Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

scholarly journals Laboratory evaluation and numerical simulation of the alkali–surfactant–polymer synergistic mechanism in chemical flooding

RSC Advances ◽  
2018 ◽  
Vol 8 (47) ◽  
pp. 26476-26487 ◽  
Author(s):  
Fuzhen Chen ◽  
Jianwei Gu ◽  
Hanqiao Jiang ◽  
Xue Yao ◽  
Yuan Li
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Laboratory Evaluation ◽  
Chemical Flooding ◽  
Asp Flooding ◽  
Synergistic Mechanism

This paper aims to reveal alkali–surfactant–polymer synergistic mechanism and construct corresponding novel ASP flooding numerical simulation model.

scholarly journals Study on the regional characteristics during foam flooding by population balance model

2020 ◽  
pp. 014459872098361
Author(s):  
Zhongbao Wu ◽  
Qingjun Du ◽  
Bei Wei ◽  
Jian Hou
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Population Balance ◽  
Growth Zone ◽  
Balance Model ◽  
Population Balance Model ◽  
Liquid Ratio ◽  
One Dimensional ◽  
Foam Flooding

Foam flooding is an effective method for enhancing oil recovery in high water-cut reservoirs and unconventional reservoirs. It is a dynamic process that includes foam generation and coalescence when foam flows through porous media. In this study, a foam flooding simulation model was established based on the population balance model. The stabilizing effect of the polymer and the coalescence characteristics when foam encounters oil were considered. The numerical simulation model was fitted and verified through a one-dimensional displacement experiment. The pressure difference across the sand pack in single foam flooding and polymer-enhanced foam flooding both agree well with the simulation results. Based on the numerical simulation, the foam distribution characteristics in different cases were studied. The results show that there are three zones during foam flooding: the foam growth zone, stable zone, and decay zone. These characteristics are mainly influenced by the adsorption of surfactant, the gas–liquid ratio, the injection rate, and the injection scheme. The oil recovery of polymer-enhanced foam flooding is estimated to be 5.85% more than that of single foam flooding. Moreover, the growth zone and decay zone in three dimensions are considerably wider than in the one-dimensional model. In addition, the slug volume influences the oil recovery the most in the foam enhanced foam flooding, followed by the oil viscosity and gas-liquid ratio. The established model can describe the dynamic change process of foam, and can thus track the foam distribution underground and aid in optimization of the injection strategies during foam flooding.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SPE Journal ◽  
2020 ◽  
pp. 1-26
Author(s):  
Sajjaat Muhemmed ◽  
Harish Kumar ◽  
Nicklaus Cairns ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Dioxide ◽  
Water Saturation ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Carbonate Mineral ◽  
Carbonate Minerals ◽  
Oil Saturation ◽  
The Core ◽  
Three Phase ◽  
Water Saturated

Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study

Laboratory Tests on Heavy Oil Recovery by Steam Injection

1983 ◽  
Vol 23 (03) ◽  
pp. 417-426 ◽  
Author(s):  
Philip J. Closmann ◽  
Richard D. Seba
Keyword(s):  
Pore Size ◽  
Heat Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Unconsolidated Sand

Abstract This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions. Introduction Considerable attention has been given to thermal techniques for stimulating production of underground hydrocarbons, particularly the more viscous oils production of underground hydrocarbons, particularly the more viscous oils and tars. Steam injection has been studied as one means of heating oil in place, reducing its viscosity, and thus making its displacement easier. place, reducing its viscosity, and thus making its displacement easier. A number of investigators have measured residual oil saturations remaining in the steam zone. Willman et al. also analyzed the steam displacement process to account for the oil recoveries observed. A number of methods have been developed to calculate the size of the steam zone and to predict oil recoveries by application of Buckley-Leverett theory, including the use of numerical simulation. The work described here was devoted to an experimental determination of oil recovery by steam injection in linear systems. The experiments were unscaled as far as fluid flow rates, gravity forces, and heat losses were concerned. Part of the study was to determine recoveries of naturally occurring very viscous tars in a suite of cores containing their original oil saturation. The cores numbered 95, 140, and 143 are a part of this group. Heterogeneities in these cores, however, led to the extension of the work to more uniform systems, such as sandpacks and Dalton sandstone cores. Our interest was in obtaining an overall view of important variables that affected recovery. In particular, because of the significant effect of steam distillation, most of the oils used in this study were chosen to avoid this factor. We also studied the effect of pore size on the residual oil saturation. As part of this work, we investigated the effect of the amount of water flushed through the system ahead of the steam front in several ways:the production rate was varied by a factor of four,the initial oil saturation was varied by a factor of two, andthe rate of heat loss was varied by removing the heat insulation from the flow system. Description of Apparatus and Experimental Technique Two types of systems were studied: unconsolidated sand and consolidated sandstone. The former type was provided by packing a section of pipe with 50–70 mesh Ottawa sand. Most runs on this type of system were in an 18-in. (45.72-cm) section of 1 1/2 -in. (3.8 1 -cm) diameter pipe, although runs on 6-in. (15.24-cm) and 5-ft (152.4-cm) lengths were also included. Consolidated cores 9 to 13 in. (22.86 to 33.02 cm) long and approximately 2 1/4 in. (5.72 cm) in diameter were sealed in a piece of metal pipe by means of an Epon/sand mixture. A photograph of two 9-in. (22.86-cm) consolidated natural cores (marked 95 and 143) from southwest Missouri, containing original oil, is shown as Fig. 1. In all steamdrive runs, the core was thermally insulated to reduce heat loss, unless the effect of heat loss was specifically being studied. Flow was usually horizontal except for the runs in which the effects of flushing water volume and of unconsolidated-sand pore size were examined. Micalex end pieces were used on the inlet end in initial experiments with consolidated cores to reduce heat leakage from the steam line to the metal jacket on the outside of the core. During most runs, however, the entire input assembly eventually became hot. SPEJ p. 417

scholarly journals Variations of Micropores in Oil Reservoir Before and After Strong Alkaline Alkaline-surfactant-polymer Flooding

2016 ◽  
Vol 9 (1) ◽  
pp. 257-267
Author(s):  
Yongqiang Bai ◽  
Yang Chunmei ◽  
Liu Mei ◽  
Jiang Zhenxue
Keyword(s):  
Quantitative Analysis ◽  
Crude Oil ◽  
Oil Recovery ◽  
Chemical Flooding ◽  
Sem Images ◽  
Force Microscopy ◽  
Micropore Structure ◽  
Asp Flooding ◽  
Before And After ◽  
Alkaline Surfactant Polymer

Enhanced oil recovery (EOR) provides a significant contribution for increasing output of crude oil. Alkaline-surfactant-polymer (ASP), as an effective chemical method of EOR, has played an important role in advancing crude oil output of the Daqing oilfield, China. Chemical flooding utilized in the process of ASP EOR has produced concerned damage to the reservoir, especially from the strong alkali of ASP, and variations of micropore structure of sandstones in the oil reservoirs restrain output of crude oil in the late stages of oilfield development. Laboratory flooding experiments were conducted to study sandstones’ micropore structure behavior at varying ASP flooding stages. Qualitative and quantitative analysis by cast thin section, scanning electric microscopy (SEM), atomic force microscopy (AFM) and electron probe X-Ray microanalysis (EPMA) explain the mechanisms of sandstones’ micropore structure change. According to the quantitative analysis, as the ASP dose agent increases, the pore width and pore depth exhibit a tendency of decrease-increase-decrease, and the specific ASP flooding stage is found in which flooding stage is most affective from the perspective of micropore structures. With the analysis of SEM images and variations of mineral compositions of samples, the migration of intergranular particles, the corrosions of clay, feldspar and quartz, and formation of new intergranular substances contribute to the alterations of sandstone pore structure. Results of this study provide significant guidance for further application to ASP flooding.

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

Parameters Estimation for Chemical Flooding Modeling Using Ensemble-Based Method

2021 ◽  
Author(s):  
Xindan Wang ◽  
Yin Zhang ◽  
Abhijit Dandekar ◽  
Yudou Wang
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
History Matching ◽  
Simulation Models ◽  
Parameters Estimation ◽  
Model Parameters ◽  
Chemical Flooding ◽  
Multiple Model ◽  
Assisted History Matching ◽  
Matching Techniques

Abstract Chemical flooding has been widely used to enhance oil recovery after conventional waterflooding. However, it is always a challenge to model chemical flooding accurately since many of the model parameters of the chemical flooding cannot be measured accurately in the lab and even some parameters cannot be obtained from the lab. Recently, the ensemble-based assisted history matching techniques have been proven to be efficient and effective in simultaneously estimating multiple model parameters. Therefore, this study validates the effectiveness of the ensemble-based method in estimating model parameters for chemical flooding simulation, and the half-iteration EnKF (HIEnKF) method has been employed to conduct the assisted history matching. In this work, five surfactantpolymer (SP) coreflooding experiments have been first conducted, and the corresponding core scale simulation models have been built to simulate the coreflooding experiments. Then the HIEnKF method has been applied to calibrate the core scale simulation models by assimilating the observed data including cumulative oil production and pressure drop from the corresponding coreflooding experiments. The HIEnKF method has been successively applied to simultaneously estimate multiple model parameters, including porosity and permeability fields, relative permeabilities, polymer viscosity curve, polymer adsorption curve, surfactant interfacial tension (IFT) curve and miscibility function curve, for the SP flooding simulation model. There exists a good agreement between the updated simulation results and observation data, indicating that the updated model parameters are appropriate to characterize the properties of the corresponding porous media and the fluid flow properties in it. At the same time, the effectiveness of the ensemble-based assisted history matching method in chemical enhanced oil recovery (EOR) simulation has been validated. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the influence of injection schemes and operating parameters of SP flooding on the ultimate oil recovery performance. It has been found that the polymer concentration, surfactant concentration and slug size of SP flooding have a significant impact on oil recovery, and these parameters need to be optimized to achieve the maximum economic benefit.

Constructing Dual-Porosity Models from High-Resolution Discrete-Fracture Models Using Deep Neural Networks

2021 ◽  
Author(s):  
Xupeng He ◽  
Ryan Santoso ◽  
Marwa Alsinan ◽  
Hyung Kwak ◽  
Hussein Hoteit
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Water Saturation ◽  
Dual Porosity ◽  
Discrete Fracture Model ◽  
Discrete Fracture ◽  
Dual Porosity Model ◽  
Reservoir Simulation Model ◽  
Porosity Model

Abstract Detailed geological description of fractured reservoirs is typically characterized by the discrete-fracture model (DFM), in which the rock matrix and fractures are explicitly represented in the form of unstructured grids. Its high computation cost makes it infeasible for field-scale applications. Traditional flow-based and static-based methods used to upscale detailed geological DFM to reservoir simulation model suffer from, to some extent, high computation cost and low accuracy, respectively. In this paper, we present a novel deep learning-based upscaling method as an alternative to traditional methods. This work aims to build an image-to-value model based on convolutional neural network to model the nonlinear mapping between the high-resolution image of detailed DFM as input and the upscaled reservoir simulation model as output. The reservoir simulation model (herein refers to the dual-porosity model) includes the predicted fracture-fracture transmissibility linking two adjacent grid blocks and fracture-matrix transmissibility within each coarse block. The proposed upscaling workflow comprises the train-validation samples generation, convolutional neural network training-validating process, and model evaluation. We apply a two-point flux approximation (TPFA) scheme based on embedded discrete-fracture model (EDFM) to generate the datasets. We perform trial-error analysis on the coupling training-validating process to update the ratio of train-validation samples, optimize the learning rate and the network architecture. This process is applied until the trained model obtains an accuracy above 90 % for both train-validation samples. We then demonstrate its performance with the two-phase reference solutions obtained from the fine model in terms of water saturation profile and oil recovery versus PVI. Results show that the DL-based approach provides a good match with the reference solutions for both water saturation distribution and oil recovery curve. This work manifests the value of the DL-based method for the upscaling of detailed DFM to the dual-porosity model and can be extended to construct generalized dual-porosity, dual-permeability models or include more complex physics, such as capillary and gravity effects.

Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water

SPE Journal ◽  
2009 ◽  
Vol 15 (01) ◽  
pp. 184-196 ◽  
Author(s):  
Adam K. Flaaten ◽  
Quoc P Nguyen ◽  
Jieyuan Zhang ◽  
Hourshad Mohammadi ◽  
Gary A. Pope
Keyword(s):  
Sodium Carbonate ◽  
Oil Recovery ◽  
High Performance ◽  
High Salinity ◽  
Divalent Cations ◽  
Low Cost ◽  
Soft Water ◽  
Chemical Flooding ◽  
Asp Flooding ◽  
Alkaline Surfactant Polymer

Summary Alkaline/surfactant/polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition, and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines having high salinity and hardness. We demonstrate this approach by combining high-performance, low-cost surfactants with cosurfactants that tolerate high salinity and hardness and with metaborate that can tolerate hardness as well. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase-behavior experiments and crude at reservoir temperature. A formulation was found that, with an optimum salinity of 120,000 ppm total dissolved solids (TDS), 6,600 ppm divalent cations, performed well in corefloods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery with no indication of precipitate formation. Metaborate chemistry was incorporated into a mechanistic, compositional chemical flooding simulator, and the simulator was then used to model the corefloods. Overall, novel ASP with metaborate performed comparably to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding.

Some Aspects of Polymer Retention in Porous Media Using a C14-Tagged Hydrolyzed Polyacrylamide

1975 ◽  
Vol 15 (04) ◽  
pp. 323-337 ◽  
Author(s):  
M.T. Szabo
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Pore Volume ◽  
Produced Water ◽  
Polymer Concentration ◽  
Oil Saturation ◽  
Polymer Flow ◽  
Hydrolyzed Polyacrylamide ◽  
Polymer Retention ◽  
Inaccessible Pore Volume

Abstract Numerous single-phase flow and oil-recovery tests were carried out in unconsolidated sands and Berea sandstone cores using C14-tagged, hydrolyzed polyacrylamide solutions. The polymer-retention polyacrylamide solutions. The polymer-retention data from these flow tests are compared with data obtained from static adsorption tests. Polymer concentrations in produced water in Polymer-flooding tests were studied using various Polymer-flooding tests were studied using various polymer concentrations, slug sizes, salt polymer concentrations, slug sizes, salt concentrations, and different permeability sands. Results show that polymer retention by mechanical entrapment had a dominant role in determining the total polymer retention in short sand packs. However, the role of mechanical entrapment was less in the large-surface-area Berea cores. In oil-recovery tests, high polymer concentrations were noted at water breakthrough in sand-pack experiments, an indication that the irreducible water was not displaced effectively ahead of the polymer slug. However, in similar tests with Berea cores, a denuded zone developed at the leading edge of the polymer slug. polymer slug. The existence of inaccessible pore volume to polymer flow is shown both in sand packs and in polymer flow is shown both in sand packs and in sandstone cores. Absolute polymer-retention values show an almost linear dependency on polymer concentration. The effect of polymer slug size on absolute polymer retention is also discussed. Distribution of retained polymer in sand packs showed an exponential decline with distance. The "dynamic polymer-retention" values in short sand packs showed much higher vales than the ‘static packs showed much higher vales than the’ static polymer-adsorption" values caused by mechanical polymer-adsorption" values caused by mechanical entrapment. The mechanism of polymer retention in silica sands and sandstones is described, based on the observed phenomenon. Introduction It is widely recognized that, as polymer solution flows in a porous medium, a portion of the polymer is retained. It is evident that both physical adsorption and mechanical entrapment contribute to polymer retention. The question of the relative importance of these retention mechanisms has not been studied adequately. The effect of residual oil saturation on polymer retention and the polymer retention during the displacement of oil from porous media has also been studied inadequately. Mungen et al. have reported a few data on polymer concentration in produced water in oil-recovery tests. However, no produced water in oil-recovery tests. However, no comparison was made between polymer retention at 100-percent water saturation and at partial oil saturation. It has been shown that the actual size of the flowing polymer molecules, with the associated water, can approach the dimensions of certain smaller pores found in porous media. Therefore, an inaccessible pore volume exists in which no polymer flow occurs. In this study, the existence polymer flow occurs. In this study, the existence of inaccessible pore volume is shown clearly, both in sand and sandstone. Although polymer-retention values have been reported for various conditions, correlation is difficult because of the differing conditions of measurements. The effect of slug size, polymer concentration, salinity, and type of porous media on polymer retention has not been systematically studied. The purpose of this study was to develop answers to these questions, rather than to provide adsorption data for actual field core samples. For this reason, unconsolidated silica sands were used in most of the experiments reported. This permitted identical, uniform single-layer and multilayer porous media to be constructed for repeated experiments under varying test conditions. Some experiments were also carried out in Berea sandstone cores to determine whether sand-pack results can be extrapolated to consolidated sandstones. Using a C 14-tagged polymer provided a very rapid, simple, and accurate polymer-concentration determination technique. SPEJ P. 323

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