Pressure transient characteristics of non-uniform conductivity fractured wells in viscoelasticity polymer flooding based on oil-water two-phase flow

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery.In contrast to water,polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening,polymer convection,diffusion,adsorption retention,inaccessible pore volume and reduced effective permeability.Meanwhile,the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution,formation damage,and proppant breakage.In this paper,we present an oil-water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior,and non-uniform fracture characteristics in fractured polymer flooding.The hydraulic fracture is firstly divided into two parts:high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section.A hybrid grid system,including perpendicular bisection(PEBI)and Cartesian grid,is applied to discrete the partial differential flow equations,and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution.The combination of polymer behavior characterizations and numerical flow simulations are applied,resulting in the calculation for the distribution of water saturation,polymer concentration and reservoir pressure.Compared with the polymer flooding well with uniform fracture conductivity,this non-uniform fracture conductivity model exhibits the larger pressure difference,and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section.The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately,and yields fracture half-lengths that better match engineering reality,enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity.The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology,as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

An Experimental Study on Alkaline/Surfactant/Polymer Flooding Systems Using Natural Mixed Carboxylate

Orthogonal-test-design method has been used to determine the optimal formula by phase behavior and interfacial tension studies, respectively. The effect of each component of two alkaline/surfactant/polymer flooding systems on interfacial tension is discussed, in which a low-price natural mixed carboxylate (SDC) is used as the major surfactant. The results indicate that the optimal composition is SDC (0.5%), alkaline NaHCO3/Na2CO3 with mass ratio of 1 (1.0%), and hydrolyzed polyacrylamide(0.1%). In the coreflood experiment, their oil recovery is increased by about 25.2% and 26.8% original oil in place, respectively.

Polymer flooding: Current status and future directions

This review presents our perspective on the factors that have brought polymer flooding to its current state. Insights are provided on why HPAM is the dominant polymer used as well as what is needed to make alternative polymers and mobility-control methods viable. Explanation is given for why large polymer banks are needed for polymer flooding, and design of the injected polymer viscosity is detailed for cases with/without crossflow. The role of fractures and horizontal wells are discussed for improving injectivity and extending polymer flooding to recover oils with viscosities as high as 10,000 cP. Operational improvements are described to minimize mechanical and oxidative stability to allow HPAM polymers to be viable to 70 °C and ATBS polymers to 120 °C. Key factors affecting polymer retention are summarized. The paper points out unresolved issues and future directions for polymer flooding.

Transient pressure analysis of polymer flooding fractured wells with oil-water two-phase flow

The oil-water two-phase flow pressure-transient analysis model for polymer flooding fractured well is established by considering the comprehensive effects of polymer shear thinning,shear thickening,convection,diffusion,adsorption retention,inaccessible pore volume and effective permeability reduction.The finite volume difference and Newton iteration methods are applied to solve the model,and the effects of fracture conductivity coefficient,injected polymer mass concentration,initial polymer mass concentration and water saturation on the well-test type curves of polymer flooding fractured wells are discussed.The results show that with the increase of fracture conductivity coefficient,the pressure conduction becomes faster and the pressure drop becomes smaller,so the pressure curve of transitional flow goes downward,the duration of bilinear flow becomes shorter,and the linear flow appears earlier and lasts longer.As the injected polymer mass concentration increases,the effective water phase viscosity increases,and the pressure loss increases,so the pressure and pressure derivative curves go upward,and the bilinear flow segment becomes shorter.As the initial polymer mass concentration increases,the effective water phase viscosity increases,so the pressure curve after the wellbore storage segment moves upward as a whole.As the water saturation increases,the relative permeability of water increases,the relative permeability of oil decreases,the total oil-water two-phase mobility becomes larger,and the pressure loss is reduced,so the pressure curve after the wellbore storage segment moves downward as a whole.The reliability and practicability of this new model are verified by the comparison of the results from simplified model and commercial well test software,and the actual well test data.

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.

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.

Electrochemical Performance of Nickel Hydroxide/Activated Carbon Supercapacitors Using a Modified Polyvinyl Alcohol Based Alkaline Polymer Electrolyte

Polyvinyl alcohol （PVA）-sodium polyacrylate （PAAS）-KOH-H2O alkaline polymer electrolyte film with high ionic conductivity was prepared by a solution-casting method. Polymer Ni（OH）2/activated carbon （AC） hybrid supercapacitors with different electrode active material mass ratios （positive to negative） were fabricated using this alkaline polymer electrolyte, nickel hydroxide positive electrodes, and AC negative electrodes. Galvanostatic charge/ discharge and electrochemical impedance spectroscopy （EIS） methods were used to study the electrochemical performance of the capacitors, such as charge/discharge specific capacitance, rate charge/discharge ability, and charge/discharge cyclic stability. Experimental results showed that with the decreasing of active material mass ratio m（Ni（OH）2）/m（AC）, the charge/discharge specific capacitance increases, but the rate charge/discharge ability and the charge/discharge cyclic stability decrease.

Characteristics of resistivity log response of oil layers under polymer flooding

Resistivity log responses are different when the oil layers is filled by a polymer solution or water and it seriously affects the log interpretation of the water flooded layer. In this paper, we first analyze the electrical properties of the polymer solution. Then, according to the different processes for polymer flooding the reservoir, we perform rock resistivity experiments and analyze the rock resistivity variations in different displacement phases. We also compare the resistivity log responses of oil layers filled with the polymer solution to those filled with water. The results show that when displacing the oil-bearing core by different polymers, the resistivity changes monotonously decrease and show either ＂W＂ type or ＂S＂ type. The resistivity log responses are weak when displacing water and there is no flooded show if the oil layer is injected by a fresh water polymer solution. If the oil layer is injected by a sewage polymer solution, the resistivity log response has similar characteristic as a polluted water flooded layer.

Visualization of adaptive polymer flow and displacement in medium-permeable 3D core-on-a-chip

Polymer flooding has been witnessed an effective technology for enhancing oil recovery from medium-to low-permeability reservoirs;however, direct visualization of polymer solution flow in such reservoir condition is still lacking. In this work, a three-dimensional (3D) core-on-a-chip device with a permeability of around 200 mD was prepared and employed to visualize the pore-scale flow and displacement of a self-adaptive polymer (SAP, 8.7 × 106 g·mol−1)−whose microscopic association structure and macroscopic viscosity can reversibly change in response to shear action−versus partially hydrolyzed polyacrylamide (HPAM), by recording their flow curves, monitoring dynamic transportation process via particle imaging velocimetry, and building 3D structure of remaining oil. The results show that, in single-phase flow, all polymer solutions exhibit flow thinning and then thickening regions as flow rate increases, but the transition between two regimes occurs at a small Weissenberg number (10−3−10−1) in this medium-permeable condition. In contrast to HPAM-1 with close weight-average molecular weight (Mw), the adaptive character not only extends SAP's shear-govern region, allowing SAP to propagate piece by piece and achieve higher accessible pore volume, but it also enhances the elastic resistibility of polymer in the extension-dominated regime, increasing the microscopic displacement efficiency. These two effects result in 1.5–3 times more oil recovery factor for SAP than for HPAM-1. Regarding ultra-high-Mw HPAM-2 (25 × 106 g·mol−1), plugging and chain degradation do occur, thus producing lower oil recovery than SAP. This work provides a direct approach for in-situ assessment of polymer-based displacing system under a more authentic condition of practical reservoirs.

Necessity and feasibility of improving the residual resistance factor of polymer flooding in heavy oil reservoirs

The efficiency of water flooding in heavy oil reservoirs would be improved by increasing the viscosity of the displacing phase, but the sweep efficiency is not of significance due to the low mobility of the vicious oil. On the basis of mobility control theory, increasing the residual resistance factor not only reduces the water-oil mobility ratio but also decreases the requirement for viscosity enhancement of the polymer solution. The residual resistance factor caused by hydrophobic associating polymer solution is higher than that caused by polyacrylamide solution in brine containing high concentrations of calcium and magnesium ions. The results of numerical simulations show that the polymer flooding efficiency improved by increasing the residual resistance factor is far better than that by only increasing solution viscosity. The recovery factor of heavy oil reservoirs （70 mPa·s） can be enhanced by hydrophobic associating polymer solution of high residual resistance factor （more than 3） and high effective viscosity （24 mPa·s）. Therefore, increasing the residual resistance factor of the polymer solution not only decreases the requirement for the viscosity of polymer solution injected into heavy oil reservoirs but also is favorable to enhanced oil recovery during polymer flooding.

Study of the mechanisms of streamline-adjustment-assisted heterogeneous combination flooding for enhanced oil recovery for post-polymer-flooded reservoirs

Streamline-adjustment-assisted heterogeneous combination flooding is a new technology for enhanced oil recovery for post-polymer-flooded reservoirs.In this work,we first carried out a series of 2D visualization experiments for different chemical flooding scenarios after polymer flooding.Then,we explored the synergistic mechanisms of streamline-adjustment-assisted heterogeneous combination flooding for enhanced oil recovery and the contribution of each component.Test results show that for single heterogeneous combination flooding,the residual oil in the main streamline area after polymer flooding is ready to be driven,but it is difficult to be recovered in the non-main streamline area.Due to the effect of drainage and synergism,the streamline-adjustment-assisted heterogeneous combination flooding diverts the injected chemical agent from the main streamline area to the non-main streamline area,which consequently expands the active area of chemical flooding.Based on the results from the single-factor contribution of the quantitative analysis,the contribution of temporary plugging and profile control of branched preformed particle gels ranks in the first place and followed by the polymer profile control and the effect of streamline adjustment.On the contrary,the surfactant contributes the least to enhance the efficiency of oil displacement.

Advanced treatment of oil recovery wastewater from polymer flooding by UV/H_2O_2/O_3 and fine filtration

In order to purify oil recovery wastewater from polymer flooding （ORWPF） in tertiary oil recovery in oil fields, advanced treatment of UV/H2O2/O3 and fine filtration were investigated. The experimental results showed that polyacrylamide and oil remaining in ORWPF after the conventional treatment process could be effectively removed by UV/H2O2/O3 process. Fine filtration gave a high performance in eliminating suspended solids. The treated ORWPF can meet the quality requirement of the wastewater-bearing polymer injection in oilfield and be safely re-injected into oil reservoirs for oil recovery.

The effect of interbeds on distribution of i ncremental oil displaced by a polymer flood

This paper discusses the effect of influencing factors on the distribution of incremental oil displaced by a polymer flood （extra-displaced oil） using numerical reservoir simulation. These factors include the location, area and permeability of a thin low-permeability interbed, and the perforation location relative to the interbed. Simulation results show the locations from where the incremental oil was displaced by the polymer solution. The interbed position from the oil formation top affects the location of extra-displaced oil. The interbed area has a slight influence on the whole shape of extra-displaced oil. Larger interbed area leads to higher partition extent of extra-displaced oil. Higher vertical permeability of interbeds contributes to worse partition extent of extra-displaced oil and the partition effect disappears if the ratio of vertical to horizontal permeability is more than 0.05. The perforation location relative to the interbed affects polymer displacement efficiency, and also has a significant effect on the distribution of extra-displaced oil in polymer flooding.

Polymer efficiency and sulfate concentration for hybrid EOR application to an acidic carbonate reservoir

Polymers play an important role in hybrid enhanced oil recovery (EOR), which involves both a polymer and low-salinity water. Because the polymer commonly used for low-salinity polymer flooding (LSPF) is strongly sensitive to brine pH, its efficiency can deteriorate in carbonate reservoirs containing highly acidic formation water. In this study, polymer efficiency in an acidic carbonate reservoir was investigated experimentally for different salinity levels and SO42− concentrations. Results indicated that lowering salinity improved polymer stability, resulting in less polymer adsorption, greater wettability alteration, and ultimately, higher oil recovery. However, low salinity may not be desirable for LSPF if the injected fluid does not contain a sufficient number of sulfate (SO42−) ions. Analysis of polymer efficiency showed that more oil can be produced with the same polymer concentration by adjusting the SO42− content. Therefore, when river water, which is relatively easily available in onshore fields, is designed to be injected into an acidic carbonate reservoir, the LSPF method proposed in this study can be a reliable and environmentally friendly method with addition of a sufficient number of SO42− ions to river water.

Enhanced oil recovery mechanisms of polymer flooding in a heterogeneous oil reservoir

Taking reservoir rocks and fluids of the Daqing,Dagang and Changqing oilfields as research objects,the EOR mechanisms and technical approach of polymer flooding were discussed.By comparing the displacement performances of ordinary polymer,glycerol,polymer in"sheet-net"structure and heterogeneous weak gel at the same viscosity and concentration,the relationship between the viscosity of polymer displacement agents and displacement performance was demonstrated,and the method of improving polymer flooding effect was worked out.The main mechanism of polymer flooding to increase oil recovery is the swept volume expansion of water injection due to polymer retention in porous media.The viscosity of polymer agents has no positive correlation with polymer flooding effect.Although polymer of"sheet-net"structure has strong capacity in increasing viscosity,it has poor compatibility with pore throat structure of reservoir rock,low injectivity and low shear resistance.Heterogeneous weak gel system has higher adsorption and capture capacity in porous media,which is easy to retain in porous media,and can effectively establish seepage resistance in high permeability layers(zones).Compared with polymer solutions with the same viscosity or concentration,it has stronger ability to expand swept volume.Long term injection of polymer flooding agents will inevitably lead to fluid entry profile reversal,and thus worsening of polymer flooding effect.Alternate injection of high retention and low or non-retention displacement agents can further improve the displacement effect of polymer flooding agents.

Effects of pore structure on surfactant/polymer floodingbased enhanced oil recovery in conglomerate reservoirs

To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer(SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher;the SP flooding can enhance the producing degree of oil in 1-3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations.

CURRENT COLLOIDAL DISPERSION GELS ARE NOT SUPERIOR TO POLYMER FLOODING

The suggestion that the colloidal-dispersion-gel (CDG) process is superior to normal polymer flooding is misleading and generally incorrect. Colloidal dispersion gels, in their present state of technological development, should not be advocated as an improvement to, or substitute for, polymer flooding. Gels made from aluminum-citrate crosslinked polyacrylamides can act as conventional gels and provide effective conformance improvement in treating some types of excess water production problems if sound scientific and engineering principles are respected.

Qualitative and Quantitative Evaluation of Permeability Changes during EOR Polymer Flooding Using Micromodels

Polymer solutions are used in chemical EOR processes to achieve incremental oil recoveries through obtaining favorable mobility ratios. In the process, the?in-situ?viscosity is a key parameter for the polymer flood design, as well as the changes in permeability due to the retention or adsorption (e.g.: plugging). Understanding the major causes of the plugging effects allows?predicting injectivity problems as well as optimizing project design. The objective of this work is to use glass-silicon-glass micromodels in combination with tracer particles—attached to the flooded fluids—to qualitatively and quantitatively describe the extent of permeability changes?after polymer injection. Laboratory work is performed in order to determine the physical properties of the polymer solutions when they flow through porous media, such as the presence of permeability reduction/plugging of the micromodel. A statistical analysis of the distribution and extent of plugged areas?is performed and a study of the pressure response during various injection stages will complement the study. A biopolymer (Scleroglucan) was tested and compared to a commonly used polymer, giving a direct insight into their pros and cons. Five different concentrations of polymers were tested and put into relation with their quantitative and qualitative amount of sort of called retention. The amount of adsorption was determined?experimentally in one case in order to draw the significance. By exploiting the potential of GSG-micromodels in combination with tracer particles, it was possible to visualize the reduction of flow paths and its increase during various injections for the first time. Expanding the working principle proposed in this work could provide further understanding of the behavior of any polymers.?The results obtained and workflow presented in this work allow for additional understanding of polymer solutions behavior in flooding applications. Furthermore, the definition of optimized workflows to?assess any kind of solutions in porous media and permeability changes is?supported.

INTERACTION OF COMPONENTS IN PETROLEUM CARBOXYLATE/ALKALINE/HYDROLYZED POLYACRYLAMIDE FLOODING SYSTEM

The IFTs(Interfacial tension)of petroleum carboxylate/alkaline/HPAM(Hydrolyzed polyacrylamide)flooding system with Daing crude oil and the effects of petroleum carboxylate and alkaline on viscoaity of HPAM solution were studied.There exists remarkable synergism between HPAM and petroleum carboxylate,and the introduction of HPAM into petroleum carboxylate/alka- line system leads the lowering of IFTs against Daqing crude oil,The introduction of petroleum carboxylate into solution of HPAM also leads the decreasing of viscosity,but the extent of viscosity decreasing is much lower than that caused by inorganic salts such as NaCl and CaCl_2.