Alkyl-aryl sulfonates have been recognized as being promising for EOR by surfactant flooding. They can be manufactured in large quantities and can generate low interfacial tensions (IFTs) in oils under favorable conditions.

While pure alkyl-aryl sulfonates, such as hexadecyl benzene sulfonate, can generate adequate phase behavior and low IFT with light alkanes, they are unsatisfactory when dealing with heavier crude oils, particularly those with a high wax content. They do not follow normal phase behavior when mixed with crude oil and brines of varying salinity. At low salinity, the surfactant stays predominantly in the aqueous phase, forming a lower-phase microemulsion, whereas at high salinity the surfactant stays predominantly in the oil phase, forming an upper-phase microemulsion.

Normally, a surfactant-oil-brine system with high oil recovery potential exhibits a lower-phase to middle-phase to upper-phase microemulsion transition as the salinity increases. Near the mid-range salinity, often termed optimal salinity, a middle-phase microemulsion forms with appreciable amounts of oil and brine solubilized in the microemulsion phase. However, if the oil contains a significant fraction of wax, the above phase transition often does not occur and the solubilization capacity is low, resulting in high IFT and poor oil recovery capability (Chou and Campbell, 2001).

A series of homologous 1-phenylalkane sulfonates, i.e., 1-phenyldodecane sulfonate, 1-phenyltetradecane sulfonate, and 1-phenylhexadecane sulfonate were synthesized, and their IFT of 1-phenylalkane sulfonates was investigated against crude oil from the Daqing oil field (China).

Minima in the IFTs were observed with respect to changes of the concentrations of surfactant and with time. Alkali concentrations at which the lowest IFTs were achieved moved to low regions by increasing the chain length of the aliphatic chain in the sulfonate. The lowest concentration needed was observed with 1-phenylhexadecane sulfonate at about 0.3%.

On the other hand, no minima were observed when IFTs of the 1-phenylalkane sulfonates against alkanes themselves were measured. This behavior is quite distinct from that of the 1-phenylalkane sulfonates against crude oil (Zhang et al., 2003).

For waxy crudes, the use of a broad distribution of α-olefins greater than C₁₀ are used for the alkylation of xylene sulfonate or toluene sulfonate, in contrast to conventionally used alkyl-aryl sulfonates, which generally have a narrow range of olefin carbon number, such as C₁₂ -xylene sulfonate (Chou and Campbell, 2001).

Various surfactants have been developed that can be used at very low concentrations to produce ultra-low IFTs for sandstone and limestone formations. These surfactants can be used for alkaline surfactant polymer floods, surfactant floods, and as an adjuvant for waterfloods (Berger and Lee, 2002).

The new surfactants differ from conventional alkyl-aryl sulfonic acids, as the sulfonate group is attached to the end of the alkyl chain, as opposed to being attached directly to the aromatic ring. In general, the surface tensions and critical micelle concentrations are similar, but the solubility of the new alkyl-aryl sulfonic acids and their salts in water is generally greater than the corresponding conventional alkyl-aryl sulfonic acids and their salts. Because the sulfonate group is attached to the alkyl group instead of to the ring, more positions are available on the aromatic ring for additional substitution.

An olefinic sulfonic acid is used to simultaneously alkylate and sulfonate the aromatic compound. The aromatics that can be used include benzene, toluene, xylenes, naphthalene, phenol, and diphenylether, as well as substituted derivatives of these compounds. The olefinic sulfonic acid can be linear or branched with a range of chain lengths. Examples are shown in Figure 16.1. Several laboratory case studies have been performed for the evaluation and application of these compounds.

Sulfoalkylated nonyl phenol can be condensed with formaldehyde into oligomers (Zaitoun et al., 2003). The use of these oligomers, in combination with other surfactants reduces the adsorption of the surfactants.

The effectiveness of alkaline flooding for the recovery of an Arabian heavy crude oil has been studied. The alkaline reagents react with the acidic species in crude oil to form surface-active soaps in situ, leading to a lowering of the IFT and subsequent mobilization of the residual oil.

The equilibrium IFTs obtained through alkaline flooding have been compared with the IFTs when a synthetic surfactant, dodecyl benzene sulfonic acid sodium salt is used (Elkamel et al., 2002).

The effects of connate water on caustic flooding processes in porous media, by employing acidified paraffin oil as the oil phase and aqueous sodium hydroxide as the water phase, were studied. Displacement processes were performed in basic solution and with linoleic acid, in the absence and presence of connate water.

The results indicate that connate water has a greater effect on the displacement pattern for systems with higher IFTs. For lower IFTs, the patterns are similar both with and without connate water. Reducing the acid concentration has a considerable effect on the displacement, indicating that the organic acid is the limiting reagent. Generally, systems containing connate water increase the oil recovery. As the IFT decreases, the number of fingers increases and the finger width decreases (Thibodeau et al., 2003).

The recovery of crude oil by an improved surfactant flooding process has been described. An alkaline polymer surfactant was used, which results in ultra-low IFTs with brine against crude oil even while the surfactant present is at or below its critical micelle concentration. This process is used in oil reservoirs; a primary surfactant system is diluted with brine and pumped downhole, where the alkali, which is usually sodium hydroxide or sodium carbonate, reacts with the residual acidic organic components in the oil to form a secondary surfactant system. This secondary surfactant helps the primary surfactant to further reduce the IFT between the residual oil and the injected fluid, thereby allowing the removal of residual oil from the pores of the reservoir.

The process utilizes a primary surfactant system (anionic surfactants, non-ionic cosurfactants), solvents, and a strong base. An improved, concentrated surfactant formulation primarily containing a mixture of anionic surfactants demonstrated ultra-low (<10⁻² mNm⁻¹) IFT against crude oils containing acidic organic components over a broad range of external parameters, such as surfactant, electrolyte and alkali concentrations, temperature, etc. The primary concentrated surfactant solution is a combination of a linear alkyl benzene sulfonate, a branched alkyl benzene sulfonate, and nonyl phenol (Hsu and Hsu, 2000).

One of the most difficult problems in the use of surfactant flooding for EOR is the frequent, substantial loss of surfactant due to adsorption on the formation matrix and precipitation by polyvalent cations such as calcium and magnesium. A significant percentage of surfactants become physically entrapped within the pore spaces of the rock matrix. Surfactant adsorption on the formation matrix significantly decreases its efficiency, making greater quantities necessary, and hence increasing operational costs.

Most surfactants are only satisfactory for surfactant flooding if the calcium and magnesium concentrations of the formation water are less than about 500 ppm. Petroleum sulfonates, the most popular type of surfactants, precipitate where divalent ion concentrations exceed about 500 ppm. Such precipitation renders the sulfonates inoperative for recovering oil and in some instances, causes formation plugging.

The main cause of surfactant loss is adsorption due to physical contact with the formation matrix, or entrapment within its pores. Carbonate or sandstone matrices contain a range of adsorptive sites hence, adsorption is a particularly vexing problem here.

The most promising way of reducing this problem has been to use sacrificial agent compounds, either in a preflush solution injected before the surfactant-containing solution, or in the surfactant solution itself. The compounds are sacrificial because their adsorption and entrapment reduces the loss of the more expensive surfactants, solubilizers, and polymers contained within the surfactant solutions.

Various chemicals have been employed, including lignosulfonates, which are economically attractive because they are unwanted by-products of the pulp industry. A lignosulfonate acrylic acid graft copolymer has been used as such a sacrificial agent. It is believed that sacrificial agents generally work by several chemical mechanisms (Kalfoglou and Paulett, 1993):

Gas production from gas fields and underground gas storage is usually accompanied by unwanted water production, which often negatively affects the gas flow and recovery efficiency in wells operating in gas fields and hamper the environmental compatibility of the operation. Silicone compounds, such as silanes, siloxanes, silicone oils, and resins have been examined for their ability to restrict water production in gas wells.

Research has therefore been directed at developing a viable method to cure the problem. The methods can be categorized (Lakatos et al., 2003a) as:

The injection of a silicone microemulsion has been developed for the restriction of water production in gas wells. The treating solution was a surfactant-stabilized siloxane emulsion, which was driven into the formation by water and nitrogen.

According to the laboratory studies, the water retention is caused by disproportional permeability modification. This phenomenon is attributed to the inversion of the microemulsion into a macroemulsion initiated by spontaneous dilution by water and then entrapping siloxane droplets so formed by the pores. Field tests showed the beneficial effect of the silicone injection on gas production and gas/water ratio; the gas production tripled and was maintained for at least six months (Lakatos et al., 2002).

The first non-ionic tensides were synthesized by C. Schöller at BASF by condensing oleic and stearic acid with polyoxyethylene glycol in 1930. Non-ionic surfactants are better than ionic surfactants in many respects, and their industrial application has been quite widespread during the past century.

The interfacial rheological properties of different Hungarian crude oil/water systems were determined over wide temperature and shear rate ranges, and in the presence of inorganic electrolytes, water-soluble polymers, non-ionic tensides and alkaline materials (Lakatos and Lakatos-Szabò, 2001a; Lakatos et al., 2003b).

Ethoxylated nonyl phenols significantly reduce both the interfacial viscosity and the non-Newtonian character of the flow. Ethoxylated nonyl phenols with ethoxy groups of 10–40 were screened. The efficiency of ethoxylated nonyl phenols decreases with increasing ethoxy units and increasing concentration. This phenomenon can be explained by the formation of a closely packed adsorption layer between the phases (Lakatos and Lakatos-Szabò, 1997; Lakatos-Szabò and Lakatos, 1989). The activation energy of viscous flow in NaOH-containing oil-water systems is similar to those calculated for surfactant-containing systems (Lakatos-Szabò and Lakatos, 1999).

Micellization experiments on an ethoxylated nonyl phenol in the presence of partially hydrolyzed polyacrylamide (PHPA) showed that the presence of a highly hydrophilic polymer in an aqueous solution of non-ionic surfactants has only a negligible effect on the micelle structure and the mechanism of micelle formation. On the other hand, above the critical polymer concentration, the network structure is stabilized by the tenside. Therefore, the tenside exhibits positive effects on the performance of the polymer (Bedo et al., 1997).

In high salinity formations, the common non-ionic and anionic surfactants are inefficient because of salting out or cloud point phenomena. A hybrid ionic/non-ionic surfactant is shown in Figure 16.2. Such a surfactant has been synthesized, and found to be soluble in 30% NaCl brine, and to show good surface activity in brine. The IFT is particularly low if the surfactant is combined with petroleum sulfonate (Wang et al., 2001a and Wang et al., 2001b).

Experimental evidence on the appearance of a third liquid crystal phase between the oil and water forming a sandwich like structure has been presented. The presence of this structure modifies both the equilibrium and the transport properties of oil-water systems.

Polarization microscopy was used to observe the sandwich structures. Naphthenic acid was used because it is the most important precursor of natural surfactants and its phase behavior is well known (Horvath-Szabó et al., 2001a and Horvath-Szabó et al., 2001b). An equilibrium liquid crystal (LC) layer on an interface between crude oils and water was observed at high pH. This layer is composed mainly of sodium naphthenates formed in situ at the water/oil interface. The transient LC layer was also generated at the interface between aqueous sodium hydroxide solution and oleic naphthenic acid solution as result of a salt formation between NaOH and naphthenic acid. The chemical reaction causes a transport process resulting in a disturbance of the interface. The optical observation of this interfacial disturbance revealed that the interface covered with LC shows a considerably lower flexibility in comparison to an LC-free interface. The LC layer eventually dissolves in the water phase at low oil-to-water ratios, while at high oil-to-water ratio it can form an equilibrium phase, which spreads spontaneously at the oil-water interface (Horvath-Szabò et al., 2002).

The time-dependent IFT has been investigated for an interfacially reactive immiscible system, composed of acidified oil and alkaline water. The acidified oil was composed of either lauric acid or linoleic acid dissolved in n-dodecane. Drop volume tensiometry was used to measure the IFT.

The rate of formation of the interfacial area depends on the alkali concentration. For lauric acid, the IFT value was found to decrease sharply with increasing alkali concentration, even at low drop formation times. In the case of linoleic acid, the decrease of the IFT with the drop formation time was more gradual, in particular at low alkali concentration (Amaya et al., 2002).

The results for micellar flooding and alkaline surfactant polymer flooding processes were compared. Laboratory experiments on micellar floods in consolidated sandstone cores and in unconsolidated sand packs were performed using combinations of an alkali, a surfactant, and a polymer. Slugs were injected sequentially in a series of experiments, while the three components were mixed and injected as a single slug in other experiments. The oil recoveries in the two series of experiments were similar. Micellar flooding was found to be the superior process, with oil recoveries ranging from 50–80% (Thomas and Ali, 2001).

The design of micellar floods is largely based on laboratory experiments, which are usually unscaled. Dimensional and inspectional analysis is helpful for scaling up the design. General scaling criteria can be simplified for corefloods, and were verified by micellar floods in scaled models. Good agreement was obtained in most cases between the actual and predicted oil production histories, showing the validity of the scale-up. The scaling criteria that were derived can be also used for a micellar flood (Thomas et al., 2000).

n-Butanol and other C₄ alcohols are suitable for hot waterflooding in medium to heavy oil reservoirs at depths greater than 1500 m (Richardson and Kibodeaux, 2001).

A composition that includes ammonia and a low molecular weight alcohol, e.g., isopropanol, in an aqueous carrier solution has been proposed to be cost-effective for EOR (Cobb, 2010). The composition can be recovered and recycled to further decrease costs. Apparently, there is no reaction with oil nor is there a significant amount remaining trapped in the formation, so the mixture can be separated from the oil and recycled.

Waste water-soluble alcohols are useful for miscible waterflooding (Ignateva et al., 1996).

Pseudozan is an exopolysaccharide produced by a Pseudomonas species. It has high viscosity at low concentrations in formation brines, forms stable solutions over a wide pH range, and is relatively stable at temperatures up to 65°C. The polymer is not shear-degradable, and has a pseudoplastic behavior. The polymer has been proposed for enhanced oil recovery processes for mobility control (Lazar et al., 1993).

Xanthan interacts with anionic surfactants, which is a beneficial synergistic effect for mobility control in chemical-enhanced oil recovery processes (Liu and Zhang, 1995).

A one-dimensional sand pack model has been used to investigate the behavior of four anionic sulfonate surfactants of varying chemical structure in the presence of steam. The study was performed with a crude oil at a residual oil saturation of approximately 12% of the pore volume. The observed pressure drop across various sections of the pack was used to study the behavior of the surfactant. The tested surfactants varied in chain length, aromatic structure, and number of ionic charges.

A linear toluene sulfonate produced the strongest foam in the presence of oil at residual saturations, in comparison with α-olefin sulfonates. This contrasts with the behavior of the surfactants in the absence of oil, where the α-olefin sulfonates perform better. The reason for this change is the relative propagation rate of the foams produced by the surfactants (Razzaq and Castanier, 1992).

When an oil reservoir is subjected to steam injection, the steam tends to move up in the formation, whereas condensate and oil tend to move down due to the density difference between the fluids. Gradually, a steam override condition develops, in which the injected steam sweeps the upper portion of the formation but leaves the lower portion untouched. Injected steam will tend to follow the path of least resistance from the injection well to a production well (Osterloh, 1994).

Thus, areas of high permeability will receive more and more of the injected steam, which in turn raises the permeability of such areas. This phenomenon exists to an even larger degree with low injection rates and thick formations, and the problem worsens at greater radial distances from the injection well, because the steam flux decreases with increasing steam zone radius.

Although residual oil saturation in the steam-swept region can be as low as 10%, the average residual oil saturation in the formation remains much higher due to poor vertical conformance. This it is because of the creation of steam override zones.

A similar conformance problem exists with carbon dioxide flooding. CO₂ has a large tendency to channel through oil, since its viscosity may be 10–50 times lower than that of the oil. This channeling problem is exacerbated by the inherent tendency of a highly mobile fluid such as carbon dioxide to preferentially flow through more permeable rock sections.

These two factors, namely unfavorable mobility ratios between carbon dioxide and the oil in place and the tendency of carbon dioxide to take advantage of permeability variations, often make carbon dioxide flooding uneconomical. Conformance problems increase as the miscibility of the carbon dioxide with the oil in place decreases.

Although not much attention has been devoted to carbon dioxide conformance, it has long been the intention of the oil industry to improve the conformance of a steamflood by reducing the permeability of the steam swept zone by various means. The injection of numerous chemicals such as foams, foaming solutions, gelling solutions, or plugging or precipitating solutions have all been tried.

Because of the danger of damaging the reservoir, it is considered important to have a non-permanent method of lowering the permeability in the steam override zones. For this reason, certain plugging agents are deemed unacceptable. In order to successfully divert steam and improve the vertical conformance, the injected chemical should be:

The literature is replete with references to various foaming agents that are employed to lower permeability in steam swept zones, the vast majority of which require the injection of a non-condensable gas to generate the foam in conjunction with the injection of steam and the foaming agent (Osterloh, 1994).

C₁₂ to C₁₅ alcohols and α-olefin sulfonate are highly effective when used with steam or carbon dioxide foaming agents in reducing the permeability of flood-swept zones (Osterloh, 1994). The sodium salt of tall oil acid is suitable as a foam surfactant. Experimental results show that sodium tallates are effective foaming agents that can produce pressure gradients of hundreds of pounds per square inch per foot in a sand pack (Osterloh and Jante, 1995).

The foam-holding characteristics of foam from surfactants in oil field jobs can be tailored by adding an imidazoline-based amphoacetate surfactant, which are a special class of amphoteric tensides (Figure 16.3). Imidazoles, such as 2-heptylimidazoline, c.f., Figure 16.4, are reacted with fatty acids by ring opening. For alkylation, the imidazoline is reacted with, for example, chloroacetate (Dino and Homack, 1997). Residues from the production of caprolactam have been proposed as surfactants (Tulbovich et al., 1996).

A foam can be generated by using an inert gas and a fluorocarbon surfactant solution in admixture with an amphoteric or anionic hydrocarbon surfactant solution. A relatively small amount of the fluorocarbon surfactant is needed when mixed with the hydrocarbon surfactant and foamed. The foam has a better stability than a foam made with hydrocarbon surfactant alone when in contact with oil (Rendall et al., 1991).

In situ visbreaking with steam and a catalyst can produce crude oils with reduced viscosity (Higuerey et al., 2001). A special variety of visbreaking that involves partial steam reforming, which produces smaller hydrocarbon components and additional hydrogen free radicals and carbon dioxide, has been described.

Practically all life forms may be infected by one or more kinds of microorganism, some of which confer a mutual advantage, such as in symbiosis, whereas some result in a disease of the host. The use of bacteria in MEOR operations necessitates a consideration of possible untoward effects against man and other living creatures. Because large numbers of bacteria are going to be placed into the ground and possibly come into direct contact with oil field workers who know little about them, it is necessary to closely examine possible hazards that may be associated with their use (Grula et al., 1989b).

MEOR methods mainly utilize the metabolites (biosurfactant, biopolymer, organic acid, and biogas) generated in situ or ex situ by bacteria to improve the mobility of the oil phase. In situ MEOR is mainly targeted toward the residual oil left after primary or secondary production, and its success depends strongly on the penetration and the stability of recovering agents. To contact the trapped oil with appropriate bacteria, the microbes must be transported from a wellbore to locations deep within the reservoir (Jang et al., 1989).

When microbial activity develops in a subsurface geologic environment, the geologic, mineralogic, hydrologic, and geochemical aspects of the environment will have a profound effect on the microorganisms and, in turn, the microbial population will have some effect on the rocks and fluids. The most significant geologic changes are (Bubela, 1989):

Various bacterial species have proven useful in MEOR, depending on the biochemical materials produced by the the species, such as gases, surfactants, solvents, acids, swelling agents, and cosurfactants, which facilitate the displacement of oil. In field experiments, in situ fermentation is often desirable for producing a great quantity of gases. Clostridium hydrosulfuricum 39E was found to have surface active properties during simulated EOR experiments (Grula et al., 1989a; Yen et al., 1991).

Key mechanisms important for improved oil mobilization by microbial formulations have been identified, including wettability alteration, emulsification, oil solubilization, alteration in interfacial forces, lowering of the mobility ratio, and permeability modification. Aggregation of the bacteria at the oil-water-rock interface may produce locally high concentrations of metabolic chemicals that result in oil mobilization. A decrease in relative permeability to water and an increase in relative permeability to oil was usually observed in microbial-flooded cores, causing an apparent curve shift toward a more water-wet condition. Cores preflushed with sodium bicarbonate showed increased oil recovery efficiency (Chase et al., 1991).

Microorganisms inhabiting petroleum-bearing formations or that are introduced into subterranean environments are subject to extremes of redox potential, pH, salinity, temperature, pressure, ecologic pressure, geochemistry, and nutrient availability. Successful MEOR requires the selection, injection, dispersion, metabolism, and persistence of organisms that have the right properties to facilitate the release of residual oil (Sheehy, 1991).

A microbial process was developed for controlling the production of hydrogen sulfide by sulfate-reducing bacteria, using mutant strains of Thiobacillus denitrificans. T. denitrificans oxidizes sulfide to sulfate, using oxygen or nitrate as the electron acceptor, but is inhibited by sulfide concentrations above 100–200μ. A mutant of T. denitrificans that is resistant to glutaraldehyde (40 mgl⁻¹) and sulfide (1500μ) was obtained by repeated subculturing at increasing concentrations of the inhibitors.

This strain prevented the accumulation of sulfide by Desulfovibrio desulfuricans when both organisms were grown in a liquid medium, or in Berea sandstone cores, which the wild-type strain did not. The mutant also prevented the accumulation of sulfide by a mixed population of sulfate-reducing bacteria enriched from an oil field brine.

Fermentation balances showed that this strain stoichiometrically oxidized the biogenically produced sulfide to sulfate. The mutant grew at temperatures up to 40°C, in salinities up to 2%, and at pressures up to 120 atm (McInerney et al., 1991). C. hydrosulfuricum 39E was found to have surface active properties during simulated enhanced oil recovery experiments (Yen et al., 1991).

The sulfur bacteria, which use sulfur compounds in their metabolism, are among the bacteria that can inhabit an oil reservoir. They produce hydrogen sulfide, which is responsible for extensive corrosion in the oil field, so the exclusion of these bacteria from MEOR is highly desirable. The net effect of souring a reservoir is a decrease in its economic value (Westlake, 1991).

B. licheniformis JF-2 and Clostridium acetogutylicum were investigated under simulated reservoir conditions. Sandstone cores were equilibrated to the desired conditions, saturated with oil and brine, and flooded to residual oil saturation. The waterflood brine was displaced with a nutrient solution. The MEOR efficiency was found to be directly related to the dissolved gas/oil ratio. The principal MEOR mechanism observed in this work was solution gas drive (Donaldson and Obeida, 1991).

Many S. putrefaciens strains can reduce metal oxides, and Shewanella species that can utilize butane have been proposed for a method of bioremediation of petroleum contaminants. Biofilms of Shewanella species can sequester gases, in particular CO₂, in underground geological formations and prevent the release into the atmosphere (Cunningham et al., 2006).

S. putrefaciens grows under denitrifying anaerobic conditions on crude oil as the sole carbon source. This organism can assist the release of oil from a substrate when grown on either lactate or peptone as a carbon source, as shown by in vitro experiments. Thus, this strain can be used to improve oil recovery (Keeler et al., 2010).

Particular strains of denitrifying bacteria belonging to the genera Azoarcus and Thauera have been shown to grow on oil and or oil constituents under anaerobic conditions, without the need for nutrient supplementation (Anders et al., 1995). Enzymes that catalyze the metabolism of simple aromatic compounds have been identified in these species.

Enzymes from Thauera aromatica metabolize toluene and all cresols, but no xylene isomers. Most of the aromatic compounds are converted to the central intermediate benzoyl-CoA via different metabolic pathways. These strains may be useful in the maintenance of oil pipelines as well as in EOR (Hendrickson et al., 2010).

A methanogenic bacterium was isolated from oil reservoir brines by enrichment with trimethylamine. Methane production occurred only with trimethylamine compounds or methanol as substrates. Sodium ions, magnesium ions, and potassium ions were all required for growth. This organism was considered to be a member of the genus Methanohalophilus on the basis of its substrate utilization and general growth characteristics (Gevertz et al., 1991).

A sulfate-reducing bacterium was isolated by enrichment with a lactate-sulfate medium containing 3% NaCl. The isolate utilized lactate as an electron donor for sulfate reduction and contained desulfoviridin, typical of the genus Desulfovibrio (Gevertz et al., 1991).

Particularly preferred bacteria are those of the genera Lactobacillus or Pediococcus. Lactic acid produced by these bacteria may be used for removal of carbonate or iron scale in oil field equipment (Coleman et al., 1992).

The IFT plays an important role in the success of enhanced oil recovery methods, but additional complications arise when the components undergo a chemical reaction. The dynamic IFT behavior of reacting acidic oil-alkaline solutions has been studied for both an artificially acidified synthetic oil, and a real crude oil, at various concentrations, with either a drop volume or a spinning drop tensiometer (Ball, 1995; Ball et al., 1996).

The spinning drop technique measures the shape of an oil drop in the flooding solution in a capillary tube. An automatic measuring system has been developed that combines a video-image analysis, an automatic recording system, and a computer for calculation of the IFT (Yamazaki et al., 2000).

The interfacial rheology is very sensitive to the chemical composition of immiscible formation liquids (Lakatos and Lakatos-Szabò, 2001), hence an understanding of these factors may contribute significantly to an extension reservoir characterization, a better understanding of displacement mechanisms, development of more profitable enhanced and improved oil recovery methods, intensification of the surface technologies, optimization of the pipeline transportation, and improvement of refinery operations (Lakatos-Szabò et al., 1997).

Interfacial rheologic properties of different crude oil water systems were determined over wide ranges of temperature and shear rate, and in the presence of inorganic electrolytes, surfactants, alkaline materials, and polymers (Lakatos-Szabò et al., 1997).

Sensitive analytical procedures enable the detection and measurement of very low levels of tracer. In studies, an identifiable tracer material is injected through one or more injection wells into the reservoir being studied. Water is then injected to push the tracer to one or more recovery wells in the reservoir. The output of the recovery wells is then monitored to determine the tracer breakthrough and flow through the recovery wells. Analysis of breakthrough times and flows yields important information regarding how to perform the secondary or enhanced recovery processes. A sharp breakthrough of tracers in a two-well tracer test is achieved by the following method (Stegemeier and Perry, 1992):

To improve evaluation techniques in a water and gas pilot, tracers were injected in the gas phase at the beginning of the first two-gas injection periods. Perfluoromethylcyclopentane and perfluoromethylcyclohexane were used. In laboratory studies, these compounds were shown to have a higher partitioning to the oil phase than did tritiated methane. This caused a minor retention of the tracer (Dugstad et al., 1992; Ljosland et al., 1993).

Seven water tracers, namely tritiated water (HTO) and the ions S¹⁴CN⁻, ³⁶Cl⁻, ¹³¹I⁻, ³⁵SO₄²⁻, H¹⁴CO³⁻, and ²²Na⁺ were tested for use in carbonate reservoirs. HTO is the ideal water tracer, although S¹⁴CN⁻ and ^{36Cl− were found to be near-ideal tracers for water flow in chalk. 131I−} and ³⁵SO₄²⁻ show a more complicated behavior because of ion exclusion, adsorption, desorption, and chemical reactions (Bjornstad et al., 1994).

Analysis of halohydrocarbons, halocarbons, and sulfur hexafluoride is usually performed by gas chromatography with an electron capture detector. Complex metal anions, such as cobalt hexacyanide, are used as nonradioactive tracers in reservoir studies. The cobalt in the tracer compound must be in the complex anion portion of the molecule, because cationic cobalt tends to react with materials in the reservoir, leading to inaccurate analytic information (Miller et al., 1993).

In most production reservoirs, the brines produced are injected into the formation to maintain reservoir pressure and avoid subsidence and environmental pollution (Hutchins and Saunders, 1993), and, in the case of geothermal fields, to recharge the formation. These brines can, however, adversely affect the fluids produced from the reservoir. For example, in geothermal fields, the injected brine can lower the temperature of the produced fluids by mixing with the hotter formation fluids. In order to mitigate this problem, the subsurface paths of the injected fluids must be known.

Tracers have been used to label fluids in order to track their movement and monitor chemical changes in the injected fluid. Radioactive materials are one class of commonly used tracers, but they have several drawbacks.

They require special handling because of the danger posed to personnel and the environment. They also alter the natural isotope ratio that is indigenous to the reservoir. In addition, the half-life of radioactive tracers tends to be either too long or too short for practical use.

A number of organic compounds are suitable for use as tracers in a process for monitoring the flow of subterranean fluids. The following have been proposed: benzene tetracarboxylic acid, methylbenzoic acid, naphthalene sulfonic acid, naphthalene disulfonic acid, naphthalene trisulfonic acid, alkyl benzene sulfonic acid, alkyl toluene sulfonic acid, alkyl xylene sulfonic acid, α-olefin sulfonic acid, salts of the foregoing acids, naphthalenediol, aniline, substituted aniline, pyridine, and substituted pyridines (Hutchins and Saunders, 1993).

The permeability of a high-permeability zone in a high-temperature oil can be reduced by placing an aqueous solution of a gellable polymeric and gelling this solution in situ (Lockhart and Burrafato, 1990b and Lockhart and Burrafato, 1990c). The gel is made of a copolymer or a mixture of a synthetic polymer and a biopolymer (e.g., xanthan gum) (Lockhart and Burrafato, 1990a). Crosslinking agents are trivalent chromium ions or aldehydes (Sydansk, 1995). The pH is adjusted to 1.5–5.5, depending on the desired gelling time.

Anti-syneresis properties can be obtained with various organic acids and their alkali metal or ammonium salts. A delay in gelation also occurs when malonic acid is used (Albonico and Lockhart, 1993). AAms also can be crosslinked in situ by o-hydroxyphenylmethanol (Moradi-Araghi and Stahl, 1991b) or furfuryl alcohol and formaldehyde (Moradi-Araghi and Stahl, 1991a).

Melamine resins (Shu, 1990) and phenol-formaldehyde resins (Shu and Shu, 1991) can be gelled in situ to reduce the permeability of a formation. Various classes of polymers can be gelled by similar principles (Hutchins and Dovan, 1992).

Latex particles may flocculate when injected in to a reservoir at high formation temperatures. When the particles flocculate, shrink, and harden, they form a more effective blocking agent than the dispersed, expanded, and softer particles (Snowden et al., 1993).

Carbon dioxide flooding is one of the most promising enhanced oil recovery method. To overcome the tendency of CO₂ to bypass the smaller pores containing residual oil, one approach is to plug the larger pores by chemical precipitation. Several, relatively inexpensive, water-soluble salts of alkaline earth metals react with CO₂ to form a precipitate.

Laboratory experiments have indicated that carbonate precipitation can alter the permeability of the core samples under reservoir conditions. The precipitation reduces the gas permeability in favor of the liquid permeability indicating that precipitation occurs preferentially in the larger pores.

Once the precipitate is formed, subsequent fluid flow will be diverted to smaller pores, thereby increasing the sweep efficiency. Additional experimental work with a series of connected cores suggested that the permeability profile can be modified successfully, but pH control plays a critical role in the propagation of the chemical precipitation reaction (Ameri et al., 1991).

The permeability profile of a formation where temperatures over 90°C are encountered can be modified by the following process: an aqueous solution of an alkali-metal hydroxide, ammonium hydroxide, or organo-ammonium hydroxide is injected into a zone of greater permeability in a formation. After this, a spacer volume of a water-miscible organic solvent is injected, followed by a water-miscible organic solvent containing an alkylpolysilicate in the greater permeability zone. A silica cement is formed in situ, which substantially closes off the higher permeability zone to fluid flow. Finally, a steamflooding, waterflooding, carbon dioxide stimulation, or fireflooding enhanced oil recovery operation is commenced in the lower permeability zone (Shu et al., 1993a and Shu et al., 1993b) .

Hydratable clays may be used as plugging agents for profile control. The swelling of the clay is desirable, unlike when formation damage occurs (Zhou, 2000). First, an aqueous solution of the salts of cations such as K⁺, Ca²⁺, or Mg²⁺ that inhibit clay swelling is prepared.

The clay slurry is introduced into the formation, where it enters the channels of high permeability where it contacts the NaCl solution already present in natural or injected drive fluids. The inhibitive cations that are bound to the clay particles are replaced by Na⁺ ions, which attract water molecules and promote clay swelling. The Na⁺ clay swells up to 10 times its original volume, causing the slurry to acquire a gel-like consistency, which then blocks the flow of water. The gel can resist a differential pressure gradient of up to 500 kPam⁻¹.

Silicate gel enhances the sweep efficiency of a waterflood, gasflood, or steamflood operation by reducing the permeability of the high-permeability zones. Weak acids may be added to control gel generation rate (Chou and Bae, 1994).