Alkaline Surfactant Research Articles

Integration between experimental investigation and numerical simulation of alkaline surfactant foam flooding in carbonate reservoirs

In Brazil, pre-salt carbonate reservoirs are largely responsible for the current increase in oil production. However, due to its peculiar characteristics, increasing oil recovery by water injection is not enough. Therefore, we seek to evaluate the recovery potential using chemical methods (cEOR). Among these, the Alkali Surfactant Foam (ASF) method appears with high potential, a variant of Alkali Surfactant Polymers (ASP) without the problems presented by it. Therefore, this work presents an innovative methodology, which seeks to evaluate the potential for recovery with ASF in carbonate reservoirs by integrating experimental characterization and recovery prediction using reservoir simulation. For this, phase behavior and adsorption analyses were carried out. The experimental results provided key parameters for the simulation, such as optimal salinity, surfactant adsorption, foam mobility reduction factors. The results are from two case studies of AS and ASF flooding, using a section of UNISIM-II benchmark, using a one-quarter of five-spot model. Having the modelling for these cEOR methods defined, an optimization process for each method was applied, allowing a reliable comparison among the methods and over a base case of water injection, seeking the maximization of the net present value (NPV). As a result, in the experimental part, a low interfacial tension (IFT) value of 0.003 mN/m was achieved with a surfactant adsorption reduction of 17.9% for an optimal setting among brine (NaCl), alkali (NaBO2.4H2O), and surfactant (BIO-TERGE AS 40). In the reservoir simulation part, using a fast genetic algorithm in the optimization process, a NPV of US$ 14.43 million higher than the base case (water injection) and a 4.5% increase in cumulative oil production for the ASF injection case were obtained. Considering the analyses of production curves (cumulative oil production and oil rate) and oil saturation maps, a considerable oil production anticipation was observed, which was the main reason for NPV improvement, proving the high potential for application of the ASF method in carbonate reservoirs.

Research on Microbial Community Structure in Different Blocks of Alkaline–Surfactant–Polymer Flooding to Confirm Optimal Stage of Indigenous Microbial Flooding

The microbial communities associated with alkaline–surfactant–polymer (ASP)-flooded reservoirs have rarely been investigated. In this study, high-throughput sequencing was used to analyse the indigenous microbial communities in two different blocks, the water flooding after the alkaline–surfactant–polymer flooding block and the alkaline–surfactant–polymer flooding block, and to ascertain the optimal stage for the implementation of indigenous microbial oil recovery technology. The different displacement blocks had significant effects on the indigenous microbial community at the genus level according to an alpha diversity analysis and community composition. In water flooding after alkaline–surfactant–polymer flooding, the dominant genus of Pseudomonas exceeded 30%, increasing to 52.1% in alkaline–surfactant–polymer flooding, but alpha diversity decreased. Through a co-occurrence network analysis, it was found that the complexity of the water flooding after alkaline–surfactant–polymer flooding was higher than that of alkaline–surfactant–polymer flooding. This means that the water flooding ecosystem after alkaline–surfactant–polymer flooding was more stable and less susceptible to external environmental influences. In addition, there were significant differences in the functional redundancy of microbial communities in different blocks. In summary, the optimal stage for implementing local microbial oil recovery technology may be water flooding after alkaline–surfactant–polymer flooding.

Characterization of the Solution Properties of Sodium Dodecylsulphate Containing Alkaline–Surfactant–Polymer Flooding Media

Alkaline–surfactant–polymer (ASP) flooding by means of which alkali additives, surfactant and polymer are inserted as the same slug is one of the most favourable worldwide focuses of Chemical Enhanced Oil Recovery (cEOR) research and field trials, due to the individual synergy of the three chemical components. To develop efficient oil recovery chemicals, it is essential to fully understand the mechanism behind ASP flooding. Nonetheless, there are hardly any studies reporting a systematic characterization of the ASP process. Thus, the present paper focuses on modelling this process in a laboratory by the use of an anionic surfactant—sodium dodecyl sulphate (SDS) in alkaline–polymer media—which is composed of a commercial water-soluble polymer (Flopaam AN125SH®, SNF Floerger, Andrézieux-Bouthéon, France) and alkali compounds (NaOH and Na2CO3). The samples were characterized using rheometry, dynamic light scattering (DLS), infrared spectroscopy (IR) and measurement of inferfacial tension (IFT) between the samples and rapeseed oil. In accordance with the experimental results, surprisingly lower IFT values were recorded between the alkaline–polymer solutions and rapeseed oil than the samples which contained SDS. Increasing polymer and sodium chloride concentration caused a decrease (from 0.591 mN/m to 0.0486 mN/m) in IFT between the surfactant containing samples and rapeseed oil. The IR measurements confirmed that the surfactant was not detected in the oil phase in the absence of NaOH and Na2CO3. The effects of SDS on the viscosity of the mixtures were also investigated, as viscosity is a considerably important parameter in processes using polymers.

Research note: A scald water surfactant combined with an organic acid carcass dip reduces microbial contaminants on broiler carcasses during processing

Organic acids are applied to poultry carcasses during processing to reduce foodborne pathogens and spoilage microorganisms. Scald water surfactant agents employed to improve feather removal may enhance the efficacy of organic acids during processing. This study investigated the effects of concurrent application of a scald water surfactant and organic acid dip on microbial contamination of carcasses processed in a small-scale production model. Broilers were reared in litter floor pens to 47 d of age and slaughtered using standard practices. Carcasses were scalded in either control or surfactant scald water initially and dipped in either a 2% organic acid blend or water after feather removal to complete a 2 × 2 factorial arrangement with n = 15 carcasses per treatment group. The commercially available scald water additive was a slightly alkaline surfactant solution labelled as a feather removal aid. The organic acid dip consisting of lactic and citric acid was maintained at pH of 2.5. Approximately 10 g of neck skin was collected 1-min postdipping and placed in buffered peptone water with an added neutralizing agent, sodium thiosulfate. Serial dilutions were performed to determine general coliform (GC), E. coli (EC), and aerobic plate (APC) counts as CFU per gram of skin sample. A significant 0.61, 0.76, and 1.6 log reduction of GC, EC, and APC, respectively, was attributed to use of the organic acid carcass dip (P ≤ 0.01). There were no significant differences in carcass microbial reduction due to surfactant scald water alone. A 0.69, 0.73 (P ≤ 0.05), and 1.96 log reduction of GC, EC, and APC, respectively, was observed in surfactant-scalded, acid-dipped carcasses compared to water-scalded, water-dipped control groups. These data demonstrated that a surfactant scald water additive and an organic acid carcass dip can have beneficial effects of microbial reduction when employed simultaneously during broiler processing.

Numerical Investigation on Alkaline-Surfactant-Polymer Alternating CO2 Flooding

For over four decades, carbon dioxide (CO2) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO2 are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO2 would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs.

Enhanced Oil Recovery in the Field A123 by Using the Injection of Alkaline, Surfactant and Polymers

Abstract This paper is based on numerical simulations in order to improve the total oil production of field A123 by using an Alkaline-surfactant and polymer (ASP) injections method. The main objective of this paper is to carry out reservoir simulations job that will further permit to conclude if producing oil and gas in this field will be rentable or not. To achieve this objective, the computer Modelling Group software version 2015.10 (CMG 2015 software) is used to carry out the field numerical simulations. Based on the tests run, one injection well is selected and used as a main injector in order to execute the chemical injection schemes in the field. Four different scenarios are studied such as natural flow of oil as the base case (primary oil production), polymer flooding, alkaline-surfactant (AS) flooding and ASP flooding are considering in the injection process and important results from simulator are analyzed and interpreted. Sensitivity analyses are done especially focusing on chemical solution concentration, injection rate and duration of injection time. The results obtained shows an oil recovery factor (ORF) of 64.1554 for polymer flooding, 64.2026 for alkali-surfactant finally 64.8056 for the combined flooding (ASP flooding), respectively. Those results have a direct influence on reservoir pressure which changes after the injected fluids are introduced in the reservoir and therefore improve the production rate. By evaluating the feasibility of the project of polymer flooding combined to AS flooding considering oil prices fluctuations due to COVID 19, the net present value (NPV) is 873 484 102 USD which is the best for the field A123.

Enhanced Oil Recovery in the Field A123 by Using the Injection of Alkaline, Surfactant and Polymers

Abstract This paper is based on numerical simulations in order to improve the total oil production of field A123 by using an Alkaline-surfactant and polymer (ASP) injections method. Its main objective is to carry out reservoir simulations job, that will further permit to conclude if producing oil and gas in this field will be profitable or not. To achieve this objective, the Computer Modelling Group software version 2015.10 (CMG 2015 software) is used to carry out the field numerical simulations. Based on the tests run, one injection well is selected and used as a main injector in order to execute the chemical injection schemes in the field. Four different scenarios are studied such as natural flow of oil as the base case (primary oil production), polymer flooding, alkaline-surfactant (AS) flooding and ASP flooding are considering in the injection process and important results from simulator are analyzed and interpreted. Sensitivity analyses are done especially focusing on chemical solution concentration, injection rate and duration of injection time. The results obtained shows the base case simulations shows that, the reservoir produce oil naturally for 26 years for a quantity of 3,749,204.82 bbl and 864,412,318 SCF of gas. With the most significant case in the third scenario, the coupled effect of ASP optimize the quantities to 32,364,440.2 bbl for oil and 7,459,728,710 scf of gas produce. Also the oil recovery factor (ORF) is 64.1554% for polymer flooding, 64.2026% for alkali-surfactant and 64.8056% for the combined ASP flooding, respectively. These results have a direct impact on reservoir pressure which changes after the injected fluids are introduced in the reservoir and therefore improve the production rate. Thus, the feasibility of the project of polymer flooding combined to AS flooding, is up to 873,484,102 USD for the field A123.

Mechanistic investigation of using low salinity alkaline surfactant solutions in carbonate reservoirs based on polarity of crude oil

The chemical enhanced oil recovery (CEOR) process is introduced as one of the most effective methods for reducing the residual oil saturation through oil reservoirs. Because the chemical phase has a great potential for altering the reservoir rock and fluids properties. The main purpose of this study is a combination of low saline water (LSW) with surfactant and alkaline-surfactant to achieve maximum oil recovery by the combination of different mechanisms. In this work, the fluid–fluid and rock-fluid interactions were investigated by conducting several experimental techniques for two varied crude oil samples. Due to the high polarity of resin and asphaltene molecules, these two crude oil samples were divided into low-polar and high-polar samples. The optimum diluted seawater was used as LSW for both crude oil samples at 3000 ppm total dissolved solids. Based on obtained results from the interfacial tension (IFT) measurement tests and dynamic contact angle, using NaOH with LSW and AOS at critical micelle concentration (CMC) has a greater influence on reducing the IFT and altering the carbonate rock wettability from oil-wet to water-wet condition compared to Na2CO3. Adding only 100 ppm NaOH to the LSW-AOS(CMC) solution, the IFT values between an alkali-surfactant solution with low-polar and high polar crude samples were decreased from 0.43 and 1.33 mN/m to 0.21 and 0.55 mN/m, respectively. Moreover, the pH of LSW-AOS solution rises with the addition of NaOH to the solution and the surface charge moves toward a more negative charge based on the zeta potential results. This phenomenon increases the repulsion between surface charge and negatively charged polar components and, consequently desorption of polar components from the rock surface get improved. Furthermore, some in-situ surfactant (soap) generates by a reaction between NaOH and carboxylic acids and the creation of an ion pair between surfactants (AOS and Soap) and adsorbed polar groups which lead to the creation of a hybrid mechanism between LSW, AOS, and NaOH for changing the wettability from oil-wetness toward water-wetness. Therefore, the maximum oil recovery was achieved by flooding with LSW- AOS(1000 ppm)-NaOH (100 ppm) solution for both crude oil samples, high polar and low polar cured oil samples, that obtain 42.24 % and 71.67% recovery factors, respectively. Moreover, coreflooding results confirmed the micromodel results in the presence of initial water saturation at high temperature condition.

Screening of Chemicals to Enhance Oil Recovery in a Mature Sandstone Oilfield in Kazakhstan: Overcoming Challenges of High Residual Oil

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.

Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned

Summary This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-based chemical flooding processes for offshore applications. Key Terms and Phrases offshore chemical flooding; polymer flooding; surfactant-based chemical flooding; offshore application cases; lessons learned

Spontaneous imbibition and core flooding analysis of pH adjusted alkali and surfactant system in high salinity sandstone reservoir

Some of the limitations of a cost-effective alkaline surfactant flooding method include chemical precipitation and other formation damage issue which has greatly affected the application of chemical flooding especially in high salinity reservoirs. This study ascertains the chelating attributes of Ethylene-diamine-tetracetic Acid-(EDTA/NaOH), investigates the ability of EDTA/NaOH and an anionic surfactant to improve oil recovery in heavy oil sandstone formation. Petrophysical analysis of the crude oil and core samples were performed. Hard brine at 5.1% optimal salinity and 0.2 wt.% surfactant imbibition were performed on the sandstone core plug for over 240 hrs. and the volume of oil recovered was determined using Amott imbibition cells. Sandstone core flooding test was thereafter conducted using the alkaline -surfactant solution at optimal salinity. Spontaneous imbibition results showed that surfactant imbibition (26.6%) produced a higher recovery than hard brine recovery (18.7%) after 240hrs. Sandstone core flooding results showed increased heavy oil recovery of 37% OOIP with alkaline-surfactant solution and additional 8% recovery was achieved by performing a final chase brine flooding, totaling 45% indicating that traces of alkaline-surfactant, in the core, aided the final imbibition process. This study underpins and complements several research solutions concerned with flooding in harsh oilfield terrains, thus making the overall process cost-effective and less time- consuming.

Bacterial co-occurrence patterns are more complex but less stable than archaea in enhanced oil recovery applied oil reservoirs

A complex microbial community exists in oil reservoirs after the application of chemical enhanced oil recovery (EOR) technologies, where the dynamic interactions of microorganisms are thought to be critical to petroleum composition, recovery, and production technologies but are poorly understood. Here, we used the 16S rRNA gene to construct co-occurrence networks for bacterial and archaeal communities associated with water-, polymer-, and alkaline surfactant polymer (ASP)-flooded oil reservoirs. Nonmetric multidimensional scaling analysis showed that bacterial and archaeal community structures differed significantly (p < 0.01) among the oil reservoirs with different EOR compositions. The microbial co-occurrence pattern in water-flooded reservoirs was more complex, with more nodes, edges, and average degrees (i.e., average links per node in the network) than in the polymer- and ASP-flooded reservoirs. However, the archaeal co-occurrence pattern maintained a more robust structure than that of bacteria under the application of polymer and ASP flooding technologies, suggesting that the application of different enhanced oil recovery techniques has diverse effects on the bacterial and archaeal co-occurrence patterns in reservoirs. The pH and [HCO3−] were significantly correlated with the variations in bacterial and archaeal network structures. Our findings provide new insights into the response of microbes to diverse EOR processes by regulating their interactions in deep oil reservoirs. Revealing the effects of water, polymer, and ASP flooding on the co-occurrence patterns of bacteria and archaea in oil reservoirs, which may facilitate the implementation of microbial enhanced oil recovery technology in the future.

The characterization study of inhibited silica/silicate scale using vinyl sulfonated copolymer (VS-Co)

Silica/silicate scale is a significant problem, especially in oilfield production during Alkaline Surfactant Polymer (ASP) flooding, where chemical inhibitors are the preferred method to prevent them. In this study, the effect of inhibitor vinyl sulfonated copolymer (VS-Co) on silica/silicate scale formation was analysed using X-Ray Diffraction (XRD) and Fourier-transform infrared spectroscopy (FTIR).The functional group type of VS-Co are sulfonate ions, SO3-, and these interact in the scaling process. Bulk-inhibited scaling brine tests were conducted at 60C and pH 8.5. During these tests, the silicon brine (with VS-Co) representing the inhibited ASP leachate was mixed with a magnesium brine representing the connate water to replicate reservoir conditions during ASP flooding. The samples tested in this study were non-inhibited Si/Mg mixed brine of 60 ppm Mg2+ and 940 ppm Si4+ (60Mg:940Si) as a blank, and inhibited 60Mg:940Si mixture with various VS-Co concentrations of 20 ppm, 50 ppm, and 100 ppm. The inhibition efficiency of the VS-Co was determined, followed by the characterisation study of the silica/silicate scale deposited from both test conditions.The IR spectra of all 60Mg:940Si samples show a similar peak at 1050 cm-1 to 1080 cm-1, attributed to a Si-O covalent bond and a band at 790 cm-1 to 800 cm-1 showing the presence of Si-O-Si stretching. XRD patterns produced a broad scattering peak for all samples at 2 of 24 showing that the samples are amorphous silica. For tests of high Mg2+ in the brine mix, 900Mg:940Si, a mix of crystalline silica and crystalline magnesium silicate was produced. Based on these results, it can be concluded that the scale formed even with 100 ppm of VS-Co present. Further studies are required to address how to mitigate scale formation effectively in the future.Based on the research conducted, we can conclude that the VS-Co alone could not significantly inhibit the formation of silica/silicate scale even at the highest concentration (100 ppm) of VS-Co. However, having VS-Co present caused an alteration in IR spectra frequency which requires further investigation to assess how best to develop the inhibiting properties of the VS-Co product. The application of nanoparticles and their successful stories spark the interest of authors in searching for an efficient method of managing the silica/silicate scale where the modification of potential scale inhibitor (SI) with nanoparticles may be able to improve the inhibition efficiency towards the silicate/silicate scale.The presence of VS-Co in the scaling brine only slightly inhibits the Mg2+ ion (initially comes from connate water) from reacting. It is worth further investigation on how this VS-Co can make it happen. Hence, the functional groups responsible for this may be altered by adding other functional groups to provide a synergistic effect in preventing this silica/silicate scale; or by modifying the VS-Co with nanoparticles to improve their adsorption/desorption capacity.The newly developed technique in analysing the inhibition mechanism of a chemical inhibitor using various spectroscopic analysis is promising where an alteration in the spectra may provide proof of the chemicals inhibition efficiency.

Design of salinity tolerant in alkaline surfactant systems for high salinity reservoirs

Chemical oil recovery from offshore reservoirs which are usually characterised by harsh conditions such as high salinities have remained a source of concern. This study assesses chemical compatibilities of alkalis –surfactant systems under high salinity and divalent ions (Ca2+ and Mg2+). It analysed the synergy between alkali-surfactant slugs and crude oil, leading to the design of an optimal low-cost alkaline- surfactant flooding. Three alkali systems: sodium hydroxide, sodium metaborate and ethylene-diamine-tetracetic acid-(EDTA/NaOH) were evaluated with two high salinity synthetic brines; one without divalent ions (soft brine) and the other containing divalent ions (hard brine). Compatibility of these alkali systems with the commercial-grade surfactant was evaluated based on fluid-fluid interaction. Phase behaviour experiments were conducted to determine the alkali–surfactant compatibility with brine. Solutions free of precipitation were used for the interfacial-tension (IFT) and phase separation analysis, obtained level readings were used to calculate optimal salinity. Results showed that all alkali systems were compatible with soft brine, while compatibility with hard brine was highly controlled by the pH. Alkali-crude oil failed to produce Type III micro-emulsion; however, the addition of surfactant achieved an ultra-low IFT. EDTA/NaOH effectively sequestered the divalent ions like sodium metaborate hence increasing the solubilisation of surfactant at higher salinity. Comparison of both alkalis with commercial surfactant, alcohol alkoxy sulphate at controlled pH exhibited a higher optimum salinity for EDTA/NaOH than for sodium metaborate. This study shows that at pH ≥ 11 and an increased salinity above optimal salinity, chemical precipitation occurs resulting in reduced oil recovery.

Design of salinity tolerant in alkaline surfactant systems for high salinity reservoirs

Design of salinity tolerant in alkaline surfactant systems for high salinity reservoirs

Developing methodology and experimental procedure эfor experimental microfluidic study of chemical enhanced oil recovery

The concern of this research was to review the different methodology on microfluidic experiments conducted to study chemical enhanced oil recovery methods on micromodel chips. In general, there are several ways to study EOR methods such core flooding and microfluidics. The disadvantage of first method is that the flow processes inside the core sample cannot be imagined. Hence, the second method helps us to fully visualize how fluid flow behaviour occurs though the porous medium of the rocks. The various chemical EOR processes such as surfactant flooding, polymer flooding and ASP flooding were studied on microfluidic chips. These chemicals were injected into micromodels to drive out crude oil. It helps to understand the interactions between crude oil and chemicals, the advancement of front developed between displacing and displaced fluids and the viscous fingering effect. Visual studies enabled us to understand the effectiveness of polymer, surfactant and alkaline separately and as combined. The different experimental methodologies to study the EOR methods are reviewed. Mainly experiments divided into two main groups: methods of geological characterisations influence to fluid transport while others study oil displacement at different condition, such high temperature, high pressure, low or high salinity, highly viscous oil. We reviewed methodologies applied to study an oil displacement by polymer, surfactant-polymer (SP) and alkaline surfactant polymer (ASP) solutions, their interactions and transport in porous media. Based on reviewed article the experimental procedure was developed. Analyses of published materials have helped to design and direct the methodology of research.

Minimizing Adsorption of Anionic Surfactant in Alkaline-Surfactant-Polymer System: Effects of pH and Surfactant Concentration

Alkaline-surfactant-polymer (ASP) flooding has been identified as the most effective enhanced oil recovery (EOR) technique to boost up the production of crude oil and improve the recoverable reserves. However, surfactant loss into the formation due to adsorption has been one of the issues, which could degrade the efficiency of the process. This study highlights the static adsorption of anionic sodium dodecyl sulphate (SDS) surfactant on the quartz sand with presences of alkaline and polymer at different pH and surfactant concentration. The critical micellar concentration (CMC) of SDS was determined using surface tension method and found at 0.22wt%. Three different systems were formulated namely A, B and C referring to the Surfactant formulation, Alkaline-Surfactant (AS) formulation and Alkaline-Surfactant-Polymer (ASP) formulation, respectively. For static adsorption tests, ASP system was formulated by adding 10,000 ppm sodium carbonate (Na2CO3) and 500 ppm of anionic Hydrolyzed Polyacrylamide (HPAM) polymer into the surfactant solution. The formulation was then mixed with the quartz sand at a fixed mass to volume ratio of 1:5. The adsorption tests involved shaking the mixtures, centrifuging, and analysing the supernatant solutions using UV-Visible spectrophotometer for adsorption measurement. The adsorption tests resulted in low adsorption at higher pH and low surfactant concentration. It was discovered that the lowest surfactant adsorption exhibited by ASP system with approximate reductions of 65% and 63% as compared to surfactant formulation at ~pH 12 and 2000 ppm surfactant concentration, respectively. Thus, anionic surfactant has a great performance in ASP system compared to its individual formulation, resulting in lower surfactant adsorption.

A Critical Overview of ASP and Future Perspectives of NASP in EOR of Hydrocarbon Reservoirs: Potential Application, Prospects, Challenges and Governing Mechanisms.

Oil production from depleted reservoirs in EOR (Enhanced Oil Recovery) techniques has significantly increased due to its huge demands in industrial energy sectors. Chemical EOR is one of the best approaches to extract the trapped oil. However, there are gaps to be addressed and studied well for quality and cost consideration in EOR techniques. Therefore, this paper addresses for the first time a systematic overview from alkaline surfactant polymer ((ASP)) and future perspectives of nano-alkaline surfactant polymer ((NASP)), its synergy effects on oil recovery improvement, and the main screening criteria for these chemicals. The previous findings have demonstrated that the optimum salinity, choosing the best concentration, using effective nano-surfactant, polymer and alkaline type, is guaranteed an ultra-low IFT (Interfacial Tension). Core flood results proved that the maximum oil is recovered by conjugating nanoparticles with conventional chemical EOR methods (surfactant, alkaline and polymer). This work adds a new insight and suggests new recommendation into the EOR application since, for the first time, it explores the role and effect of nanotechnology in a hybrid with ASP. The study illustrates detailed experimental design of using NASP and presents an optimum micro-model setup for future design of NASP flow distribution in the porous media. The presence of nano along with other chemicals increases the capillary number as well as the stability of chemicals in the solution and strengthens the effective mechanisms on the EOR.

Reservoir Simulation using Water and Chemical Injection Scenarios on Structure B of "X" Field

Structure B in field "X" is a mature field that has been in production for 27 years and contribute in 80% of total oil production in PSC "S". The production declining faster as an impact of reservoir pressure depletion. In order to recover the remaining oil, some efforts to increase reservoir pressure such as water and chemical injection are needed. The aim of this study is to obtain best scenario to produce the remaining oil in structure B and increasing the recovery factor. Static and dynamic reservoir model with the latest data were created to obtain four production scenarios. Economic evaluations of the project also carried out to ensure that the project investment plan are attractive to implement. Black oil method of reservoir simulation applied in E314-E315 layer formation was the limitation of this study. The study suggest that scenario-4 with injecting water + alkaline surfactant polymer (ASP) + polymer is the optimum scenario on this project, which provide incremental oil production of 9.4 MMstb or increase the recovery factor by 11%. This selected scenario gives an NPV of 29.3 MM$, IRR 31.4%, pay out time of 5.6 years, and government take of 83 MM$.

Nanomaterials for scaling prevention in alkaline–surfactant–polymer flooding: A review

Nanomaterials for scaling prevention in alkaline–surfactant–polymer flooding: A review