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.

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.

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.

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.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

A New High-Temperature Gel for Profile Control in Heavy Oil Reservoirs

2015 ◽  
Vol 138 (2) ◽  
Author(s):  
Changjiu Wang ◽  
Huiqing Liu ◽  
Qiang Zheng ◽  
Yongge Liu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Three Dimensional ◽  
Heat Stability ◽  
Steam Injection ◽  
Oil Reservoirs ◽  
Steam Flooding ◽  
Profile Control ◽  
Heavy Oil Reservoirs

Controlling the phenomenon of steam channeling is a major challenge in enhancing oil recovery of heavy oil reservoirs developed by steam injection, and the profile control with gel is an effective method to solve this problem. The use of conventional gel in water flooding reservoirs also has poor heat stability, so this paper proposes a new high-temperature gel (HTG) plugging agent on the basis of a laboratory experimental investigation. The HTG is prepared with nonionic filler and unsaturated amide monomer (AM) by graft polymerization and crosslinking, and the optimal gel formula, which has strong gelling strength and controllable gelation time, is obtained by the optimization of the concentration of main agent, AM/FT ratio, crosslinker, and initiator. To test the adaptability of the new HTG to heavy oil reservoirs and the performance of plugging steam channeling path and enhancing oil recovery, performance evaluation experiments and three-dimensional steam flooding and gel profile control experiments are conducted. The performance evaluation experiments indicate that the HTG has strong salt resistance and heat stability and still maintains strong gelling strength after 72 hrs at 200 °C. The singular sand-pack flooding experiments suggest that the HTG has good injectability, which can ensure the on-site construction safety. Moreover, the HTG has a high plugging pressure and washing out resistance to the high-temperature steam after gel forming and keeps the plugging ratio above 99.8% when the following steam injected volume reaches 10 PV after gel breakthrough. The three-dimensional steam flooding and gel profile control experiments results show that the HTG has good plugging performance in the steam channeling path and effectively controls its expanding. This forces the following steam, which is the steam injected after the gelling of HTG in the model, to flow through the steam unswept area, which improves the steam injection profile. During the gel profile control period, the cumulative oil production increases by 294.4 ml and the oil recovery is enhanced by 8.4%. Thus, this new HTG has a good effect in improving the steam injection profile and enhancing oil recovery and can be used to control the steam channeling in heavy oil reservoirs.

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.

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.

Challenging Water Channeling in Unconsolidated Heavy Oil Reservoirs: Risks and Management

2021 ◽  
Author(s):  
Anton Gudz ◽  
Ilnur Ilyasov ◽  
Alexander Podkorytov ◽  
Maksim Tomashevskiy ◽  
Nikolai Glushchenko
Keyword(s):  
Risk Management ◽  
Heavy Oil ◽  
Methodological Approach ◽  
Oil Field ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Reservoir Development ◽  
Heavy Oil Reservoirs ◽  
First Results ◽  
Basic Features

Abstract The paper describes the basic features of the East-Messoyahskoe oil field that are important for efficient reservoir development, the key of which are high oil viscosity (111 cP), high heterogenieity and permeability contrast, and the presence of aquifer with a different strength. The review of the experience in proactive breakthrough risks identification is presented. The actual breakthroughs during waterflooding of the PK-13 reservoir of the East-Messoyahskoe oil field are described and analyzed. The backgrounds and regularities increasing the risks of breakthroughs are identified. The analytical calculations have been made and key influencing factors have been defined. Based on the obtained results, the methodology of the proactive breakthrough identification was developed. The methodology has been tested in the real conditions of the East-Messoyahskoe oil field. The first results have been received, which confirm the operational efficiency of the developed methodological approach. All wells were rated according to their breakthrough risk, and measures for operative and proactive breakthroughs risk management has been proposed. All listed are combined into a system which permits minimization of breakthrough risks and manages them for the increase of unconsolidated heavy oil reservoirs development efficiency.

scholarly journals Status Quo of a CO2-Assisted Steam-Flooding Pilot Test in China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Zongyao Qi ◽  
Tong Liu ◽  
Changfeng Xi ◽  
Yunjun Zhang ◽  
Dehuang Shen ◽  
...  
Keyword(s):  
Field Test ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Drainage Pattern ◽  
Steam Flooding ◽  
Production Wells ◽  
Water Cut ◽  
Production Dynamics

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to reduced residual oil saturation, high steam-oil ratio, and lower profitability. A field test of the CO2-assisted steam flooding technique was carried out in the steam-flooded heavy oil reservoir in the J6 block of the Xinjiang oil field (China). In the field test, a positive response to the CO2-assisted steam flooding treatment was observed, including a gradually increasing heavy oil production, an increase in the formation pressure, and a decrease in the water cut. The production wells in the test area mainly exhibited four types of production dynamics, and some of the production wells exhibited production dynamics that were completely different from those during steam flooding. After being flooded via CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence, they yielded stable oil production. In addition, emulsified oil and CO2 foam were produced from the production well, which agreed well with the results of laboratory-scale tests. The reservoir-simulation-based prediction for the test reservoir shows that the CO2-assisted steam flooding technique can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and can yield a final recovery factor of 70%.

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