An investigation was made of the simulation of bulk and solution polymerization of styrene in a continuous stirred-tank reactor (CSTR). A theoretical model from the literature was usad to predict conversion, molecular weight distribution (MWD), and molecular weight averages. The kinetic rate constants required to solve the model were also taken from the literature.Styrene Commercial production of a new polymer is generally preceded by several stages of laboratory-scale and pilotplant production and testing to overcome problems associated with scale-up. Two objectives are to produce a product of a desired specification and to maximize its yield (or minimize its cost). The savings which could be realized by reducing pilot-plant production and testing provide a real incentive for investigating the design, simulation, and optimization of polymerization reactors.Considerable work has been done on the theoretical description of polymerization reactors (1 to 14), but little experimental work has been done to check the theoretical models (10 to 141, due, until recently, to the lack of a rapid technique for measuring molecular weight distribution. The object of this investigation was to test the validity of a theoretical model for the bulk and solution polymerization of styrene.This investigation is concerned with the simulation of a bench-scale, continuous, stirred-tank reactor (CSTR) in which monomer conversion and polymer molecular weight distribution (MWD) were used as criteria of simulation. Conversion was chosen since it is a measure of yield and MWD was chosen since many of the important physical properties of the polymer are determined by it. The solution polymerization of styrene (benzene as solvent) was chosen for study since its reaction mechanism has been relatively well established at low conversions (15) and the required rate constants are available in the literature (15to23).The mass balance equations were solved to predict conversion and MWD. Experimental olymerizations in a CSTR over a range of reaction con&ions yielded experimental conversions and MWD's which were compared with the theoretical results.The recently developed gel permeation chromatogra h distribution. This relatively rapid technique and the availability of a high-speed digital computer (IBM 7040) for solving the theoretical model have made this investigation feasible.art of a larger study, which includes development wor ! on gel permeation chromatography and polymerization studies in batch reactors (28). THEORYIn the development of the theoretical model the assumptions made were: mixing is perfect, reactor is operating at steady state, kp and kt are independent of polymer radical chain length, termination is by combination only, all radicals have the same reactivity, and no density change occurs in the reactor.The kinetic mechanism selected for the theoretical model is from Bamford et al. (15). It includes transfer to monomer and solvent.

Summary This paper discusses the extension of the steamflood process to the recovery of light oil and the state of the art of this emerging technology. A review of the various steamflood mechanisms indicates that distillation will dominate if steam is injected into light-oil reservoirs. The results of light-oil steamflood laboratory studies, computer simulations, and field projects are also reviewed. A rough screening guide for selecting a light- projects are also reviewed. A rough screening guide for selecting a light- oil steamflood candidate is discussed. New areas of advanced steamflooding technology need to be developed and field tested before light-oil steamflooding can be applied on a routine basis, as is currently the case for heavy-oil steamflooding. Introduction Steam injection is the principal EOR method used today, accounting for 75% of oil produced in the U.S. by enhanced recovery methods. Table 1 delineates the U.S. thermal EOR production from 1976 to 1980. Steamdrive- and steamsoak- (huff ‘n' puff) assisted production has steadily increased from 235,000 B/D [37,362 m3/d] in 1976 to 296,000 B/D [47,060 m3/d] in 1980. The most notable development in the growth of steam-assisted recovery is the increase of steamdrive EOR production. Oil recovered by steamflooding technology has increased from 105,000 to 155,500 B/D [16,694 to 24,723 m3/d] in 5 years, a 48% growth rate in the period 1976–80. Steamsoak production remained fairly constant during this same time period. Table 2 summarizes the number of active thermal EOR projects-- combustion, steamsoak, and steamdrive--during the last 10 years. While there may be some question as to what constitutes a "project," it is clear that the number of steam projects has grown steadily while the number of combustion projects has declined. Again, the number of steamdrive projects has increased dramatically during the last 5 years, from 31 projects in 1976 to 61 projects in 1980. This shift to steamdrive is probably attributable to two factors. One is the relatively high ultimate oil recovery of steamdrive compared with that obtainable by cyclic steam. The other is higher oil prices that have made steamdrive projects economically attractive at the relatively higher steam/oil ratios that are characteristic of steamfloods. What types of reservoirs and reservoir oils are candidates for steamdrives? Farouq Ali and Meldau presented a list of successful steamfloods. Of the 15 successful steamflood projects listed, 7 projects had in-situ reservoir oil viscosities of 1,000 cp [1 Pa s] or projects had in-situ reservoir oil viscosities of 1,000 cp [1 Pa s] or higher. All projects except one were completed at a depth of 2,600 ft [792 m] or less. Reservoir pressures were 300 psi [2.1 MPa] or less for all the projects. These properties are typical of heavy-oil reservoirs that are projects. These properties are typical of heavy-oil reservoirs that are prime candidates for thermal methods because of the effectiveness of heat prime candidates for thermal methods because of the effectiveness of heat in lowering oil viscosity. Included in the steamflood projects reported by Farouq Ali and Meldau are three projects (Brea, Coalinga, Smackover) that are or were conducted in reservoirs containing oils with viscosities of 100 cp [0.1 Pa s] or less. These projects were reported to have steam/oil ratios of 2.8 to 4.0. The Brea field (CA) steamdrive was referred to as a test to determine the feasibility of driving a relatively light (24 API [0.91-g/cm3]), low-viscosity (6-cp [0.006-Pa s]), volatile oil with steam. The definition of light and heavy oil based on crude-oil properties is somewhat arbitrary. The U.S. DOE defines heavy oil as having an API gravity of less than 20 [0.93 g/cm3]. At a recent UNITAR meeting in Caracas, the conference proposed a definition of heavy oil as: "Heavy oil has a gas-free viscosity of 100 to 10,000 centipoise inclusive at original reservoir temperature or a density of 20API to 10API inclusive at 60F at atmospheric pressure."Crude oil (other than tar sand oil) not described by this definition would be classified as medium or light crude oil. A review of the steamdrive projects summarized in an EOR survey indicates that two to four steamdrive projects during the last 10 years could be classified as light-oil or medium-oil steamfloods according to the UNITAR heavy-oil definition. These projects are listed separately from the heavy-oil steamflood projects in Table 2. In 1982, the light-oil steamfloods in progress or announced by the oil industry totaled nine projects. Can steamflood technology be extended economically to light-oil projects. Can steamflood technology be extended economically to light-oil reservoirs? What are the dominant recovery mechanisms during a light-oil steamflood? What are some of the reservoir characteristics for the limited number of successful light-oil steamfloods completed? What are some of the economic and technological barriers that need to be overcome before light-oil steamflooding is applied as routinely as heavy-oil steamflooding is today? This paper discusses the extension of the steamflood process to oil recovery from medium- and light-oil reservoirs and addresses some of these questions. JPT p. 1115

Summary Steam-foam processes to improve the efficiency of steam stimulation and steamflooding are being developed. The objectives of the laboratory study were to develop a steam-foam surfactant for field testing and to elucidate the mechanisms of steam-foam EOR. More than 50 commercial and experimental surfactants were screened for foamability; some were also screened for thermal stability at steamflood conditions. Results showed that: many sulfonate surfactants have good thermal stability; foam requires constant regeneration to be effective; foamability varies inversely with temperature and directly with gas-phase nitrogen concentration; foamability is adversely affected by brine but is relatively insensitive to foam liquid volume fraction (LVF); and effective foam can be generated at reservoir flow rates. One of our proprietary sulfonates was selected for field testing on the basis of good thermal stability, superior foaming performance, significant reduction of steamflood residual oil saturation, performance, significant reduction of steamflood residual oil saturation, and good solubility characteristics. Introduction Steam injection is currently the dominant EOR process, accounting for about 80% of 1982 EOR production in the U.S. Two types of reservoir problems can cause reduced steam use efficiency-gravity override and steam channeling. With gravity override, gravitational forces cause the low-density steam to rise to the top of the formation where it displaces oil. When steam breaks through at the producing well, a significant fraction of the initial oil in place is bypassed in the lower part of the reservoir. In the case of steam channeling, a relatively high-permeability zone causes the steam to channel through and to displace the oil from that zone, while bypassing significant oil in adjacent, lower-permeability zones. Because of the high cost of fuel to generate the injected steam, major research efforts have been directed recently toward overcoming the effects of gravity override and steam channeling. One of the more promising methods is the injection of surfactants with steam to form a resistive foam that can divert the steam into the bypassed zones. Phillips Petroleum Co. and Shell Oil Co, have patented the steam-foam and hot-water-foam recovery processes patented the steam-foam and hot-water-foam recovery processes in both uniform and stratified reservoirs. In the Phillips patents, the foaming agent or the foaming agent Phillips patents, the foaming agent or the foaming agent plus polymer is injected with steam to plug a plus polymer is injected with steam to plug a high-permeability zone temporarily. In the Shell steam-foam process, a foam-forming mixture of steam, process, a foam-forming mixture of steam, noncondensable gas, and surfactant is injected into a steam override channel to divert the steam and to accelerate channel growth. Laboratory studies at steamflood conditions have been reported by Shell, CLD Group Inc. Stanford U. Petroleum Research Inst. (SUPRI), and Sandia Natl. Petroleum Research Inst. (SUPRI), and Sandia Natl. Laboratories. Shell found that C linear alpha-olefin sulfonate was a superior foamer when combined with nitrogen and sodium-chloride brine. CLD selected Thermophoam BW-D, an alpha-olefin sulfonate, for field testing on the basis of laboratory performance and commercial availability. From extensive screening studies, SUPRI selected Suntech IV, a C alkyltoluene sulfonate, for field testing. Sandia found that the most promising surfactants for geothermal drilling foams were the alkyl and alkyl-aryl sulfonates. Steam-foam field tests have been reported by CLD Group Inc.," Shell, SUPRI, and Chemical Oil Recovery Co. (CORCO). 13 Of five field tests conducted by CLD, four were successful in improving sweep efficiency and producing significant quantities of incremental oil. Since 1976, Shell has conducted two Kern River field tests that demonstrated increased injection pressure, incremental oil production, improved sweep pressure, incremental oil production, improved sweep efficiency, and the importance of noncondensable gas. SUPRI conducted a Kern River field test in which increased injection pressure and significant incremental oil production were observed. On the basis of the reductions production were observed. On the basis of the reductions in the steam/oil ratio, CORCO claimed significant incremental oil recovery in their Kern Front field test. In summary, most of the steam-foam field tests reported to date have demonstrated incremental oil recovery. Table 1 summarizes seven of the well-documented successful field tests, including calculated values for pounds of surfactant per incremental barrel of oil. The data suggest that small, frequent slugs of surfactant plus nitrogen provide the best chance of economic success. provide the best chance of economic success. Additional laboratory and field tests are required to optimize the application of foaming surfactants to steamdrive EOR. This paper reports the results of a laboratory study of foaming surfactants as steam-diverting additives. The objectives were to develop a surfactant for field testing and to elucidate the mechanisms of steam-foam EOR. SPERE P. 44

Two successful steam-diverting field tests were conducted at the Midway-Sunset Field in the San Joaquin Valley, California. A Chevron proprietary sulfonate was used as a steam-diverting agent to improve oil recovery. The results showed that, for the conditions of the field experiment, the sulfonate used is very economic, significantly increasing oil recovery. Also, there were no associated sulfonate-handling and produced oil-treating problems.

The objectives of this investigation were to generate crude oil steam distillation data for the prediction of phase behavior in steamflood simulation and to correlate the steam distillation yields for a variety of crude oils. Thirteen steam distillation tests were run on 10 crude oils ranging in gravity from 9.4 to 37 deg. API (1.004 to 0.840 g/cm3). In each test the crude was steam distilled sequentially at about 220, 300, 400, and 500 deg. F (104, 149, 204, and 260 deg. C). The cumulative steam distillation yields at 400 deg. F (204 deg. C) ranged from about 20 to 55 vol%. Experimental results showed that crude oil steam distillation yields at steamflood conditions are significant, even for heavy oils. The effects of differences in steam volume throughput and steam temperature were taken into account when comparing yields for different crudes or repeat runs on the same crude. Steam distillation yields show a high correlation with crude oil API gravity and wax content. Introduction Steam distillation is an important steamflood oil recovery mechanism, especially in reservoirs containing light oils. Injected steam heats the formation and eventually forms a steam zone, which grows with continued steam injection. A fraction of the crude oil in the steam zone vaporizes into the steam phase according to the vapor pressures of the hydrocarbon constituents contained in the crude oil. The hydrocarbon vapor is transported through the steam zone by the flowing steam. Both the steam and hydrocarbon vapor condense at the steam front to form a hot-water zone and a hydrocarbon distillate bank. The vaporization, transport, and condensation of the hydrocarbon fractions is a dynamic process that displaces the lighter hydrocarbon fractions and generates a distillate bank that miscibly drives reservoir oil to producing wells. The effect of steam distillation on oil recovery has been investigated in several laboratory studies, steamf lood field tests, and in simulation studies. In a critical review of steam flood mechanisms, Wu discussed the steam distillation mechanism in detail. Wu and Brown reported steam distillation yields for six crude oils ranging from 9 to 36 deg. API (1.007 to 0.845 g/cm3). When plotted against their steam distillation correlation parameter, Vw/Voi (the ratio of collected steam condensate, Vw, and initial oil volume, Voi), the yields were independent of the porous medium used, steam-injection rate, and initial oil volume. For the crude oils tested, they concluded that changing the saturated steam pressure and temperature had an insignificant effect on yield, but superheating the steam from 471 to 600 deg. F (244 to 316 deg. C) significantly increased the yield. Wu and Elder reported steam distillation yields for 16 crude oils ranging from 12 to 40 deg. API (0.986 to 0.825 g/cm3). Yields ranged from 12 to 56% of initial oil volume at a distillation temperature and pressure of 380 deg. F and 200 psig (193 deg. C and 1.379 MPa). Yields at Vw/Voi = 15 were correlated with three parameters:simulated distillation temperature of the oil at 20% yield,oil viscosity, andoil API gravity. The simulated distillation obtained by gas chromatography closely approximates the true boiling-point distillation as determined by ASTM distillation. The simulated distillation temperature at 20% yield gave the closest correlation with steam distillation yield. SPEJ P. 265^