Journal articles on the topic 'CO2-assisted gravity drainage'
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Al-Obaidi, Dahlia A., and Mohammed S. Al-Jawad. "Immiscible CO2-Assisted Gravity Drainage Process for Enhancing Oil Recovery in Bottom Water Drive reservoir." Association of Arab Universities Journal of Engineering Sciences 27, no. 2 (June 30, 2020): 60–66. http://dx.doi.org/10.33261/jaaru.2020.27.2.007.
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The CO2-Assisted Gravity Drainage process (GAGD) has been introduced to become one of the mostinfluential process to enhance oil recovery (EOR) methods in both secondary and tertiary recovery through immiscibleand miscible mode. Its advantages came from the ability of this process to provide gravity-stable oil displacement forenhancing oil recovery. Vertical injectors for CO2 gas have been placed at the crest of the pay zone to form a gas capwhich drain the oil towards the horizontal producing oil wells located above the oil-water-contact. The advantage ofhorizontal well is to provide big drainage area and small pressure drawdown due to the long penetration. Manysimulation and physical models of CO2-AGD process have been implemented at reservoir and ambient conditions tostudy the effect of this method to improve oil recovery and to examine the most parameters that control the CO2-AGDprocess. The CO2-AGD process has been developed and tested to increase oil recovery in reservoirs with bottom waterdrive and strong water coning tendencies. In this study, a scaled prototype 3D simulation model with bottom waterdrive was used for CO2-assisted gravity drainage. The CO2-AGD process performance was studied. Also the effects ofbottom water drive on the performance of immiscible CO2 assisted gravity drainage (enhanced oil recovery and watercut) was investigated. Four different statements scenarios through CO2-AGD process were implemented. Resultsrevealed that: ultimate oil recovery factor increases considerably when implemented CO2-AGD process (from 13.5%to 84.3%). Recovery factor rises with increasing the activity of bottom water drive (from 77.5% to 84.3%). Also,GAGD process provides better reservoir pressure maintenance to keep water cut near 0% limit until gas flood frontreaches the production well if the aquifer is active, and stays near 0% limit at all prediction period for limited waterdrive.
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Wang, Huang, Xin Wei Liao, Meng Meng Li, Ning Lu, Yu Li Lv, and Chang Lin Liao. "Influencing Factor Study of CO2-Assisted Gravity Drainage in Extra-Low Permeability Reservoir." Advanced Materials Research 734-737 (August 2013): 1400–1405. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1400.
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CO2flooding is an important method of enhancing oil recovery (EOR) in extra-low permeability reservoir, which can resolve the problems of water flooding effectively. The EOR theory and influencing factors of CO2-assisted gravity drainage were studied in this paper. The influencing factors, such as reservoir dip, injection volume, injecting position, well placement and reservoir effective thickness were analyzed and optimized based on the theoretical numerical model which had been established according to Tuha Niuquanhu inclined reservoir parameters. This research indicates that CO2-assisted gravity drainage can effectively EOR if appropriate parameters were adopted. The results of this paper can offer suggestions to similar reservoir development.
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Han, Haishui, Xinglong Chen, Zemin Ji, Junshi Li, Weifeng Lv, Qun Zhang, Ming Gao, and Hao Kang. "Experimental Characterization of Oil/Gas Interface Self-Adjustment in CO2-Assisted Gravity Drainage for Reverse Rhythm Reservoir." Energies 15, no. 16 (August 12, 2022): 5860. http://dx.doi.org/10.3390/en15165860.
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Worldwide practices have proven that gas-assisted gravity drainage can obviously enhance oil recovery, and this technology can be especially effective for reservoirs with a thick formation and large inclination angle. For the successful implementation of this process, a key technology is the stable control of gas–oil interface during gas injection. For a detailed exploration of this technique, a three-stage permeable visual model was designed and manufactured, with permeability decreasing from top to bottom, thus, a reverse rhythm reservoir was effectively modeled. Then the experiment concerning CO2-assisted gravity drainage was carried out with the adoption of a self-developed micro visual displacement device. This study mainly focused on the micro migration law of gas–oil interface and the development effects of CO2-assisted gravity drainage. According to the experiments, CO2 fingering somewhat happens in the same permeable layer from the beginning of gas injection. However, phenomena of “wait” and “gas–oil interface self-adjustment” occur instead of flowing into the next layer when the injected CO2 reaches the boundary of the next lower permeability layer through the dominant channel. By the “gas–oil interface self-adjustment”, the injected CO2 first enters into the pores of the relative higher permeability layer to the greatest extent, and thus expands the sweep volume. Futhermore, in the process of CO2 injection, obvious gas channeling occurs in the low permeability layer directly connected to the outlet, resulting in low sweep efficiency and poor development effect. After connecting the core with lower permeability at the outlet, the development indexes of the model, such as the producing degree of the low permeability layer, the oil recovery before and after gas breakthrough, are significantly improved, and the recovery degrees of the medium permeability layer and the high permeability layer are also improved, and the overall recovery factor is increased by 12.38%. This “gas–oil interface self-adjustment” phenomenon is explained reasonably from the two scales of macroscopic flow resistance and microscopic capillary force. Finally, the enlightenments of the new phenomenon are expounded on the application of gas-assisted gravity drainage on site and the treatment of producers with gas breakthrough in gas injection development.
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Massoudi, Mehrdad. "Mathematical Modeling of Fluid Flow and Heat Transfer in Petroleum Industries and Geothermal Applications 2020." Energies 14, no. 16 (August 19, 2021): 5104. http://dx.doi.org/10.3390/en14165104.
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In this Special Issue, all aspects of fluid flow and heat transfer in geothermal applications, including the ground heat exchanger, conduction, and convection in porous media, are considered. The emphasis here is on mathematical and computational aspects of fluid flow in conventional and unconventional reservoirs, geothermal engineering, fluid flow and heat transfer in drilling engineering, and enhanced oil recovery (hydraulic fracturing, steam-assisted gravity drainage (SAGD), CO2 injection, etc.) applications.
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Qi, Zongyao, Tong Liu, Changfeng Xi, Yunjun Zhang, Dehuang Shen, Hertaer Mu, Hong Dong, et al. "Status Quo of a CO2-Assisted Steam-Flooding Pilot Test in China." Geofluids 2021 (October 15, 2021): 1–13. http://dx.doi.org/10.1155/2021/9968497.
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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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Al-Mudhafar, Watheq J., Dandina N. Rao, and Sanjay Srinivasan. "Robust Optimization of Cyclic CO2 flooding through the Gas-Assisted Gravity Drainage process under geological uncertainties." Journal of Petroleum Science and Engineering 166 (July 2018): 490–509. http://dx.doi.org/10.1016/j.petrol.2018.03.044.
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Jadhawar, P. S., and H. K. Sarma. "Effect of well pattern and injection well type on the CO2-assisted gravity drainage enhanced oil recovery." Journal of Petroleum Science and Engineering 98-99 (November 2012): 83–94. http://dx.doi.org/10.1016/j.petrol.2012.09.004.
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Hu, Lanxiao, Huazhou Andy Li, Tayfun Babadagli, and Majid Ahmadloo. "A Semianalytical Model for Simulating Combined Electromagnetic Heating and Solvent-Assisted Gravity Drainage." SPE Journal 23, no. 04 (March 12, 2018): 1248–70. http://dx.doi.org/10.2118/189979-pa.
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Summary Solvent/thermal hybrid methods have been proposed recently to enhance heavy-oil recovery and to overcome the shortcomings that are encountered when either method is solely applied. One of the methods for this hybridization is to combine electromagnetic (EM) heating and solvent injection to facilitate heavy-oil production by gravity drainage. This approach has several advantages including reduced CO2 emissions, decreased water consumption, and appropriateness for water-hostile reservoirs. We are currently lacking any mathematical model for better understanding, designing, and optimizing this hybrid technique, which is partly attributed to this technique still being in its infancy. We propose a semianalytical model to predict the oil-flow rate resulting from the combined EM heating and solvent-assisted gravity drainage. The model first calculates the temperature distribution within the EM-excited zone caused by the radiation-dominated EM heating. Using different attenuation coefficients within and beyond the vapor chamber, the model can properly describe the corresponding temperature responses in these regions. Next, an average temperature of the chamber edge contributed by EM heating is used to estimate the temperature-dependent properties, such as vapor/liquid equilibrium ratios (K-values), heavy-oil/solvent-mixture viscosity, and solvent diffusivity. Subsequently, a 1D diffusion equation is used to calculate the solvent-concentration distribution ahead of the chamber edge. Eventually, the oil-flow rate is evaluated with the calculated temperature and solvent distributions ahead of the chamber edge. The proposed model is validated against the experimental results obtained in our previous study, and the predicted oil-flow rate agrees reasonably well with the experimental data. The proposed model can efficiently predict the oil-flow rate of this hybrid process. We conduct sensitivity analyses to examine the effect of major influential factors on the performance of this hybrid technique, including EM heating powers, solvent types, solvent-injection pressures, and initial reservoir temperatures. The modeling results demonstrate that a higher EM heating power, a heavier solvent, and a higher solvent-injection pressure could accelerate the oil-recovery rate, but tend to lower the net present value (NPV) and increase the energy consumption. In summary, the newly proposed model provides an efficient tool to understand, design, and optimize the combined technique of EM heating and solvent-assisted gravity drainage.
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Atia, Abdelmalek, and Kamal Mohammedi. "Lattice Boltzmann investigation of thermal effect on convective mixing at the edge of solvent chamber in CO2-VAPEX process." World Journal of Engineering 12, no. 4 (August 1, 2015): 353–62. http://dx.doi.org/10.1260/1708-5284.12.4.353.
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The high viscosity of heavy oil is a serious problem for the recovery efficiency of this resource by conventional methods. Since a few past years, the vapour extraction process (VAPEX) has emerged as a promising technology for the recovery of heavy oils and bitumen in reservoirs where thermal methods, such as steam-assisted gravity drainage cannot be applied. Recently, the use of CO2 as a solvent is believed to make the VAPEX process more economical and environmentally and technically attractive. Convective mixing at the edge of the solvent chamber enhances mass and heat transfer rates which increases oil mobility and production rate. The objective of this study is to analysis the influence of the main controlling parameters, such as buoyancy ratio and Prandtl number on the flow patterns and mass transfer mechanism, in order to understand the thermal effect on the dissolution of carbon dioxide through natural convection at the boundary layer of solvent chamber of CO2-VAPEX process. The numerical results obtained by lattice Boltzmann method show that the flow structure and the mass transfer mechanism are strongly depend on the buoyancy ratio and Prandtl number. So, the performances of CO2-VAPEX process are strongly influenced by thermal effect; and we found that it has negative consequences on this process.
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Al-Obaidi, Dahlia A., Watheq J. Al-Mudhafar, and Mohammed S. Al-Jawad. "Experimental evaluation of Carbon Dioxide-Assisted Gravity Drainage process (CO2-AGD) to improve oil recovery in reservoirs with strong water drive." Fuel 324 (September 2022): 124409. http://dx.doi.org/10.1016/j.fuel.2022.124409.
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Johnston, David H. "Introduction to this special section: Reservoir monitoring." Leading Edge 39, no. 7 (July 2020): 462–63. http://dx.doi.org/10.1190/tle39070462.1.
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The papers submitted to this special section demonstrate that the topic of reservoir monitoring is extremely diverse. This diversity is reflected in the wide range of geologic settings covered by these papers — deepwater unconsolidated clastics, more cemented sandstones in onshore fields, and carbonates. Diversity is seen in the range of production scenarios described by these papers — water sweep of oil and gas, thermal recovery using steam-assisted gravity drainage (SAGD), and enhanced recovery using CO2 injection. Moreover, the papers in this section cover much more than time-lapse 3D seismic. Although about half of the submitted papers use 4D surface seismic data to monitor reservoirs, the remainder cover a diversity of methods that include time-lapse vertical seismic profiles (VSPs), repeat well logging using distributed acoustic sensing (DAS), and muon tomography. Even the concept of the “reservoir” is expanded to include monitoring microseismicity that might result from production activity.
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Wang, Chao, Yongbin Wu, Chihui Luo, Youwei Jiang, Yunjun Zhang, Haoran Zheng, Qiang Wang, and Jipeng Zhang. "Experimental Study and Numerical Simulation of an Electrical Preheating for SAGD Wells in Heavy Oil Reservoirs." Energies 15, no. 17 (August 23, 2022): 6102. http://dx.doi.org/10.3390/en15176102.
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It is necessary to establish effective communication between two horizontal wells during the preheating period of steam-assisted gravity-drainage (SAGD). However, the preheating time is usually very long, which results in high steam consumption and CO2 emissions. There is little research on the effects of different wellbore fluids during the preheating period. The heat transfer and heating characteristics of different wellbore fluids–water, heat-conduction oil, and air–were explored by using physical experiments and numerical simulations. In this study, the results indicated that the heat-transfer performance of heat-conduction oil is the best. The numerical simulation’s results indicated that compared with the wellbore saturated with water, the heat-conduction oil reduced the viscosity of crude oil, and energy consumption was not obvious during the preheating stage. The super-heavy oil flowed into the wellbore due to the solubility of the heat-conduction oil and its own gravity. As a result, the super-heavy oil content in the wellbore gradually accumulated, increasing the risk of coking. Those experiments showed that the use of electrical heating provides good potential to improve SAGD efficiency during the preheating period, and water is the best injection fluid for wellbores during the electrical heating process.
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Al-Mudhafar, Watheq J., Dandina N. Rao, and Sanjay Srinivasan. "Reservoir sensitivity analysis for heterogeneity and anisotropy effects quantification through the cyclic CO2-Assisted Gravity Drainage EOR process – A case study from South Rumaila oil field." Fuel 221 (June 2018): 455–68. http://dx.doi.org/10.1016/j.fuel.2018.02.121.
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Chen, Zehua, Zulong Zhao, and Daoyong Yang. "Quantification of Phase Behavior for Solvent/Heavy-Oil/Water Systems at High Pressures and Elevated Temperatures with Dynamic Volume Analysis." SPE Journal 25, no. 06 (June 30, 2020): 2915–31. http://dx.doi.org/10.2118/201240-pa.
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Summary Accurate quantification of phase behavior of solvent/heavy-oil/bitumen/water systems at high pressures and elevated temperatures is of high significance for the design of vapor extraction, cyclic solvent injection, expanding-solvent steam-assisted gravity drainage (ES-SAGD), and hot-solvent injection processes. The relevant experimental data and theoretical analyses are still insufficient for achieving a reliable model. This is especially true when the system temperatures approach or exceed the critical temperatures of the solvents used (i.e., when the solvent density is large enough). This study provides new experimental measurements of the phase behavior of propane (C3H8)/carbon dioxide (CO2)/heavy-oil/water systems at pressures up to 20 MPa and temperatures up to 432.3 K. More specifically, four feeds of C3H8/CO2/heavy-oil/water systems are used to conduct constant composition expansion (CCE) tests, during which the heights of the entire fluid system (i.e., total volume) and each phase are recorded at each pressure and temperature, respectively. Theoretically, a dynamic volume analysis (DVA) of the measured data is proposed for the first time to quantify each phase, provided that the assumption for vapor phase is valid and that the vapor and oleic phase densities can be accurately calculated. By tuning the binary interaction parameter (BIP) for solvent/heavy-oil pairs (denoted as BIPS−HO) to match the total volume, the height of the vapor/oleic (V/L) interface can be matched as well. By using the tuned BIPS−HO, the total volume and height of the V/L interface of C3H8/CO2/heavy-oil/water systems can be accurately predicted, no matter whether the solvent solubility in water is low (i.e., C3H8) or high (i.e., CO2). This DVA can be used to determine/evaluate the solvent solubility, saturation pressure/phase boundary, and phase volume/density accurately in a large temperature and pressure range. The newly proposed DVA method is also used to reproduce the experimental measurements collected from the literature, including phase-volume fractions, solvent solubility, and saturation pressure. In addition, the DVA method can serve as a tool to check whether the experimental measurements are reliable or not.
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Ali, Babkir. "Integration of Impacts on Water, Air, Land, and Cost towards Sustainable Petroleum Oil Production in Alberta, Canada." Resources 9, no. 6 (May 28, 2020): 62. http://dx.doi.org/10.3390/resources9060062.
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This paper intends to develop quantitative indicators for comparative sustainability assessment of petroleum oil pathways in the province of Alberta, Canada. Eighteen pathways of oil production were developed in this study, and the sustainability indicators were assigned for each pathway to cover greenhouse gas (GHG) emissions, water demand, and land use in addition to the cost of supply. The developed sustainability indicators were aligned per functional unit and covered the full life cycle of petroleum oil production. The developed GHG emissions, cost of supply, and land use indicators are found in the range 17.50–226.20 kg of CO2 eq./bbl, 12.28–53.53 USD/bbl, and 0.06–0.178 m2/bbl, respectively. Four scenarios were comparatively conducted and assessed against the business-as-usual scenario within the period horizon 2009–2030. The cost-effective scenario was optimized with the objective function to minimize the cost of supply based on the constraints derived from the business-as-usual scenario. Sustainable scenarios were conducted with the lowest possible impacts on natural resources, GHG emissions, and the cost of supply accompanied by specific assumptions for petroleum oil production from different pathways in Alberta. The average annual savings on water demand and land area were found to be 67 and 30%, respectively, due to the shifting of upgrader feedstock from surface mining to the in-situ steam-assisted gravity drainage (SAGD) pathway. The corresponding increases due to this shifting in upgrader feedstock were found to be 40 and 3% in GHG emissions and cost of supply, respectively.
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Eghbali, Sara, and Hassan Dehghanpour. "An Experimental and Modeling Study of Carbon Dioxide/Bitumen and C4/Bitumen Phase Behavior at Elevated Temperatures Using Cold Lake Bitumen." SPE Journal 23, no. 06 (October 17, 2018): 1991–2014. http://dx.doi.org/10.2118/187259-pa.
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Summary The coinjection of carbon dioxide (CO2) or light hydrocarbons with steam in the steam-assisted-gravity-drainage (SAGD) process might enhance bitumen mobility and reduce the steam/oil ratio (SOR). Understanding and modeling the phase behavior of solvent/bitumen systems are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen/CO2 and bitumen/C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater Formation. Constant-composition-expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2/bitumen mixture, and C4/bitumen mixture. The Peng and Robinson (1978) equation of state (EOS) (PR-EOS) is calibrated using the measured data and is used for pressure/volume/temperature (PVT) modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 393.2 to 453.2 K. The potential of asphaltene precipitation for CO2/bitumen and C4/bitumen mixtures is also investigated using three screening criteria. According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than does CO2 at operating pressure of 3997.9 kPa and temperature between 393.2 and 453.2 K (393.2 K < T < 453.2 K). During the CCE tests, coexistence of three equilibrium phases is observed for the C4/bitumen system with high C4 concentration. The three phases consist of a heavy oleic phase (L1), gaseous phase (V), and a light (solvent-rich) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into the L2 phase and preserve the heavy components in the L1 phase. Also, the L2 phase becomes darker by increasing the pressure, suggesting the extraction of heavier hydrocarbon components at higher pressures. Similar tests on the CO2/bitumen system show only two effective phases over a similar temperature range. The two phases consist of a heavy oleic phase (L1) and a gaseous phase (V). Phase-equilibrium regions are predicted using the regressed EOS model in the compositional space for the solvent/bitumen system. EOS predictions indicate two types of two-phase regions in the composition space for the C4/bitumen system (i.e., L1/L2 when 393.2 K < T < 421.2 K and L1/V when 421.2 K < T < 453.2 K). However, only one type of two-phase region (i.e., L1/V) exists in a similar temperature range for a CO2/bitumen system. The EOS predictions show that 1.8 wt% CO2 can reduce bitumen viscosity by up to 1.4 times, and 16.3 wt% C4 can reduce bitumen viscosity by up to 20 times when 393.2 K < T < 453.2 K. Viscosity calculations indicate that oil dilution by CO2 and C4 dissolution is more effective at lower temperatures, especially for C4. This shows the potential of injecting hot hydrocarbon solvents for bitumen recovery. The results show that asphaltene might precipitate in a system of C4/bitumen with high C4 concentration.
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Manfre Jaimes, Diego, Ian D. Gates, and Matthew Clarke. "Reducing the Energy and Steam Consumption of SAGD Through Cyclic Solvent Co-Injection." Energies 12, no. 20 (October 12, 2019): 3860. http://dx.doi.org/10.3390/en12203860.
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The amount of oil that is contained in the Canadian oil sands represent the third largest oil accumulation in the world. Approximately half of the daily oil production from the oil sands comes from mining processes and the other half is produced mostly using steam assisted gravity drainage (SAGD). This method is effective at reducing the viscosity of the oil. However, the generation of steam requires a significant amount of energy. Thus, there is an ongoing effort to reduce the energy needed to produce oil from the oil sands. In this article the intermittent injection of a solvent, along with steam, is investigated as a means of reducing the amount of energy required to extract oil from the Canadian oil sands. A simulation-based study examined the effect of the type of solvent, the cycles’ duration, the solvent concentration and the number of cycles. The simulations covered a time span of 10 years during which several different solvents (methane, ethane, propane, butane, pentane, hexane, and CO2) were injected under varying injection schedules. The solvents that were investigated are compounds that are likely to be readily available at a heavy oil production site. The solvent injection periods ranged from six to 24 months in length. The results reveal that SAGD combined with intermittent injection of hexane resulted in the most significant improvement to the cumulative oil production and in the cumulative energy-oil ratio (cEOR). Compared to SAGD without solvent injection, the cumulative oil production was increased by 45% and the cEOR was reduced by 23%. It was also seen that the performance of the proposed process is highly dependent on the resulting physical properties of the solvent-bitumen mixture. Finally, a simplified economic analysis also identified SAGD with intermittent hexane injection as the scheme that resulted in the highest net present value. Compared to SAGD without solvent injection, the intermittent injection of hexane led to an 85% increase in the net present value.
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Zhao, Litong. "Steam Alternating Solvent Process." SPE Reservoir Evaluation & Engineering 10, no. 02 (April 1, 2007): 185–90. http://dx.doi.org/10.2118/86957-pa.
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Summary A new heavy-oil-recovery process, the steam alternating solvent (SAS) process, is proposed and studied using numerical simulation. The process is intended to combine the advantages of the steam-assisted gravity drainage (SAGD) and vapor-extraction (vapex) processes to minimize the energy input per unit oil recovered. The SAS process involves injecting steam and solvent alternately, and the basic well configurations are the same as those in the SAGD process. Field-scale simulations were conducted to assess the SAS process performance under typical Cold Lake, Alberta, reservoir conditions. These results suggested that the oil-production rate of an SAS process could be higher than that of a SAGD process, while the energy input was 18% less than that of a SAGD process. By varying the length of the steam- and solvent-injection periods in a cycle, a different set of steam/oil and solvent/oil ratios may be obtained because the temperature profiles and solvent-concentration distributions in the vapor chamber can be affected by the injection pattern. The process therefore can be optimized for a specific reservoir under certain economic conditions. Introduction There are large heavy-oil and bitumen deposits in many areas of the world. The resources are especially enormous in northern Alberta, Canada. However, the high viscosity of these oils, usually more than 10 000 mPa×s, hinders the recovery of these resources. To recover such petroleum resources, two types of methods exist for the reduction of oil viscosity. The first is to increase oil temperature. This can be achieved by injecting a hot fluid, such as steam, into the formation, or by in-situ combustion through injecting oxygen-containing gases. The second method is to dilute the viscous petroleum by lower-viscosity hydrocarbon solvent. This method involves injecting a hydrocarbon solvent, such as propane or butane, or a mixture of hydrocarbons into the oil reservoir. As the solvent dissolves into viscous oil, the viscosity of the mixture becomes much lower than the original viscosity of the heavy oil. The diluted oil then can be recovered. The combinations of the above viscosity reduction methods and the horizontal-well technology have been the focus of research for the past 20 years. Two processes, SAGD and vapex, have been developed for the recovery of heavy-oil and bitumen resources (Butler et al. 1981; Butler and Mokrys 1991; Frauenfeld and Lillico 1999). The first has been tested successfully in the field and is currently the process of choice for commercial in-situ recovery (Edmunds et al. 1994; Mukherjee et al. 1995), while the second is starting initial field testing (Butler and Yee 2000). The advantage of the SAGD process is its high recovery and high oil-production rate. However, the high production rate is associated with excessive energy consumption, CO2 generation, and expensive post-production water treatment. The vapex process has the advantage of lower energy consumption (and, therefore, less CO2 generation) and much lower water-treatment costs. The major drawback of the vapex process, however, is its expected relatively lower oil-production rate and the uncertainty on reservoir retention of solvent. In the past several years, modifications have been proposed to improve SAGD's energy efficiency, either through injection of noncondensable gas with steam for reducing heat loss (Jiang et al. 1998) or through injection of solvents and steam together for increasing production rate (Nasr and Isaacs 2001). The combination of solvent with steam also has been studied in the steamflooding process (Farouq Ali and Abad 1976; Venturini and Mamora 2003).
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Al-Obaidi, Dahlia Abdulhadi, and Mohammed Saleh Al-Jawad. "Numerical Simulation of Immiscible CO2-Assisted Gravity Drainage Process to Enhance Oil Recovery." Iraqi Journal of Science, August 28, 2020, 2004–16. http://dx.doi.org/10.24996/ijs.2020.61.8.17.
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The Gas Assisted Gravity Drainage (GAGD) process has become one of the most important processes to enhance oil recovery in both secondary and tertiary recovery stages and through immiscible and miscible modes. Its advantages came from the ability to provide gravity-stable oil displacement for improving oil recovery, when compared with conventional gas injection methods such as Continuous Gas Injection (CGI) and Water – Alternative Gas (WAG).
Vertical injectors for CO2 gas were placed at the top of the reservoir to form a gas cap which drives the oil towards the horizontal oil producing wells which are located above the oil-water-contact. The GAGD process was developed and tested in vertical wells to increase oil recovery in reservoirs with bottom water drive and strong water coning tendencies. Many physical and simulation models of GAGD performance were studied at ambient and reservoir conditions to investigate the effects of this method to enhance the recovery of oil and to examine the most effective parameters that control the GAGD process.
A prototype 2D simulation model based on the scaled physical model was built for CO2-assisted gravity drainage in different statement scenarios. The effects of gas injection rate, gas injection pressure and oil production rate on the performance of immiscible CO2-assisted gravity drainage-enhanced oil recovery were investigated. The results revealed that the ultimate oil recovery increases considerably with increasing oil production rates. Increasing gas injection rate improves the performance of the process while high pressure gas injection leads to less effective gravity mediated recovery.
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Beaton, Meagan L., Neda Mashhadi, Karlynne R. Dominato, Timothy J. Maguire, Kristopher D. Rupert, and Scott O. C. Mundle. "Monitoring CO2 injection and retention in steam-assisted gravity drainage (SAGD) operations." Journal of Petroleum Science and Engineering, September 2022, 111050. http://dx.doi.org/10.1016/j.petrol.2022.111050.
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Xiao, Pufu, Maolei Cui, Wei Zhang, Qichuan Hu, Shuxia Zhao, Rui Wang, and Yongqiang Tang. "Experimental and dimensional analysis of CO2-assisted gravity drainage in low permeability dip reservoirs of east China." Energy Sources, Part A: Recovery, Utilization, and Environmental Effects, June 1, 2020, 1–11. http://dx.doi.org/10.1080/15567036.2020.1763519.
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