Effect Of Polymer Flooding Research Articles

Research on Optimization of Reservoir Perforation Position in Offshore Polymer Flooding Oilfield

In order to enhance the effect of polymer flooding in offshore oilfields, so as to realize the longer stable production period and higher oil recovery, the reservoir perforation positions of production wells and injection wells are taken as research objects. By analyzing the distribution of remaining oil and production characteristics under different perforation positions, the optimum perforation positions of production wells and injection wells are selected. Bohai oilfield L was taken as target oilfield in this article, according to the actual reservoir characteristic parameters, three-dimensional laboratory physical simulation experiments of water flooding and polymer flooding were carried out, the experiments include different perforation positions of production wells and injection wells. The research result showed that the influence of perforation position on residual oil and development characteristics of the model is obvious. When takes the scheme of injection well upper part perforated and production well all part perforated, the least of the remaining oil distribution, the longest of the production period without water. Contrast with other perforation schemes, its stable production period increase about 1.2 times, the oil recovery of water flooding increase 3.7% - 6.0%, the oil recovery of polymer flooding increase 2.5% - 4.1%. So it is recommended as the best perforation scheme. Preferable effect had been achieved when translating research findings into practice. It can serve as a reference to the similar offshore oilfield.

Experimental Study on Influencing Factors of Resistance Coefficient and Residual Resistance Coefficient in Oilfield Z

In order to clarify the major influence factors of resistance coefficient and residual resistance coefficient, so as to provide the basis for optimizing the polymer flooding schemes in oilfield Z of Bohai Sea, artificial cores were made by simulated the characteristic parameters of real reservoir and the spacing of production-injection wells. The main parameters considered include reservoir permeability, polymer solution concentration and polymer injection rate. Core experiment of polymer flooding was taken by considering all the main parameters. The result showed that resistance coefficient and residual resistance coefficient decrease with the increase of core permeability. Resistance coefficient and residual resistance coefficient increase with the increase of concentration of polymer solution. The increment of displacement pressure in low permeability core is higher than in medium and high permeability core. The resistance coefficient increase with higher displacing velocity, and the increment in high permeability core is higher than in low permeability core. The displacement velocity has little effect on the residual resistance coefficient. The experimental results can effectively guide the formulation of polymer flooding scheme in offshore oilfields, and optimize the appropriate injection rate and concentration of polymer solution for different properties of reservoirs, thus ensuring the effectiveness of polymer flooding in offshore oilfields.

Experimental study on the effect of polymer concentration and slug size on recovery degree in hyper-permeability reservoir

Aimed at the characteristics of high porosity and high permeability reservoir, used the indoor physical simulation method, the experiment of polymer flooding with different polymer concentration and slug size were carried out after water flooding. The effects of polymer concentration and slug size on oil displacement were analysed. The results showed that the optimum polymer concentration was 2200ppm and the optimum polymer slug size was 0.9PV. And polymer concentration and slug size are the decisive factors influencing polymer flooding effect. Under the condition of a certain amount of injection, the higher the polymer concentration, the higher the viscosity of the polymer solution, the greater the reduction range of water content, and the higher the recovery rate of polymer flooding. Under the condition of a certain polymer concentration, the larger the size of the polymer solution slug, the greater the reduction of water content, and the higher the recovery rate of polymer slug flooding.

Study on the Influence of Inaccessible Pore Volume of Polymer Development

In this paper, laboratory experiment and numerical simulation methods show that: (1) For reservoir formations with different permeability, there exists an optimal molecular weight for injection, and as the permeability increases, the optimal molecular weight gradually increases; (2) Inaccessible pore volume is too large, the polymer solution to reduce the volume; Inaccessible pore volume is too small, the polymer adsorption loss increases, affecting the polymer flooding effect. Therefore, there is an optimal value for the inaccessible pore volume; (3) At different times into polymer flooding, the optimal inaccessible pore volume will change, and the later the transfer time, the best access to the larger inaccessible pore volume. For example, the optimal unobtainable pore volume at 90% water injection is 0.4, while the optimal inaccessible pore volume at 30% aqueous transfer is 0.3.

Polymer Flooding Separate Injection and High Efficiency Measurement and Adjustment Technology

Daqing Oilfield is the largest onshore oil field in China. Polymer flooding plays an important role in the development of Daqing oil field, producing more than 10 million tons of oil for 11 consecutive years. If the injection is not carried out separately, polymer solution will advance along the high permeability layer, which will lead to the serious ineffective and low efficiency cycle, and reduce the production degree of the low and medium permeability layers, which will affect the overall development effect of polymer flooding. Therefore, stratified injection must be carried out, and a new type of delamination injection process string should be developed.1 The whole process integrated separate injection column was designed. The throttle element adopted the streamline annular pressure reducer structure. When the polymer solution passed, the molecular chain expanded and contracted, forming the effective throttling pressure difference and the flow rate 70m3/d. The maximum throttling pressure difference can reach 2.5 MPa, which can effectively control the injection amount into the high permeability layer and improve the production degree of the reservoir. The structural design of streamline ring pressure reducer can effectively control the degradation of polymer solution and reduce the viscosity loss rate from 12.3% to 8%, which ensures the maximum economic benefit of injecting polyacrylamide dry powder. The oil displacement effect of polymer solution is improved effectively. Developed a complete set Electric direct and high efficiency measuring and adjusting technology are used in this paper. From the manual to the cable controlled direct reading mechatronics, the injection test is developed from the manual trial to the cable controlled direct reading era. This technique has been applied in 6464 wells in Daqing Oilfield. The success rate of one salvage operation has been raised from 75% to 96.4% and the testing time of the 3-5 interval wells has been reduced from 5.2 days to 2.5 days, and the injection profile has been obviously improved. The effective production thickness ratio is increased from 62.8% to 74.7%, the oil production ratio is increased from 52.1% to 68.7%, and the oil recovery factor is increased by 2 percentage points. It is especially suitable for the old oil field to enter into the high water cut development. Effective technology for further improving oil recovery after stage.

Method of improving heterogeneous oil reservoir polymer flooding effect by positively-charged gel profile control

The project of polymer flooding has achieved great success in Daqing oilfield, and the main oil reservoir recovery can be improved by more than 15%. But, for some strong oil reservoir heterogeneity carrying out polymer flooding, polymer solution will be inefficient and invalid loop problem in the high permeability layer, then cause the larger polymer volume, and a significant reduction in the polymer flooding efficiency. Aiming at this problem, it is studied the method that improves heterogeneous oil reservoir polymer flooding effect by positively-charged gel profile control. The research results show that the polymer physical and chemical reaction of positively-charged gel with the residual polymer in high permeability layer can generate three-dimensional network of polymer, plugging high permeable layer, and increase injection pressure gradient, then improve the effect of polymer flooding development. Under the condition of the same dosage, positively-charged gel profile control can improve the polymer flooding recovery factor by 2.3∼3.8 percentage points. Under the condition of the same polymer flooding recovery factor increase value, after positively-charged gel profile control, it can reduce the polymer volume by 50 %. Applying mechanism of positively-charged gel profile control technology is feasible, cost savings, simple construction, and no environmental pollution, therefore has good application prospect.

Effects of Pore and Grain Size on Water and Polymer Flooding in Micromodels

We have conducted a comprehensive series of experiments to evaluate the effects of pore size distribution of porous media on the dynamics of shear-thinning fluid flow and oil displacement efficiency. To do so, we have conducted microfluidic experiments, using micromodels fabricated from X-ray computed tomography images of sand-packs with varying grain sizes to create a realistic pore network. Three micromodels with well-defined particle size distribution were fabricated and used in our experiments. The use of micromodels to assess the effectiveness of polymer flooding is often superior to methods such as core flooding because of the detailed pore-scale information obtained during the experiments. The micromodels were initially saturated by oil, and the displacing fluids were prepared as aqueous solutions with dissolved xanthan gum. The dynamics and patterns of the interface displacement as well as the size distribution of the trapped oil ganglia were visualized using an optical microscope. The main findin...

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.

Research on Well Testing Interpretation Method of Polymer Flooding Considering Variety of Polymer Concentration in Reservoirs

Combining the oretical analysis and actual production data statistics, the paper found that concentration of polymer solution at a point in the stratum had exponential relation with the distance away from injectors. Based on viscosity model considering shear degradation and polymer concentration, a non-Newtonian power-law fluid well test interpretation model is built. Then well test interpretation chart of polymer flooding is proposed by numerically resolving the new model. Example analysis shows that the polymer flooding well test interpretation method and chartprovide a theoretical and technical support for explaining reasonably formation parameters under conditions of polymer flooding and quantitatively evaluating the effects of polymer flooding.

English

During polymer flooding, the behaviors of water injection profile reflect the flooding efficiency and its performance in medium and low permeable layers represents the sweep efficiency of the reservoir. In this work, the polymer flooding wells in Bohai Oilfield is analyzed and the observations on the performance are, with more polymer injected, the injection profile is characterized by: In most of the wells, vertically, the intake profile of each layers is improved efficiently and water absorption of low and medium permeable layers increase correspondingly; however, in some wells, the injection profile is not improved vertically but the water absorption of high permeable layers increases instead while low and medium permeable layers do not absorb any water; in addition, water absorption volume in high permeable layer is higher than that of the total volume of low and medium permeable layers, which is prejudicious for polymer flooding. By analyzing the field scale data, it is found that the differential of formation capacity between layers has big impact on water injection profile improvement by polymer flooding. Nevertheless, with certain formation capacity, injection profile of low and medium permeable layer, with the increase of injection volume, will increase first, then decrease and then increase again. Based on the study, it should be avoided to inject polymer to wells whose formation capacity differential is large. If it is ineluctable, injection profile should be adjusted before injecting polymer. For those wells whose intake profile is improved obviously, attention should be paid on the rules of the injection profile with the increase of injected polymer, and conduct zonal polymer injection, injection profile adjustment or increase polymer volume to enhance polymer flooding effect when its relative water absorption volume reduce. Key word: Polymer flooding, offshore oil field, water injection profile, influences factors.

The Screening of Biopolymer Bacteria in Porous MediaThe Screening of Biopolymer Bacteria in Porous Media

MEOR has advantages of less polluting environment and low cost, which can be extended to the volume of the biopolymer produced by metabolism, and it is one of the main mechanisms of microbial enhanced oil recovery. The fermentation, the study of biopolymers produced growth and metabolism of bacteria rules; after using the orthogonal experimental method and optimized the optimum culture conditions, through the indoor driving oil experimental evaluation of biological polymer flooding effect. The optimal bio polymer producing strain DJ was screened out. The strain had the ability to produce polymer and the product quantity was high. The effect of the biopolymer flooding was good. DJ strain optimum culture time for 72 hours, the optimal fermentation culture conditions: fermentation temperature 35 degrees Celsius; shaking speed r/min; 10 mL of inoculum; fermentation culture medium formula: glucose 40 g/L, 20 g/L of corn steep liquor, corn starch 2 G/L, NaNO3 3 g/L, KH2PO4 0.5 g/L, Na2HPO4·12H2O 1 g/L, MgSO4·7H2O 0.5 g/L, CaCl2 0.05 g/L, pH 7.2.

Characterizing the Role of Clay and Silica Nanoparticles in Enhanced Heavy Oil Recovery During Polymer Flooding

Polymer flooding as one of the most effective methods for enhancing oil recovery has a significant effect on tertiary production of reservoirs with poor vertical sweep efficiencies and those which are extremely heterogeneous. Water-soluble polymers are used to both increase the viscosity of water and decrease the mobility ratio of the displaced and displacing fluids. However, due to high amount of polymer adsorption, presence of divalent cations and mechanical degradation, polymer molecules may lose their properties. Hence it is necessary to further improve the displacement effectiveness of polymer flooding. Despite the fact that several ways have been suggested to enhance the performance of polymer flooding, application of nanoparticles in the improvement of rheological properties of the polymer solution used in enhanced oil recovery has not been reported previously and is still an ongoing subject. This paper investigates the effects of nanoparticles on flow behavior of polymer solution in porous media by employing both experimental studies and numerical simulations. The simulation model first is validated against well-controlled laboratory experiment to have reliable predictions of the full-field implementations. The results show that the amount of polymer adsorption and viscosity of polymer solution will improve when the clay or silica nanoparticles is present in the injectant, and accordingly, the cumulative oil recovery and breakthrough time will be bettered. The result of sensitivity analysis demonstrates that polymer molecules are more degradable during polymer flooding compared to nanoparticles-assisted polymer flooding. Based on the validated model, 3D simulations of nanoparticles-assisted polymer field pilot were performed and the results revealed that the cumulative oil recovery, water cut and breakthrough time will improve when the injectant has some dispersed nanoparticles.

Experimental Study of Chemical Flooding of Suizhong 36-1 Oilfield

Aim at the reservoir characteristics of Suizhong 36-1 Oil Field, this paper has developed typical two-dimensional physical model in parallel between the layers and studied the macroscopic displacement effect of polymer flooding and binary compound flooding, and studied the interlayer spread law and oil displacement efficiency of polymer flooding and binary combination flooding by using saturation monitoring system deeply. The results show that: when the multiples of pore volume injected for polymer was 0.3 after water flooding, the recovery efficiency increased by 10.3%, and when the multiples of pore volume injected for binary combination flooding was 0.3 after polymer flooding and the recovery efficiency could also increase by 19.3%, and the effect of enhanced oil recovery was obvious during the binary combination flooding and polymer flooding; Saturation monitoring data showed that there formed oil wall and increased the flow resistance and expanded the swept volume during the stage of polymer flooding and binary combination flooding, effective use of low-permeability layer was the key to improve oil recovery.

Research on Configuration of Polymer Molecular Aggregate and Its Reservoir Applicability

This article researches the effect of configuration of polymer molecular aggregate on the performance of polymer solution and its reservoir applicability, taking configuration of polymer molecular aggregate, first normal stress difference, resistance coefficient, residual resistance coefficient, and oil recovery as the evaluation indexes, guided by physical chemistry, polymer materials science, and reservoir engineering, by means of chemical analysis, instrument detection, and physical simulation. Results show that the apparent viscosity of polymer solution is closely related to the configuration of molecular aggregate. However, that reflects neither the transporting and migrating ability of molecular aggregate in porous media nor the applicability of polymer solution for reservoir core pore. Compared with “linear-branched chain” polymer, network polymer has a regional “laminated-net” structure, which has a stronger ability to adsorb and wrap hydrone, when deformation occurs, internal friction of which is larger, and apparent viscosity of which is higher with isoconcentration. Changing the configuration of molecular aggregate can enhance the tackify performance of polymer, but crosslinking or association degree must be controlled properly. Otherwise, the applicability of polymer solution for reservoir core pore will become poor, thus influencing the oil incremental effect of polymer flooding.

Research into polymer injection timing for Bohai heavy oil reservoirs

Polymer flooding has been proven to effectively improve oil recovery in the Bohai Oil Field. However, due to high oil viscosity and significant formation heterogeneity, it is necessary to further improve the displacement effectiveness of polymer flooding in heavy oil reservoirs in the service life of offshore platforms. In this paper, the effects of the water/oil mobility ratio in heavy oil reservoirs and the dimensionless oil productivity index on polymer flooding effectiveness were studied utilizing relative permeability curves. The results showed that when the water saturation was less than the value, where the water/oil mobility ratio was equal to 1, polymer flooding could effectively control the increase of fractional water flow, which meant that the upper limit of water/oil ratio suitable for polymer flooding should be the value when the water/oil mobility ratio was equal to 1. Mean while, by injecting a certain volume of water to create water channels in the reservoir, the polymer flooding would be the most effective in improving sweep efficiency, and lower the fractional flow of water to the value corresponding to $$ \Delta \,J_{\hbox{max} } $$ . Considering the service life of the platform and the polymer mobility control capacity, the best polymer injection timing for heavy oil reservoirs was optimized. It has been tested for reservoirs with crude oil viscosity of 123 and 70 mPa s, the optimum polymer flooding effectiveness could be obtained when the polymer floods were initiated at the time when the fractional flow of water were 10 % and 25 %, respectively. The injection timing range for polymer flooding was also theoretically analyzed for the Bohai Oil Field utilizing relative permeability curves, which provided methods for improving polymer flooding effectiveness.

The Complementary Technologies to Improve Polymer Flooding Efficiency for Class II Reservoirs of Daqing Oilfield

With the amount of polymer used in oil field increases year by year and the development results turn worse, people started to pay more attention to the technologies which can improve the polymer flooding recovery of class II reservoirs. Polymer flooding efficiency can be enhanced through methods such as detail geologic analysis, project design optimization and strengthen procedure management with applying mature supporting technologies. In this paper, the necessity of improving the polymer flooding effect of class II reservoir is introduced. The technologies to develop polymer flooding efficiency are proposed. The applying results of these technologies show that meticulous reservoir simulation and deepen recognize of structure and reserve and residual oil distribution are the base of improving polymer flooding efficiency. Optimizing polymer injection design to match the oil reserve is the key part of improving polymer flooding efficiency. Deepening technology research and building workflow of different measures and adjustment technologies at different production stages are efficient ways to improve polymer flooding efficiency. Insisting on the comprehensive adjust pattern of normal molecular weight with normal molecular concentration, individual design, scale injection, profile control in time, adjust with time and strengthen procedure management are the predominant guarantee of improving polymer flooding efficiency.

Experimental Investigation of Polymer Adsorption-Induced Permeability Reduction in Low Permeability Reservoirs

The polymer retention during polymer flooding causes reduction in pore throat size which can be detrimental to oil recovery. Especially, in low permeability reservoir unlikely in high permeability system, EOR effect of polymer flooding would not excel comparing to water flooding because of the polymer adsorption onto grain surface. This phenomenon is more significant as higher concentration of polymer solution is injected. In this study, we investigated oil recovery process during polymer flooding for a quarter of 2D 5-spot pattern of low permeability sandstone slab, in which the injected polymer solution flows in different shear rates corresponding to streamlines. The results showed that the ultimate recovery was 1.9 times higher in concentration of 1,000 ppm case than 0 ppm. The polymer adsorption layer formed during the flooding reduced the effective permeability of 1,000 ppm polymer solution. Therefore, it facilitated the oil flow and the stage of water-cut reaching 99% was slackened off.

The Evaluation Experiment Research on Sp Binary Composite System Performance and the Oil Displacement Effect

SP binary composite system can reduce the interfacial tension, has good viscoelasticity, and has similar displacement effect with ASP ternary composite system. In addition, the scaling formation can be weaken because it does not contain alkali. Therefore, it plays a important role in guiding the formulas of SP binary composite system and designing the injection scheme to evaluate the main performance and oil displacement effect of SP binary composite system. Experiments on the main performance evaluation, microscopic simulation model for oil displacement and oil displacement in cores have been carried in this paper, which is intended for the new type of surfactant (HLX-BO1 type)/polymer binary complex system which is applied in SP binary composite flooding test block of Daqing oil field. The emulsification property, adsorption characteristics, stability and rheological property of the SP binary composite system have been evaluated. The oil displacement effect of polymer flooding, surfactant flooding, and SP binary composite flooding have been analyzed in this paper. The evaluation experimental research on SP binary complex system performance shows that: 1The binary composite system has good viscosity stability and interfacial tension stability. 2the emulsification time and emulsification degree both increase With the increasing of surfactant concentration. 3The higher oil content in the oil sand, the greater the surfactant adsorption capacity. 4The concentration of surfactant has less affect on the apparent viscosity of the polymer solution, while alkali has greater influence on the apparent viscosity of the polymer solution. The oil displacement experimental research on SP binary system shows that the oil displacement effect of SP binary system is significantly better than that of the unitary system of polymer or surfactant alone. The oil displacement effect is well whether SP system is flooded after water flooding or polymer flooding. The average enhanced oil recovery rates of artificial cores in the oil displacement experiment are 17.5% and 10.10% respectively. The average enhanced oil recovery rate of natural cores in the oil displacement experiment after polymer flooding is 9.5%.

Study on Properties of Pectinate Hydrophobically Associating Polyacrylamide Solutions

In this article, the viscosifying abilities, rheological properties, flow characteristics of pectinate hydrophobically associating polymer (PHAP) solutions with different hydrophobe content were studied using technical methods of viscosity measurement, rheological and core flow experiments. Researches on viscosifying of different PHAPs at 20°C and 65°C in distilled water and saline indicate that, with the raise of hydrophobe content, viscosity of polymer solutions increases first and then decreases, which means that there should be a critical hydrophobe content( CHC). Below CHC, the anti-shear ability of polymer solutions enhances as hydrophobe content rises; while the shear resistance would fall down when and after the content reaches CHC. In high permeability porous media, all polymer solutions take on greater injectivity, and RFF can all be higher than 5, yet with the increasing of hydrophobe content, RF goes up first and then declines. It could be an effective way to enhance mobility control ability, improve polymer flooding effect in high permeability reservoirs and design polymer molecular structure more reasonably, using the pectinate structure and hydrophobic association interaction between polymer moleculars.

Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geomechanical Considerations

Summary A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated-sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated- sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding. Laboratory tests under polyaxial conditions indicate that nearwellbore fracturing and permeability increase in unconsolidated sands occur at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of binding several key parameters for fracture prediction. These include sand shale stress contrast, fluid quality and total-suspended-solids (TSS) content, fluid rheology and effective viscosity in the formation, and the filter-cake properties in the presence of polymer. This paper provides a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures. It highlights the existing technological gaps in the current predictive capabilities.