Polymer Injection Research Articles

Experimental investigation on plugging performance of CO2 microbubbles in porous media

To further improve carbon dioxide enhanced oil recovery CO2-EOR efficiency in heterogeneous reservoirs, the use of CO2 microbubbles as a temporary blocking agent is attracting widespread interest due to their significant stability. This study aims to investigate the plugging performance of CO2 microbubbles in both homogeneous and heterogeneous porous media through a series of sandpack experiments. First of all, CO2 microbubble fluids were generated by stirring CO2 gas diffused into polymer (Xanthan gum (XG)) and surfactant (Sodium dodecyl sulfate (SDS)) solution with different gas: liquid ratios. Then, CO2 microbubbles fluids were injected into single-core and dual-core sandpack systems. The results show that the rheological behaviors of CO2 microbubble fluids in this study were followed the Power-law model at room temperature. The apparent viscosity of CO2 microbubble fluid increased as the gas: liquid ratio increased. CO2 microbubbles could block pore throat due to the “Jamin effect” and increase the resistance in porous media. The blocking ability of CO2 microbubbles reached an optimal value at the gas:liquid ratio of 20% in the homogeneous porous media. Moreover, the selective pugging ability of CO2 microbubbles in dual-core sandpack tests was significant. CO2 microbubbles exhibited a good flow control profile in the high permeability region and flexibility to flow over the pore constrictions in the low permeability region, leading to an ultimate fractional flow proportion (50%:50%) in the dual-core sandpack model with a permeability differential of 1.0:2.0 darcy. The fractional flow ratio was considerable compared with a polymer injection. At the higher heterogeneity of porous media (0.5:2.0 darcy), CO2 microbubble fluid could still establish a good swept performance. This makes CO2 microbubble fluid injection a promising candidate for heterogeneous reservoirs where conventional CO2 flooding processes have limited ability. This finding would be helpful in developing the utilization of CO2 microbubbles in EOR operation by better understanding their plugging mechanism in porous media.

A novel method for calculating polymer adsorption in fractures through a dual porosity model

Increasing demand for energy and limited capacity of available resources of fossil fuels have drawn attention to enhanced oil recovery for maximum use of the available resources. Among different enhanced recovery methods, polymer injection maintains the advantages of water flooding, including the simplicity of this technique, while eliminating some of its drawbacks such as high mobility of the injected water. Therefore, mechanisms involved in the flow of polymer in the reservoirs need to be well understood and modeled. An important phenomenon affecting the flow of polymer in the oil reservoirs is polymer adsorption on reservoir rock. In fractured reservoirs, the polymer is adsorbed both in the matrix and the fracture. Miscalculation of the amount of adsorbed polymer results in the miscalculation of the fracture permeability on one hand, and concentration of dissolved polymer on the other. This, in turn, leads to over- or under-estimation of polymer injection performance in fractured reservoirs. An important tool for simulating fractured reservoirs is dual-porosity models. The models, however, may not correctly estimate polymer adsorption in fractures. This is attributable to the assumptions used in the dual-porosity model and the nature of adsorption. The present study attempts to improve the way this phenomenon is modeled by dual-porosity models. A new parameter called “pseudo-density” is defined here to replace the density of the fracture cells in the dual-porosity model for polymer adsorption. Then, a hypothetical reservoir is simulated using this new parameter, and the results of the two simulations, one with density and the other with pseudo-density, are compared in terms of three parameters, including the polymer adsorbed in the reservoir, the polymer dissolved in the aqueous phase, and the polymer produced in the reservoir. The results show that using pseudo-density instead of rock density decreases the required polymer amount to reach the maximum polymer concentration. Consequently, polymer solution viscosity and permeability reduction are increased. Furthermore, it results in increasing the polymer production compared to the conventional dual-porosity models.

Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

Insights into oil recovery mechanism by Nothing-Alternating-Polymer (NAP) concept

This paper introduces new oil recovery mechanisms for oil recovery by polymer injection in heavy oil reservoirs with strong bottom aquifers. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, for the case demonstrated in this paper, a polymer injection pilot was executed with three horizontal injectors, located a few meters above the oil/water contact. The injectivity issues resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with intentional well shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP).It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer squeezes the existing cones and creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The resistance caused by polymer adsorption reduces the extent of fingering of water into polymer bank. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.

On the reduction of the residual oil saturation through the injection of polymer and nanoparticle solutions

Polymer flooding has been traditionally applied to achieve favorable mobility ratios compared to water flooding, and thus increase formation sweep efficiency in oil displacement processes. Based on laboratory studies, several authors have reported lower residual oil saturations, Sorc, to the waterflood residual oil saturation, Sorw, when viscoelastic polymers were used during polymer flooding. The reported mechanisms contributing to the observed reduced residual oil saturation include mobility control, improved sweep efficiency, and improved microscopic displacement efficiency. The limitations of polymer flooding are obvious: high oil viscosity requires high concentration of polymer which increases the process cost, presence of clays which increases polymer adsorption, formation brine and water make-up salinity and type of ions which will affect the injected polymer viscosity, and extensively fractured formations which will cause sweep challenges. This review paper summarizes the most recent research findings, observations, conclusions, and reported physical mechanisms contributing to more efficient oil displacement processes and lower than Sorw residual oil saturation. The discussion focuses on viscoelastic polymer oil displacement processes and includes formation water and polymer solution salinity, resistance factor (RF), and polymer molecular weight effects. The use of nanoparticles (NPs) during polymer flooding is examined and results obtained are also reported in this review. More specifically, the polymer-NP system rheological behavior for several different types of NPs and surface modified silica NP are examined to find the most efficient system for oil displacement. Mechanisms contributing to more effective oil displacement processes when carefully screened NPs are added into the viscoelastic polymer solutions include interfacial tension reduction, formation wettability alteration, increased injected polymer solution viscosity, and prevention of asphaltene precipitation.

Adjustment method and understanding of water-cut recovery period in polymer injection block

Taking an injection station in polymer injection block (BLOCK A) as an example, this paper proposed a series of measures such as stratification polymer injection and regional overall profile control to improve the development effect and further enhance the final recovery factor of the block in view of the problems of low injection pressure in individual areas, profile in thrust and high comprehensive water cut of produced Wells in the block. It provides some basis and reference for production and development of other polymer injection blocks.

Fluid dynamics analysis and performance of polymer flow regulators for polymer flooding in multilayered reservoirs

Polymer flooding, a high viscosity solution of water and polymer, is introduced as an enhancement of oil recovery methods which is pumped through injector wells to push the liquid hydrocarbon towards production wells. Nowadays, the polymer injections method through layers for different flow admissions has allowed the improvement of heterogeneous flow distribution and the oil recovery factor itself. However, choke valves are needed to get the flow control in admission layers. Nevertheless, any flow obstruction affects the polymer viscosity via mechanical degradation. The shear stress in a standard orifice waterflood regulator breaks down the polymer molecule, causing viscosity loss, and hence reducing the recovery factor properties. In order to avoid shear degradation, several proposal nonstandard regulators of flow/pressure control options have been selected. In this work, experimental and computational studies were made to evaluate the design performance of pressure regulators to inject a polymer solution. The intermittent flow patterns concept has gotten a superior performance. The experimental data from this shock absorber has shown the average viscosity loss being less than 10% and pressure drop up to 34.5 bar with a polymer concentration of up to 700 mg/L, high flowrate around 89 m 3 /d and average salinity water was used to prepare the polymer solution. It was confirmed that the computational results have achieved a good match with experimental data. These results will validate regulator design, and improve cost estimation, saving materials and additional water treatment facilities. • Polymer flood regulator must be a static choke to guarantee the shear control. • There should be a specific choke for each flow-rate. • The shear rate is the main issue of polymer mechanical degradation. • High pressure drop does not induce directly the polymer degradation. • The fluid path longitude is an important issue to design a polymer flood regulator.

Laboratory study of polymer injection into heavy oil unconventional reservoirs to enhance oil recovery and determination of optimal injection concentration

<abstract> <p>Polymers have been used for many years to control the mobility of injected water and increase the rate of oil extraction from unconventional reservoirs. Polymer flossing improves the volume of the broom, reduces the finger effect, creates channels, and delays water breakage. The combination of these processes has the potential to increase oil production and reduce production costs. To carry out this process, various polymers are used alone or in combination with surfactants and alkalis. In this study, a new type of polymer called FLOPPAM 3630 has been used to investigate the overload of very heavy oil reservoirs. For this purpose, six polymer solutions with different concentrations were made, and stability tests on shear rate, time, and temperature were performed. The polymer's stability results indicate that it is stable under other shear rate, temperature, and time passage conditions. As a result, this polymer is a suitable candidate for conducting silicification tests in reservoir temperature conditions. Then three more suitable polymer solutions were selected, and the polymer was polished. The results showed that the solution with a concentration of 1000 ppm has the best yield of about 40%. The reason for the good efficiency of this concentration is that the surface and vertical sweepers are higher than the other concentrations. Also, the difference in efficiency between less than 1000 and 2000 ppm is greater because it is more economical, and its injectability is easier to use with less concentration. Furthermore, the oil efficiency of this type of polymer in sandblasting is higher than that of other polymers tested under these conditions, making its use more economical.</p> </abstract>

Experimental study on constant pressure of polymer flooding in second-class reservoirs

At present, the second-class oil layer has become the main polymer flooding replacement layer in the Lamadian Oilfield. The second-class oil layer has low permeability, low connectivity and serious heterogeneity. The results of the polymer flooding laboratory experiments are quite different from the field flooding effect. Polysystem design provides better guidance. Based on theoretical and field data analysis, this paper adopts constant pressure injection method. After the experimental injection fluid is seepage through a 1.5m long core, the core flooding experiment is carried out, that is, the problem of excessive pressure rise in polymer flooding is controlled, so that the injection fluid is closer to the oil layer. state of the injected system. The constant pressure polymer flooding experiment was used to establish the matching relationship between the polymer system and oil layers with different permeability, which effectively guided the design of the on-site polymer injection system. At present, indoor polymer flooding core experiments generally adopt the constant speed mode, without controlling the injection pressure. However, due to the influence of permeability, connectivity and other factors, the injection pressure increases greatly, and the reservoir water absorption is difficult, which leads to a great difference between the experimental results and the field effect. In order to make the indoor core experiment closer to the actual field injection state and better guide the design of polymer flooding scheme, it is urgent to optimize and improve the experimental method.

Numerical simulation of polymer flooding in water flooding reservoir

Different influencing factors in the process of polymer flooding have different degrees of influence on the development effect, so it is necessary to carry out the dynamic prediction of polymer flooding before implementing the development scheme. In this study, the reservoir model of C Block is established and the production performance is fitted. The fitted reservoir model is used to study the influence of polymer concentration, injection time, injection rate multiple and injection timing on the development effect of C Block. The results show that the cumulative oil production increases gradually with the increase of polymer concentration, and combined with the principle of economic development, there is an optimal polymer concentration in C Block, which is 0.15 wt%; With the increasing of injection time and injection rate multiple, the cumulative oil production and incremental oil production (compared with water flooding) show an increasing trend; For injection timing, the earlier polymer injection is more conducive to obtaining higher cumulative oil production and oil increment. The cumulative oil production under the optimal development scheme of C block is 23.8494×104 m3, which is 1.5042×104 m3 higher than that of water flooding.

Enhancement of oil recovery by surfactant-polymer synergy flooding: A review

With the depletion of conventional resources, it is necessary to enhance the recovery of remaining oil. The tertiary oil recovery chemical flooding is the most promising for enhanced oil recovery (EOR). The use of alkali in chemical flooding produces fouling with the formation, which brings new challenges to chemical flooding EOR. So, alkali-free surfactant-polymer (SP) flooding is used as a new solution for EOR. The polymer makes the displacing fluid have a high viscosity and increases the swept volume. The surfactant can decrease the interfacial tension and emulsify the crude oil while the displacing fluid reaches the corresponding area. The synergistic effect of the two is more conducive to the recovery of the remaining oil. As a result, SP flooding is a more practical approach to enhance oilfield EOR. The research status of several surfactant and polymer types for EOR is reported in this work. According to the study, complex and anionic surfactants are better for EOR. For difficult formations, SP flooding is more suited because of the presence of polymers. Additionally, study analysis demonstrates that SP flooding and alternative polymer injection, when employed at the same cost, can enhance EOR and assist in resolving issues brought on by low oil prices.

Nanometric Measurement of Microcavity Filling During Polymer Injection Moulding Using Interferometric Sensing

Nanometric Measurement of Microcavity Filling During Polymer Injection Moulding Using Interferometric Sensing

Research on Fast Ultrasonic Phased Array Imaging of High-performance Polymer Injection Molded Components

Research on Fast Ultrasonic Phased Array Imaging of High-performance Polymer Injection Molded Components

The Study of Flow Behavior and Performance of Polymer Injection in Homogenous Porous Media Using Etched Micromodel

The implementation of polymer injection on a field scale needs a preliminary laboratory test to analyze the performance and flow behavior of polymer injection in a porous media. Compared to coreflooding method, micromodel provides the visualization of oil displacement mechanism and facilitating a more detailed process description. Understanding the effect of polymer concentration on the incremental of oil recovery factor and its displacement mechanism are essential to know the polymer injection performance with the intention of avoiding failures in the implementation of polymer injection at field scale. We used dry etching technique for the fabrication of acrylic micromodel with homogenous characteristic. In this work, pre-flush (waterflooding) is performed first before doing the polymer injection to determine the incremental oil recovery factor and analyze the effect of polymer concentration on oil recovery factor enhancement in homogenous porous media. They were positioned horizontally then saturated with synthetic brine and light crude oil as the initial condition before starting the injection scenario. The experiment was conducted at room temperature. The entire process of micromodel flooding test was monitored by camera and then for the further analysis was done using Digital Image Analysis (DIA). According to the polymer rheology and aqueous stability test, it can be proven that polymer is a non-newtonian fluid indicated by shear thinning behavior and it can be observed that FP3630S polymer is a good candidate for micromodel flooding test. The micromodel flooding result confirmed that the increasing of polymer concentration will result in higher incremental oil recovery factor. In addition, based on the final condition of the micromodel after the polymer injection process, there is improvement of sweep efficiency due to the front stability resulted by the decreasing of mobility ratio between displacing fluid (polymer solution) and the oil bank.

The Effect of Surfactant Polymer Concentration on the Distribution of Oil Drainage Area in Heterogeneous Reservoir


 
 
 The use of chemical injection has been widely used in the oil field on a large scale. One of the enhanced oil recovery (EOR) methods to increase production from old oil fields is through polymer surfactant injection, which functions to reduce interfacial tension and water-oil mobility ratio. This study focuses on developing a simulation model for chemical injection of polymer surfactant reservoirs by hypothetically making heterogeneous reservoir models in each layer with dimensions of 10x10x4. It consists of one a vertical well which is producer well located at the top of the left corner and one an injection well which is located at the bottom of right corner. This study shows a comparison between surfactant injection, polymer injection and SP injection using the same surfactant and polymer concentration with a concentration of 1000 ppm with 0.3 PV. Oil recovery in polymer injection turned out to be quite high compared to other chemical injections. In polymer injection, the oil recovery was 4.17%. Meanwhile, surfactant injection and SP injection increased by 0.59% and 0.61, respectively.
 
 

Effect of the Glass Fiber Content of a Polybutylene Terephthalate Reinforced Composite Structure on Physical and Mechanical Characteristics.

This work presents the influences of glass fiber content on the mechanical and physical characteristics of polybutylene terephthalate (PBT) reinforced with glass fibers (GF). For the mechanical characterization of the composites depending on the GF reinforcement rate, tensile tests are carried out. The results show that increasing the GF content in the polymer matrix leads to an increase in the stiffness of the composite but also to an increase in its brittleness. Scanning Electron Microscope analysis is performed, highlighting the multi-scale dependency on types of damage and macroscopic behavior of the composites. Furthermore, flammability tests were performed. They permit certifying the flame retardancy capacity of the electrical composite part. Additionally, fluidity tests are carried out to identify the flow behavior of the melted composite during the polymer injection process. Finally, the cracking resistance is assessed by riveting tests performed on the considered electrical parts produced from composites with different GF reinforcement. The riveting test stems directly from the manufacturing process. Therefore, its results accurately reflect the fragility of the material used.

Study on Countermeasures for Increasing Polymer Injection Viscosity of Chemical Flooding in Shu3 Area

Study on Countermeasures for Increasing Polymer Injection Viscosity of Chemical Flooding in Shu3 Area

The optimization and economic evaluation of oil production using low salinity polymer flood: a case study for EOR 26

Trinidad and Tobago (TT) have been producing crude oil commercially since 1908. For the past few decades, TT’s crude oil production has been in steady decline because most of the oil reservoirs are beyond the primary phase of their production. This situation coupled with lower energy prices have resulted in a shortfall in TT’s energy revenues and presents TT with major economic challenges. The objective of this study was to optimize a field simulation model of a combined Low Salinity Polymer Gel flood to highlight the possibility that Enhanced Oil Recovery (EOR) can boost crude oil production especially from heavy oil reserves and mature fields. A field simulation model of the EOR 26 Upper Forest Sands was built using the CMG Builder software. The EOR 26 Upper Forest Sand reservoirs of the Forest Reserve field are delineated by shale-outs, faults and water–oil contacts. The entire Forest Reserve is bordered by the Fyzabad anticline to its north-west and the Los Bajos fault to its south-west. A dynamic field simulation model of the combined Low Salinity Polymer Gel flooding of EOR 26 Upper Forest Sands was created using CMG STARS software and the optimum parameters of polymer gel concentration, salinity concentration and injection rates and pressure for the highest oil recovery were investigated. The highest oil recovery was obtained using a polymer gel concentration of 500 ppm with a salinity of 1000 ppm and an injection rate of 900 bbls/day during continuous polymer gel injection for a period of 545 days. The polymer gel injection was preceded by pre flush water injection for 180 days and followed by water injection for the duration of the ten (10) year period. The predicted oil recovery for the project is an additional 14.52% of OOIP and is considered economically feasible at a crude oil price of US$50 per barrel with a payback period of two years and an IRR of 63.53%.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

Influence of the Sintering Conditions on the Structure, Phase Composition, and Porosity of Titanium Alloy VT6 Parts Formed by Powder–Polymer Injection Molding

Influence of the Sintering Conditions on the Structure, Phase Composition, and Porosity of Titanium Alloy VT6 Parts Formed by Powder–Polymer Injection Molding