Polymer Flooding In Reservoirs Research Articles

Application and Optimization of the Rheological Model for a Hydrophobically Associating Dendrimer Polymer.

Polymer flooding is one of the most important enhancing oil recovery (EOR) technologies in the world. With the optimization of polymer synthesis, the performance of polymer solutions has been greatly improved, which can adapt to more complex oil and gas reservoirs. However, with the continuous improvement of the properties of polymer solutions, the elastic property of polymer solutions is significantly improved, and the rheological law has also changed. This series of changes affects the application of polymer flooding reservoir numerical simulation technology. Therefore, constructing an accurate description model and precise limitation conditions is particularly important. The rheological curve with a wide shear range (0.1~10,000 s−1) and the viscoelasticity of the two polymers (partially hydrolysed polyacrylamide (HPAM) and dendritic hydrophobic association polymer (DHAP)) were analyzed and tested by a rotating rheometer. The results showed that under the experimental conditions, the rheological curve of both polymers can be described by the Carreau rheological model. Meanwhile, the structural viscosity of the hydrophobically associating polymer solution (DHAP) greatly improved the elasticity of the solution and led to the change of elastic modulus. Considering the influence of elastic characteristics on the rheological curve, the relaxation time spectrum derived from small vibration experimental data was used to limit the characteristic relaxation time, that is, the value range of λ. It was observed that the experimental data were highly matched with the nonlinear regression fitting curve of the Carreau rheological model. Therefore, the relationship between different test parameters should be fully considered while studying the rheological constitutive equation of viscoelastic fluid, so as to optimize and improve the equation of it.

Experimental Study of Microgel Conformance-Control Treatment for a Polymer-Flooding Reservoir Containing Superpermeable Channels

SummaryPolymer flooding has been widely used to improve oil recovery. However, its effectiveness would be diminished when channels (e.g., fractures, fracture-like channels, void-space conduits) are present in a reservoir. In this study, we designed a series of particular sandwich-like channel models and tested the effectiveness and applicable conditions of micrometer-sized preformed particle gels (PPGs, or microgels) in improving the polymer-flooding efficiency. We studied the selective penetration and placement of the microgel particles, and their abilities for fluid diversion and oil-recovery improvement. The results suggest that polymer flooding alone would be inefficient to achieve a satisfactory oil recovery as the heterogeneity of the reservoir becomes more serious (e.g., permeability contrast kc/km > 50). The polymer solution would vainly flow through the channels and leave the majority of oil in the matrices behind. Additional conformance-treatment efforts are required. We tried to inject microgels in an attempt to shut off the channels. After the microgel treatment, impressive improvement of the polymer-flooding performance was observed in some of our experiments. The water cut could be reduced significantly by as high as nearly 40%, and the sweep efficiency and overall oil recovery of the polymer flood were improved. The conditions under which the microgel-treatment strategy was effective were further explored. We observed that the microgels form an external impermeable cake at the very beginning of microgel injection and prevent the gel particles from entering the matrices. Instead, the microgel particles could selectively penetrate and shut off the superpermeable channels under proper conditions. Our results suggest that the 260-µm microgel particles tested in this study are effective to attack the excessive-water-production problem and improve the oil recovery when the channel has a high permeability (>50 darcies). The gels are unlikely to be effective for channels that are less than 30 darcies because of the penetration/transport difficulties. After the gels effectively penetrate and shut off the superpermeable channel, the subsequent polymer solution is diverted to the matrices (i.e., the unswept oil zones) to displace the bypassed oil. Overall, this study provides important insights to help achieve successful polymer-flooding applications in reservoirs with superpermeable channels.

Experimental Investigation of the Heterogeneity Limit for the Application of Polymer Flooding in Reservoirs

Abstract It is generally accepted that polymer flooding gets less effective as the heterogeneity of a reservoir increases. However, very little experimental information or evidence has been collated to indicate which levels of heterogeneity correspond to reservoirs that can (and cannot) be efficiently developed using polymer flooding. Therefore, to experimentally determine a heterogeneity limit for the application of polymer flooding to reservoirs, a series of flow tests and oil displacements were conducted using parallel sand packs and visual models possessing different heterogeneities. For low-concentration polymer flooding (1.0 g/l), the limit determined corresponds to permeability contrasts (PCs) of 10.8 and 10.2, according to the parallel and visual tests, respectively. A significant increase in oil recovery can be achieved by polymer injection within these limits. Increasing the polymer concentration to 2.0 g/l increased these limiting PCs to 52.8 and 50.0, respectively. Additionally, within or beyond these limits, the combined use of polymer and gel may be the best.

Formation mechanism and location distribution of blockage during polymer flooding

The blockage produced during polymer flooding can lead to a significant decline in reservoir productivity. The composition of the oilfield scale is very complicated, and formation mechanism and location distribution of blockage are unclear. In this work, the composition of the oilfield scale produced during polymer flooding was analyzed by thermal gravimetric analysis (TGA), infrared spectrum analysis (FI-IR), X-ray diffraction analysis (XRD), and scanning electron microscopy observation (SEM). The formation mechanism of the blockage was studied by means of water compatibility experiment, core flooding experiment, swelling experiment, and polymer retention experiment. The location distribution of blockage was explored by physical simulation displacement experiment using the long sand pack tube. The results show that the oilfield scale is composed of polymer, inorganic substances, water, and crude oil. Various components are interdependent and entangled in the scale. After the polymer solution is injected into the formation, the “fish eye” scale and inorganic salt crystal/polymer scale are produced in the near-injection well zone. Through scale migration and fine particle exfoliation, there occurs the complex composite scale combined by migrated scale and fine particles as well as the newly-generated fine particle/polymer flocculent scale. When the scale encounters with crude oil, the asphaltene from crude oil can be adsorbed and precipitated on the scale surface, leading to the oil-wrapped composite scale. Besides, the injected polymer can be adsorbed and captured in the oil layer, causing the decrease of the layer permeability. With decrease of oil layer permeability, various scale is deposited and bridge-blocked in the oil layer, causing the blockage during the polymer flooding process. After three displacement stages of water flooding, polymer flooding, and subsequent water flooding, blockage is produced in all zones of oil layer, with the most severe blockage in the middle zone near the injection well. The study can provide a theoretical basis for the subsequent research on the blockage-removing fluid systems suitable for polymer flooding reservoirs.

Potential of the base-activated persulfate for polymer-plugging removal in low temperature reservoirs

Conventional polymer-plugging removers perform badly in low temperature reservoirs and this has prompted researchers to look for more effective removers. In this work, base-activated sodium persulfate (PDS) was used to degrade polymer-plugging. The performance of the novel remover was first compared with that of conventional removers at 35 °C. Then, the degradation mechanism involved and factors of influence were investigated by carrying out radical scavenger and single-factor experiments, respectively. Finally, corrosion tests were performed and the ability of the new remover to remove plugging in porous media was investigated by carrying out flooding tests. The results show that the PDS/NaOH system is a much more potent remover at temperatures as low as 35 °C (giving a degradation efficiency of 100% compared to 10–70% using conventional removers). Furthermore, the radical scavenger experiments show that HO· is the predominant radical responsible for polymer gel degradation. The degradation efficiency is affected by the concentrations of the PDS and NaOH solutions, the temperature, and also by the salinity of the polymer gel. We also demonstrate that the polymer gel can be completely degraded when its salinity is 30,000 mg/L by optimizing the temperature and concentration of PDS and NaOH. The corrosion rate using PDS/NaOH was found to be 1.085 g m−2 h−1 which satisfies the requirements for entry well fluid. In addition, the static plugging degradation and dynamic plugging removal tests show that PDS/NaOH can degrade the plugging effectively and recover the permeability of the sandpack to over 65%. Our results suggest that the PDS/NaOH system is a highly promising plugging remover for use in low-temperature polymer flooding reservoirs and is a good replacement for the ones conventionally used.

Pressure Transient Behavior for Alternating Polymer Flooding in a Three-zone Composite Reservoir

Alternating polymer flooding has achieved great attractions recently in oil industry, however, the research of pressure analysis in alternating polymer flooding reservoir is rare. This work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. A new numerical pressure analysis model (three-zone composite model) is established by considering diffusion, convection, shear, and inaccessible pore volume, which is based on the rheology experiments. Based on this model, the type curves are then developed and sensitivity analysis is further conducted. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between low concentration and high concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.

Well testing interpretation method and application in triple-layer reservoirs by polymer flooding

Well testing method has historically been the main source of formation evaluation in oilfields. This work demonstrates well testing analysis for formation evaluation in crossflow triple-layer reservoirs by polymer flooding, and a well testing model is proposed by considering mechanical degradation, dispersion, convection, and shear-thinning of polymer solutions. The type curves, having five segments with different flow regime, are developed based on this model, and parameter sensitivity is analyzed. The typical characteristic is the existence of two ’concaves’ in the type curves, distinguished from one-layer and double-layer reservoirs. A field test validates the proposed well testing model, which can effectively evaluate the layered permeability and skin factor. Furthermore, formation damage due to adsorption of polymers at the rock surface is estimated through comparison of the interpreted parameters with the values prior to polymer flooding, which explores the feasibility of applying this interpretation method in formation evaluation of polymer flooding reservoirs.

The Effect of Injection Velocity on Injectivity Profile Reverse Phenomenon in Polymer Flooding Reservoirs

The Effect of Injection Velocity on Injectivity Profile Reverse Phenomenon in Polymer Flooding Reservoirs

Numerical Well Test Analysis for Polymer Flooding considering the Non-Newtonian Behavior

Well test analysis for polymer flooding is different from traditional well test analysis because of the non-Newtonian properties of underground flow and other mechanisms involved in polymer flooding. Few of the present works have proposed a numerical approach of pressure transient analysis which fully considers the non-Newtonian effect of real polymer solution and interprets the polymer rheology from details of pressure transient response. In this study, a two-phase four-component fully implicit numerical model incorporating shear thinning effect for polymer flooding based on PEBI (Perpendicular Bisection) grid is developed to study transient pressure responses in polymer flooding reservoirs. Parametric studies are conducted to quantify the effect of shear thinning and polymer concentration on the pressure transient response. Results show that shear thinning effect leads to obvious and characteristic nonsmoothness on pressure derivative curves, and the oscillation amplitude of the shear-thinning-induced nonsmoothness is related to the viscosity change decided by shear thinning effect and polymer concentration. Practical applications are carried out with shut-in data obtained in Daqing oil field, which validates our findings. The proposed method and the findings in this paper show significant importance for well test analysis for polymer flooding and the determination of the polymer in situ rheology.

Pressure-Transient Behavior in a Multilayered Polymer Flooding Reservoir

A new well-test model is presented for unsteady flow in multizone with crossflow layers in non-Newtonian polymer flooding reservoir by utilizing the supposition of semipermeable wall and combining it with the first approximation of layered stable flow rates, and the effects of wellbore storage and skin were considered in this model and proposed the analytical solutions in Laplace space for the cases of infinite-acting and bounded systems. Finally, the stable layer flow rates are provided for commingled system and crossflow system in late-time radial flow periods.

E&P Notes (June 2014)

E&P Notes ’DuPont Touts MEOR Technology’ DuPont is ramping up the commercial-scale implementation of its microbial enhanced oil recovery (MEOR) method after nearly a decade of development and testing of what it says is a low-risk way to improve production from mature fields. Using its bioanalysis technology, DuPont has isolated microbes able to promote flow conformance through the production of a biofilm that restricts flow by reducing permeability. The company has also identified and isolated microbes that have oil-releasing (or wettability-changing) qualities to reduce residual oil adhering to the rock. Based on successful results both in the lab and in the field, the company says that its MEOR solution can increase production rates by as much as 25% at a cost of USD 10 per incremental barrel. DuPont presented the details of its laboratory tests and discussed the results of field trials at the SPE Improved Oil Recovery Symposium in Tulsa in April. ’Wintershall Sees EOR Promise in New Biopolymer’ After a year of field testing, a new type of biopolymer developed by Wintershall, Germany’s largest oil and gas producer, is showing promise as an effective enhanced oil recovery (EOR) tool in one of the country’s longest producing oil fields. The company presented the first-year results of its pilot project using the biopolymer in a pair of technical papers in April at the recent SPE Improved Oil Recovery Symposium in Tulsa. The biopolymer, Schizophyllan, is named after one of the most widespread fungi found in the forests of Germany. What is novel about Wintershall’s biopolymer is that it can survive inside high-salinity reservoirs with temperatures as high as 275°F. The triple-helix configuration of the molecular structure provides durability and high viscosity. According to the company, these tolerances are unmatched by all other commercially available polymers and will enable polymer flooding in reservoirs previously considered too harsh for such a treatment. ’Two Big Equipment Makers Working on Tougher Fracture Pumping Systems’ Pumping fracturing jobs is an equipment killer. To begin with, the job requires running enormous quantities of water and sand through a pump, which is an abrasive mix that damages pumps in ways that cannot be fixed. Adding to the pressure is the trend toward clustering wells on pad sites to allow larger, non-stop, multi-well jobs that extend run time.

Evaluation of Potential of Remaining Oil after Polymer Flooding

Figuring out the rule of remaining oil distribution after polymer flooding is the basis for continuing study on development policy after polymer flooding in Daqing Oil Field. Based on the basic principles of percolation mechanics, percolation mechanics of polymer flooding reservoirs under fixed injection pressure and injection rate was studied, the mechanism of remaining oil changes after polymer flooding was investigated; According to the numerical simulation results, the rule of remaining oil distribution in Daqing oilfield has been given out. This will be theoretical and practical guidance for enhancing oil recovery after polymer flooding.

Wireline Log Interpretation Method of Remaining Oil Saturation in Polymer Flooding Reservoir

Interpreting the remaining oil saturation in polymer flooding reservoir is very important for the oil exploration and development. Based on the original physical model of Archie formula, a kind of remaining oil saturation interpretation method for the polymer flooding reservoir is proposed, on the analysis of the variation rules of Archie parameters caused by the polymer influences in the reservoir microscopic pore structure, conductivity and wettability in this article. Theoretical analysis and actual applications show that Archie formula is still applied to calculate the remaining oil saturation for polymer flooding reservoir. This formula form is simple, easy to calculate the parameters, the interpretation accuracy can satisfy the practical development needs, and can be widely used for polymer flooding reservoir.

Pressure Response of Polymer Flooding Reservoir by Considering Diffusion and Conduction Behaviors

A polymer solution is classified as non-Newtonian Fluid. The results of pressure data analysis for polymer flooding reservoirs would be inaccurate when generalized using non-Newtonian fluid flow models, which treat polymer solution as power law fluid. To improve analysis results, a study to create new pressure interpretation models for polymer flooding reservoirs is needed. First, this study presents a new viscosity model by considering diffusion and conduction. Then the model is applied to set up a new model of an injection well located at an infinite polymer flooding reservoir. The modeling solutions have been prepared through numerical iterations. An extended study has been done about the characteristics of the new pressure response curves.

Study on Injection-Production Well Connectedness Evaluation Method in Polymer Flooding Reservoir

This paper introduces the Grey theory to evaluate the injection-production well connectedness in polymer flooding reservoir. Gery theory can give the law of the data by data analysis and calculation. Through the production data dynamic analysis and calculation using the Grey method, realized the injection-production well connectedness quantitative evaluation in polymer flooding reservoir. Comparing the injection-production well connectedness calculate by the Gery method with the tracer test result shows that using the Gery method to calculate the injection- production well connectedness can get reliable and accurate results. This method can be used to calculate the injection-production well connectedness in polymer flooding reservoir.

Technology Focus: EOR Performance and Modeling (January 2011)

Technology Focus SPE hosted two enhanced-oil-recovery (EOR) conferences in 2010: One was the 2010 SPE Improved Oil Recovery Symposium in Tulsa and the other was the 2010 SPE EOR Conference at Oil & Gas West Asia, Muscat, Oman. Many other SPE conferences had sessions on EOR technologies. Therefore, it is not surprising that more than 350 papers were presented on the topic in the past year. These papers covered past field-application experiences and accomplishments, current strides, and future directions. As in previous years, when I selected papers to highlight EOR this year, I classified the papers into the categories of gas injection, chemical methods, thermal methods, conformance control, microbial EOR, carbonate-reservoir EOR, reservoir-problem-identification technologies, and novel EOR methods such as low-salinity waterflooding and nanoparticles for EOR. However, it was still quite difficult to select only four to highlight from so many outstanding papers. In the past few EOR features, I highlighted chemical methods, CO2 EOR and sequestration, low-salinity waterflooding, particle gel for conformance control, wettability alteration, and methods to identify reservoir channels. Even though those topics are still quite important and many new ideas and information were presented this year, I decided to give preference to topics not highlighted before and to papers that comprehensively summarize field experiences. Overall, the leading-edge EOR technologies presented in SPE meetings this past year will be applied increasingly on a global scale and will increase the oil recovery of mature oil fields significantly as the technologies mature. EOR Performance and Modeling additional reading available at OnePetro: www.onepetro.org SPE 133089 • “Rock/Fluid Characterization for Miscible-CO2 Injection: Residual-Oil Zone, Seminole Field, Permian Basin” by M.M. Honarpour, SPE, Hess Corporation, et al. SPE 129899 • “Potential for Polymer Flooding Reservoirs With Viscous Oils” by R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center. See SPE Res Eval & Eng, August 2010, page 730. SPE 132487 • “Air Injection in Heavy-Oil Reservoirs—A Process Whose Time Has Come (Again)” by M.G. Ursenbach, SPE, University of Calgary, et al. See J Can Pet Technol, January 2010, page 48. SPE 129925 • “Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility-Control Applications” by David Espinosa, SPE, University of Texas at Austin, et al. SPE 129692 • “Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska” by Jim Seccombe, SPE, BP plc, et al. SPE 139667 • “Tertiary Oil Recovery and CO2 Sequestration by Carbonated-Water Injection” by N.I. Kechut, SPE, Heriot-Watt University, et al. SPE 132359 • “Identifying Injector/Producer Relationships in Waterflood Using Hybrid Constrained Nonlinear Optimization” by H. Lee, University of Southern California, et al.

Potential for Polymer Flooding Reservoirs with Viscous Oils

Summary This paper examines the potential of polymer flooding to recover viscous oils, especially in reservoirs that preclude the application of thermal methods. A reconsideration of enhanced-oil-recovery (EOR) screening criteria revealed that higher oil prices, modest polymer prices, increased use of horizontal wells, and controlled injection above the formation parting pressure all help considerably to extend the applicability of polymer flooding in reservoirs with viscous oils. Fractional-flow calculations demonstrated that the high mobile-oil saturation, degree of heterogeneity, and relatively free potential for crossflow in our target North Slope reservoirs also promote the potential for polymer flooding. For existing EOR polymers, viscosity increases roughly with the square of polymer concentration—a fact that aids the economics for polymer flooding of viscous oils. A simple benefit analysis suggested that reduced injectivity may be a greater limitation for polymer flooding of viscous oils than the cost of chemicals. For practical conditions during polymer floods, the vertical sweep efficiency using shear-thinning fluids is not expected to be dramatically different from that for Newtonian or shear-thickening fluids. The overall viscosity (resistance factor) of the polymer solution is of far greater relevance than the rheology.

Characteristics of remaining oil viscosity in water- and polymer-flooding reservoirs in Daqing Oilfield

The experimental analysis of 21 crude oil samples shows a good correlation between high molecular-weight hydrocarbon components (C40+) and viscosity. Forty-four remaining oil samples extracted from oil sands of oilfield development coring wells were analyzed by high-temperature gas chromatography (HTGC), for the relative abundance of C21−, C21–C40 and C40+ hydrocarbons. The relationship between viscosity of crude oil and C40+ (%) hydrocarbons abundance is used to expect the viscosity of remaining oil. The mobility characteristics of remaining oil, the properties of remaining oil, and the next displacement methods in reservoirs either water-flooded or polymer-flooded are studied with rock permeability, oil saturation of coring wells, etc. The experimental results show that the hydrocarbons composition, viscosity, and mobility of remaining oil from both polymer-flooding and water-flooding reservoirs are heterogeneous, especially the former. Relative abundance of C21− and C21–C40 hydrocarbons in polymer-flooding reservoirs is lower than that of water-flooding, but with more abundance of C40+ hydrocarbons. It is then suggested that polymer flooding must have driven more C40− hydrocarbons out of reservoir, which resulted in relatively enriched C40+, more viscous oils, and poorer mobility. Remaining oil in water-flooding reservoirs is dominated by moderate viscosity oil with some low viscosity oil, while polymer-flooding mainly contained moderate viscosity oil with some high viscosity oil. In each oilfield and reservoir, displacement methods of remaining oil, viscosity, and concentration by polymer-solution can be adjusted by current viscosity of remaining oil and mobility ratio in a favorable range. A new basis and methods are suggested for the further development and enhanced oil recovery of remaining oil.

Designing of Partial Similarity Models and Evaluation Method in Polymer Flooding Experiment

Based on the scaling criteria of polymer flooding reservoir obtained in our previous work in which the gravity and capillary forces, compressibility, non-Newtonian behavior, absorption, dispersion, and diffusion are considered, eight partial similarity models are designed. A new numerical approach of sensitivity analysis is suggested to quantify the dominance degree of relaxed dimensionless parameters for partial similarity model. The sensitivity factor quantifying the dominance degree of relaxed dimensionless parameter is defined. By solving the dimensionless governing equations including all dimensionless parameters, the sensitivity factor of each relaxed dimensionless parameter is calculated for each partial similarity model; thus, the dominance degree of the relaxed one is quantitatively determined. Based on the sensitivity analysis, the effect coefficient of partial similarity model is defined as the summation of product of sensitivity factor of relaxed dimensionless parameter and its relative relaxation quantity. The effect coefficient is used as a criterion to evaluate each partial similarity model. Then the partial similarity model with the smallest effect coefficient can be singled out to approximate to the prototype. Results show that the precision of partial similarity model is not only determined by the number of satisfied dimensionless parameters but also the relative relaxation quantity of the relaxed ones.

Sensitivity Analysis of the Dimensionless Parameters in Scaling a Polymer Flooding Reservoir

A set of scaling criteria of a polymer flooding reservoir is derived from the governing equations, which involve gravity and capillary force, compressibility of water, oil, and rock, non-Newtonian behavior of the polymer solution, absorption, dispersion, and diffusion, etc. A numerical approach to quantify the dominance degree of each dimensionless parameter is proposed.With this approach, the sensitivity factor of each dimensionless parameter is evaluated. The results show that in polymer flooding, the order of the sensitivity factor ranges from 10−5 to 100 and the dominant dimensionless parameters are generally the ratio of the oil permeability under the condition of the irreducible water saturation to water permeability under the condition of residual oil saturation, density, and viscosity ratios between water and oil, the reduced initial oleic phase saturation and the shear rate exponent of the polymer solution. It is also revealed that the dominant dimensionless parameters may be different from case to case. The effect of some physical variables, such as oil viscosity, injection rate, and permeability, on the dominance degree of the dimensionless parameters is analyzed and the dominant ones are determined for different cases.