Alkaline Surfactant Polymer Flooding Research Articles

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 The paper has not been peer reviewed.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.

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.

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.

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.

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

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

Silicate Scaling Formation: Impact of pH in High-Temperature Reservoir and Its Characterization Study

Silicate scaling tends to form and be aggravated during high pH Alkaline Surfactant Polymer (ASP) floods and this silicate scale deposition affects oil production. Hence, it is important to examine the conditions that lead to silicate scale forming. The severity of the silicate scaling reaction, the type and morphology of silica/silicate scale formed in an experimental ASP flood were studied for pH values 5, 8.5, and 11, whilst the temperature was kept constant at 90 ℃. In addition, the impact of calcium ion was studied and spectroscopic analyses were used to identify the extent of scaling reaction, morphology type and the functional group present in the precipitates. This was performed using imagery of the generated precipitates. It was observed that the silica/silicate scale is most severe at the highest pH and Ca:Mg molar ratios examined. Magnesium hydroxide and calcium hydroxide were observed to precipitate along with the silica and Mg-silicate/Ca-silicate scale at pH 11. The presence of calcium ions altered the morphology of the precipitates formed from amorphous to microcrystalline/crystalline. In conclusion, pH affects the type, morphology, and severity of the silica/silicate scale produced in the studied scaling system. The comprehensive and conclusive data showing how pH affects the silicate scaling reaction reported here are vital in providing the foundation to further investigate the management and prevention of this silicate scaling. Copyright © 2022 by Authors, Published by BCREC Group. This is an open access article under the CC BY-SA License (https://creativecommons.org/licenses/by-sa/4.0)

The Effect of Alkaline on the Properties of Combination Flooding Agent During Long Distance Migration in Daqing Oilfield

Abstract Combination flooding, which performs well on both sweep efficiency and displacement efficiency, is being extensively utilized in Daqing Oilfield. Surfactant-polymer (SP) flooding and alkaline-surfactant-polymer (ASP) flooding are two of the most used combination flooding techniques. According to the findings, alkaline lowers the oil-water interfacial tension and reduces the other component’s adsorption. Nevertheless, alkaline also has negative effects like scaling and cost increasing. Therefore, the use of alkaline in combination flooding is still disputed. In order to clarify the role of alkaline on combination flooding, SP and ASP flooding comparative tests are conducted with typical formula in Daqing Oilfield. A 3000-centimeter long model is built to simulate long distance migration for the property change study. During the flooding, fluid samples are obtained along the model, and the properties of the samples such as viscosity, interfacial tension (IFT), and components concentration are measured. According to the findings, the 3.60 percent higher recovery rate caused by ASP flooding compared to SP flooding is primarily due to the near inlet area. In ASP flooding, alkaline reduces polymer and surfactant near inlet dynamic retention by 20.16% and 13.43%, respectively, when compared to SP flooding. Besides, alkaline also maintains viscosity at a higher level and IFT at a lower level in the first third of the well spacing in ASP flooding. Consequently, the effects of alkaline are noticeable in the near inlet area and fade as distance increase.

An Experimental Study on Efficient Demulsification for Produced Emulsion in Alkaline/Surfactant/Polymer Flooding

Abstract Tertiary oil recovery technologies, for example, alkaline/surfactant/polymer (ASP) flooding, can enhance oil recovery as an important oil displacement technology noteworthy in the present oilfields. However, it is the fact that the produced emulsion droplets have strong electronegativity, which will lead to the destabilization of electric field and affect the dehydration effect in the process of electric dehydration. This article innovatively proposed an efficient demulsification scheme, which uses polyaluminum chloride (PAC) as a chemical regulator to control electric field destabilization through the charge neutralization mechanism and then introduces demulsifier to promote oil–water separation. Furthermore, the dehydration temperature, power supply mode, and electric field parameters are optimized so as to achieve superior dehydration effect of ASP flooding produced liquid. The results indicate that PAC as a chemical regulator by exerting charge neutralization and electrostatic adsorption mechanism could reduce the electronegativity of the emulsified system, decrease the peak current of dehydration, shorten the duration of peak current of dehydration, improve the response performance of the electric field, and increase dehydration rate in the ASP flooding dehydration process. When the demulsifier dosage is 100–120 mg/l, using the composite separation process with the dehydration temperature of 45–50 °C for the thermochemical separation stage and 60 °C in the electrochemical dehydration stage and AC–DC composite electric field or pulse electric field can achieve better dehydration effect. The investigations in this study will provide support and basis for the efficient treatment of ASP flooding produced emulsion.

Efficiency and bacterial diversity of an improved anaerobic baffled reactor for the remediation of wastewater fromalkaline-surfactant-polymer (ASP) flooding technology.

Alkaline-surfactant-polymer (ASP) flooding technology is used to maximize crude oil recovery. However, the extensive use of alkaline materials makes it difficult to treat the water used. Here, an improved multi-zone anaerobic baffled reactor (ABR) using FeSO4 as electron acceptor was employed to treat the wastewater from ASP flooding technology, and the effects on major pollutants (hydrolyzed polyacrylamide, petroleum substances, surfactants suspended solids) and associated parameters (chemical oxygen demand, viscosity) were evaluated. Gas chromatography-mass spectrometry (GC-MS) was used to follow the degradation and evolution of organic compounds while high-throughput DNA sequencing was used to determine the bacterial diversity in the ABR. The results obtained after 90 d of operation showed decreases in all parameters measured and the highest mean removal rates were obtained for petroleum substances (98.8%) and suspended solids (77.0%). Amounts of petroleum substances in the ABR effluent could meet the requirements of a national standard for oilfield reinjection water. GC-MS analysis showed that a wide range of chemicals (e.g. aromatic hydrocarbons, esters, alcohols, ketones) could be sequentially removed from the influent by each zone of ABR. The high-throughput DNA sequencing showed that the bacteria Micropruina, Saccharibacteria and Synergistaceae were involved in the degradation of pollutants in the anaerobic and anoxic reaction zones, while Rhodobacteraceae and Aliihoeflea were the main functional microorganisms in the aerobic reaction zones. The results demonstrated that the improved ABR reactor had the potential for the treatment of wastewater from ASP flooding technology.

Experiment on the Scaling Mechanism of Strong Alkaline-Surfactant-Polymer in a Sandstone Reservoir.

Most of the mature oilfields are facing the problem of great difficulty in exploitation currently. Alkaline–surfactant–polymer (ASP) flooding has been widely used in Daqing Oilfield as a tertiary oil recovery technology that can effectively enhance oil recovery (EOR). However, various degrees of scaling appeared in field application tests, which hindered the large-scale application of this technology. The damage and scaling mechanisms of strong alkali–surfactant–polymer (SASP) flooding to heterogeneous reservoirs with high clay mineral content are still unclear. In this study, several sets of experiments have been carried out to determine the core mineral composition and the pore structure. Additionally, the damage mechanism and mineral corrosion with different permeabilities can be explored from a microscopic point of view. The results indicate that the corrosion of SASP reduces the contents of quartz and kaolinite, while the illite/montmorillonite mixed layer increases. In addition, there is chlorite and secondary quartz generation, which do not exist in the original mineral composition. Clay particles and sediment are easy to form bridges or stay on the surface and block the pore throats, which results in core seepage capacity reduction. All our preliminary results have contributed to the present understanding of scaling during ASP flooding. Moreover, it is of great significance to guide ASP flooding field application and prevent scaling.

Review of Important Aspects and Performances of Polymer Flooding versus ASP Flooding

Polymer flooding is a promising and effective chemical Enhanced Oil Recovery (cEOR) technology. Polymer flooding is especially cost-effective, whereas other chemical flooding methods, such as Alkaline Surfactant Polymer (ASP), are not profitable and cause serious on-site problems (scaling, uptime decrease, injectivity is-sue, hard-breaking emulsions). Recent papers in the literature mention ~30 field polymer floods. Most of them reported technical success. Although, polymer flooding has been applied ~60 years and it still requires further investigation to provide improvements. Thus, this paper describes important aspects and performances during polymer flooding based on a review of recent projects, combined with the Kalamkas field experience. A comprehensive literature review examines the applicability range in temperature, brine salinity, water source selection, oil properties, formation type, and permeability. Water source selection has an essential role during pilot/field project design and is one of the most responsible technical and economic success decisions. Polymer slug design has been extensively analyzed especially for the high viscosity oil fields; the selected oil/polymer viscosity ratio was usually much less than one. We placed significant emphasis on clarifying ob-served high polymer injectivities. We conducted feasibility studies of some reported ASP floods to clarify that this technology is not profitable at current oil prices. Also, we performed TAN analysis of three Kazakh-stan oil fields for screening of ASP flood.

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 differential wide field electromagnetic method and its application in alkaline-surfactant-polymer (ASP) flooding monitoring

To improve effectiveness of ASP flooding, it is necessary to establish a reliable parameter design and tracking adjustment method to monitor the process of oil displacement. A differential wide field electromagnetic method was proposed and applied to the ASP displacement monitoring test in a block of the Daqing Oilfield. In the process of ASP flooding, the electromagnetic field was measured many times. The data acquired before the ASP flooding were set as the background field, and the resistivity model was obtained by inversion. Then, the resistivity data were calibrated by logging data and the resistivity model was established. Finally, the range and front of ASP flooding were deduced with the residual gradient from the spatial domain first-order difference of the resistivity model. Production data of well groups in this block have proved that this method can work out the range and front of ASP flooding accurately, providing support for optimization of ASP flooding parameters.

Effectiveness of sodium sulfite as an electron acceptor for bioenhanced treatment of salt-containing water produced from ASP flooding

The wastewater produced from alkaline-surfactant-polymer (ASP) flooding is a complex multiphase mixture that contains oil, polymers, surfactants and other pollutants and is thus a salt-containing industrial waste recalcitrant to treatments. Through laboratory tests, this study assessed the effectiveness of using sodium sulfite as an electron acceptor for a modified anaerobic baffled reactor (ABR) for removing oil, suspended solids, polymers and surfactants from salt-containing wastewater produced from ASP flooding. During the 90-day operation, the method established in this study successively removed 52.8%, 98.6%, 77.0%, 21.2% and 21.5% of the chemical oxygen demand (COD), oil, suspended solids, polymers and surfactants, respectively, from the wastewater. The changes in organic compounds in the reactor during the treatment were monitored through gas chromatography-mass spectrometry (GC-MS), and the results showed that the established method was very effective in removing alkanes, alkenes, cycloalkanes, aromatic hydrocarbons and esters, and the organic macromolecules in the wastewater were degraded to small molecules. The main bacterial species and microbial communities in the reactor were characterized using molecular biological techniques, and the results indicated that under the stress of high pH and salts, Halomonas sp. gradually dominated and played a major role in degrading hydrocarbons. The findings of this study can aid the development of a cost-effective biological system to treat the water produced from ASP flooding.

Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management

Abstract Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3-) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.