Enhanced Oil Recovery Techniques Research Articles

An Overview of Oil Production Stages: Enhanced Oil Recovery Techniques and Nitrogen Injection

During the life oil wells, production process usually passes three stages. Primary recovery uses the natural source of energy. Pumps and gas lifting are involved in the primary recovery. The main purpose of secondary recovery process is to maintain the reservoir pressure by either a natural gas flooding or water flooding. The rise in world oil prices has encouraged the producers to use the new technical developments. Enhanced oil recovery (EOR) is a collection of sophisticated methods, to extract the most oil from a reservoir. EOR can be divided into two major types of techniques: thermal and non-thermal recovery. Each technique has a specific use in a certain type of reservoirs. Among non-thermal techniques is the gas flooding, where gas is generally injected single or intermittently with water. Flue gas and nitrogen have only limited application as agents of a miscible displacement in deep and high pressure reservoirs. Although new development processes such as water alternating gas (WAG) or Simultaneous water alternating gas (SWAG), are implemented, there are still some problems encountered by EOR engineers. This paper is discussing the last updating in this field.

Screening and PVT Analysis on Explored-Not-Productive Southern Iranian Oilfields

One of the main concerns of each petroleum engineer is the selection of the best EOR method to maximize the oil production from the reservoir. In this regard, one of the explored-not-productive southern Iranian oil fields was considered as the objective of this study to find which enhanced oil recovery (EOR) method is the proper method to apply on this reservoir. Therefore, a procedure capable of combining the data extracted from different sources ranging from worldwide field experiences to the existing tables into a unified expert system is used. This expert system is based on Bayesian network analysis in order to sort the proper EOR techniques for further assessment by economical and environmental criteria. In addition, after collecting of surface samples at the gas and liquid separator, and subsequently recombined with solution gas oil ratio, several tests including constant composition expansion (CCE) (flash vaporization, flash liberation flash expansion, pressure-volume relations), differential vaporization (differential liberation differential expansion) and solubility and swelling tests were performed.

Structure Analysis on Oil- and Water-Mineral Interface for Application to Enhanced Oil Recovery Technique

Structure Analysis on Oil- and Water-Mineral Interface for Application to Enhanced Oil Recovery Technique

CO2 Low-Salinity Water Alternating Gas: A Promising New Approach for EOR

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169071, ’CO2 Low-Salinity Water Alternating Gas: A New Promising Approach for Enhanced Oil Recovery,’ by Cuong T.Q. Dang, SPE, University of Calgary; Long X. Nghiem, SPE, Computer Modelling Group; Zhangxin Chen and Ngoc T.B. Nguyen, SPE, University of Calgary; and Quoc P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12-16 April. The paper has not been peer reviewed. Significant advantages have been seen from combining low-salinity waterflooding (LSW) with other enhanced-oil-recovery (EOR) techniques. This paper proposes a novel concept of low-salinity-water-alternating- gas (LSWAG) injection with CO2 under CO2-miscible-displacement conditions. While LSW is an emerging EOR method based on alteration of wettability from oil-wet to water-wet conditions, water-alternating-gas (WAG) injection is a proven method for improving gas-flooding performance by controlling gas mobility. Therefore, LSWAG injection promotes a synergy of the mechanisms underlying these methods that enhances oil recovery further. Introduction LSW is receiving increasing attention in the oil industry and is currently identified as an important EOR technique because it shows more advantages than conventional chemical EOR methods in terms of chemical costs, environmental impact, and field process implementation. Although the benefits of LSW have been realized, the mechanism for incremental oil recovery by LSW is still a topic that is open for discussion. Among the proposed hypotheses, wettability alteration toward increased water-wetness during LSW is accepted widely as the cause for the EOR. It has been found experimentally that low-salinity brine has a significant effect on the shape and the endpoints of the relative permeability curves, resulting in a lower water relative permeability and higher oil relative permeability. The mechanisms of wettability alteration because of ion exchange and geochemical reactions have been implemented successfully in a compositional simulator for modeling LSW. Excellent agreements between simulation results and important measurements from coreflood experiments and pilot observations were obtained with this modeling approach.

Oman Champions EOR in the Middle East

Oman EOR Although famous for its abundant oil fields, generations of production in the Middle East is putting sharper focus on ultimate recovery from these fields. The issue is particularly pressing for Oman. Output in the country’s maturing oil fields peaked in the 1990s and Petroleum Development Oman (PDO), the national oil company, spearheaded the implementation of enhanced oil recovery (EOR) techniques with its first trials in the late 1980s. For Oman, EOR remains a major strategic option in its challenge to increase recovery and to meet long-term production requirements. Substantial efforts have been directed at investigating cost-effective ways in which production levels from existing fields can both be sustained and increased. Oman’s first EOR program was completed in 1989 and led to progress in experience gained and reduction in technical and cost uncertainties. Oman has seen considerable investment in a range of EOR technologies to produce heavy oil, and a host of other countries in the Middle East and India have been encouraged by Oman’s success. Between 2001 and 2007, Oman’s oil production fell by 27%, but by 2009, due mostly to EOR projects, oil production had increased by 17%. In a region where national oil companies essentially control all the hydrocarbon resources, Oman’s partnership between national and international oil companies stands out, also because it has been an important driving force behind the country’s EOR rollout. The growth in use of EOR techniques has increased the cost of Oman’s oil production but also has boosted output by 180,000 BOPD to 200,000 BOPD. Total Oman production is 940,000 BOPD. “In comparison with primary oil extraction, which sometimes costs only USD 4-5 per barrel, EOR techniques come at an expense of USD 10-12 per barrel,” said Salim bin Nasser Al-Aufi, undersecretary of the Ministry of Oil and Gas in Oman. The EOR techniques that Oman has used include chemical EOR as well as thermal and miscible gas injection. The choice of EOR technology is based on the reservoir depth and oil viscosity. PDO’s Experience PDO, which produces more than 80% of Oman’s oil production, commissioned its first EOR project in 2004, and expects that EOR will contribute to 25% of total liquids production by 2020. “We have had to move into a significant program of EOR technologies. We are the only company in the world that has thermal, miscible, and polymer chemical-injection recovery mechanisms within the same concession, all of which are in full-scale implementation,” said Raoul Restucci, managing director of PDO.

Visualizing Low-Salinity Waterflooding

Technology Update Low-salinity waterflooding has recently attracted considerable interest from governments, researchers, and oil companies, who are evaluating the method’s potential to increase oil recovery. While laboratory work and field tests have indicated that low-salinity waterflooding can have positive results, and implementation of the technology is planned, there are still a number of challenges and uncertainties related to the technique. It is generally accepted that the effects of low-salinity waterflooding are caused by wettability alteration, but the processes involved are still not fully understood. Heriot-Watt University has been conducting research to investigate the mechanisms of interactions between low-salinity water, crude oil, and porous media at reservoir conditions. Industry support for the work was secured through Industry Technology Facilitator (ITF), and professor Mehran Sohrabi, director of the Center for Enhanced Oil Recovery (EOR) and CO2 Solutions at the university, is leading the project team. Low-Salinity Water Injection Waterflooding improves oil recovery by displacing oil, and injection water is usually taken from the nearest available source (which is seawater for most offshore fields). The first effects of low-salinity water injection were published in the 1990s, when work at the University of Wyoming indicated that injecting water with a total dissolved-solids content of less than 5,000 ppm resulted in a higher oil recovery than that attained by injecting high-salinity water such as seawater. Since then, a number of studies with varying results have been published, and the recovery benefits described are likely to be field-dependent. Low-salinity waterflooding has a number of potential benefits. It has relatively low costs compared with other techniques. It can be implemented in ongoing and new waterflood projects onshore and offshore and has shown potential for sandstone and carbonate reservoirs. In addition, it can be used alone or in conjunction with other EOR techniques, e.g., polymer injection, as a technology enabler. It also can alleviate problems associated with conventional waterflooding, such as scale formation and souring.

Can Lowering the Injection Brine Salinity Further Increase Oil Recovery by Surfactant Injection under Otherwise Similar Conditions?

It is well-established that injecting water with significantly lower salinity than the formation water salinity may give increased oil recovery. Although less well studied, the observed low-salinity effect has drawn attention to possible benefits from combining low-salinity water with traditional enhanced oil recovery techniques, such as surfactant, polymer, alkali, etc., to make the overall recovery process more efficient. Surfactant injection, for example, reduces the interfacial tension (IFT) between the injected surfactant solution and the oil, thus mobilizing capillary trapped oil and/or reducing the tendency for capillary trapping. The majority of literature on the topic of low salinity and surfactant flooding primarily addresses one or the other. This study, however, compares the combined effect of reduction in IFT and low-salinity conditions to the effect of a sole reduction in IFT on oil recovery in intermediate-wet Berea sandstone cores. We find that reductions in residual oil saturation, at similar capillary numbers and phase behavior conditions, are higher for the low-salinity surfactant injection experiments compared to regular surfactant injection experiments. This strongly indicates that there is a combined effect of IFT reduction and low salinity on recovery compared to that from a reduction in IFT alone.

Microemulsions: a novel approach to enhanced oil recovery: a review

The trend of growing interest in alternative source of energy focuses on renewable products worldwide. However, the situation of petroleum industries in many countries needs much concern in improving the oil recovery technique. Chemical method, especially microemulsion flooding, plays an important role in enhanced oil recovery technique due to its ability to reduce interfacial tension between oil and water to a large extent as well as alter wettability of reservoir rocks. Surfactant-based chemical systems have been reported in many academic studies and their technological implementations are potential candidates in enhanced oil recovery activities. This paper reviews the role of different types of surfactants in enhanced oil recovery, structure of microemulsion, phase behavior of oil–brine–surfactant/cosurfactant systems with variation of different parameters such as salinity, temperature, pressure and physicochemical properties of microemulsions including solubilization capacity, interfacial tension, viscosity and density under reservoir conditions. The enhanced oil productivity by microemulsion flooding with different surfactant/cosurfactant systems has also been discussed in this paper. This review introduces a new opening in enhanced oil recovery by microemulsion flooding with some new aspects.

Evaluation of interfacial mass transfer coefficient as a function of temperature and pressure in carbon dioxide/normal alkane systems

CO2 gas injection is known as one of the most popular enhanced oil recovery techniques for light and medium oil reservoirs, therefore providing an acceptable mass transfer mechanism for CO2–oil systems seems necessary. In this study, interfacial mass transfer coefficient has been evaluated for CO2–normal heptane and CO2–normal hexadecane systems using equilibrium and dynamic interfacial tension data, which have been measured using the pendant drop method. Interface mass transfer coefficient has been calculated as a function of temperature and pressure in the range of 313–393 K and 1.7–8.6 MPa, respectively. The results showed that the interfacial resistance is a parameter that can control the mass transfer process for some CO2–normal alkane systems, and cannot be neglected. Additionally, it was found that interface mass transfer coefficient increased with pressure. However, the variation of this parameter with temperature did not show a clear trend and it was strongly dependent on the variation of diffusivity and solubility of CO2 in the liquid phase.

New Laboratory Core Flooding Experimental System

This paper focuses on finding ways to improve the traditional core flooding experimental setup that has been used by the reservoir engineers over the past decades. The new proposed setup can be used in contemporary studies related to enhanced oil recovery. This setup has a possibility of using different flooding agents, e.g., surfactant, polymer, emulsion, oil and water. It also includes an automated effluent analysis, which has been developed to provide estimates on oil recovery efficiency. For validation purposes, the core flooding setup has been tested with an unconsolidated one-dimensional sand pack as a porous medium. Traditional water flooding experiments with paraffin oil and water were conducted at first. Also, two types of emulsion flooding techniques were tested for the sand packs: the direct emulsion flooding and the water flooding followed by the emulsion flooding as an example to exploit the capability of the new setup to successfully perform enhanced oil recovery techniques. Hence, this setup provides a valuable tool for the reservoir engineers to test the different flooding strategies in a laboratory scale experiment, before committing to huge resources in terms of man-power and cost in actual drilling operations in oil reservoirs.

Development of Small-Molecule CO2 Thickeners

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169039, ’Development of Small-Molecule CO2 Thickeners for EOR and Fracturing,’ by J.J. Lee, S. Cummings, A. Dhuwe, R.M. Enick, and E.J. Beckman, University of Pittsburgh, and R. Perry, M. Doherty, and M. O'Brien, General Electric Global Research, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12-16 April. The paper has not been peer reviewed. The ideal carbon dioxide (CO2) thickener would be an affordable, safe, water-insoluble additive that could dissolve in CO2 at typical wellhead and reservoir conditions during CO2 enhanced oil recovery (EOR) and elevate the viscosity of CO2 to the same value as that of the oil. Further, the additive would not require heating or an organic cosolvent to achieve dissolution. In this paper, a strategy for designing a novel small-molecule CO2 thickener is detailed. Introduction Despite its longstanding success as an EOR technique, CO2 flooding does not recover all of the oil in the formation regardless of whether the reservoir has been waterflooded previously. Typically, primary recovery results in the production of approximately 5–15% of the original oil in place (OOIP), while secondary recovery is responsible for an additional 20–40% of OOIP. The fundamental causes of this disappointingly low oil recovery can be traced to the density and viscosity of dense CO2. First, the low density of high-pressure CO2 relative to oil promotes gravity override of the CO2, reducing oil recovery in the lower portions of the formation. Second, the viscosity of dense liquid or supercritical CO2 at typical CO2- flooding conditions is approximately 0.05–0.10 cp, a value so much lower than typical oil- and brine-viscosity values that it results in an unfavorable mobility ratio. This leads to viscous fingering, which in turn leads to early CO2 breakthrough, high CO2-usage ratios, delayed CO2 production, depressed oil-production rates, and low-percent OOIP recovery. These problems can be worse when the injection well is completed in two or more producing zones.

Mobilization of Immobile Water: Connate-Water Mobility During Waterfloods In Heterogeneous Reservoirs

SummaryIn a series of laboratory waterfloods, we investigate the extent of mixing of injection water and connate water, connate-water mobility, and connate-water banking during water injection for enhanced oil recovery (EOR). Local dynamic water saturations of connate water and injected water were imaged individually by use of a nuclear-tracer technique. The connate water was displaced from the pore space by the injected water and accumulated downstream in a connate-water bank that advanced toward the production end. The connate-water bank significantly reduced the contact between the injected water and mobile oil. During capillary displacement—i.e., during spontaneous imbibition without a viscous pressure drop—the connate water was also mobilized and accumulated downstream in the core. During viscous displacement—i.e. with a pressure gradient as small as 0.3 mbar/cm—the accumulated connate water was mobilized in a miscible displacement and produced from the core. Only a small mixing zone was observed between the injected and connate waters, even with fully miscible conditions by use of identical brine compositions. The results of the displacement mechanisms experimentally visualized in this work are important for water-based EOR techniques, including low-salinity-water and polymer injections, as well as any tertiary oil-recovery method based on chemical injection.

Enhanced Oil Recovery Techniques Miscible and Immiscible Flooding

The shortage of oil products in the recent years has evidently proved that Enhanced Oil Recovery (EOR) technologies require great attention in order to offer solutions to the impending energy demands in the coming years. This present study shows the details survey of EOR techniques of oil recovery processes and the possibility of producing more oil at a very cost effective manner in oil reservoirs. More specifically, this study deliberated on EOR techniques for offshore fields. The comparisons between miscible and Immiscible CO2-EOR techniques and the general preview of CO2 will be discussed.

Preparation of silica supported nanoscale zero valence iron and its feasibility in viscosity reduction of heavy oil

Conventional solvent and thermal enhanced oil recovery techniques are less competitive, because of the presence of resin and asphaltene components which are difficult to remove; therefore it is imperative to develop new types of catalysts for the efficient recovery of heavy oil. In this reported research, silica-supported nanoscale zero valence iron (denoted as SiO2/nanoFe) is adopted as a catalyst to break the C–S bonds of resin and asphaltenes so as to reduce the viscosity of heavy oils and acquire enhanced oil recovery. A target SiO2/nanoFe catalyst was prepared via liquid-phase reduction of ferric chloride hexahydrate by sodium borohydride in the presence of surface-modified silica as a support. The as-prepared SiO2/nanoFe catalyst was characterised by transmission electron microscopy, X-ray diffraction and Fourier transform infrared spectrometry. The dispersibility of as-prepared SiO2/nanoFe catalyst in various organic solvents was evaluated, and its specific surface area was determined using classic Brunauer-Emmett-Teller isotherm method. Moreover, the catalytic performance of the SiO2/nanoFe catalyst for the aquathermolysis process of a heavy oil sample collected from Shengli Oilfield (Dongying, China) was evaluated. It was found that as-prepared SiO2/nanoFe, composed of silica with an average size of about 10 nm and zero valence iron nanoparticles with an average size of several nanometers, exhibits good anti-oxidation stability. The SiO2/nanoFe catalyst also exhibits good catalytic performance for the aquathermolysis process of heavy oils; in particular, at a mass fraction of 1.0%, it can significantly reduce the viscosity of a tested heavy oil from 184 to 42 Pa·s, showing promising potential in the industrial production of heavy oils.

Downhole Electrical Heating for Enhanced Heavy-Oil Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16858, ’Downhole Electrical Heating for Heavy-Oil Enhanced Recovery: A Successful Application Offshore Congo,’ by F. Bottazzi, C. Repetto, E. Tita, and G. Maugeri, Eni, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. Several enhanced-oil-recovery (EOR) techniques (thermal methods in particular) are currently available to achieve higher recovery factors in heavy-oil fields. However, some technologies, such as downhole electrical heating (DHEH), have been improved recently, allowing enhancement of production and therefore improvement of the recovery factor with relatively low investment cost in comparison with the high costs involved in the implementation of thermal technologies. To increase the production of a heavy-oil reservoir offshore Congo, a study of DHEH applications has been carried out with encouraging results. Introduction The Zatchi Marine field, operated by Eni Congo in partnership with Total Congo, is located approximately 25 km from the Congolese coast (Fig. 1). It is a multilayered sand reservoir with five oil-bearing levels (A through E). In particular, Level B is a 30-m-thick sand characterized by a large accumulation of heavy and highly viscous oil with the presence of both a bottom and a gas cap and very low reservoir pressure. Water depth ranges from 55 to 57 m, and there is an areal extension of approximately 34 km2. The development of the Zatchi B reservoir has always been an extreme challenge. Since the development of the field, six wells have been drilled and only three have been put into production, with sometimes unsatisfying results because of the severe problems of gas coning and cresting. An important improvement was achieved in 2008 with the drilling and completion of Well ZAM-408 ML, the first successful multilateral well ever drilled in West Africa and the first Technology Advancement of Multilaterals Level 6 technology applied in the Congo basin. Following this important achievement and the growing interest in the various EOR techniques and development scenarios, a dedicated study was conducted by Eni to evaluate and assess the most suitable integrated technology applicable to the Zatchi B reservoir. Reservoir simulations showed that among the different EOR techniques, thermal methods could enhance the recovery factor from this reservoir significantly. However, because the study is considering an offshore field (producing from a platform with very limited space and available power supply), and taking into account the heterogeneous reservoir environment, thermal methods were deemed to be too costly, with a high risk and a long-term implementation. Therefore, another technique was taken into consideration: cold production assisted by a DHEH system, which represents the edge between cold and hot production. DHEH allows production enhancement and thus improvement of recovery factor, with significantly lower investment costs when compared with those typically associated with the implementation of thermal technologies such as steam injection. This technology uses a three-phase system designed to provide a defined wattage according to the different applications and type of cables. The heater section is set downhole and is connected to the surface with a power cable. It generates heat to the near-wellbore region, decreasing viscosity and friction and, consequently, increasing oil mobility.

Antenna array design for enhanced oil recovery under oil reservoir constraints with experimental validation

In this paper, a detailed mathematical model of EM (electromagnetic) heating for EOR (enhanced oil recovery) is presented. The model takes into consideration three different designs of the array of EM sources under the constraint of the dimensions, dielectric constituents, and geophysics properties of oil reservoirs. This includes a simple waveguide antenna, an E-plane spectral horn antenna of different dimensions and an array of waveguide antennas with and without deflected phases. Simulation studies have been performed at frequencies of 915 MHz, 2450 MHz and 5800 MHz for the three aforementioned designs under different combinations of the placement, positioning, and orientation of antennas. Furthermore, an experimental verification of the suggested model is addressed by designing and building a new experimental setup which has the advantage to mimic more realistically real oil reservoirs as compared to microwave ovens. These latest which were mainly used as the test platform by other researchers feature substantial differences with oil field reservoirs. The corresponding results indicate a good matching (i.e. 95% matching) with the suggested model, while outperforming other traditional enhanced oil recovery techniques. This leads to state that EM-based EOR can be a good alternative to the other existing techniques.

Efficient screening of enhanced oil recovery methods and predictive economic analysis

Oil demand for economic development around the world is rapidly increasing. Moreover, oil production rates are getting a peak in mature reservoirs and tending to decline in the near future, which has led to considerable researches on enhanced oil recovery (EOR) methods. Therefore, an efficient technical and economical screening to appropriate selection of EOR methods can make savings in time and cost. The purpose of this communication is to present a method to select an efficient EOR process and investigate its economic parameters. A database of reservoir parameters of rock and fluid properties along with successful EOR techniques has been collected and analyzed. First, an artificial neural network (ANN) was developed to classify the EOR methods technically. Then, an economical EOR screening model was designed, and then, future cash flows on the use of EOR methods were predicted. The results show that the ANN system can select proper EOR methods and classify them. Moreover, the obtained results indicate that the economic analysis performed in this study is efficient and useful to predict future cash flows.

Recovery rates, enhanced oil recovery and technological limits

Enhanced oil recovery (EOR) techniques can significantly extend global oil reserves once oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average oil recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR.

EOR POTENTIAL WITHIN IRAN

As the application of enhanced oil recovery (EOR) mechanisms expands globally, a vast amount of information is reported annually and many statistical works are carried out aiming mostly at the feasibility study of employing EOR methods for candidate reservoirs. In the last decades, researchers have gathered huge databases and used various techniques to identify screening criteria ranges for each EOR method. Screening algorithms are then developed to desirably benefit from the criteria ranges for candidate selection. The numerous screening criteria ranges reported for each EOR technique and the variety of screening algorithms raise the problem of choice, especially for petroleum engineers who plan to initiate EOR projects. This paper summarizes important screening criteria and screening algorithms and discusses and elaborates on subjects such as the importance of the following: accuracy in the EOR screening, comparing the parameters of the candidate reservoir with the criteria ranges, establishing a quantitative basis for comparison, dealing with a large number of candidate reservoirs, ranking the importance of parameters for each EOR method, assigning weights for parameters, and defining cutoffs. Based on a series of optimistic and pessimistic criteria extracted from the collected criteria, a case study is performed involving 11 candidate Iranian reservoirs and the EOR options for each reservoir are ranked accordingly. Then, a predictive correlation is used to identify reservoirs with the highest recovery factors among the candidates of the CO2 miscible flooding. The results show that miscible CO2 and hydrocarbon gas injections are two promising mechanisms for the reservoirs under study.

Efficient Scheme for Chemical Flooding Simulation

In this paper, we investigate an efficient implicit scheme for the numerical simulation of chemical enhanced oil recovery technique for oil fields. For the sake of brevity, we only focus on flows with polymer to describe the physical and numerical models. In this framework, we consider a black oil model upgraded with the polymer modeling. We assume the polymer only transported in the water phase or adsorbed on the rock following a Langmuir isotherm. The polymer reduces the water phase mobility which can change drastically the behavior of water oil interfaces. Then, we propose a fractional step technique to resolve implicitly the system. The first step is devoted to the resolution of the black oil subsystem and the second to the polymer mass conservation. In such a way, jacobian matrices coming from the implicit formulation have a moderate size and preserve solvers efficiency. Nevertheless, the coupling between the black-oil subsystem and the polymer is not fully resolved. For efficiency and accuracy comparison, we propose an explicit scheme for the polymer for which large time step is prohibited due to its CFL (Courant-Friedrichs-Levy) criterion and consequently approximates accurately the coupling. Numerical experiments with polymer are simulated : a core flood, a 5-spot reservoir with surfactant and ions and a 3D real case. Comparisons are performed between the polymer explicit and implicit scheme. They prove that our polymer implicit scheme is efficient, robust and resolves accurately the coupling physics. The development and the simulations have been performed with the software PumaFlow [PumaFlow (2013) Reference manual, release V600, Beicip Franlab].