Tertiary Oil Recovery Process Research Articles

Effect of Salinity, Resin, and Asphaltene on the Surface Properties of Acidic Crude Oil/Smart Water/Rock System

It has been already well established that adjusting the salinity of displacing fluid critically affects the oil recovery efficiency during secondary and tertiary oil recovery processes. In this investigation, systematic experiments are designed and conducted to find the effects of both low and high salinity water on the surface properties of crude oil–brine/solid surfaces. In this respect, the effects of the major salts including NaCl, CaCl2, and MgCl2 are tested in the concentration range of 0–45 000 ppm on fluid/solid and fluid/fluid interactions for a crude oil/water/rock system. Two main surface properties including contact angle and interfacial tension (IFT) are measured using a pendant drop apparatus. The obtained results demonstrate the critical effects of heavy oil components on the interfacial properties. High film stability in some cases resulted in small contact angle changes, mostly in the range of the strongly water wet condition, for different brine salinity.

Effects of the Initial Rock Wettability on Silica-Based Nanofluid-Enhanced Oil Recovery Processes at Reservoir Temperatures

Coreflood experiments were conducted to evaluate the impact of the initial rock wettability on oil recovery during a tertiary oil recovery process using hydrophilic silica-based nanofluids at reservoir temperatures. An adopted scale of reservoir wettabilities (water-, intermediate-, and oil-wet systems) is used for the core plugs, which were prepared by aging processes. The relationships among temperature, initial wettability, and an additional oil recovery nanofluid flooding process were investigated. The results showed that the initial wettability affects oil recovery performance and showed a greater effect at higher temperatures, as represented by the reservoir temperature. An extended postflush nanoflooding was performed to evaluate incremental oil recovery, and this cycle shows great potential for field applications. By evaluating the contact angle and interfacial tension, it was found that wettability alteration plays a more dominant role in the oil displacement mechanism via nano-EOR. These results...

Petrophysical and rock-mechanics effects of CO2 injection for enhanced oil recovery: Experimental study on chalk from South Arne field, North Sea

Abstract Enhanced oil recovery by CO2 injection (CO2-EOR) is a tertiary oil recovery process which has a prospective for being used, at the same time, as an effective technique for carbon dioxide storage. There is a huge potential for additional oil production and CO2 storage in the North Sea depleted chalk reservoirs. North Sea chalk is characterized by high porosity but also high specific surface causing low permeability. A high porosity provides room for CO2 storage, while a high specific surface causes a high risk for chemical reaction and consequently for mechanical weakening. In order to address this issue we studied two types of chalk from South Arne field, North Sea: (1) Ekofisk Formation having >12% non-carbonate and (2) Tor Formation, which has less than 5% non-carbonate. We performed a series of laboratory experiments to reveal the changes in petrophysical and rock-mechanics properties due to the injection of CO2 at supercritical state. We analyzed these changes with respect to the differences in porosity, specific surface, pore stiffness, wettability, mineralogy and mechanical strength. We observed a 2–3% increase in porosity, a minor decrease of specific surface and consequently a small increase in permeability. A decrease in elastic stiffness is indicated by an increase of Biot׳s effective stress coefficient (α) by 1–2%. Nuclear Magnetic Resonance (NMR) data indicated no change in wettability and the samples remained water wet. We found that the effect of CO2 injection on both petrophysical and mechanical properties of chalk depends on carbonate content. Pure chalk with high carbonate content was found to be vulnerable to mechanical weakening due to CO2 injection, whereas, no significant mechanical effect was observed in the impure chalk of Ekofisk Formation. It should in this context be noted that the experiments spanned only 8 days, therefore long term effects cannot be ruled out. In spite of weakening of the chalk, we expect only minor mechanical effects, because the weakening also causes a lowering of effective stress due to an increase in effective stress coefficient. Extensive time-lapse monitoring strategies are required during a CO2-EOR process for the measurement of changes in reservoir properties that may cause deformation of and leakage from a reservoir. Results of this study will provide data for designing future monitoring strategies based on 4D seismic.

Measurement of Immiscible CO2 Flooding Processes and Permeability Reduction due to Asphaltene Precipitation by X-ray CT Imaging

Carbon dioxide tertiary or secondary oil recovery becomes increasingly significant to the petroleum industry. CO2 flooding can not only enhance or improve oil recovery clearly but also considerably reduce greenhouse gas emission. After CO2 was injected into an oil reservoir, it contacted the reservoir oil and, consequently, changed the equilibrium conditions and fluid properties, which may lead to the precipitation of organic solids, primarily asphaltenes. In this case, the bulk porosity reduces obviously because of asphaltene deposition, which can cause permeability reduction of a tight sandstone reservoir after immiscible CO2 flooding. In this paper, a total of three CO2 coreflood tests under immiscible conditions were performed through the so-called dry, secondary, and tertiary oil recovery processes, respectively. After or before each process, the distribution of crude oil and brine (3wt% NaCl) in the core was scanned by employing X-ray CT scanning. Comparing two CT images before and after recovery processes in one test, it is found that asphaltenes deposited onto the sand grains and thus left in the reservoir, which caused permeability reduction of a tight sandstone reservoir after immiscible CO2 flooding.

β-Cyclodextrin modified anionic and cationic acrylamide polymers for enhancing oil recovery.

Both of acrylamide and allyl-β-cyclodextrin are utilized to react with acrylic acid and dimethyl diallyl ammonium chloride respectively to synthesize the novel anionic acrylamide polymer and cationic acrylamide polymer by redox free-radical copolymerization. The structures of copolymers are characterized by Fourier transform infrared spectroscopy and scanning electron microscopy. Subsequently, the copolymers are evaluated on several aspects such as optimum polymerization conditions, intrinsic viscosity, interfacial tension and stability experiments. It is found that the anionic and cationic acrylamide polymers containing cyclodextrin moieties show better performances on interfacial tension, salt resistance, temperature tolerance, viscosification property and shear resistance than that of polyacrylamide. By the comprehensive comparison and analysis, the anionic polymer is more conductive to decrease the interfacial tension for the tertiary oil recovery process, while the cationic polymer is more suitable for enhancing oil recovery in high-temperature and high-mineralization oilfield.

Oil Recovery and Permeability Reduction of a Tight Sandstone Reservoir in Immiscible and Miscible CO2 Flooding Processes

In this paper, oil recovery and permeability reduction of a tight sandstone reservoir in immiscible and miscible CO2 flooding processes are experimentally studied. First, a series of saturation tests are conducted to determine the onset pressure of asphaltene precipitation from a light crude oil−CO2 system. Second, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) between the light crude oil and CO2. Third, a total of nine CO2 coreflood tests under immiscible and miscible conditions are performed through the so-called dry, secondary, and tertiary oil recovery processes, respectively. It is found that the onset pressure of asphaltene precipitation is much lower than the MMP. In the CO2 secondary oil recovery process, the coreflood test data show that, when the injection pressure is between the onset pressure of asphaltene precipitation and the MMP, the oil recovery factor is higher but the oil effective permeability reduction is larger at a higher injection pressure in the immiscible CO2 flooding. They both reach almost constant maximum values in the miscible CO2 flooding (P ≥ MMP). It is also found that, in three different miscible CO2 oil recovery processes, the CO2 tertiary flooding process gives the lowest oil recovery factor but the largest oil effective permeability reduction. This is attributed to the most severe codeposition of asphaltenes and metal carbonates. However, the CO2 dry or secondary flooding process has a significantly higher oil recovery factor but a much smaller oil effective permeability reduction due to asphaltene deposition alone in the former process or codeposition of asphaltenes and metal carbonates in the latter process.

Coreflooding Studies to Evaluate the Impact of Salinity and Wettability on Oil Recovery Efficiency

In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of experiments) with decrease in brine salinity and increase in brine temperature.

Application of Emulsion Blocking Mechanism for Sealing the Near Wellbore Region

Abstract Across Canada, thousands of abandoned gas wells leak gas to the surface. As a potential solution to this problem, we have done laboratory-scale, experiments relevant to a field-tested novel process that injects a viscous oil-in-water emulsion to plug the formation near the wellbore. In an earlier study, we observed that, for unconsolidated cores, the process is effective and may withstand large pressure gradients over long periods of time; however, the emulsion penetration depth was limited to a small fraction of the core's length. Now, we report results of subsequent experiments, our understanding of the emulsion blocking mechanism and criteria for controlling the distance into the formation to which an emulsion may penetrate. In these experiments, well-characterized emulsions were injected into an etched glass micromodel or a micromodel packed with well-sorted glass beads or sand grains to yield the desired permeability. Visualization experiments were done to observe the capture mechanisms of the emulsion droplets. We observed that, for a given pressure gradient, some droplets are too large to pass through a pore's throat (size exclusion), that other droplets attach to the pore's surface and coalesce with nearby droplets to accelerate the blockage process and that more viscous droplets are most effective in blocking pores. We found that the rate and extent of transfer of surfactant from the solution to the bead's surface must be important. In subsequent experiments, we flushed the micromodels with a surfactant solution to alter the wettability of the beads prior to injecting the emulsions. The results showed that the choice of surfactant, its concentration and the volume of its injected solution predictably affect the depth to which the oil-in-water emulsion may penetrate into a micromodel. In conclusion, this work characterizes the flow behaviour and breaking of an emulsion in a porous medium and examines parameters that may be adjusted to control the novel process. Introduction Crude oil emulsions are a broad area and several books have been written on the subject(1–3). Their occurrence in certain modes of crude oil production and their application as a blocking agent in underground porous media have received more attention recently. Emulsions can be encountered in almost all phases of oil production and processing(4, 5). Field emulsions can be generated within oil reservoirs and/or in the wellbore during production. The problem has been more pronounced recently due to the fact that many oil reservoirs are being watered out. Salty water has to be separated from the produced emulsions in order to meet crude specifications for transportation, storage and export, as well as avoid catalyst poisoning in the refineries. However, emulsion treatment is not an easy task and demands an application of various thermal, mechanical, chemical and/or electrical processes or their combination(4, 5). On the other hand, the application of emulsions as blocking agents in many secondary and tertiary oil recovery processes makes them of particular interest to many researchers. Laboratory studies have suggested that oil-in-water (O/W) emulsions can be used to obtain a deeper formation plugging resulting in better sweep efficiency and greater oil recovery(6–11).

Effects of Viscous and Capillary Forces on CO2Enhanced Oil Recovery under Reservoir Conditions

Carbon dioxide flooding has been proven to be one of the most effective and viable enhanced oil recovery (EOR) processes for light and medium oil reservoirs. In the past, an extremely large number of laboratory experiments and numerical simulations have been conducted to study the CO2 EOR process. However, the specific effects of viscous and capillary forces on this tertiary oil recovery process are neither thoroughly studied nor well understood yet. In this paper, an experimental study is carried out to examine the detailed effects of viscous and capillary forces on the CO2 EOR under the actual reservoir conditions. First, the equilibrium interfacial tensions between a light crude oil and CO2 are measured at different equilibrium pressures. Second, a series of CO2 coreflood tests are performed to measure the CO2 EOR at different CO2 injection pore volumes, pressures, and rates. Each CO2 coreflood test is terminated after a total of 1.5 pore volume of CO2 is injected. The detailed experimental results show that, in general, the measured equilibrium interfacial tension is reduced with the equilibrium pressure but the measured CO2 EOR at 1.5 pore volume of CO2 is increased with the CO2 injection pressure and rate. Finally, the measured CO2 EOR at 1.5 pore volume versus injection pressure data at different CO2 injection rates are related to the measured equilibrium interfacial tension versus equilibrium pressure data in terms of the complete capillary number, which is defined as the ratio of the viscous force to the capillary force for each CO2 coreflood test. This study shows that if the complete capillary number is in an intermediate range, the CO2 EOR increases quickly with the complete capillary number. Otherwise, the CO2 EOR is lower and remains almost constant for a smaller complete capillary number, or it is higher and remains unchanged for a larger complete capillary number.

Laboratory Investigation of Enhanced Light-Oil Recovery By CO/Flue Gas Huff-n-Puff Process

Abstract This paper focuses on phase behaviour measurements with reservoir oil-CO2 mixtures and on coreflooding tests in the huffn- puff mode to characterize the system, determine the influential mechanisms, and supply data for simulation of the field implementation. The results indicate that significant amounts of CO2 could dissolve in the oil, which caused oil swelling and viscosity reduction. During the puff cycle, the oil retained CO2 preferentially to methane; thus, the beneficial swelling and viscosity effects were maintained over an extended portion of this cycle. Corefloods were performed to investigate the effect of waterflood residual oil saturation and injection gas composition (CO2 and enriched flue gas) on oil recovery. Incremental oil recovery was observed to be sensitive to waterflood residual oil saturation and to the process application scheme. Coreflooding results suggest that the huff-n-puff process may be more suitable to oil-wet than water-wet reservoirs. Introduction Various technologies have been applied in tertiary oil recovery processes, such as gas miscible/immiscible injection and chemical flooding. Among these enhanced oil recovery (EOR) methods, the huff-n-puff process has been reported to be economic at an oil price of less than US$20/STB and CO2 costs of US$40/ton(1). For example, it was shown in a flue-gas huff-n-puff project(2)that oil production rates stabilized, and the project proved to be cost effective with small investment requirements and low operating costs. In another case(3), the CO2 huff-n-puff process was not successful in increasing incremental oil recovery. However, there were reduced water-handling and electrical requirements during the injection, soak, and flow phases, which were beneficial to the project. There is increasing interest in CO2/flue-gas huff-n-puff injection into single wells because the process is relatively easy to apply and does not require a large initial capital outlay. The process typically begins with the injection of a slug of gas into a single well. This is followed by a shut-in or soak period to allow the gas to dissolve into the oil, swell its volume, and reduce its viscosity. The same well is then returned to production and the response is monitored. In reservoirs with poor inter-well communication, this single-well approach may be one of the best ways, and sometimes the only way, to accelerate response in underperforming wells. Since miscibility between the reservoir oil and injected gas is not a requirement of the huff-n-puff process, it is well suited for low pressure reservoirs and for gases with high minimum miscibility pressures such as flue gas. The mechanisms involved in the production of oil during gas huff-n-puff are diverse and complex. The following mechanisms have been mentioned in the literature(4–6):oil viscosity reduction;oil swelling;solution gas drive;relative permeability hysteresis due to reduced water saturation, drainage/imbibition, and wettability alternation;repressurization;gas diffusion and mass transfer; and,interfacial tension reduction in the zone near the wellbore. The purpose of this work is to investigate the potential for applying the CO2 huff-n-puff process in a medium-gravity oil reservoir in Saskatchewan.

A Decline-Analysis Technique Incorporating Corrections for Total Fluid-Rate Changes

Summary Decline analysis inherently assumes a constant total-reservoir-fluid rate in contrast to constantly varying rates in actual field operations. This paper provides an approach for determining decline constants under varying total fluid rates for secondary or tertiary oil recovery processes. It further enables forecasting oil and nonoil production performance under different total fluid rate strategies. The technique helps identify pseudosteady state flow periods when decline analysis techniques are valid. It distinguishes incremental from accelerated oil responses when a recovery process change, operating practices, or workover activity causes a total fluid rate change.

Methodology for Numerical Simulation With Cycle-Dependent Relative Permeabilities

SummaryMultiphase flow involving saturation oscillations should be modeled with history-dependent, relative permeability functions. Earlier approaches have been based on two-phase flow. The main assumptions have been that the imbibition process is reversible. Moreover, scanning curves were developed only for saturations between some extreme values.Several tertiary oil recovery processes have shown cycle-dependent hysteresis for relative permeability. When saturation oscillations occur during three-phase flow such as water alternating gas (WAG), the two-phase hysteresis models will generally not be able to describe relative permeabilities obtained from corefloods. For three-phase flow, local hysteresis effects may also be important. New relative permeability representations that account for local hysteresis effects are presented.Hysteresis models for both wetting and nonwetting phase permeabilities have been developed. The new models account for reduced mobility and irreversible hysteresis loops during three-phase flow. The models depend on the initial saturation at the start of the given process. An algorithm is presented for implementing the nonwetting phase hysteresis model in a numerical simulator. The new three-phase models use experimental wetting and nonwetting relative permeabilities as input, and knowledge of relations between maximum nonwetting saturation and trapped nonwetting saturation.

Parachors Based on Modern Physics and Their Uses in IFT Prediction of Reservoir Fluids

SummaryPrediction of interfacial tension (IFT) is essential for modeling many secondary and tertiary oil recovery processes. The parachor method (PM) has been widely used to predict IFT. There has been considerable confusion in the literature concerning the PM for estimating IFT. The confusion is based primarily on the lack of clarity concerning the scaling exponent and parachors derived from this exponent.According to modern physics, the theoretical value ofthe scaling exponent is 3.88 for all pure substances, although several values may be found in the literature, usually altered to match existing data. This paper addresses clarification of the confusion about the scaling exponent, derivation of parachors for pure species occurring in petroleum fluids and oil cuts, and verification of the validity of these derived parachors in IFT prediction of reservoir fluids.We have analyzed experimental data for various compounds occurring in reservoir fluids and found that 3.88 is a valid scaling exponent for pure species inside and outside, to some large extension, of the critical region. Taking 3.88 as a fixed scaling exponent, parachors of 139 crude oil components are back-calculated by means of surface tension and density data obtained from experiments by previous investigators. These parachors are compared with three selected parachor correlations for IFT prediction of six crude oil and CO2 mixtures and are found to be more accurate.

Hybrid foam flooding

A new enhanced oil recovery process called the hybrid foam flood is described. It is a secondary or a tertiary oil recovery process involving the injection of a miscible solvent in two stages. Initially, the original solvent is injected and is intentionally allowed to channel towards the producer to take advantage of the early breakthrough response. In the second stage, the rest of the solvent is injected in the form of a foam to take advantage of the increased sweep efficiency. Experiments conducted verify the advantages of the hybrid foam flood over both the solvent the stright solvent and the conventional foam flood for tertiary miscible recovery.

Enhanced Oil Recovery by Flooding With Dilute Aqueous Chemical Solutions

The theory of enhanced oil recovery by surfactant flooding (micellarpolymer and “low-tension” floods) is based on three premises: that the chemical slug is 1) less mobile than the crude oil, 2) miscible with the reservoir fluids (oil and brine), and 3) stable over long periods of time (years) in the reservoir environment. We report here a rather simple process in which none of these expensive and exacting requirements have to be met. In this process, relatively small amounts of “EOR-active” substances present in certain petroleum-based sulfonates are found to recover 15–20 percent of the residual oil from waterflooded Berea sandstone cores. The chemicals are injected in the form of slugs of their aqueous solutions. If the chemical slugs are followed with similar slugs of additives such as partially hydrolyzed polyacrylamide, acrylamide monomer, urea, EDTA, or anions such as P2O7‴‴‴‴ and PO4‴‴‴, the oil recovery is increased 30–40 percent of the in-place residual oil. The concentrations of the “active” sulfonate and additive in their respective slugs appear to be of the order of 500 ppm or less. Extrapolation of the laboratory data to field conditions indicate that chemical requirements for the recovery of a barrel of tertiary oil are about 0.5–2 lb of sulfonate and a like amount of additive. The main features of the displacement process are: 1) Oil recovery is independent of oil viscosity in the tested range of 0.4–100 cps. 2) The process is essentially an immiscible displacement in which oil recovery depends on the amount of active chemical in the slug and not its concentration. 3) Tertiary oil is produced in the form of a clean “oil bank” and the buildup of a residual oil saturation at the producing end of linear cores occurs during the flood. From the data on hand, it is apparent that the oil recovery mechanism differs basically in character from the conventional Buckley-Leverett-type immiscible displacement. The low level concentrations of sulfonate and additive involved, and the independence of oil recovery with respect to oil viscosity suggest that the recovery mechanism is possibly actuated by certain specific functional groups in the structure of the EOR-active molecule or its anion, and of the additive. The results hold great potential for developing a simple and economical tertiary oil recovery process that can recover, very substantially, more oil (light as well as moderately viscous) than is now considered possible by conventional chemical floods.

Smackover Nacatoch Crude Oil – Separation of Surfactant Precursors and Their Effect on the Crude

Abstract A procedure is given for separating surfactant precursors that occur in some crude oils. The effect of the precursors on the properties of the oils are described also. The separations were made by silica gel chromatography on crude oil from which the asphaltenes had been removed. The effect of the precursors on the properties of the crude was evaluated by blending the surfactant precursors into the original oil, a modified oil, or a hydrocarbon solvent such as benzene. Precursors activated and converted to surface active materials by a strong base such as sodium hydroxide are effective in reducing the interfacial tension between the oil and aqueous phase. Occurrence of precursors in crude oils is essential for improved oil recovery by the causticflood process. The procedure for separating the precursors should provide a viable means for evaluating the applicability of a causticflood tertiary oil recovery process to a particular crude or reservoir.

Effect of Fractional Flow Hysteresis on Recovery of Tertiary Oil

Abstract This paper deals with the oil/water bank propagation in a tertiary oil recovery process. Oil/water bank propagation was studied in a series of laboratory micellar floods and simultaneous oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation. It was observed that a high oil saturation region, or hump, developed at the leading edge of the oil/water bank and grew linearly with distance. A lower steady-state oil saturation region was observed behind the hump. As the hump was produced from the core, high initial oil fractions were observed, as often seen in laboratory micellar floods. This is the result of the observed hysteresis in fractional flow behavior. A graphical method of predicting the occurrence of a hump, its rate of growth, and saturations within an oil/water bank was developed using the observed hysteresis in fractional flow. Using this prediction procedure, it was concluded that in a tertiary oil recovery process, oil breakthrough time or rate of advance of the oil/water bank, oil saturation at the leading edge, and initial produced oil fractions are only functions of the oil-saturation-increasing fractional flow curve and are not necessarily indications of oil recovery efficiency.

THE MOLECULAR MECHANISM FOR ACHIEVING ULTRA LOW INTERFACIAL TENSION MINIMUM IN A PETROLEUM SULFONATE/ OIL/ BRINE SYSTEM

ABSTRACT A unified theory is proposed to explain the ultra-low inter-facial tension minimum observed in dilute petroleum sulfonate solution/ oil systems encountered in tertiary oil recovery process. The relative distribution of the surfactant in oil and aqueous phase was determined using UV spectrophotometry as well as the monolayer technique. The critical micelle concentration ( CMC) of the aqueous phase equilibrated with oil was measured using surface tension, osmotic pressure and light scattering measurements. For three major variables namely, the surfactant concentration, the chain length of oil and the salinity of brine, the interfacial tension minimum was found to occur whenever the equilibrated aqueous phase was at CMC. This minimum in interfacial tension also coincided with partition coefficient of unity for surfactant distribution in oil and brine. The increase of the interfacial tension after reaching a minimum was attributed to the decrease in the onomer concentration in the aqueous phase. Three possible causes of the decrease in monomer concentration are (1) he incorporation of oil soluble fraction into mixed micelles in the aqueous phase, or (2) the decrease of the effective CMC in the equilibrated aqueous phase due to solubilization of oil or (3) the transfer of surfactant from aqueous to oil phase upon increasing the salinity. The decrease in surface concentration of surfactant at the oil-brine interface after the interfacial tension minimum is reached was confirmed by the electrophoretic mobility measurements The six major experimental findings related to the behavior of dilute petroleum sulfonate solutions are as follows: 1) the ultra-low Interfacial tension minimum occurs at the CMC of the equilibrated aqueous phase; 2) the partition coefficient is near unity at CMC; 3) the effective CMC for concentrations above the IFT minimum decreases with an increase in petroleum sulfonate concentration due to mixed micelle formation in the aqueous phase 4 ) the effective CMC decreases as the chain-length of dissolved oil increases; 5) the partitioning of the surfactant in the oil phase increases as the salinity increases and 6) the partitioning of the surfactant in the oil phase decreases as the chain-length of oil increases. It was established experimentally that the necessary condition for achieving an ultra-low interfacial tension minimum in dilute petroleum sulfonate solution/oil systems is that the CMC of the surfactant in the aqueous phase must condition, with partition coefficient of near unity. Under this condition, the concentration of surfactant monomers is maximum in brine and oil leading to maximum surfactant concentration at the interface.

Observations on the Coalescence Behavior of Oil Droplets and Emulsion Stability in Enhanced Oil Recovery

Original manuscript received in Society of Petroleum Engineers office Sept. 20, 1977. Paper accepted for publication June 2, 1978. Revised manuscript received Aug. 2, 1978. Paper (SPE 6846) was presented at SPE-AIME 52nd Annual Fall Technical Conference and Exhibition, held in Denver, Oct. 9-12, 1977. Abstract Results of experiments on the coalescence of crude oil drops at an oil-water interface and interdroplet coalescence in crude oil-water emulsions containing petroleum sulfonates and cosurfactant as surfactant systems with other chemical additives were analyzed in terms of interracial viscosity, interfacial tension, interfacial charge, and thickness of the films surrounding the microdroplets. A qualitative correlation was found between coalescence rates and interfacial viscosities; however, there appears to be no direct correlation with interfacial tension. New insight has been gained into the influence of emulsion stability in tertiary oil recovery by surfactant/polymer flooding in laboratory core tests. We concluded that those systems that result in relatively stable emulsions yield poor coalescence rates and, hence, poor oil recovery, Introduction The ability of the surfactant/polymer system to initiate and to propagate an oil bank is the single most important feature of a successful tertiary oil-recovery process. The mechanisms of oil-bank formation and development are yet unknown. It has been suggested that without the initiation of the oil bank, the process behaves more like the unstable injection of a surfactant solution alone, where the oil is produced by entrainment or emulsification in the flowing surfactant stream. In a laboratory study of the initial displacement of residual hydrocarbons by aqueous surfactant solutions, Childress and Schechter and Wade observed that those systems that spontaneously emulsified and coalesced rapidly yielded better oil recovery than those systems that spontaneously formed stable emulsions. Recently, Strange and Talash, Whitley and Ware, and Widmeyer et al. reported results of Salem (IL) low-tension, water-flood tests that used Witco TRS 10-80 TM petroleum sulfonate surfactant solution. They found stable oil-in-water emulsions at the observer well in addition to emulsion problems at the production well and reported that problems at the production well and reported that actual oil recovery was about one-quarter the target value. These studies clearly suggested that poor efficiency of oil recovery results from emulsion stability problems in the low-tension surfactant or micellar processes. Vinatieri presented results of experiments on the stability of crude-oil-in-water emulsions that coo be produced during a surfactant or micellar flood. More recently, we have assessed the rigidity of interfacial films and its relationship to coalescence rate through measurements of interfacial viscosities of crude oils contacted against aqueous solutions containing various concentrations of surfactants and other pertinent chemical additives. Our data clearly indicate that in the absence of a commercial surfactant, interfacial viscosity builds up rapidly, coalescence is inhibited, and the resulting emulsion is quite stable. These phenomena also have been observed by Gladden and Neustadter. Several studies were conducted on the structure of film-forming material at the crude oil/water interface, its effect on emulsion stability, and the role of such films in oil recovery by water or caustic solution displacements. Rigid films were found to reduce the amount of oil recovered. Our studies also have shown that the addition of a commercial surfactant lowered both the interfacial viscosity (ISV) and interfacial tension (IFT) of the crude oil-aqueous solution system. However, the concentration at which both the IFT and ISV are minimized cannot be identified by measuring IFT alone. We have conducted a cinephotomicrographic examination of spontaneous emulsification and a microvisual study of the displacement of residual crude oil by aqueous surfactant solutions in micromodel porous media. SPEJ P. 409

Ion-Exchange Conditioning of Sandstones for Chemical Flooding

The ionic hardness of reservoir brines and clays can be destructive in some of the newer chemical flooding processes. Such aggressive conditions were treated in laboratory studies by preflushing with soft brines to displace the offending ions. Results for some cases show that successful preflushing requires large volumes of low- or moderate-salinity brine, whereas smaller volumes of more saline brines may be adequate. Introduction One current obstacle to the widespread use of certain tertiary oil recovery processes is the reservoir ionic environment that injected fluids must withstand. Those processes based on micellar fluids containing substantial processes based on micellar fluids containing substantial quantities of anionic surfactants (such as petroleum sulfonates) may be particularly vulnerable to the effects of high salinity or moderately high multivalent-cation concentration. Even when acceptable chemical formulations exist for specific ionic conditions, oil displacement efficiency may suffer if the reservoir brine composition is not reasonably constant throughout the reservoir. Reservoir conditioning is attempted primarily for these reasons. By injecting a brine of the desired composition ahead of a slug of micellar solution, the most favorable circumstances for effective performance of the chemicals may be established. This study examines the efficiency of preflushing in situations where ion-exchange phenomena are important. In particular, the replacement of divalent cations (such as calcium and magnesium) by less offensive monovalent cations (such as sodium) was studied. The effects of soluble minerals like gypsum or anhydrite were not considered; their behavior can be described adequately by relatively straightforward solubility relationships. Also, the use of chemicals in the preflush brine to react with divalent cations by precipitation or complex ion formation was not examined. It is hoped that this study can be used to determine whether such chemical treatments are needed. Basic Considerations Ion exchange is a process in which an ion bound to a surface is replaced by another ion of like electrical charge from a surrounding solution. In the simplest exchange cases, the total ionic charge on the surface does not change, nor does the bulk concentration of ionic charges in solution. Thus, even though the solution chemical composition may change, salinity will not change when defined as total equivalents of cations per unit volume (as done in this paper). Among the usual components of sandstone petroleum reservoirs, clay minerals are well known for their ion exchange properties. The cation exchange capacities (CEC) vary from about 10 meq (milliequivalents)/ 100 gm of kaolinite to about 100 meq/100 gm of montmorillonite. Other sandstone materials reported to possess ion-exchange properties are quartz, feldspars, and organic matter. The exchange capacities of quartz and feldspars are usually quite low, but the capacity of solid organic matter may be as high as 150 to 500 meq/100 gm. The major factors that appear to influence cation exchange and, thus, preflush efficiency are cation exchange capacity, brine composition, shape of exchange isotherm, and brine salinity. Fig. 1 shows two hypothetical exchange isotherms of an ion-exchanging substance in contact with a solution containing two cationic species. These curves represent the quantity of one species adsorbed on the ion exchanger as a function of its relative concentration in solution. JPT p. 959