Academic literature on the topic 'CO2-assisted gravity drainage'
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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.
Full textDissertations / Theses on the topic "CO2-assisted gravity drainage"
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Jadhawar, Prashant Sopanrao. "Co₂-assisted gravity drainage EOR: numerical simulation and scaling models study." Thesis, 2010. http://hdl.handle.net/2440/74663.
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Increasing demand of the oil and gas have given rise to surge in drilling and exploration activities to recover oil from other unexplored oil-bearing formations (such as offshore) as well as in the efforts to improve and/or modify the existing methods of the enhanced oil recovery to recover the residual oil left-behind by the applied EOR method. Nearly one-third volume of the original oil in place (OOIP) is left-behind by the current EOR technologies. Estimated 2 trillion barrels of this volume is lucrative to cater the energy needs of the respective countries. Gas injection EOR method is a major contending process in exploitation of this resource, and its application is on the rise since last decade. Continuous gas injection (CGI) and water-alternating gas (WAG) injection are the most notable and commonly field-implemented horizontal displacement type gas injection EOR processes. The limitations of CGI are the severe gravity segregation and poor sweep efficiencies. Although the reservoir sweep efficiencies are improved with the WAG, review of 59 field projects suggest that they yield only maximum of 10% incremental oil recoveries due to the detrimental effects of increased water saturation to diminish gas injectivity, reducing oil mobility, decreased oil relative permeability and oil bypassing due to gravity segregation. Conversely, vertical downward oil-displacement gas driven gravity drainage EOR methods uses the gravity forces to its advantage for enhancing the oil recovery. Gravity drainage EOR methods have been applied to dipping and reef type reservoirs in the field projects and reported to yield high incremental oil recoveries. In this study, the CO₂-assisted gravity drainage EOR method is investigated in the non-dipping reservoir through the 3D reservoir simulations and scaling and the sensitivity analysis. Both the compositional and pseudomiscible black-oil numerical reservoir simulations are conducted in the 50 and 35 °API gravity oil-reservoirs respectively. Main objectives of this research are to (i) develop a better production strategy for the oil recovery optimization (ii) investigate the options to optimize oil recovery in the CO₂-assisted gravity drainage EOR process (numerical simulation studies) (iii) to develop a set of scaled models sufficient to completely scale the CO₂-assisted gravity drainage EOR process through the scaling and sensitivity studies. Original contributions of this research are (i) First comprehensive demonstration of the CO₂-assisted gravity drainage EOR method application in 50 °API gravity oil-reservoir, (ii) Development and verification of a new hypothesis of the horizontal gas floodfront in the top-down CO₂-assisted gravity drainage EOR process, (iii) Development of a general process selection map for the preliminary choice between the immiscible and miscible process, (iv) Grid size effect studies: Changes in both the x and y grid-dimensions has no impact on the CO₂-assisted gravity drainage oil recovery, (v) Grid thickness effect studies: Thin layers, even in the upper layers, facilitates the optimum CO₂-assisted gravity drainage oil recovery (vi) Heterogeneity in permeability effect: Presence of heterogeneity in permeability (kv / kv = 0.001) improves the CO₂-assisted gravity drainage oil recovery performance (95.5% incremental oil recovery) thereby reducing the number of pore volumes and the operational time. It has been found that recovery further improves when the molecular diffusion effects are taken into account, (vii) Heterogeneity in porosity: Porosity values increasing downwards, such as in the overturned faults, promotes the CO₂-assisted gravity drainage mechanism to yield better oil recovery performance, (viii) Clear identification of the overall mechanisms and the supporting micro-mechanisms through the parametric analysis of the reservoir simulation results, (ix) Development of a new correlation (combination number, NJadhawar and Sarma) that encompasses the traditional process affecting multiphase operational parameters in the form of the dimensionless groups. It is further validated using the field projects including the data from the Oseberg field, Norway. Excellent logarithmic correlation match is obtained between the new combination
number, NJadhawar and Sarma, and the oil recoveries from both the immiscible and miscible reservoir simulations as well as the field projects. New combination number, NJadhawar and Sarma, is a useful tool to predict CO₂-assisted gravity drainage oil recoveries, and (x) Development of a set of the additional scaled models sufficient to completely scale the CO₂-assisted gravity drainage EOR process are proposed and validated.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2010
Books on the topic "CO2-assisted gravity drainage"
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Green, Don W., and G. Paul Willhite. Enhanced Oil Recovery. Society of Petroleum EngineersRichardson, Texas, USA, 2018. http://dx.doi.org/10.2118/9781613994948.
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Building on the comprehensive, fundamental mechanisms and mathematical computations detailed in the First Edition, the new Second Edition of Enhanced Oil Recovery presents the latest insights into the applications of EOR processes, including-Field-scale thermal-recovery such as steam-assisted gravity drainage and cyclic steam stimulation-Field-scale polymer flooding including horizontal wells-Field-scale miscible-displacement processes such as CO2 miscible flooding-Laboratory-scale chemical flooding in the development and testing of surfactant formulations An invaluable tool for petroleum engineering students, Enhanced Oil Recovery also serves as an important resource for those practicing oil recovery in the field or engaged in the design and operation of commercial projects involving enhanced-or improved-oil-recovery processes. A prior understanding of basic petrophysics, fluid properties, and material balance is recommended.
Conference papers on the topic "CO2-assisted gravity drainage"
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Jadhawar, Prashant Sopanrao, and Hemanta Kumar Sarma. "Improved Production Strategy for Enhancing the Immiscible and Miscible CO2-Assisted Gravity Drainage Oil Recovery." In International Oil and Gas Conference and Exhibition in China. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/130593-ms.
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Al-Mudhafar, W. J., D. N. Rao, and S. M. Hosseini Nasab. "Optimization of Cyclic CO2 Flooding through the Gas Assisted Gravity Drainage Process under Geological Uncertainties." In ECMOR XV - 15th European Conference on the Mathematics of Oil Recovery. Netherlands: EAGE Publications BV, 2016. http://dx.doi.org/10.3997/2214-4609.201601830.
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Al-Mudhafar, Watheq J., and Dandina N. Rao. "Effect of Gas Injection Pressure on the Performance of CO2-Assisted Gravity Drainage Process in Heterogeneous Clastic Reservoirs." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/192023-ms.
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Al-Mudhafar, Watheq J., and Dandina N. Rao. "Integrating Designed Simulations for Bayesian Identification of Geological Controls on the Performance of a Multilayer Heterogeneous Sandstone Oil Reservoir: Applied on the CO2-Assisted Gravity Drainage Process." In SPE Western Regional Meeting. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/190109-ms.
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Gupta, Subodh. "Physics-Based 3-Phase Relative Permeability for Gas-Liquid Counter-Current Flow." In SPE Annual Technical Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/210445-ms.
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Abstract The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase relative permeability model to describe flow more accurately in countercurrent movement of gas and liquids situation. While most flooding operations have both gas and liquids flowing in the same direction, in gravity dominated processes such as steam assisted gravity drainage (SAGD) or CO2 storage in water saturated reservoirs, often due to density difference the gases rise above and liquids flow down. This gives rise to a counter-current flow situation. It has been documented by a few researchers including Adebayo et al. (2017) and Prats et al. (2008). At the gas-liquid interface, the shear forces act to oppose movement of gas and liquids resulting in a slowdown in the flow of both. This slow-down or reduced flow is not captured in standard relative permeability curves which are typically generated using co-current flows. In the current work, the approach adopted by Gupta (2021) for a mechanistic 3-phase flow model is used to develop relative permeability expressions for gravity-incorporated flow. To do this, three-phase core-annular laminar flow expressions are first developed in a single thin tube, then these flow expressions are aggregated for the entire pore volume represented by a bundle of tubes with varying tube sizes mimicking pore-size distribution. An irreducible water saturation, when water is the wetting phase, is also assumed. The relative permeabilities obtained with counter-current flow considerations are compared with the ones presented in Gupta (2021) for co-current flow to highlight the difference. Additionally, the impact of these modified rel. perms is shown with an example SAGD problem resulting in a slower and more realistic growth of the steam chamber. Similar to the observation of Gupta (2021) this mechanistic model also indicates a natural dependence of rel. perms of the intermediate phase on temperature, which in literature has been a subject of much debate. The novelty of the work is in development of a three-phase relative permeability model which takes into account gas-liquid countercurrent movement in porous media based on fundamentals of flow in fine capillaries. The significance of the work includes, aside from predicting results more in line with expectations in gravity-dominated processes, an explanation of temperature dependent relative Gupermeabilities of the intermediate phases. Also, unlike Stone-II method, it predicts a more realistic time dependent residual oleic-phase saturation for gravity drainage recovery methods.
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Al-Mashrafi, Abdulsallam, Mahmood Fani, Faisal Asfand, Mahmood Amani, Mohsen Assadi, and Nader Mosavat. "Downhole Steam Generation for Green Heavy Oil Recovery." In Abu Dhabi International Petroleum Exhibition & Conference. SPE, 2021. http://dx.doi.org/10.2118/207597-ms.
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Abstract The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location. Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased. In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method. The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.
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Finan, Ashley, and Andrew C. Kadak. "Integration of Nuclear Energy Into Oil Sands Projects." In Fourth International Topical Meeting on High Temperature Reactor Technology. ASMEDC, 2008. http://dx.doi.org/10.1115/htr2008-58239.
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Energy security and greenhouse gas reductions are thought to be two of the most urgent priorities for sustaining and improving the human condition in the future. Few places pit the two goals so directly in opposition to one another as the Alberta oil sands. Here, Canadian natural gas is burned in massive quantities to extract oil from one of North America’s largest native sources of carbon-intensive heavy oil. This conflict need not continue, however; non-emitting nuclear energy can replace natural gas as a fuel source in an economical and more environmentally sound way. This would allow for the continued extraction of transportation fuels without greenhouse gas emissions, while freeing up the natural gas supply for hydrogen feedstock and other valuable applications. Bitumen production in Alberta has expanded dramatically in the past five years as the price of oil has risen to record levels. This paper explores the feasibility and economics of using nuclear energy to power future oil sands production and upgrading activities, and puts forth several nuclear energy application scenarios for providing steam and electricity to in-situ and surface mining operations. This review includes the Enhanced CANDU 6, the Advanced CANDU Reactor (ACR) and the Pebble Bed Modular Reactor (PBMR). Based on reasonable projections of available cost information, nuclear energy used for steam production is expected to be less expensive than steam produced by natural gas at current natural gas prices and under $7/MMBtu (CAD). For electricity production, nuclear becomes competitive with natural gas plants at natural gas prices of $10–13/MMBtu (CAD). Costs of constructing nuclear plants in Alberta are affected by higher local labor costs, which this paper took into account in making these estimates. Although more definitive analysis of construction costs and project economics will be required to confirm these findings, there appears to be sufficient merit in the potential economics to support further study. A single 500MWth PBMR reactor is able to supply high-pressure steam for a 40,000 to 60,000 bpd Steam Assisted Gravity Drainage (SAGD) plant, whereas the CANDU and ACR reactors are unable to produce sufficient steam pressures to be practical in that application. The CANDU, ACR and PBMR reactors have potential for supplying heat and electricity for surface mining operations. The primary environmental benefit of nuclear energy in this application is to reduce CO2 emissions by up to 3.1 million metric tons per year for each 100,000 barrel per day (bpd) bitumen production SAGD facility, or 2.0 million metric tons per year for the replacement of 700MWe of grid electricity with a nuclear power plant. Should carbon emissions be priced, the economic advantages of nuclear energy would be dramatically improved such that with a $50/ton CO2e at the releases expected for typical projects using natural gas, breakeven gas prices for nuclear drop to less than $3.50/MMBtu, well below the current natural gas price of $10/MMBtu for SADG steam production.