The apparent viscosity of foam flowing through smooth capillaries was measured experimentally, and a mathematical model was developed. Foam texture (a measure of bubble volume) is a key parameter in determining the following properties of foam flowing through a capillary:whether the foam exists as bulk foam or as a chain of bubbles where each pair of bubbles is separated by an individual lamella,the number of lamellae per unit length of the capillary, andthe radius of curvature of the gas-liquid interface. The apparent viscosity is the sum of three contributions:that from slugs of liquid between bubbles,the resistance to deformation of the interface of a bubble passing through a capillary, andthe surface tension gradient that results when surface active material is swept from the front of a bubble and accumulates at the back of it. The sensitivity of both measured and calculated apparent viscosity is presented as a function of bubble size, capillary radius, ratio of bubble radius to capillary radius, velocity, quality, and surface tension gradient. Introduction An early conceptual model for the relative permeability of two-phase flow was the bundle of capillary tubes model. In this model, the wetting phase flowed in the smaller capillaries and the nonwetting phase flowed in the larger capillaries. The relationship between the flow rate and pressure drop in a capillary was described by the pressure drop in a capillary was described by the Hagen-Poiseuille law. The flow of a discontinuous nonwetting phase, such as a foam, cannot be described by the Hagen-Poiseuille law. The purpose of this investigation was to determine the relationship between flow rate and pressure drop for the flow of foam through a capillary. This relationship is described by an apparent viscosity that is required to modify the Hagen-Poiseuille law for the flow of foam. Our previous observations of flow of foam lamellae in transparent porous models showed that lamellae move from pore to pore by translation. Breaking and re-forming of lamellae were rare; so was bubble coalescence. These observations suggest that the apparent viscosity of foam or lamellae in uniform, smooth capillaries is related to and, indeed, is one component of the mobility of foam in porous media. A reasonable conceptual model of a natural porous medium is a bundle of interconnected capillaries of different sizes and containing constrictions. All capillary sections, or pores, near to one another have the same capillary pressure. Thus, phase saturations may differ from pore to pore, but the radii of curvature of the gas/ liquid interfaces are equal. When flow in such an array of capillaries is modeled, resistance to flow in parallel channels of both the same and different sizes is conceived to be in parallel. Flow in smooth, uniform pore sections is in series with flow through constrictions. The component of resistance owing to smooth, uniform pore sections is approximated by resistance to flow in smooth, uniform capillaries. Measurements and theory presented here show that the most important variable affecting foam viscosity in uniform, smooth capillaries is foam texture (bubble size). Foam of finer texture has more lamellae per unit length and, as a result, greater resistance to flow. This is true both for flow of bulk foam and series of lamellae. The principal factors affecting apparent viscosity of foam in uniform capillaries are dynamic changes at gas/liquid interfaces. These are illustrated in Fig. 1.Slugs of liquid between gas bubbles resist flow.Viscous and capillary forces result in interfaces that are deformed against the restoring force of surface tension. The extent of this deformation and the resulting bubble shape partially determine apparent viscosity as a function of flow rate.Another factor determining apparent viscosity as a function of velocity is expansion of the interface at the leading end of a bubble, accompanied by compression at the trailing end. This sweeping action causes surface active material to be depleted at the front and to accumulate at the back of the bubble. The result is a surface tension gradient that resists flow. Scaling of Foam Texture and Capillary Radius Since foam texture is a measure of the average volume or equivalent radius of its bubbles, one would expect that an important scale factor is the ratio of this equivalent radius to the equivalent radius of a porous medium or the radius of a capillary. This ratio can be expressed either as the wetted perimeter per unit area of the solid or as the number of lamellae per unit length of capillary. These quantities are denoted as nL and are referred to as the number of equivalent lamellae per unit length. This concept is illustrated in Fig. 2. SPEJ P. 176

Many crude oil candidates for enhanced oil recovery by alkaline flooding produce their lowest interfacial tension at very low concentrations of alkali. Alkaline consumption by the rock makes propagation through the oil reservoir of such propagation through the oil reservoir of such dilute alkaline solutions prohibitively slow. The dilemma of having to choose between highest displacement efficiency (lowest interfacial tension) and satisfactory displacement rate can be resolved by adding cosurfactants to the alkali. Low concentrations of properly chosen cosurfactants raise the concentration of electrolyte required for minimum interfacial tension to alkali concentrations high enough for satisfactory propagation of the alkaline bank. That is, just as in chemical flooding, a cosurfactant can be used to raise the "salinity requirement" of an alkaline flood. Activity Maps, similar to the Salinity Requirement Diagrams of chemical flooding, are useful in formulating and understanding the results of cosurfactant-enhanced alkaline floods. Alkaline flooding systems, formulated by the methods discussed in this paper, recover as much oil in laboratory core floods as well-formulated chemical flooding systems. Introduction Johnson defined four mechanisms of enhanced oil recovery by alkaline flooding:"Emulsification and Entrainment" in which the crude oil is emulsified in-situ and entrained by the flowing aqueous alkali,"Wettability Reversal (Oil-Wet to Water-Wet)" in which oil production increases due to favorable changes in permeabilities accompanying the change in wettability,"Wettability Reversal (Water-Wet to Oil-Wet)" in which low residual oil saturation is attained through low interfacial tension and viscous water-in-oil emulsions working together to produce high viscous/ capillary number, and"Emulsification and Entrapment" in which sweep efficiency is improved by the action of emulsified oil droplets locking the smaller pore throats. Castor, et al proposed a fifth mechanism, "Emulsification and proposed a fifth mechanism, "Emulsification and Coalescence," in which unstable water-in-oil emulsions form spontaneously in the alkaline solution, then break to create local regions of high oil saturation, hence, increased permeability to oil. Because alkaline flooding research predated surfactant flooding research in Shell and basic concepts of salinity control and low IFT viscous/ capillary mechanisms were developed in those early alkaline studies, we have generally considered both in-situ generated surfactant flooding and preformed surfactant flooding to be special cases preformed surfactant flooding to be special cases of the same process. That is, we view alkaline flooding as a type of chemical flooding in which the surfactant is formed in-situ as the alkali converts petroleum acids in the crude oil to soaps. Our objective is to improve the cost- effectiveness of alkaline flooding by applying principles developed through recent research on principles developed through recent research on chemical flooding. As in chemical flooding, high oil-displacement efficiency depends upon attaining and maintaining conditions of "optimum salinity." When optimum salinity cannot be achieved by simple adjustments in salinity, we use cosurfactants, just as in chemical flooding. In keeping with the terminology of chemical flooding, we call the petroleum soaps formed during and alkaline flood the "primary surfactant" and any added preformed surfactant the "cosurfactant." Hence, supplementing an alkaline flood with preformed surfactants, added to the alkaline slug preformed surfactants, added to the alkaline slug before injection, becomes "cosurfactant-enhanced alkaline flooding." P. 413

A surfactant/foam process is described for the remediation of aquifers contaminated with dense nonaqueous phase liquid (DNAPL). Foam is used for mobility control to displace DNAPL from low permeability sands that are often unswept during a remediation process. Introduction An area where the technology developed for enhanced oil recovery can be applied to environmental remediation is the application of surfactant to remove nonaqueous phase liquid (NAPL) from aquifers. NAPL can be of two types, those which are less dense than water, called light nonaqueous phase liquid (LNAPL) and those which are more dense than water, called dense nonaqueous phase liquid (DNAPL). We concentrate on DNAPL because there are fewer viable alternatives to surfactant remediation. DNAPL will tend to migrate to the lowest accessible point in the aquifer and to enter lower permeability sediments if the capillary pressure becomes large enough. The challenge is to remove DNAPL from local depressions along the base of an aquifer and from low permeability layers in the presence of higher permeability layers. An approach to improve the sweep efficiency of a displacement process is to use mobility control so that the injected fluid is less mobile than the resident fluids. The common method of mobility control for surfactant flooding is through the generation of an inherently viscous microemulsion phase and through the addition of a polymer. However, Lawson and Reisberg introduced the concept of injecting gas with the surfactant solution to generate an in situ foam for mobility control. This approach has not been as popular because the mobility of foam is not as predictable as with polymers. However, much has been learned about the mobility of foam since that time and some publications on the use of foam for mobility control of surfactant flooding have appeared. Also foam has the potential of selectively reducing the mobility more in higher permeability layers in contact with lower permeability layers. Site Characterization The location for a field test of the surfactant/foam process for aquifer remediation is Hill Air Force Base near Ogden, Utah. This base has been the test site of many remediation technologies during 1996. The Operable Unit 2 (OU2) is a waste disposal site where unlined earthen trenches were used from 1967 to 1975 for the disposal of spent liquid degreasing solvents (primarily trichloroethylene). OU2 is currently being treated by "pump and treat" where the DNAPL and ground water are pumped out and the organic material removed by sedimentation and steam stripping. However, pump and treat treatment alone would have to continue for a very long time because of the low solubility of the contaminants in water and the large volume of DNAPL existing in pools and as a residual saturation. A surfactant flood without mobility control was conducted successfully by INTERA and the University of Texas at a site adjacent to where the surfactant/foam is to be tested. A steam flood test in an adjacent site is planned in the near future. Aquifer structure A structure map of the base of the unconfined aquifer is shown in Fig. 1. The aquifer consists of coarse-grained, unconsolidated sediments of recent alluvium and/or Provo Formation. It is about 50 ft thick and the water table is about 25 ft below ground level. The aquifer is underlain by more than 100 ft of the clay dominated Alpine Formation. This formation will be called the "aquitard". The structure of the aquitard and the water table helps to keep the aquifer confined in a trough or channel. Fig. 2 is a cross section along the long axis of the channel. The disposal trenches were located somewhere near the southern end of this cross-section. P. 471

Field tests suggest that a steam-foam drive is more effective when nitrogen, methane, or the like is added to the formulation. A plausible explanation is that foam lifetime is longest when transport of noncondensable gas limits mass transfer between steam bubbles. On the basis of this hypothesis, a method to estimate the amount of noncondensable gas to be included is presented.

Summary A test of cosurfactant-enhanced alkaline flooding, without polymer for mobility control, was conducted in a small reservoir in the White Castle field, Louisiana. Although the flood was unstable, the process recovered at least 38% of the waterflood residual oil in the reservoir as true tertiary oil and exhibited virtually 100% displacement efficiency. Alkali and cosurfactant propagated through the reservoir with acceptable and predictable losses. Introduction To demonstrate that cosurfactant-enhanced alkaline flooding1 is viable in recovering waterflood residual oil from sandstone reservoirs in the near-offshore Gulf of Mexico, a series of tests is being conducted in the White Castle field, Louisiana. The strategy adopted was to pilot the technology in three stages:a flood without polymer to prove features of the process unrelated to achieving mobility control,a test of process polymer injectivity in the same reservoir, anda full process demonstration in a shallower sand. The first phase of the pilot is described in this paper; pilot design, slug formulation, and operations are summarized and key responses are documented and interpreted. Ref. 2 describes the polymer injectivity test. The final pilot stage has not been initiated yet. Pilot Design and Operations Site Selection and Description. After screening of many potential sites, reservoirs in a small fault block in the Wilbert lease of the White Castle field were chosen for the cosurfactant-enhanced alkaline flooding pilot. Key properties of the White Castle reservoirs and their fluids (Table 1) are representative of Shell-owned targets for commercial processes except for the ˜45° dip in the salt dome White Castle reservoirs vs. 0 to 5° dip in the target fields. The difference in this parameter, however, was judged to be less significant because we thought its impact on process performance could be simulated adequately. Other attractive features of the White Castle field included its onshore location, stacked pays (enabling pilots in more than one reservoir with the same wells and surface facilities), proximity to chemical supplies, and infrastructure, all of which made operations less costly than in alternative locations. The reservoirs in the pilot fault block are bounded to the north and south by sealing faults and to the east (updip) by an impermeable shale sheath that drapes the salt dome (Fig. 1). The reservoirs communicate with strong aquifers through a nonsealing fault downdip. The Q sand was initially chosen for the first flood; shallower P and O 1 horizons, which were also deemed suitable, were left as either backups, if subsequent characterization work ruled out the Q sand, or objectives for follow-up pilot phases. Q-Sand Flood Objectives. The goals of the first phase of field testing of cosurfactant-enhanced alkaline flooding were (1) to validate designs of injection facilities; (2) to determine the injectivity of process slugs; (3) to establish the degree of gravity segregation during the process (vertical sweep efficiency); (4) to measure oil recovery, oil cuts, and process displacement efficiency; (5) to measure alkali consumption and surfactant retention; and (6) to gather information on treating produced fluids with conventional production facilities. Well Locations and Functions. To carry out the pilot, a pattern containing a downdip injector; two updip, gas-lifted producers; two logging observers; and a low-fate, rod-pumped sampling well was used (Fig. 1). All the wells used in the operations were drilled specifically for the pilot except the sampler; an existing penetration was recompleted to serve as that well. To obtain detailed petrophysical data on the pilot sands, pressure and rubber sleeve cores were taken when the injector and one of the producers (Well 267), respectively, were drilled. Residual oil saturation (ROS) determinations from core analyses, openhole logs, and a single-well tracer test 3 conducted through Well 267 were remarkably consistent, and the "average" value of 20% was adopted as the residual present in the Q sand. Before the alkaline pilot, Well 85 was the only well ever completed in the Q sand. Consequently, when Well 267 was added updip, it produced oil. To water out Well 267 (and thereby recover mobile oil lying even farther updip that might later compromise pilot interpretation), it was produced at ˜1,250 B/D, a rate more than five times that to be used during most of the pilot operations. During this prepilot attic drawdown, Well 267 produced 12,640 bbl of oil (the first 6,800 bbl at 100% oil cut) and 341,860 bbl of water. Wells 269 and 25, by contrast, both cut 100% water at the time they were completed in the Q sand. The logging observers, Wells 268 and 286, were cased with fiberglass so that process performance could be monitored with gamma spectroscopy, induction, and gamma ray logs. Facilities. Figs. 2 and 3 show the injection and production facilities used for the Q-sand flood. Because the methods of preparing injected fluids and handling produced fluids were unproved, these facilities were designed to provide flexibility for moving process fluids from one area of the facilities to another and with extensive capabilities for sampling and automated data collection. The injection facilities provided (1) storage for ample supplies of slug components, (2) blending and automatic monitoring (pressures, temperatures, pH, conductivities, oxygen content, flow rates, tank levels, and motor on/off condition) equipment, and (3) tanks to maintain a few days' supply of slug. An 02 scavenger (ammonium bisulfite) was added at various points to protect the facilities and well tubulars from corrosion. An on-site laboratory was equipped to perform the wet chemistry analyses needed to confirm that alkali, salt, and cosurfactant concentrations were within tolerances. Throughout the operations, injected fluid compositions were maintained within 5% of specifications, even when the facilities were operated by field personnel with no previous chemical-handling experience. A 30-day period during the drive when 0.4 rather than 1 wt% NaCl was mistakenly injected was the exception. p. 217–223