Improvement of Displacement Efficiency in Heavy Oil Reservoirs with Enzyme

2021 ◽  
pp. 1-30
Author(s):  
Yu Shi ◽  
Yanan Ding ◽  
Qianghan Feng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Contact Time ◽  
Enzyme Concentration ◽  
Oil Reservoirs ◽  
Recovery Factor ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Enzyme Solution ◽  
Heavy Oil Reservoirs

Abstract In this study, a systematical technique has been developed to experimentally and numerically evaluate the displacement efficiency in heavy oil reservoirs with enzyme under different conditions. Firstly, dynamic interfacial tensions (IFTs) between enzyme solution and heavy oil are measured with a pendant-drop tensiometer, while effects of pressure, temperature, enzyme concentration, and contact time of enzyme and heavy oil on equilibrium IFT were systematically examined and analyzed. After waterflooding, enzyme flooding was carried out in sandpacks to evaluate its potential to enhance heavy oil recovery at high water-cut stage. Numerical simulation was then performed to identify the underlying mechanisms accounting for the enzyme flooding performance. Subsequently, a total of 18 scenarios were designed to simulate and examine effects of the injection modes and temperature on oil recovery. Except for pressure, temperature, enzyme concentration, and contact time are found to impose a great impact on the equilibrium IFTs, i.e., a high temperature, a high enzyme concentration, and a long contact time reduce the equilibrium IFTs. All three enzyme flooding tests with different enzyme concentrations show the superior recovery performance in comparison to that of pure waterflooding. In addition to the IFT reduction, modification of relative permeability curves is found to be the main reason responsible for further mobilizing the residual heavy oil. A large slug size of enzyme solution usually leads to a high recovery factor, although its incremental oil production is gradually decreased. Plus, temperature is found to have a great effect on the recovery factor of enzyme flooding likely owing to reduction of both oil viscosity and IFT.

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.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

An Investigation Into Propagation Behavior of the Steam Chamber During Expanding-Solvent SAGP (ES-SAGP)

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 413-430
Author(s):  
Zhanxi Pang ◽  
Lei Wang ◽  
Zhengbin Wu ◽  
Xue Wang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Heat Losses ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Steam Chamber ◽  
Heavy Oil Reservoirs

Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.

Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs

2006 ◽  
Vol 9 (02) ◽  
pp. 154-164 ◽  
Author(s):  
Mingzhe Dong ◽  
S.-S. Sam Huang ◽  
Keith Hutchence
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Oil Reservoirs ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Pressure Cycling ◽  
Oil Resources ◽  
Heavy Oil Reservoirs ◽  
Secondary Methods

Summary The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) scheme intended for application in some heavy-oil reservoirs after termination of either primary or waterflood production. The essence of the process is the restoration of the solution-gas-drive mechanism. The restoration is accomplished by reinjecting an appropriate amount of solution gas (mainly methane) and then repressuring the gas back into solution by injecting water until approximate original reservoir pressure is reached. This, aside from the replacement of produced oil by water, recreates the primary-production conditions. This novel recovery technique is being developed to target the considerable portion of heavy-oil resources located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil in place (IOIP). Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs. Sandpack-flood tests in 30.5-cm (length) × 5.0-cm (diameter) sandpacks were carried out for oils with a range of dead-oil viscosities from 1700 to 5400 mPa.s. The results showed that the pressure-cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the MPC process of cycle termination strategy, oil viscosity, and mobile-water saturation were investigated. Simulations were conducted to investigate the MPC process in three heavy-oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas-injection rate, and the presence of wormholes in reservoirs were studied. Introduction Heavy oil in thick-pay reservoirs (i.e., >10 m) is commonly produced with thermal-recovery methods. These methods (steam injection and its variants) are generally not suitable for thin reservoirs because of heat losses to overburden and underburden or bottomwater zones (Fairfield and White 1982; Dyer et al. 1994). The world's large untapped oil resource remaining after recovery by conventional technology offers potential for exploitation by a suitably developed tertiary-recovery technique. For example, Saskatchewan accounts for 62% of Canada's total heavy-oil resources (Bowers and Drummond 1997), including 1.7 billion m3 of proved reserves and 3.7 billion m3 of probable reserves (Saskatchewan Energy and Mines 1998). Of the province's proven initial heavy oil in place, 97% is contained in reservoirs where the pay zone is less than 10 m, and 55% in reservoirs with a pay zone less than 5 m thick (Huang et al. 1987; Srivastava et al. 1993). Primary and secondary methods combined recover, on average, only about 7% of the proven IOIP (Saskatchewan Energy and Mines 1998). The incentive is strong for the development of appropriate EOR techniques that will maximize the recovery potential of and profitability from these thin heavy-oil reservoirs. Extensive literature is available on CO2, flue gas, and produced-gas injection for heavy-oil recovery, including slug displacement, water alternating gas (WAG), and cyclic (huff ‘n’ puff) processes (Huang et al. 1987; Srivastava et al. 1993, 1994, 1999; Srivastava and Huang 1997; Ma and Youngren 1994; Issever et al. 1993; Olenick et al. 1992). A comparative study of the oil-recovery behavior for a 14.1°API heavy oil with different injection gases (CO2, flue gas, and produced gas) showed that CO2 was the best-suited gas for EOR of heavy oils (Srivastava et al. 1999). Cyclic CO2 injection for heavy-oil recovery was tested in the field, and field case histories indicated that oil production was enhanced (Olenick et al. 1992). However, natural CO2 sources are not available to most oil reservoirs. The cost of CO2 capture from flue gas and other sources may range from U.S. $25 to $70/ton (Padamsey and Railton 1993). Produced gas is available in large quantities at a much lower cost. With this consideration, produced gas can be an economically effective agent for heavy-oil recovery by the cyclic-injection process.

Microemulsion Formulations with Tunable Displacement Mechanisms for Heavy Oil Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2663-2677
Author(s):  
Elsayed Abdelfatah ◽  
Farihah Wahid-Pedro ◽  
Alexander Melnic ◽  
Celine Vandenberg ◽  
Aidan Luscombe ◽  
...  
Keyword(s):  
Intermolecular Interactions ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Recovery Factor ◽  
Sodium Dodecylbenzene Sulfonate ◽  
Acid Salt ◽  
Base Solution ◽  
Significant Difference ◽  
Heavy Oil Reservoirs

Summary Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir because of the significant difference in viscosity between water and heavy oil and, hence, the oil is trapped. Here, we propose a platform for designing ultralow interfacial tension (IFT) solutions for reducing the capillary pressure and mobilizing the heavy oil. In this study, we formulated mixtures of organic acids and bases. We tested three different formulations: an ionic liquid (IL) formulation in which the bulk acid [4-dodecylbenzene sulfonic acid (DBSA)] and base [tetra-N-butylammonium hydroxide (N4444OH)] were mixed using general protocols for IL synthesis; an acid/base solution (ABS) in which the acid (DBSA) and base (N4444OH) were mixed in low weight fractions directly in water; and an acid salt/base solution (ASBS) in which the acid salt [sodium dodecylbenzene sulfonate (SDBS)] was used instead of the acid. All the formulations have a 1:1 stoichiometric ratio of acid and base. Salinity scans were conducted to determine the optimum salinity that gives the lowest IFT for each formulation. Corefloods were conducted in hydrophilic and hydrophobic sandpacks to evaluate the three formulations at their optimum salinities for post-waterflood heavy oil recovery. The IL and ABS formulation are acidic solutions with a pH of approximately 3. The ASBS formulation is highly basic with a pH of approximately 12. None of the formulations salted out below 14 wt% of sodium chloride (NaCl), whereas the conventional surfactant, SDBS, precipitated at a salt concentration of less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBS and 3 wt% NaCl for IL and ABS. Although the IL and ABS have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (∼15,000 cp) and a fixed Darcy velocity of 12 ft/D. A slug of 1 pore volume (PV) of each formulation was injected after waterflooding for 5 PV followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and ABS formulation produced an oil bank consisting mainly of a water-in-oil (W/O) emulsion, with oil recovery that was 1.7 times what was recovered by 11 PV of waterflooding solely. The majority of the oil was recovered in the 2 PV of waterflood after the IL slug. ASBS formulations produced oil-in-water (O/W) emulsions with prolonged recovery over 5 PV waterflooding after the ASBS slug. The recovery factor for ASBS was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, the ASBS formulation slightly increased the recovery factor compared with only waterflooding, whereas for IL and ABS formulations, the recovery factor decreased. In this work, we present a novel platform for tuning the recovery factor and the timescale of the recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field applications.

THE VARIATION OF TEMPERATURE OF DIFFERENT OIL RESERVOIR DENSITIES EXPLOITED BY THERMAL METHODS

2020 ◽  
Author(s):  
Ionescu (Goidescu) Nicoleta Mihaela ◽  
Vasiliu Viorel Eugen ◽  
Onutu Ion
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Thermal Methods ◽  
Injection Process ◽  
Heavy Oil Reservoirs ◽  
The World ◽  
Recovery Methods

Enhanced oil recovery (E.O.R) is oil recovery by the injection of materials not normally present in the reservoir. Thermal methods such as steam injection process are the best heavy oil recovery methods. Improvement of mobility ratio in the reservoir and economic recovery from heavy oil reservoirs depend mainly on reduction of heavy oil viscosity. For a steam injection process should consider the heat and mass transfer. Heavy oil reservoirs contain a considerable amount of hydrocarbon resources of the world. Meanwhile further demand for oil resources in the world , reduction of natural production from oil reservoirs, and finally price of oil in recent years have attracted notices to production methods from heavy and extra heavy oil reservoirs. High viscosity and great amounts of asphaltene in these hydrocarbons make difficulties in extraction, transportation, and process of heavy oil. In Romania there have been numerous theoretical and laboratory researches, as well as site experiments on the application of secondary recovery methods,Romanian specialists having a wide experience in this field

Investigation of Well Production Mechanism in Heavy Oil Reservoirs Underlain by Strong Bottom Water

2016 ◽  
Author(s):  
Wenting Qin ◽  
Andrew K. Wojtanowicz ◽  
Pingya Luo
Keyword(s):  
Analytical Solution ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Bottom Water ◽  
Oil Reservoirs ◽  
Recovery Factor ◽  
Recovery Efficiency ◽  
Drainage Radius ◽  
Heavy Oil Reservoirs ◽  
Water Coning

Low recovery factor is identified as the main problem encountered in the heavy oil production from a strong bottom-water-drive reservoir. Unlike for conventional oils, where the expected recovery from such reservoirs could be very high — in excess of 50 percent, the expected recovery factor in heavy oil water-driven reservoirs is less than 20 percent. In this study, a qualitative analysis of the well productivity mechanisms specific for heavy oil reservoirs with bottom water is provided. The objective is to understand what make the production of heavy oil different to that of lighter oils, identify the mechanism that mostly hamper the well’s productivity and recovery efficiency. Many believe the by-passed oil due to water coning is the major cause of low ultimate oil recovery in heavy oils underlain by strong bottom water. However, in this paper, we identify another important parameter affecting recovery efficiency in such reservoirs, which hasn’t been recognized by others and its effect on recovery process is significant. The mathematic modeling and numerical study lead to a new finding: due to the aquifer’s influence on pressure response in reservoir, a no-flow boundary at xi is established, where xi is often much smaller than that of the actual reservoir size xe. The oil out to the distance xi is immobile and become bypassed oil, which accounts for large amount of the OOIP. Even the water coning can be effective controlled; the ultimate oil recovery factor will not be improved significantly if the small mobilized oil zone can’t be enlarged. An analytical solution is derived in this paper to calculate the actual drainage radius. The validity of this analytical solution is confirmed by numerical simulation runs.

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.

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