Laboratory Studies On Alkaline Waterflooding

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract Alkaline waterflooding has been extensively investigated over the past 50 years in laboratory and field testing situations as a method for increasing crude oil recovery. Alkaline salts such as sodium silicate, sodium hydroxide and sodium carbonate have been cited in various patents and investigations as useful agents for patents and investigations as useful agents for improving water flood performance. Laboratory measurements of interfacial tension (IFT) values between alkaline solutions of sodium orthosilicate and sodium hydroxide and several mid-continent and California crude oil samples have been obtained with a variety of types of injection water. In softened water with no Ca++ or Mg++ ions present, both alkaline salts exhibit similar reductions in interfacial tension with all the crude samples tested. When unsoftened water was used to prepare alkaline injection solutions, sodium orthosilicate was effective in significantly reducing IFT values at concentrations of 0.5% to 1.0% with mid-continent crudes. However, using sodium hydroxide, even up to 5% by weight, IFT values with these same crudes were not reduced as much as with sodium orthosilicate. Both alkaline salts were equally effective in reducing IFT values between the California crude oils tested and unsoftened injection solutions. The concentration of alkaline salt required to produce a minimum IFT value ranged from 0.01% to 0.5% by weight, depending upon the injection water used. This paper will review the laboratory data which has been accumulated, and present a comparison between sodium orthosilicate and sodium hydroxide as alkaline waterflood additives. Introduction A recent article by Johnson provides an excellent review of the historical background, proposed mechanisms and the state-of-the-art proposed mechanisms and the state-of-the-art in caustic and emulsion methods for improved waterflood recovery of oil. The addition of alkaline chemicals to injection water has been proposed by many workers over the past six proposed by many workers over the past six decades (Reference 1 and the references contained therein). Considerable laboratory data and a few field trials have suggested that alkaline waterflooding, or modifications thereof, can provide an incremental increase in oil recovery under the proper operating conditions in selected reservoirs. At the present time there are several field trials of alkaline waterflooding under way or proposed.

Experiments at NIPER have demonstrated that oil mobilization by microbial formulations is not merely the result of the effects of the metabolic products from the in situ fermentation of nutrient. A combination of two microorganisms, Bacillus licheniformis, NIPER and a Clostridium species (NIPER 6) was determined to be an effective microbial formulation for the recovery of residual crude oil in porous media. Flask tests with various nutrients and environmental conditions were used to evaluate the growth and metabolite production of NIPER 1 and 6. Several interfacial tension (IFT) measurements were conducted using certain metabolic products from the combined microbial cultures NIPER 1 and NIPER 6. Nonane was used as the oil for these experiments, since crude oil from Delaware-Childers field emulsifies very easily. The IFT of a selected microbial formulation were measured with two different crude oils using brines of varying salinities. Comparisons were made with saline brines containing only the nutrient and with microbial metabolite solutions from which the active cells have been removed by filtration to isolate the specific effects of the microbial cells. Etched-glass micromodel studies showed that the microbial formulation effectively mobilized crude oil trapped after waterflooding. Wettability alteration and unsteady-state relative permeability tests were performed in Berea Sandstone cores. 16 refs., 17 figs., 12 tabs.

Interfacial tensions between sodium hydroxide solutions and four crude oils were measured as a preliminary step in the investigation of caustic waterflooding possibilities. Based on these initial results and some laboratory caustic flood tests reported in the literature; the Wainwright and Viking Kinsella Wainwright B heavy oil reservoirs are possible candidates for improved oil recovery by caustic waterflooding. Core displacement measurements or pilot floods will, however, be required to evaluate actual benefits from the process. A minimum interfacial tension between these heavy oils and caustic solutions occurs with about O.25wt. % NaOH injection water. The interfacial tension between the erode oils and sodium hydroxide solutions was found to release with the age of tire interface. This behaviour suggests that many of the sodium soap products, which are formed when acidic compounds in the crude oil react at the interface with sodium ions in the aqueous phase, subsequently migrate away from the oil-water interface. Introduction The current upswing in improved recovery research has resulted in several recent reports of laboratory studies and field trials of caustic waterflooding processes. This work has been discussed in detail by Johnson(1) and Ehrlich et al.(2). Several controlling mechanisms all relying on changing the properties of some of the interfaces involved, have been identified or suggested as being responsible for improving the recovery aver that of a conventional waterflood. Reisberg and Doscher(3) indicated that interfacial tension lowering and the elimination of rigid films at oil/water interfaces were responsible for an improved ultimate recovery in laboratory displacement experiments, Others(2, 4–6) have tested relatively high NaOH concentrations for alkaline waterflooding in light oil reservoirs where the controlling mechanism appeared to be a wettability change from oil-wet to water-wet. A caustic process has also been used with saline water, in which there was a wettability change from water-wet to oil-wet and the production of a water-in-oil emulsion(7). Workers at Chevron Oil Field Research (8, 9) found significant increases in viscous oil recovery before water breakthrough, and have attributed this to a reduction in water channelling- which results from residual oil being emulsified in situ at low interfacial tensions (oil-in-water emulsion) and then becoming trapped again in small pare throats, Johnson's recent paper(1) also discusses the emulsification and entrainment mechanism, in which emulsified oil is produced rather than becoming trapped. A mobility-controlledaustic flooding process has been outlined by Sarem(10) and is currently being field tested(11). Friedman recently suggested using polyethylenimine, a polybasic polymer, for the recovery of viscous acidic crudes(12). The present study was concentrated on interfacial tension determinations between four Canadian crude oils and caustic solutions. Most of the measurements were with heavy oil of 21–22 º API gravity" from the Wainwright and Viking Kinsella Wainwright B pools in Alberta. Scott et al.(13) and Dranchuk et al.(14) have reported a number of alkaline waterflood tests with heavy ail primarily from the Lloydminster area.

The goal of this work is to evaluate stabilization of foams by a combination of nanoparticles and surfactants. Hydrophilic silica nanoparticles (NP) and anionic surfactants were used in this study. Static foams were generated using surfactants and surfactant-NP mixtures with and without the presence of a crude oil. The decay of the foam height with time was studied and half-lives were determined. The foam drainage behavior and thickness of the foam lamella were studied by fluorescence microscopy. Aqueous foams were created in-situ by co-injecting the surfactant or surfactant-NP mixtures with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). Oil displacement experiments were conducted in Berea cores using surfactant and surfactant-nanoparticle mixture as foaming agents. Static foam tests indicate stabilization effect of nanoparticles on surfactant-nanoparticle foam stability in the absence of crude oil. Lighter crude oils were more destabilizing to foams than heavier oils. Adding nanoparticles even in low concentrations (0.3 wt %) can significantly improve the foam stability and mobility reduction factor in the absence of oil. As the concentration of nanoparticles increased, mobility reduction factor (MRF) of surfactant-nanoparticle foam in a Berea core increased significantly. Fluorescence microscopy elucidated that nanoparticles are trapped in the plateau border as well as lamellas which retard liquid drainage and bubble coalescence. The core floods with a crude oil revealed that the incremental oil recovery by surfactant-NP blend over water flood was about 10% OOIP with an immiscible foam.

The effect of aging and displacement temperatures, and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea Sandstone using three distinctly different crude oils and three reservoir brines. Brine concentration was varied by changing the concentration of total dissolved solids of the synthetic brine in proportion to give brine of twice, one tenth, and one hundredth of the reservoir brine concentration. Aging and displacement temperatures were varied independently. For all crude oils, water-wetness and oil recovery increased with increase in displacement temperature. Tests on the effect of brine concentration showed that salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the reservoir brine with dilution of both the initial (connate) and invading brine or dilution of either. Removal of light components from the crude oil resulted in increased water-wetness. Addition of alkanes to the crude oil reduced the water-wetness, and increased oil recovery. Relationships between waterflood recovery and wettability are summarized.

A laboratory study of alkaline flooding behavior of three viscous acidic crude oils has been carried out. Optimum flooding formulations have been selected by constructing 'activity maps' of the phase behavior of the crude oil-NaOH mixtures as a function of oil fraction and NaOH concentration. Crude oil-NaOH mixtures demonstrate Optimum phase behavior within a very narrow range of NaOH concentration. Addition of nonionic surfactant Triton X-100, as cosurfactant, has been found to enlarge the optimum region of the activity map very considerably. The results obtained from a series of one-dimensional core flow experiments using Berea sandstone cores indicate that simple application of dilute NaOH solution does not recover any significant amount of additional oil as compared to waterflooding. Optimum caustic-cosurfactant solutions with adequate mobility control, using polyacrylamide Cyanatrol 960, recovered upto 96% of oil in place. Caustic consumption appeared to be a significant factor and unfavorable mobility ratio precludes high oil recovery even when caustic solution initiates oil mobilization.

The global production of tight oil has increased dramatically over the past few years. In order to maintain and extend the production growth from such resources, enhanced oil recovery methods must be applied to shale oil reservoirs. Some of earlier studies have confirmed the potential of cyclic gas injection to improve the oil recovery from shale reservoirs. More studies are needed to explore the mechanisms and to optimize the process. In this study, the nitrogen huff-n-puff technique has been applied to oil-saturated shale core samples to improve oil recovery. This paper presents the new experimental work to investigate the effect of pressure decline rate on oil recovery. The effect of soaking time is also studied. Eagle Ford shale core plugs were used in the experiment. For the purpose of comparison and validation, two groups of tests were conducted. One group of tests had one-day soaking time, and the other had three-day soaking time. Both of them were under 1,000 psi soaking pressure. Within each group, three pressure depletion rates were controlled, with the initial soaking pressure depleted in 0.05 hours, 4 hours, and 40 hours, respectively. During the puff periods of experiments, the amount of oil recovered with time (history of oil recovery) was closely monitored to understand the mechanisms. The experimental results show that oil was recovered rapidly during the first two hours during each puff cycle. The oil recovered in each cycle should be measured when no further oil comes out of the core, and we chose six hours as the production time. The results also showed that oil recovery increased as the pressure depletion time was increased, with the same cyclic time and the same number of cycles. For example, for the case of one-day soaking time, the oil recovery factor under the pressure blowout condition was the highest (nearly 50.5% after 10 cycles), while the oil recovery factor was about 43.4% when the soaking pressure was depleted in 40 hours. The oil recovery also increased with longer soaking time only within a certain period, because a further longer period did not present a better performance. The results show that the pressure depletion rate, soaking time and the production time played important roles during the huff-n-puff gas injection process. Introduction Gas injection has become an efficient and promising EOR method for a long time. It accounts for nearly 60 percent of EOR production in the United States. N2 has been successfully used as the injection fluid for the recovery of crude oil. With the advantages of cost-effective than CO2 or hydrocarbon-gas and non-corrosive, N2 becomes an economical alternative for oil recovery by gas miscible displacement (Hudgins et al. 1990). Lots of literature discussed the recovery of crude oil by N2 injection into fractured reservoirs based on the findings from experimental and simulation study (Sayegh et al. 1987; Sayegh et al. 1988; Vicencio et al. 2004; Mungan 2000). The very good agreement between experimental and numerical simulation results showed that N2 is a feasible injection gas for recovering crude oil by gravity floods. Also, the performance N2 and enriched N2 injection that were applied as secondary and tertiary oil recovery process were tested and analyzed. Application of huff-n-puff process has been tested as a means of implementing variety of enhanced oil recovery processes. From the laboratory experimental results of applying huff-n-puff CO2 flooding on Berea cores, Asghari et

Four series of slim tube displacement tests were carried out on a Nisku crude oil at 103 °C, wherein the injection gases were nitrogen and nitrogen enriched with propane and carbon dioxide. Ail the runs were immiscible at pressures up to 34.6 MPa. Twelve floods were performed in Berea cores using the same oil to examine the effects of miscibility, water saturation, mode of injection, and care orientation. The propane slug/nitrogen chase gas mode of injection was the most efficient way of utilizing these gases to produce oil, especially when gas injection was carried out as a secondary enhanced oil recovery process. Introduction This is the second paper written by the authors (Sayegh and Wang) on the recovery of crude oil by N2 injection. The first Paper(l) dealt with the screening of petroleum reservoirs to select candidates for N2 flooding; phase behaviour data of a Nisku crude oil with N2, N2 plus CO2, and N2 plus C3Hg; and the correlation of the phase behaviour data using the Peng-Robinson equation of state. This paper deals with the displacement of Nisku crude oil from porous media by N2 injection, and includes slim tube displacement tests and their numerical simulation as well as Berea core floods. The oil-in-place (live Nisku crude), the injection gases (N2, CJHg and CO2 mixtures), and the temperature (l03 °C) are the same as those for the phase behaviour measurements. Table 1 lists some of the main properties of the live Nisku crude. The displacement pressures include those at which the phase behaviour measurements were carried out, as well as higher values. Hence, this paper, together with the work presented in Reference 1, provide complementary sets of data relating to the recovery of crude oil from petroleum reservoirs by N2 injection. Slim tube Displacement Tests of Nisku Crude Oil by N2 Mixtures The phase behaviour measurements presented in Reference 1 were designed to simulate the multiple contact process that occurs during oil displacement in porous media. A lot of information was gleaned from these measurements, but unfortunately only four "contacts" could be carried out because of equipment limitations. The slim tube displacement data presented in this section provide information on what occurs in such systems when a large number of contacts occur. Experimental Apparatus and Procedure The slim tube displacement apparatus is shown schematically in Figure 1, and a detailed description may be found in Reference 2. The tube itself was made from stainless steel, was 12.2 m long, had an internal diameter of 4.57 mm, and was coiled. It was packed with 100 µm diameter glass beads to a porosity of 0.37. Its pore volume was measured to be 73.7 ml. Live Nisku crude was the oil-in-place in all the displacements, 103 °C was the test temperature, and the gas injection rate was kept at 2.5 ml/hr for all of the runs.

Caustic in the form of sodium hydroxide solutions is shown to interact strongly with sandstone at elevated temperature (185°F). Such interaction has substantial influence on the success of secondary and tertiary oil-recovery sodium hydroxide floods carried out in sandstone formations of more ordinary temperatures. Caustic in the form of sodium hydroxide interacts with sandstone at elevated temperature to promote (1) significant dissolution of the more susceptible silicate minerals, predominantly clay and large-surface-area silica minerals; (2) sandstone weight loss; (3) increased porosity; (4) propagation of significant concentrations of water-soluble silicates, including sodium orthosilicate; (5) in-situ formation of new immobile aluminosilicate material; (6) changes in permeability; and (7) hydroxide ion consumption. Caustic/sandstone interaction resulting from sodium hydroxide dissolution of silicate minerals is limited by kinetics. The interaction increases with increasing temperature, increasing sodium hydroxide concentration, and increasing caustic/sandstone contact time. The rate and the amount of interaction are sensitive to sandstone mineralogy and lithology. Although not studied during this work, the presence of crude oil, along with crude-oil type, may affect the rate and the amount of interaction. Based on the laboratory study of elevated temperature caustic/sandstone interaction involving silicate-mineral dissolution by sodium hydroxide, it is concluded that, at lower temperatures, the much slower dissolution interaction has implications for field application of sodium hydroxide for improving waterflood sweep efficiency and enhancing oil recovery. Specifically, during field applications, the slow interaction could deplete the active hydroxide ions. More common low-temperature field applications are especially susceptible because of long caustic/sandstone contact times and because, in general, relatively small concentrations of sodium hydroxide have been used historically. This study points out that proper extrapolation of laboratory caustic-flooding results to field conditions should account for slow kinetic phenomena. The study also helps explain detrimental caustic/sandstone interactions and lower-than-expected oil recoveries experienced during a number of long-duration low-temperature enhanced oil recovery (EOR) field tests and floods. On the positive side, the dissolution interaction, especially at elevated temperatures, generates in-situ significant concentrations of water-soluble silicates, including sodium orthosilicate. Water-soluble silicates have been reported as candidates for improving oil recovery and for use in preflushes to condition formations for other EOR techniques. Other than noting their in-situ formation and propagation, we did not study the alkaline water-soluble silicates in detail, and they are not discussed.

Summary This paper examines the role of molecular diffusion in the mobilization of waterflood residual oil. A numerical model that simulates the swelling of residual oil blobs by CO, diffusion through a blocking water phase is developed. The diffusion times calculated with the model are compared with those calculated in laboratory micromodel and coreflood experiments. The comparison shows that diffusion plays a major role in the mobilization and recovery of waterflood residual oil and that high unit or local displacement efficiencies are achieved when there is sufficient time for diffusion to swell the oil significantly. For the length scales normally associated with laboratory corefloods, diffusion is sufficiently rapid to reduce effectively the adverse effects of bypassing on overall recovery efficiency. This is not so for field floods, where bypassing of oil by injected CO2, may be expected to occur on a much larger scale. Introduction The displacement of oil by CO2 has been the subject of numerous studies, and a considerable volume of experimental data now exists for the process. In these studies, CO2, usually displaces oil from a fully saturated slim tube or test core in a secondary displacement under conditions where phase behavior favors the development of miscibility. For these conditions, recoveries are observed to be high and rate-insensitive, provided that the effects of gravity segregation, viscous fingering, and bypassing are minimized. In direct contrast, for tertiary recovery experiments where CO2, is injected into a previously watered-out test core, recoveries of residual oil are observed to be considerably lower, dependent on both flood rate and core length. and different for water-wet and oil-wet systems. The differences in performance between secondary and tertiary flood experiments are usually explained in terms of the high water saturations present in the tertiary flood experiments and their effect on the microscopic displacement efficiency. As a consequence of the highly unfavorable mobility ratio for the immiscible CO2, water displacement, injected CO2, bypasses considerable volumes of water, leaving high water saturations behind the displacement front in water-wet rock. The water blocks or shields the residual oil from direct contact with the injected CO2. This prevents development of miscibility and results in a considerable reduction in microscopic displacement efficiency. Molecular diffusion of CO2, through the water blocking phase has been suggested as an important mechanism in the mobilization and recovery of the residual oil in water-wet rock. Swelling of the oil phase causes a breakdown of the original capillary equilibrium, resulting in a pore-scale redistribution of the phases. For this process to be fully effective in recovering residual oil, sufficient time must be available for diffusion of CO2, to swell the oil significantly. Recent flow visualization studies in two-dimensional (2D) micromodels qualitatively confirmed the importance of diffusion and oil swelling in tertiary CO2 displacement experiments. These studies have demonstrated clearly that the bulk of the waterflood residual oil is left behind the CO2, displacement front, trapped by water and therefore inaccessible to the flowing CO2, channels. It was further observed that CO, diffusion through the blocking water phase caused isolated oil droplets in water-wet rock to swell. When sufficient time (overnight) was allowed for diffusion, the swelling eventually was enough to break the water barrier that blocked the oil from the flowing CO2, channel and therefore to allow high oil recoveries. Although the available experimental data suggest that diffusion is important in the recovery of waterflood residual oil, the role of diffusion has not yet been quantified. It is therefore not possible to scale the diffusion times and associated nonequilibrium effects responsible for oil recovery in tertiary CO2, floods correctly on the laboratory scale or in the field. The purpose of this paper is to examine the role of molecular diffusion and to determine the time scales necessary for diffusion to be an effective recovery mechanism both in laboratory floods and in the field. An idealized one-dimensional (1D) pore-scale model is developed that simulates CO2 diffusion through a water barrier to a trapped oil phase and the subsequent swelling of the oil phase. The model clearly demonstrates the important role of diffusion in the recovery process. Computed diffusion times are compared with available experimental data both to validate the proposed model and to relate correctly the time scales over which this process is effective both in laboratory corefloods and in the process is effective both in laboratory corefloods and in the field. Model Development The actual mechanism by which waterflood residual oil is mobilized during a tertiary CO2, flood is not yet fully understood. JPT P. 591

In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding. To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding. The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode. The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.

To develop crude oil production, we investigated several solvents in produced water treatment. This study inspects the direct influences of some solvents on improving recovery and reuse to the crude oil export streamlines. Produced water is characterized by the presence of trace amounts of petroleum, which form complex emulsions that are difficult to break down. A method to purify produced water involves breaking these emulsions with solvents, thereby inducing the coalescence of oil droplets, and facilitating their complete separation. In this work, 40 different solvents have been evaluated to determine their suitability for purifying produced water. Suitability criteria included efficiency in crude oil recovery, cost-effectiveness, toxicity, and availability. To facilitate comprehensive analysis, these solvents were categorized into families based on their chemical characteristics and potential interaction mechanisms. The families were linear aliphatic hydrocarbons, aliphatic and aromatic cyclic hydrocarbons, chlorinated hydrocarbons, alcohols and glycols, low and high molecular weight ethers, ketones, esters, and a miscellany of solvents with special characteristics. Among all the solvents analysed, xylene and cyclohexane are recommended for the purification of produced water due to their high efficiency in the recovery of residual oil. The Hansen solubility parameters (HSP) reveal that oil emulsions in produced water exhibit three solubility spheres. Solvents with solubility parameters within these spheres are effective destabilisers of the emulsions. Additionally, they are readily available, cost-effective materials suitable for the petroleum industry, and capable of being reused within the process. Tetrahydrofuran is also commendable for its extremely high efficiency, availability, low cost, ease of recycling, and reuse in the process, as well as its low toxicity. In conclusion, applying solvents is an effective and viable alternative for the purification of produced water. This method not only achieves high efficiencies in the recovery of residual oil, which can be commercialised to offset the costs, but also the produced water obtained after the purification process is of excellent quality.

Summary Alkaline and alkali/polymer flooding are economical and versatile techniques proposed for application in EOR. Recently, the use of high-pH alkaline chemicals was emphasized to obtain low interfacial tensions (IFT's) with the crude oil and to counteract alkali loss by both reservoir rock and interstitial water reactions. This experimental study compares the utility of sodium carbonate (Na2CO3) buffer solutions with sodium hydroxide (NaOH) and sodium orthosilicate (Na4SiO4) at equal Na2O levels for alkaline and alkali/polymer flooding. The alkalis were found to be equally effective in reducing IFT with Wilmington Ranger zone crude, and eight other acid crude oils. Tertiary recovery results from 20 Berea corefloods with the Ranger zone crude and hard reservoir brine were equivalent (6 to 17%) for Na2CO3, NaOH, and Na4SiO4. Similar modest recoveries were obtained for polymer floods that used Polyacrylamide or xanthan gum. However, polymer augmentation of alkaline floods dramatically increased tertiary oil yields to 73 to 95%. In addition, alkali improved the injectivity of polymer solutions. The alkali reactions with sandstone were much less severe with Na2CO3 than with NaOH or Na4SiO4.

Interfacial interactions between Bakken crude oil and injected gases at reservoir temperature: A molecular dynamics simulation study

Dynamic interfacial tension behaviour has been identified in a surfactant-enhanced alkaline flooding process using David Lloydminster crude oil, sodium carbonate, and the surfactant Neodol 25–35. The magnitude of this dynamic behaviour was found to vary with the surfactant concentration. Five linear corefloods in Berea sandstone were performed with different Neodol 25-3S concentrations. It was found that the initial interfacial tension value in each system, measured with the spinning drop apparatus, correlated with oil recovery efficiency. Further confirmation of this effect was found by comparison Son with literature values of oil recovery vs capillary number for linear Berea sandstone corefloods. Introduction In this paper, dynamic interfacial tension is shown to occur in surfactant-enhanced alkaline flooding. In such a process, the interfacial tension that occurs after initial oil/aqueous phase contact changes with time. The effect that this dynamic behaviour has on oil recovery in linear Berea sandstone cores is demonstrated. Dynamic interfacial tensions can occur when two immiscible liquid phases come into contact, provided one or both of the phases contains a surface-active material Interfacial tension between the two phases can change continuously with time until an equilibrium value is reached. During the course of attainment of equilibrium, the system may pass through an interfacial tension minimum. The possibility of this type of behaviour was mentioned by Wilson(1) and by Harkinsl21 in the 1920s. In 1952, the phenomenon was observed by Mansfield(3) with nujol/oleic acid in contact with a caustic solution, using the pendant-drop apparatus. England and Berg(4) described dynamic interfacial tension as the result of adsorptive accumulation of surface-active species at the interface, and observed the presence of adsorption and desorption barriers for the transfer of 1,5-pentanediol from white oil to water. Dynamic interfacial tensions have been observed repeatedly for crude oil/caustic systems. The phenomenon of interfacial tension (IFT) reduction in this system was first reported by Atkin-son(5) and Nutting(6) in 1927. A more detailed investigation was carried out by Reisburg and Doschert(7), who looked at the effect of interface age and of sodium hydroxide concentration on interfacial tension. Jennings(6) examined 164 crude oils from 78 oil fields and measured IFT as a function of sodium hydroxide concentration using the pendant-drop method. He defined the term "caustic coefficient" as "the number of square cycles on log-log paper bounded by the caustic interfacial tension curve between interfacial tension values of 0.01 and 1.0 dyne/cm and caustic concentrations between 0.001 and 1.0wt%. A poor correlation between caustic coefficient and crude oil total acid number was found. However, 90% of the oils tested showed their lowest IFT with a sodium hydroxide concentration of 0.1 wt%, Jennings did not measure dynamic IFT behaviour. McCaffrey(9) measured IFT between sodium hydroxide solutions and four crude oils using the spinning drop method(10). In some cases he found that IFT increased dramatically as the interface aged, which he attributed to the migration of soap products away from the interface after their initial formation.