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Results
Summary An accurate finite-element simulator with a very fine 2D grid was used inthis study of viscous instabilities. The simulator has negligiblegrid-orientation and numerical-dispersion effects and treats longitudinal andtransverse dispersivities separately. The simulator was validated by comparingnumerical results with the analytical solution for unit-mobility-ratio miscibledisplacements under varying longitudinal and transverse dispersivities and wasfurther tested by simulating the results of published laboratory displacementsunder adverse-mobility-ratio conditions. A good match was obtained between thesimulated and experimental results for recovery and effluent-concentration profiles for adverse-mobility-ratio displacements. A permeability variance of only 0. 1 or an inlet concentration perturbation for a homogeneous system wasenough to initiate the effects of viscous fingers seen in laboratorydisplacements. Results showed that the parameters that control unstable displacements arethe permeability variance (Dykstra-Parsons coefficient), the size of heterogeneity (scale length), the mobility ratio, and the dimensionlesstransverse Peclet number, Npet. It was concluded that the instabilitiesincrease with increases in the permeability variance, the scale length, and themobility ratio. With increased instability, the recovery decreases and thebreakthrough time decreases. For Npet, less than 0.01) the displacement remainsunstable. In addition, the effect of longitudinal dispersivity is negligible. As long as the parameters (mobility ratio, permeability variance, and size of heterogeneities, Npet, less than 0.01) permeability variance, and size of heterogeneities, Npet, less than 0.01) were the same, the effect of the size of the modeled medium on recovery and effluent profiles was insignificant. Thisimplies that the effects of viscous instabilities can be scaled within therange of parameters investigated. Introduction Oil displacement by miscible flooding processes, including CO2 flooding, isaffected by instability at the flood front caused by an adverse mobility ratio. An unfavorable-mobility-ratio displacement coupled with the heterogeneity of the porous medium results in viscous instability (fingering), which in turnaffects the displacement efficiency of multiple-contact-miscible processes, sweep efficiency, breakthrough time, and slug-size design. Our previous investigations showed that the effect of small-scaleheterogeneity of the porous media on the displacement front can be representedby an effective dispersivity. The investigation, however, was restricted tounit-mobility-ratio displacements. The purpose of this investigation is toextend the previous analysis to purpose of this investigation is to extend theprevious analysis to adverse-mobility-ratio (greater than unity)displacements. Extensive literature is available on the phenomenon of viscous fingering. The literature can be divided into three categories: analytical, experimental, and numerical. Analytical work involves the mathematical description of theinception and modeling of fingers and the method to scale fingers to fieldconditions. Experimental work involves laboratory core experiments underadverse-mobility-ratio conditions. The numerical work relates to differentsimulation techniques that are used to predict and simulate the physicalbehavior of the viscous fingers. Most of the previous numerical work concentrated on matching theexperimental laboratory data for adverse-mobility-ratio displacements. Some of it matched the data of Blackwell et al. in sandpacks; others matched their ownexperimental data. The numerical techniques used varied from finite-differencesimulations to the method of weighted residuals to random walk models. Most of these investigators were reasonably successful in matching experimentallaboratory data, indicating that the physical phenomenon of fingering can bemimicked by simulators if appropriate precautions are taken. Chief among theseare the use of a large number of gridblocks, minimization of grid-orientationeffects, and proper initiation of viscous fingers. In addition to matching experimental data, some investigators conductedsensitivity studies to investigate the effect of various parameters on viscousfingering. Detailed simulations by Giordano et al. and Moissis et al. indicatethat mobility ratio and scale length of heterogeneity significantly affect thecharacteristics of viscous fingers. An increase in either of these twoparameters accentuates the instability of the viscous fingers. parametersaccentuates the instability of the viscous fingers. Although numericalinvestigations in the last few years have remarkably improved the physicalunderstanding of viscous fingering, some questions still remain unanswered. First, can the effects of laboratory-observed viscous fingering on displacementperformance be modeled? Second, how is a viscous instability affected byvarious parameters including mobility ratio, permeability variance, size of heterogeneities, and rock dispersivity values? permeability variance, size of heterogeneities, and rock dispersivity values? And third, can the viscousfingering be scaled? This paper addresses these questions. To address these questions, several assumptions were made: the displacementwas contact miscible, the gravity effects were negligible (densities of displacing and displaced phases were identical), and the permeabilitydistribution for small-scale heterogeneities was log-normal. In addition, asshown in Fig. 1, a linear (strictly rectilinear) displacement was conducted inwhich 2D flow effects were captured. Amoco's finite-element simulator, modified to include both longitudinal andtransverse rock dispersivities, was used for this investigation. Approach A three-step approach was taken in this study. First, the finite-elementmodel was modified and validated with analytical solutions and the literatureexperimental results. Second, with the same model, mechanistic aspects of viscous instabilities were investigated. Third, the effect of differentvariables on recovery and effluent profiles was analyzed to provide insightinto scaling of viscous fingers. The effects of various parameters on viscous instabilities wereinvestigated. These parameters (Table 1) include longitudinal dispersivity(rock dispersivity), ratio of transverse to longitudinal dispersivity, permeability variance (Dykstra-Parsons coefficient), scale length (size of heterogeneity), mobility ratio, spatial permeability distribution, and size of the modeled medium. The longitudinal values were chosen on the basis of theavailable literature evidence. The mobility-ratio values chosen represent atypical range of mobility ratios observed for miscible-displacementprocesses. To define the permeability heterogeneity, it is necessary to characterizetwo parameters-permeability variance and scale length. The permeabilityvariance characterizes the extent of heterogeneity, whereas permeabilityvariance characterizes the extent of heterogeneity, whereas the scale lengthcharacterizes the size of heterogeneity. In this study, the permeabilitydistribution was assumed to be log-normal.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary This paper shows that inclusion of a physical dispersion formulation in a fully compositional simulator improves the ability to model and interpret the displacement characteristics of horizontal gas-drive corefloods conducted in 2-in.-diameter, 2- to 32-ft-long, horizontal Berea cores at secondary and tertiary conditions. Foremost among these improvements are (1) quantifying the effects of mixing, characterized by the Peclet number (L). on breakthrough time and displacement efficiency; (2) simulating the effect of core length on miscibility development observed experimentally for multiple-contact-miscible (MCM) displacements with vaporizing/extraction mass transfer, including immiscible behavior in short cores (large mixing) and miscible behavior in long cores (small mixing); and (3) eliminating the need to adjust the number of gridblocks to match coreflood performance. Introduction CO2 miscible flooding is being conducted on a commercial scale in numerous petroleum reservoirs. To reduce the risk associated with the design of field-scale projects, knowledge of reservoir properties and the ability to make accurate predictions of reservoir performance are needed. Laboratory displacements (conducted at reservoir conditions) and numerical simulations are viable approaches to develop knowledge of the physics required for accurate predictions. Displacement behavior of gas-drive processes in 2-in.-diameter laboratory cores is greatly influenced by mass transfer and mixing of the fluids within the porous medium. For example, Yellig observed that during CO2 displacements of a west Texas oil from homogeneous Berea cores. a minimum core length is required to attain miscibility. Immiscible displacement behavior. characterized by low oil recovery, early gas breakthrough, and two-phase slug production, was observed in 8-ft cores, whereas the corefloods conducted in 16-ft or longer Berea cores displayed miscible behavior (high oil recovery, late gas breakthrough, and single-phase production). The core tests were performed in horizontal Berea cores at reservoir temperature and at pressures above the slim-tube minimum miscibility pressure (MMP). The viscosity ratio between the oil and CO2 was highly adverse (about 31). Two distinct mixing modes have been recognized during miscible displacement tests. In core tests conducted with equal-density fluids with a favorable viscosity ratio between the in-place and displacing fluids, the mixing process is controlled mainly by the physical dispersion or dispersivity of the porous medium (characterized by the flow channels or tortuosity). This results in a typical S-shaped effluent profile with the mixing-zone length growing with the square root of the distance traveled. In the second type, core tests conducted with an unfavorable viscosity ratio and/or with different-density fluids, mixing proceeds at a rate governed by physical dispersion and such flow instabilities as viscous fingering and gravity tonguing. Previous authors attempted to simulate mixing in the ID mode by varying the number of gridblocks - in effect, using numerical dispersion to mimic physical dispersion. They concluded that the effect of core length on miscibility development cannot be modeled with numerical dispersion. Furthermore, the use of numerical dispersion to mimic physical dispersion presents other severe limitations, particularly for multidimensional flow where numerical dispersion cannot be related one-to-one to physical dispersion. Simulation results frequently depend not only on grid size but also on grid orientation. This prompted development of a reservoir simulation approach that greatly reduced numerical dispersion while replacing it with physical dispersion. While this approach could simulate multiphase flow, it lacked generality in that it could not handle gravity or capillary pressure effects or phase discontinuities. Because phase discontinuities are typically encountered in enhanced gas-drive processes, this limitation was fairly severe.
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- North America > United States > Wyoming > Nugget Formation (0.97)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract This paper presents a novel method of characterizing the broad equivalent-weight (BEW) sulfonates composed of two pseudosulfonate fractions that behave as the oil-moving and the sulfonate-solubilizing components. The terms quasi-monosulfonate and quasi-disulfonate are used to characterize these oil-moving and solubilizing components, respectively. Such a description of BEW sulfonates allows determination of sulfonate concentration in the flowing phases as well as the quantity adsorbed on the porous medium, and permits modeling of the sulfonate retention and transport behavior. Furthermore, the paper shows that the performance of a BEW sulfonate system in which a lower-phase microemulsion environment is predominant can be predicted by using independently measured input data, which include interfacial tension (IFT), fluid viscosity, and sulfonate retention isotherm. Introduction The BEW sulfonates commonly have a broad range of equivalent weights and a significant percentage of di- and polysulfonated components, and exhibit unique properties and phase behavior compared with the relatively narrow-equivalent-weight or pure sulfonates. They usually are fractionated during the oil displacement process. This paper introduces a method to calibrate the fractionated sulfonates by using two pseudosulfonate fractions obtained from a polarity partitioning technique. This technique, in conjunction with the high-performance liquid chromatography (HPLC) analysis, allows an artificial separation of BEW sulfonates into two major fractions, which simulate the oil-moving and the solubilizing components of sulfonate. The terms quasi-monosulfonate and quasi-disulfonate are used to characterize these oil-moving and sulfonate-solubilizing components, respectively. This calibration method was used successfully to determine sulfonate concentrations in the oil and aqueous phase effluents as well as the sulfonate retained on the rock surfaces. This has been valuable for interpreting the sulfonate retention and transport behavior. The retention measurements of quasi-monosulfonate were found to depend on micellar slug size, core length, and contact time. These results suggest that the effect of contact time may become significant in laboratory short-core tests with a small slug and should be an important consideration when interpreting the data. This paper also discusses the sulfonate propagation and displacement behavior of micellar systems with a BEW sulfonate in which the lower-phase microemulsion environment is predominant. It is shown that such a system can give effective oil displacement through the generation of low IFT, favorable phase behavior, and good mobility control. Furthermore, the performance of such a lower-phase system can be simulated easily by using independently measured input data, which include IFT, fluid viscosity, and sulfonate retention isotherm. This simulation provides a means to estimate sulfonate retention and also to optimize sulfonate use in micellar flooding. Micellar Fluid Systems and Experimental Details The primary surfactant used in all the formulations is a BEW vacuum gas oil (VGO) sulfonate. Table 1 lists the major components of the bulk sulfonate. The equivalent-weight distributions of VGO sulfonate components in this study range between 300 and 700. The cosurfactant was either isopropyl alcohol or an ethoxylated hexanol. A micellar formulation containing a VGO sulfonate and isopropyl alcohol is given in Table 2. The oil was a 4-cp [4-MPa's] field crude, and the in-place brine consisted of 0.25 N NaCl solution. Xanflood biopolymer was used as the mobility control agent. All tests were conducted at 110 degrees F [43.3 degrees C]. Oil displacement tests for the sulfonate propagation and retention studies were conducted in 2- and 6-ft [0.61- and 1.83-m] Berea cores at 2.3-ft/D [0.70-m/D] frontal advance rate. Sulfonate retention measurements in the absence of crude oil were conducted in 8-in. [20-cm] Berea cores. Details of these tests are given in Tables 3 through 5. Analyses of the core effluent components were accomplished by using HPLC, gas chromatography, and gel permeation chromatography. The fluid viscosity was measured by using a Brookfield viscometer with a UL adaptor. The IFT's were measured by using a spinning-drop interfacial tensiometer. SPEJ P. 435^
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- North America > United States > Wyoming > Powder River Basin > Salt Creek Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Borregos Field (0.99)
- North America > United States > Nebraska > Sloss Field (0.99)
- 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 > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The performance of the micellar/polymer flood conducted in the Sloss reservoir did not follow predictions by a streamtube model. The model assumed that micellar flood displaces oil and water in a piston-type miscible manner with a final oil saturation of 5 % PV, and sulfonate retention based on short-term laboratory adsorption tests. This paper, in conjunction with a complementary paper, describes process mechanisms needed to model the flood performance. The results of laboratory studies show higher sulfonate retention caused by ion-exchange effects, which result in partitioning of sulfonate into the oil phase and higher adsorption caused by long contact times. Long-term aging of the Sloss micellar fluid at the high reservoir temperature (93.3°C [200°F]) does not reduce oil recovery. The results of laboratory studies also show that the final oil saturation after micellar flooding is capillary-number dependent. A higher final oil saturation can be the result of reduced injectivity /productivity, increased interfacial tension (1FT), and/or decreased viscosity. This paper demonstrates that ion exchange, hardness, and sulfonate partitioning can significantly affect micellar-flood performance. The paper presents an experimental plan that provides information for optimizing the design of micellar/polymer floods. This plan, when applied to a specific flood, allows an investigator to examine effects of adsorption, ion exchange, hardness, and partitioning on flood performance. Specifically, phase studies and sulfonate requirements must encompass effects of in-situ-generated calcium ions as a result of sodium/calcium ion exchange. Sulfonate itself can increase the calcium content of the fluids because of a calcium/micelle association. High calcium concentrations can increase sulfonate requirements. Sulfonate adsorption requirements for micellar flood design are sensitive to the experimental procedures employed. The paper outlines improved procedures encompassing ion exchange and time effects and demonstrates that a favorable ion-exchange process can be used to reduce adsorption requirements. Introduction Interpretation of micellar-flooding pilots is essential to the development of a predictive model for commercial demonstration and fieldwide micellar floods. To interpret field micellar-flood performance, process variables (e.g., compositional effects) must be separated from field variables (e.g., reservoir description and operational difficulties), and the process mechanisms must be identified. This paper describes experimental procedures for use by industry to identify effects of composition changes during micellar flooding. The paper describes application of these procedures to determine the effects of composition changes on the displacement mechanisms of the micellar/polymer fluids injected in the Sloss field, Kimball County, NE. The results enhanced our mechanistic understanding of the micellar-flooding process. This understanding is required for interpretation of pilot performance. This paper discusses the first portion of the mechanism studies for the micellar/polymer system used in the Sloss reservoir. Results of the second portion of the mechanism research were published in 1982. A separate paper discussed results of the Sloss pilot posttest evaluation well. Pilot Performance The streamtube model with classical miscible-immiscible displacements was used to obtain preflood predictions. This model assumed sulfonate retention (by adsorption) of 3.42 kg active Mahogany AA sulfonate/m contacted PV [1.20 lbm/bbl PV], a final oil saturation of 5 % PV in the micellar swept zone, and mobility control. The preflood predictions and pilot performance were in excellent agreement during the early stages of the project. However, the observed performance later deviated from the preflood predicted performance. Postflood predictions by the same model more closely matched total pilot performance by assuming an increased sulfonate retention and a higher final oil saturation. Process Mechanism Studies Detailed laboratory studies were initiated to enhance our mechanistic understanding of the process. These studies needed for interpretation of the pilot performance included:phase behavior, compositional effects on oil displacement, propagation of the oil and micellar banks, ion-exchange behavior, sulfonate retention, time effects on sulfonate adsorption, and effect of micellar fluid aging on oil recovery.
Gupta, Surendra P., SPE, Amoco Production Co. Abstract This paper presents results of laboratory experiments and computer simulation studies of the micellar/polymer fluids injected in the Sloss field, NE. The paper shows that the dispersion coefficient for the partitioned sulfonate in the oil phase can be an order of magnitude larger than the dispersion coefficient in the water phase. The results show that the two principal components of the micellar fluid (sulfonate and polymer) propagate at different rates because of partitioning and dispersive mixing effects. Sulfonate is produced much earlier than polymer and is concentrated in the produced oil. Sulfonate partitions into the oil phase as a consequence of ion exchange, and the polymer remains in the water phase. The oil phase that contains the partitioned sulfonate i.e., upper-phase microemulsion-has high mobility. The increased dispersion coefficient for a component in the nonwetting phase, in this case the partitioned sulfonate into the oil phase, is supported by an independent study. These mechanisms contribute to early sulfonate breakthrough and a larger sulfonate requirement per barrel of oil displaced than anticipated for a nondispersive displacement. The results of this paper can be beneficial for design of other micellar fluids and performance predictions and interpretation of micellar floods in other fields. Introduction A micellar/polymer pilot was conducted in the Sloss field, Kimball County, NE. Interpretation of the performance of micellar pilots aids in the development of a prediction model. To meet this objective, process variables (e.g., compositional effects) must be separated from field variables (e.g., reservoir description and operating variables), and the process mechanism must be identified. Concurrent with the pilot, research continued on the process mechanism of the micellar/polymer fluids injected in the field test. This paper presents an example of partitioning and dispersive mixing effects in micellar flooding. The paper demonstrates that detailed core effluent analyses in conjunction with numerical simulation studies can reveal displacement mechanisms within the two mixing zones. These zones are between an oil/water bank and a micellar slug and between the micellar slug and a polymer bank. Results of previous studies of the first portion of the mechanism research have been published. Before discussing the results of this paper, the following provides a brief summary of the previous studies. A separate paper discusses results of a Sloss pilot post-test evaluation well. Previous Studies The fluids designed (see Appendix A for details) for the Sloss pilot involved a salinity contrast (or gradient) concept. The salinity of the preconditioning and the makeup brines for the micellar fluid was 12,000 ppm NaCl added to the available Sloss fresh water. The low-salinity fresh water was used for the polymer water. The following summarizes pertinent results of the previous studies. The results showed that the designed micellar fluid forms a middle-phase microemulsion when a volume of the micellar fluid is mixed with an equal volume of crude oil. A middle-phase microemulsion is in equilibrium with excess oil and water phases. A lower-phase microemulsion is generated when the salinity is less than 10,000 ppm NaCl. A lower-phase microemulsion is in equilibrium with an excess oil phase. The final oil saturation after micellar flooding (Sof), in small slug tests, increases as micellar fluid salinity decreases from the designed value. Furthermore, Sof is dependent on the capillary number (viscosity × velocity interfacial tension). SPEJ P. 481^
Abstract This paper deals with the oil/water bank propagation in a tertiary oil recovery process. Oil/water bank propagation was studied in a series of laboratory micellar floods and simultaneous oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation. It was observed that a high oil saturation region, or hump, developed at the leading edge of the oil/water bank and grew linearly with distance. A lower steady-state oil saturation region was observed behind the hump. As the hump was produced from the core, high initial oil fractions were observed, as often seen in laboratory micellar floods. This is the result of the observed hysteresis in fractional flow behavior. A graphical method of predicting the occurrence of a hump, its rate of growth, and saturations within an oil/water bank was developed using the observed hysteresis in fractional flow. Using this prediction procedure, it was concluded that in a tertiary oil recovery process, oil breakthrough time or rate of advance of the oil/water bank, oil saturation at the leading edge, and initial produced oil fractions are only functions of the oil-saturation-increasing fractional flow curve and are not necessarily indications of oil recovery efficiency. Introduction During a tertiary oil recovery process, a small slug of displacing fluid (e.g., a micellar fluid) mobilizes residual oil and water and forms an oil/water bank. It is important to understand the propagation behavior of the oil/water bank in a tertiary oil recovery process since it affects the oil breakthrough time and initial oil cuts. This understanding also will aid in the interpretation of oil displacement tests. Moreover, oil breakthrough time and initial oil cuts have been used for judging the efficiency of a tertiary oil recovery process. Oil/water bank propagation was studied in a series of micellar floods and oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation profiles. Experimental Details The microwave scanning apparatus used is similar to that discussed by Parsons and Parsons and Jones. Microwaves are transmitted through a core where they are partially absorbed by the water molecules. The measured microwave power attenuation, or degree of absorption of the microwave energy, is a direct measure of the quantity of water and, consequently, of the oil saturation in an oil/water system since the oil does not absorb the microwave energy. The microwave scanning apparatus is capable of measuring the dynamic oil saturation profiles during pressure-monitored laboratory micellar floods and other oil/water flow tests. Fig. 1 is a schematic of the apparatus. Additional experimental details are given in Appendix A. Displacement tests were conducted at room temperature in 120-cm-long rectangular Berea cores (1.91 cm thick×7.62 cm wide). The brine permeability range of these cores was from 418 to 714 md, and pore volumes varied from 377 to 395 cm. Three tertiary micellar floods were conducted in separate Berea cores with Second Wall Creek crude oil. Table 1 shows the fluid injection sequence and compositions for the micellar floods. In addition, simultaneous oil/water injection tests were conducted in separate Berea cores using both Second Wall Creek crude oil and refined oils (see Table 2 for the fluid injection sequence).
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)