fieldwide tests have shown that significant amounts of residual oil can be recovered by CO2 flooding. The success of the CO2 floods has been diminished by the unfavorable mobility ratio between CO2 and oil. The unfavorable mobility ratio, together with the heterogeneities of the reservoir, results in reduced sweep efficiency. Several methods have been proposed to control CO2 mobility. The major methods are direct thickening of CO2 with chemicals, injection of alternate slugs of CO2 and water, and in-situ generation of foam. Direct thickening of CO2 involves increasing its viscosity by adding a chemical directly to supercritical CO2. It has been difficult, however, to find chemicals that at low concentration can increase the viscosity of dense-phase CO2. In the other method of improving CO2 mobility, water-alternating-gas (WAG) injection, the multiphase flow of CO2 and water increases the resistance to flow, thereby reducing the CO2 mobility. A WAG process, however, is not without its drawbacks. Major ones are process, however, is not without its drawbacks. Major ones are gravity segregation between water and CO2 and increased project time. A promising method of mobility control is the in-situ generation of foam by the injection of slugs containing a foaming agent. CO2 disperses throughout the liquid slug, generating a large interfacial area whose resistance to flow is much greater than that of the CO2 or the solution. This process causes increased flow of CO2 to unswept areas of the reservoir. A foaming agent can also reduce the interfacial tension at the oil/water interface and thereby assist in mobilizing residual oil. The major objectives of this laboratory study were to develop and implement methods to screen and select foaming agents and to test the oil production efficiency of the foaming process in parallel cores of different permeabilities. Selection of a Foaming Agent An effective screening method should result in the selection of a suitable foaming agent for a given set of reservoir conditions. The foaming agent should be capable of generating ample, lasting foam in the presence of reservoir rock. It should have low adsorption and decomposition losses. A good foaming agent should increase the CO2 sweep efficiency and the oil recovery in porous media tests. In addition, it should be commercially available and inexpensive. A screening procedure was devised and implemented. This procedure is similar to that given by others. Fig. 1 shows the procedure is similar to that given by others. Fig. 1 shows the overall screening method. It consists of preliminary screening, sta-bility, and core tests. Preliminary Screening Tests. Preliminary screening provides a rapid and simple method for estimating the concentration of maximum foam quality, for determining relative foaming ability and stability, and for estimating the effects of brine and oil on these properties. Shaking and blender tests were used to determine the foaming ability and stability. The shaking test used air and isooctane, whereas the blender test used air. In each test, the foam volume and the time required to drain one-half of the liquid were recorded. The foam volume and liquid were used to calculate foam quality. The time for one-half of the liquid to drain was taken as a measure of foam stability. Stability Tests. A foaming agent may lose its ability to function in the reservoir because of adsorption on the reservoir rock, partitioning into the oil, or chemical decomposition. The main goals partitioning into the oil, or chemical decomposition. The main goals of the stability tests are to determine these losses and to help predict which foaming agents would have a good chance of success over the life of a CO2 field flood. Fig. 2 shows the test variables, test duration, and the determined properties for short-term, long-term and high-pressure stability. The short-term static adsorption tests last for several days and are conducted in reservoir brine with crushed rock at reservoir temperature and different foaming-agent concentrations. The long-term stability tests last for 6 months. They include the conditions of the short-term static adsorption tests; in addition, the pH is adjusted to that caused by the dissolution of CO2. The high-pressure stability testing apparatus featured two high-pressure window cells that could be rotated to mix their contents. SPERE P. 1186
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- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary. The surfactant properties usually required for EOR are investigated with alpha-olefin sulfonates (AOS's), particularly at high temperature, salinity, and hardness, together with their solubility in brine, chemical stability, phase behavior, and adsorption. The use of a cosolvent enables aqueous solutions to be prepared with concentrated brine, even at high divalent cation levels. But the chemical stability of some solutions can be affected by their sensitivity to the oxidation of unsaturated components, resulting in a decrease of the pH. Precautionary measures to stabilize the solutions are stressed-i.e., anaerobic environment, maintenance of an alkaline pH, or addition of alcohol. As already shown, these surfactants provide low interfacial tensions (IFT's) and high solubilization parameters at high salinity and divalent cation content. Properties of optimal formulations have been investigated as a function of Properties of optimal formulations have been investigated as a function of surfactant and cosolvent molecular weight and brine composition. Adsorption data on Na- and Ca- kaolinite are presented. In NaCl solutions, the amount of sulfonate adsorbed increases slightly with salinity. Preliminary measurements in hard water are shown to bring out the specific effect of calcium ions. According to the results concerning properties validly considered as screening criteria, we conclude that this family of sulfonates appears to be a potential candidate for EOR. potential candidate for EOR. Introduction Petroleum and synthetic aromatic sulfonates were the first Petroleum and synthetic aromatic sulfonates were the first surfactant families selected for EOR by micellar flooding because of their availability and relatively low cost. Their performances decrease as water salinity and divalent cation concentration increase, however, inducing poor brine solubility and low interfacial effectiveness. In many fields, the electrolyte content is higher than 50 g/L'; therefore, the micellar flooding process would increase to a great extent if the salinity is no longer a limiting factor. For this purpose, other classes of surfactants have been suggested-e.g., purpose, other classes of surfactants have been suggested-e.g., sulfated or sulfonated ethoxylated fatty alcohols or alkylphenols. which display both anionic and nonionic character in the same molecular structure, and AOS'S. These last compounds, dealt with in this paper, are relatively easy to manufacture and are of moderate price. paper, are relatively easy to manufacture and are of moderate price. They have been suggested for EOR, and recent papers have reported quite favorable behavior at high salinity from an interfacial standpoint: solubilization parameters and IFT'S. For a surfactant to be considered as a candidate for EOR, the main requirement is its ability to give low IFT's in multiphase systems formed in porous media The relationship between IFT's and phase behavior in the surfactant/oil/brine systems is well known, but it is imperative to take other properties into account, such assolubility in hard water (because of the possibility that the process is implemented by injection of aqueous surfactant solutions instead of oil-containing microemulsions); long-term chemical stability; sensitivity of phase behavior-e.g., to the variations in salinity that may arise from interactions with the rock surface, especially clay minerals, and to the variations in surfactant concentration; and adsorption onto the reservoir rock. Extending the evaluation of AOS's to these properties is the purpose of this paper. Encouraging results previously reported are confirmed, but some features are also pointed out related to solubility, pH conditions, and adsorption behavior that should be considered pH conditions, and adsorption behavior that should be considered in any investigation for implementing the process. Experimental Materials. C16, C18, and C20 through C14 AOS's were manufactured with sulfur trioxide and the falling-film technique. The AOS consisted of a mixture of alkane sulfonate R-CH = CH-(CH2), -S03Na, hydroxy sulfonate R-CHOH-(CH2),-SO3Na, and disulfonate R-CH(SO3Na)-(CH2),-SO3Na (less than 1 wt%), with n = 1 to 3. Specific synthesis of octadecene sulfonate was performed to provide a standard molecule for the analysis and to performed to provide a standard molecule for the analysis and to characterize its behavior with regard to AOS stability. The main characteristics of the surfactants used are given in Table 1. All the other chemicals mentioned in this paper (alcohols, dodecane, and inorganic salts) were of reagent grade. Twice-distilled water was used. A Charentes kaolinite was used for adsorption ex-periments. The surface area, determined by the BET method, wafound to be 26.8 m2/g [909 in.2/lbm]. Analytic Procedures. Sulfonates were titrated by turbidimet with Hyamine 1662 TM as a chemical reagent. Water and hydrocarbon (dodecane) concentrations were occasionally determined by gas chromatography with thermal conductivity and flame ionization detectors, respectively. The iodine index was measured according to Intl. Standards Organization Standard No. 3961 for determining alkene group concentration. Methods. Sulfonate solubility was studied by preparing series of mixtures having various compositions. After the mixtures were mixed and allowed to settle for a minimum of 1 week at regulated temperature, the boundaries between single and multiphase systems were constructed by visual examination. Critical micelle concentrations (CMC's) were determined by conductivity. Before infrared spectroscopy analysis, the samples of sulfonate were dehydrated by lyophilization. Phase behavior studies were performed in tightly closed, graduated test tubes. The mixtures, consisting of brine, alcohol, AOS, and hydrocarbon, were equilibrated by being shaken several times daily and then resting at least 1 week in an oven. Interfacial properties were determined mostly from solubilization parameter properties were determined mostly from solubilization parameter measurements. The solubilization parameter, 0, is the amount of water or hydrocarbon solubilized in the surfactant-rich phase per unit amount of surfactant assumed to be in that phase. By definition, conditions (salinity for instance) are said to be optimals when the amounts of water and hydrocarbon in the surfactant phase are equal. IFT's, y, were measured by the spinning-drop method.
- Geology > Mineral > Silicate > Phyllosilicate (0.76)
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- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.95)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.86)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.76)
Rock Dissolution and Consumption Phenomena in an Alkaline Phenomena in an Alkaline Recovery System Summary. Consumption of alkali in the reservoir (loss of pH value) is a major concern to engineers designing alkaline slugs for EOR. Although several attempts have been made to model and to quantify these effects, the complexity of silicate chemistry has been a major stumbling block in adequately and realistically describing the mechanisms. The data and mechanisms presented in this paper indicate that recently proposed consumption models should be modified to incorporate lower limits proposed consumption models should be modified to incorporate lower limits on SiO2 solubility at high pH values. A simple pseudo-first-order kinetics model is presented that provides an easy method to estimate the decrease in pH value and buildup of silica vs. time for any reasonable reservoir pH value and buildup of silica vs. time for any reasonable reservoir conditions where alkaline chemicals are used. When these limits are properly applied, the past long-term trends in laboratory data can be properly applied, the past long-term trends in laboratory data can be better explained. The implications of these changes in the dissolution rate model for improved slug design are discussed. Introduction Quartz-sand-dissolving studies in caustic solutions where autoclaves are used to make sodium silicates I have shown that there is a thermodynamic limit to the amount of quartz that can be dissolved. This limit or apparent equilibrium varies from approximately a 2.0 to a 2.5 molar ratio of SiO2 to Na2O in solution at 140C [284F], and under several atmospheres of pressure, depending on the starting alkali level. Recent dissolution tests with impure Berea sandstone at about 90C [194F] show that this limit is closer to a 1.75 to 2.0 ratio, irrespective of the starting alkali concentration or SiO2/Na2O ratio. These facts imply that one should expect reduced apparent consumption rates for alkaline slugs containing sodium ortho- and metasilicates. Because there is an equilibrium between SiO2 and Na2O in solution, there is a limit to the decrease in pH value (which is a function of solids content and ratio) and increase in SiO2 that can occur because of rock dissolution. In effect, this dissolution effect is not consumption at all but really a buffering effect provided by the silicate ions. The proposed model allows a better estimation of long-term consumption (buffering) effects caused by silica dissolution in the presence of reservoir brine. Other fast reactions, such as ion exchange, presence of reservoir brine. Other fast reactions, such as ion exchange, precipitation of hardness, and reaction with the crude oil acids, will precipitation of hardness, and reaction with the crude oil acids, will continue to result in falling pH levels but at slower overall rates. Therefore, the probability that an alkaline slug will effectively propagate through the reservoir is increased and slug design certainty propagate through the reservoir is increased and slug design certainty can be improved. In design of an alkaline slug, the most critical and least understood parameter is probably the consumption of the alkali by the oil, the brine constituents, and predominantly the rock. Rock reaction and consumption decreases the pH value of the alkaline slug to the point where it may no longer be able to saponify the acids in the oil. This occurs at a pH value of about 10 for most crudes as noted by Chan and Yen and Chan et al. Several authors have tried to quantify these effects and to explain these mechanisms. Bunge and Radke studied the migration of alkaline pulses and developed an empirical first-order rate model to explain pulse movement through reservoirs using the Damkohler number. Sydansk studied the interaction of caustic at elevated temperatures with certain sandstones and found that a considerable amount of silicate is generated in situ. Lieus studied the long-term consumption of caustic and sodium orthosilicate solutions and found that consumption is reduced when silicates are used. Work in our laboratories has shown that the higher-ratio sodium silicates, as well as other less alkaline chemicals, can impart certain benefits in dilute-surfactant low-tension waterfloods. These benefits include additional reduction in interfacial tension (IFT), reduced hardness levels, decreased surfactant retention by the core, increased sweep by selective permeability reduction, increased water-wetness, and improved oil recovery. These dilute-surfactant low-tension systems are analogous to simple alkaline systems where a dilute surfactant is generated in situ. Also, it was shown that in batch consumption tests, a steady-state ratio of from 1.6 to 2.0 SiO2/Na2O was reached after 1 month at elevated temperatures. These results were the starting point for this work, which has led to a reformulation of the concepts concerning rock dissolution. The results suggest that high-ratio silicates can be and should be used as alkaline slug candidates, especially at extreme reservoir temperatures, to promote slug propagation. The Quantitative Model for SiO2 Dissolution Bunge and Radke consider the SiO2 dissolution irreversible because of the high solubility of SiO2 estimated from literature data 10 and the increased SiO2 Solubility at higher temperatures. As they indicate, the dissolution of SiO2 is a very complex process that is not mathematically describable without making simplifying assumptions. Let us look at the historic development of information currently available concerning SiO2 dissolution. O'Connor and Greenberg 11 showed that, for surface area equal to A, the rate of vitreous silica dissolution, dC/dt, waswhere the rate of silica dissolution is zero order with rate constant k, and the subsequent deposition is first order in dissolved SiO2 with rate constant k2. At equilibrium, dC/dt=0, thus and Thus, assuming that an equilibrium state exists, this treatment Suggests a pseudo-first-order reaction for the dissolution of silica. SPERE P. 62
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