Waterflooding In Oil Reservoirs Research Articles

Optimal control of multilateral waterflooding wells in carbonate reservoirs with uncertainty consideration

The benefits of adjoint formulation in studying and improving the economic and production viability of reservoir waterflooding problems has been reported in several researches. However, there is little or no recorded report on its use for multilateral wells in uncertain waterflood reservoir conditions. This study aims to investigate the effect of geological uncertainty to multilateral well performance using adjoint formulation in oil reservoir waterflooding. First, an oil reservoir model with uncertainty assumption in permeability, Corey value, and physical dimension in reservoir compartmentalization was developed. Second, an optimal control sequence for the multilateral injection well was developed to optimize the net present value (NPV). The study revealed that with the obtained control sequence, reservoir compartmentalization notably faults in rock structure, significantly influenced the production capacity of multilateral wells which resulted in a higher NPV and oil rate when compared to other uncertainty cases.

Comparative study on the optimal control of smart well in oil reservoir waterflooding with uncertainty

ABSTRACT In oil reservoir setting, an alternative for conventional wells are the smart wells having inflow control valves (ICVs). In this work, optimal control theory is implemented to investigate the performance of smart wells alongside conventional wells on an oil reservoir with permeability uncertainty and model mismatch. The performance of this scenario was compared using the Net Present Value (NPV) and Injection rates of the injector wells as perfromance indicators. The results obtained showed a better performance with smart wells irrespective of uncertainty and mismatch in the reservoir. An NPV of $4193430 was recorded for the smart well case as against its corresponding counterpart having an NPV of $3901415. Whereas for the faulted reservoir, an NPV of $314946 was obtained which is an 11% gain against the conventional well setting. This study shows that even though the rationale behind the implementation of conventional wells stems from their simple drilling process, they possess inherent limitation of sub-optimal reservoir-well contact depleting their productivity. Conversely, smart wells were shown to be better due to their enhanced monitoring and control capabilities making them suitable for reservoirs with uncertainties.

SODIUM SILICATE GELS FOR WATER SHUT-OFF IN OIL RESERVOIRS

This work is dedicated to the problem of reducing the permeability of oil reservoirs to water. An experimental study was conducted, the results of which show that the gel based on liquid glass and hydrochloric acid is partially washed out from the model of water flooded oil reservoir under a pressure gradient of approximately 14 MPa/m, which in practice will lead to a decrease in efficiency. However, adding laponite nano-clay to the solution of liquid glass and hydrochloric acid allows solving this problem and achieving a 400-fold reduction in the permeability of the model of water flooded oil reservoir at a pressure gradient of approximately 33 MPa/m. This result can be explained by the fact that adding laponite to the solution of liquid glass and hydrochloric acid leads to an increase in the mechanical strength of the gel. For example, adding 1% laponite to the solution of liquid glass and hydrochloric acid increased the Young’s modulus from 550 to 1280 Pa. The results of this work demonstrate the potential application of liquid glass gels with fillers to increase the efficiency of plugging agents in operations to reduce water production in oil wells. Future research will focus on conducting filtration experiments on fractured models.

Analysis of sensitive factors for sidetrack drilling in water-flooded oil reservoirs: data mining based on actual field data

Sidetracking technology is an important measure to increase production and efficiency, too many complex factors affect the development effect of sidetracking wells. At present, most of the research on sensitive factors of sidetracking wells is based on theory, numerical simulation, or application analysis of limited wells. In this study, we adopt a data-driven research paradigm to conduct data mining studies on the actual data of a large number of sidetracking wells accumulated in the oil fields. Actual data from more than 130 sidetracking wells in oil fields within 5 years is collected and cleaned. An index system including 25 indicators for the analysis of sidetracking effect and a sample set of influencing factors are established. On this basis, scatter plots between various influencing factors and sidetracking development effect parameters are drawn to achieve intuitive qualitative understanding through visualization. The correlation coefficients between each parameter are calculated by Pearson and Spearman correlation analysis methods to quantitatively characterize and analyze the linear and nonlinear correlation degrees between each indicator. A feature importance calculation method based on a decision tree is constructed to calculate and rank the importance of each influencing factor for the development effect of sidetracking wells. The results show that compared with Pearson, the Spearman correlation coefficient can more accurately reflect the complex nonlinear correlation relationship between each indicator. Four indicators such as sidetracking target point position show medium or above correlation with sidetracking development effect. Through the calculation of the feature importance of the decision tree, it can be known that the importance of remaining recoverable reserves to the development effect of sidetracking wells exceeds 10%. The importance of six indicators, such as perforation thickness, is small, all less than 3%. This research work can provide guidance for future sidetracking well design and development work.

The performance of streamline simulation technique to mimic the waterflooding management process in oil reservoirs

Multiple simulation techniques are often used to predict the performance of waterflooding and to plan the infill drilling techniques via a process called waterflooding management. However, such simulation techniques usually suffer from many drawbacks and shortages. Therefore, the waterflooding process management is in an evitable need for a robust technique, which can predict the optimal water injection rates and the incremental oil production in a cost-effective manner.In this study, the streamline simulation technique (SST) was used to visualize and analyze the fluid flow patterns in order to investigate the validity of this technique for improving waterflooding management process. In addition, the feasibility of SST in waterflooding management was clearly tested by setting new injection strategies to improve the sweep efficiency via estimating the injector-producer relationship as well as the water injection efficiency. Furthermore, the advantages of streamline simulation visualization in determining the best infill drilling locations, which production wells could be converted to injection wells, and optimizing water injection rates based on monitoring and trials were investigated. The results of this research indicated that the streamline simulation technique is capable to efficiently model and predict the waterflooding process. The SST is computationally efficient and fast in terms of providing flow visualization among injectors and producers, estimating an allocation factor for injection system, and optimizing the locations of new injectors/producers’ wells to increase the sweep efficiency. In addition, the SST could provide a deep understanding with visualization to the waterflooding process and how to improve the waterflooding in oil reservoirs. In this work, through the comparison of various waterflooding scenarios, we discovered the best solution that eliminated the need for optimization algorithms with high computational requirements. This approach relies on areas exhibiting low streamline densities to enable streamlined prediction of infill well locations, thereby reducing simulator processing time. Consequently, this method represents an effective first step in the process of identifying approximate infill well locations, and its efficacy can be enhanced by integrating optimization methods.

UNCERTAINTY QUANTIFICATION OF WATERFLOODING IN OIL RESERVOIRS COMPUTATIONAL SIMULATIONS USING A PROBABILISTIC LEARNING APPROACH

In the present paper, we propose an approach based on probabilistic learning for uncertainty quantification of the water-flooding processes in oil reservoir simulations, considering geological and economic uncertainties and multiple quantities of interest (QoIs). We employ the probabilistic learning on manifolds (PLoM) method, which has achieved success in many different applications. This methodology enables the construction of surrogate models to cope with expensive computational costs using high-fidelity simulators. It also allows the incorporation of unavoidable uncertainties, like in the porosity and permeability fields, resulting from difficulties in the characterization of the heterogenous subsurface media, or arising from economic instabilities. We are particularly interested in computing high-order statistics of the system response, which combines oil operational production and economic aspects, to evaluate risk losses. In this paper, we assess the efficacy of the PLoM stochastic surrogate through two numerical examples contemplating the above uncertainties and typical reservoir configurations.

An evaluation of different detection methods for anaerobic ammonium-oxidizing (anammox) bacteria inhabiting the oil reservoir systems

Anaerobic ammonium-oxidizing (anammox) bacteria are widely detected in diverse anoxic niches, but only a few studies have reported their presence in oil reservoirs. Here, we collated published clone library data of the 16S rRNA and hzo genes of anammox bacteria and high-throughput sequencing data of the 16S rRNA genes from microbial communities to identify anammox bacteria inhabiting oil reservoir environments. Furthermore, the community composition of anammox bacteria and nitrate-reducing bacteria (NRB) associated with dissimilatory nitrate reduction to ammonium (DNRA) in a water-flooded oil reservoir was investigated by metagenome sequencing. The combined results suggested the occurrence of anammox bacteria in oil reservoirs, however sequencing of the 16S rRNA genes and metagenome from microbial communities could not effectively detect them due to their low abundance in the overall community. The results also showed that anammox bacteria were more easily detected in the downhole of the water-injection wells rather than wellheads of injection and oil-production wells. The co-existence of denitrifying bacteria (DNB) reducing nitrate to N2O and N2, NRB associated with DNRA, and anammox bacteria in oil reservoirs supports a unique N cycling in such ecosystem and implies the potential reduction of externally injected nitrate into the oil reservoirs via the production of N2O and N2. This study improves our knowledge on efficient detection of anammox bacteria and highlights the roles of these bacteria in the nitrogen cycle in oil reservoirs.

Influence of Nitrogen Slugs on Co2 Storage and Eor in Water-Flooded Oil Reservoirs

Influence of Nitrogen Slugs on Co2 Storage and Eor in Water-Flooded Oil Reservoirs

Investigation of Influential Parameters on Oil/Water Interfacial Tension During Low-Salinity Water Injection

Abstract Injecting low-salinity water has proved to be an efficient displacement process in oil reservoirs, owing to its ability to modify the properties at the fluid-rock and fluid-fluid interfaces in favor of mobilizing more oil. In this regard, reduction of interfacial tension (IFT) between oil and water is one of the key controlling parameters. It is suspected that the asphaltene constituents of the oil and type of water ions are responsible for such a reduction in IFT. In this study, systematic experimental investigations were carried out to scrutinize the influence of brine salinity, asphaltene concentration, and temperature on IFT. Single and multi-component brines, which in particular compose of NaCl, CaCl2, and MgCl2 salts, and two synthetic oils with 1 and 10 wt% asphaltene content were used at temperatures ranging from 25 to 80 °C. The results showed that the presence of salt in the solution can alter the distribution of polar components at the oil-brine interface due to the electrostatic effects, which in turn would change IFT of the system. IFT also decreased when temperature increased from 25 to 80 °C; however, the level of changes was strongly depended on the brine type, salinity level, and asphaltene content. The results also demonstrated that the crude oil with the higher asphaltene concentration experiences higher IFT reduction when is contacted with the low-salinity water. The new findings from this study will improve the understanding of the underlying mechanisms for low salinity water flooding in oil reservoirs.

Evaluation of CO2 storage of water alternating gas flooding using experimental and numerical simulation methods

The potential of water alternating gas (WAG) flooding in CO2 storage was exploited using experimental and numerical simulation methods in this study. Through comparing experiments results of WAG flooding and continuous CO2 flooding, WAG flooding after water flooding enhanced oil recovery by 39.0%, 2.2% higher than that of continuous CO2 flooding. However, the water slugs in WAG displaced part of the previously stored CO2 out the core. Only 13.1% of the injected CO2 was stored through WAG, 13.4% lower than that of continuous CO2 flooding. Then, numerical simulations of WAG and continuous CO2 flooding were conducted at a water flooded oil reservoir. The field-scale case study showed that the number of rounds of alteration from CO2 slug to water slug in WAG, the duration time of each round, and the CO2 injection time in each round were the main factors influencing CO2 storage. Improper design of influencing parameters led to 118,986 tons lower CO2 storage through WAG than continuous CO2 flooding. Finally, to obtain the maximum CO2 storage, surrogate optimization was applied to adjust the proposed influencing factors. The optimization results showed less rounds of alteration and a pure CO2 slug size at the end improved the CO2 swept area in the reservoir for CO2 storage and inhibited the displacement of CO2 by water slug. After optimization of the proposed factors, 391,000 tons of CO2 were stored in the water flooded oil reservoir through WAG flooding, 65,764 tons more than continuous CO2 flooding. This study provides valuable experimental data and theoretical guidance for CO2 storage in water flooded oil reservoirs.

Relationship Between Zeta Potential and Wettability in Porous Media: Insights From a Simple Bundle of Capillary Tubes Model

Hypothesis & MotivationExperimental data suggest a relationship between the macroscopic zeta potential measured on intact rock samples and the sample wettability. However, there is no pore-scale model to quantify this relationship. MethodsWe consider the simplest representation of a rock pore space: a bundle of capillary tubes of varying size. Equations describing mass and charge transfer through a single capillary are derived and the macroscopic zeta potential and wettability determined by integrating over capillaries. Model predictions are tested against measured data yielding a good match. FindingsMixed- and oil-wet models return a macro-scale zeta potential that is a combination of the micro-scale zeta potential of mineral-brine and oil-brine interfaces and the relationship between macro-scale zeta potential and water saturation exhibits hysteresis. The model predicts a similar relationship between zeta potential and wettability to that observed in experimental data but does not provide a perfect match. Fitting the model to experimental data allows the oil-brine zeta potential to be estimated at conditions where it cannot be measured directly. Results suggest that positive values of the oil-brine zeta potential may be more common than previously thought with implications for surface complexation models and the design of controlled salinity waterflooding of oil reservoirs.

Mathematical Modeling of Oil Reservoir Waterflooding Using Fixed Streamtube at Various Values of Viscosity Ratio

Mathematical Modeling of Oil Reservoir Waterflooding Using Fixed Streamtube at Various Values of Viscosity Ratio

New proxy models for predicting oil recovery factor in waterflooded heterogeneous reservoirs

To predict the recovery factor (RF) in waterflooded layered oil reservoirs, two empirical relationships were derived. Both correlations use four independent variables. These are reservoir heterogeneity (characterized by permeability variation coefficient), permeability anisotropy (ratio of vertical to horizontal permeability), viscosity of the injected water, and water injection rate. One of the correlations estimates RF at water breakthrough time (RFBT) and the other evaluates RF at the end of project (RFEOP). Each correlation comes in an expanded form with more parameters and a reduced form with fewer parameters. Both models are based on the global linear model. Eclipse black-oil simulation was used to determine RF for generic reservoirs with different combinations of permeability variation, permeability anisotropy, injected water viscosities, and water injection rates. A total of 192 data sets have been generated. Out of these, 144 data sets (about 75% of the generated sets) were used for model development and 48 data sets (about 25% of the generated sets) were used for model testing and validation. The expanded forms of the new developed correlations gave reliable estimates of RFBT and RFEOP with absolute average percent difference (AAPCD) of 6.9 and 1.02, respectively. The reduced forms yielded slightly higher AAPCDs of 8.30 and 1.04, respectively. When tested against 48 simulation-generated data sets, the expanded forms yielded excellent fits for RFBT and RFEOP with AAPCDs of 14 and 6.5, respectively. The reduced forms showed comparable fit with AAPCDs of 16.9 and 6.70, respectively. The highest RFEOP of 50.6% was achieved for a generic reservoir with a permeability variation in V = 0.1 and a permeability anisotropy of kz/kx = 1.0. This particular reservoir needs to be waterflooded using a water viscosity of µw = 1.0 cp and a water injection rate of qi = 10,000 bpd. Finally, when tested against the Guthrie–Greenberger and the API statistical study, using a single field data set, the proposed correlations gave higher absolute percent difference of 22.9 and 22.7 compared to 0.758 and 19.2 for Guthrie–Greenberger and the API statistical study, respectively.

Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms

Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.

Wastewater treatment plant for the preparation of industrial water for waterflooding of oil reservoirs using pressure hydrocyclones

To increase the oil recovery of productive oil-bearing reservoirs, the method of increasing reservoir pressure is used. It consists of pumping process water into the oil-bearing horizons. To increase the long-term intake capacity of injection wells, this water is purified from the suspended substances.This article presents treatment facilities for the preparation of industrial water, including the use of pressure hydrocyclones and various hydrocyclone installations for its treatment. The paper presents the results of the research on water purification from suspension in pressure cylinders of Kazan State University of Architecture and Engineering. The settling time for water purification from suspended substances, which was pre-treated in pressure hydrocyclones, was determined.The results obtained allow us to design treatment facilities with devices of the «block hydrocyclone-sump» type, in which the reagent-free preparation of technical water used for flooding productive horizons is carried out.Studies of water purification processes from suspension in hydrocyclone installations are of high scientific and practical significance for the oil fields of Russia.

Tepidiphilus olei sp. nov., isolated from the production water of a water-flooded oil reservoir in PR China.

A novel, moderately thermophilic, Gram-stain-negative bacterium, designated strain J18T, was isolated from a water-flooded oil reservoir. Cells were aerobic, oxidase- and catalase-positive, with a polar flagellum. Growth occurred at 35-60 °C and at pH 6-8.5. The respiratory quinones were ubiquinone 8 and ubiquinone 9. The dominant cellular fatty acids were C16 : 0, C17 : 0 cyclo, C19 : 0 cyclo ω8c and summed feature 8 (C18 : 1 ω7c/C18 : 1 ω6c). The polar lipids consisted of phosphatidylethanolamine, phosphatidylglycerol, diphosphatidylglycerol, phosphatidylcholine, an unidentified aminolipid, an unidentified phospholipid and an unidentified aminophospholipid. The strain showed the highest 16S rRNA gene sequence similarities to Tepidiphilus margaritifer DSM 15129T (98.6 %), Tepidiphilus succinatimandens DSM 15512T (98.4 %) and Tepidiphilus thermophilus DSM 27220T (98.1 %), respectively, and the similarity to other species was lower than 93 %. In the phylogenetic trees, it constituted a unique sub-cluster within the genus Tepidiphilus. The DNA G+C content of strain J18T was 64.44 mol%. As compared with the type strains, the genome-to-genome distances of strain J18T were 34.7-40 %. These results confirmed the separate species status of J18T with its close relatives. On the basis of physiological, chemotaxonomic and phylogenetic analyses along with the low levels of identity at the whole-genome level, it can be concluded that strain J18T represents a new species of the genus Tepidiphilus, for which the name Tepidiphilus olei sp. nov. is proposed. The type strain of T. olei is J18T (=CGMCC 1.16800T=LMG 31400T).

Migration and plugging of polymer microspheres (PMs) in porous media for enhanced oil recovery: Experimental studies and empirical correlations

To decrease the unwanted water and increase oil, the influences of factors such as matching coefficient (the ratio of particle size to pore throat size), particle elasticity, seepage velocity, and particle concentration on migration and plugging of polymer microspheres (PMs) in porous media were studied. Then, particular emphasis was placed on the development of empirical correlations of resistance coefficient and blocking rate versus the factors mentioned above, which was less studied in the profile control of PMs. The results indicated that the plugging capability of PMs was notably enhanced after the matching coefficient and particle elasticity were increased to 1.2 and 10 K Pa, respectively. The resistance coefficient and blocking rate increased while reducing seepage velocity and raising particle concentration, especially the seepage velocity from 1.3 to 0.8 m/d and the particle concentration from 0.1 to 0.3 wt%. To control water production in mature waterflooded oil reservoirs with high-permeable layers, the matching coefficient, particle elasticity, and particle concentration were supposed to be at least 1.2, 10 K Pa, and 0.2 wt%, respectively, and seepage velocity should be no higher than 0.8 m/d. The obtained empirical correlations were expected to predict the profile control performance and optimize the size, elasticity, seepage velocity, and concentration of PMs.

INTELLIGENT NATURAL DUMP FLOODING WELL - CASE STUDY FROM THE AREA OF THE WESTERN PERSIAN/ARABIAN GULF AND POSSIBLE APPLICATION IN THE CROATIAN MATURE OIL FIELD BENIČANCI

In the process of oil reservoir waterflooding, natural water dump flood technology for reservoir pressure decline prevention is considered as an unconventional but technically less demanding, more economical and safer method in comparison to surface power water injection. With natural dump flood technology, a single well serves as a water producer from a water bearing layer (aquifer) and simultaneously through gravity and the pressure difference between the aquifer and the depleted oil reservoir, it serves as a water injector inside the oil reservoir without expensive and complex injecting water treatment facilities at the surface. With the use of such technology and the running of intelligent well completion, it allows for the permanent monitoring of water production, injection rates and temperature inside the chosen reservoir. In addition, in offshore operations, the use of a subsea wellhead with a mud line suspension system allows for the placing of the injector well at the best predetermined position for water injection in a targeting reservoir and, together with an efficient subsurface acoustic data acquisition system, leads to better reservoir management and well integrity improvement. The overview and critical reflection of the drilling and intelligent completion of a natural dump flooding well for reservoir pressure support in partially depleted oil reservoirs in the Persian/Arabian Gulf has been given, referring to both their preparation and execution phase. The possibility of applying natural water dump flood was also considered in the Croatian onshore Beničanci oil field through a pilot project of water injection into the Be-62 well.

Water flooding of oil reservoirs: Effect of oil viscosity and injection velocity on the interplay between capillary and viscous forces

Water flooding is the most widely applied recovery process in both conventional and heavy oil reservoirs. It is generally accepted that theories explaining water flooding performance in light oil reservoirs are not applicable to heavy oil reservoirs. Nonetheless, there is a lack of a systematic study discussing the underlying mechanisms of water flooding in heavy oil systems. This article presents findings of water flooding experiments and discusses the interplay between viscous and capillary forces as a function of oil viscosity and injection velocity. Experimental data of 178 core floods were used to develop a new dimensionless capillary number, NCa=(μwVwσCosθφ)0.26(μwμo)0.50(KLD)0.18 , which is useful in predicting water flood performance for a wide range of oil to water viscosity ratio up to 15,000. This scaling parameter along with the Peters and Flock's (Peters and Flock, 1981) instability number were used to map the interplay between capillary and viscous forces. It was found that there is a critical oil to water viscosity ratio (≤20) below which the flow is stable (having instability numbers below a critical value) and viscous-dominant. In these cases, breakthrough oil recovery monotonically increases with increasing injection velocity. For viscous oils with viscosity of greater than 160 mPa s, flow is identified as pseudo-stable flow with instability numbers above a critical instability number. In these cases, breakthrough oil recovery is almost independent of injection velocity. In intermediate oil to water viscosity ratio of 20–160, breakthrough oil recovery increases with decreasing injection velocity, suggesting the flow regime is capillary-dominant. In these cases, imbibition activated at slower velocities has been identified as the main mechanism responsible for incremental oil recovery. In viscous oil systems (160 < μo < 15,000), late time oil recovery monotonically increases with decreasing injection velocity. This increase in oil recovery is more pronounced in more viscous oil systems suggesting the importance of capillary forces in these systems. Results of this study suggest some new insights on the mechanisms of water flooding as a cost effective non-thermal EOR technique and how this can be very different in light oil systems compared to heavy oil reservoirs.

Alkali/Cosolvent/Polymer Flooding of High-TAN Oil: Using Phase Experiments, Micromodels, and Corefloods for Injection-Agent Selection

SummaryChemical enhanced oil recovery (EOR) leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high total acid number (TAN) could be produced by the injection of alkali. Alkali might lead to the generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. On the basis of the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in the formation of initial emulsions is observed.Micromodel experiments are performed to investigate the effects on the pore scale. For the injection of alkali into high-TAN oils, the mobilization of residual oil after waterflooding is seen. The oil mobilization results from the breaking up of oil ganglia or the movement of elongated ganglia through the porous medium. As the oil is depleting in surface-active components, residual oil saturation is left behind either as isolated ganglia or in the down gradient side of grains.Simultaneous injection of alkali and polymers leads to a higher incremental oil production in the micromodels owing to larger pressure drops over the oil ganglia and more-effective mobilization accordingly.Coreflood tests confirm the micromodel experiments, and additional data are derived from these tests. Alkali/cosolvent/polymer (ACP) injection leads to the highest incremental oil recovery of the chemical agents, which is difficult to differentiate in micromodel experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micromodels, the incremental oil recovery is also higher for alkali/polymer (AP) injection than with alkali injection only.To evaluate the incremental operating costs of the chemical agents, equivalent utility factors (EqUFs) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and, hence, the lowest chemical incremental operating expenditures are incurred by the injection of Na2CO3; however, the highest incremental recovery factor is seen with ACP injection. It should be noted that the incremental oil recovery owing to macroscopic-sweep-efficiency improvement by the polymer needs to be accounted for to assess the efficiency of the chemical agents.