scholarly journals Effects of nanocomposite polymer flooding on Egyptian crude oil recovery

2020 ◽  
Vol 10 (8) ◽  
pp. 3937-3945
Author(s):  
M. E. Helmi ◽  
M. Abu El Ela ◽  
S. M. Desouky ◽  
M. H. Sayyouh
Keyword(s):  
Crude Oil ◽  
Relative Permeability ◽  
Polymer Matrix ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Western Desert ◽  
Polymerization Process ◽  
Reservoir Temperature ◽  
Nanocomposite Polymer ◽  
Relative Permeability Curves

Abstract In this work, a laboratory study of enhanced oil recovery (EOR) was carried out using Egyptian crude oil of 37°API extracted from a reservoir in the Western Desert to identify the optimum conditions for the application of locally prepared nanocomposite polymer flooding under harsh reservoir condition. In contrary to the other studies, we tested the ability of nanocomposite polymer where nanoparticles are involved in the polymer matrix during polymerization process. Measurements of viscosity and shear rate of several solutions were taken. Displacement runs were conducted at different conditions of nanocomposite polymer salinities (10,000, 20,000, 30,000, 40,000, 50,000, 60,000 and 65,000 ppm), concentrations (1, 1.5, 2, 2.5, 3, 3.5 and 4 g/L) and slug sizes (0.2, 0.4, 0.6 and 0.8 PV). A linear sandpack (length of 62.5 cm and diameter of 2″) was prepared and wrapped with thermal jacket to simulate several reservoir temperatures. It was filled by selected sand size to produce linear sandpack model with reasonable porosity (22%) and permeability (129–157 mD) values. The model was used to perform several displacements runs for waterflooding and nanocomposite polymer flooding. The results of the flood runs are analyzed using the water–oil relative permeability curves. The measurements of the solutions properties showed that the critical concentration of the used nanocomposite polymer in the solution is 2 g/L. Also, it was observed that the used nanocomposite polymer solution could withstand a salinity of 60,000 ppm. As a result of the flooding, it was found that the optimum economical slug size of the used nanocomposite polymer is 0.4 PV at reservoir temperature of 40 °C. The results indicated also that the used nanocomposite polymer could withstand a reservoir temperature of 90 °C. The water–oil relative permeability curves showed an enhancement of oil relative permeability and a decrease in the water relative permeability using nanocomposite polymer over waterflooding. The cost of the used nanocomposite polymer with a concentration of 2 g/L and slug size of 0.4 PV is 0.626 $ for each barrel of the incremental oil recovery. Based on the results of this work, it is clear that involving nanoparticles such as silica in the polymer matrix composition improves its properties, thermal and salinity resistivity. Such study is an original contribution to carry out successful nanocomposite polymer EOR projects.

Micellar Flooding - Compositional Effects on Oil Displacement

1979 ◽  
Vol 19 (02) ◽  
pp. 116-128 ◽  
Author(s):  
Surendra P. Gupta ◽  
Scott P. Trushenski
Keyword(s):  
Crude Oil ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Capillary Number ◽  
Field Application ◽  
Displacement Efficiency ◽  
Micellar Phase ◽  
Oil Displacement ◽  
Relative Permeability Curves

Abstract Key variables that govern oil displacement in a micellar flood are capillary number (velocity x viscosity/interfacial tension) and chemical loss. At high capillary numbers, oil displacement is very efficient if various phases propagate at the same velocity. Chemical loss, however, is not always low when oil displacement efficiency is high. Compositions developed in situ often alter the ability of the micellar fluid to displace oil. Oil recovery can be predicted from static equilibrium fluid properties, providing the in situ compositions are known.The displacement of the wetting phase requires a capillary number of 10 times higher than that required to displace the nonwetting phase. This implies less efficient oil displacement in oil-wet systems. The correlation of oil recovery vs capillary number also varies with rock structure and wettability. Hence, for field application, immiscible oil displacement with micellar fluids should be determined in reservoir rocks. The decrease in final oil saturation with increase in capillary number indicates that relative permeability changes with capillary number. A numerically study showed that both the end-points and the shape of the relative permeability curves affect oil recovery at high permeability curves affect oil recovery at high capillary number in a slug process. The shape of the relative-permeability curves also affects the design of micellar slug viscosity. Thus, for field application, it is important to know the shape of relative-permeability curves at anticipated capillary numbers. Introduction In a micellar flood, the injected fluid banks interact with one another and with the reservoir brine, crude oil, and reservoir rock. This places stringent requirements on the design of the micellar flood. Initially, the micellar fluid may be miscible with crude oil and reservoir brine. However, because of dilution and surfactant adsorption, the flood can degenerate to an immiscible displacement. If low interfacial tension (IFT), or more specifically, high capillary number (velocity x viscosity/IFT) is maintained between all the phases, the displacement efficiency is good.There are many phenomena that can decrease oil recovery efficiency. The most important are chemical (surfactant or sulfonate) losses from adsorption by the rock, precipitation by high-salinity and high-hardness brines, interaction with polymer, partitioning into an immobile phase, and trapping of partitioning into an immobile phase, and trapping of the surfactant-rich phase. Recovery efficiency also can be poor when unfavorable in situ compositions develop. This occurs when the micellar fluid is diluted, develops undesirable salinity and hardness environment, experiences selective adsorption of surfactant, or undergoes selective partitioning of components into phases moving at different velocities.A micellar phase (or microemulsion) can exist in equilibrium with excess oil, water, or both. Winsor designated such phase behavior as Type I, II, and III, respectively. More recently, Healy et al. identified this behavior as lower phase (where the micellar phase is in equilibrium with excess oil), upper phase (where the micellar phase is in equilibrium with excess water), and middle phase (where the micellar phase is in equilibrium with excess oil and water). The importance of phase behavior has been the subject of considerable discussion in the literature.Since the function of the micellar fluid is to displace crude oil, not water, it would be desirable if the micellar fluid remained miscible with oil and immiscible with water during the immiscible displacement portion of a flood. This is achieved with upper-phase micellar systems. Since only a small bank of micellar fluid is injected, it must be displaced effectively by the succeeding polymer water bank. However, the upper-phase micellar fluid is not miscible with the polymer water; therefore, some of the micellar phase may be trapped as an immobile saturation (much as residual oil is trapped). SPEJ p. 116

Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2260-2278 ◽  
Author(s):  
R. S. Seright ◽  
Dongmei Wang ◽  
Nolan Lerner ◽  
Anh Nguyen ◽  
Jason Sabid ◽  
...  
Keyword(s):  
Crude Oil ◽  
Polymer Solution ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Water Saturation ◽  
Field Application ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Polymer Flood

Summary This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

A Temperature Operating Window Concept for Application of Nonionic Surfactants for EOR in Unconventional Shale Reservoirs

2021 ◽  
Author(s):  
I Wayan Rakananda Saputra ◽  
David S. Schechter
Keyword(s):  
Crude Oil ◽  
Nonionic Surfactant ◽  
Cloud Point ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Spontaneous Imbibition ◽  
Reservoir Temperature ◽  
Rock System ◽  
Temperature Operating ◽  
Operating Window

Abstract Surfactant performance is a function of its hydrophobic tail, and hydrophilic head in combination with crude oil composition, brine salinity, rock composition, and reservoir temperature. Specifically, for nonionic surfactants, temperature is a dominant variable due to the nature of the ethylene oxide (EO) groups in the hydrophilic head known as the cloud point temperature. This study aims to highlight the existence of temperature operating window for nonionic surfactants to optimize oil recovery during EOR applications in unconventional reservoirs. Two nonylphenol (NP) ethoxylated nonionic surfactants with different EO head groups were investigated in this study. A medium and light grade crude oil were utilized for this study. Core plugs from a carbonate-rich outcrop and a quartz-rich outcrop were used for imbibition experiments. Interfacial tension and contact angle measurements were performed to investigate the effect of temperature on the surfactant interaction in an oil/brine and oil/brine/rock system respectively. Finally, a series of spontaneous imbibition experiments was performed on three temperatures selected based on the cloud point of each surfactant in order to construct a temperature operating window for each surfactant. Both nonionic surfactants were observed to improve oil recovery from the two oil-wet oil/rock system tested in this study. The improvement was observed on both final recovery and rate of spontaneous imbibition. However, it was observed that each nonionic surfactant has its optimum temperature operating window relative to the cloud point of that surfactant. For both nonionic surfactants tested in this study, this window begins from the cloud point of the surfactant up to 25°F above the cloud point. Below this operating window, the surfactant showed subpar performance in increasing oil recovery. This behavior is caused by the thermodynamic equilibrium of the surfactant at this temperature which drives the molecule to be more soluble in the aqueous-phase as opposed to partitioning at the interface. Above the operating window, surfactant performance was also inferior. Although for this condition, the behavior is caused by the preference of the surfactant molecule to be in the oleic-phase rather than the aqueous-phase. One important conclusion is the surfactant achieved its optimum performance when it positions itself on the oil/water interface, and this configuration is achieved when the temperature of the system is in the operating window mentioned above. Additionally, it was also observed that the 25°F operating window varies based on the characteristic of the crude oil. A surfactant study is generally performed on a single basin, with a single crude oil on a single reservoir temperature or even on a proxy model at room temperature. This study aims to highlight the importance of applying the correct reservoir temperature when investigating nonionic surfactant behavior. Furthermore, this study aims to introduce a temperature operating window concept for nonionic surfactants. This work demonstrates that there is not a "one size fits all" surfactant design.

The Characteristics and Impacts Factors of Relative Permeability Curves in High Temperature and Low-Permeability Limestone Reservoirs

2014 ◽  
Vol 1010-1012 ◽  
pp. 1676-1683 ◽  
Author(s):  
Bin Li ◽  
Wan Fen Pu ◽  
Ke Xing Li ◽  
Hu Jia ◽  
Ke Yu Wang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Phase Region ◽  
Two Phase ◽  
Experimental Conditions ◽  
Irreducible Water Saturation ◽  
Productive Water ◽  
Relative Permeability Curves ◽  
Water Cut

To improve the understanding of the influence of effective permeability, reservoir temperature and oil-water viscosity on relative permeability and oil recovery factor, core displacement experiments had been performed under several experimental conditions. Core samples used in every test were natural cores that came from Halfaya oilfield while formation fluids were simulated oil and water prepared based on analyze data of actual oil and productive water. Results from the experiments indicated that the shape of relative permeability curves, irreducible water saturation, residual oil saturation, width of two-phase region and position of isotonic point were all affected by these factors. Besides, oil recovery and water cut were also related closely to permeability, temperature and viscosity ratio.

An Imbibition Model - Its Application to Flow Behavior and the Prediction of Oil Recovery

1961 ◽  
Vol 1 (02) ◽  
pp. 61-70 ◽  
Author(s):  
J. Naar ◽  
J.H. Henderson
Keyword(s):  
Porous Medium ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Pore Geometry ◽  
Mathematical Treatment ◽  
Complete Wetting ◽  
Permeability Characteristics ◽  
Relative Permeability Curves ◽  
Wetting Fluid

Introduction The displacement of a wetting fluid from a porous medium by a non-wetting fluid (drainage) is now reasonably well understood. A complete explanation has yet to be found for the analogous case of a wetting fluid being spontaneously imbibed and the non-wetting phase displaced (imbibition). During the displacement of oil or gas by water in a water-wet sand, the porous medium ordinarily imbibes water. The amount of oil recovered, the cost of recovery and the production history seem then to be controlled mainly by pore geometry. The influence of pore geometry is reflected in drainage and imbibition capillary-pressure curves and relative permeability curves. Relative permeability curves for a particular consolidated sand show that at any given saturation the permeability to oil during imbibition is smaller than during drainage. Low imbibition permeabilities suggest that the non-wetting phase, oil or gas, is gradually trapped by the advancing water. This paper describes a mathematical image (model) of consolidated porous rock based on the concept of the trapping of the non-wetting phase during the imbibition process. The following items have been derived from the model.A direct relation between the relative permeability characteristics during imbibition and those observed during drainage.A theoretical limit for the fractional amount of oil or gas recoverable by imbibition.An expression for the resistivity index which can be used in connection with the formula for wetting-phase relative permeability to check the consistency of the model.The limits of flow performance for a given rock dictated by complete wetting by either oil or water.The factors controlling oil recovery by imbibition in the presence of free gas. The complexity of a porous medium is such that drastic simplifications must be introduced to obtain a model amenable to mathematical treatment. Many parameters have been introduced by others in "progressing" from the parallel-capillary model to the randomly interconnected capillary models independently proposed by Wyllie and Gardner and Marshall. To these a further complication must be added since an imbibition model must trap part of the non-wetting phase during imbibition of the wetting phase. Like so many of the previously introduced complications, this fluid-block was introduced to make the model performance fit the observed imbibition flow behavior.

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

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1929-1943 ◽  
Author(s):  
Yongge Liu ◽  
Jian Hou ◽  
Lingling Liu ◽  
Kang Zhou ◽  
Yanhui Zhang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Relative Permeability ◽  
Polymer Flooding ◽  
Inversion Method ◽  
Residual Resistance ◽  
Relative Permeability Curve ◽  
Nonsteady State ◽  
State Method ◽  
Relative Permeability Curves

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

Experimental Study of the Biochemistry Method for Enhancing Oil Recovery in the Oil Reservoir after Polymer Flooding

2013 ◽  
Vol 647 ◽  
pp. 144-149
Author(s):  
Yue Hui She ◽  
Fan Zhang ◽  
Bo Xun Liang ◽  
Zheng Liang Wang ◽  
Long Jiang Yu
Keyword(s):  
Polycyclic Aromatic Hydrocarbon ◽  
Aromatic Hydrocarbon ◽  
Crude Oil ◽  
Oil Recovery ◽  
Degradation Rate ◽  
Polymer Flooding ◽  
Residual Oil ◽  
Degrading Bacteria ◽  
Profile Control ◽  
Polycyclic Aromatic

A delayed cross linked gel profile control agent is used to plug high permeable formations. Also, well nutrient fluid and microbes are injected with 50% of the heavy residual oil, after polymer flooding, in order to improve oil recovery due to the complex environment of oil reservoirs. Four strains of polycyclic aromatic hydrocarbon-degrading bacteria are selected from oilfield produced water with a high efficiency. Two of the four strains, namely BISYX17 and BISYX14, are new. Polycyclic aromatic hydrocarbon-degrading bacteria have high growth activity and they are able to reach a maximum stain concentration after being cultured 4 to 8 days, using phenanthrene as their sole carbon source. They are able to effectively degrade heavy hydrocarbon with a phenanthrene degradation rate of up to 80％, after the sample is cultured for seven days. Strain BISYX7 has the strongest phenanthrene -degrading ability, with a maximum degradation percentage of 89.89％. The strains are capable of producing dioxygenase to open rings of polycyclic aromatic hydrocarbon. The dioxygenase activity, produced by BISYX17, is able to reach 40.2 IU/mg, which is higher than the enzyme activities of a wild strain. This shows the strain has excellent potential to produce enzymes. Enzymes, produced by metabolism, have a direct degradation rate of 68% on crude oil. A core displacement simulation experiment indicates a profile control oil-displacing system is able to improve crude oil recovery efficiency by 17%, after polymer flooding. Thus, the system has excellent application potential for residual oil recovery.

Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform

2021 ◽  
Author(s):  
Mohammad Sedaghat ◽  
Hossein Dashti
Keyword(s):  
Complex System ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Wettability Alteration ◽  
System Modelling ◽  
Naturally Fractured ◽  
Relative Permeability Curves

Abstract Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.

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