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Carbon dioxide-enhanced oil recovery (CO2-EOR) has gained widespread attention in light of the declining conventional oil reserves. Moreover, CO2-EOR contributes to the reduction of the global emissions of greenhouse gases through CO2 sequestration in subsurface geologic formations. This method has been largely used in the petroleum industry for several decades especially for extracting oil from light-to-medium oil reservoirs approaching an advanced state of maturity. Traditionally, CO2 is used in a continuous flooding scheme for EOR. However, continuous CO2 flooding tends to be problematic due to unfavorable mobility, viscous fingering/channeling and early breakthrough of CO2, especially in the presence of reservoir heterogeneities. In this paper, recent developments in the methods used to overcome these problems are reviewed. These developments include CO2 water-alternating-gas (WAG) injection, polymer-assisted CO2 injection, surfactant-assisted CO2 mobility control (CO2-foam injection), and nanoparticle-assisted CO2 flooding. Each method addresses, to an extent, one or more of the problems associated with conventional CO2 flooding. Furthermore, incorporating more than one method can provide better performance in terms of CO2 mobility control and oil recovery. In comparison with CO2-WAG and CO2-foam injection methods, the use of polymers and nanoparticles with CO2 flooding is relatively new. These two new methods were mostly investigated experimentally, at the laboratory level, and they still need further development prior to field implementation.

Foams would play a substantial role in mobility control and are considered an efficient chemical agent to improve the oil recovery factor. Co-injection of foam and carbon dioxide (CO2) would be one of the optimum injectivity scenarios in fractured tight core samples. This paper aimed to experimentally investigate the surfactant alternating gas injection and CO2-foam injection and how to determine the optimum parameters like foam quality, flow rate, and the number of cycles. It is observed that 0.65 is the optimum foam quality for the fractured tight core samples, and by the increase of foam quality, the pressure drop has been decreased. By increasing foam quality, pressure drop increases up to a specific value ( f g = 0 .65), and after this point, pressure drop has been decreased. Moreover, by the increase of injectivity cycles, pressure drop has increased subsequently. It is observed that five cycles are the optimum number of cycles, and after that, there is no pressure drop decrease in the system. Due to the surfactant property to control the mobility ratio, CO2 breakthrough has occurred at 1.2 PV. Its oil recovery factor at breakthrough is about 48%, and the total oil recovery factor is about 65%. CO2-foam were injected into the system, and due to the presence of a foaming agent in CO2, a CO2 breakthrough occurred at 1.8 PV. The total oil recovery factor is about 83% that indicated the efficiency of this scenario.

This paper examines literature that claims, suggests, or implies that floods with “colloidal dispersion gels” (CDGs) are superior to polymer floods for oil recovery. The motivation for this report is simple. If CDGs can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker, then CDGs should be used in place of polymer solutions for most/all polymer, surfactant, and ASP floods. In contrast, if the claims are not valid, (1) money spent on crosslinker in the CDG formulations was wasted, (2) the mobility reduction/mobility control for CDG field projects was under-designed, and (3) reservoir performance could have been damaged by excessive loss of polymer, face-plugging by gels, and/or excessive fracture extension. From this review, the clear answer is that there is no credible evidence that colloidal dispersion gels can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker. CDGs have been sold using a number of misleading and invalid arguments. Very commonly, Hall plots are claimed to demonstrate that CDGs provide higher resistance factors and/or residual resistance factors than normal polymer solutions. However, because Hall plots only monitor injection pressures at the wellbore, they reflect the composite of face plugging/formation damage, in-situ mobility changes, and fracture extension. Hall plots cannot distinguish between these effects—so they cannot quantify in situ resistance factors or residual resistance factors. Laboratory studies—where CDG gelants were forced through short cores during 2–3 h—have incorrectly been cited as proof that CDGs will propagate deep (hundreds of feet) into the porous rock of a reservoir over the course of months. In contrast, most legitimate laboratory studies reveal that the gelation time for CDGs is a day or less and that CDGs will not propagate through porous rock after gelation. A few cases were noted where highly depleted Al and/or HPAM fluids passed through cores after one week of aging. Details about these particular formulations/experiments were sparse and questions remain about their reproducibility. No credible evidence indicates that the CDG can propagate deep into a reservoir (over the course of weeks or months) and still provide a greater effect than that from the polymer alone. With one exception, aluminum from the CDG was never reported to be produced in a field application. In the exception, Chang reported producing 1–20% of the injected aluminum concentration. The available evidence suggests that some free (unreacted) HPAM and aluminum that was associated with the original CDG can propagate through porous media. However, there is no evidence that this HPAM or aluminum provides mobility reduction greater than that for the polymer formulation without crosslinker.

In this study, lab research was performed to obtain a method to determine the timing for early polymer injection in oilfields, to increase applicability of lab research in actual oilfield management and to identify the optimum timing for polymer flooding to ensure efficient development of offshore oilfields. This study optimized the methods for lab experiments on oil displacement, analyzed the characteristics of two-phase flow permeability experiments, identified the effect of early polymer flooding, and found the method to decide the timing for early polymer flooding applicable to real-world oilfield management. The research result shows that there is optimum timing for early polymer flooding: in the case that a reservoir’s oil viscosity is 70mPa ⋅ s, the optimum timing is when the water cut is within the range from 0% to 40%. The water cut increase rate and the water/oil mobility ratio are key factors to the performance of polymers in mobility control: the best control effect can be achieved when the water/oil mobility ratio is below 1 and before the water cut increase rate reaches the maximum. Before polymer flooding, injection of a certain volume of water can unclog the channels, give full play to the effect of waterflooding, reduce the pressure of polymer injection, and cut the loss of effective viscosity of the polymer solution. In actual oilfield development, it is feasible to predict and monitor changes in the oil productivity index and take the timing of sharp decrease of the index as the optimum timing for polymer flooding.

The formation heterogeneity is considered as one of the major factors limiting the application of foam flooding. In this paper, influences of formation properties, such as permeability, permeability distribution, interlayer, sedimentary rhythm and 3D heterogeneity, on the mobility control capability and oil displacement efficiency of foam flooding, were systematically investigated using 2D homogeneous and 2D/3D heterogeneous models under 120 °C and salinity of 20 × 104 mg/L. The flow resistance of foam was promoted as the permeability increased, which thus resulted in a considerable oil recovery behavior. In the scenario of the vertical heterogeneous formations, it was observed that the permeability of the high-permeable layer was crucial to foam mobility control, and the positive rhythm appeared favorable to improve the foam flooding performance. The additional oil recovery increased to about 40%. The interlayer was favorable for the increases in mobility reduction factor and oil recovery of foam flooding when the low permeability ratio was involved. For the 3D heterogeneous formations, foam could efficiently adjust the areal and vertical heterogeneity through mobility control and gravity segregation, and thus enhancing the oil recovery to 11%–14%. The results derived from this work may provide some insight for the field test designs of foam flooding.

The development of natural/artificial fractures leads to significant differences of the physical properties between the matrix and the fractures, which usually causes serious channeling and low sweep efficiency during CO2 flooding in ultra-low permeability reservoirs, the use of a CO2-responsive smart mobility control system to generate bulk gel by wormlike micelles (WLMs) to mitigate gas channeling has great potentials for enhanced oil recovery (EOR) in ultra-low permeability reservoirs. In this study, five kinds of chemicals with CO2-sensitive groups are screened to measure the apparent viscosity using a rheometer. The experimental results show that the optimum system consists of 4.4 wt% N, N-dimethyl octylamide-propyl tertiary amine (DOAPA) and 2.0 wt% sodium p-toluenesulfonate (SPTS). Subsequently, the plugging capacity and EOR performance of the system are systematically evaluated using core flooding experiments. The optimized system (DOAPA/SPTS) exhibits outstanding plugging capacity for gas channeling with a plugging efficiency of 99.2%. The oil recovery of the CO2 flooding increases by 20.0%. In addition, the thickening mechanism of the CO2-responsive system is studied using rheological experiments and a cryogenic transmission electron microscopy (Cryo-TEM). The shear-thinning behavior demonstrates that the thickening effect of the high-viscosity WLMs is strong in the DOAPA/SPTS-CO2 solution, and the Cryo-TEM results indicate a transition from spherical micelles to the WLMs. The protonation contributes to the formation of the WLMs in the solution during phase transformation process. The results of this study are expected to provide benchmark to select the mobility control agent for CO2 flooding in ultra-low permeability reservoirs.

Chemical enhanced oil recovery (CEOR) is a well-recognized technique for exploiting the original oil in place (OOIP) left behind in subsurface petroleum reservoirs after primary and secondary recovery processes. However, CEOR is not practiced or implemented widely because of project cost, operational and technical complexity, and environmental risks. Polymeric surfactants have emerged as a viable alternative to conventional chemical methods. They offer multifunctional mechanisms such as viscosity increment and interfacial tension (IFT) reduction. Thus, they are thought to be more versatile in enhancing recovery due to mobility control and wettability-induced fluid redistribution. This review presents a summary of recent studies in the literature that provides new insights into the properties, mechanisms, and applications of polymeric surfactants related to improved hydrocarbon recovery. From the published studies, fluid-fluid interactions influencing rheology and IFT, and fluid-rock interactions dictating wettability alteration and adsorption tendencies, are systematically evaluated. Implications of these mechanisms on enhanced hydrocarbon recovery by the polymeric surfactants are analyzed. Recent advances and knowledge gaps are highlighted, and possible directions to improve research methodology are suggested.

Foam application has been introduced in enhanced oil recovery processes for mobility control to overcome some issues occurred during gas injection. The stability of foam has become the main concern as it dictates the effectiveness of foam mobility control. Many attempts at enhancing foam stability under reservoir conditions involve the application of chemical additives which can produce synergistic effect in combination with surfactant. Ionic liquids (ILs), salts melting below 100 °C, are considered to be able to alter surface behavior of surfactant molecules, hence supporting the surfactant performance at the interface. Their alteration is expected to be favorable in improving surface properties of foam. This research has introduced ionic liquid based additives for the first time to improve surfactant foam stability. Identification of the effect of ILs was performed by conducting bulk foam experiments at ambient conditions and also at high temperature using Foamscan. The foaming properties of in-house surfactant (MFOMAX) were evaluated in the absence and presence of ILs at different mixture ratios. The results show that imidazolium- and eutectic-based ILs were able to improve surfactant foam stability to different extent at high temperature and their effect on foam stabilization was more pronounced at surfactant/IL mixture ratio of 60:40. The highest foam stability increment exhibited by the best formulation reached 136% of that achieved by the formulation without IL. This study has indicated that ionic liquid has a promising potential for improving surfactant-stabilized foam mobility control during EOR processes.

As an enhanced oil recovery (EOR) method, polymer flooding has been widely applied in heavy oil production. Polymer's viscosity and residual resistance factor (RRF) are the key parameters of mobility control, whose increment can both result in the increased oil recovery factor (RF) and worse injectivity. Aiming at oil with viscosities of 50–350 cP, recovery factor and injection pressure of polymer flooding are obtained in the reservoir numerical simulation model. Then we used response surface method to optimize the combination of viscosity and residual resistance factor. The results show that injecting polymer solutions can balance the injectivity gap among layers caused by permeability heterogeneity, while high permeability layers contribute most in oil recovery. For polymer solutions with different combinations of viscosity and RRF in research scope, analyses of growth rates of recovery factor and pressure show that increasing RRF is suitable for above three-fourths of polymers. In such a way, a greater incremental recovery can be achieved under a reasonable increased injecting pressure. This study indicates that polymer solutions with relatively low viscosity and high RRF are more applicable to heterogeneous heavy oil reservoirs.

In this work, a visual two-dimensional (2D) heterogeneous fracture network model was designed to investigate CO2 foam generation, propagation and sweep with two different injection strategies (co-injection, COI; and surfactant solution alternating gas, SAG). In addition, gravitational effect was explored by this fracture model. In the case of the optimum foam quality (fg = 0.67), the results indicated the COI could form stable foam morphologies and differential pressures (ΔP), while the foam morphologies and ΔP showed a dynamic trend during each cycle of SAG. The ΔP of larger slug injection can establish 6–12 times than smaller slug injection in the fractured system. Because of CO2 breakthrough, the total sweep efficiency of continuous gas injection (CGI, 42%) and SAG (66%) were lower than COI (81%). Gravitational effect is insignificant during COI, whereas gravity has a considerable effect on SAG in terms of ΔP and sweep efficiency. As a result of gravitational effect, the entire ΔP curve decreased and required more fracture volume (FV) injected to achieve the final sweep efficiency during SAG. The results of this study provide preliminary observations that can provide new insights into mobility control by using CO2 foam in fractured tight reservoirs.

The use of surfactants for foam generation and gas-mobility control to improve oil recovery of CO2 flooding processes has been extensively studied. This review covers the most important aspects regarding the design of CO2-foams for mobility control in carbonate reservoirs, including recent advances in the formulation of novel surfactants, analytical techniques to determine key properties such as adsorption and thermal stability, and bench-scale visualization systems of foam flow. Several key concepts regarding foam transport in porous media are reviewed such as the minimum pressure gradient, the effect of the partition coefficient for CO2-soluble surfactants, and the effect of oil on foam stability and rheology. This work also discusses the most recent advances of two major foam modeling methods, the semi-empirical STARS foam model and the population balance model, along with recent CO2 foam pilot tests and the elements governing success in foam deployment and oil recovery.

The high mobility of CO2 in porous media is an issue in most subsurface CO2 projects worldwide, demonstrated by uncontrolled and rapid migration through the reservoir, early well breakthroughs and poor sweep efficiency. Improved mobility control of CO2 is needed to accelerate and improve the value-creation from subsurface CO2 projects, both in terms of energy produced and volumes of CO2 stored. Field-proven conformance and mobility control techniques, such as foam, provide a cost-effective and sustainable alternative to overcome geological and process constraints observed with CO2 flow in reservoirs. In this laboratory study, we have investigated CO2 mobility control by foam in sandstone core samples at typical North Sea reservoir conditions, 220 barg and 100°C, respectively. Two important aspects related to any field application of foam have been evaluated and discussed: I) Can strong CO2-foams be generated at reservoir conditions using AOS surfactant? If not, II) can relatively simple modifications to the foam system be made to improve foam properties and CO2 mobility control? Our results show that only high-mobility CO2-foams with low degree of CO2 mobility reduction are obtained at 220 barg and 100°C. An easy way to improve the foam properties at reservoir conditions is suggested by changing the gas-phase in foam to nitrogen (N2). The N2-foams display improved foam generation performance, larger mobility control in terms of mobility reduction factors (MRF) and ability to block subsequent CO2 injection. An alternative strategy for applying foam for CO2 conformance and mobility control in subsurface CO2 projects, which emerges from this study, is to initiate the foam treatment with nitrogen followed by subsequent CO2 injection to change the main direction of CO2 flow to enhance the displacement area or reduce uncontrolled CO2 production between the injecting and producing wells (as illustrated in the graphical abstract). The possible mechanisms explaining the observed differences in foam properties using CO2 versus N2, including implications that could be helpful for future studies and CO2 field applications are discussed further in more detail. The efficiency and limitations of miscible CO2 flooding to recover oil and simultaneously store CO2 after extensive water flooding are also demonstrated in this article, which are relevant to enhanced oil recovery (EOR) and subsequent CO2 storage applications, known as the Carbon Capture Utilization and Storage (CCUS).

The Deep Q-Network (DQN) is one of the key methods in the deep reinforcement learning algorithm, which has a deep neural network structure used to estimate Q -values in Q-learning methods. We have previously implemented a simulation system considering DQN for control of actuator nodes in Wireless Sensor and Actuator Networks (WSANs). In addition, we have designed and implemented a DQN based Autonomous Aerial Vehicle (AAV) testbed . In this paper, we propose and evaluate a Tabu List Strategy based DQN (TLS-DQN) for AAV mobility control. For evaluation, we compared the simulation results of the mobility control of AAV in indoor single-path environment using normal DQN and the TLS-DQN. The simulation results show that the TLS-DQN has a better performance than the normal DQN.

This work evaluated the performance of designed AAm/AAc copolymers with tailor-made properties in polymer flooding applications for enhanced oil recovery (EOR). Displacement tests using unconsolidated sand-packs with simulated real reservoir conditions were performed to evaluate the effectiveness of the designed copolymers during the displacement of heavy oil having a viscosity of 1192 cP. Experimental results demonstrated the superior mobility control functionality of the AAm/AAc copolymers compared to a commercially available EOR polyacrylamide copolymer. Likewise, higher incremental heavy oil recovery was obtained under the same experimental conditions by the AAm/AAc copolymers. This work identified the best performing copolymers and, more significantly, emphasizes the importance of a systematic approach in designing appropriate copolymers for EOR polymer flooding applications.

Mobility control is a major concern in gas flooding process, and water-alternating-gas injection (WAG) for enhanced oil recovery (EOR), which can be improved by simultaneous injection of chemicals. Chemically enhanced water alternating gas injection (CEWAG) is getting significance importance in EOR after WAG due to its ability to improve both the displacement and sweep efficiency. The unique feature of the process includes use of alkaline, surfactant, and polymer as a chemical slug during the CEWAG process to reduce the interfacial tension (IFT) with simultaneous improvement of mobility ratio. The paper reviews the mechanism of CEWAG injection for EOR and the advantages of the method over other conventional methods. Role of different chemicals and gases, modes and patterns of the injection, mobility control and capillary mechanisms along with different laboratory studies and field implications have been discussed. Different challenges associated with CEWAG process and their solutions have been demonstrated. Finally future development and conclusion have been drawn on the basis of reported research in the relevant field.

A simulation study has been carried out using realistic model of a North Sea oil reservoir to assess the performance of CO 2 flood in oil recovery compared to the base case water injection. The development strategy for this reservoir is based on one injector and a single producer. Various CO 2 injection strategies were studied to define injection schemes that would outperform water injection. Pure CO 2 injection, water flooding followed by CO2 injection, CO 2 Water-Alternating-Gas (CO 2 WAG) injection, and CO 2 Simultaneous-Water-And-Gas (CO 2 SWAG) injection are strategies that were studied. The latter one was chosen to study the mitigation of gravity segregation between water and gas. Various well locations and well configurations were also evaluated to determine the optimal arrangement. Simulation results showed that the increased recovery factors by the CO 2 flooding varies in the range between 3 to 8 percent and is to a considerable extent dependent on well configuration and injection scheme. The flooding with SWAG (water above gas) shows very promising results due to the increased mobility control achieved. Regarding the storage potential, the analysis indicates that this method would result in highest CO 2 retention in the reservoir.

CO2 foam is effective for mobility control and blocking of high permeability channels in the process of CO2 flooding for enhanced oil recovery. CO2 foams are much less stable than nitrogen foams due to the specific properties of CO2, and selection of surfactants as foaming agents is important for foam performance under harsh reservoir conditions. In this study, different surfactants and their mixtures were tested to evaluate their performance as CO2 foam agents, and the experiments were conducted using a visualized foam meter and a core flooding facility at high pressure and high temperature conditions. The influences of temperature, pressure, salinity and the HLB value of surfactants on CO2 foaming capability were investigated. The synergistic effect of the surfactants was also evaluated in order to increase high temperature tolerance of the foams. The experimental results show that the performance of CO2 foams at high temperature is greatly dependent on the types of the surfactants used. For nonionic and anionic-nonionic surfactants, there is a critical or optimum HLB value for best foam performance. Pressure has a positive effect on the stability of CO2 foams but dependent on the HLB value of the surfactants. Combined or mixed surfactants have a synergistic effect that can significantly improve the performance of CO2 foams and increase the foam's stability at high temperatures.

Foam is of practical interest in many industrial processes, and can be used for blocking gas channeling and mobility control during the process of CO 2 storage and improved oil recovery (IOR). It is important to develop new kinds of foam agents, which can tolerate high temperature and salinity under complex reservoir conditions. It is also desirable to develop chemicals that have CO 2 -sensitivity for selective channeling blocking. CO 2 -sensitivity is referred to that injected chemical can be converted into effective foam agent in formation water with CO 2 presence. In this paper, an organic amine, octadecyl dipropylene triamine, was studied in terms of chemical mechanisms for foam generation and CO 2 -sensitivity. The chemical can be converted into a Gemini surfactant like agent to generate CO 2 foams in-situ. The effects of important influencing factors on foaming performance at reservoir conditions were evaluated, including CO 2 purity, chemical concentration, temperature, pressure and water salinity. The results indicated that the amine chemical has good CO 2 -sensitivity for generation of CO 2 foams and has exhibited extraordinary features with high temperature and salinity tolerance. CO 2 flooding assisted by this type of chemical will broaden the scope of reservoirs that can be candidates for CO 2 IOR and geo-storage.

Fractures and heterogeneity commonly exist in ultra-low permeability reservoirs, which will cause serious gas channeling phenomena and lead to poor oil recovery during CO2immiscible flooding. CO2water alternating gas (WAG) flooding combined with gas channeling control treatments are recognized as effective approaches to enlarge the sweep efficiency of CO2. Performance of gel systems were evaluated to screen out a high-strength gel which can be utilized as fracture blocking agent. Then, performance of small molecule amines were evaluated to screen out a kind of small molecule amine which can be utilized as rock-matrix blocking agent. Performance evaluation results showed that high-strength gel with 8% modified starch + acrylic amide, 0.05% crosslinking agent, 0.15% initiator and 0.15% stabilizer could be served as fracture blocking agent, while etheylenediamine was proposed as rock-matrix blocking agent which could react with CO2 and generate solid particles to improve the heterogeneity of the reservoirs. To examine gas channeling control effect in actual reservoir conditions, a 3D radial flow model with complex fractures and heterogeneity was designed according to the actual oilfield, and five-spot pattern was employed in the model. Waterflooding, continuous CO2 flooding, and gas channeling control using high-strength gel, etheylenediamine and CO2 WAG flooding were conducted successively in the 3D radial flow model. After a series of treatments, the oil recovery was enhanced by 15.09%, which was significant for CO2 immiscible flooding in the field application. The gas channeling along major fracture and microfractures of the model was effectively controlled by high-strength gel, while fluid diversion could occurred after ethylenediamine injection due to the solid particles which could mitigate gas channeling along relatively high permeability areas of the rock-matrix, and the gas channeling phenomena can be further mitigated by the mobility control ability of CO2 WAG flooding.

The high mobility contrast between injected CO2 and the formation brine at reservoir conditions makes the displacement efficiency low and can give early breakthrough of injected CO2 into brine extraction wells for pressure management, or early reaching of spill points in structural traps. The storage capacity could in many cases be increased if efficient mobility control methods could be implemented for the injected CO2. In this paper we investigate the potential benefits of mobility control for CO2 injection in saline aquifers using both a commercial reservoir simulator and a specially developed module for the Matlab Reservoir Simulation Toolbox. The mobility control method investigated is surfactants for foam generation. These exists today both as water soluble and CO2 soluble surfactants, and the efficiency of both types are studied. Rough estimates of the cost of additional storage capacity are made. Results show that the storage capacity in some cases can be more than doubled, at a cost the order of 7 $ per additional tonne of stored CO2.

Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses ( S w ∗ ). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.

A large portion of the remaining oil world-wide is located in tight formations, often of carbonate origin, with substantial heterogeneity. In this review article, we aim to study EOR opportunities from a reservoir characterisation point of view. The main categories chosen include heavily-fractured reservoirs, communicating reservoir layers with large permeability contrast, low-permeability reservoirs and finally reservoirs with large oil-water transition zones. The literature sources, which are critically reviewed, have highlighted suitable methods in each of the four categories. In many cases, field implementation suggests that EOR is indeed economically feasible and a number of key learnings can be extracted from these successful projects. In general, the earlier EOR can be implemented, the better. This reduces the incremental cost required for EOR and provides an earlier pay-back in terms of higher production. The increment due to EOR may become more difficult to quantify since the baseline case would have to be entirely based on numerical simulation. A low baseline recovery without EOR shifts the economics in favour of EOR. Use of the existing well stock is not always sufficient or suitable; in most cases EOR must be complemented by drilling of new wells with appropriate well type, well placement, sufficient monitoring and surveillance. Large fields offer more EOR opportunities because injectant breakthrough can be better managed by redirecting injectant to poorly swept areas. EOR can also be taken offshore; industry experience shows that if the size of the prize is big enough, EOR projects are being sanctioned. Gas injection has the broadest range of applicability for a number of reasons. Occasional lack of market to export produced gas from remotely-located fields provides a strong incentive for gas re-injection. Furthermore, gas offers better injectivity compared to water or chemical EOR methods. Gas injection does not require development of miscibility to be successful, although miscibility helps. Swelling of highly under-saturated fluids leads to oil viscosity reduction and oil saturation increase and delays premature gas breakthrough. However, gas based EOR may suffer from poor sweep efficiency due to geological heterogeneity, gravity override and viscous fingering leading to unfavourable mobility ratio and premature gas breakthrough. Hence, gas-based EOR will require mobility control to improve sweep efficiency. Appetite for risk taking varies among operators. Unique problems require unique solutions. Operators who demand firm proof before field testing may have to adjust their mind-set and pilot a new concept in a statistically significant number of wells to fully evaluate the potential.

This paper presents a study on the use of polymer-gel technology as an option to remediate non-conformal flow behaviour of CO2 within the storage reservoir. Several polymer-gels with crosslinkers were tested. The rheology, gelation and working times of these polymer-gels at various concentrations were characterised under different temperatures representative of CO2 storage reservoirs. Laboratory core flooding experiments were then carried out on high permeability core samples to test the suitability of polymer-gel solution for flow through and containment of CO2 in porous media. The core samples saturated with brine were subjected to polymer-gel injection. Core sample permeability for CO2 was then measured and the change in CO2 permeability of the sample before and after polymer-gel injection was noted. Reservoir simulations for different scenarios of flow diversion were carried out using the permeability reduction results from the laboratory work on a realistic reservoir model with faults and high permeability channel structures.

Mobility control is a key issue in gas and CO2 flooding process, and water-alternating-gas (CO2) injection (WAG) has been used in various field applications. The WAG process can be CO2 foam assisted in order to further improve the sweeping efficiency of the injectants. In this study, a novel foaming method for reducing CO2 mobility and blocking gas channeling is proposed, which is based on a CO2-sensitive chemical (compound with amine group) to generate foams or thicken the injected water in situ. The CO2-sensitive chemical is referred to that, in a reaction triggered by CO2, it can be converted to an effective surfactant or foam agent. The chemical can be dissolved in water and injected as a slug. In this study, the foaming behavior and the CO2-sensitivity of the chemical were tested using a visualization apparatus and a viscometer in the presence of CO2 and N2. The capability of the foams generated using the CO2-sisentive chemical for mobility control was evaluated via gas flooding experiments of sand-packs. Stable CO2 foams have been obtained at high temperature and pressure conditions (up to 140 °C and 16 MPa), and high viscosity was observed in the chemical solution when CO2 was present in comparison with that of N2, indicating the chemical's sensitivity with dissolved CO2 in water. In the sand-pack flooding experiments, a high resistance factor was achieved in a simulated WAG process using the CO2-sensitive chemical, which is attributed to the CO2 foams and viscous micelles generated in situ during CO2 injection.

Emulsion flooding is a promising method for enhanced oil recovery (EOR). The static and dynamic behavior of the emulsions is greatly influenced by the nature of the applied surfactant. In this work, the effect of fatty acids, as natural surface-active agents, and their chain length on the emulsion behavior was investigated in both bulk and porous media. A panel of the fatty acids with different chain lengths (6

Low tension gas (LTG) process attempts to employ microemulsion (MI) and foam to enhance oil recovery (EOR). It is challenging to model surfactant phase behavior as a function of salinity for commercially available simulators since they lack the capability to explicitly represent MI properties. In this paper, a novel approach is developed to simultaneously model foam flow and surfactant/oil/brine key characteristics, using the general framework of CMG/STARS. Measured phase behavior data is transferred into k-value based relationships with multi-components oleic phase, based on which phase viscosities are calculated with non-linear mixing equation as function of different key components. Winsor Type phase variations are tracked by a pseudo-component generated by kinetic reactions, as another invention here. The mobility control by foam is fulfilled by the novel bubble dispersion model when increasing aqueous phase viscosity through bubble characteristics. Investigations of phase viscosities, IFT and compositions in 1D and 2D section models show that the developed methodology correctly accounts for surfactant solution desaturation in matrix and for mobility control by foam flow in the fractures. As such, the developed techniques provide a methodology to model LTG process in naturally fractured reservoirs within the framework of commercially available simulators along with their limited functionalities.

Low Tension Gas (LTG) flooding has been established as a successful tertiary oil recovery method for low-permeability carbonate reservoirs with high salinity and hard formation brine (~200,000 ppm and hardness 19,000 ppm). LTG flooding recovers oil using two integral mechanisms: ultra-low interfacial tension (IFT) between oil and water, and mobility control using in-situ foam generated by injected gas. In the present work, the scope of applicability of LTG flooding has been extended to secondary oil recovery under the same reservoir conditions. Secondary recovery using LTG flooding has been compared to conventional secondary recovery methods such as waterflooding. Oil recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary oil recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary recovery. Gas injection strategy was improved in terms of injected foam quality and onset of gas injection. When gas was injected only during drive, ultimate oil recovery was reduced to 70% OOIP. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on oil recovery.

The conventional foaming surfactants have drawbacks such as premature lamellae rupture in contact with oil, copious water amount required for foam generation, adsorption issue or surfactant partitioning in water/oil interface, salinity tolerance problem and instability at temperature and high pressure. The addition of CO2-philic functionalities in surfactant structure and surfactant blending is suggested to alleviate these problems, improve mobility control, and accelerate foam propagation. In our previous publications, foaming performance of a newly developed surfactant blend with CO2-philic functionalities was described based on surfactant structure-property characterization in Malaysian reservoir conditions. In this study, we develop a fast-track screening procedure for sulfonate anionic based surfactant blend design accounting for the effect of surfactant tail groups (single, double and triple-tailed) and morphology on CO2 foam performance targeting high pressure/high temperature sandstone reservoirs. A visualized foam meter and HTHP coreflood was used to observe performance of the foam generated. IFT surfactant solutions with CO2were also used to examine the attraction of surfactant with CO2. It was observed that triple tailed surfactant perform better both in bulk and coreflood tests in terms of stability, propagation and oil recovery at a high temperature of 102 °C, pressure of 125 bar and salinity of 30,000 ppm. The addition of tail into surfactant structure also increased surfactant activity at C/W interface and reduced surface tension. However, the adsorption of surfactants onto Berea sandstone rock showed a direct relation with the number of tail groups that impose a limitation on it. The blend of selected superior surfactants with betaine foam booster were compared in terms of foam propagation in coreflood in the absence and presence of oil, where blend of triple-tail surfactant performed better than double-tail surfactants, as expected.

Low Salinity Waterflooding (LSW) is a promising technology for improving oil recovery in secondary and tertiary stages over the conventional waterflooding (HSW). As widely reported in the literature, this emerging recovery approach has relatively low operating costs and is more environmentally-friendly than conventional Enhanced Oil Recovery (EOR) methods. In fact, LSW is a multi-physics recovery process; however, most of the previous studies focused on wettability modification as the sole mechanism for the incremental oil recovery by LSW. Unfortunately, these studies often ignored other crucial factors that importantly affect the performance of LSW, e.g., fines transport under a low salinity injection environment. This paper introduces a robust modeling workflow to capture important recovery mechanisms occurred in LSW by integrating fines migration, wettability alteration, and geochemistry. The results showed that fines transport including fines deposition, fines migration, and fines plugging plays an important role in LSW process. Fines plugging by LSW can cause formation damage, but it also can be used as a mobility control agent. The LSW model equipped with fines transport shows an excellent agreement for incremental oil recovery and pressure drop against laboratory coreflooding. Finally, a novel concept of hybrid low salinity assisted gas flooding was proposed to overcome the existing technical challenges associated with the conventional CO2 flooding.

Foam is widely used in well treatment or enhanced oil recovery (EOR). In EOR, foam is an effective agent for mobility control to improve sweep efficiency. Foam's flow characteristic is the foundation of its application. In this work, we systematically investigated the effects of the surfactant concentration, the liquid flow rate, and the fracture width on the flow resistance and the bubble shape characteristics of foam in a fracture by using a visualized fracture model. The results showed that the pressure drop increased with the concentration of the surfactant. When the concentration of surfactant was 0.03%, the pressure drop reached a maximum value at a foam quality of 60%, and this value increased to 92% for a surfactant concentration of 0.3%. The pressure drop reached a maximum with the surfactant solution flow rate and decreased thereafter, and the pressure drop reached a maximum for a foam quality of 92% at the gas flow velocity of 2.0 m/min. The foam bubbles were small in diameter and high in number with the increase of surfactant concentration. The number of polygonal foam bubbles raised with the foam quality, and the bubble shape shifting took place at a foam quality of 90%. The flow resistance of the foam in the fracture dropped with the fracture width, and the fracture width hardly affected the shape and size of the foam.

Amine-surfactant can be converted to be cationic surfactant in water solution saturated with CO2, which can enhance their foaming ability and foam stability, and the foaming ability can be switched off or on by CO2 or replacing with N2 with heating, so the amine-surfactants have great potential for smart mobility control to gas channeling during CO2 flooding. In this study, three alkyl propyl dimethylamines with different carbon chain length (R = 11, 17 and 22, named as UC11AMPM, UC17AMPM, and UC22AMPM, respectively), were investigated as CO2 responsive foam agent, and their foam performance under static and dynamic condition was tested up to 130 °C and 10.5 MPa using a visualized foam meter and a sand-pack flooding setup. The influence of carbon chain length on bulk solution viscosity, surface activity, foaming ability, and foam quality on bulk foam stability were measured and analyzed. The experimental results indicate that the three amine surfactants all demonstrate well CO2 responsibility and CO2 foaming ability, and show well switchable by CO2 and N2 at high temperature and high pressure (HTHP) condition. With the carbon chain length increasing, the surfactant shows higher absorption on the foam films, and bulk solution has a higher viscosity, which can decrease de-foam velocity and enhance the foam stability, as a result, the surfactant shows higher mobility control ability.

High molecular weight polyfluoroacrylate (PFA) is an amorphous, sticky, hydrophobic, oil-phobic, CO2-soluble homopolymer. 1 wt% PFA-in-CO2 solutions are four times as viscous as pure CO2. Although these solutions provided modest mobility control, unexpectedly large increases in pressure drop occurred because a portion of the PFA adsorbed onto the pore surfaces, altering wettability and significantly permeability. Further, PFA exhibited diminished solubility in CO2 in the presence of light extracted hydrocarbons. Although these effects rendered CO2-PFA solutions inappropriate for mobility control, excellent conformance control for dual parallel brine-saturated cores was attained when a CO2-PFA solution was first injected into the isolated high permeability sandstone core. This core was then placed in parallel with a low permeability sandstone core, and all of the subsequently injected CO2 was diverted to the low permeability core. Conformance control was not as effective in limestone, possibly due the low pH-induced erosion of the limestone that mitigated PFA adsorption.

Reservoir heterogeneity and natural fractures greatly affect CO 2 flooding efficiency in ultra-low permeability oil reservoirs. CO 2 water alternating gas (WAG) flooding and the combinations of continuous CO 2 flooding and gas channeling treatments are recognized as effective approaches to improve CO 2 sweep efficiency. It is of major interest to propose the novel gas channeling treatments and conduct a feasibility study of different CO 2 -EOR technologies. Heterogeneous cores with different permeability ratios and fracture model were utilized in the laboratory experiments to simulate different types of heterogeneity in the oil reservoirs. Continuous CO 2 flooding, CO 2 WAG flooding, continuous CO 2 flooding+one-stage gas channeling control, and continuous CO 2 flooding+two-stage gas channeling control were conducted after water flooding in homogeneous and heterogeneous cores and fracture model. Ethylenediamine and modified starch gel were proposed as blocking agents to mitigate gas channeling. During the experiments, the CO 2 flooding efficiency was evaluated through the oil recovery increment, fluid mobility control and the changes of producing pressure drop. Experimental results show that producing pressure drop during continuous CO 2 flooding decreases rapidly with an increase in permeability ratio. Continuous CO 2 flooding cannot displace much of remaining oil in low permeability layers due to high mobility of CO 2 and serious heterogeneity. WAG flooding can effectively control the fluid mobility and improve CO 2 flooding efficiency when the permeability ratio is less or equal to 30. Plenty of remaining oil can be displaced by combining continuous CO 2 flooding and gas channeling treatments. When the permeability ratio is less or equal to 100, ammonium carbamate, the reaction product of injected ethylenediamine and CO 2 can block off high permeability layer and impel the injecting gas into low permeability layer. The two-stage injection of modified starch gel and etheylenediamine can significantly mitigate the gas channeling within high-capacity gas channel model and fracture model during continuous CO 2 flooding, and the incremental oil recovery could be more than 20%. Pilot test of CO 2 flooding was operated in Northwest China and concentrations of CO 2 are monitored in six production wells. Two kinds of construction plans for gas channeling treatments have been preliminary designed to control the gas channeling in the pilot.

Context Polymer microgels are submicron-to-micron size, water-dispersible particles that are formed through use of a crosslinking agent. Their permeability reduction capabilities, when triggered, enable the strategic plugging of high-permeability channels so as to divert flooding fluid to the relatively unswept adjacent low-permeability zones. This improves macroscopic sweep efficiency, increasing hydrocarbon production and decreasing associated water production. Polymer microgel flooding thus serves to provide in-depth conformance control, distinguishing it from conventional polymer floods that offer primarily mobility control benefits. Objective This paper provides a literature review on the use of polymer microgel technology for conformance control purposes. Method Polymer microgel flooding is first introduced, and the motivation for their use over conventional polymer flooding is outlined. This is followed by a discussion on the characterization of polymer microgels as well as some theories on how they act as conformance control agents. In addition, an extensive survey of four different types of polymer microgels (Colloidal Dispersion Gels, Preformed Particle Gels, Temperature-Sensitive Microgels, and pH-Sensitive Polymer Microgels) is provided. Attention is mainly given to the microgel characteristics, laboratory observations, and field applications. The rheology and plugging mechanism of the different polymer microgels are also discussed in some detail. Conclusion Polymer microgel flooding is gaining popularity as a means of conformance control. Despite uncertainty around the precise mechanism by which microgels divert flow, numerous lab and field applications have demonstrated this technology׳s ability to improve sweep efficiency and enhance oil recovery.

Foam assisted CO 2 enhanced oil recovery has attracted increasing attention of oil companies and research institutions, mainly due to the potentially high benefit of foam on CO 2 -EOR performance. Numerous theoretical and experimental studies, limited numbers of pilot tests as well as cases of field applications have indicated that foaming of CO 2 can greatly improve the EOR process, at both the microscopic and macroscopic levels. However, there are still various conceptual and operational challenges, which may compromise the success and application of foaming process. The oil recovery mechanisms involved in a CO 2 foam flood, the complex flow behavior of the system, and the synergy between gas mobility control foaming agent and ultra-low IFT surfactants have been identified as the main challenges of this process. The unavailability of reliable predictive tools due to the less understood concepts and phenomena adds more challenges to the process results and application justifications. A literature review of the foam assisted CO 2 -EOR process is presented in this paper to reveal its strengths, highlight the knowledge gaps, and suggest ways to bring physical understandings of experiments into foam projects׳ performance evaluation and simulation models for potential field application purposes.

This paper summarizes the results of a 4-year study regarding the implications of CO 2 exsolution on geological carbon storage security and subsurface flow management, including core-flood experiments, micro-model studies, pore-scale modeling, and relative permeability calculations. When separate phase CO 2 exsolves from carbonated water in sandstones, water relative permeability drops significantly. The relative permeability of exsolved CO 2 is disproportionately reduced compared to drainage due to the dispersed morphology of exsolved CO 2 bubbles in the pore space. Our studies suggest that CO 2 exsolution provides an opportunity for mobility control in subsurface processes. The low mobility of exsolved CO 2 suggests that risks of groundwater contamination due to this phenomenon are small.

Permeability decline during waterflooding by varying water composition, in particular with low salinity or high pH water, has been observed in numerous laboratory studies. This has been explained by the lifting, migration and subsequent plugging of pores by fine particles. Recently, mathematical models have been presented to investigate the concept of using this permeability decline for mobility control during a waterflood. Now, these models need to be tested against observations during a core flood test. This paper presents a systematic laboratory study to investigate the underlying physics mechanisms for improved oil recovery as a consequence of injecting low-salinity water. Three sister plugs of Berea sandstone were used in the experiments. The first plug was subjected to single-phase waterflood for permeability measurements with varying salinities from 4 (high-salinity) to 0 (low-salinity) g/L NaCl. Core permeability decreased from 495 to 60 md, confirming the effect of changing water composition on permeability. The second plug saturated with high-salinity water was subjected first to primary oil flood (using Soltrol) to the connate water saturation and then to a benchmark waterflood using the same water. The oil recovery was noted and the core was restored to the connate water by a secondary oil flood. Finally, low-salinity waterflood was carried out and oil recovery was recorded. Experimental observations were interpreted using a numerical model. In order to check the reproducibility of the observations, the same experimental procedure was applied on the third plug. Results confirmed the reproducibility of the observations. Significant decrease in water relative permeability by approximately 50% and some decrease in residual oil saturation by about 5% were observed during the low-salinity waterflood in comparison with the high-salinity waterflood. Treatment of the low-salinity coreflood data by a numerical model reveals the decrease in water relative permeability with increasing water saturation at high water saturations. This observation is explained by the expansion of rock surface exposed to low-salinity water during the increase of water saturation. The laboratory data matched by the numerical model shows a high surface exponent value (nA=30), which is explained by a sharp surface area rise at high water saturations. The abnormal behavior of water relative permeability in response to low-salinity waterflood has resulted from matching water permeability increase at low water saturations and decrease at high saturations.

Introducing engineered nanoparticles into an aquifer or reservoir can potentially increase the storage efficiency and mitigate the risk of leakage of stored CO 2 . We have measured flow pattern and pressure drop during core floods in which high pressure liquid CO 2 or a CO 2 analogue fluid displaces an aqueous suspension of nanoparticles. The displacement front is more spatially uniform and travels more slowly compared to a control displacement with no in- situ nanoparticles. Pressure measurements are consistent with generation of a viscous phase such as an emulsion during the displacement. These observations suggest that a nanoparticle stabilized emulsion is formed during the displacement which acts to suppress the viscous instability.

A novel EOR method using carbonated water injection followed by depressurization is introduced. Results from micromodel experiments are presented to demonstrate the fundamental principles of this oil recovery method. A depressurization process (1 MPa/hr) was applied to a micromodel following carbonated water injection (Ca ≈ 10-5). The exsolved CO2 in water-filled pores blocked water flow in swiped portions and displaced water into oil-filled pores. Trapped oil after the carbonated water injection was mobilized by sequentially invading water. This method's self-distributed mobility control and local clogging was tested in a sandstone sample under reservoir conditions. A 10% incremental oil recovery was achieved by lowering the pressure 2 MPa below the CO2 liberation pressure. Additionally, exsolved CO2 resides in the pores of a reservoir as an immobile phase with a high residual saturation after oil production, exhibiting a potential synergy opportunity between CO2 EOR and CO2 sequestration.

In this paper, we proposed a node placement strategy in linear networks and mobility control strategy for equally-spaced placements. Our purpose is to maximize the sensing area by solving the problem of unbalanced traffic load in the sensor network. Through simulations, we verify that these strategies have significant benefits on the total sensing area of a given system. Finally, we extend our node placement strategy to a 2-dimensional network and identify its advantages.

We introduce a capability-based access control model integrated into a linguistic formalism for modeling network aware systems and applications. Our access control model enables specification and dynamic modification of policies for controlling process activities (mobility of code and access to resources). We exploit a combination of static and dynamic checking and of in-lined reference monitoring to guarantee absence of run-time errors due to lack of capabilities. We illustrate the usefulness of our framework by using it for implementing a simplified but realistic scenario. Finally, we show how the model can be easily tailored for dealing with different forms of capability acquisition and loss, thus enabling different possible variations of access control policies.

We define a typed bisimulation equivalence for the language DPI, a distributed version of the π-calculus in which processes may migrate between dynamically created locations. It takes into account resource access policies, which can be implemented in DPI using a novel form of dynamic capability types. The equivalence, based on typed actions between configurations, is justified by showing that it is fully abstract with respect to a natural distributed version of a contextual equivalence.In the second part of the paper we study the effect of controlling the migration of processes. This affects the ability to perform observations at specific locations, as the observer may be denied access. We show how the typed actions can be modified to take this into account, and generalise the full-abstraction result to this more delicate scenario.

It has been found that addition of hydrophilic polymers in the range 0–10,000 ppm has little effect on surfactant bulk properties in the II(−) state. In some cases, added hydrophilic polymer can reduce the saturation value for surfactant adsorption due to competitive adsorption. Surfactant-polymer interactions, for non-associating systems, have little effect on surfactant/polymer core floods. On a larger scale, polymer will of course provide mobility control and a somewhat higher capillary number due to the increased viscosity. It is concluded that the observed effects of polymer on laboratory surfactant core floods is due to secondary effects that have little relevance at the reservoir scale. This means that in field applications there is a freedom in the choice of surfactant-polymer combination.

Xanthan gum is used extensively for enhanced oil recovery as a mobility control agent, in drilling operations to increase the suspension capacity of the drilling mud, and in gels to improve the volumetric sweep efficiency. Flow properties, injectivity, and adsorption characteristics depend on acetate and pyruvate content of xanthan. This review discusses various methods and techniques available for measuring the concentration of xanthan and its pyruvate and acetate content in laboratory and field samples. It includes a description of the principles of each method, advantages, limitations, interferences, and other information necessary to understand the strengths and weaknesses of each.

This research addresses the problem of waterflooding a medium-gravity of oil-bearing formation with a water leg, and offers recommendations for process selection. In many reservoirs the presence of a bottom-water zone results in a very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil-recovery technique for these reservoirs. Waterflood performance in these reservoirs can be improved greatly with effective methods of partially plugging the bottom-water zone. One such method is the use of CO 2 -activated silica gel as a blocking agent in the presence of a bottom-water zone. Thirteen large-model experiments were conducted using silica gel, to study the effect of oil-to-water zone permeability contrast and thickness ratio, oil viscosity, and CO 2 injection. A qualitative comparison is made to show the relative merit of CO 2 -activated silica gel injection among other mobility control agents. Several runs were conducted to study silica gel rheology both in presence and in absence of CO 2 .

When the policy of optimal intervention in the foreign exchange market and that of optimal control of capital mobility are considered individually, their relative effectiveness in stabilizing the economy cannot be determined a priori. When they are jointly considered, the best combination is (i) zero capital mobility and fixed exchange rate, when only expenditure disturbances occur, (ii) flexible exchange rate and an arbitrary degree of mobility control, when only trade disturbances occur, or (iii) fine-tuning intervention accompanied by completely free or zero capital mobility, depending on the given situations, when both types of disturbances are present.

The use of surfactants as additives, sometimes in conjunction with noncondensible gases, has recently been tested under various conditions to improve both steam drive and cyclic steam injection in field projects. The objective of this technique is to reduce gravity override and channeling of the steam. When successful, this technology seems to be economic even at today's low oil price. However the results have ranged from excellent to negative. This paper aims to be a general evaluation of the field projects published to date. Sixteen field tests of steam with additives have been studied. They cover a broad spectrum of reservoirs, oils, depths and pressures. The type of surfactant used, the surfactant concentration, the presence or absence of noncondensible gases and their nature and the mode of injection of the additives also varied widely. The effect of these factors on the efficiency of the projects will be discussed. Some of the field tests have been performed after extensive laboratory work. The data published on laboratory screening of additive and on field support are used to explain some of the results observed in field testing. A brief description of each of the field tests is given. Emphasis of this work is on explaining some of the possible causes of failures or partial success and on suggestions for possible improvements for future field tests. Evidence of mobility control has been sought through pressure measurements, tracer testing, injectivity profiling, logging, temperature monitoring and observation wells. Production data have of course been analyzed. Evaluation of some of the monitoring techniques used in field testing of steam with additives is also discussed. The results of this study show that the use of additives with steam can provide significant benefits over the use of steam alone. Indeed addition of surfactant to the steam has as far as the author is concerned been proven as both technically and economically successful as long as some relatively simple criteria are met. These criteria are discussed in the paper.