The effect of temperature on the adsorption of asulfonate surfactant and a nonionic surfactant ontocrushed Berea sandstone was studied by both staticand dynamic techniques. Static experiments were conducted over atemperature range from 25 to 95 degrees C to definetemperature-sensitive rock/surfactant systems and toestablish the shape of the equilibrium isotherm.Dynamic experiments served to reinforce the findingsof the static tests and extended the temperature rangefor sorption to 80 degrees C. This is a typicalsteamflood temperature. A mathematical model thatincorporates the mass transport, thermal degradation, and rate-dependent adsorption of the surfactantrepresented these dynamic results. The model wasused to determine the effect of temperature on the sorption rate constants. Mineral dissolution at elevated temperatures hasbeen found to cause precipitation of the sulfonate.Adsorption of the nonionic surfactant decreased withan increase in temperature at low concentrations, whereas the opposite was true at high concentrations.This has favorable implications for a low-concentration injection scheme. When performingstatic adsorption experiments, care had to be takenbecause of the poor thermal stability of the nonionic surfactant. Introduction Injection of surfactants concurrently with steam intooil-bearing reservoirs has been proposed recentlyto improve the recovery efficiency of the steam-driveprocess. From the behavior of chemical additivespreviously used in steamfloods, it is anticipated thatthe injected surfactant will travel through thatportion of the reservoir being flooded by hot water. Oil recovery can be increased if the surfactanteffectively reduces the residual oil saturation withinthis hot-water zone. For concurrent surfactant/steam injection to be technically attractive, a synergisticeffect between the surfactant and temperature isdesired. In our concept of the process, the surfactant mustmove in the heated portion of the reservoir and beable to function as an effective recovery agent atelevated temperatures for prolonged periods of time.Surfactant screening, therefore, requires thisinformation:surfactant stability under steamfloodconditions,temperature effects on the interfacial tension (IFT) between the reservoir oil and aqueoussurfactant,an evaluation of the effect oftemperature on surfactant flood performance, andthe effect of temperature on surfactant adsorption atthe water/solid interface. Handy et al. reported the thermal stabilities ofseveral classes of surfactants. Hill et al. showed thattemperature can have a dramatic effect in reducingthe IFT between crude oil and an aqueous sulfonatesystem. Handy et al. saw a similar temperatureeffect for a nonionic-surfactant/crude-oil system. Itappears, therefore, that the required synergismbetween temperature and surface activity necessaryfor concurrent surfactant/steam injection exists.Surfactant core floods are required to evaluate theeffect of temperature on oil recovery. Finally, toensure that the surfactant moves in the heatedportion of the reservoir, it is necessary to determinethe effect of temperature on adsorption. SPEJ P. 218^
Experiments were conducted to evaluate the use of surfactants for improving heavy-oil recovery from the hot-water zone in a steamflood. Criteria used to screen surfactants for this high-temperature application included thermal stability, interfacial activity, and surfactant flood performance.The thermal stabilities of several classes of sulfonate surfactants were measured. Surfactants exhibiting no thermal decomposition at elevated temperature (500°F [260°C]) were identified.The phase behavior between heavy crude oil (l4.5°API [0.969 g/cm 3 ]) and surfactant solution was determined over a temperature range from 150 to 350°F [65 to 177°C]. Regions of high interfacial activity were generated by the addition of salt to the brine phase. Interfacial tension (1FT) measurements confirmed the high salinity requirement of the selected surfactant/brine/oil system at elevated temperature.High-temperature (200 to 350°F [93 to 177°C]) surfactant floods were performed to study the effect of several variables on tertiary oil recovery. Variables studied included preflush slug size, surfactant slug size, surfactant concentration, flood temperature, core material, and mobility control. Improved oil recovery was obtained when a salinity-gradient flood design was used. For the most favorable systems, incremental oil recoveries up to 14% PV were achieved.Estimates of field performance indicate an 8 to 32 % increase in oil recovery when surfactant is used with steam.
The thermal stabilities of several sulfonate surfactants and one nonionic surfactant have been evaluated. The decomposition reactions have been observed to follow first-order kinetics. Consequently, a quantitative measure of a surfactant's stability at a given temperature is its half-life. Furthermore, the activation energy can be estimated from rate data obtained at two or more temperatures. This permits limited extrapolation of the observed decomposition rates to lower temperatures for which the rates are too low for convenient measurement. The surfactants we investigated are being considered for steamflood additives and need to be relatively stable at steam temperatures.None of the surfactants evaluated to date has the requisite stability for use in steamfloods. The most stable petroleum sulfonate we have investigated has a half-life of 11 days at 180°C (356°F). With this half-life, substantial overdosing would be required to maintain the minimum effective surfactant concentration for the life of the flood. On the other hand, the estimated half-life for this surfactant at 93°C (200°F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxypolyethanol, have shown this material to have a very short half-life at steam temperatures, but it does appear to be more stable at concentrations greater than the critical micelle concentration (CMC). In limited tests, the sulfonates showed increased stability in the presence of a 2-M salt solution.
Summary. This paper describes the use of a black-oil, thermal simulator to compare steamflood development using five-spot and inverted nine-spot patterns. The input data selected were representative of a homogeneous patterns. The input data selected were representative of a homogeneous heavy-oil reservoir. This study considered three different development strategies: conventional pattern steamflooding, pattern steamflooding with infill drilling, and steamflooding with infill drilling and pattern realignment. Comparison of pattern steamfloods indicates that at close well spacing (1.25 acres/well [0.5 ha/well]), the inverted nine-spot recovers more oil than the five-spot. Steam breakthrough and oil production are accelerated for the nine-spot relative to the production are accelerated for the nine-spot relative to the five-spot pattern. At larger well spacing, however, oil recovery from the five-spot pattern exceeds that from the nine-spot. Conversion of a five-spot pattern to an inverted nine-spot increases and accelerates oil recovery. Processing of multiple sands will improve the effectiveness of this infill drilling strategy. A development strategy using inverted nine-spot patterns on large well spacings (2.5 to 5.0 acres/well [1 to 2 ha/well]) that yields improved oil recovery compared with conventional five-spot steamflood development was identified. This strategy uses infill drilling and pattern realignment to improve steamflood performance. Introduction Steam injection is currently the most successful EOR process. Both cyclic steam injection and steamdrives are used. Because of the hither ultimate recovery that can be achieved in a drive process, however, normal field practice dictates conversion from process, however, normal field practice dictates conversion from cyclic to continuous steam injection. Because of this evolution, judicious well placement is required to provide an appropriate flood pattern for steamdrive. pattern for steamdrive. Selection of a pattern configuration for steamflooding is usually made on the basis of existing well locations, injectivity/productivity considerations, and reservoir geology. For reservoirs with high structural relief, linedrive patterns with injectors in an updip location have been used with success. A linedrive pattern has also been used successfully in a reservoir with significant water influx. For shallow-dipping reservoirs, steamflood development has usually used repeating patterns with rectangular or triangular geometries. Where wells are on rectangular spacing, which is the usual case, five-spots and nine-spots are the most common flooding patterns. Steamflood development at the Kern River field, the world's largest thermal recovery project, has used five-spot patterns. In waterflooding with rectangular patterns, the choice between using a five-spot or a nine-spot is usually made on the basis of the mobility ratio [M= (k/ )w/l(k/)o]. Selection on this basis is justified by results of laboratory studies that indicate that oil recoveries from both patterns are virtually identical. As described by Craig, the mobility ratio is a measure of a well's injectivity relative to its productivity. At unfavorable mobility ratios (M>1), in-jectivity exceeds productivity. To balance injection with withdrawal therefore, a pattern that has more producers than injectors is required. For favorable mobility ratios (M less than 1), the opposite is true, and the preferred pattern should have more injectors than producers. At unit mobility ratio, the number of producers in a pattern should equal the number of injectors. This implies that the five-spot pattern would be the preferred configuration for a unit-mobility-ratio pattern would be the preferred configuration for a unit-mobility-ratio waterflood. Selection between five-spot and nine-spot patterns for steamflooding is complicated by two major factors. First, there has been no definitive study comparing steamflood oil recovery from the two patterns. Second, even assuming a similar recovery performance. patterns. Second, even assuming a similar recovery performance. selection on the basis of injectivity/productivity considerations is uncertain because of the variation of mobility ratio during a steamflood. The successful use of nine-spot patterns in steamflooding has been recently reported. In the first case, steamflood development began with large-area patterns. This initial phase was followed by infill drilling and well conversion to realign the inverted nine-spot configuration and to reduce well spacing. Steamflood oil recovery was predicted to exceed 50% of the original oil in place (OOIP) with this development strategy. In the second case, a multizone reservoir was developed with separate nine-spot patterns for each zone. Because of the extensive use of steamflood patterns with rectangular geometry, a study to compare the relative merits of five-spot and inverted nine-spot patterns was performed. This study used a three-phase, noncompositional (black-oil) simulator to model the steam injection process. Reservoir and fluid properties representative of the Kern River field were used in the simulation work. A previous simulation study compared steamflood performance in five-spot and inverted nine-spot patterns. This study concluded that the five-spot pattern was superior to the nine-spot pattern on the basis of ultimate oil recovery. However, this evaluation did not compare pattern performance with equal well spacings (acres per well). Use of equal well spacing and injection rate (i.e., equal capital investment and operating costs) is considered essential for a valid comparison between patterns. This investigation began by evaluating the sensitivity of oil recov-ery predicted by the simulator to numerical dispersion. This was followed by a comparison of oil recovery from five-spot and inverted nine-spot patterns with equal well spacing and normalized steam injection rates. Finally, development strategies using inverted nine-spot patterns were compared with conventional steamflood development using five-spot patterns. Reservoir and Model Descriptions Reservoir and Fluid Properties. The reservoir and fluid properties used in this study were considered representative of heavy-oil properties used in this study were considered representative of heavy-oil sands within the Kern River field. These sands are characterized by their shallow depth (1,000 ft [300 m]), negligible dip (less than 5 degrees [0.09 rad]), high permeability (4,000 md), and high compressibility (3 × 10 – psi – [0.4 × 10 - kPa -]). The oil contained in these sands (60% PV) is typified by its low gravity (14 degrees API [0.97 g/cm ]), low volatility, and temperature-sensitive viscosity. Tables 1 through 4 present the basic input data used to perform the simulations. These data were selected from previous simulation studies. SPERE P. 549
Summary Methods to optimize steamflood performance of a California heavy-oil reservoir were evaluated numerically. Simulation and field results show that a reduction in steam (heat) injection rate after steam breakthrough is beneficial. A linear heat-reduction schedule resulted in the highest discounted net or salable oil production with less steam injection compared with the constant injection schedule. For unconfined patterns, steam migrates and drainsoil from outside the pattern boundaries; therefore, rate reduction may not be beneficial in such cases. For mature steamfloods, conversion to hot waterflood or injector shut-in results in somewhat higher net oil production than for continued steam injection. Recompleting the producer after steam breakthrough resulted in increased recovery. Introduction Steamflood projects usually are operated at a constant injection rate until the economic limit for steam injection is reached. Subsequently, the injection wells either are converted to hot water injection or are shut in and production is continued until project termination. It is now well-recognized that steam overrides in heavy-oil reservoirs because of its lower density, especially in thick formations and in formations with good vertical communication(permeability). Furthermore, after steam breakthrough, a significant portion of the injected steam is produced through the production wells, which reduces steam utilization. Therefore, production wells, which reduces steam utilization. Therefore, decreasing heat injection rate after steam breakthrough can improve steam utilization and project economics. Neuman first proposed ananalytical gravity-override model for steamflooding. He also derived an expression for the steam injection schedule (see the Appendix) to keep the areal extent of the steam zone constant. Vogel simplified Neuman's model and proposed that the heat injection rate should be sufficient to proposed that the heat injection rate should be sufficient to maintain the rate of verticalsteam-zone growth and to provide for heat losses. However, analytical models are essentially heat-balance models; therefore, their ability to predict oil production rate is limited. Furthermore, there currently are no production rate is limited. Furthermore, there currently are no guidelines for an optimum injection schedule. Chu and Trimble suggested that the steam injection rate should be higher at initial stages and should decrease (hyperbolically) with time. However, their reduction schedule was not related to breakthrough time, and they did not include the effect of heat losses in fuel calculations. Almost all previous steamflooding simulation studies (e.g., see Refs. 3 through 6)were conducted with confined models. In a field project, however, many patterns are (partially) unconfined. Therefore, determining the effect of unconfined patterns on predicted results would be instructive. predicted results would be instructive. Many steamfloods are terminated by converting them to hot waterflood; in others, injectors are shut in. Field results of projects where waterflood followed steamflood have been mixed. projects where waterflood followed steamflood have been mixed. Some field data have shown definite beneficial response to waterflooding, whereas others have found it to be ineffective. Interpretation of field data is difficult, especially when a mature steamflood is converted to hot waterflood while other adjacent patterns are on steamflood. In such situations, it is very patterns are on steamflood. In such situations, it is very difficult to separate the waterflood response from the adjoining steamflood. It would be valuable to evaluate quantitatively these two methods of terminating a steamflood project. Another way of using the injected steam after breakthrough could be to recomplete and shut in the top part of the producer to divert steam to the lower parts of the reservoir (to counter gravity override and to improve sweep efficiency). Note that initial gravity override of steam is desirable because it accelerates heat communication between the injector and producer, which is essential before any significant steamflood production response is observed. This paper provides guidelines to design injection schedules for steamfloods to maximize discounted net oil recovery with better use of steam generation capacity (same or higher net oil production with lower steam injection) and to determine the best method to terminate a steam injection project. The specific objectives of this study were four-fold:to determine the optimum steam injection schedule for confined patterns,to determine the effect of confined vs. unconfined patterns on the results.to evaluate waterflooding vs. injector shut-in for terminating a steamflood project, andto determine the effect of recompleting producing wells after steam breakthrough. producing wells after steam breakthrough. Simulation Model and Input Parameters Simulator. Our vectorized, general-purpose reservoir simulator, CHEARS, was used in this study. The thermal option of CHEARS is a 3D, three-phase, fully implicit, compositional simulator. The simulator accounts for and rigorously models important physical processes that occur during steamflooding. processes that occur during steamflooding. Reservoir Grid. A 3D model was used to represent the symmetric element (one-eighth) of a 100-ft-thick, 2.6-acre, repeated five-spot pattern. A 7 × 4 × 10 parallel grid system was used for the pattern. A 7 × 4 × 10 parallel grid system was used for the confined patterns(Fig. 1), resulting in a 220-cell model with 22 active gridblocks in each layer. The injector was open to the bottom four layers (40% of the reservoir thickness). The production well was open to the entire sand interval. production well was open to the entire sand interval. For the unconfined (or single) pattern, the no-now boundary did not coincide with the pattern boundary. The simulation or drainage area was larger than the pattern area; however, the injector and producer locations were unchanged, Reservoir and Fluid Properties. Table 1 summarizes the reservoir and fluid properties used in the model. The reservoir was considered homogeneous for this study, which allowed the separation of process effects from reservoir geology. The porosity and horizontal permeability were 31 % and 4,000 md, respectively. The kv/kH ratio was 0.5. The initial reservoir pressure and temperature were 35psia and 90F, respectively. The initial oil saturation was 52% and the initial water saturation was 48%. The reservoir (PV) compressibility of 50 × 10 psi is within the range of our recent measurements on unconsolidated cores. The crude gravity was 13API, and its molecular weight was 405. This heavy oil was represented by a single component and was assumed to be nonvolatile. Table 2gives the crude oil viscosity as a function of temperature. The initial steaminjection rate was 390 B/D cold-water equivalent (CWE) or 1.5 B/D-acre-ft. The steam quality at the sandface was 50%.
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