Small Slugs Research Articles

Investigation of surface hydrodynamic properties using a β-emitting radiotracer

To study the details of surface renewal of a clean and a film-covered liquid surface, a new technique using weak radiotracers has been developed. A small slug of radioactive Na 2SO 4 ( 35S) is injected below the surfaces. The β-particles have a range of 300 μm in water, so a Geiger counter positioned just above the surface records only the 35S which arrives (and departs) within this depth of surface layer. Measurements were obtained for mass transport by a slow (0.017 m s −1) water stream directed vertically on to an air-water surface from below. When a surface film was present, the appearance of tracer in the surface layer was significantly delayed compared to the transport to a clean water surface. The results show that the clean surface was influenced predominantly by surface renewal, whereas at the monolayer covered surface diffusion effects were much more significant. Capillary rippling was found to enhance transport, with this effect progressively suppressed by increasing strengths of surfactant, which also suppressed convective transport in unstirred systems.

Alvord [3000 ft Strawn] LPG Flood Design and Performance Evaluation

Summary Mitchell Energy Corp. has implemented a liquefied petroleum gas (LPG)/drive-gas miscible process in the Alvord (3000 ft Strawn) Unit in Wise County, TX, utilizing the U.S. DOE tertiary incentive program. The field has been waterflooded for 14 years and was producing near its economic limit at the time this project was started. This paper presents the results of the reservoir simulation study that was conducted to evaluate pattern configuration and operating alternatives to maximize LPG containment and oil recovery performance. Several recommendations resulting from this study were implemented for the project. On the basis of model predictions, tertiary oil recovery is expected to be between100,000 and 130,000 bbl [15 900 and 20 700 m3]or about 7% of the oil originally in place (OOIP) in the unit. An evaluation of the project performance through Dec.1981 is presented. This portion of the paper was written after drive-gas injection had just been initiated and represents only a preliminary evaluation of the project. In July 1981 the injection of a 16% hydrocarbon pore volume (HCPV) slug of propane was completed. Natural gas is being used to drive the propane slug. A peak oil response of 222 B/D [35.3 m3/d] was achieved in Aug.1981 and production has since been declining. This compares with a peak rate of 400 B/D [63.6 m3/d] during the waterflood, and an oil rate just prior to initiation of LPG injection of 7 B/D [1.1 m3/d]. The observed performance of the LPG flood indicates that the actual tertiary oil recovered will reach the predicted value, although the project life will be longer than expected. The results presented in this paper indicate that, without the DOE incentive program, the economics for this project would still be uncertain at this time. Introduction The Alvord (3000 ft) is approximately 10 miles [16 km]north of the town of Bridgeport in Wise County, TX(Fig. 1). The Alvord (3000 ft) Unit has been successfully waterflooded and was producing near its economic limit in Dec. 1979. A tertiary flood then was considered as an alternative to abandoning the field. Of the tertiary methods available, micellar flooding was eliminated from serious consideration because freshwater was not available and, according to published screening parameters, the calcium and magnesium concentrations were too high in the reservoir and supply water. CO2 was ruled out because of the question of miscibility at this depth and lack of supply. The LPG/drive-gas miscible process was chosen because miscibility could be achieved and convenient sources of LPG and natural gas were available. Economic risks were reduced because the DOE tertiary incentive program was available at that time. The LPG/drive-gas process has produced favourable results in waterflooded reservoirs in the past. The objective of this process in a waterflooded reservoir is to connect the residual oil with the injected LPG and displace it to the producing wells. The water must be displaced by the developing oil bank, the oil must be miscibly displaced by the LPG, and the LPG must be miscibly displaced by the drive gas. The mobility ratio is unfavorable at all flood fronts, and one should expect viscous fingering of the LPG into the oil bank and viscous fingering of the drive gas into the LPG bank. This is an important phenomenon and results in the rapid dissipation of small LPG slugs. When the reservoir is horizontal, the slug dissipation is faster because of stratification and gravity override. When the LPG slug is dissipated, the process reverts to an immiscible gas drive. In the early history of LPG flooding, the use of slugs that were too small probably prevented many projects from being as successful as expected. Several publications indicated that LPG slug sizes, on the order of 10 % HCPV or less, would be adequate for most reservoir situations. Later, others reported that because of viscous fingering, stratification, and gravity override, larger LPG slugs were needed. From the onset of this project it was felt that a successful project required a large LPG slug (about 20%HCPV). It was also recognized that a pattern flood configuration and operating procedure would have to be adopted that would prevent the mobilized oil and the displacing LPG solvent from migrating downdip into the aquifer. Thus a short simulation study was undertaken before embarking on the field project to evaluate alternative flood patterns and operating procedures and to estimate project recovery performance. General Field Description The field is in the central portion of the Fort Worth basin. It produces from an upper Pennsylvanian Strawn series sandstone, the Bryson sand, which was deposited by fluvial processes. A porous sand isopach of the Bryson sand is presented in Fig. 2. JPT P. 119^

CHANNEL CHANGES IN ARID BADLANDS, BORREGO SPRINGS, CALIFORNIA

Geometric, hydraulic, and sediment characteristics in arid badlands near Borrego Springs, California, are examined in relation to precipitation events of varying magnitude and frequency. The longitudinal and cross profiles of five ephemeral channels occupying a 2.5 km2 catchment were surveyed under pre-and post-storm conditions during the February 1976-December 1978 period. Such arid region channels offer the opportunity to observe and explain rates and methods of profile change under different flow types in a short period of time. Catchment responses to light winter events include substantial lags between initial precipitation and channel runoff, the limited downstream movement of small slugs of sediment, high losses of discharge into channel alluvium, and prolonged mass movement of debris from adjacent hillslopes into the channels following the storm events thus promoting aggradation along certain channel reaches. Responses to intense summer storms include explosive channel and hillslope runoff and loca...

Single-Well Tracer Tests for Evaluating Chemical Enhanced Oil Recovery Processes

Summary A method is presented for testing enhanced oil recovery (EOR) processes in a single well. The method uses a multitracer version of the single-well tracer test (SWTT) for determining residual oil saturation to measure the oil displaced by an EOR slug process. A test was conducted to demonstrate the validity of the method. This test and its results are described. Introduction Piloting an EOR process is both time-consuming and expensive. Conventional pilot tests can take 3 years or more to conduct and cost several million dollars. A single-well test for evaluating tertiary slug processes has been developed that is both faster and less expensive than conventional piloting by at least one order of magnitude. The basis for this method of evaluating tertiary slug processes is the SWTT for measuring residual oil saturation developed by Exxon Production Research Co. The large depth of investigation from the wellbore of the SWTT and the ability to control this investigation depth are unique properties that make the single-well test for evaluating EOR slug processes possible. This single-well test consists of the following steps.Conduct an SWTT to determine the residual oil saturation after waterflooding.Inject a small slug containing an oil recovery chemical to establish an oil saturation profile within the SWTT pore volume (PV) of investigation.Inject a mobility control bank if needed.Inject a brine bank to displace the mobile banked oil from the test area, and recover the inaccessible PV caused by the mobility control bank if one was used.Conduct another SWTT with several different esters, each having different partition coefficients, so that average oil saturations can be measured for different distances from the wellbore. Steps 1 and 5 can be analyzed to determine oil saturation curves as a function of contacted PV and percent oil recovery vs. chemical slug size. These data are very useful in scale-up to larger projects and are not directly available from multiwell pilot tests. Another application of this testing method could be to conduct several tests with different chemical formulations in a given area. This would aid in selecting the best system for a particular field. Conoco Inc. has conducted a 1-acre (4047-m2) pilot test of a surfactant process at the Big Muddy field in Wyoming. Success of that pilot led to expansion of the surfactant process to 90 acres (364 km 2). In April 1979, Conoco ran a single-well surfactant test in conjunction with the surfactant expansion project. This single-well test was conducted to measure residual oil saturation after waterflooding and to determine the potential for evaluating tertiary slug processes by use of the single-well method. The same surfactant formulation used in the pilot test was used in the single-well test to provide a basis for checking the single-well test. This paper discusses theory, design, operation, results, and interpretation of the single-well surfactant test conducted in the Big Muddy field. Theoretical Development The theoretical basis and the general technique for measuring residual oil saturation by the single-well tracer method are well documented in the literature. Briefly, the method relies on determination of the chromatographic retardation factor of a tracer, which partitions between the oil and water phases in the reservoir. In practice, this determination is made by injecting a slug of primary tracer, such as an organic ester (having solubility in both water and oil), followed by a relatively large volume of water. A shut-in period then follows, during which the ester partially hydrolyzes to form an alcohol (having essentially no solubility in oil); this is the secondary tracer. JPT P. 1887^

Factors Affecting Miscible Flooding Dispersion Coefficients

Abstract Miscible solvent slug size, and therefore cost, is dependent on the mixing or dispersion taking place in the reservoir. Fluid mixing can also be important in the interpretation of laboratory simulations of miscible floods. An experimental program was conducted to study the effects of velocity, viscosity ratio, rock type and core length on dispersion (mixing) coefficients measured in short cores, with the objective of scaling laboratory measurements to field systems. Statistical analysis of the results of the tests, matched with the capacitance-dispersion ("dead-end core volume") model, shows that an effective dispersion coefficient derived from the model is the most consistent measure of mixing in the systems studied. Viscosity ratios differing by ±4%from unity had no significant effect on the effective dispersion coefficient. The effect of system length on the effective dispersion coefficient Is shown. Because of the length dependence, dispersion coefficients measured in short laboratory systems may underestimate the true dispersion taking place in the reservoir. The length dependence of the dispersion coefficient may also have important implications in the interpretation of laboratory results where mixing is a factor. INTRODUCTION Economical enhanced oil recovery requires injection of a relatively small slug of solvent or oil mobilization fluid, e.g., CO2 rich gas or micellar fluid. A chase fluid (N2 flue gas or polymer water), which is miscible with the solvent, is generally used to maximize solvent utilization. A physical phenomenon referred to as dispersive mixing acts to reduce the effectiveness of the solvent. Dispersive mixing also decreases the effectiveness of chase fluid in displacing the solvent. Therefore, the effect of dispersive mixing on the process must be included in numerical models for the design of enhanced oil recovery projects. Various mathematical models have been propsoed to simulate the dispersive mixing which occurs in oil reservoirs(1). These models include the simple dispersion model and the capacitance-dispersion model. The dispersive mixing simulated by these models is characterized by adjustable parameters. The parameters must be determined or estimated for a porous medium in order to simulate the dispersive mixing which will take place between miscible fluids flowing through it. In previous work on dispersive mixing(2), a technique was developed to determine the dispersion coefficient for a consolidated core. This technique consists of conducting displacements in the core of interest with equal-viscosity-contact miscible fluids and matching the effluent concentration data with a dispersive mixing model. This work concluded that for many systems the simple dispersion model was not adequate. The capacitance-dispersion model was shown(2) to better simulate the dispersive mixing in these systems. This model includes additional parameters which allow it to fit more irregular effluent concentration profiles with greater accuracy. The work described in this paper is a continuation of the miscible-displacement, dispersion-coefficient study. The prinicpal objectives of this work were to:determine the physical significance of the parameters of the capacitance-dispersion model;determine the validity of using an "effective dispersion coefficient" defined by this model to simulate dispersive mixing; andshow that as system length increases the dispersive mixing for heterogeneous systems can be simulated by a simple dispersion model with an "effective dispersion coefficient."

A Laboratory Study of the Effects of CO2 Injection Sequence on Tertiary Oil Recovery

Abstract The major reason that CO2 stands out as a fluid displacement agent for enhanced oil recovery is because of the adaptability and relatively low cost of CO2 compared with other chemical flooding agents. CO2 miscible displacement could be achieved for a wide spectrum of reservoir oils through an extraction/vaporization process. Even under immiscible reservoir conditions, incremental oil recovery still can be obtained by simple viscosity reduction and swelling of crude oil. Among other desirable properties of CO2 is its high density. At typical reservoir conditions, CO2 is nearly as heavy as reservoir oil; thus, the problem of overriding common to most gas injecting systems could be minimized greatly. In spite of all the advantages of CO2 process, it inherits the disadvantage of high mobility ratio so that the CO2 has a great tendency to channel through the oil, bypassing much of the oil in the reservoir. To alleviate the difficulties, a technique consisting of alternately injecting small CO2 and water slugs has been applied in field tests.1 The injected water interferes with the flow of CO2 to minimize the chance of premature CO2 breakthrough. Another technique, called "programmed slug," has long been applied in polymer flooding to prevent deleterious effects of viscous fingering. More recently, Claridge2 has developed a method for designing graded banks for both polymer and miscible flooding. His study indicates that the use of a graded slug often results in improvement of oil recovery and/or economic attractiveness.

A Sensitivity Study of Micellar/Polymer Flooding

Abstract The compositional simulator of Pope and Nelson has been extended to include a number of additional effects. The efficiency of the oil displacement has been calculated as a function of slug size, polymer drive size, surfactant and oil concentrations in the slug, slug/oil bank and drive/slug mobility ratios, surfactant and polymer absorption, interfacial tension (IFT), phase type, binodal curves, plait point location, capillary desaturation curves for each point location, capillary desaturation curves for each phase, relative permeabilities, waterflood residuals, phase, relative permeabilities, waterflood residuals, dispersion, electrolyte gradient, and amount of surfactant injected. High-concentration slugs in a Type II (+) (or plait point left) phase environment were found to be less dependent on low IFT than low-concentration slugs or slugs in a type II (-) phase environment. For the Type II (-) case, oil phase environment. For the Type II (-) case, oil recovery is not sensitive to plait point location. However, the best oil recovery for a given amount of injected surfactant occurs where a salinity higher than optimal exists downstream of the slug and a salinity lower than optimal exists upstream of the slug (in the polymer drive) and the slug itself traverses as much of the reservoir as possible in the low-tension Type III environment. The low final salinity promotes low final retention of surfactant. For the cases studied, the salinity, surfactant concentration, oil concentration, and polymer concentration of the slug itself then made relatively little difference. Introduction Several authors have examined one-dimensional simulation of surfactant flooding and the various complex compositional effects that occur during the displacement of oil with surfactants and polymers. Nelson and Pope presented laboratory results showing the importance of the Type III phase environment and how oil recovery can result from mechanisms other than low IFT. Actually, several key phenomena affecting oil recovery are strongly coupled and need to be considered simultaneously both to understand and to simulate the process. The simulator of Pope and Nelson was a first attempt to model these effects, which include IFT, phase behavior, fractional flow, adsorption, and polymer properties as a function of electrolyte. Ion exchange properties as a function of electrolyte. Ion exchange has been shown to have an important impact on the process as well, since the electrolyte environment process as well, since the electrolyte environment affects many of the most important fluid properties involved. Pope and Nelson have shown how the displacement of oil is "miscible-like" under certain conditions, even when dispersion and adsorption are considered and small slugs are used. However, to be practical, a very carefully designed electrolyte practical, a very carefully designed electrolyte gradient must exist (or some other equivalent gradient of another variable such as surfactant molecular weight, alcohol, etc.). Here we continue the investigation of these process variables by presenting results of a sensitivity study. Both presenting results of a sensitivity study. Both water and oil-rich surfactant slug cases are simulated. Model Changes Pope and Nelson presented a description of the Pope and Nelson presented a description of the original simulator. Several changes that have been made will be discussed briefly. The IFT functions are now those proposed by Healy and Reed. ....... (1) ....... (2) SPEJ P. 357

Role of Injection-production Strategy In the Solvent-steamflooding of the Athabasca Oil Sands

Abstract A comprehensive study was carried out of the in-situ recovery of bitumen from a three-dimensional model, packed with Athabasca Oil Sand, with injection in the centre, near the base and production from the our corner wells, over the entire interval. Five injection-production schemes were tested in a recovery process involving the use of a solvent (Suncor's synthetic crude) with steam. Solvent slug sizes varied from 5to 30% pore volume, with varying amounts of steam injected. Recoveries varied from 5 to 50% of the bitumen in place depending on the slug size, rate of solvent injection and steam volume. It was found that both large and small solvent slugs are less effective than an "optimal" slug size. Of the injection strategies tested, solvent injection into the production wells was found to be most effective, with steam injection into the injection well. Splitting of the solvent slug among the injection and production wells was the next best choice. Base runs involving steam injection alone facilitated interpretation of results, and showed that on the whole solvent-steam injection is a far more promising technique. Among the variables studied rate of solvent injection appears to be a significant factor in determining bitumen recovery. Implications of the results obtained are considered from the standpoint of field application. Introduction In-situ recovery from the Athabasca Oil Sands poses special problems, in view of the virtually immobile nature of the inplace bitumen. Implementation of a suitable recovery method, usually thermal, requires creation of flow paths for the initial injection of a hot fluid. The present research on the subject, now in its tenth year, proposes the use of a solvent for this purpose which is followed by steam injection. Among other non-thermal schemes for creating initial communication between wells, the most notable are those proposed by Redford(l) and formation fracturing using emulsions or air, as employed by Shell Canada (1961) and Amoco Canada, respectively, in the Athabasca Oil Sands region. Thermal methods include cyclic steam stimulation with air or gas, electrical heating of the formation and combustion under fracture pressures. This paper outlines the principal results of the experimental research conducted during the last four years on the use of solvents and steam for in-situ recovery from the Athabasca Oil Sands, encompassing three separate studies (2,3,4) by the co-authors. The data reported here should be of value in judging the applicability of the processes considered, even though the largely unscaled experiments would preclude direct application of the data to field situations. For complete details of individual experiments, the aforementioned works may be referred to. Background and Objectives Previous work on the use of solvents and steam has been reviewed in Reference (5). It led us to believe that Suncor's synthetic crude holds considerable potential for the Athabasca Oil Sands, as an additive to steam injection, in a carefully planned operating strategy. Apart from the desirable properties of this "solvent" vis-a-vis the Athabasca bitumen, it is readily available and cheaper than any other solvent or comparable refinery stream.

Interfacial Tension Required for Significant Displacement of Residual Oil

Abstract A static analysis of displacement in a single irregular pore partially filled with oil is used to investigate the effects of interfacial tension and wettability on the tertiary recovery of residual oil by a low interfacial tension waterflood. There are several results. For the most efficient displacement of residual oil, either the porous structure should be water-wet or intermediate-wet. There is a critical value for the interfacial tension above which the residual oil cannot be displaced, but instead will assume a static configuration. Although the computation describes the static configuration of an oil globule in a pore, it suggests the underlying mechanism for the episodic motion or jump of a globule as it is displaces. The discussion of displacement in a single pore is extended by an estimate for the value of the capillary number, required for recovery of residual oil from those pores whose neck radii are larger than the mean pore neck radius. A comparison is offered with data taken from the literature. Introduction Petroleum is found in the microscopic pores of sedimentary rocks such as sandstones and limestones. Not all pores will be filled with petroleum. Some pores contain water or brine that petroleum. Some pores contain water or brine that is saturated with the minerals in the local rock structure. In the primary stage of production, oil and brine are driven into a well from the surrounding rock by the relatively large difference between the initial field pressure and the pressure in the well. Perhaps 10 to 20% of the oil originally in place is recovered in this manner. In the secondary stage of production, water or steam is pumped into a selected pattern of wells in a field, forcing a portion of the oil into other production wells. The void volume in a permeable production wells. The void volume in a permeable rock may be thought of as many intersecting pores of varying diameters. Consider two parallel pore spaces of unequal permeabilities. A blob of oil (residual oil) will be trapped in that pore space, through which the oil is displaced by the water more slowly. In this manner, 10 to 40% of the oil initially in place will be recovered, but 40 to 80% of the oil originally in place is left behind in the field. Several tertiary recovery techniques have been proposed. We focus our attention here on the proposed. We focus our attention here on the recovery of residual oil by a low interfacial tension waterflood. One can distinguish between at least two different types of such waterfloods. One type uses a small volume (3 to 20% PV) of a relatively concentrated surfactant solution. The concentration of the surfactant solution is high enough to ensure that it is miscible with the crude oil in all proportions. As a small slug of this surfactant solution moves through the porous structure mixing with and displacing the crude oil, surfactant is lost by adsorption on the rock. The solution is diluted further with the connate water present in the structure. As the concentration of present in the structure. As the concentration of surfactant falls, the water/crude oil/surfactant mixture can move from a single-phase region to a multiphase region on its phase diagram. We should expect that a miscible displacement conducted with a small slug of surfactant solution will revert to an immiscible displacement at some point in the reservoir. In the type of waterflood with which we are concerned here, a large volume (15 to 60% PV or more) of a dilute surfactant solution is used. The crude oil is nearly insoluble in the surfactant solution, and we speak of an immiscible displacement. It has been estimated that in carefully selected, well-designed, well-performing operations, an additional 30% of the oil originally in place might be recovered by a low interfacial tension waterflood. The crude oil/water interfacial tension can be reduced by orders of magnitude when either a mixture of surfactants or an alkaline solution is added to the waterflood. SPEJ P. 83

Development and Application of Variational Methods for Simulation of Miscible Displacement in Porous Media

Abstract Many reservoir engineering problems involve solving fluid flow equations whose solutions are characterized by sharp fronts and low dispersion levels. This is particularly important in tracking small slugs that are characteristic of chemical floods, polymer floods, first- and multiple-contact hydrocarbon miscible polymer floods, first- and multiple-contact hydrocarbon miscible displacements, and most thermal processes. The use of finite-difference approximations to solve these problems when low dispersion levels and small slugs need to be modeled accurately may be prohibitively expensive. This paper shows that the use of high-order variational approximations is a very effective means for economically solving these problems. This paper presents some numerical results that demonstrate that high-order variational methods can be used to solve two-dimensional reservoir engineering problems where finite-difference approximations would require 104 problems where finite-difference approximations would require 104 to 105 blocks. The variational solutions are shown to be essentially insensitive to grid orientation for unfavorable mobility ratios up to M = 100. Introduction The equations describing miscible displacement in a porous medium (convection-diffusion equations) are among the more difficult to solve by numerical means. The character of the concentration equation ranges from parabolic to almost hyperbolic depending on the ratio of convection to diffusion (Peclet number). Consequently, the finite-difference techniques developed for solving the convection diffusion problem can be divided into two categories: those solving the problem as parabolic and those treating the problem as hyperbolic. The parabolic techniques are unsatisfactory when the diffusion becomes small compared with the convection. The methods using central difference approximations for the convection terms oscillate. Price et al. have shown that these oscillations can be eliminated only by using small spatial increments. Methods using upstream difference approximations do not oscillate, but they introduce large truncation errors that have the character of a large diffusion term. Lantz has shown that for many practical problems, reducing the magnitude of numerical dispersion problems, reducing the magnitude of numerical dispersion sufficiently so that it does not mask the physical dispersion will force an impractically fine grid. Several improvements have been suggested, such as transfer of overshoots truncation-error cancellation, and two-point upstream approximations; but none of these is quite satisfactory in the general case. The hyperbolic methods (method of characteristics, point tracking, etc.) also pose many practical problems. These include the complex treatment required for sources and sinks, the need to redistribute points continually when modeling converging and diverging flow, the problem of maintaining a material balance, problems created by complex geometries, and the practical limitation problems created by complex geometries, and the practical limitation of the time-step size. Moreover, these schemes cannot be shown to converge, thereby making the choice of grid size and point distribution fairly arbitrary. Finally, many nonlinearities, such as reactions and adsorption, need to be treated point-by-point, requiring large amounts of computer time and storage. Because the major difficulty in solving the miscible displacement problem is the determination of an accurate approximation to a very sharp concentration front, one of the most promising alternatives to the schemes mentioned above is the use of promising alternatives to the schemes mentioned above is the use of high-order variational approximations, such as those proposed by Ciarlet et al. These methods (which include Galerkin and finite-element methods) are potentially far more accurate for a given amount of computation than the standard finite-difference techniques and, therefore, more able to solve problems that would otherwise be impractical. SPEJ P. 228

Status of CO2 and Hydrocarbon Miscible Oil Recovery Methods

In this state-of-the-art review, the basic procedures for applying CO2 and hydrocarbon miscible oil recovery, processes are explained. Some principal field tests and commercial applications of the processes are presented with a current assessment of the miscible flooding techniques. Introduction From studies of displacing oil from reservoir rock by water or gas, we have teamed that a portion of the oil is left as residual when immiscible conditions are present because interfaces are formed by capillary and viscous forges. Eliminating the interfaces allows complete displacement of the oil. Early in the search for ways to completely displace oil from rock, the idea of washing porous media with several volumes of solvent was porous media with several volumes of solvent was technically feasible but, because of the amount of solvent required, it was economically unattractive. The potential for achieving attractive economics was first reported potential for achieving attractive economics was first reported by Whorton and Kieschnich; they found that natural gas at sufficiently high pressures would miscibly displace crude oil. Actually, a miscible solvent was extracted by the injected gas from the crude being displaced. Miscible displacement has been described as the displacement of crude oil from pore space in a rock using a solvent action that prevents formation of interfaces between the driven and the driving fluids. Koch and Slobod and Hall and Geffen showed that a slug of solvent could be driven through a porous medium by a less valuable driving agent; this technique permits small quantities of the expensive solvent to be used to remove large quantities of oil. In the laboratory, ratios of about 10 bbl of oil per barrel of solvent were achieved. Since this discovery, both laboratory and field tests have shown why this flooding technique may not be economical; maintaining the integrity of the slug in irregular porous rock and under otherwise hostile reservoir porous rock and under otherwise hostile reservoir conditions has been the main problem. Both longitudinal and transverse mixing occurs to disperse the small slug. Gravity segregation of fluids, unfavorable viscosity effects, and sand permeability variations tend to disperse it and to prevent it from contacting a large portion of the reservoir sand. Also, dead-end pores and water-shielded pore spaces trap part of the solvent, thereby deteriorating the slug. All these work to dilute the miscible slug and reduce its displacement efficiency. This paper reviews (1) various miscible recovery methods that have been proposed, (2) problems associated with applying each method, (3) improvements developed to overcome the problems, (4) past and current field applications, and (5) current appraisal of miscible recovery. The Basic Process and Variations The basic miscible displacement processes described here use such displacing fluids as LPG (propane) - gas; enriched (condensing) gas; high-pressure (vaporizing) gas; carbon dioxide; and mutual solvents. LPG-Gas The LPG, or propane slug, process illustrates the miscible oil recovery technique. The process consists of injecting a small slug of LPG or propane as a liquid and driving it through the reservoir with less expensive natural gas (Fig. 1). JPT P. 76

Application of finite element methods to solving immiscible displacement problems with sharp fronts (abstract)

Many reservoir engineering problems involve solving fluid flow equations, whose solutions are characterized by sharp fronts and low dispersion levels. This is particularly important in tracking small slugs which are characteristic of chemical floods, polymer floods, first and multiple contact hydrocarbon miscible displacements and most thermal processes. The use of finite difference approximations to solve these problems when low dispersion levels and small slugs need to be accurately modeled is prohibitively expensive. In two dimensions, as many as 500 grid blocks on a side would be required in order to obtain the necessary accuracy. However, the use of high order finite element schemes are shown to be a very effective means of economically solving this problem. This paper presents some numerical results of a research project recently completed which has demonstrated that high order finite element methods can be used to solve difficult reservoir engineering problems where finite difference approximations would be prohibitively expensive.

Micellar Flooding - Fluid Propagation, Interaction, and Mobility

Abstract Laboratory core tests show that small polymer-driven micellar slugs displace tertiary oil, polymer-driven micellar slugs displace tertiary oil, efficiently. Surfactant adsorption studies reveal nonclassical behavior. Polymer requirements are decreased by permeability-reducing micellar/clay interaction and by reduced losses behind a micellar slug. The required volume of polymer slug increases when the pore volume that is inaccessible to the polymer increases. Long-core tests with multiple polymer increases. Long-core tests with multiple pressure taps reveal the existence of a high-mobility pressure taps reveal the existence of a high-mobility oil-water bank and a low-mobility oil-micellar mixing zone. Introduction Micellar fluids that use petroleum sulfonate surfactants have been tested by several organizations as potential candidates for secondary and tertiary oil recovery operations. Typically, a micellar flood consists of a brine preflush to condition the formation, a bank of micellar fluid (5 to 40 percent PV) that displaces the oil, a mobility buffer (polymer) bank to drive the micellar slug, and a chase-water bank. Micellar flooding is attractive as an improved oil recovery process because it is not severely affected by gravity segregation and is not limited by ultimate surfactant availability. DEVELOPMENT OF MICELLAR FLUIDS The micellar fluids that have been developed by our laboratory for miscible waterflooding are microemulsions of high water content (85 to 95 percent by weight). These fluids generally are percent by weight). These fluids generally are prepared with 4 to 10 weight percent oil-soluble prepared with 4 to 10 weight percent oil-soluble hydrocarbon sulfonate (with an equivalent weight, EW, from 350 to 475) and an oil- or water-soluble alcohol cosurfactant. The cosurfactant performs several functions. In many cases it aids the water solubility of the sulfonate. Gale and Sandvik reported that systems that do not use cosurfactants require sulfonates with a broad EW range. The low-EW sulfonates provide water solubility for the high-EW material. Since the systems discussed here use a cosurfactant to perform this function, the EW range of the sulfonates we used is much narrower. An additional benefit of the cosurfactant is that sulfonate adsorption by the rock surface is reduced. SCREENING PROCEDURE Before core testing, crude oils that are potential candidates for micellar flooding are screened qualitatively against a number of micellar compositions of varying surfactant/cosurfactant ratio, monovalent ion concentration, and water content. Divalent ion tolerance and temperature are also examined. Preliminary qualitative screening tests are used to visually examine the degree of miscibility between the crude oil and the micellar solution. If a micellar fluid shows potential for oil displacement and is economically attractive, a core testing program is initiated. Typically, tertiary floods are conducted at reservoir conditions in fresh 2-in.-diameter, 4-ft-long Berea sandstone cores mounted in Hassler holders. A small volume of micellar fluid (from 2.5 to 10 percent PV) is injected at a linear advance rate of percent PV) is injected at a linear advance rate of about 2 ft/D and is followed by a bank of low-salinity, polymer-thickened water. If the tertiary recovery is encouraging, the micellar fluid is evaluated in detail. This evaluation involves extensive adsorption studies to optimize the fluid composition and long-core tests to examine the propagation and interaction of the fluid banks. propagation and interaction of the fluid banks. MICELLAR FLUID DEVELOPMENT FOR A PARTICULAR RESERVOIR The Second Wall Creek reservoir of the Salt Creek field north of Casper, Wyo., has been selected as one of the potential candidates for micellar flooding. The reservoir has a temperature of 110 degrees F, a crude oil viscosity of 4.0 cp, and an average permeability of 50 md. Analyses of the Second Wall Creek formation water and the Madison Field water (to be used as the micellar and polymer bank makeup water) are shown in Table 1. Both waters produce stable one-phase micellar fluids since the produce stable one-phase micellar fluids since the total dissolved solids and divalent ion contents are low. SPEJ P. 633

Microdissection of developmental stages of the cellular slime mold, Dictyostelium discoideum, using a ruby laser

The ruby microlaser was used to damage restricted regions of the migrating slug and fruiting stages. No absorption of the laser beam occurred unless the cells were colored. Neutral red in the growth medium added the necessary color. A 50-μm diameter beam pulsed against the anterior end or midsection of a 1 mm-long slug often produced breakup of the entire slug into several smaller slugs. It was hypothesized that the cells of the anterior end initiate signals to the rear, which maintain their leadership over the posterior cells. The anterior cells of the fruiting stages were most sensitive to the laser and the result was often permanent desistance of stalk development. In early fruits, laser irradiation could prevent completion of both stalk development and spore formation. Laser irradiation of the fruit's exposed stalk resulted in loss of stalk cell turgor pressure, and collapse of the pressure supported cellulose walls and stalk sheath.

Penetration in granite by jets from shaped-charge liners of six materials

A new application of theory for three-dimensional collapse of conical liners shows why the two-dimensional analysis may offer a good approximation. Shaped-charge design parameters and rock target properties were investigated to determine their effects on penetration and breakage. Several metals, liner thicknesses, cone angles and standoff ranges for each were investigated. Effective standoff is greater for aluminum than more dense metals. Jets from the 60° monel, brass and steel liners gave the deepest penetration in granite. Jets from copper and brass liners gave equal penetration for 42° apex angles. Liners containing zinc produced small slugs or none at all. The holes in the granite were uniform and approximated right circular cones. Jet penetration velocities into granite varied from a maximum of 10,000 m/sec to a minimum of 2000 m/sec for the most effective metal jet.

Comments on Finding the Most Profitable Slug Size

In the Forum, "Finding the Most Profitable, Slug Size" (Aug, 1972 JPT, Pages 993-994), S. C. Jones found that the most profitable slug size for the micellar solutions he investigated was about 3 percent PV for a homogeneous porous system. He concludes that "even smaller slugs should be used with increasingly stratified reservoirs, quite the opposite conclusion from a classical paper on the subject." The explanation Jones gives for using reduced slug sizes in heterogeneous sands is that the oil in the tighter zones costs more to recover than it is worth. On the surface, this explanation seems reasonable. However, these tight zones may contain the major portion of the oil we seek to recover. In any event, I think the conclusion applies only to a limited number of reservoirs. Let me explain why. To begin with, Jones' conclusion that the optimum slug size becomes smaller as the degree of stratification increases is not supported by experimental data. The oil recovery curves presented by Jones for various stratified sands were calculated on the basis of the curve for the homogeneous sand. These calculated curves apply to watered-out, stratified systems in which no communication between zones exists and in which all zones are at or near residual oil saturation. Consequently, they do not include the effects of crossflow or transverse dispersion that occurs between zones of different permeabilities in many porous systems. porous systems. On Fig. 1,* I have plotted Jones' calculated curves for comparison with experimental results (Curve A) that we have obtained from soluble-oil floods conducted in a two-layer, noncommunicating stratified system at high (65 percent PV) oil saturation. The greater slope of the experimental curve indicates that the optimum slug size would not decrease as stratification increases but may remain at about the 3-percent-PV level. P. 77

Oil Saturation Measurements in the Bartlesville Sand After Waterflooding And After Propane Flooding

In this post-waterflood test, oil saturations determined from logs agreed well with those from production tests using laboratory-measured relative permeability data. Information was obtained on oil saturations before and permeability data. Information was obtained on oil saturations before and after propane flooding, on the distribution of propane in the sand, and on the flow of oil mobilized by the propane during the flood. Introduction The Delaware District Unit, located in Nowata County, Okla., and covering about 2,500 acres, was discovered in 1910. The reservoir rock and oil characteristics are summarized on Table 1. The production from the Bartlesville sand was by both primary and secondary methods. The secondary methods included pumping under vacuum, air and gas injection, and waterflooding. Since the waterflood was approaching its economic limit (Fig. 1) and since a material balance indicated that the oil saturation remaining in the reservoir was about 43 percent PV, it was decided to conduct a pilot test to determine whether additional oil could be economically recovered from the watered-out area in this reservoir. Because of the shallow depth and low pressure of the reservoir, a miscible flood could not be achieved. A laboratory investigation of the immiscible propane slug displacement mechanism, indicated that injection of a 4-percent PV slug of propane, followed by air and then water, could recover substantial amounts of oil from watered-out areas. It was also found in laboratory work that a more effective technique was reverse flooding; i.e., propane is injected, then air and water are injected into the existing production wells and the existing injection wells are converted to producers. Laboratory studies showed that, with small slugs of propane, higher and more efficient oil recovery was obtained when the propane was injected into an area where mobile oil saturation was present. A field test of this reverse flow. propane flood was conducted and is described briefly in Appendix A. To determine more accurately what had occurred in the reservoir during the flood, three wells were drilled into the Bartlesville sand on a line between an injection and a production well. Oil saturations were determined at these well locations from the following sources of information: 1. Conventional core analyses. 2. Special logging procedures. 3. Production history of these core wells and therelative permeability data obtained on the cores. The oil saturation values determined from the above sources of data were compared with those measured in cores taken when the injection and production wells were originally drilled. The values production wells were originally drilled. The values were also compared with calculations of oil saturation based upon the Buckley-Leverett fractional flow formula using production data from these wells. The results of the oil saturation measurements are presented in this paper. presented in this paper. Procedure Procedure Wells Drilled in Pilot Area Three wells (W. L. Connelly Nos. 1, 2. and 3) were drilled in the propane test area during 1962 and 1963, as shown in Fig. 2. The wells were cored and logged, and Nos. 1 and 3 were completed as producers. JPT P. 1411

Oil Recovery by Hydrocarbon Slugs Driven by a Hot Water Bank

Abstract An experimented study was conducted of the recovery of oil from as porous medium overlain and underlain by heat-conducting formations and containing a residual oil or connate water saturation by injection of a small slug of a light hydrocarbon followed by 1/2 PV of hot water driven by a conventional waterflood. The fluid production histories and the temperature distribution obtained showed that a light hydrocarbon sag injected ahead of a hot water slug leads to a considerable increase in oil recovery. The net oil recovery was found to depend on the original oil viscosity, hydrocarbon slug viscosity, and the injection rate. The process was more effective in a previously waterflooded core rather than in one containing connate water. The over-all ratio of the total hydrocarbon produced to the hydrocarbon injected ranged from 1.10 to 3.96, the variation corresponding to the viscosity of the hydrocarbon slug employed. Introduction Numerous methods have been proposed for recovering oil from previously waterflooded porous media. Some methods involve the application of heat in one form or another, while others utilize miscible displacement processes. The proposed method involves a combination of the two, employing a small hydrocarbon slug followed by a slug of hot water, which is driven by a conventional waterflood. An attempt was made to investigate the conditions (residual oil saturation, viscosity, etc.) under which such a method would yield a sizable oil recovery. Use of a solvent dug followed by a heat-carrying agent was earlier considered by Pirela and Farouq Ali. The process was designed to take advantage of the improved ternary-phase equilibrium behavior at elevated temperatures in the alcohol slug process. The experimental runs were conducted under isothermal conditions. In another study, Avendano found that injection of a light crude oil into a core containing a highly viscous oil prior to steam injection led to a large improvement in oil recovery. A number of investigators have studied the effect of water-driven hydrocarbon slugs on oil recovery from waterflooded porous media. Csaszar and Holm employed slugs of propane in waterflood cores containing oils with viscosities ranging from 3 to 9 cp. The volume of the oil recovered was 2 to 3 times the propane injected, the efficiency of the process depending on the amount of mobile oil process depending on the amount of mobile oil near the point of injection and the viscosity of the in-place oil. Wiesenthal used gasoline as an intermediate slug when waterflooding cores containing oils having viscosities of 1.28 to 324 cp. He found that the process was effective in waterflooded porous media, especially in the case of viscous oils. Fitzgerald conducted similar experiments using gasoline and arrived at more or less the same conclusions. The process under consideration involves a combination of miscible displacement and hot waterflooding, both of which have been amply discussed in the literature. A comprehensive survey of miscible displacement has been presented by Perkins and Johnston, while a description of hot Perkins and Johnston, while a description of hot waterflooding may be found elsewhere. In the following, only the most important features of the two processes operating in the combination process will be considered.

Use of Soluble Oils for Oil Recovery

A method involving the use of soluble oils can substantially reduce the oil saturation in a reservoir below, that obtainable by waterflooding. The soluble oil, which consists essentially of hydrocarbon, surfactant, and a stabilizing agent, will spontaneously emulsify with water. Small soluble-oil slugs driven with thickened water can displace all or most of the oil in linear porous systems. Introduction In recent years, many new oil recovery processes have been developed in an effort to improve waterflooding or to substitute for it. These processes include placement of oil with LPG or enriched gas alcohol placement of oil with LPG or enriched gas alcohol flooding, surfactant injection, polymer solution flooding, and CO flooding. The miscible displacement methods and surfactant flooding processes were found to be capable of reducing the capillary retention forces that limit oil displacement by waterflooding. However, miscible displacement involving either LPG and gas or alcohol and water has not been profitable in most applications because of the unfavorable mobility ratio that exists between displaced and displacing phases and the large amount of solvent required. The addition of surface-active agents to the injection water has not been a profitable oil recovery method because of the high loss of the surfactant by adsorption on the pore surface of reservoir rock. A means to combine the beneficial effects of oil miscible solvents and surface-active agents was first suggested in U. S. Patent 3,082,822 (Ref. 1); in this teaching, surface-active agents in solution with oil-soluble solvents were introduced ahead of flood water to enhance oil recovery. Later, Csaszar, described a new oil recovery process consisting of the combination of oil-soluble solvents, surface-active agents, and amphipathic solvents as a water-driven, soluble-oil flooding process. Since 1968 there have been published several studies of oil recovery by displacement with micellar solutions of hydrocarbons, surfactants, and water. These flooding materials have begun to look economically promising for secondary and tertiary oil recovery if they are driven by thickened water so that favorable mobility ratios are maintained during the flood. The following terminology is provided to orient the reader and show the relationships among the various flooding agents associated with this type of oil-recovery process. A micellar solution is a dispersion of surfactant in a solvent (oleic or aqueous), in which the surfactant molecules or ions are arranged in oriented aggregates. Many micellar solutions can spontaneously take up (solubilize) large amounts of water or oil to form either water-in-oil or oil-in-water microemulsions, respectively. In such cases, the internal phase is solubilized into the centers of the surfactant aggregates. A microemulsion is a thermodynamically stable emulsion of oil and water in which the particle size of the emulsified or internal phase is less than about 0.1 microns. In the absence of color bodies, these emulsions are transparent. Microemulsions can be of the water-in-oil or of the oil-in-water type. Soluble oils are oleic compositions that spontaneously take up (solubilize) water when mixed with it; they are specific and limited micellar solutions - that is, they will spontaneously solubilize water (not oil). JPT P. 1475

Development and Evaluation of Micellar Solutions To Improve Water Injectivity

By removing residual oil and organic skins from the vicinity of a well, water injection rates can be increased. The micellar compositions described here are highly effective for this purpose and are applicable under widely divergent field mixing and reservoir conditions. Introduction To achieve favorable oil productivity during a waterflood project, water injection rates must be maintained at a high level. Acidizing and fracturing are established techniques for increasing water injectivity. These treatments should be avoided, however, where a created fracture or channel might result in the bypassing of oil. Injectivity may be increased in some wells by removing organic deposits and residual oil from around the wellbore. Potentially y effective treatments are solvent-alcohol injection and micellar solution injection. The micellar compositions found most effective in improving injectivity are of the type described in the earlier work of Jones. These solutions, when used with special injection techniques, have been found to be effective under diverse reservoir conditions. We shall emphasize here the laboratory and developmental aspects, including both micellar composition studies and core displacement tests. Other literature discusses the use of micellar solutions in producing wells and in injection wells. Laboratory Evaluation The micellar solutions are composed of a hydrocarbon solvent (usually kerosene), a sulfonate surfactant, a cosurfactant (usually an alcohol or a modified alcohol), and water, which normally contains added amounts of an electrolyte such as sodium chloride. The micellar solutions normally are transparent and single phase. Laboratory tests show that a small slug of a micellar solution driven by water can displace all of the oil from a rock matrix. The micellar solution performs as a true solvent, similar in mechanism to that proposed by Morse. The surfactant and cosurfactant act as coupling agents to create a single-phase solution from two otherwise immiscible fluids. This mechanism may be compared to adding a mutually soluble alcohol or other solvent to a mixture of water and oil to create a single-phase, homogeneous solution. The type and amount of ingredients must be carefully selected to formulate a stable micellar solution. The surface chemistry explaining the various physical phenomena exhibited by micellar solutions physical phenomena exhibited by micellar solutions is highly complex so we shall not discuss it here. Requirements for a Versatile Composition In order that one composition may be effectively applied in many different reservoirs, the micellar fluid should exhibit the following properties. The micellar slug driven by water should be able to miscibly displace crude oils from various types of reservoir rock. It is desirable that the micellar solution be able to dissolve organic deposits, such as paraffins and asphaltenes, and to disperse solids or emulsions. The micellar solution should remain as a single-phase, homogeneous fluid over the expected range of surface and reservoir temperatures. It should be possible to prepare solutions with the various fresh waters that may be available near the treatment site. JPT P. 614