Alkaline Surfactant Polymer Research Articles

Evaluation and regulation methods for the utilization of Type-II oil reservoirs using ASP flooding

Abstract Existing methods for calculating oil reservoir utilization in chemical flooding rely on the instantaneous water absorption profile, which fails to provide an accurate description of the actual utilization conditions of the reservoir, making it imperative to find a method that accurately reflects the reservoir utilization. Type-II oil reservoirs often exhibit significant vertical heterogeneity. During chemical flooding, the impacts of high-permeability layer utilization, low-permeability layer utilization, and the simultaneous utilization of both layers on recovery are to be explored. Therefore, it is important to investigate the recovery requirements for different types of reservoirs. This study explores the solutions for improved reservoir utilization as well as the evaluation and regulation methods for the utilization of secondary oil reservoirs using the Alkaline-Surfactant-Polymer (ASP) flooding, which is of great significance for the adjustment of ASP flooding, injection, and production of secondary oil reservoirs.

Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery

Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

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.

*Synthesis, characterization, and mechanistic study of a new highly-stable comb-like polymeric surfactant in enhanced oil recovery

Numerous investigations suggest that the primary impediment to chemical flooding, particularly in cases involving surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) injection, is the resilience of the injected fluid front in severe reservoir conditions. To surmount this obstacle, one could amalgamate the characteristics of individual polymer and surfactant molecules into a singular molecule capable of achieving the desired interfacial tension reduction and viscosity enhancement. In the literature, these compounds are referred to as “polymeric surfactants” and are extensively expounded upon in terms of synthesis techniques and their practical applications. Nevertheless, the diverse facets of polymeric surfactant implementation in the enhanced oil recovery sector are scarcely explored and necessitate a systematic reassessment.The present study describes a complete procedure of polymeric surfactant analysis for an enhanced oil recovery purpose in three parts. First, we utilized the free-radical copolymerization method to build novel comb-like polymeric surfactant molecules, and the accuracy of the synthesis was confirmed by multiple characterization tests. The polymeric surfactant had a CMC of 432.7 ppm and was stable up to 220 °C, which is accepted for most subsurface applications. In the second part, the stability of polymeric surfactant solutions was tested in various conditions and compared with some commercial SP solutions, and improved stability of polymeric surfactant solution was observed. Furthermore, interfacial tension (IFT) was measured with different oil compositions, and the relationship between oil acid/base number and IFT was figured out. In addition, a comprehensive study on surface adsorption of the polymeric surfactant was applied to find its consequent effects on rock wettability and correlations with rock composition and it was pointed out that the polymeric surfactants are adsorbed in multilayer configuration rather than monolayer over the rock surface. In the end, four core flooding experiments and capillary number analysis showed that the primary recovery mechanism in polymeric surfactant flooding is increased water viscosity, which leads to the discovery of a new unswept area of the core plugs. Nonetheless, interfacial tension reduction was the second recovery mechanism in polymeric surfactant flooding.

Research on the ratio of multicomponent emulsion flooding system

In recent years, field test and industrialized application of ASP (alkaline/surfactant/polymer) flooding has been carried out in oilfields, which has obtained an obvious effect on increasing oil and decreasing water and good economic efficiency. However, due to the large proportion of alkali in the ASP flooding system, there are problems such as severe scaling and high cost during field tests, which restrict the promotion of ASP flooding. In order to reduce the amount of alkali used, achieve the goal of reducing scaling and costs, and meanwhile improve emulsification performance while maintaining interfacial activity, a multicomponent emulsion flooding system was developed by combining emulsifier HEFR2 with petroleum sulfonate and sacrificial agent LSCP1 with NaOH.Through laboratory experiments, the water extraction rate, particle diameter, Tsi value, and interfacial activity of the multicomponent emulsion flooding system were tested under different conditions. The results show that when the mass ratio of petroleum sulfonate to emulsifier HEFR2 is between 3:1 and 5:1, and the mass ratio of sacrificial agent LSCP1 to NaOH is between 3:1 and 7:1, the multicomponent emulsion flooding system can maintain good emulsification stability and interfacial activity. The multicomponent emulsion flooding system significantly reduces the amount of alkali used, and the cost of chemical agents is 11% lower than that of the ASP flooding system. At the same time, it achieves the goal of improving the stability of emulsifiers, maintains interfacial activity and reduces costs. This technology has broad application prospects.

Study Reviews Largest ASP Project From Laboratory to Pilots and Field Application

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215058, “A Systematic Review of the Largest ASP Flood Project in the World: From Laboratory to Pilots and Field Application,” by Yunan Wei, SPE, Xiaoguang Lu, SPE, and Jianhong Xu, SPE, C&C Reservoirs, et al. The paper has not been peer reviewed. _ The complete paper presents a systematic review of the largest alkaline-surfactant-polymer (ASP) flood project in the world, applied in the largest oil field in China. First, reservoir and fluid characteristics are highlighted to understand heterogeneity of the reservoir. Next, project history is summarized, including laboratory studies, pilot tests, industrial-scale tests, and fieldwide application. Finally, typical ASP flood performance and reservoir management measures from over 30 years of experience are presented. Performances of ASP flood and polymer floods in the same field also are compared.​​​​ Introduction In the La-Sa-Xing Field, ASP flooding was studied in the laboratory from 1987 to 1993 and followed by five small-scale pilots from 1994 to 1999, all successfully achieving incremental recoveries of approximately 20% stock-tank oil initially in place (STOIIP). As a result, industrial-scale pilots were conducted from 2000 to 2007, resulting in increased production by ASP flooding from 3,887 to greater than 19,000 BOPD in 2007. Fieldwide ASP expansion was launched in December 2007. By 2021, the ASP-flooded blocks registered a STOIIP of 1.9823 billion bbl. Daily production was approximately 96,000 BOPD through approximately 9,650 wells. Average incremental recovery factor was 20% STOIIP with waterflooding and 8% with polymer flooding, providing an ultimate recovery factor of 60%. Cumulative oil production by ASP flooding had reached 316 million bbl by 2021, making it the largest ASP flooding project in the world. Geological Background and Reservoir Characteristics The La-Sa-Xing Field is in the north of the Songliao Basin of northeast China, comprising the majority of the Daqing field complex. The field was placed onstream in 1960. The hydrocarbon-bearing reservoir has a gross thickness of 1,377 ft and a net thickness of 394 ft. Net pay averages 150 ft. Initial reservoir pressure ranges from 1,523 to 2,585 psi. Reservoir temperature varies from 113 to 122°F. Crude oil has an API gravity of 33°, a viscosity of 8.5–10.3 cp at reservoir conditions, an initial gas/oil ratio of 258 scf/STB, and a bubblepoint pressure of 1,291 psi. Formation water salinity is 7000 mg/L. Reservoir rock initially shows water or weak oil wettability. Depending on permeability, three types of reservoir sand (Type I, Type II, and Type III) have been identified. Currently, ASP flooding is mainly applied to Type I sand, with partial application to Type II Sand.

Relation between Conventional and Starch-Assisted ASP Injection and Impact of Crystallinity on Flood Formation.

Alkaline-surfactant-polymer (ASP) flooding, a recognized method for oil recovery, encounters limited use due to its expense. In addition, ASP's best composition and injection sequence still remains uncertain today. This study explores conventional ASP flooding using PT SPR Langgak's special surfactants, simulating Langgak oilfield conditions in Sumatra, Indonesia. By comparing the outcomes of this flooding technique with that of starch-assisted ASP performed in another study, the benefits of adding starch nanoparticles to flooding are evident. Nano-starch ASP increased oil recovery by 18.37%, 10.76%, and 10.37% for the three configurations investigated in this study. Water flooding preceded ASP flooding, and flooding operations were carried out at 60 °C. This study employed sodium hydroxide (NaOH), sodium carbonate (Na2CO3), and specialized surfactants from PT SPR. The adopted polymer is solely hydrolyzed polyacrylamide (HPAM) at 2000 ppm. Starch nanoparticles underwent comprehensive characterization and focused more on charge stability. Purple yam nanoparticles (PYNPs) exhibited remarkable stability at -36.33 mV, unlike cassava starch nanoparticles (CSNPs') at -10.68 mV and HPAM's at -27.13 mV. Surface properties affect interactions with fluids and rocks. Crystallinity, a crucial characterization, was assessed using Origin software 2019b. CSNPs showed 24.15% crystallinity, surpassing PYNPs' 20.68%. Higher crystallinity benefits CSNPs' thermal stability. The amorphous behavior found in PYNPs makes them less suitable if applied in harsh reservoirs. This research correlated with prior findings, reinforcing starch nanoparticles' role in enhancing oil recovery. In summary, this study highlighted conventional ASP flooding using HPAM as the sole polymer and compared it with three formations that used two starch nanoparticles included with HPAM, assessing their impact on charge stability, crystallinity, and recovery rate to emphasize their importance in the oil recovery industry. Starch nanoparticles' benefits and limitations guided further investigation in this study.

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

Enhancing ASP Flooding by Using Special Combinations of Surfactants and Starch Nanoparticles.

This study aimed to address the challenges faced by mature oilfields in extracting substantial oil quantities. It focused on improving the efficiency of alkaline-surfactant-polymer (ASP) flooding technique, which is a proven tertiary recovery technology, to overcome scaling issues and other hindrances in its large-scale implementation. Appropriate materials and their suitable concentrations were selected to enhance the ASP flooding technique. Special surfactants from Indonesia were introduced to improve the interfacial tension reduction and wettability alteration. Reservoir rock model that resembling Langgak oilfield in Sumatra was utilized, and low-salinity water was employed to mimic the oilfield conditions. Starches derived from cassava nanoparticles (CSNPs) and purple yam nanoparticles (PYNPs) were combined separately with conventional hydrolyzed polyacrylamide (HPAM) polymer to enhance its performance. Sodium hydroxide and sodium carbonate were used as alkaline in final ASP formula. It was demonstrated from this research that only two combinations of ASP formulations have led to improved oil recovery. One combination utilizing PYNPs resulted in 39.17% progressive recovery, while the other combination incorporating CSNPs achieved 35% incremental oil recovery. The ASP combination that resulted in recovery rate of 39.17% was composed of sodium hydroxide (NaOH) at a concentration of 1.28 wt.%, PSC EOR 2.2 (0.98 wt.%), and a combined polymer consisting of HPAM (0.2 wt.%) and PYNPs nano-starch (0.6 wt.%). The second combination led to 35% recovery rate and involved NaOH also at concentration 1.28 wt.%, PSC HOMF (0.63 wt.%), and a combined polymer comprising from HPAM (0.2 wt.%) and CSNPs nano-starch (0.8 wt.%). These findings of this study highlighted the potential of this modified ASP flooding to enhance oil recovery in mature oilfields, thereby offering valuable insights for oil industry.

Heavy Alkyl-Benzene Sulfonate-Controlled Growth of Aragonite-Based Polymorphic CaCO3 Crystals in Emulsion

The non-natural mineralization of CaCO3 with special structures or morphologies is generated during the migration of crude oil and is the main form of scale in alkaline/surfactant/polymer (ASP) flooding in oilfields, adversely affecting oil recovery and causing environmental pollution. To date, the mineralization of aragonite superstructures and the role of heavy alkyl-benzene sulfonate (HABS) in mineralization are still unclear. In this work, aragonite-based superstructures of CaCO3 crystals were obtained in an O/W emulsion with HABS to help deepen the understanding of the diversified growth of CaCO3 scaling in oilfields. As a result, rosette-like, bouquet-like, and dumbbell-shaped CaCO3 crystals with vaterite–aragonite, aragonite, and calcite–aragonite phases were formed with 200 mg/L HABS concentration at 45 °C for 60 min and spherical vaterite phase stabilized at a high HABS concentration (800 mg/L and 1000 mg/L). Rhombohedral calcite content experienced a fluctuation of about 40% as the HABS concentration varied. Needle-like and bundle-like aragonite precipitates were generated with increasing temperatures from 65 °C to 85 °C. Thus, HABS affects the nucleation and growth of the precipitated CaCO3 solid, leading to modifications in the structure and morphology of the crystals. The synergistic effect between HABS and temperature can regulate ion pairs with the calcium ions and block sites that are essential to the incorporation of new solutes into the crystal lattice, which leads to the heterogeneous nucleation of vaterite and aragonite on calcite, forming aragonite-based superstructures in kerosene emulsion. This work may enrich the understanding of CaCO3 mineralization in oilfields, and also provide a novel strategy for manufacturing organic–inorganic composites.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

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.

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.

Surfactant formulation development for shallow reservoirs with high clay content

Sandstone reservoirs with high clay content can potentially adsorb large amounts of surfactants making the chemical flood processes unattractive. The objective of this work was to develop an alkaline-surfactant-polymer (ASP) process for a shallow, clayey sandstone reservoir to minimize surfactant retention. The phase behavior study was conducted to identify commercially available surfactants that display ultralow interfacial tension behavior. The selected surfactant formulations were tested in tertiary ASP core floods in outcrop and reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for core floods. The cumulative oil recovery was in the range of 92–96% of the original oil in place (OOIP) in the core floods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content due to the use of alkali. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. Injection of the ASP slug immediately after the field brine flood with divalent ions did not cause any plugging or adverse effect. The novelty of this work lies in designing ASP formulations with a single surfactant and reducing the residual oil saturations to ∼3% in field cores along with low surfactant retention. This paper illustrates a workflow to identify the chemical formulation, chemical concentrations and slug sizes.

Numerical Simulation of Low Salinity Water and Alkaline Surfactant-Polymer Flooding with Optimal Injection Pattern

Combined Low Salinity Water (LSW) and Alkaline-Surfactant-Polymer (ASP) flooding is a new enhanced oil recovery method that aids oil recovery from reservoirs following the traditional recovery methods. Experimental studies on combined LSW and ASP flooding show additional oil recovery potential. This paper used numerical simulation to investigate different flooding patterns with LSW and ASP combined. A homogenous reservoir was saturated with oil and water to obtain the required modelled factors. Oil reservoir simulations of 11 flooding patterns were created and run using ECLIPSE 100. These patterns were used in the field's development for five years. The results showed the normal 7-spot pattern to provide the best recovery, while the direct line drive provided the worst. The high salinity, low salinity, and combined LSW and ASP flooding recorded oil recoveries of 30%, 55%, and 93%, respectively. An economic analysis was also done to analyse the project’s economic viability which proved to be economical with a profit margin of 40.7%. Furthermore, it was discovered that normal flood patterns outperformed their inverted counterparts. It was thus concluded that the normal 7-spot pattern provides the highest profits from a purely technical standpoint.

The Effect of Silica Dissolution on Reservoir Properties during Alkaline-Surfactant-Polymer (ASP) Flooding

The Effect of Silica Dissolution on Reservoir Properties during Alkaline-Surfactant-Polymer (ASP) Flooding

A Visualization Study of Low-Tension Polymer Flooding for Viscous Oil Reservoirs

Summary Polymer flooding improves the sweep efficiency of viscous oil recovery over waterflooding. The low-tension polymer (LTP) flooding has the potential to improve the displacement efficiency due to low interfacial tension (IFT) without sacrificing sweep efficiency. Compared with ultralow tension (&amp;lt;0.001 mN/m) alkaline-surfactant-polymer (ASP) floods, LTP flooding uses a low concentration surfactant to moderately reduce the IFT (&amp;gt;0.01 mN/m). The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sandpack. Over 20 nonionic surfactants/cosolvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dyne/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. The sandpack was water-wet for the experiments with connate water. For the experiments without connate water, the sandpack was oil-wet. A base-case secondary polymer flood (without any surfactant) with a viscosity ratio (µo/µp) of 10 showed a stable displacement and an oil recovery of 82% at the first pore volume injected (PVI). An LTP flood with an IFT of 0.1 dyne/cm also had a stable displacement front, but a higher oil recovery at 1 PVI [90% original oil in place (OOIP)]. Further reduction in IFT to 0.05 dyne/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet; the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding surfactants did not improve the oil recovery in oil-wet sandpacks.