Inaccessible Pore Volume Research Articles

Comparative Study of Green and Synthetic Polymers for Enhanced Oil Recovery.

Several publications by authors in the field of petrochemical engineering have examined the use of chemically enhanced oil recovery (CEOR) technology, with a specific interest in polymer flooding. Most observations thus far in this field have been based on the application of certain chemicals and/or physical properties within this technique regarding the production of 50–60% trapped (residual) oil in a reservoir. However, there is limited information within the literature about the combined effects of this process on whole properties (physical and chemical). Accordingly, in this work, we present a clear distinction between the use of xanthan gum (XG) and hydrolyzed polyacrylamide (HPAM) as a polymer flood, serving as a background for future studies. XG and HPAM have been chosen for this study because of their wide acceptance in relation to EOR processes. To this degree, the combined effect of a polymer’s rheological properties, retention, inaccessible pore volume (PV), permeability reduction, polymer mobility, the effects of salinity and temperature, and costs are all investigated in this study. Further, the generic screening and design criteria for a polymer flood with emphasis on XG and HPAM are explained. Finally, a comparative study on the conditions for laboratory (experimental), pilot-scale, and field-scale application is presented.

Application of Fractional Flow Theory for Analytical Modeling of Surfactant Flooding, Polymer Flooding, and Surfactant/Polymer Flooding for Chemical Enhanced Oil Recovery

Fractional flow theory still serves as a powerful tool for validation of numerical reservoir models, understanding of the mechanisms, and interpretation of transport behavior in porous media during the Chemical-Enhanced Oil Recovery (CEOR) process. With the enrichment of CEOR mechanisms, it is important to revisit the application of fractional flow theory to CEOR at this stage. For surfactant flooding, the effects of surfactant adsorption, surfactant partition, initial oil saturation, interfacial tension, and injection slug size have been systematically investigated. In terms of polymer flooding, the effects of polymer viscosity, initial oil saturation, polymer viscoelasticity, slug size, polymer inaccessible pore volume (IPV), and polymer retention are also reviewed extensively. Finally, the fractional flow theory is applied to surfactant/polymer flooding to evaluate its effectiveness in CEOR. This paper provides insight into the CEOR mechanism and serves as an up-to-date reference for analytical modeling of the surfactant flooding, polymer flooding, and surfactant/polymer flooding CEOR process.

Determination of mesopores in the wood cell wall at dry and wet state

Wood porosity is of great interest for basic research and applications. One aspect is the cell wall porosity at total dry state. When water is absorbed by wood, the uptake of water within the cell wall leads to a dimension change of the material. A hypothesis for possible structures that hold the water is induced cell wall porosity. Nitrogen and krypton physisorption as well as high pressure hydrogen sorption and thermoporosimetry were applied to softwood and hardwood (pine and beech) in dry and wet state for determining surface area and porosity. Physisorption is not able to detect pores or surface area within the cell wall. Krypton physisorption shows surface area up 5 times lower than nitrogen with higher accuracy. With high pressure sorption no inaccessible pore volumes were seen at higher pressures. Thermoporosimetry was not able to detect mesopores within the hygroscopic water sorption region. Physisorption has to be handled carefully regarding the differences between adsorptives. The absence of water-induced mesopores within the hygroscopic region raise doubts on existing water sorption theories that assume these pore dimensions. When using the term “cell wall porosity”, it is important to distinguish between pores on the cell wall surface and pores that exist because of biological structure, as there are no water-induced mesopores present. The finding offers the possibility to renew wood-water-sorption theories because based on the presented results transport of water in the cell wall must be realized by structures lower than two 2 nm. Nanoporous structures in wood at wet state should be investigated more intensively in future.

Laboratory Evaluation of Polymer Retention in a Heavy Oil Sand for a Polymer Flooding Application on Alaska's North Slope

SummaryFor a polymer flooding field trial in a heavy oil reservoir on Alaska's North Slope, polymer retention is a key parameter. Because of the economic impact of retention, this parameter was extensively studied using field core material and conditions. In this paper, multiple types of laboratory measurements were used to assess hydrolyzed polyacrylamides (HPAM) polymer retention, including a brine tracer, effluent viscosity, total effluent organic carbon, and effluent chemiluminescent nitrogen. Retention tests were conducted in different Milne Point Schrader Bluff sands, with extensive permeability, grain size distribution, X-ray-diffraction (XRD), and X-ray fluorescence (XRF) characterizations. Several important findings were noted. Polymer retention based on effluent viscosity measurements can be overestimated unless the correct (nonlinear) relation between polymer concentration and viscosity is used. Polymer degradation (either mechanical or oxidative) can also lead viscosity-based measurements to overestimate retention. Inaccessible pore volume (PV) (IAPV) can be overestimated if insufficient brine is flushed through the sand between polymer banks. Around 100 PVs of brine may be needed to displace mobile polymer to approach a true residual resistance factor and properly measure IAPV. Even for a sandpack with kwsor = 20 md, IAPV was zero for HPAM with a molecular weight (Mw) of 18 MM g/mol. Fine-grained particles (<20 µm) strongly impacted polymer retention values. Native NB#1 sand with a significant component of particles <20 µm exhibited 290 µg/g, while the same sand exhibited 28 µg/g after these small particles were removed. Polymer retention did not necessarily correlate with mineral composition. The NB#1, NB#3, and OA sands had similar elemental and clay compositions, but the NB#1 sand exhibited ∼10 times higher retention than the NB#3 sand. Polymer retention did not necessarily correlate with permeability. NB#1 sand exhibited much higher retention than OA sand, even though NB#1 sand was twice as permeable as OA sand. No evidence of chromatographic separation of HPAM molecular weights was found in our experiments. Although retention tended to be greater without a residual oil saturation (than at Sor), the effect was not strong. Aging a core (with high oil saturation) at 60°C reduced HPAM retention by a factor of two. Under similar conditions, polymer retention was greater for a higher Mw HPAM (18 MM g/mol) than for a lower Mw HPAM (10 to 12 MM g/mol). In many cases with high polymer retention values (e.g., 240 µg/g), polymer arrival at the end of the core was relatively quick, but achieving the injected concentration occurred gradually over many PVs. This effect was not caused by chromatographic separation of polymer molecular weights. Results from modeling of this behavior were consistent with concentration-dependent polymer retention. The form assumed for the retention function in a simulator can have an important impact on the timing and magnitude of the oil response from a polymer flood. Field-based observations can underestimate polymer retention, depending on when the tracer and polymer concentrations were measured and the assumptions made about reservoir heterogeneity.

History matching of experimental polymer flooding for enhanced viscous oil recovery

Polymer flooding has been widely studied and applied for enhancing reservoir oil recovery. The key to evaluating the potential application of polymer injection is based on a clear understanding of the mechanisms involved in the recovery process. This work focuses on history matching of laboratory core flooding of heavy oil recovery by polymer flooding. We match the experiments through a small-scale simulation model and evaluate the challenges of representing the polymer behavior in porous media. The methodology we propose in this paper aims to model core-flooding experiments with laboratory-measured data. These data come from different experiments, including rheology, single- and two-phase core flooding and are separated into consolidated and uncertain data. Consolidated data include: core volume, permeability, porosity, oil viscosity and density, initial saturation conditions, test temperature and injection rate. The uncertain input parameters involve more complex variables, such as viscosity behavior against shear rate and concentration, residual resistance factor, adsorption, inaccessible pore volume and water–oil relative permeabilities. We compare the simulation output parameters with laboratory results and evaluate the quality of the match for four different two-phase core-flooding experiments. The output parameters include histories for differential pressure, recovery factor, water cut and cumulative produced water, oil and liquid. Our results show that the simulation models successfully matched the experimental data, for all the cases, using appropriate representation of the laboratory parameters. The contribution of this work relies on the proposed methodology, which allows integrating the laboratory data in the construction and validation of core scale simulation models appropriately.

Soluciones HPAM de baja concentración como método de reducción de la retención de polímeros en CEOR

Polymer Flooding has become one of the most implemented EOR techniques, due to three factors: First, Polymer flooding has expanded the range of the screening criteria parameters. Second, this EOR method is more effective than water injection, while handling water management issues in high water-cut reservoirs. Nevertheless, polymer retention can turn a viable technical project into an uneconomical one. Polymer loss due to retention is an inevitable phenomenon, which happens during injection processes. The development of experimental analysis aiming to minimize or reduce polymer loss from the displacing fluid bank is beneficial to broaden the application of this CEOR method. This experimental work evaluated the injection schemes aiming to reduce polymer retention in porous media. The approach consisted of injecting less-concentrated polymer banks followed for the main polymer bank designed for mobility control. An experimental methodology to quantify polymer retention due to each injected polymer bank, cumulative polymer retention, resistance factor, residual resistance factor and inaccessible pore volume (IPV) was developed. The measurement process was based on the injection of 20 PV polymer banks at a constant flow rate of 1ml/min at 25°C, separated by 30 PV brine banks. Two HPAM with molecular weights of 6-8 million and 20 million Daltons using 350mD and 5000 mD sandstone cores were tested, respectively. The HPAM solutions considering a Colombian field (0.7% NaCl) and seawater (3.5% TDS) salinities were prepared. All rock samples were previously submitted to the injection of 50 PV for preventing fines migration. Two injection schemes with variable polymer concentrations were performed: The first one in which the polymer concentration increased in each successive bank, and the second one in which the concentration decreased. HPAM concentration solutions from 50 ppm to 2000 ppm were sequentially used in both injection schemes. By comparing the results of these two schemes, the effect of the injection of the less-concentrated polymer solutions was evaluated. For the increasing concentration experiments, cumulative retention values of 175.7 μg/g and 58.9 μg/g were calculated for the low-molecular weight polymer and the high-molecular weight polymer, respectively. While comparing with decreasing concentration experiments, for the high-molecular weight HPAM a 19% of retention reduction was evidenced, but no retention reduction was observed for the low-molecular weight one. The results indicate that different retention mechanisms are strongly dependents on the absolute permeability of the samples. Additionally, IPV values of 0.5 PV and 0.25 PV were calculated using low and high permeability samples, respectively. There was no linear relation between the absolute permeability reduction and the polymer concentration of the first bank injected into the sample. The novelty of this work is to use sacrificial banks of less-concentrated HPAM solutions as a reducing retention agent for the polymer bank designed for mobility control.

Investigation of an Improved Polymer Flooding Scheme by Compositionally-Tuned Slugs

Polymer flooding is an effective enhanced oil recovery technology used to reduce the mobility ratio and improve sweep efficiency. A new polymer injection scheme is investigated that relies on the cyclical injection of low-salinity, low-concentration polymer slugs chased by high-salinity, high-concentration polymer slugs. The effectiveness of the process is a function of several reservoir and design parameters related to polymer type, concentration, salinity, and reservoir heterogeneity. We use reservoir simulations and design-of-experiments (DoE) to investigate the effectiveness of the proposed polymer injection scheme. We show how key objective functions, such as recovery factor and injectivity, are impacted by the reservoir and design parameters. In this study, simulations showed that the new slug-based process was always superior to the reference polymer injection scheme using the traditional continuous injection scheme. Our results show that the process is most effective when the polymer weight is high, corresponding to large inaccessible pore-volumes, which enhances polymer acceleration. High vertical heterogeneity typically reduces the process performance because of increased mixing in the reservoir. The significance of this process is that it allows for increased polymer solution viscosity in the reservoir without increasing the total mass of polymer, and without impairing polymer injectivity at the well.

Experimental evaluation of low concentration scleroglucan biopolymer solution for enhanced oil recovery in carbonate

Injection of polymers is beneficial for Enhanced Oil Recovery (EOR) because it improves the mobility ratio between the displaced oil and the displacing injected water. Because of that benefit, polymer flooding improves sweep and displacing efficiencies when compared to waterflooding. Due to these advantages, polymer flooding has many successful applications in sandstone reservoirs. However, polymer flooding through carbonatic rock formations is challenging because of heterogeneity, high anionic polymer retention, low matrix permeability, and hardness of the formation water. The scleroglucan is a nonionic biopolymer with the potential to overcome some of those challenges, albeit its elevated price. Thus, the objective of this work is to characterize low concentration scleroglucan solutions focusing on EOR for offshore carbonate reservoirs. The laboratory evaluation consisted of rheology, filtration, and core flooding studies, using high salinity multi-ionic brines and light mineral oil. The tests were run at 60 °C, and Indiana limestone was used as a surrogate reservoir rock. A rheological evaluation was done in a rotational rheometer aiming to select a target polymer concentration for the injection fluid. Different filtration procedures were performed using membrane filters to prepare the polymer solution for the displacement process. Core flooding studies were done to characterize the polymer solution and evaluate its oil recovery relative to waterflooding. The polymer was characterized for its retention, inaccessible pore volume, resistance factor,in-situviscosity, and permeability reduction. Rheology studies for various polymer concentrations indicated a target scleroglucan concentration of 500 ppm for the injection solution. Among the tested filtration methods, the best results were achieved when a multi-stage filtration was performed after an aging period of 24 h at 90 °C temperature. The single-phase core flooding experiment resulted in low polymer retention (20.8 μg/g), inaccessible pore volume (4.4%), and permeability reduction (between 1.7 and 2.4). The polymer solutionin-situviscosity was slightly lower and less shear-thinning than the bulk one. The tested polymer solution was able to enhance the oil recovery relative to waterflooding, even with a small reduction of the mobility ratio (38% relative reduction). The observed advantages consisted of water phase breakthrough delay (172% relative delay), oil recovery anticipation (159% and 10% relative increase at displacing fluid breakthrough and 95% water cut, respectively), ultimate oil recovery increase (6.3%), and water-oil ratio reduction (38% relative decrease at 95% water cut). Our results indicate that the usage of low concentration scleroglucan solutions is promising for EOR in offshore carbonate reservoirs. That was supported mainly by the low polymer retention, injected solution viscosity maintenance under harsh conditions, and oil recovery anticipation.

Numerical simulations of polymer flooding process in porous media on distributed-memory parallel computers

Polymer flooding is a mature enhanced oil recovery technique that has been successfully applied in many field projects. By injecting polymer into a reservoir, the viscosity of water is increased, and the efficiency of water flooding is improved. As a result, more oil can be recovered. This paper presents numerical simulations of a polymer flooding process using parallel computers, where the numerical modeling of polymer retention, inaccessible pore volumes, a permeability reduction and polymer absorption are considered. Darcy's law is employed to model the behavior of a fluid in porous media, and the upstream finite difference (volume) method is applied to discretize the mass conservation equations. Numerical methods, including discretization schemes, linear solver methods, nonlinearization methods and parallel techniques are introduced. Numerical experiments show that, on one hand, computed results match those from the commercial simulator, Eclipse, Schlumberger, which is widely applied by the petroleum industry, and, on the other hand, our simulator has excellent speedup, which is demonstrated by large-scale applications with up to 27 million grid blocks using up to 2048 CPU cores.

Polymer Gels Made with Functionalized Organo-Silica Nanomaterials for Conformance Control

Deep placement of gel in waterflooded hydrocarbon reservoirs may block channels with high water flow and may divert the water into other parts of the reservoir, resulting in higher oil production. In order to get the gel constituents to the right reservoir depths, a delay in the gelling time in the order of weeks at elevated temperatures will be necessary. In this work, a methodology for controlled gelation of partially hydrolyzed polyacrylamide using hybrid nanomaterials with functional groups as cross-linkers was developed. Two delay mechanisms with hybrid materials and polyelectrolyte complexes were designed and tested. Both mechanisms could significantly delay the gelation rate, giving gelling times ranging from several days to several weeks in synthetic sea water at 80 °C. Gelling experiments in sandstone cores showed that gel strength increased with aging time. For long aging times, strong gels were formed which resulted in almost no water permeability. A series of coreflooding experiments with polymer and deactivated nanomaterial were performed. In addition to differential pressures and concentration profiles, the experiments enabled calculation of retention and inaccessible pore volumes. A novel numerical model of 1D two-phase flow has been developed and tested with results from core flooding experiments. The model can track the age distribution and concentrations of the nanomaterial (and therefore water viscosity) throughout the porous medium at every time step. The model generated a good fit of experimental results.

NANOFLUID INJECTIVITY STUDY FOR ITS APPLICATION IN A PROCESS OF ENHANCED OIL RECOVERY (CEOR)

The application of tertiary recovery techniques through chemical injection (CEOR) is in full development in the mature oil fields of Argentina. An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. A polyacrylamide solution prepared in brine with addition of silica nanoparticles was used as the focus of the study. Dynamic sweep tests of the displacement fluids in a laboratory-scale triaxial cell using a standard Berea sandstone cores that simulates the formation of the reservoir allow the calculation of parameters related to its injectivity, which take into account damage to the formation and blockade of poral throats , such as the resistance factor (FR), the residual resistance factor (FRR), the inaccessible pore volume (VPI) and the dynamic retention of the nanofluid (RD). The injection of the nanofluid has not produced an increase in the damage of the porous medium, so it is potential for its application in the displacement of crude oil.

POLYMER APPARENT VISCOSITY DEPENDENCE ON INACCESSIBLE PORE VOLUME: LABORATORY AND FIELD STUDIES OF ITS INFLUENCE ON ENHANCED OIL RECOVERY

The successful use of polymer-enhanced oil recovery observed in the last two decades is leading to effective field implementations. One of the reasons for such positive results in polymer flooding is the integration between laboratory-measured properties and reservoir simulation. Recent reports show that inaccessible pore volume (IAPV) plays a significant role in the apparent viscosity of random coil polymers, such as hydrolyzed polyacrylamide (HPAM). This paper assesses both direct and indirect impacts of IAPV on polymer flooding. This investigation relies on laboratory and field-scale simulations of polymer flooding using CMG-STARS. Simulation cases review the effects of IAPV on production indicators in direct and indirect forms. This study compares laboratory-scale simulations with experimental results and uses quality indicators to evaluate the history matching of both approaches. It relies on a modified benchmark field case to study both approaches in comparison to waterflooding and idealized polymer flooding. Results indicate that IAPV has a small direct impact on production curves. However, data show significant indirect implications of the IAPV on recovery. This effect occurs because the apparent viscosity of HPAM has a direct relationship with IAPV. Although the simulation results were consistent with current literature, the results obtained through the experiments indicate that the most realistic simulation case is achieved when considering the impact of IAPV on polymer viscosity.

A numerical model to evaluate formation properties through pressure-transient analysis with alternate polymer flooding

A numerical pressure transient analysis method of composite model with alternate polymer flooding is presented, which is demonstrated by field test data provided by China National Petroleum Corporation. Polymer concentration distribution and viscosity distribution are obtained on the basis of polymer rheological model, considering shear effect, convection, diffusion, inaccessible pore volume and permeability reduction of polymer. Pressure analysis mathematical model is established by considering wellbore storage effect and skin effect. Type curves are then developed from mathematical model which have seven sections and parameter sensitivity is analyzed, among which the transient sections of low-concentration and high-concentration hydrolyzed polyacrylamides (HPAM) solution, high-concentration HPAM solution and crude oil show obvious concave shape on pressure derivative curve due to different viscosities of three zones. Formation parameters and viscosity distribution of polymer solution can be calculated by type-curve matching. The polymer flooding field tests prove that the three-zone composite model can reasonably calculate formation parameters in onshore oilfield with alternate polymer flooding, which demonstrate the application potential of the analysis method.

Rheology-based method for calculating polymer inaccessible pore volume in core flooding experiments

Polymer flooding is an enhanced oil recovery (EOR) method that reduces the mobility ratio between the displaced oil and the displacing injected water. The flow of polymer solutions through porous media is subject to some process-specific phenomena, such as the inaccessible pore volume (IAPV). Due to IAPV, polymer molecules move faster through the porous medium than smaller ones. Thus the IAPV value needs to be accounted for in experiments and field projects. Recent reports found that polymer in-situ rheology correlates with the IAPV. The objective of this paper is to develop a method for estimating IAPV based on the in-situ rheology of polymers. The methodology proposed here can be used in both single- and two-phase experiments. The technique requires measurement of polymer resistance factor (RF) and residual resistance factor (RRF) at steady state conditions. Core permeability, porosity, and residual oil saturation, as well as water and polymer bulk viscosities, also need to be taken into account. Correlations for polymer in-situ viscosity and shear rate are solved simultaneously, to wield an estimative for the IAPV. Aiming at to prove the method, we report 16 core-flooding experiments, eight single- and eight two-phase experiments. We used a flexible polymer and sandstone cores. All the tests were run using similar rock samples. In the single-phase experiments, we compare the alternative method with the classic tracer method to estimate IAPV. The results show an average relative difference of 11.5% between the methods. The two-phase results display, on average, an 18% relative difference to the IAPV measured in the single-phase experiments. The difference between single- and two-phase results can be an effect of the higher shear rates experienced in the two-phase floodings since, in these cases, the aqueous phase shear rate is also dependent on the phase saturation. Additionally, temperature, core length, pore pressure, and iron presence on the core did not show any influence on the IAPV for our two-phase experiments. The method proposed in this paper is limited by the accuracy of the pressure drop measurements across the core. For flexible polymers, the method is valid only for low and mid shear rates, but, accoording to literature, for rigid polymers the method should be accurate for a broad range of shear rates. The method proposed here allows the measurement of polymer IAPV on two- and single- phase core-flooding experiments when a tracer is not used.

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.

An Inversion Method of Relative Permeability Curves in Polymer Flooding Considering Physical Properties of Polymer

Summary Reliable relative permeability curves of polymer flooding are of great importance to the history matching, production prediction, and design of the injection and production plan. Currently, the relative permeability curves of polymer flooding are obtained mainly by the steady-state, nonsteady-state, and pore-network methods. However, the steady-state method is extremely time-consuming and sometimes produces huge errors, while the nonsteady-state method suffers from its excessive assumptions and is incapable of capturing the effects of diffusion and adsorption. As for the pore-network method, its scale is very small, which leads to great size differences with the real core sample or the field. In this paper, an inversion method of relative permeability curves in polymer flooding is proposed by combining the polymer-flooding numerical-simulation model and the Levenberg-Marquardt (LM) algorithm. Because the polymer-flooding numerical-simulation model by far offers the most-complete characterization of the flowing mechanisms of polymer, the proposed method is able to capture the effects of polymer viscosity, residual resistance, diffusion, and adsorption on the relative permeability. The inversion method was then validated and applied to calculate the relative permeability curve from the experimental data of polymer flooding. Finally, the effects of the influencing factors on the inversion error were analyzed, through which the inversion-error-prediction model of the relative permeability curve was built by means of multivariable nonlinear regression. The results show that the water relative permeability in polymer flooding is still far less than that in waterflooding, although the residual resistance of the polymer has been considered in the numerical-simulation model. Moreover, the accuracy of the polymer parameters has great effect on that of the inversed relative permeability curve, and errors do occur in the inversed water relative permeability curve—the measurements of the polymer solution viscosity, residual resistance factor, inaccessible pore-volume (PV) fraction, or maximum adsorption concentration have errors.

Distribution and Presence of Polymers in Porous Media

In order to better utilize the residual polymers formed after polymer flooding, the distribution and the presence of the polymers after polymer flooding were studied. This paper studied the vertical and plane distribution of the hydrophobically-associating polymer in addition to measuring the parameters after polymer flooding, which is important for numerical reservoir simulation. The results showed that the polymers mainly enter into the high permeability zone and distribute in the mainstream line area with only a small portion in the wing area. Based on the comparison of various experimental methods, double-slug experiments were chosen to measure the inaccessible pore volume and retention, which is considered to be the most accurate, most time-consuming and most complex method. Following this, we improved the processing method of experimental data by reducing it to one experiment with two parameters. At the same time, we further enhanced the accuracy of the experimental results. The results show that at 1750 mg/L, the inaccessible pore volume of the polymer is 25.8%. When the detention is 68.2 µg/g, the inaccessible pore volume constituted 22% of the total polymer, with the other 77.7% being the dissolved polymer. Moreover, the static adsorption and dynamic detention were measured, with the results showing that the static adsorption is larger than dynamic detention. Therefore, in the numerical reservoir simulation, using the static adsorption capacity instead of the dynamic detention is unreasonable. The double-slug method was chosen since it is more accurate for the determination of various parameters. Meanwhile, in order to enhance the accuracy of results, we improved the treatment of data.

Computation of polymer in-situ rheology using direct numerical simulation

In-situ rheology of synthetic polymers like hydrolyzed polyacrylamide, HPAM, cannot be directly calculated from bulk rheology. The in-situ viscosity of polymers will be influenced by shear history and local pore structure contraction/expansion. Transition from flux in porous media to bulk shear rate requires empirical correlations. The conventional approach for in-situ rheology is to define apparent viscosity vs. Darcy velocity and connecting Darcy velocity to bulk shear rate by using a correction factor, which generally depends on both polymer and rock properties.Estimating polymer in-situ rheology is important for estimation of displacement pressure gradients and injectivity in the reservoir. In the following study, different models used to quantify the shear-to-flux correction factor are compared by using direct numerical simulation in 3D real rock images. We found that the models developed based on capillary bundle approach are not able to predict accurately in-situ rheology and microstructures of a rock sample can influence in-situ rheology. A novel approach is suggested to provide a more accurate prediction of in-situ rheology by adjusting appropriately bulk power index of the Carreau model before applying the correction factor. The pore scale simulations have revealed that the key parameters of porous media influencing in-situ rheology are pore aspect ratio and inaccessible pore volume.

Impact of flow rate variation in dynamic properties of a terpolymer in sandstone

The effectiveness of polymer enhanced oil recovery relies on its dynamic properties in the porous medium, such as resistance factor (RF), residual resistance factor (RRF), inaccessible pore volume (IAPV), in-situ viscosity, and retention. This paper presents a laboratory investigation of the injection flow rate on those properties of a terpolymer containing hydrolyzed polyacrylamide flowing through sandstone. We propose a methodology and evaluate the flow rate influence by both increasing and decreasing its values in different experiments. The materials, experimental setup, test protocol, and data treatment are explained thoroughly to allow reproduction. We analyze three different methodologies to measure dynamic retention, and we compare the results with one another. We report both irreversible (due to adsorption) and reversible (due to hydrodynamic effects) retentions, and also analyze their trends. In our experiments, reversible retention, RF, and RRF increase with the flow rate. The IAPV do not show any trend regarding the flow rate. We also obtain a good correlation between in-situ viscosity and a literature model. Our results indicate that the in-situ viscosity correlates to the IAPV.

Laboratory Experiment on Inaccessible Pore Volume of Polymer Flooding

The research on inaccessible pore volume is completed on the basis of laboratory experiments. The experiment prepared 4 different kinds of polymers, whose molecular weight are 8 million, 12 million, 16 million and 20 million whose molecular coil size are measured by light blockage counter. Through kerosene mass method we can get pore cumulative distribution of field cores and finally plot the relation between the inaccessible pore volume and molecular coil size of polymer. The size of small pore where primary water was taken as the minimum number polymer coils can be passed. Then the polymer molecular weight with better compatibility with rock pores is optimized. The study shows with the increase of polymer relative molecular mass, pore volume increased linearly. The conclusion can better guide the selection of the polymers in practical production.