Miscible Flooding for Bitumen Recovery with a Novel Solvent

2021 ◽  
Author(s):  
Tanya Ann Mathews ◽  
Alex J.Cortes ◽  
Richard Bryant ◽  
Berna Hascakir
Keyword(s):  
Oil Recovery ◽  
Cold Water ◽  
Pore Space ◽  
Oil Quality ◽  
Environmental Concerns ◽  
Solvent Recovery ◽  
Core Flooding ◽  
Recovery Method ◽  
Steam Flooding ◽  
Oil Emulsions

Abstract Steam injection is an effective heavy oil recovery method, however, poses several environmental concerns. Solvent injection methods are introduced in an attempt to combat these environmental concerns. This paper evaluates the effectiveness of a new solvent (VisRed) in the recovery of a Canadian bitumen and compares its results with toluene. While VisRed is selected due to its high effectiveness as a viscosity reducer even at very low concentrations, toluene is selected due to its high solvent power. Five core flooding experiments were conducted; E1 (Steam flooding), E2 (VisRed flooding), E3 (Toluene flooding), E4 (Steam + Toluene flooding), and E5 (Steam + VisRed flooding). Core samples were prepared by saturating 60% of the pore space with oil samples and 40% with deionized water. The solvents were injected at a 2 ml/min rate, while steam was injected at a 18 ml/min cold water equivalent rate. Produced oil and water samples were collected every 20 min during every experiment. The oil recovery efficiencies of the core flood experiments were analyzed by the emulsion characterization in the produced fluids and the residual oil analysis on the spent rock samples. The best oil recovery of ~30 vol % was obtained for E2 (VisRed) in which VisRed was injected alone. Although similar cumulative recoveries were obtained both for E2 (VisRed) and E3 (Toluene), the amount of VisRed injected [~1 pore volumes (PV)] was half the volume required by toluene (~2 PV). The produced oil quality variations are mainly due to the formation of the water-in-oil emulsions during mainly steam processes (E1, E4, and E5). The increased amount of the polar fractions in the produced oil enhances the formation of the emulsions. These polar fractions are namely asphaltenes and resins. As the amount of the polar fractions in the produce oil increases, more water-in-oil emulsion formation is observed due to the polar-polar interaction between crude oil fractions and water. Consequently, E1 and E5 resulted in more water in oil emulsions. The cost analysis also shows the effectiveness of solvent recovery over steam-solvent recovery processes.

scholarly journals The Fast Potential Evaluation Method of Enhanced Oil Recovery Based on Statistical Analysis

Processes ◽  
2019 ◽  
Vol 7 (11) ◽  
pp. 795
Author(s):  
Zhengbo Wang ◽  
Qiang Wang ◽  
Desheng Ma ◽  
Wanchun Zhao ◽  
Xiaohan Feng ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Evaluation Method ◽  
Enhanced Recovery ◽  
Chemical Flooding ◽  
Recovery Method ◽  
Steam Flooding ◽  
Tertiary Oil Recovery ◽  
Similarity Ratio ◽  
Potential Evaluation ◽  
Target Block

Based on a large number of empirical statistics of tertiary oil recovery technology in China, including polymer flooding, chemical flooding, gas flooding, in situ combustion, steam flooding, ect., 22 key reservoir parameters were filterized. Five levels of quantitative screening criteria were developed for different tertiary oil recovery methods. The mean algorithm for the downward approximation and the grey correlation theory were used in this paper to quickly select the appropriate tertiary oil recovery method for the target blocks, which provides a preferred development method for subsequent potential evaluation. In the rapid analogy evaluation method of tertiary oil recovery potential, the total similarity ratio between the target block and the example block is determined. The target block is matched with the appropriate instance block according to the total similarity ratio value, using 80% as the boundary. The ratio of the geological reserves is used to predict the oil recovery interval, the actual annual injection data, and the economic profit, thus quickly predicting the economic potential of the tertiary oil recovery technology in the target block. Currently, our research team has integrated these two methods into the tertiary oil production potential evaluation software EORSYS3.0. The empirical analysis shows that this method is reasonable and the conclusion is reliable. In addition, the actual enhanced recovery value is within the effective range predicted by the method. The method and results of this paper will provide an important decision-making reference for the application and sustainable development of China Petroleum’s main tertiary oil recovery technology in the next 5–10 years.

scholarly journals Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing

Nanomaterials ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 972 ◽  
Author(s):  
Amin Rezaei ◽  
Hadi Abdollahi ◽  
Zeinab Derikvand ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Amir Mosavi ◽  
...  
Keyword(s):  
Size Distribution ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Alpha Olefin Sulfonate ◽  
Core Flooding ◽  
Recovery Method ◽  
Fluid Saturation

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

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

SPE Journal ◽  
2014 ◽  
Vol 20 (01) ◽  
pp. 88-98 ◽  
Author(s):  
Arne Graue ◽  
Johannes Ramsdal ◽  
Martin A. Fernø
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Water Injection ◽  
Spontaneous Imbibition ◽  
Local Dynamic ◽  
Water Mobility ◽  
Recovery Method ◽  
Connate Water ◽  
The Core ◽  
Viscous Pressure

Summary In 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.

Visual Flooding Experiment of Hot Water, Steam and Solvent Under SAGD and VAPEX Conditions

2021 ◽  
Author(s):  
Songyan Li ◽  
Rui Han ◽  
Qun Wang ◽  
Xuemei Wei
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Hot Water ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Water Steam ◽  
Solvent Vapor ◽  
Recovery Method ◽  
Steam Flooding

Abstract Steam-assisted gravity drainage (SAGD) is an important method of heavy oil production, and the solvent vapor extraction (VAPEX) process is also an economically feasible, technically reliable, and environmentally friendly in situ heavy oil recovery method. In this paper, a microscopic visual flooding device was used to conduct seven groups of visual flooding experiments, including hot water, steam, liquid solvent and vapor solvent, at different temperatures. It can be directly observed that the residual oil in the hot water swept area is generally distributed in “spots”, “strips” and “clusters” of varying sizes. The residual oil after steam flooding generally has a “cluster” distribution, the residual oil after liquid solvent flooding has a “film” distribution, and there is only a little “spot” residual oil distributed after solvent vapor flooding. Additionally, we found that the sweep efficiency and displacement efficiency of hot water, steam and solvent increase with increasing temperature, and the sweep efficiency of hot water is higher than that of steam and liquid solvent. Vapor solvent has the greatest recovery factor, reaching approximately 90%. The experimental results hint at the future development trend of solvent injection and support the foundation of more general applications pertaining to the sustainable production of unconventional petroleum resources.

Novel Enhanced Oil Recovery Method Using Co2+xFe2+1-xFe3+2O4 as Magnetic Nanoparticles Activated by Electromagnetic Waves

2013 ◽  
Vol 26 ◽  
pp. 111-116 ◽  
Author(s):  
Hasan Soleimani ◽  
Noorhana Yahya ◽  
Noor Rasyada Ahmad Latiff ◽  
Hasnah Mohd Zaid ◽  
Birol Demiral ◽  
...  
Keyword(s):  
Magnetic Nanoparticles ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Electromagnetic Waves ◽  
High Salinity ◽  
Harsh Environment ◽  
Oil Reservoir ◽  
Core Flooding ◽  
Recovery Method ◽  
High Pressure And Temperature

Research on the application of nanoparticles, specifically magnetic nanoparticles in enhanced oil recovery has been increasing in recent years due to their potential to increase the oil production despite having to interact with reservoirs of high salinity, high pressure and temperature and un-natural pH. Unlike other conventional EOR agents e.g. surfactants and polymers, a harsh environment will cause degradation and failure to operate. Magnetic nanoparticles which are activated by a magnetic field are anticipated to have the ability to travel far into the oil reservoir and assist in the displacement of the trapped oil. In this work, ferromagnetic Co2+xFe2+1-xFe3+2O4 nanoparticles were synthesized and characterized for their morphological, structural and magnetic properties. At a composition x = 0.75, this nanomaterial shows its best magnetisation parameters i.e. highest value of saturation magnetization, remanence and coercivity of 65.23 emu/g, 12.18 emu/g and 239.10 Oe, respectively. Subsequently, a dispersion of 0.01 wt% Co2+0.75Fe2+0.25Fe3+2O4 nanoparticles in distilled water was used for core flooding test to validate its feasibility in enhanced oil recovery. In a core flooding test, the effect of electromagnetic waves irradiation to activate the magnetization of Co2+0.75Fe2+0.25Fe3+2O4 nanofluid was also investigated by irradiating a 78 MHz square wave to the porous medium while nanofluid injection was taking place. In conclusion, an almost 20% increment in the recovery of oil was obtained with the application of electromagnetic waves in 2 pore volumes injection of a Co2+0.75Fe2+0.25Fe3+2O4 nanofluid.

Oil Recovery by a Water-Driven Steam Slug

1971 ◽  
Vol 11 (04) ◽  
pp. 351-355 ◽  
Author(s):  
M.M. El-Saleh ◽  
S.M. Farouq Ali
Keyword(s):  
Porous Medium ◽  
Oil Recovery ◽  
Cold Water ◽  
Steam Injection ◽  
Injection Rate ◽  
Heat Losses ◽  
Recovery Method ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Experimental Apparatus

Abstract Results of an experimental study of oil recovery by a steam slug driven by a cold waterflood in a linear porous medium are described. The model included simulation of heat losses to the adjacent formations. Steam displacements were conducted, using a number of hydrocarbons and various steam-slug sizes, with the core initially containing a residual oil or irreducible water saturation. It was found that the steam-slug displacement is more efficient in the case of light oils than for the heavier ones. The injection of cold water following steam resulted in almost total condensation of the steam present in the porous medium, with the process degenerating into a hot waterflood. The oil process degenerating into a hot waterflood. The oil recovery efficiency of the process depends on whether an oil bank is formed during the steam-injection phase and whether the oil responds favorably to a hot phase and whether the oil responds favorably to a hot waterflood Introduction Steam injection has been shown to be an effective oil recovery method both by field and laboratory tests. However, the method has the inherent disadvantages of a high cost of operation and excessive heat losses. The modification discussed here consists in the injection of cold water after a slug of steam, which helps to offset the above disadvantages partly at the expense of oil recovery. The injected water serves to propel the oil bank formed ahead of the steam-invaded zone and transports the heat contained in the steam-swept zone farther downstream, thus leading to more complete utilization of the heat injected. EXPERIMENTAL APPARATUS AND PROCEDURE Fig. 1 depicts a schematic diagram of the apparatus employed. It consisted of a 4-ft-long core composed of a steel tube having a rectangular cross-section (see Table 1 for dimensions and other information) packed with glass beads (mesh size 200 to 270, corresponding to 0.0021 to 0.0029 in.) and fitted with 15 iron-constantan thermocouples and eight pressure gauges. The two ends of the core were fitted with sintered bronze plates to ensure strictly linear fluid flow. In order to simulate the underlying formations, the core was placed upon a sand-filled wooden box having a depth placed upon a sand-filled wooden box having a depth of 2.5 ft and a length and width equal to those of the core. An identical box was placed in contact with the top surface of the core to simulate the overlying formations. The sand packs simulated infinitely thick formations, since the temperatures at the upper and lower extremities remained undisturbed during a run. The sides of the two boxes were fitted with thermometers and insulated, together with the exposed surface of the core; the top and bottom surfaces of the core were in contact with sand. An electrical system was designed for temperature measurement at the 15 points; the core inlet and outlet were fitted with thermocouples. A technique was devised for pressure measurement virtually without disturbing the flow. A positive-displacement pump, in conjunction with a coil immersed in a high-temperature oil bath, was used for conducting hot waterfloods as well as for preparing the core for a run (Fig. 1). Steam, having a quality of 95 percent was supplied by an electric boiler capable of delivering up to 69 lb/hr at pressures up m 250 psig. The core effluent was passed though a suitable condenser provided with passed though a suitable condenser provided with a backpressure regulator used to control the steam injection rate. The average steam (as condensate) injection rate for a run was estimated by dividing the total effluent volume minus the volume of the water needed to fill up the core at the end of steam injection, by the steam injection time. The properties of the fluids used are listed in Table 1. The hydrocarbon mixtures were chosen to study the steam distillation effects. Drakeol 15 and 33 at 80 deg. F are high-boiling mineral oils having viscosities of 515 and 100.0 cp, respectively. Viscosity-temperature behavior for the hydrocarbons used is shown in Fig. 2. The core was saturated with distilled water and then saturated with the oil to be tested by displacement (terminal WOR 1:100). If desired, the core was waterflooded prior to steam injection (terminal WOR 100:1). SPEJ P. 351

scholarly journals Quantifying the Effect of De-Emulsifiers on Acid Treatment in Carbonate Formations

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1148
Author(s):  
Mohamed Elsafih ◽  
Mashhad Fahes ◽  
Catalin Teodoriu
Keyword(s):  
Pore Space ◽  
Added Value ◽  
Core Flooding ◽  
Rock Matrix ◽  
Well Productivity ◽  
Matrix Acidizing ◽  
Shear Mixing ◽  
Oil Emulsions ◽  
Carbonate Formations ◽  
The Cost

Matrix acidizing is a highly successful, effective, and relatively inexpensive approach to enhancing well productivity in carbonate formations. Accordingly, there has been little motivation to address the ways to optimize the acid stimulation process better. Acid-in-oil emulsions that form during this process cause one of the most challenging problems that negatively impact the performance and deliverability, especially when these emulsions are highly stable over extended periods. Such stable emulsions can plug the flow path of oil causing high resistance to flow and potentially reducing well productivity. De-emulsifiers are some of the most widely used acid additives targeting the reduction of emulsion stability. However, there is doubt in the research community on whether there is enough shear mixing that can cause the formation of emulsions inside the rock matrix. Besides, the effectiveness of de-emulsifiers in eliminating such emulsions in the pore space has not been investigated. In the current oil price market, there is a need to be more vigilant regarding the cost of well stimulation and the added value from the various additives. While laboratory work on matrix acidizing in carbonate formations is abundant, the work on oil-saturated samples is rare, and therefore, the effect of emulsions on the acidizing process has not been widely documented. In this work, we present a stacked study of bottle tests and core flooding tests designed to investigate the de-emulsifiers’ role in the rock matrix. The results reveal that (1) emulsion-risk in the pore space is real, and (2) the addition of de-emulsifiers to the acid allows for efficient backflow of oil, revealing an improvement in the performance of the acidizing treatment.

scholarly journals Steam injection in porous media: Case study WadiRajil, Jordan

2020 ◽  
Vol 3 (2) ◽  
pp. 57-63
Author(s):  
Mehaysen Mahasneh
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Cold Water ◽  
Steam Injection ◽  
Core Sample ◽  
Thermal Recovery ◽  
Hot Water ◽  
Influx Rate ◽  
Recovery Method ◽  
Total Oil

Hot fluid injection, the preferred method used in the recovery of heavy oil and in various mechanisms such as steam drive, cyclic steam injection, steam stimulation, has become the industrial method for increasing recovery. These methods were used to promote heavy oil recovery by reducing the viscosity of asphalt and heavy oil and increasing the mobility of oil in reservoirs. The experimental test was carried out on a core sample obtained from the Ghareb Formation in the Wadi-Rajil area using cold water, hot water, and steam injection. The maximum recovery of oil in the sample using cold and hot water was 9.75% and 27.3 % respectively. On the other hand, the recovery of oil using steam injection was 42.5%. Thus, steam injection yielded more oil than cold and hot water injections in this experiment; the steam injection influx rate was approximately 15 mL/min. The total oil recovery of the sample using these three mechanisms was around 80%. The steam injection can, thus, be considered a promising thermal recovery method for asphalt and heavy oil in the Wadi-Rajil area.

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

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.

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