Experimental study on the performance of emulsions produced during ASP flooding

ASP (Alkaline/Surfactant/Polymer) flooding is one of the most promising techniques that has proven to have successful application in several laboratory and pilot tests. However, the formation of persistent and stable emulsions is one of the associated problems with ASP flooding. The present work investigated the effect of sodium carbonate alkaline, Alpha Olefin Sulfonate (AOS) surfactant, and GLP100 polymer on produced crude oil emulsion. The study was conducted by measuring the emulsion stability in terms of water separation and rag layer volume using a TurbiScan analyzer, the dispersed droplet size using cross-polarization microscopy, the interfacial tension using spinning drop tensiometer, and rheological properties using rheometer. The experimental results have shown that AOS presence increased the emulsion stability only when its concentration is above 100 ppm. Meanwhile, below 100 ppm, the presence of AOS promoted water separation and reduced the rag layer volume. In a less significant manner, a high concentration of sodium carbonate alkali increased the stability of the emulsion. The use of GLP100 Polymer has shown substantial ability in promoting water separation and reducing the rag layer volume to a minimal level. It is believed that the outcomes of this work will aid in developing a suitable destabilization process to enhance the oil–water separation and produced water treatment from ASP flooding in the oil production fields. Further investigations on AS, AP, SP as well as the ASP's combined effect on emulsion stability, droplet size, interfacial tension and rheological properties are highly recommended to support the decision-makers on the EOR implementations with chemical additives.

A Review on the Use of Chemicals as Steam Additives for Thermal Oil Recovery Applications

This study conducts a literature survey on the chemical steam additives tested in both lab and field settings from 1982 to present (2020). We summarize the major recovery mechanisms of both steam-based recovery process and steam-chemical-based recovery process. Next, we review the previous lab-scale/field-scale studies examining the applications of surfactants, alkali, and novel chemicals in the steam-based oil recovery process. Among the different surfactants studied, alpha-olefin sulfonate (AOS) and linear toluene sulfonate (LTS) are the recommended chemicals for their foam control/detergency effect. In particular, AOS was observed to perform especially well in residual oil saturation (ROS) reduction and sweep efficiency improvement when being co-injected with alkali. Application of organic alkali (alone or with a co-surfactant) has also drawn wide attention recently, but its efficacy in the field requires further investigation and the consumption of alkali by sands/clay is often an inevitable issue and, therefore, how to control the alkali loss requires further investigation. Novel chemical additives tested in the past five years include fatty acids (such as tail oil acid, TOA-Na+), Biodiesel (o/w emulsion), along with other types of chemical additives including switchable hydrophilicity tertiary amines (SHTA), chelating agents, Deep Eutectic Solvents (DES), graphite and SiO2 particles, ionic liquids and urea. High thermal stability of some of the novel chemicals and their potential in increasing displacement efficiency and ROS reduction efficiency in the lab studies require further investigation for their optimized application in the field settings to minimize the use of steam while improving the recovery effectively. This review reveals that when being properly applied, chemical additives can improve oil recovery via steam foam control, detergency effect (IFT reduction and wettability control), and viscosity reduction. In certain cases, microemulsion generation could be observed (o/w or w/o) with the addition of chemical additives at steam condition (which leads to recovery improvement), but the microemulsion effect on the conformance control (separate from the foamy effect), is lacking detailed investigation.

High-temperature high-pressure microfluidic system for rapid screening of supercritical CO2 foaming agents

CO2 foam helps to increase the viscosity of CO2 flood fluid and thus improve the process efficiency of the anthropogenic greenhouse gas’s subsurface utilization and sequestration. Successful CO2 foam formation mandates the development of high-performance chemicals at close to reservoir conditions, which in turn requires extensive laboratory tests and evaluations. This work demonstrates the utilization of a microfluidic reservoir analogue for rapid evaluation and screening of commercial surfactants (i.e., Cocamidopropyl Hydroxysultaine, Lauramidopropyl Betaine, Tallow Amine Ethoxylate, N,N,N′ Trimethyl-N′-Tallow-1,3-diaminopropane, and Sodium Alpha Olefin Sulfonate) based on their performance to produce supercritical CO2 foam at high salinity, temperature, and pressure conditions. The microfluidic analogue was designed to represent the pore sizes of the geologic reservoir rock and to operate at 100 °C and 13.8 MPa. Values of the pressure drop across the microfluidic analogue during flow of the CO2 foam through its pore network was used to evaluate the strength of the generated foam and utilized only milliliters of liquid. The transparent microfluidic pore network allows in-situ quantitative visualization of CO2 foam to calculate its half-life under static conditions while observing if there is any damage to the pore network due to precipitation and blockage. The microfluidic mobility reduction results agree with those of foam loop rheometer measurements, however, the microfluidic approach provided more accurate foam stability data to differentiate the foaming agent as compared with conventional balk testing. The results obtained here supports the utility of microfluidic systems for rapid screening of chemicals for carbon sequestration or enhanced oil recovery operations.

Characterization of lauryl betaine foam in the Hele-Shaw cell at high foam qualities (80%–98%)

Lauryl betaine (LB) as an amphoteric surfactant carries both positive and negative charges and should be able to generate stable foam through electrostatic interaction with nanoparticles and co-surfactants. However, no previous attempts have been made to investigate the influence of nanoparticles and other co-surfactants on the stability and apparent viscosity of LB-stabilized foam. In this study, a thorough investigation on the influence of silicon dioxide (SiO2) nanoparticles, alpha olefin sulfonate (AOS) and sodium dodecyl sulfate (SDS), on foam stability and apparent viscosity was carried out. The experiments were conducted with the 2D Hele-Shaw cell at high foam qualities (80%–98%). Influence of AOS on the interaction between the LB foam and oil was also investigated. Results showed that the SiO2-LB foam apparent viscosity decreased with increasing surfactant concentration from 0.1 wt% to 0.3 wt%. 0.1 wt% SiO2 was the optimum concentration and increased the 0.1 wt% LB foam stability by 108.65% at 96% foam quality. In the presence of co-surfactants, the most stable foam, with the highest apparent viscosity, was generated by AOS/LB solution at a ratio of 9:1. The emulsified crude oil did not imbibe into AOS-LB foam lamellae. Instead, oil was redirected into the plateau borders where the accumulated oil drops delayed the rate of film thinning, bubble coalescence and coarsening.

Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

Investigation of Countercurrent Imbibition in Oil-Wet Tight Cores Using NMR Technology

Summary Countercurrent spontaneous imbibition is one of the most significant mechanisms for the mass transfer between fractures and matrixes in tight reservoirs. Adding surfactants and pressurization are two common methods to enhance the imbibition. In this study, we used the low-field nuclear magnetic resonance (NMR) instrument to monitor the dynamic imbibition processes with surfactants added and fluid pressure applied. The T2 relaxation distribution and corresponding water saturation profiles during the imbibition process were obtained by analyzing NMR responses. We found that sodium alpha-olefin sulfonate (AOS) could improve the oil recoveries of laboratory-scale cores to 22.31 and 29.59% with different concentrations (0.1 and 0.5 wt%). The surfactant addition not only expands the imbibition area, but also reduces the residual oil saturation in the imbibition profile. However, the actual maximum imbibition distances are only approximately a centimeter long (0.9412 and 1.1372 cm), which is insignificant for field scale. Due to the minimal imbibition distance, high-quality hydraulic fracturing is required to generate a large number of fractures for imbibition to ensure considerable oil recovery at the field scale. In addition, surfactant is consumed during spontaneous imbibition of oil-wet rocks and increasing surfactant concentration facilitates the imbibition process. However, arbitrarily increasing the concentration does not achieve the expected oil recovery because of the high adsorption capacity resulting from the high concentration. We need to consider economic efficiency to optimize a reasonable surfactant concentration. It was found that traditional dimensionless scaling models are not applicable in the complicated surfactant-enhanced imbibition. Hence, we proposed a new scaling group for scaling laboratory date to the field in fractured oil-wet formations. Moreover, we compared the imbibition process under different pressure conditions (7.5 and 15 MPa) and found that the effect of fluid pressure on countercurrent imbibition is not obvious.

Laboratory Analysis of Foam Generating Surfactants and Their Thermal Stability for Enhanced Oil Recovery Application

The residual oil after primary or secondary oil recovery can be recovered by the methods of EOR (Enhanced Oil Recovery). The objective of this study is screening the surfactants that generate maximum stable foam in the presence of brine salinity at 92oC. Laboratory experiments have been performed to examine and compare the stability of generated foam by individual and blended surfactants in the synthetic brine water. AOS C14-16 (Alpha Olefin Sulfonate) and SDS (Sodium Dodecyl Sulfonate) were selected as main surfactants. Aqueous stability test of AOS C14-16 and SDS with brine water salinity 62070ppm was performed at 92oC. AAS (Alcohol Alkoxy Sulfate) was blended with SDS and AOS C14-16. The solution was stable in the presence of brine salinity at same conditions. Salt tolerance experimental study revealed that AOS C14-16 did not produce precipitates at 92oC. Further, the foam stability of surfactant blend was performed. Result shows that, the maximum life time of generated foam was observed by using blend of 0.2wt% SDS+0.2wt% AOS+0.2wt% AS-1246 and 0.2wt% AOS+0.2wt% IOSC15-18+0.2wt% AAS surfactants as compared to the foam generated by individual surfactants. The success of generated foam by these surfactant solutions in the presence of brine water is the primary screening of surfactant stability and foamability for EOR applications in reservoirs type of reservoirs.