Chemical Enhanced Oil Recovery Techniques Research Articles

Mathematical modeling of low salinity waterflooding in sandstone reservoirs: Enhanced Oil Recovery by multicomponent cation exchange

Low salinity waterflooding is the injection of water with a smaller salt concentration than the connate water. The control of the pH of injection water, and the amount of dissolved monovalent and divalent cations in the water affect the cation exchange in the reservoir and the mobilization of residual oil. In this work, the solution for the problem of low salinity slug injection driven by seawater considering three dissolved cations and pH effects is described. It was considered that the cations and H+ adsorbed on the rock follow a Langmuir adsorption isotherm type. The adsorption parameters of the cations depend on the water pH. The mathematical problem is split into three parts: a pH equation, a one-phase chromatographic system, and a scalar equation. First, the pH problem is solved, and its solution is used to calculate the one-phase chromatographic problem, and both results are applied in the scalar equation solution. Next, the solution is mapped onto the space-time plane. The solution shows that due to the high adsorption rate, the pH effects take place close to the injection point. Moreover, the high contrast between the adsorption rates of hydrogen and the other cations creates small regions where salinity changes. Cations separation in the porous media, similar to a chromatographic cycle, lead to the generation of several small oil and water banks along the porous media. The oil banks contain residual oil which was mobilized by the cation exchange. The analytical solution was compared with experimental data, showing close agreement. These results, mainly the relation between pH and salinity, and the appearance of water and oil banks along the flooding are new and important to the design of this chemical enhanced oil recovery technique.

Elucidation of the mechanistic aspects of chemical EOR in viscous oil systems

Chemical enhanced oil recovery techniques have been suggested as efficient alternatives to thermal methods in many thin/small viscous oil reservoirs in western Canada. These acidic oil reservoirs have been screened as good candidates for alkaline (A) and surfactant (S) floods. In this study, sand-pack core flooding experiments and pore-scale microfluidic tests were designed to give some new insights on the mechanisms of AS floods augmented with polymer (P) solutions in viscous oil systems.Viscous oil samples from Luseland field (14,850 mPa s at 25 °C) was used in all the experiments. The most efficient chemical generates ultralow interfacial tension, 0.002 mN/m, producing low viscosity type II (+) emulsion (740 mPa s, which is much lower than the viscosity of originating oil). The two pore volumes injection of this cocktail results in around 20% OOIP incremental oil recovery, which is almost doubled after injecting two pore volumes of extended water. The core effluents were all low viscosity oil in water emulsions, consistent with observations in batch mixing experiments. The incremental oil recovery to ASP flood is almost twice the recovery obtained in the polymer flood with nearly 4.5 times larger pressure build-up across the core. These observations suggest that the main mechanism is emulsification and oil entrainment rather than improvement in sweep efficiency.These speculated mechanisms based on the core scale observations were verified through the results of the microfluidic experiments. ASP solution can efficiently penetrate the residual ganglia or the edge of the water channels from which oil can be efficiently stripped. This oil is easily entrained in the form of low viscosity oil in water emulsions. Our results emphasize the critical role of polymer in the cocktail. In the absence of polymer, AS cannot efficiently penetrate the residual viscous oil leading to only a minuscule improvement in oil recovery.

Hydrolyzed Polyacrylamide Screening for EOR in an Indonesia Mature Oil Field

Most of Indonesia’s oil field has been producing the oil for long period of time. For this reason, enhanced oil recovery (EOR) method becomes the most promising method to improve oil production for the country. Chemical flooding, especially polymer flooding is the simplest and the most commonly applied chemical enhanced oil recovery technique, since it can be used after water flooding process. Screening is considered the first step in evaluating and selecting potential polymers for reservoirs. Therefore, this paper aims to select partially Hydrolyzed Polyacrylamide (HPAM) base polymers to find suitable polymer for a targeted mature reservoir in Indonesia. A polymer screening study was carried out on 3 HPAM polymers to identify a potential candidate which can withstand reservoir conditions. These are Kerui, Zekindo, and FP 3630S. Initially, a comprehensive rheological (viscosity, shear rate) study was conducted at various polymer concentrations (500 - 2500 ppm) and brine to investigate the polymers. Then, filtration and screen factor test was conducted at various concentrations (1000 - 2000 ppm). Then, a thermal stability test was conducted at anaerobic condition and 140 °F for 2 months. Finally, for oil recovery used core flooding test. Based on the result of the test, FP 3630S with a concentration of 2000 ppm was chosen for the core flooding test. The test was designed in 3 steps: At first, water injected into the sample, followed by polymer-solvent at 2000 ppm concentrated of 1 PV, the finally injected by water. The results of core flooding showed oil recovery of 28.93 % OOIP. Finally, this study was performed to develop screening criteria and to correlate oil recovery prediction.
 HIGHLIGHTS
 
 One of the efforts to increase old field production is by choosing the right type of polymer to be injected
 Polymer screening was carried out through testing stages, namely rheology, filtration and screen factor, thermal stability, and core flooding
 Selected one type of polymer that meets all the qualifications of the screening tests
 
 GRAPHICAL ABSTRACT

Hydrolyzed Polyacrylamide Screening for EOR in an Indonesia Mature Oil Field

Most of Indonesia’s oil field has been producing the oil for long period of time. For this reason, enhanced oil recovery (EOR) method becomes the most promising method to improve oil production for the country. Chemical flooding, especially polymer flooding is the simplest and the most commonly applied chemical enhanced oil recovery technique, since it can be used after water flooding process. Screening is considered the first step in evaluating and selecting potential polymers for reservoirs. Therefore, this research aims to select partially Hydrolyzed Polyacrylamide (HPAM) base polymers to find suitable polymer for a targeted mature reservoir in Indonesia. A polymer screening study was carried out on 3 HPAM polymers to identify a potential candidate which can withstand reservoir conditions. These are Kerui, Zekindo, and FP 3630S. Initially, a comprehensive rheological (viscosity, shear rate) study was conducted at various polymer concentrations (500 - 2500 ppm) and brine to investigate the polymers. Then, filtration and screen factor test was conducted at various concentrations (1000 - 2000 ppm). Then, a thermal stability test was conducted at anaerobic condition and 140 °F for 2 months. Finally, for oil recovery used core flooding test. Based on the result of the test, FP 3630S with a concentration of 2000 ppm was chosen for the core flooding test. The test was designed in 3 steps: At first, water injected into the sample, followed by polymer-solvent at 2000 ppm concentrated of 1 PV, the finally injected by water. The results of core flooding showed oil recovery of 28.93 % OOIP. Finally, this study was performed to develop screening criteria and to correlate oil recovery prediction.
 HIGHLIGHTS · One of the efforts to increase old field production is by choosing the right type of polymer to be injected · Polymer screening was carried out through testing stages, namely rheology, filtration and screen factor, thermal stability, and core flooding · Selected one type of polymer that meets all the qualifications of the screening testsGRAPHICAL ABSTRACT

Reducing surfactant retention using polyacrylate in Berea sandstone

The efficacy of surfactant flooding as a Chemical Enhanced Oil Recovery (EOR) method depends on the amount of the surfactant loss in the porous medium. Adding alkali to surfactant-polymer (SP) floods lowers surfactant adsorption/retention, but alkali has several key challenges that prevent operators from adopting it as the universal chemical EOR technique. Sodium polyacrylate has been successfully used as a sacrificial agent to reduce surfactant adsorption in static and dynamic adsorption tests. In this study, we evaluated the effect of sodium polyacrylate in Berea sandstone in the presence/absence of petroleum crude oil and compared dynamic adsorption/retention values with and without NaPA. Prior to corefloods, ultra-low interfacial tension surfactant formulations were identified using microemulsion phase behavior experiments for two different crude oils. Corefloods were conducted at corresponding optimum salinity of the surfactant formulations with a negative salinity gradient towards polymer drive. Surfactant concentration in effluent was measured by a high-performance-liquid-chromatography method (HPLC), and the adsorption/retention values were calculated by material balance. In our experiments, surfactant adsorption during single-phase corefloods (in the absence of crude oil) in Berea sandstone cores was found to be around 0.17–0.23 mg/g-rock; addition of a 0.5–1.0 wt % sodium polyacrylate decreased surfactant adsorption to 0.10 mg/g-rock. Surfactant retention in SP oil recovery corefloods in Berea sandstone cores without and with NaPA was found to be 0.20 mg/g-rock and 0.11 mg/g-rock, respectively.

Application of Novel Colloidal Silica Nanoparticles in the Reduction of Adsorption of Surfactant and Improvement of Oil Recovery Using Surfactant Polymer Flooding.

Surfactant polymer flooding is one of the most common chemical enhanced oil recovery techniques, which improves not only the microscopic displacement of the fluid through the formation of the emulsion but also the volumetric sweep efficiency of the fluid by altering the viscosity of the displacing fluid. However, one constraint of surfactant flooding is the loss of the surfactant by adsorption onto the reservoir rock surface. Hence, in this study, an attempt has been made to reduce the adsorption of the surfactant on the rock surface using novel colloidal silica nanoparticles (CSNs). CSNs were used as an additive to improve the performance of the conventional surfactant polymer flooding. The reduction in adsorption was observed in both the presence and absence of a polymer. The presence of a polymer also reduced the adsorption of the surfactant. Addition of 25 vol % CSNs effectively reduced the adsorption of up to 61% in the absence of a polymer, which increased to 64% upon the introduction of 1000 ppm polymer in the solution at 2500 ppm of the surfactant concentration at 25 °C. The adsorption of surfactant was also monitored with time, and it was found to be increasing with respect to time. The adsorption of surfactant increased from 1.292 mg/g after 0.5 days to 4.179 mg/g after 4 days at 2500 ppm of surfactant concentration at 25 °C. The viscosity, surface tension, and wettability studies were also conducted on the chemical slug used for flooding. The addition of CSNs effectively reduced the surface tension as well as shifted the wettability toward water-wet at 25 °C. Sand pack flooding experiments were performed at 60 °C to access the potential of CSNs in oil recovery, and it was found that the addition of 25 vol % CSNs in the conventional surfactant polymer chemical slug aided in the additional oil recovery up to 5% as compared to that of the conventional surfactant polymer slug.

Clay Analysis of Upper Assam Basin for Chemical Enhanced Oil Recovery

Abstract The success and failure of different chemical enhanced oil recovery (CEOR) techniques can control to a large extent by the presence of different types of clay, its surface area and the reactivity of the clay with the injected chemicals during CEOR techniques. Therefore, reservoir clay analysis is important to study the CEOR process in general and to formulate the CEOR slug in particular. This study pertains to the underground porous media of upper Assam basin. In this paper effective porosity, absolute permeability, minerals and clays present in porous media is studied. Effective porosities were determined to estimate the total pore volume and more importantly the connecting pores and the throat volumes. The absolute permeability are exclusively the properties of the porous media, which determines the ease of flow of fluid through the porous media. Rock petrography study was done by examining the thin sections under optical microscope, Scanning Electron Microscope (SEM) and X-ray Diffractometer (XRD). From these studies the mineral and clay content of the reservoir was characterized, which helps to study the feasibility of a CEOR in upper Assam basin. This petrography study provides two and three dimensional accurate description of minerals of reservoir rock and clay particles. The porous media is a sandstone with high porosity and low absolute permeability. The clays present are smectite, kaolinite and illite with a dominance of smectite and kaolinite, conforming to the swelling and disintegration.

Implications of hot chemical–thermal enhanced oil recovery technique after water flooding in shale reservoirs

Due to the applicability of hot water injection in the heavy oil production, it has considered as one of the efficient methods in recovery performances. However, its low viscosity has caused to produce lower oil in shale formations. Therefore, hybrid chemical enhanced oil recovery techniques such as foam injection with sequential carbon dioxide injection would be of important in the heavy oil production. In this paper, we aimed to consider induced hot carbon dioxide–foam enhanced oil recovery technique after water flooding at different temperatures. First, we investigated temperature impact on the resistance factor at different gas–oil ratios (henceforth; GOR). Then, polyacrylamide additive (PAM) at different concentrations were added to the foaming agent to increase the foam stability. Oil recovery factor and water cut were measured for each scenario. According to the results of these experiments, temperature increase would cause to resistance factor increase in which the temperature of 180 °C has the highest resistance factor. It is about 93%. Moreover, increase of GORs has caused to enhance the resistance factor. Polymer concentration increase has caused to resistance factor increase that is related to the polymer property to enhance the foam stabilization. Consequently, by the increase of temperature, water changes from liquid phase to gas or vapor and this is why it has decreased in the first steps of pore volume injection. Therefore, in the temperature of 180 °C, there is not any water cut in the first period of injection. Furthermore, higher polymer concentration would have an important role on the oil recovery increase.

Hybrid Chemical Enhanced Oil Recovery Techniques: A Simulation Study

Simultaneous utilization of surfactant and preformed particle gel (henceforth; PPG) flooding on the oil recovery enhancement has been widely investigated as a preferable enhanced oil recovery technique after the polymer flooding. In this paper, a numerical model is developed to simulate the profound impact of hybrid chemical enhanced oil recovery methods (PPG/polymer/surfactant) in sandstone reservoirs. Moreover, the gel particle conformance control is considered in the developed model after polymer flooding performances on the oil recovery enhancement. To validate the developed model, two sets of experimental field data from Daqing oil field (PPG conformance control after polymer flooding) and Shengli oil field (PPG-surfactant flooding after polymer flooding) are used to check the reliability of the model. Combination of preformed gel particles, polymers and surfactants due to the deformation, swelling, and physicochemical properties of gel particles can mobilize the trapped oil through the porous media to enhance oil recovery factor by blocking the high permeable channels. As a result, PPG conformance control plays an essential role in oil recovery enhancement. Furthermore, experimental data of PPG/polymer/surfactant flooding in the Shengli field and its comparison with the proposed model indicated that the model and experimental field data are in a good agreement. Consequently, the coupled model of surfactant and PPG flooding after polymer flooding performances has led to more recovery factor rather than the basic chemical recovery techniques.

Impact of anionic and cationic surfactants interfacial tension on the oil recovery enhancement

Surfactant flooding is considered as one of the efficient chemical enhanced oil recovery techniques in recent decades as it has the potential ability to alter the wettability and reduce the interfacial tension of water-oil. Addition of surfactants has caused a dramatic decrease in the interfacial of water-oil. Thereby, the capillary number has increased and has caused to enhance oil mobilization in the porous media. In this paper, a cationic surfactant of Cetyl trimethyl ammonium bromide and an anionic surfactant of linear alkylbenzene sulfonic acid were used to consider their effect on the interfacial tension and oil recovery factor. According to the results of this study, the anionic surfactant of linear alkylbenzene sulfonic acid has the highest recovery factor of 70%, and cationic surfactant of Cetyl trimethyl ammonium bromide has the second-highest oil recovery factor of about 55%. Therefore, the addition of surfactants due to its beneficial impact on the interface adsorption between oil and water would be an essential point on the oil recovery enhancement as it can increase the oil recovery factor. Moreover, the critical micelle concentration value is about 300 ppm and 250 ppm for anionic and cationic surfactants respectively where the two crosslines meet each other and anionic has the highest interfacial tension rather than cationic which has caused to have more oil recovery factor.

A mathematical model to evaluate the polymer flooding performances

Due to the enormous demand for crude oil, the selection of appropriate and economical techniques to enhance the oil recovery are always considered as the major concerns in reservoir developments. Polymer flooding is considered as one of the chemical enhanced oil recovery techniques especially for heavy oil reservoirs by the sweep efficiency improvement. The objective of this study is to perform a mathematical model to evaluate the polymer flooding performances in the presence of saturation profile and cross flow effect to validate the accuracy of the model with simulated field data. Thereby, the results of this developed model indicate that the model is approximately matched with the simulated field data rather than previous models. Furthermore, some geological problems such as high permeable channeling and semi-sealing issues are considered in the model to calculate the pressure integral and how each parameter would change regarding the cumulative pore volume alteration. Consequently, the proposed model would be an appropriate choice to verify the pressure integral which is compared with the simulated field data by the consideration of saturation distribution and cross flow effect.

Surfactant flooding: The influence of the physical properties on the recovery efficiency

Enhanced Oil Recovery (EOR) processes aim at increasing the performance and operative life of oilfields while newer, greener and more efficient energy sources are developed. Among the chemical EOR techniques, surfactant flooding is one of the most well-known methods, applied mainly in low- and medium-viscosity oilfields. Surfactants diminish the interfacial energy between the oleous and aqueous phases, reducing the forces responsible of the capillary trapping phenomenon and mobilizing the remaining oil. This paper presents the study of a novel two-dimensional surfactant flooding simulator for a four-component (water, petroleum, chemical, salt), two-phase (aqueous, oleous) system in porous media. It is aimed mainly at discussing the influence of the physical phenomena present in the reservoir during the recovery, namely: rock compressibility, diffusion, capillary pressure and adsorption. The system is numerically solved using a second-order finite difference method using the IMPEC (IMplicit Pressure and Explicit Concentration) scheme. The oil recovery factor was negatively affected when these phenomena were considered, being strongly sensitive to the adsorption. The other phenomena decreased the efficiency of the process to a lesser extent, whilst the capillary pressure did not affect significantly the flooding performance. The presence of salt in the reservoir rendered the adsorption process more relevant, with water-in-oil emulsions being more sensitive to the presence of this fourth component. This paper shows the importance of the design and optimization of chemical agents to be used in EOR before its field application.

The effect of surfactant concentration, salinity, temperature, and pH on surfactant adsorption for chemical enhanced oil recovery: a review

Enhanced oil recovery (EOR) processes have a great potential to maximize oil recovery factor of the existing reservoirs, where a significant volume of the unrecovered oil after conventional methods is targeted. Application of chemical EOR techniques includes the process of injecting different types of chemicals into a reservoir to improve the overall sweep efficiency. Surfactant flooding is one of the chemical EOR used to reduce the oil–water interfacial tension and to mobilize residual oil toward producing wells. Throughout the process of surfactant flooding, selecting a suitable surfactant for the reservoir conditions is quite challenging. Surfactants tend to be the major factor associated with the cost of an EOR process, and losing surfactants leads to substantial economic losses. This process could encounter a significant loss of surfactant due to adsorption into the porous media. Surfactant concentration, salinity, temperature, and pH were found to be as the main factors that influence the surfactant adsorption on reservoir rocks. Most of the research has been conducted in low-temperature and low-salinity conditions. Only limited studies were conducted in high-temperature and high-salinity (HT/HS) conditions due to the challenging for implementation of surfactant flooding in these conditions. This paper, therefore, focuses on the reviews of the studies conducted on surfactant adsorption for different surfactant types on different reservoir rocks under different reservoir conditions, and the influence of surfactant concentration, salinity, temperature, and pH on surfactant adsorption.

Simultaneous feasible injectivity of foam and hydrolyzed polyacrylamide to optimize the oil recovery enhancement

Foam flooding is considered as one of the beneficial chemical enhanced oil recovery techniques to increase the value of gas viscosity and thereby, the efficiency of the produced oil would be improved dramatically rather than other methodologies. The objective of this extensive study is to determine a suitable injectivity model for one of the heterogeneous sandstone reservoir in which hydrolyzed polyacrylamide concentration in the solution foam has the most recovery factor. To do this, the results of laboratory investigation and simulation analysis are taken into consideration in different injectivity scenarios to obtain the more efficient scenario. Consequently, higher concentration of hydrolyzed polyacrylamide in the foaming agent, the high volume of oil has been produced after 10 years of producing. Furthermore, by selecting three cores from the three wells in this field, it is clarified that, owing to the increasing the volume of foam in the injectivity fluid, the pressure drop increased dramatically and subsequently has leaded to produced more oil volume.

Statement of Removal

ABSTRACTPolymer flooding is an attractive branch of chemical enhanced oil recovery techniques. Regrettably, chemical and mechanical degradation reduces the effectiveness of polymer flooding. This paper explores the effects of silica nanoparticles on flow behavior of polymer solution in porous media by employing both rheological experiments and numerical simulations. Experimental results indicate that dispersed silica nanoparticles in polymer solution are responsible for polymer adsorption reduction and the solution viscosity improvement. Simulation results revealed that if the injectant has some dispersed silica nanoparticles, the cumulative heavy oil recovery and breakthrough time will be bettered compared to the conventional polymer flood.

Effect of Alkyl Ammonium Ionic Liquids on the Interfacial Tension of the Crude Oil–Water System and Their Use for the Enhanced Oil Recovery Using Ionic Liquid-Polymer Flooding

Crude oil recovery from matured reservoir still pose challenges due to the low efficiency of the existing enhanced oil recovery (EOR) methods. The chemical enhanced oil recovery technique is one of the potential EOR technique being used to produce trapped oil from mature reservoirs. One of the key challenge for chemical-EOR process is that the conventional surfactants does not show efficacy toward reduction in interfacial tension and oil recovery under high saline and high temperature conditions. Ionic liquids (ILs) can be one of the potential alternative for possible application in chemical-EOR due to their enhanced stability under high saline and thermal conditions. In this investigation, six different alkyl ammonium ILs and sodium dodecyl sulfate (SDS) have been investigated for their effect on the interfacial tension (IFT) of low waxy crude oil–water system (with and without salt) as a function of temperature (283.15–353.15 K) and for EOR-flooding process. Water-soluble polymer (polyacrylamide) was us...

Efficient Scheme for Chemical Flooding Simulation

In this paper, we investigate an efficient implicit scheme for the numerical simulation of chemical enhanced oil recovery technique for oil fields. For the sake of brevity, we only focus on flows with polymer to describe the physical and numerical models. In this framework, we consider a black oil model upgraded with the polymer modeling. We assume the polymer only transported in the water phase or adsorbed on the rock following a Langmuir isotherm. The polymer reduces the water phase mobility which can change drastically the behavior of water oil interfaces. Then, we propose a fractional step technique to resolve implicitly the system. The first step is devoted to the resolution of the black oil subsystem and the second to the polymer mass conservation. In such a way, jacobian matrices coming from the implicit formulation have a moderate size and preserve solvers efficiency. Nevertheless, the coupling between the black-oil subsystem and the polymer is not fully resolved. For efficiency and accuracy comparison, we propose an explicit scheme for the polymer for which large time step is prohibited due to its CFL (Courant-Friedrichs-Levy) criterion and consequently approximates accurately the coupling. Numerical experiments with polymer are simulated : a core flood, a 5-spot reservoir with surfactant and ions and a 3D real case. Comparisons are performed between the polymer explicit and implicit scheme. They prove that our polymer implicit scheme is efficient, robust and resolves accurately the coupling physics. The development and the simulations have been performed with the software PumaFlow [PumaFlow (2013) Reference manual, release V600, Beicip Franlab].

Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

Several researchers have proposed that mobility control mechanisms can positively contribute to oil recovery in the case of emulsions generated in Enhanced-Oil Recovery (EOR) operations. Chemical EOR techniques that use alkaline components or/and surfactants are known to produce undesirable emulsions that create operational problems and are difficult to break. Other water-based methods have been less studied in this sense. EOR processes such as polymer flooding and LoSalTM injection require adjustments of water chemistry, mainly by lowering the ionic strength of the solution or by decreasing hardness. The decreased ionic strength of EOR solutions can give rise to more stable water-in-oil emulsions, which are speculated to improve mobility ratio between the injectant and the displaced oil. The first step toward understanding the connection between the emulsions and EOR mechanisms is to show that EOR conditions, such as salinity and hardness requirements, among others, are conducive to stabilizing emulsions. In order to do this, adequate stability proxies are required. This paper reviews commonly used emulsion stability proxies and explains the advantages and disadvantage of methods reviewed. This paper also reviews aqueous-based EOR processes with focus on heavy oil to contextualize in-situ emulsion stabilization conditions. This context sets the basis for comparison of emulsion stability proxies.