Injection Of Surfactant Solution Research Articles

Overview: EOR/IOR (January 2008)

Overview Currently available primary- and secondary-oil-production technologies leave behind two-thirds of the oil in place as stranded oil. However, many analysis and field projects have shown that significant oil-recovery increases are possible with improved/enhanced oil recovery (EOR) by gas injection, thermal recovery, or chemical injection. The first two methods have proved cost-effective even at low oil prices. Current oil prices have created renewed interest in more-costly chemical-based EOR methods such as gel treatment, foam flooding, polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline flooding. This year, we focus on chemical-based EOR methods. Chemical-EOR methods focus on improving the sweep efficiency by correcting reservoir heterogeneity or controlling fluid mobility, or they focus on increasing displacement efficiency by reducing residual-oil saturation. Gel treatment usually is intended to improve sweep efficiency and to reduce excess water production in channeled or fracture-dominated mature reservoirs. A newer trend in gel treatment is to apply preformed gels for in-depth treatments. These gels have been reported to penetrate deeply into superhigh-permeability streaks or fractures and seal or partially seal them off, thus creating high flow resistance in formerly watered-out, high-permeability zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water. Foam flooding often is used to reduce gas mobility and to correct reservoir heterogeneity and increase sweep efficiency for gasflooding. Foam can be injected into the reservoir by coinjection of gas and surfactant solution or by injection of surfactant solution alternating with gas (SAG). Foam stability, surfactant-adsorption reduction, and optimized SAG-process design are the keys to controlling the economics of foam flooding. Polymer flooding is designed to control mobility for waterflooding. High-molecular-weight and new high-temperature salt-resistant polymers have made polymer flooding more economical. Adding either an alkaline or surfactant chemical, or both, in a polymer flood will scour residual oil from the rock, resulting in higher oil recovery than with polymer flooding alone. However, the scale problem associated with alkaline limits the use of ASP flooding. Wettability is of major importance to oil recovery, especially for fractured oil-wet carbonate reservoirs where water flows through the fractures but does not imbibe into the matrix because of negative capillary pressure. The chief concern is to develop cost-effective chemical formulations that change the carbonate wettability from oil-wet to water-wet. EOR/IOR additional reading available at the SPE eLibrary: www.spe.org SPE 107095 "Field-Scale Wettability Modification—The Limitations of Diffusive Surfactant Transport" by W.M. Stoll, SPE, Shell International E&P, et al. SPE 107776 "Improved ASP Design Using Organic-Compound/Surfactant/Polymer for La Salina Field, Maracaibo Lake" by E. Guerra, PDVSA Intevep, et al. SPE 107727 "Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario" by Ivonete P. Gonzalez da Silva, Petrobras, et al. SPE 106901 "SAGD Optimization With Air Injection" by J.D.M. Belgrave, EnCana Corporation, et al.

Parametric analysis of surfactant-aided imbibition in fractured carbonates

Many carbonate oil reservoirs are oil-wet and fractured; waterflood recovery is very low. Dilute surfactant solution injection into the fractures can improve oil production from the matrix by altering the wettability of the rock to a water-wetting state. A 2D, two-phase, multicomponent, finite-volume, fully-implicit numerical simulator calibrated with our laboratory results is used to assess the sensitivity of the process to wettability alteration, IFT reduction, oil viscosity, surfactant diffusivity, matrix block dimensions, and permeability heterogeneity. Capillarity drives the oil production at the early stage, but gravity is the major driving force afterwards. Surfactants which alter the wettability to a water-wet regime give higher recovery rates for higher IFT systems. Surfactants which cannot alter wettability give higher recovery for lower IFT systems. As the wettability alteration increases the rate of oil recovery increases. Recovery rate decreases with permeability significantly for a low tension system, but only mildly for high tension systems. Increasing the block dimensions and increasing oil viscosity decreases the rate of oil recovery and is in accordance with the scaling group for a gravity driven process. Heterogeneous layers in a porous medium can increase or decrease the rate of oil recovery depending on the permeability and the aspect ratio of the matrix block.

Carbon Dioxide Foam Rheology in Porous Media: A CT Scan Study

Summary Carbon dioxide (CO2) foam has been widely studied in connection with its application in enhanced oil recovery (EOR). This paper reports an experimental study concerning CO2 foam propagation in a surfactant-saturated Bentheim sandstone core and the subsequent liquid injection with the aid of X-ray computed tomography (CT). The experiments were carried out under various system backpressures. It is found that CO2 foam flows in a characteristic front-like manner in the transient stage and that the water saturation keeps at relatively high level at the outlet of the porous media because of CO2 solubility and capillary end effect. The subsequent surfactant solution injection shows a significant fingering behavior, accompanied by a low flow resistance over the core. It is also found that CO2 foam flow shows higher liquid saturation near the outlet and lower pressure drops under higher system backpressures. This can be attributed to the solubility of CO2 in the liquid phase. The results indicate the advantage of using foam in EOR processes such as water alternating foam (WAF), in which foam flow has higher sweep efficiency and stronger mobility control ability compared, for instance, to water alternating gas (WAG). Nevertheless, care should be taken during the water-injection stage in order not to favor the fingering.

Novel operational method of continuous foam separation of gold – Injection of metal and/or surfactant solutions into rising foam bed

A novel operational method of continuous foam separation, in which metal and/or surfactant solutions were injected into the rising foam bed, has been applied to the Au(III) recovery from binary metal solutions with Cu(II). The effects of experimental parameters, such as an air flow rate, metal concentration and solution acidity, were discussed in terms of the percent recovery and the separation factor of Au(III). A nonionic surfactant, polyoxyethylene nonyl phenyl ether, used in this study showed a strong affinity to Au(III) in HCl media and played a double role of foam-producing and metal collecting reagent. By injecting a metal solution to the foam bed, the recovery of Au(III) was improved due to the efficient contact between the metal and the foam surface counter-currently. On the other hand, injection of a surfactant solution facilitated the washing-out of the metals in the interstitial water between the adjacent foam, enhancing the separation of Au(III) from Cu(II). Furthermore, simultaneous injection of metal and surfactant solutions to the foam bed was also examined, and satisfactory results were obtained both in the yield and purity of Au(III).

Visualization of TCE recovery mechanisms using surfactant–polymer solutions in a two-dimensional heterogeneous sand model

This research focused on the optimization of TCE dissolution in a physical two-dimensional model providing a realistic representation of a heterogeneous granular aquifer. TCE was infiltrated in the sand pack where it resided both in pools and in zones of residual saturation. Surfactant was initially injected at low concentration to minimize TCE remobilization at first contact but was incrementally increased later during the experiment. Xanthan gum was added to the injected surfactant solution to optimize the sweep efficiency through the heterogeneous medium. Photographs and digital image analysis illustrated the interactions between TCE and the injected fluids. During the polymer flood, the effects of heterogeneities inside the sand pack were greatly reduced by the increased fluid viscosity and the shear-thinning effects of the polymer. The polymer also improved the contact between the TCE ganglia and the surfactant–polymer solution, thereby promoting dissolution. Surfactants interacted with the polymer reducing the overall viscosity of the solution. At first contact with a 0.5% mass surfactant solution, the TCE pools drained and some remobilization occurred. However, no TCE bank was formed and TCE did not penetrate into any previously uncontaminated areas. As a result, TCE surface area was increased. Subsequent surfactant floods at higher surfactant concentrations did not trigger more remobilization. TCE was mainly dissolved by the solution with the highest surfactant concentration. Plugging from bacterial growth or microgel formation associated to the polymer at the inflow screen prevented the full completion of the experiment. However, more than 90% of TCE was recovered with the circulation of less than 6 pore volumes of surfactant–polymer solution.

A laboratory feasibility study of dilute surfactant injection for the Yibal field, Oman

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding. The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations. The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

PIC, Dow plan ethylene complex in Kuwait

The Yibal field, the largest oil field in Oman, comprises 15% of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of a dilute surfactant in addition to the current waterflooding.The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning. Nineteen samples were waterflooded followed by dilute surfactant injection. Eight samples were flooded with dilute surfactant. The reason for this scheme is that some parts of the reservoir under study were totally watered out while others are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were conducted to treat fractured zones where recovery by capillary imbibition during injection is a possibility. Twelve different surfactants (at different concentrations) were tested. Five surfactants were non-ionic, two cationic, four anionic, and one was a mixture of anionic and non-ionic. The selection of the optimum concentrations was based on IFT values at different concentrations.The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1% of OOIP (out of 19 experiments) whereas surfactant injection yielded an average of 69.9% of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding was obtained and found to vary between 0% and 7.4% of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is more effective to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.

Conductivity reduction due to emulsification during surfactant enhanced-aquifer remediation. 2. Formation of emulsion in situ.

Permeability reduction due to surfactant emulsification can impact the effectiveness of surfactant-enhanced aquifer remediation (SEAR). The objective of this study was to examine the process of in situ emulsification in systems composed of tetrachloroethylene (PCE) and solutions of two nonionic surfactants selected for their ability to enhance solubility. The injection of the surfactant solutions into columns packed with sand-sized silica particles containing residual saturations of PCE resulted in the formation of an emulsion with an average droplet diameter of 0.1-0.2 microm, about an order of magnitude smaller than that of the ex situ formed emulsion. The measurements of hydraulic conductivity showed an initial decrease, followed by a gradual increase, with a final steady-state reduction of about 35% after the injection of 7-8 pore volumes of surfactant solution, of which about 8% could be attributed to the deposition of the emulsion. To describe the observed trends, the modified emulsion transport model from Part 1 was modified to include the processes of the formation of the emulsion and the reduction of the PCE residual. The good comparison between the simulations and the experimental data suggests that the model correctly reflects the multiple processes controlling the hydraulic conductivity of the packed columns during surfactant solution injection.

The effects of surfactant formulation on nonequilibrium NAPL solubilization

Surfactant-enhanced aquifer remediation (SEAR) involves the injection of surfactant solutions into aquifers contaminated with nonaqueous phase liquids (NAPL). Batch and column experiments were used to assess the effect of surfactant formulation on the rate of NAPL solubilization. The experimental variables were surfactant type, surfactant concentration, electrolyte concentration, and cosolvent concentration. Model equations were proposed and solved to describe solubilization under the conditions of each type of experiment. Using these models, a solubilization rate constant, k b, and an overall mass transfer rate coefficient, k, were estimated from the batch and column experiments, respectively. The solubilization rate constant was consistently sensitive to surfactant type, surfactant concentration, and electrolyte concentration. The estimated solubilization rate constants varied over two orders of magnitude. The results of the column experiments also were sensitive to the surfactant formulation. Variations in the fitted mass transfer rate coefficient parameter, β 0, were related to variations in the surfactant formulations. A comparison between the results of the batch and column experiments yields an apparent relationship between β 0 and k b. This relationship suggests that the mass transfer rate coefficient is directly related to the formulation of the surfactant solution.

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Abstract An in-depth analysis covering over forty foam applications in Enhanced Oil Recovery (EOR) projects and numerous production well treatment operations was conducted, to obtain insights on screening and design of such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; proper identification of the cause, as well as of the affected production well(s) is basic to definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam is placed in production wells mainly to mitigate an override problem. The most important factors in foam assisted EOR projects are:manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam),reservoir pressure andpermeability. While pre-formed foams are effective in the treatment of production wells, co-injection foam and SAG foam can be employed for solving specific sweep problems. For designing a steam-foam project (which is a low pressure foam application), foam quality in the range 45% to 80% should be considered. In this application, a co-injection foam is employed and the additives (surfactant and non-condensable gas) are injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days are common. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with this implementation. At high pressure, such as in gas miscible flooding, foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, in these projects, alternate injection of surfactant solution and gas (SAG foam) is favoured over a coinjection mode of placement. Introduction The first review of field applications of EOR foams was published in 19891, and it was not until 1994–1995 that more advanced EOR foam Reviews(2, 3, 4)appeared in the public domain. Building on the previous reviews, more than 40 foam field tests are analyzed here. Unlike the previous reviews, our focus was on the reservoir engineering aspects of foam application, mainly on the mode of foam placement with respect to the problem to be solved. Other differences from the previous reviews include:For the various field tests presented, all available details are tabulated to enable an easy analysis of the data.A reservoir engineering analysis is conducted for the basic recovery process during which foam injection was implemented, in order to establish "a-posteriori", the nature of problem solved.Interpretation of results of field foam applications is based on the results of recent laboratory foam tests on long distance foam propagation In this paper only the key conclusions of our analysis are presented; 19 tables containing the supporting details accompany this paper, and they can be made available by the Journal of Canadian Petroleum Technology, upon request.

An Optimized Surfactant Formulation for the Remediation of Diesel Oil Polluted Sandy Aquifers

Reduction of hydraulic conductivity during the treatment of hydrocarbon polluted soils by using surfactants may be an inconvenience for a good recovery of the pollutant. The purpose of the present research work is to determine the main factor responsible for this reduction and by the same way to give an application solution to this problem. Experimental studies on sand filled laboratory columns have shown that the reduction of hydraulic conductivity can be due neither to the precipitation of the anionic surfactants in the presence of calcium ions nor to the clay minerals present in small proportion in the porous medium. We point out that this phenomenon is essentially due to the agglomeration of micelles and show that addition of 4 wt % of butyl alcohol under specific conditions contributes to improving both the injectability of the surfactant solution and the efficiency of the treatment. The optimized surfactant formulation, containing a mixture of two commercial surfactants and this cosolvent, palliates the reduction of hydraulic conductivity and decreases the interfacial tension by a factor of 100. As a consequence, after three pore volumes of injected surfactant solution, 85% of the trapped oil is removed compared to 11.4% obtained without cosolvent.

Surfactant Remediation Field Demonstration Using a Vertical Circulation Well

AbstractA field demonstration of surfactant‐enhanced solubilization was completed in a shallow unconfined aquifer located at a Coast Guard Station in Traverse City, Michigan. The primary objectives of the study were: (1) to assess the ability of the vertical circulation well (VCW) system for controlling chemical extractants added to the subsurface; and (2) to assess the behavior of the surfactant solution in the subsurface, with a goal of maximum surfactant recovery. A secondary objective was to demonstrate enhanced removal of PCE and recalcitrant components of a jet fuel. The analytical results showed that the surfactant increased the contaminant mass extracted by 40–fold and 90–fold for the PCE and jet fuel constituents, respectively. The surfactant solution demonstrated minimal sorption (retardation) and did not precipitate in the subsurface formation. In addition, the VCW system was able to capture in excess of 95% of the injected surfactant solution. Additional field testing and full‐scale implementation of surfactant‐enhanced subsurface remediation should be performed.

Boundary Condition and Soil Attribute Impacts on Anionic Surfactant Mobility in Unsaturated Soil

AbstractSurfactant mobility in unsaturated soil will impact the effectiveness and efficiency of using these compounds for in situ environmental remediation above the water table. For this reason, transient unsaturated column tests were used to study the influence of boundary conditions and soil attributes on anionic surfactant transport. In these tests, aqueous surfactant solutions were injected into the inlet of horizontally mounted soil columns. Two commercial anionic surfactants were used, an alkyl ether sulfate (AES) and a linear alkylbenzene sulfonate (LAS).The overall study was divided into two parts. First, boundary condition effects including injected surfactant solution concentration, initial moisture content, and surfactant application rate were investigated. Increasing the injection solution concentration increased anionic surfactant mobility in the column while changes in the initial soil moisture content and surfactant application rate had no significant impact. Second, the impacts of soil attributes such as texture, dominant exchangeable cation, and resident organic matter were measured. With respect to texture, mobility was found to be greater in a sandy soil as compared with two loamy soils. Both surfactants, especially LAS, were found to be more mobile in a Na+ dominated soil rather than one dominated by Ca−2.The absence of soil organic matter increased LAS mobility.

A Model System to Study the Precipitation and Migration of Colloidal Particles in Porous Media

Studies on the formation and migration of colloidal iron sulfide in porous media were carried out using consolidated artificial alumina–kaolin cores sintered at 1500°C. The artificial alumina–kaolin cores were imbibed with a solution containing thioacetamide and ferrous ions and heated at 80°C to obtain the formation of FeS particles. Scanning electron micrographs showed particles less than 1 μm in diameter and aggregates of different sizes covering the surface of the porous media. Core flooding experiments showed that the migration of the fine FeS particles reduced the permeability of core and the injection of surfactant solutions at constant salinity restored the original permeability after the production of the redispersed iron sulfide particles, in some cases.

Optimal Injection Strategies for the Propagation of Surfactant Mixtures Through Porous Media

Abstract The chromatographic movement of surfactant mixtures through porous media is examined to determine possible injection strategies for minimizing the amount of surfactant required in a tertiary oil recovery chemical flood. The model used does not consider the presence of oil but does account for mixed micelle formation. Expressions are derived that represent the surfactant required to expose an entire reservoir to an "effective oil recovery mixture." This effective mixture may be either one whose overall composition is within prescribed limits of the composition of the injected surfactant solution or it may be a mixture whose overall composition varies but which contains micelles of fixed composition. Mixtures considered contain cosolvents and one, two, or three surfactant components. Initial calculations neglect dispersion, but numerical calculations including dispersion leave the conclusion unchanged; within the limitations of the model, there are optimal strategies for the propagation of surfactant mixtures through porous media. The optimal injection strategy varies, depending on the nature of the surfactant solution injected into the porous medium. Conditions for and the location of the optimum are discussed. Conclusions based on observations about these systems then are extended to cover the injection of surfactant mixtures currently available commercially.