Alkaline Surfactant Polymer Research Articles

Application of Killer Whale Algorithm in ASP EOR Optimization

Enhanced Oil Recovery (EOR) is utilized to increase oil production after primary and secondary methods. EOR is classified into three main categories i.e. thermal recovery, chemical flooding and miscible flooding. Alkaline Surfactant Polymer (ASP) EOR is a method of chemical flooding in which the increase of oil recovery is ranging from 19% to 34% of original oil in place (OOIP). In order to obtain optimal results of ASP EOR needs to consider several parameters i.e. the concentration of ASP, ASP material procurement costs, the injection pressure and mass flow rate of injection. Beggs-Brill method is used to model the pressure drop in the injection well and production well. The mean error of Beggs-Brill method to PIPESIM simulation result is 0.5076%. Meanwhile the modelling of reservoir pressure conducted using Darcy equation shows that the mean error of Darcy equation model to COMSOL Multiphysics simulation result is 3.378×10-5%. The optimization results using Killer Whale Algorithm (KWA) exhibits the net profit of ASP EOR increases up to 87.72% or net profit can be optimized from 9586.40 USD/day to 17995.19 USD/day.

Experimental Study of Enhancing Oil Recovery with Weak Base Alkaline/Surfactant/Polymer

Na2CO3 was used together with surfactant and polymer to form the Alkaline/Surfactant/Polymer (ASP) flooding system. Interfacial tension (IFT) and emulsification of Dagang oil and chemical solutions were studied in the paper. The experiment results show that the ASP system can form super-low interfacial tension with crude oil and emulsified phase. The stability of the emulsion is enhanced by the Na2CO3, surfactant, and the soap generated at oil/water contact. Six core flooding experiments are conducted in order to investigate the influence of Na2CO3 concentration on oil recovery. The results show the maximum oil recovery can be obtained with 0.3 wt% surfactant, 0.6 wt% Na2CO3, and 2000 mg/L polymer. In a heterogeneous reservoir, the ASP flooding could not enhance the oil recovery by reducing IFT until it reaches the critical viscosity, which indicates expanding the sweep volume is the premise for reducing IFT to enhance oil recovery. Reducing or removing the alkali from ASP system to achieve high viscosity will reduce oil recovery because of the declination of oil displacement efficiency. Weak base ASP alkali can ensure that the whole system with sufficient viscosity can start the medium and low permeability layers and enhance oil recovery even if the IFT only reaches 10−2 mN/m.

Seepage flow characteristics and ability for enhanced oil recovery based on ultra high molecular weight partially hydrolysed polyacrylamide

The ultra high molecular weight partially hydrolysed polyacrylamide (UHMW-HPAM) has captured much attention because of its good thickening property and rheological behaviour. In this paper, the seepage property, dynamic retention capacity and effective viscosity of UHMW-HPAM are studied and compared with traditional partially hydrolysed polyacrylamide (HPAM). The results indicate that the UHMW-HPAM can build stronger flow resistance in porous medium than HAPM, but the effective viscosities of UHMW-HPAM and HPAM have few discrepancies. It is because the retention capacity of UHMW-HPAM is generally higher than that of HPAM under the same conditions. The result also confirms that the molecular weight has no significant influence on effective viscosity. The abilities to improve oil recovery of chemical flooding based on UHMW-HPAM and HPAM were also investigated. When the permeability ratio is approximately 5.0, the ability of alkaline-surfactant-polymer (ASP) flooding based on UHMW-HPAM to increase oil recovery is far better than that of ASP system based on ordinary HPAM. [Received March 5, 2015; Accepted November 23, 2015]

Measurement of Streaming Potential in Downhole Application: An Insight for Enhanced Oil Recovery Monitoring

Downhole monitoring using streaming potential measurement has been developing in order to respond to actual reservoir condition. Most studies have emphasized on monitoring water flooding at various reservoir condition and improving the approaches of measurement. Enhanced Oil Recovery (EOR) could significantly improve oil recovery and the efficiency of the process should be well-monitored. Alkaline-surfactant-polymer (ASP) flooding is the most promising chemical EOR method due to its synergy of alkaline, surfactant and polymer, which could enhance the extraction of residual oil. However, limited studies have been focused on the application of streaming potential in EOR processes, particularly ASP. Thus, this paper aims to review the streaming potential measurement in downhole monitoring with an insight for EOR application and propose the potential measurement in monitoring ASP flooding. It is important for a preliminary study to investigate the synergy in ASP and the effects on oil recovery. The behaviour of streaming potential should be investigated when the environment of porous media changes with respect to ASP flooding. Numerical model can be generated from the experimental data to forecast the measured streaming potential signal during production associated with ASP flooding. Based on the streaming potential behaviour on foam assisted water alternate gas (FAWAG) and water alternate gas (WAG) processes, it is expected that the streaming potential could change significantly when ASP flooding alters the environment and surface properties of porous media. The findings could provide new prospect and knowledge in the relationship between streaming potential and ASP mechanisms, which could be a potential approach in monitoring the efficiency of the process.

Multifaceted Solution of Analytical Challenges in Complex Oilfield Materials With Synchrotron Techniques

Summary The versatility of synchrotron techniques for the solution of oilfield questions is illustrated by the application of powder X-ray diffraction (PXRD) and X-ray absorption near-edge structure (XANES) spectroscopy to a toluene-insoluble oilfield-residue sample from an alkaline/surfactant/polymer (ASP) -flood site in Taber, Alberta, Canada. The primary questions regarding the sample were the sources of the barium and nitrogen (both at levels of approximately 0.8 wt%). Synchrotron PXRD provided better signal–noise and detection limits than previously obtained laboratory PXRD data, enabling the identification of four additional crystalline minerals including heulandite, (Ba, Ca, Sr, K, Na)5 Al9 Si27 O72 (H2O)22, a tecto-silicate zeolite known for accommodation of a wide variety of cations. Heulandite provides a plausible location for barium (and strontium) observed with chemical analysis. Synchrotron XANES spectra at the nitrogen K-edge suggested that the source of the nitrogen content was a corrosion inhibitor, rather than a polyacrylamide (PAM) -based compound, as originally assumed.

Variations of Micropores in Oil Reservoir Before and After Strong Alkaline Alkaline-surfactant-polymer Flooding

Enhanced oil recovery (EOR) provides a significant contribution for increasing output of crude oil. Alkaline-surfactant-polymer (ASP), as an effective chemical method of EOR, has played an important role in advancing crude oil output of the Daqing oilfield, China. Chemical flooding utilized in the process of ASP EOR has produced concerned damage to the reservoir, especially from the strong alkali of ASP, and variations of micropore structure of sandstones in the oil reservoirs restrain output of crude oil in the late stages of oilfield development. Laboratory flooding experiments were conducted to study sandstones’ micropore structure behavior at varying ASP flooding stages. Qualitative and quantitative analysis by cast thin section, scanning electric microscopy (SEM), atomic force microscopy (AFM) and electron probe X-Ray microanalysis (EPMA) explain the mechanisms of sandstones’ micropore structure change. According to the quantitative analysis, as the ASP dose agent increases, the pore width and pore depth exhibit a tendency of decrease-increase-decrease, and the specific ASP flooding stage is found in which flooding stage is most affective from the perspective of micropore structures. With the analysis of SEM images and variations of mineral compositions of samples, the migration of intergranular particles, the corrosions of clay, feldspar and quartz, and formation of new intergranular substances contribute to the alterations of sandstone pore structure. Results of this study provide significant guidance for further application to ASP flooding.

Development of anionic-cationic inhibitors for mitigating silicate scales during ASP flooding

Silicate scaling is often induced by alkaline surfactant polymer (ASP) flooding in sandstone reservoirs. The formation of silicate scale is complicated by its dependence on multiple factors including pH, silica concentration, and magnesium concentration, which vary as the flood progresses. These factors affect silicate scaling tendency, and consequently, severity of the problem. Silicate scale is a very serious problem in the oil and gas production system. Therefore, silicate scale inhibitors have been suggested to mitigate problems in oilfields. In this study, some of the dendrimers inhibitors with enhanced functionality used in the water industry were reviewed and assessed for possible application in oilfields scales. It was found that the NH2-terminated dendrimers exhibited excellent inhibitory silica polymerization efficiency compared with the control. It is now certain that effective silica scale inhibition is dependent on the cationic charge on the polymer backbone. However, these dendrimer inhibitors suffered from a serious disadvantage when the silicates that had not been inhibited entrapped the dendrimers. Visual observations showed that these particles appeared as white flocculant precipitates at the bottom of the test vessels. Previously, it had been found that silica scale inhibition could be achieved by using of scale inhibitors in combination with anionic polymer additives. It is believed that an effective silica inhibition should be based on a delicate balance structure of cationic–anionic charges. Therefore, in the present study pteroyl-L-glutamic acid (PGLU) compound is used in synergistic action with cationic dendrimer polymer. PGLU was proven to be an effective scale inhibitor at high temperature in aqueous solution of synthetic produced water. Furthermore, it was found that PGLU assisted the inhibitory action of dendrimers by alleviating formation of insoluble SiO2-PAMAM precipitates to operate more effectively.

Study on organic alkali-surfactant-polymer flooding for enhanced ordinary heavy oil recovery

With regard to ordinary heavy oil reservoirs which are not suitable for thermal methods, alkaline-surfactant-polymer (ASP) flooding exhibits great potential for enhancing heavy oil recovery. But for the formation water with high content of Ca2+ and Mg2+ ions, conventional ASP flooding always causes precipitation of a large amount of Ca and Mg salts which are damage to reservoirs. In this study, organic alkali-surfactant-polymer (OASP) flooding system is established, which exhibits good compatibility with the brine containing high-valent metal ions. The interfacial tension tests show that the combination of Shengli petroleum sulfonate (SLPS) and ethanolamine exhibits a good synergistic effect, and acquires an ultralow interfacial tension. Based on micromodel flooding tests, the mechanisms of OASP flooding system are studied as follows: the organic alkali in OASP system reacts with the acidic component of heavy oil and promotes the formation of water-in-oil (W/O) emulsion in heavy oil, thus increasing the flow resistance of flooding liquid and improving the sweep efficiency of normal ASP system. The generated surface active materials and surfactant can decrease the interfacial tension to an ultralow level, which could easily initiate the emulsion dispersion of crude oil, form the O/W emulsion, and improve the oil displacement efficiency. The sandpack flood results demonstrate that the oil recovery is increased by about 20%, and the recovery increases with the increase in organic alkali concentration. Therefore, the organic alkali-surfactant-polymer flooding technology can be developed into a new type of economically and technically feasible compound flooding technology suitable for ordinary heavy oil reservoirs with high content of Ca2+ and Mg2+ ions. Moreover, OASP flooding technology shows broad application prospects in improving the recovery of ordinary heavy oil reservoirs in Shengli Oilfield.

Design and Demonstration of New Single-Well Tracer Test for Viscous Chemical Enhanced-Oil-Recovery Fluids

Summary Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test. The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactive-transport reservoir models. The ability of the simulator to model every phase of the one-spot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs. The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-spot pilot.

Mixtures of Anionic/Cationic Surfactants: A New Approach for Enhanced Oil Recovery in Low-Salinity, High-Temperature Sandstone Reservoir

Summary Test results indicate that a lipophilic surfactant can be designed by mixing both hydrophilic anionic and cationic surfactants, which broaden the design of novel surfactant methodology and application scope for conventional chemical enhanced-oil-recovery (EOR) methods. These mixtures produced ultralow critical micelle concentrations (CMCs), ultralow interfacial tension (IFT), and high oil solubilization that promote high tertiary oil recovery. Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications in sandstone reservoirs are described in this study. Physical chemistry properties, such as surface tension, CMC, surface excess, and area per molecule of individual surfactants and their mixtures, were measured by the Wilhelmy (1863) plate method. Morphologies of surfactant solutions, both surfactant/polymer (SP) and alkaline/surfactant/polymer (ASP), were studied by cryogenic-transmission electron microscopy (Cryo-TEM). Phase behaviors were recorded by visual inspection including crossed polarizers at different surfactant concentrations and different temperatures. IFTs between normal octane, crude oil, and surfactant solution were measured by the spinning-drop-tensiometer method. Properties of IFT, viscosity, and thermal stability of surfactant, SP, and ASP solutions were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, SP, and ASP. The coreflooding experiments were conducted with synthetic brine with approximately 5,000 ppm of total dissolved solids (TDS), and with a crude oil from a Sinopec reservoir.

The Influence of Geology Factor on Alkaline Surfactant Polymer Flood Effect and the Corresponding Strategy

This study gives the influence laws of abandoned channel, in-layer interlayer, sand body contact relationship on the development effect of the Alkaline Surfactant Polymer (ASP) flooding based on the data of the industry promotion block ( Pu I32、Pu I33 sedimentation), and give out corresponding adjustment strategy at the same time. The result shows that: The ‘abruptly abandoned’ channels have a bad connection with the main channel and possesses a far lower reservoir producing degree (16.1%) than the ‘gradually-abandoned’ channels (79.9%). The injection wells located upon the channel sand need high concentration inject fluid with lower injection rate to handle the polymer breakthrough; The injection wells located between the channels need lower concentration injection; The injection wells located upon the abandoned channels firstly need high concentration injection to achieve the profile control and then inject low concentration fluid to adjust low permeable sublayer; The production wells located upon abandoned channels need timely fracturing measures. By July 2014, water content of this area is 90.7%, oil recovery improved 18.08% and is expected to reach 22.0%. Similar the success experience we get from this area can guide the study of block geologic factors that affect development result and has important guiding significance to the implementation of pointed development adjustment.

Formation damage during alkaline-surfactant-polymer flooding in the Sanan-5 block of the Daqing Oilfield, China

Alkaline-Surfactant-Polymer (ASP) flooding is an emerging chemical Enhanced Oil Recovery (EOR) technology which has significantly enhanced oil recovery of Daqing Oilfield. ASP flooding benefits from the synergy effects of alkali, surfactant and polymer to improve both volumetric and displacement efficiencies and meanwhile lower surfactant adsorption. However, ASP flooding also induces some negative formation damage effects such as scaling, adsorption, and mineral dissolution. In this paper, we investigated the formation damage caused during ASP flooding in Block Sanan-5 in Songliao Basin – one of the most productive blocks of Daqing Oilfield in China.It was found that the distribution of formation damage caused by ASP flooding followed flow paths of chemical solutions and was dependent on well locations. The severity of damage varies as distance increases from the near-injection-well area to the near-production-well area. Understanding the effects of well locations on formation damage during ASP flooding could provide more accurate evaluation of formation damage and helped to guide reservoir development strategies. To analyze the well location factor, we collected scaling samples and more than 970 m of core samples from Block Sanan-5 of Daqing Oilfield covering different wells on various flow paths before and after ASP flooding. The changes of some key petrophysical parameters such as porosity and permeability before and after ASP flooding were investigated. A series of experiments, including Scanning Electron Microscopy (SEM), Casting Thin Sections (CTS), X-Ray Diffraction (XRD) and ion analysis of produced water were performed to test properties of core samples. In addition, absorption of different components in the ASP solutions was also measured.Experimental results indicate that the ASP flooding has considerably different influences on different parts of flow paths. After ASP flooding, permeability distribution of core samples exhibits different variability trends from the near-injection-well areas to near-production-well areas. Due to absorption of alkali and polymer, grains migration and scaling of calcium and magnesium, permeability decreases at the near-injection-well area, then increases at an intermediate distance and decreases again at the near-production-well. Moreover, porosity of samples shows a similar tendency with variability of permeability, which is interpreted by the strong mineral corrosion due to high concentration of alkali in the near-wellbore area, while its extent of variation is smaller than permeability.

Ammonia-based ASP floods in carbonate cores containing gypsum

The amount of synthetic surfactants required for a surfactant flood can be minimized by the addition of an alkali. An alkali reduces surfactant adsorption on sandstone and carbonate rocks, and generates in-situ surfactant with acidic crude oils. Many reservoirs, especially carbonates, contain gypsum (or anhydrite), which is sparingly soluble in water. In such cases, a conventional alkali such as sodium carbonate cannot be added to alkaline-surfactant-polymer (ASP) formulations because it precipitates as CaCO3 on interacting with gypsum (or anhydrite). In this study, we test ammonia as an alkali to perform ASP floods in carbonate cores containing gypsum. The concentration of calcium ions in the presence of gypsum when ammonia is used as alkali can be as high as 2000ppm, depending on the brine salinity and composition. Therefore, surfactant and polymer selection study was performed to identify suitable candidates under high calcium concentrations. Oil recovery experiments were performed in carbonate cores containing gypsum, using ammonia as the alkali. PHREEQC, the USGS geochemical simulator, was used for reactive transport modeling and was found to be an effective tool for designing these corefloods. High pH propagation and good oil recovery was observed in the ASP coreflood performed in a carbonate core containing gypsum. Addition of sodium sulfate in injection brines decreased gypsum dissolution. Gypsum dissolution was also lower at higher temperatures and lower NaCl concentrations. The surfactant retention in the ASP coreflood using ammonia, however, was found to be about the same as that of the SP coreflood, even though a high pH propagation was observed during the ASP coreflood. A good agreement was observed between the measured concentration of the effluent ions from the corefloods and the PHREEQC simulations.

A chemical EOR benchmark study of different reservoir simulators

Interest in chemical EOR processes has intensified in recent years due to the advancements in chemical formulations and injection techniques. Injecting Polymer (P), surfactant/polymer (SP), and alkaline/surfactant/polymer (ASP) are techniques for improving sweep and displacement efficiencies with the aim of improving oil production in both secondary and tertiary floods. There has been great interest in chemical flooding recently for different challenging situations. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils.More oil reservoirs are reaching maturity where secondary polymer floods and tertiary surfactant methods have become increasingly important. This significance has added to the industry's interest in using reservoir simulators as tools for reservoir evaluation and management to minimize costs and increase the process efficiency. Reservoir simulators with special features are needed to represent coupled chemical and physical processes present in chemical EOR processes. The simulators need to be first validated against well controlled lab and pilot scale experiments to reliably predict the full field implementations.The available data from laboratory scale include 1) phase behavior and rheological data; and 2) results of secondary and tertiary coreflood experiments for P, SP, and ASP floods under reservoir conditions, i.e. chemical retentions, pressure drop, and oil recovery. Data collected from corefloods are used as benchmark tests comparing numerical reservoir simulators with chemical EOR modeling capabilities such as STARS of CMG, ECLIPSE-100 of Schlumberger, REVEAL of Petroleum Experts. The research UTCHEM simulator from The University of Texas at Austin is also included since it has been the benchmark for chemical flooding simulation for over 25 years.The results of this benchmark comparison will be utilized to improve chemical design for field-scale studies using commercial simulators. The benchmark tests illustrate the potential of commercial simulators for chemical flooding projects and provide a comprehensive table of strengths and limitations of each simulator for a given chemical EOR process. Mechanistic simulations of chemical EOR processes will provide predictive capability and can aid in optimization of the field injection projects. The objective of this paper is not to compare the computational efficiency and solution algorithms; it only focuses on the process modeling comparison.

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Alkaline–surfactant–polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the sub-optimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with more-complicated geochemical conditions.

Enhanced heavy oil recovery by organic alkali combinational flooding solutions

ABSTRACTAlthough alkaline/surfactant/polymer (ASP) flooding is successfully applied in oil fields, some disadvantages such as scales, corrosion effects, and viscosity reductions of polymer solutions appear. Usage of organic alkalis can avoid or decrease these disadvantages. In this paper, the physicochemical properties, including interfacial tension (IFT), and viscosity, of organic alkali combinational flooding solutions and their effectiveness as enhanced oil recovery agents are investigated. Monoethanolamine (MEA) is the optimal one for decreasing the IFT among the three organic alkalis studied in this paper. Although MEA cannot decrease the IFT as low as NaOH does, it has good compatibility with both surfactant and the polymer hydrolyzed polyacrylamide (HPAM). MEA not only helps a surfactant solution or HPAM/surfactant mixture attain ultralow IFT values, but can also promote better viscosity stability for HPAM or HPAM/surfactant solutions compared to NaOH. Moreover, core flood experiments show that adding MEA can obtain additional tertiary oil recovery of 6%–10% original oil in place (OOIP) on the top of HPAM or HPAM/surfactant flooding, although MEA has a lower enhanced oil recovery than NaOH. The experimental results show that MEA is a good choice to replace NaOH in enhancing heavy oil recovery.

Process, mechanism and impacts of scale formation in alkaline flooding by a variable porosity and permeability model

In spite of the role of alkali in enhancing oil recovery (EOR), the formation of precipitation during alkaline-surfactant-polymer (ASP) flooding can severely do harm to the stratum of oil reservoirs, which has been observed in situ tests of oil fields such as scale deposits found in oil stratum and at the bottom of oil wells. On the other hand, remarkable variation of stratum parameters, e.g., pore radius, porosity, and permeability due to scale formation considerably affects seepage flow and alkaline flooding process in return. The objective of this study is to firstly examine these mutual influential phenomena and corresponding mechanisms along with EOR during alkaline flooding when the effects of precipitation are no longer negligible. The chemical kinetic theory is applied for the specific fundamental reactions to describe the process of rock dissolution in silica-based reservoirs. The solubility product principle is used to analyze the mechanism of alkali scale formation in flooding. Then a 3D alkaline flooding coupling model accounting for the variation of porosity and permeability is established to quantitatively estimate the impact of alkali scales on reservoir stratum. The reliability of the present model is verified in comparison with indoor experiments and field tests of the Daqing oil field. Then, the numerical simulations on a 1/4 well group in a 5-spot pattern show that the precipitation grows with alkali concentration, temperature, and injection pressure and, thus, reduces reservoir permeability and oil recovery correspondingly. As a result, the selection of alkali with a weak base is preferable in ASP flooding by tradeoff strategy.

Heavy oil recovery using ASP flooding: A pore‐level experimental study in fractured five‐spot micromodels

AbstractAlthough alkaline‐surfactant‐polymer (ASP) flooding has proven efficient for heavy oil recovery, the displacement mechanisms and efficiency of this process should be discussed further in fractured porous media. In this study, several ASP flooding tests were conducted in fractured glass‐etched micromodels with a typical waterflood geometrical configuration, i.e. five‐spot injection‐production pattern. The ASP flooding tests were conducted at constant injection flow rates but different fracture geometrical characteristics. The ASP solutions consisted of five polymers, two surfactants, and three alkaline types. It was found that using synthetic polymers, especially hydrolyzed polyacrylamide with high molecular mass, as well as cationic surfactant increases the ultimate recovery. The location of the injection well with respect to the fracture system plays a significant role in the ASP flooding performance, i.e. an increase in the angle associated with the longitudinal extension of fractures with respect to the main flow direction resulted in enhanced oil recovery and also postponed the wetting phase breakthrough time. Mechanistic study of this displacement process revealed that dispersive and diffusive behaviour of the ASP front enhanced the fluid transport from fracture to matrix and increased the microscopic displacement efficiency. Emulsification and coalescence mechanisms were responsible for ASP frontal advancement. Residual oil in the invaded region, which was observed in the form of discontinuous oil ganglia dispersed in the invaded pore bodies or in the form of pendular bridges formed around some of the solid particles, was mobilized in the form of oil wads through the droplets of the displacing phase.

Chemical EOR for Heavy Oil: The Canadian Experience

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169715, “Chemical EOR for Heavy Oil: The Canadian Experience,” by Eric Delamaide, SPE, IFP Technologies; Brigitte Bazin and David Rousseau, IFP Energies nouvelles; and Guillaume Degre, Solvay, prepared for the 2014 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 31 March–2 April. The paper has not been peer reviewed. Chemical enhanced-oil-recovery (EOR) methods such as polymer and alkaline/surfactant/polymer (ASP) flooding are generally not considered suitable for oil viscosities greater than 100 or 200 cp. However, this perception is changing, in particular because of field results from a number of chemical EOR pilots or full-field floods conducted in Canada in higher viscosity oil. The aim of this paper is to review some of these projects. Introduction Canada is well-known for its heavy-oil and bitumen reserves. Most of the bitumen reserves are exploited using thermal methods, such as cyclic steam stimulation or steam-assisted gravity drainage, while heavy oil is exploited mostly using cold production methods, such as cold heavy-oil production with sand. Cold production leads to recovery of less than 10% of original oil in place (OOIP). Thermal methods are not always applicable, in particular when the pay is thin. In that case, alternatives such as chemical EOR are required to increase recovery. The two main chemical EOR processes are polymer and ASP flooding. In the past 10 years, several chemical-flooding projects have taken place in Canadian heavy-oil fields. The most successful of these is the Pelican Lake project, which is currently producing more than 60,000 B/D, much of it through polymer flooding. But other less-well-known projects such as the Taber South project, the Mooney project, and the Seal project are all interesting and worthy of discussion. For full descriptions of these fields, please see the complete paper. Projects Pelican Lake Polymer Flood. The Pelican Lake field is approximately 250 km north of Edmonton, Alberta, Canada (Fig. 1). The recovery factor for primary production remained low even after the introduction of horizontal drilling. Thus, a first—unsuccessful—polymer flood was attempted in 1997, after which waterflood was also piloted. The waterflood managed to increase oil production but with high water cut. Thus, another polymer pilot was started in 2005. Polymer injection started in May 2005. The responses were excellent, with rates going from 18 to 232 BOPD in the first well, from 9 to 364 BOPD in the central well, and from 16 to 139 BOPD in the last well. The water cut increased slowly and moderately in all three wells. The operators estimate that polymer flooding will increase the recovery factor to 20 to 30% of OOIP.

A Mechanistic Integrated Geochemical and Chemical-Flooding Tool for Alkaline/Surfactant/Polymer Floods

SummaryMechanistic simulation of alkaline/surfactant/polymer (ASP) flooding considers chemical reactions between the alkali and the oil to form in-situ soap and reactions between the alkali and the minerals and brine. A comprehensive mechanistic modeling of such process remains a challenge, mainly caused by the complicated ASP phase behavior and the complexity of geochemical reactions that occur in the reservoir. Because of the lack of the microemulsion phase and/or lack of reactions that may lead to the consumption of alkali and resulting lag in the pH, a simplified ASP phase behavior is often used.A state-of-the-art geochemical package, IPhreeqc, of the United States Geological Survey was coupled with UTCHEM, an in-house research chemical-flooding reservoir simulator developed at The University of Texas at Austin (UT), for a robust, flexible, and accurate integrated tool to mechanistically model ASP floods. UTCHEM has a comprehensive three-phase (water, oil, microemulsion) flash package for the mixture of surfactant and soap as a function of salinity, temperature, and cosolvent concentration.Through this integrated tool, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, surface complexation, and ion exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium and kinetic conditions. Italic words are defined in Appendix A. IPhreeqc has rich databases of chemical species and also the flexibility to include the alkaline reactions required for modeling ASP floods. Hence, to the best of our knowledge, for the first time, the important aspects of ASP flooding are considered.An algorithm is presented for modeling the geochemistry in an implicit-in-pressure-and-explicit-in-concentration solution algorithm. Finally, we show how to apply the integrated tool, UTCHEM-IPhreeqc, to match three different reaction-related chemical-flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a nonacidic crude oil, and alkaline/cosolvent/polymer flooding.