Applied Research of Heat Self-Generated CO2 Technology in Steam Huff and Puff

2014 ◽  
Vol 1010-1012 ◽  
pp. 1693-1698
Author(s):  
Yi Ding ◽  
Guo Wei Qin ◽  
Peng Liu ◽  
Zi Li Fan ◽  
Hong Wei Xiao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Field Experiments ◽  
Reduction Rate ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Blowing Agent ◽  
Steam Flooding ◽  
Gas Flooding

Heat self-generated CO2 technique is proposed, which is focused on the problems of recovery difficulty, poor effect steam soaking and so on for heavy oil reservoirs. This technology is combining of steam flooding and gas flooding and so on. Its main mechanism is the application of steam heating blowing agent to generate a large volume of gases (including CO2, NH3, etc) in the formation. While some of these gases acting with the oil to reduce the oil viscosity, some form miscible flooding to reduce water interfacial tension, so as to achieve the purpose of enhancing oil recovery. An optimized selection of the heat blowing agents was performed. By comparison the difference before and after the reaction of blowing agent solution, the increase of alkaline is occurred after the reaction, and is helpful to reduce oil viscosity and lower interfacial tension, etc. Studies indicate that heat-generating CO2 flooding technology can get a maximum viscosity reduction rate of 76.7%, oil-water interfacial tension decreased by 54.77%, further improve oil recovery by 4.17% based on the steam drive, which shows a technical advantage toward conventional EOR method. The field experiments indicate that the technique can greatly improve the oil production, which will provide a powerful technical supporting for the efficient development of heavy oil.

Indoor Study of Viscosity Reducer for Thickened Oil of Huancai

2012 ◽  
Vol 268-270 ◽  
pp. 547-550
Author(s):  
Qing Wang Liu ◽  
Xin Wang ◽  
Zhen Zhong Fan ◽  
Jiao Wang ◽  
Rui Gao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
High Viscosity ◽  
Oil Field ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Low Viscosity ◽  
Viscosity Reducer ◽  
Oil Water

Liaohe oil field block 58 for Huancai, the efficiency of production of thickened oil is low, and the efficiency of displacement is worse, likely to cause other issues. Researching and developing an type of Heavy Oil Viscosity Reducer for exploiting. The high viscosity of W/O emulsion changed into low viscosity O/W emulsion to facilitate recovery, enhanced oil recovery. Through the experiment determine the viscosity properties of Heavy Oil Viscosity Reducer. The oil/water interfacial tension is lower than 0.0031mN•m-1, salt-resisting is good. The efficiency of viscosity reduction is higher than 90%, and also good at 180°C.

scholarly journals Enhancement of Heavy Oil Recovery by Nanoparticle/Microwave Application

2019 ◽  
pp. 51 ◽  
Author(s):  
P. Pourafshary ◽  
H. Al Farsi
Keyword(s):  
Porous Media ◽  
Microwave Radiation ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Thermal Recovery ◽  
Viscosity Reduction ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Steam Flooding ◽  
Recovery Methods

The primary heavy oil recovery is low due to the high viscosity and low mobility; hence, conventional thermal enhanced oil recovery methods such as steam flooding are widely applied to increase the oil production. New unconventional method such as microwave assisted gravity drainage (MWAGD) is under study the change the viscosity of the oil by microwave radiation. Different challenges such as heat loss and low efficiency are faced in unconventional thermal recovery methods especially in deep reservoirs. To improve the performance of unconventional methods, nanotechnology can play an important role. Nanomaterials due to their high surface to volume ratio, more heat absorbance, and more conductivity can be used in a novel approach called nanomaterial/microwave thermal oil recovery. In this work, several nanofluids prepared from nanoparticles such as γ-Alumina (γ-Al2O3), Titanium (IV) oxide (TiO2), MgO, and Fe3O4 were used to enhance the oil viscosity reduction in the porous media under MWAGD mechanism. Our tests showed that adding nanoparticles can increase the absorption of microwave radiation in the oil/ water system in the porous media. The magnitude of this increase is related to the type, particle size distribution in base fluid and, concentration of nanoparticles. Aluminum oxide nanoparticle was found to have the greatest effect on thermal properties of water. For example, only 0.05 wt.% of this nanoparticle, improves the alteration in temperature of water for around 100%. This change can affect the oil recovery and changed it from 37% to more than 40% under MWAGD. Hence, our experiments showed that besides other applications of nanotechnology in enhance oil recovery, heavy oil recovery can also be affected by nanomaterials.

The Experimental Analysis of the Role of Flue Gas Injection for Horizontal Well Steam Flooding

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Zhanxi Pang ◽  
Peng Qi ◽  
Fengyi Zhang ◽  
Taotao Ge ◽  
Huiqing Liu
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Three Dimensional ◽  
Steam Injection ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Steam Flooding ◽  
Heavy Oil Reservoirs

Heavy oil is an important hydrocarbon resource that plays a great role in petroleum supply for the world. Co-injection of steam and flue gas can be used to develop deep heavy oil reservoirs. In this paper, a series of gas dissolution experiments were implemented to analyze the properties variation of heavy oil. Then, sand-pack flooding experiments were carried out to optimize injection temperature and injection volume of this mixture. Finally, three-dimensional (3D) flooding experiments were completed to analyze the sweep efficiency and the oil recovery factor of flue gas + steam flooding. The role in enhanced oil recovery (EOR) mechanisms was summarized according to the experimental results. The results show that the dissolution of flue gas in heavy oil can largely reduce oil viscosity and its displacement efficiency is obviously higher than conventional steam injection. Flue gas gradually gathers at the top to displace remaining oil and to decrease heat loss of the reservoir top. The ultimate recovery is 49.49% that is 7.95% higher than steam flooding.

scholarly journals Study on Autogenous Heat Technology of Offshore Oilfield: Experiment Research, Process Design, and Application

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Yanping Sun ◽  
Chengsheng Wang ◽  
Jun Sun ◽  
Shuliang Ren ◽  
Hua Peng ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Reduction Rate ◽  
Oil Production ◽  
Gas Production ◽  
Viscosity Reduction ◽  
Heavy Oil Recovery ◽  
Heat System ◽  
Heat Technology ◽  
Reservoir Permeability

Conventional heavy oil has abundant reserves and low recovery efficiency in offshore oilfields. Autogenous heat technology uses 2-3 kinds of inorganic salt solution to produce inert gas and release a lot of heat under the action of a catalyst. It is applied to improve heavy oil recovery of the offshore oilfield. This paper applies experimental schemes such as viscosity reduction rate evaluation, heat conditions, gas production conditions, reaction rate control, and effect of environmental factors. This paper evaluates the performance of the autogenous heat system, optimizes the process parameters, and designs the process scheme and construction scheme according to the oil well production. This paper researches an autogenous heat system with nontoxic and high heat production and optimizes the catalyst type, concentration, and time to reach exothermic peak. When the concentration of the thermogenic agent is 1.5 mol/L in the autogenous heat system, the range of temperature rise is 67°C, which achieves the target requirement of more than 50°C. Field application shows that the autogenous heat system can effectively reduce the viscosity of heavy oil, dissolve solid paraffin, clean organic scale, improve reservoir permeability, and increase heavy oil production. This paper applies autogenous heat technology to improving the efficiency of heavy oil recovery of the offshore oilfield. Research conclusions show that the autogenous heat system can effectively reduce the viscosity of heavy oil, improve reservoir permeability, and increase heavy oil production.

scholarly journals In-Situ Heavy Oil Aquathermolysis in the Presence of Nanodispersed Catalysts Based on Transition Metals

Processes ◽  
2021 ◽  
Vol 9 (1) ◽  
pp. 127
Author(s):  
Firdavs A. Aliev ◽  
Irek I. Mukhamatdinov ◽  
Sergey A. Sitnov ◽  
Mayya R. Ziganshina ◽  
Yaroslav V. Onishchenko ◽  
...  
Keyword(s):  
Metal Ions ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Synergetic Effect ◽  
Field Tests ◽  
Water Soluble ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Catalytic Aquathermolysis

The aquathermolysis process is widely considered to be one of the most promising approaches of in-situ upgrading of heavy oil. It is well known that introduction of metal ions speeds up the aquathermolysis reactions. There are several types of catalysts such as dispersed (heterogeneous), water-soluble and oil soluble catalysts, among which oil-soluble catalysts are attracting considerable interest in terms of efficiency and industrial scale implementation. However, the rock minerals of reservoir rocks behave like catalysts; their influence is small in contrast to the introduced metal ions. It is believed that catalytic the aquathermolysis process initiates with the destruction of C-S bonds, which are very heat-sensitive and behave like a trigger for the following reactions such as ring opening, hydrogenation, reforming, water–gas shift and desulfurization reactions. Hence, the asphaltenes are hydrocracked and the viscosity of heavy oil is reduced significantly. Application of different hydrogen donors in combination with catalysts (catalytic complexes) provides a synergetic effect on viscosity reduction. The use of catalytic complexes in pilot and field tests showed the heavy oil viscosity reduction, increase in the content of light hydrocarbons and decrease in heavy fractions, as well as sulfur content. Hence, the catalytic aquathermolysis process as a distinct process can be applied as a successful method to enhance oil recovery. The objective of this study is to review all previously published lab scale and pilot experimental data, various reaction schemes and field observations on the in-situ catalytic aquathermolysis process.

A Novel Hybrid Solvent-Based Complex Fluid for Enhanced Heavy Oil Recovery

2021 ◽  
Author(s):  
Ali Telmadarreie ◽  
Christopher Johnsen ◽  
Steven L. Bryant
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Apparent Viscosity ◽  
Viscosity Reduction ◽  
Heavy Oil Recovery ◽  
Green Solvent ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Complex Fluid

Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).

scholarly journals The Supercritical Multithermal Fluid Flooding Investigation: Experiments and Numerical Simulation for Deep Offshore Heavy Oil Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Xianhong Tan ◽  
Wei Zheng ◽  
Taichao Wang ◽  
Guojin Zhu ◽  
Xiaofei Sun ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Numerical Model ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Steam Flooding ◽  
Heavy Oil Reservoirs

The supercritical multithermal fluids (SCMTF) were developed for deep offshore heavy oil reservoirs. However, its EOR mechanisms are still unclear, and its numerical simulation method is deficient. In this study, a series of sandpack flooding experiments were first performed to investigate the viability of SCMTF flooding. Then, a novel numerical model for SCMTF flooding was developed based on the experimental results to characterize the flooding processes and to study the effects of injection parameters on oil recovery on a lab scale. Finally, the performance of SCMTF flooding in a practical deep offshore oil field was evaluated through simulation. The experiment results show that the SCMTF flooding gave the highest oil recovery of 80.89%, which was 29.60% higher than that of the steam flooding and 11.09% higher than that of SCW flooding. The history matching process illustrated that the average errors of 3.24% in oil recovery and of 4.33% in pressure difference confirm that the developed numerical model can precisely simulate the dynamic of SCMTF flooding. Increases in temperature, pressure, and the mole ratio of scN2 and scCO2 mixture to SCW benefit the heavy oil production. However, too much increase in temperature resulted in formation damage. In addition, an excess of scN2 and scCO2 contributed to an early SCMTF breakthrough. The field-scale simulation indicated that compared to steam flooding, the SCMTF flooding increased cumulative oil production by 27122 m3 due to higher reservoir temperature, expanded heating area, and lower oil viscosity, suggesting that the SCMTF flooding is feasible in enhancing offshore heavy oil recovery.

scholarly journals The Effect of Carbonyl and Hydroxyl Compounds on Swelling Factor, Interfacial Tension, and Viscosity in CO2 Injection: A Case Study on Aromatic Oils

Processes ◽  
2021 ◽  
Vol 9 (1) ◽  
pp. 94
Author(s):  
Asep Kurnia Permadi ◽  
Egi Adrian Pratama ◽  
Andri Luthfi Lukman Hakim ◽  
Doddy Abdassah
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Viscosity Reduction ◽  
Co2 Injection ◽  
Minimum Miscibility Pressure ◽  
Lower Viscosity ◽  
Hydroxyl Compounds ◽  
Swelling Factor

A factor influencing the effectiveness of CO2 injection is miscibility. Besides the miscible injection, CO2 may also contribute to oil recovery improvement by immiscible injection through modifying several properties such as oil swelling, viscosity reduction, and the lowering of interfacial tension (IFT). Moreover, CO2 immiscible injection performance is also expected to be improved by adding some solvent. However, there are a lack of studies identifying the roles of solvent in assisting CO2 injection through observing those properties simultaneously. This paper explains the effects of CO2–carbonyl and CO2–hydroxyl compounds mixture injection on those properties, and also the minimum miscibility pressure (MMP) experimentally by using VIPS (refers to viscosity, interfacial tension, pressure–volume, and swelling) apparatus, which has a capability of measuring those properties simultaneously within a closed system. Higher swelling factor, lower viscosity, IFT and MMP are observed from a CO2–propanone/acetone mixture injection. The role of propanone and ethanol is more significant in Sample A1, which has higher molecular weight (MW) of C7+ and lower composition of C1–C4, than that in the other Sample A9. The solvents accelerate the ways in which CO2 dissolves and extracts oil, especially the extraction of the heavier component left in the swelling cell.

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