Polymer Injection Research Articles

A natural polymer extracted from Chia seeds for application in chemical enhanced oil recovery by taper polymer concentration (TPC) and alkali-polymer (AP) slug injection into sandstone oil reservoirs

In this research, the extracted mucilage from Chia seeds is introduced as a new natural polymer for use in polymer injection into oil reservoirs. Chia seeds polymer (CSP) is environmentally friendly, economical, efficient and available, and its industrial production and extraction are done in the world for use in various applications. Polymer fluid injection was performed under two polymer injection scenarios: taper polymer concentration (TPC) and alkali-polymer (AP) slug injection. CSP is stable up to salinity above 90,000 ppm and also maintains its performance at reservoir temperature. The viscosity changes of CSP solutions against shear rate confirm its non-Newtonian behavior, which increases in intensity with increasing CSP concentration. The CSP hydrocolloid increases the viscosity of the injection fluid at low concentrations to suitable values for EOR. In this way, the viscosity values of polymer solutions at concentrations of 200, 400, 600, 800, 1000 and 1200 ppm were equal to 27.14, 42.36, 68.11, 93.75, 125.62 and 154.51 mPa.s, respectively. Although the viscosity of CSP solutions decreases with increasing salinity and temperature, there is no sharp drop and the obtained values are suitable even at high salinity and temperature. The hydrophilicity of the sandstone reservoir rock is proportional to the increase in CSP concentration. The contact angle sizes at concentrations of 600, 800, 1000 and 1200 ppm were obtained as 84.98°, 78.04°, 70.39° and 67.69°, respectively. CSP injection under both scenarios reduces the water-cut well and oil recovery is increased by 21.2% and 16.3% by TPC and AP injection, respectively.

Polymer Injection as a Development Strategy to Improve Oil Recovery in the BKH Layer of YDP Field

There are still have a potential oil to be produced, the reduced reservoir pressure due to continuous oil production at a high rate, and the high water cut value are the background for the polymer injection process in the BKH Layer of YDP Oil Field. Due to a high water cut value, the study then conducted using a polymer injection method. Screening criteria for polymers injection was conducted to see the suitability of the reservoir, and then carry out an advanced scenarios using polymers of various concentrations to be compared, and see a cumulative incremental oil production and recovery factor. The stages including collecting and preparing data, processing and analyzing RCAL, SCAL, and PVT data, input data to simulation model with actual conditions. The reservoir simulation performed including initialization, history matching and PI matching, carry out polymer injection scenarios with certain polymer concentrations, then predict and analyze the scenario results, and finally determine the best polymer injection scenario to be applied in the BKH layer of YDP field. Based on the results of the study, it is shows that the scenario IV-A is the best scenario for polymer injection compared to other scenarios. Scenario IV-A performed by injection of polymer with a peripheral pattern with an additional 5 (five) injection wells, injection pressure of 1200 psi, injection rate of 300 bbl/d, polymer concentration of 0.6 lb/bbl, incremental recovery factor of 2.01%, and oil production cumulative obtained until December 2035 is 5087 MSTB.

Enhancing the Fatigue Strength of the Weld Line in Advanced Polymer Injection Molding: Gas-Assisted Mold Temperature Control for Thermoplastic Polyurethane (TPU) Composites.

This study presents an innovative approach to enhancing weld line strength in advanced polymer injection molding through applying gas-assisted mold temperature control, significantly increasing mold temperature beyond typical values observed in conventional processes. We investigate the effects of various heating times and frequencies on the fatigue strength of Polypropylene (PP) samples and the tensile strength of Acrylonitrile Butadiene Styrene (ABS) composite samples at different Thermoplastic Polyurethane (TPU) percentages and heating times. Using gas-assisted mold heating, mold temperatures exceeding 210 °C are achieved, which represents a significant advancement compared to the standard mold temperatures of less than 100 °C. As a result, the fatigue strength of the PP sample with mold heating at 15 s shows a remarkable increase of up to 5.4 times at 5 Hz compared to the sample without mold temperature control. Moreover, ABS/TPU blends with 15 wt.% TPU exhibit the highest ultimate tensile strength (UTS) value of 36.8 MPa, while blends with 30 wt.% TPU have the lowest UTS value of 21.3 MPa. This advancement demonstrates the potential for improved welding line bonding and fatigue strength in manufacturing. Our findings reveal that increasing the mold temperature before injection results in higher fatigue strength in the weld line, with the TPU percentage having a more significant influence on the mechanical properties of ABS/TPU blends than heating time. The results of this study contribute to a deeper understanding of advanced polymer injection molding and offer valuable insights for process optimization.

Development of an in situ emulsifying/ultra-low-interfacial-tension cyclic flooding system for medium- and low-permeability reservoirs

Medium- and low-permeability reservoirs are important in oilfield development. However, due to their characteristics of poor pore permeability and high heterogeneity, the development of suitable technologies has been very difficult. In this study, an in situ emulsifying/ultra-low-interfacial-tension cyclic flooding system has been developed for low- and medium-permeability reservoirs. Based on the hydrophilic-lipophilic balance (HLB) value method, an emulsifying surfactant ASD with Span 80 (sorbitan monooleate) as the main component has been identified as highly promising through screening. At mass fractions of surfactant ASD between 0.2% and 0.6%, the extent of water separation from the emulsion is greatly reduced, and the W/O emulsion can effectively improve the mobility ratio and increase the sweep volume. The surfactant SA synthesized in our laboratory reduces the interfacial tension of crude oil to 10−4 mN m−1. Laboratory core flooding experiments have shown that multiple rounds of alternating injection with aqueous solutions of surfactants ASD and SA can improve oil recovery by 22.25%. Upon injecting a low-viscosity aqueous solution of surfactant ASD, it emulsifies crude oil in situ under reservoir conditions, solving the problems of difficult polymer injection and insufficient spread. Our work provides useful insights for the development of low- and medium-permeability reservoirs.

Pectin Extraction From Orange Peel With Microwave-Assisted Extraction Method as an Alternative Material in Polymer Injection

The problems of degradation on oil production can be solved by chemical EOR (Enchanced Oil Recovery) methods, polymer injection is the one kind of chemical EOR methods. When the polymer fluids injected in to reservoir then it will be increase the oil sweep efficiency and fixed the mobility ratio of the injected fluids. The sample that will be tested in this experiments is biopolymer. Besides the xanthan gum that extracted by using bacterial, in side the plant contained a compound as know as paectin, it is a derived from the polysaccharide. So far the pectin was extracted and has been used in food industrial as a thickening agent and gelling agent, so in this experiments will be doing the pectin extraction and then do the analysis step that prospected as an alternative material in polymer injection method. The extraction method that used in this experiments is by using Microwave-Assisted Extraction (MAE) method from oranges peel waste. The purpose of this experiments is to knowing the pectin properness as a thickening agent as an alternative alternatife biopolymer material. The results of the FTIR test showed that there is compatibility of the function groups that formed the pection compounds.

Analysis of numerical modeling strategies to improve the accuracy of polymer injection molding simulations

Analysis of numerical modeling strategies to improve the accuracy of polymer injection molding simulations

Heterogeneity Effect on Polymer Injection: a Study of Sumatra Light Oil

The production of oil and gas is heavily dependent on the heterogeneity of the reservoir. Optimizing the production plan and maximizing recovery from the reservoir depends on an understanding of how heterogeneity affects fluid flow and recovery. Techniques such as water flooding and polymer flooding were used to increase oil production from reservoirs while evaluating the impact of reservoir heterogeneity. Numerical simulations in homogeneous and heterogeneous models were performed in this research to identify the optimal operational parameters that will optimize oil recovery and assess the effect of heterogeneity in the reservoir on the recovery factor of the reservoir. The result showed that the homogeneous model obtained 59.86% of the oil recovery factor, while the heterogeneous reservoirs for Lk = 0.2, 0.4, and 0.6 resulted from 45.83%, 69.27%, and 80.46% of oil recovery after twenty years of production, respectively. The heterogeneous reservoir with Lk = 0.6 indicated the highest sweep efficiency compared to other scenarios, while the reservoir with Lk = 0.2 showed the lowest sweep efficiency

Reservoir Simulation Model Predicts EOR Performance on Alaska’s North Slope

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206247, “History Matching and Performance Prediction of a Polymerflooding Pilot in a Heavy Oil Reservoir on Alaska’s North Slope,” by Xindan Wang, Cody Keith, SPE, and Yin Zhang, University of Alaska Fairbanks, et al. The paper has not been peer reviewed. _ The complete paper discusses the first polymerflooding pilot to enhance heavy oil recovery on the Alaskan North Slope. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut, from 65% to less than 15% in project producers. The primary objective of the study was to develop a robust history-matched reservoir simulation model capable of predicting future polymerflooding performance. Pilot Description The pilot program targets an isolated fault block in the Schrader Bluff NB sands with two horizontal injectors (J-23A and J-24A) and two horizontal producers (J-27 and J-28). The producing lengths of the horizontal wells range from 4,200 to 5,500 ft, and the average interwell distance is approximately 1,100 ft. The project wells were put on waterflooding in June 2016, recovering approximately 7.6% of the original oil in place with a cumulative water injection of 0.09 pore volumes (PV). In August 2018, polymer solution injection commenced. The polymer solution, with a target viscosity of 45 cp, was introduced to both injectors by means of a polymer injection unit. By the end of December 2020, a total of 1.7 million STB of polymer solution had been injected, representing 0.08 PV in the flood pattern. A significant benefit of polymerflooding has been observed in the decrease in water cut in both producers. The oil production rate of Producer J-27 (supported by both injectors) increased continuously from 500 to 800 BOPD in April 2019. The oil production rate of Producer J-28 (supported only by J-23A to the north) also increased to approximately 700 BOPD in late 2019 and stabilized at approximately 500 BOPD in 2020. Reservoir Modeling Base Reservoir Model. A 3D reservoir model was developed for the pilot fault block. The selected active reservoir simulation model, including 23,848 active gridblocks, covers the potential sweep area of the project wells. The 3D view of the selected active reservoir simulation model is shown in Fig. 1. The approximate dimensions of the active reservoir simulation model are 6,900, 4,100, and 15 ft in the x, y, and z directions, respectively. The reservoir simulation model consists of eight layers in the z direction. High-Transmissibility Strips. The early water breakthrough and high water cut during the pre-polymer/waterflooding period indicate strong communication and short-circuiting behavior between the injecting and producing wells. To simulate this short-circuiting effect, four high-transmissibility strips at different locations and with different widths were introduced to connect the injectors and producers in the reservoir simulation model. Each strip was present in all eight layers of the model such that the strips in each layer were identical.

Injection molding of semi‐crystalline polymers in a space‐time framework

AbstractThe challenges in the numerical simulation of the polymer injection molding process are manifold. Such simulation involves a two‐phase flow formulation and the physical modeling of complex material, i.e., molten polymer. This paper presents a complete macroscale simulation approach for the filling stage of injection molding with semi‐crystalline polymers, applied on polypropylene as example. Accurate and efficient results are obtained using a space‐time finite‐element discretization. Heading towards more efficient computations, we search for a reduction of the polymer's physical model, which includes variable viscosity, density, and several crystallization models. The final contribution of the present work is a model sensitivity analysis, which evaluates the relevance of each material model during the filling stage of injection molding.

Effect of melt temperature on microstructural and strength properties of in-situ aluminum metal matrix composites containing SiCNO particles

Polymer Injection Pyrolysis (PIPs) can be adopted to synthesize in-situ ceramic particles within molten metal by stir-casting process. This paper investigated the effect of pyrolysis temperatures on microstructural and strength properties of in-situ aluminum matrix composites containing 2.5 vol% of SiCNO particles. In-situ composites were synthesized by stir-mixing of cross-linked polysilazane at four different pyrolysis temperatures (675–850°C) at which in-situ pyrolysis occurred and then followed by ultrasonic agitation and squeeze casting process. Microstructural data reveals that grain size and the particle size of SiCNO particles decreases with increasing the temperature of the melt at which polymer was introduced into the melt. The increase in the strength properties of the fabricated composites as compared to pure aluminum is almost 210% for the composites fabricated at 850°C while it is marginally 17% for the composites fabricated at 720°C. Fractography studies suggest that composite fabricated at 675°C exhibits a better combination of yield strength and ductility.

Multi-objective global and local Surrogate-Assisted optimization on polymer flooding

Oil production and polymer injection are two performance indicators of polymer flooding and are usually conflicting objectives. In order to obtain optimal trade-off solutions, this paper proposes a multi-objective global and local surrogate-assisted particle swarm optimization (MO-GLSPSO) method, which consists of alternative steps: global population prescreen and local population search.The global steps use generalized regression neural network (GRNN) to prescreen a better population, and the local steps use radial basis function (RBF) as proxy to search for the next generation. The global steps aim to reduce the chance of generations being trapped in local minima, and the local steps obtain the optimal solutions with a fast convergence rate. The rates (liquid production rate and water injection rate) and polymer injection concentration of wells are tuned to obtain a Pareto-front that maximizes cumulative oil production and minimizes cumulative polymer injection.The MO-GLSPSO method is tested using both synthetic and Brugge benchmark cases. The iterations generally improve the oil production or reduce polymer injection and are stabilized at a Pareto-front of the two objectives. Improved sweep efficiency and polymer utility are also observed in the optimal results. The proposed method is also compared with other two methods, multi-objective genetic algorithm (MOGA) and multi-objective particle swarm optimization (MOPSO), to examine the pros and cons. The results indicate that MO-GLSPSO has a better pareto-front than others.

Monitoring and viscosity identification via temperature measurement on a polymer injection molding line

Recent studies emphasize the importance of monitoring equipment/strategy for energy efficiency and quality control of polymer processing. New devices and new methods are proposed for temperature and viscosity measurements on a polymer production line. In this paper, an annular measuring device is used on an injection molding machine to detect material changes through temperature measurement. When the material becomes more viscous, the melt temperature increases due to the viscous dissipation in the production line. An original inverse method based on the viscous dissipation phenomenon is proposed for viscosity identification using temperature measurements of the annular device. The identification process successfully distinguishes the difference in viscosity between two different polymers, and the identification results are in good agreement with other viscosity curves available from the literature.

A pragmatic approach to polymer flooding to accelerate field implementation

Background: Polymer flooding is a well-known enhanced oil recovery technique which can increase recovery factors in mature oilfields above 10% of the oil originally in place. Despite a lengthy history and many published field cases, the speed of deployment is still rather slow. With the need to boost energy production while minimizing energy wastes and carbon emissions, considering this technique known to reduce water usage and accelerate oil recovery should be a must.
 Aim: This short publication aims at providing guidelines to accelerate deployment of polymer injection in various oilfields and a couple of pragmatic approaches recognizing the need for field data instead of poorly constrained simulations or incomplete laboratory studies.
 Materials and methods: After a brief review of the technique and current implementation workflows, we will discuss new approaches to foster the deployment of injection pilots by showing how polymer injection can reduce emissions and energy wastes while accelerating oil production.
 Results: We provide a different perspective on polymer injection with pragmatic tools and ideas showing that going to the field fast provides more information than any laboratory study.
 Conclusion: Given the current need for mitigating oil production declines, polymer flooding is a technique of choice which can be deployed fast if basic criteria explained in this paper are met.

Formulation for chemical EOR: Development and evaluation of an ASP formulation In customer field conditions

AbstractAlkali surfactant polymer (ASP) flooding is an enhanced oil recovery (EOR) technology with an impressive potential for increasing incremental oil production from conventional hydrocarbon bearing reservoirs. A challenge to ASP application is the complexity of determining an effective formulation, typically requiring extensive laboratory screening of nearly countless combinations of surfactants and cosolvents. This paper focuses on demonstrating the utility of the hydrophilic–lipophilic deviation (HLD) concept for EOR application to simplify surfactant formulation workstreams seeking an economically viable ASP formulation for field application. In describing work performed for EOR application of ASP under customer conditions using crude oil, the discussion covers the initial evaluation of the promising surfactant formulation (interfacial tension and solubility), the improvement upon the formulation via HLD principles, and the evaluation of the improved surfactant formulation (coreflood studies). The final ASP formulation identified consisted of a 9 to 1 mixture of alkyl propoxy sulfate sodium salt (APS) to alkyl ethoxy sulfate sodium salt (AES) totaling 2000 ppm active surfactant content, 2.0 wt% Na2CO3, and 3000 ppm polyacrylamide polymer (all commercially available products). This formulation had ultra‐low interfacial tension and favorable mixing behavior under reservoir conditions. In coreflood studies, the final formulation reproducibly achieved cumulative oil recovery of 96.4%–98.5% of original oil in place with only 0.3 PV of ASP injection with a chase alkali polymer injection.

Investigation of Polymer Flood Performance in Light Oil Reservoir: Laboratory Case Study

The use of polymer solutions in the application of chemical EOR injection technology has a role in increasing oil recovery efforts by improving oil mobility in porous media. The addition of the polymer solution is expected to increase the viscosity value of the displacement fluid so that it can form a “piston-like” effect to increase the volumetric sweep efficiency of the light oil reservoir. The polymer used in this study was HPAM using 3 concentrations, namely 500 ppm, 1000 ppm, and 1500 ppm conducted at a temperature of 70 °C. The rheology test of the polymer included concentration vs temperature and shear rate vs viscosity. Thermal stability testing of polymer for 7, 14, 30, 60, and 90 days at 70 °C was done to determine the stability of the polymer solution. Filtration testing was conducted with the criteria of FR 1.2. The static adsorption test has been done with the standard limit of adsorption value 400 µg / gr. Polymer injectivity test using 3 variations of injection rates and coreflooding test were conducted to determine the reduction of Sor in reservoirs due to polymer displacement. From the polymer testing stage, it was found that HPAM polymers at 3 concentrations were compatible with the injection. This is indicated with the clear solution for 3 concentrations at room temperature and 70 °C. The rheology test results showed that the polymer solution with 3 concentrations was decreased in viscosity with the addition of the shear rate value. In the thermal stability test, the viscosity value of the HPAM with 500 ppm was relatively constant. The value of the FR for HPAM 500 ppm is 1.1, HPAM 1000 ppm is 1.07 and HPAM 1500 ppm is 1.03. The results of the static adsorption test showed the lowest HPAM value of 500 ppm was 156 µg/gr. In the injectivity test results, the resistance residual factor (RRF) values at injection rates of 0.3, 0.6, and 1 cc/min were 0.8, 1.04, and 1.12. The RRF value was close to 1, indicating that after injection of 500 ppm of HPAM tended to not experience plugging. Polymer flooding shows the oil recovery factor (RF) of water injection is 39% OOIP, and RF after polymer injection with 0.35 PV with flush water is 13.5% OOIP or 22% Sor. Knowing the behavior of HPAM polymer with various concentrations to be used for chemical EOR injection, it could provide advantages for future implementation in the light oil reservoir in Indonesia.

Parameter Analysis of Polymer on Sandstone Reservoir in Indonesia: An Experimental Laboratory Study

Polymers are often used to increase oil recovery by improving sweeping efficiency. The screening was carried out as a first step in evaluating the test parameters of several polymers of the Hydrolyzed Polyacrylamide (HPAM) type in fluid and sandstone reservoir rocks. The test was carried out using a reservoir fluid classified as light oil (35°API) and at a reservoir temperature (60°C). The HPAM polymers used are A1, F1, F2, F3, and P1 polymers. The test parameters carried out on these 5 types of polymer (A1, F1, F2, F3 dan P1) include a compatibility test for formation water. The rheology polymer test includes concentration vs Tres, and shear rate vs viscosity which aims to determine the type of polymer solution being tested is a non-Newtonian or pseudoplastic fluid group. Thermal stability test of polymer for 60 days to determine the stability of the polymer solution and whether it is degraded or stable. Filtration testing with criteria FR value 1.2, screen factor test, and adsorption testing using the static method with a standard limit of adsorption value 400 µg/gr and polymer injectivity test. From these tests, scoring (range 0-100) was carried out to determine polymer candidates in polymer flooding testing. The F1 polymer candidate for the sandstone reservoir was obtained with a score of 82.25. From the scoring results, the selected F1 polymer candidate has a concentration value of 2000 ppm. For thermal degradation, the polymer F1 2000 ppm experienced degradation of 15.5%. The results of the F1 2000 ppm polymer static adsorption test were 54.8 µg/gr. With the RRF = 1 value indicating rock permeability after injection of polymer F1 2000 ppm, it tends not to experience plugging due to injection of polymer solution.

Optimal polymer slugs injection profiles

The graded viscosity banks technology (tapering) for polymer flooding is studied for several different models of mixing zones behavior. Depending on the viscosity function the limiting polymer injection profile is rigorously derived for the transverse flow equilibrium model, for the Koval model and for the Todd–Longstaff model. The potential gain in the polymer quantity compared to the profile with a finite number of slugs is numerically estimated.

Numerical Simulation of High Concentration Polymer Flooding in Oilfield Development

The field test of high concentration polymer flooding has the characteristics of high cost, long cycle and irreversibility of the reservoir development process. In order to ensure the best development effect of the development block, this paper simulated and calculated the high concentration polymer flooding development case of the polymer flooding pilot test area through numerical simulation research, and selected the best case through the comparison of various development indicators. The simulation results showed that the larger the polymer dosage and the higher the concentration, the better the oil displacement effect. The best injection method in the construction process was the overall injection of high concentration polymer. The test area should implement high concentration polymer oil displacement as soon as possible. The research results provided theoretical guidance for the future development and management of the pilot area.

Establishment of Unstable Flow Model and Well Testing Analysis for Viscoelastic Polymer Flooding

At present, the polymer solution is usually assumed to be Newtonian fluid or pseudoplastic fluid, and its elasticity is not considered on the study of polymer flooding well testing model. A large number of experiments have shown that polymer solutions have viscoelasticity, and disregarding the elasticity will cause certain errors in the analysis of polymer solution seepage law. Based on the percolation theory, this paper describes the polymer flooding mechanism from the two aspects of viscous effect and elastic effect, the mathematical model of oil water two-phase three components unsteady flow in viscoelastic polymer flooding was established, and solved by finite difference method, and the well-test curve was drawn to analyze the rule of well test curve in polymer flooding. The results show that, the degree of upward warping in the radial flow section of the pressure recovery curve when considering polymer elasticity is greater than the curve which not considering polymer elasticity. The relaxation time, power-law index, polymer injection concentration mainly affect the radial flow stage of the well testing curve. The relaxation time, power-law index, polymer injection concentration and other polymer flooding parameters mainly affect the radial flow stage of the well testing curve. The larger the polymer flooding parameters, the greater the degree of upwarping of the radial flow derivative curve. This model has important reference significance for well-testing research in polymer flooding oilfields.

Effects of injection Moulding Parameters on the Produced Parts

The publication deals with an innovative technology called powder-based metal injection moulding, which is a combination of traditional polymer injection moulding and powder metallurgy. With the technology, it is possible to produce metal components with complex geometry in large series. There is an extremely large selection of materials that can be used, mostly steel, copper, titanium or nickel-based alloys. In this research, the material used is type 17-4PH, martensitic corrosion-resistant steel, and since it is a widely used material, it is examined in many international articles and research studies, and it is also common in industry, so it is advisable to use this type of material for further comparability. Little information can be found in the literature about spraying parameters and their effects, which is why this research focusses on this. On the other hand, these data can also serve as useful information for the industry. During the production of so-called green products, the effects of product shrinkage were measured by changing the most important parameters and comparing the effects of these parameters to traditional polymer injection moulding.