The preservation of the integrity of CO_(2) injection wells holds immense significance for the efficacy of Carbon Capture and Storage (CCS) projects.This is attributable to the fact that a wellbore exhibiting robust m...The preservation of the integrity of CO_(2) injection wells holds immense significance for the efficacy of Carbon Capture and Storage (CCS) projects.This is attributable to the fact that a wellbore exhibiting robust mechanical and flow integrity substantially diminishes the likelihood of CO_(2) leakage into the overlying aquifer or release to the atmosphere,thereby curtailing associated risks.Given the potential hazards and repercussions stemming from the failure of CO_(2) injection wells,encompassing environmental catastrophes,financial implications,and health risks,it is imperative to earnestly address these challenges through adept management and monitoring protocols.This study aims to advance the current understanding and enhance the management of wellbore integrity issues in CO_(2) injection wells.Accordingly,this review paper undertakes a thorough exploration of the primary factors influencing wellbore integrity in CO_(2) injection wells.Furthermore,it delineates a pressing necessity for more exhaustive investigations regarding the influence of CO_(2) injection rate,CO_(2) purity,and wellbore geometry on wellbore integrity.展开更多
Low-permeability reservoirs are generally characterized by low porosity and low permeability.Obtaining high production using the traditional method is technologically challenging because it yields a low reservoir reco...Low-permeability reservoirs are generally characterized by low porosity and low permeability.Obtaining high production using the traditional method is technologically challenging because it yields a low reservoir recovery factor.In recent years,hydraulic fracturing technology is widely applied for efficiently exploiting and developing low-permeability reservoirs using a low-viscosity fluid as a fracturing fluid.However,the transportation of the proppant is inefficient in the low-viscosity fluid,and the proppant has a low piling-up height in fracture channels.These key challenges restrict the fluid(natural gas or oil)flow in fracture channels and their functional flow areas,reducing the profits of hydrocarbon exploitation.This study aimed to explore and develop a novel dandelion-bionic proppant by modifying the surface of the proppant and the fiber.Its structure was similar to that of dandelion seeds,and it had high transport and stacking efficiency in low-viscosity liquids compared with the traditional proppant.Moreover,the transportation efficiency of this newly developed proppant was investigated experimentally using six different types of fracture models(tortuous fracture model,rough fracture model,narrow fracture model,complex fracture model,large-scale single fracture model,and small-scale single fracture model).Experimental results indicated that,compared with the traditional proppant,the transportation efficiency and the packing area of the dandelion-based bionic proppant significantly improved in tap water or low-viscosity fluid.Compared with the traditional proppant,the dandelionbased bionic proppant had 0.1-4 times longer transportation length,0.3-5 times higher piling-up height,and 2-10 times larger placement area.The newly developed proppant also had some other extraordinary features.The tortuosity of the fracture did not influence the transportation of the novel proppant.This proppant could easily enter the branch fracture and narrow fracture with a high packing area in rough surface fractures.Based on the aforementioned characteristics,this novel proppant technique could improve the proppant transportation efficiency in the low-viscosity fracturing fluid and increase the ability of the proppant to enter the secondary fracture.This study might provide a new solution for effectively exploiting low-permeability hydrocarbon reservoirs.展开更多
Subsurface geothermal energy storage has greater potential than other energy storage strategies in terms of capacity scale and time duration.Carbon dioxide(CO_(2))is regarded as a potential medium for energy storage d...Subsurface geothermal energy storage has greater potential than other energy storage strategies in terms of capacity scale and time duration.Carbon dioxide(CO_(2))is regarded as a potential medium for energy storage due to its superior thermal properties.Moreover,the use of CO_(2)plumes for geothermal energy storage mitigates the greenhouse effect by storing CO_(2)in geological bodies.In this work,an integrated framework is proposed for synergistic geothermal energy storage and CO_(2)sequestration and utilization.Within this framework,CO_(2)is first injected into geothermal layers for energy accumulation.The resultant high-energy CO_(2)is then introduced into a target oil reservoir for CO_(2)utilization and geothermal energy storage.As a result,CO_(2)is sequestrated in the geological oil reservoir body.The results show that,as high-energy CO_(2)is injected,the average temperature of the whole target reservoir is greatly increased.With the assistance of geothermal energy,the geological utilization efficiency of CO_(2)is higher,resulting in a 10.1%increase in oil displacement efficiency.According to a storage-potential assessment of the simulated CO_(2)site,110 years after the CO_(2)injection,the utilization efficiency of the geological body will be as high as 91.2%,and the final injection quantity of the CO_(2)in the site will be as high as 9.529×10^(8)t.After 1000 years sequestration,the supercritical phase dominates in CO_(2)sequestration,followed by the liquid phase and then the mineralized phase.In addition,CO_(2)sequestration accounting for dissolution trapping increases significantly due to the presence of residual oil.More importantly,CO_(2)exhibits excellent performance in storing geothermal energy on a large scale;for example,the total energy stored in the studied geological body can provide the yearly energy supply for over 3.5×10^(7) normal households.Application of this integrated approach holds great significance for large-scale geothermal energy storage and the achievement of carbon neutrality.展开更多
In order to improve oil recovery, Enhanced Oil Recovery (EOR) techniques have been applied to several light and medium oil reservoirs. This research was directed towards the development of chemical flooding methods fo...In order to improve oil recovery, Enhanced Oil Recovery (EOR) techniques have been applied to several light and medium oil reservoirs. This research was directed towards the development of chemical flooding methods for such reservoirs. The main objective of this experimental work was to investigate the efficiency of introducing various types of Ionic Liquids (ILs), 1-Ethyl-3-methylimidazolium Chloride [EMIM][Cl], 1-Benzyl-3-methylimidazolium Chloride [BenzMIM][Cl], and Trihexyltetradecylphosphonium Chloride [THTDPh][Cl] on the Recovery Factor (RF) of medium oil (Weyburn oil, 30.25 API°) at room temperature. The series of flooding experiments were carried out by introducing a slug of IL mixtures. Results demonstrated that maximum oil recovery factor was obtained when [EMIM][Cl] was added in the displacing fluid. Further investigations have been conducted to examine the effect of ILs concentrations on the recovery mechanisms by measuring Surface Tension (SFT), pH, and viscosity of the displacing phases. Finally, the effect of theses ILs in wettability alteration was examined.展开更多
This paper demonstrates the use of a commercial simulator as a tool with which to optimize the SAGD （steam-assisted gravity drainage） start-up phase process. The factors affecting the start-up phase are the prime ta...This paper demonstrates the use of a commercial simulator as a tool with which to optimize the SAGD （steam-assisted gravity drainage） start-up phase process. The factors affecting the start-up phase are the prime targets. Among the key investigated factors are wellbore geometry effects, reservoir heterogeneity and circulation phase length. Each of the parameters was investigated via steam chamber development observation along the well pair length and the cross sections in the mid, toe and heel areas. In addition, the cumulative recovery in given time, steam-to-oil ratio and CDOR （calendar day oil rate） production data are used to backup the observations produced in the simulated model. Furthermore, an additional component developed during the research is a statistical modification of a layer cake model with which to create a heterogeneous reservoir to represent real reservoir conditions, based on Monte Carlo＇s simulation.展开更多
Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery opti...Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery optimization, has taken a prominent role in resource management. Chemical flooding has proved to be one of the most efficient EOR techniques. This study investigated the potential of employing Ionic Liquids (ILs) as alternative chemical agents for improving oil recovery. There is very little attention paid to employing this technique as well as few experimental and simulation studies. Consequently, very limited data are available. Since pilot and field studies are relatively expensive and time consuming, a numerical simulation study using CMG-STARS simulator was utilized to explore the efficiency of employing 1-Ethyl-3-Methyl-Imidazolium Acetate ([EMIM][Ac]) and 1-Benzyl-3-meth- limidazolium chloride ([BenzMIM][Cl]) with respect to improving medium oil recovery. Eight different lab-scale sandpack flooding experiments were selected to develop a numerical model to obtain the history matching of the experimental flooding results using CMG-CMOST. We observed that the main challenge was tuning the relative permeability curves to achieve a successful match for the oil recovery factor. Finally, a sensitivity study was performed to examine the effect of the chemical injection rate, the chemical concentration, the slug size, and the initiation time on oil recovery. The results showed a noticeable increase in the oil RF when injecting IL compared to conventional waterflooding.展开更多
Surfactant/alkali flooding is one of the best chemical flooding methods to enhance the oil Recovery Factor(RF).In this research,Ionic Liquid/Alkali(ILA)mixtures were chosen to represent a form of chemical flooding exp...Surfactant/alkali flooding is one of the best chemical flooding methods to enhance the oil Recovery Factor(RF).In this research,Ionic Liquid/Alkali(ILA)mixtures were chosen to represent a form of chemical flooding experiments.The selected Ionic Liquids(ILs),{[EMIM][Cl],[THTDPH][Cl],[EMIM][Ac],[BzMIM][Cl],[DMIM][Cl],[BzMIM][TOS],[dMIM][TOS]and[MPyr][TOS]},were introduced to investigate their efficiency in improving heavy oil(14o API)RF from the sand packs.Besides,the use of mixtures of the same ionic liquids and brine(3.37 wt.% salts)with an alkali(Sodium Bicarbonate[NaHCO3])were also investigated.In this experimental study,the flooding process started with injecting about 3.2 Pore Volumes(PVs)of only brine,followed by one PV of the chemical composites,and flushed with two PVs of formation brine.The study discussed the influence of cation type,anion type,the structure of the ILs,and the effect of combining ILs/alkali on the RF.The results revealed that the proposed chemical mixtures are effective in enhancing the recovery factor.ILs with shorter alkyl chain and more aromatic rings are noticeably more efficient in enhancing the RF.Finding the optimum composition of([DMIM][Cl]+NaHCO3)the chemical slug increased the additional RF up to 31.55(%OOIP).Also,increasing the slug size to two PVs improved the RF to 42.13(%OOIP).The recovery factor mechanism was explained and supported by measuring the effect of IL types on the viscosity,Surface Tension(SFT),and Zeta Potential(ZP)of the mixture.展开更多
The prediction of formation pore pressure and fracture pressure gradients is a significant step towards the drilling plan.In this study,the formation pressures of twelve wells from NC98 field-Sirte Basin(Waha Oil Comp...The prediction of formation pore pressure and fracture pressure gradients is a significant step towards the drilling plan.In this study,the formation pressures of twelve wells from NC98 field-Sirte Basin(Waha Oil Company)were calculated by employing empirical methods,Eaton's equations,that depend on the real drilling and well-logging data.Regarding the results,the normal pore pressure in the NC98 field in Sirte basin is 9.89 kPa/m(0.437 Psi/ft),and it is extending from the top of the wells in the investigated area to 2134 m(7,000 ft).A subnormal to normal pore pressure zone is noticed in the interval of 2134 m to 2743 m(7,000 ft.-9,000 ft).Then,slightly subnormal to somewhat abnormal(overpressure)region is seen from 2743–3414(9,000 ft.-11,200 ft).Beyond to that depth and down to the top of the reservoir,the overpressure zone was clearly observed.Based on the results,the casing seating depth and the equivalent mud weight were simply determined for the area of study.展开更多
A Trombe wall-heating system is used to absorb solar energy to heat buildings.Different parameters affect the system performance for optimal heating.This study evaluated the performance of four machine learning algori...A Trombe wall-heating system is used to absorb solar energy to heat buildings.Different parameters affect the system performance for optimal heating.This study evaluated the performance of four machine learning algorithms—linear regression,k-nearest neighbors,random forest,and decision tree—for predicting the room temperature in a Trombe wall system.The accuracy of the algorithms was assessed using R^(2)and root mean squared error(RMSE)values.The results demonstrated that the k-nearest neighbors and random forest algorithms exhibited superior performance,with R^(2)and RMSE values of 1 and 0.In contrast,linear regression and decision tree showed weaker performance.These findings highlight the potential of advanced machine learning algorithms for accurate room temperature prediction in Trombe wall systems,enabling informed design decisions to enhance energy efficiency.展开更多
In recent years,the demand for heavy oil has increased due to its abundant availability and low cost.However,the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility.Therefo...In recent years,the demand for heavy oil has increased due to its abundant availability and low cost.However,the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility.Therefore,various methods have been developed to enhance the recovery of heavy oil,including the use of catalysts.This study has created a unique simulation approach that uses liquid catalysts(LCs)to improve heavy oil recovery.In this work,laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery.CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments(water flooding and liquid catalyst flooding in tertiary recovery mode).Moreover,a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters.Finally,oil production optimization is performed using a genetic algorithm(particle swarm optimization)by selecting the optimum-operating parameters.In comparison to typical water flooding,the results revealed a discernible rise in the heavy oil recovery factor(RF)when injecting LCs.The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%.The injection rate,slug size,and injection temperature were found to be significant factors in optimizing the production of heavy oil.This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.展开更多
In this paper,the bubble-point pressures and pseudo bubble-point pressures of various heavy crude oil-solvent systems were measured and studied by conducting the constant-composition-expansion(CCE)tests,during which t...In this paper,the bubble-point pressures and pseudo bubble-point pressures of various heavy crude oil-solvent systems were measured and studied by conducting the constant-composition-expansion(CCE)tests,during which the test pressure was depleted in a stepwise manner.A total of fourteen CCE tests were performed for five heavy crude oil-CO_(2)systems,four heavy crude oil-CH_(4)systems,and five heavy crude oil-C_(3)H_(8)systems,respectively.All the CCE tests were conducted by using a pressure-volume-temperature(PVT)system.It was found that for most heavy crude oil-solvent systems with relatively low solvent concentrations,the measured PVT cell pressure vs.molar volume(Pcell-nmix)data in the CCE tests had three distinct regions,which were one-liquid phase region(Regions I),foamy-oil region(Region II)and two-phase region(Region III).Accordingly,the PVT cell pressure at the intersection point of Regions I and II was referred to as the measured bubble-point pressure,whereas the PVT cell pressure at the intersection point of Regions II and III was termed as the measured pseudo bubble-point pressure.For some heavy crude oil-solvent systems with high solvent concentrations,however,the measured Pcell-nmix data may have two regions only.In this special case,the PVT cell pressure at the intersection point of the two regions was considered as the measured bubble-point pressure and no pseudo bubble-point pressure could be obtained.It was also found that the heavy crude oil-CH_(4)system had not only the highest bubble-point pressure and pseudo bubble-point pressure but also the largest difference between the bubble-point pressure and pseudo bubble-point pressure,in comparison with the heavy crude oil-CO_(2)system and the heavy crude oil-C_(3)H_(8)system at the same solvent concentration.These facts indicate that CH_(4)not only is the most volatile solvent but also can remain as dispersed gas bubbles to induce the most stable foamy oil in the largest pressure range after it is nucleated from a live heavy oil.展开更多
Carbon Capture,Utilization and Storage(CCUS)plays a key role in addressing two important problems of our life-time:(i)climate-change and(ii)energy security.An International Energy Agency(IEA)study reports that there i...Carbon Capture,Utilization and Storage(CCUS)plays a key role in addressing two important problems of our life-time:(i)climate-change and(ii)energy security.An International Energy Agency(IEA)study reports that there is a significant opportunity of storing up to 360 Gt of CO_(2)through enhanced oil recovery(EOR)applications over the next 50 years.This is also an opportunity to potentially and simultaneously increase oil production by up to 375 billion barrels at the same time[1].From the perspective of life cycle assessment,the total emission of CO_(2)per unit energy produced from the oil produced by CO_(2)EOR flooding is much less than that from natural gas[2].展开更多
Surfactant flooding is a well-known chemical approach for enhancing oil recovery.Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions.Improvements in oil recovery and releas...Surfactant flooding is a well-known chemical approach for enhancing oil recovery.Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions.Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO_(2)co-injection because they generate stable foam,reduce the interfacial tension(IFT)between water and oil,cause emulsions to spontaneously form,change the wettability of porous media,and change the characteristics of flow.In the current work,the simultaneous injection of SiO_(2),Al2O3 nanoparticles,anionic surfactant SDS,and CO_(2)in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery.IFT(interfacial tension)was reduced by 44%when the nanoparticles and SDS(2000 ppm)were added,compared to a reduction of roughly 57%with SDS only.SDS-stabilized CO_(2)foam flooding,however,is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil.To assess foam's potential to shift CO_(2)from the high permeability zone(the thief zone)into the low permeability zone,directly visualizing micromodel flooding was successfully executed(upswept oil-rich zone).Based on typical reservoir permeability fluctuations,the permeability contrast(defined as the ratio of high permeability to low permeability)for the micromodel flooding was selected.However,the results of the experiment demonstrated that by utilizing SDS and nanoparticles,minimal IFT was reached.The addition of nanoparticles to surfactant solutions,however,greatly boosted oil recovery,according to the findings of flooding studies.The ultimate oil recovery was generally improved more by the anionic surfactant(SDS)solution including nanoparticles than by the anionic surfactant(SDS)alone.展开更多
Surfactant foam stability gets a lot of interest while posing a significant obstacle to many industrial operations.One of the viable solutions for addressing gas mobility concerns and boosting reservoir fluid sweep ef...Surfactant foam stability gets a lot of interest while posing a significant obstacle to many industrial operations.One of the viable solutions for addressing gas mobility concerns and boosting reservoir fluid sweep efficiency during solvent-based enhanced heavy oil recovery processes is foam formation.The synergistic effect of nanoparticles and surfactants in a porous reservoir media can help create a more durable and sturdier foam.This study aims to see how well a combination of the nanoparticles(NPs)and surfactant can generate foam for controlling gas mobility and improving oil recovery.This research looked at the effects of silicon and aluminum oxide nanoparticles on the bulk and dynamic stability of sodium dodecyl surfactant(SDS)-foam in the presence and absence of oil.Normalized foam height,liquid drainage,half-decay life,nanoparticle deposition,and bubble size distribution of the generated foams with time were used to assess static foam stability in the bulk phase,while dynamic stability was studied in the micromodel.To understand the processes of foam stabilization by nanoparticles,the microscopic images of foam and the shape of bubbles were examined.When nanoparticles were applied in foamability testing in bulk and dynamic phase,the foam generation and stability were improved by 23%and 17%,respectively.In comparison to surfactant alone,adding nanoparticles to surfactant solutions leads to a more significant pressure drop of 17.34 psi for SiO_(2)and 14.86 psi for Al_(2)O_(3)NPs and,as a result,a higher reduction in gas mobility which ultimately assists in enhancing oil recovery.展开更多
The production process in the gas reservoir with an aquifer is complex.With gas production,aquifer water could possibly flow into the production well and accumulate within the well bore,which leads to a lower producti...The production process in the gas reservoir with an aquifer is complex.With gas production,aquifer water could possibly flow into the production well and accumulate within the well bore,which leads to a lower production rate and may even block the producer.However,few studies in the literature investigate the damage caused by the liquid phase in this kind of reservoir or predict gas productivity using the relationship between reservoir pressure and water gas ratio(WGR).For this reason,it is important to know the effects of the formation of liquid phase behavior on production when an aquifer is present under a gas reservoir.From the results of published literature reviews,we found that studies focused on the production of a gas reservoir with bottom water.Nevertheless,for gas well damage from the liquid phase behavior,we found that there was no statistical data or mathematical model of the relationship between reservoir pressure and the gas oil ratio(GOR),which affects production.In this research,based on the theory of fluid flow in porous media,a new mathematical model of water and gas production and a new equation on gas well productivity is developed.To verify the model and equation,gas production data collected from the field are applied.By analyzing the typical gas reservoir with bottom water and the collected data,influences from the liquid phase behavior are shown.In this way,mathematical relationships between reservoir pressure and the WGR and between the GOR and production decline were obtained.The new gas productivity model is derived from the gas and water pseudo pressure functions,which can be applied to analyze well damage caused by the liquid phase.In order to verify the mathematical model,production data were collected from a typical gas reservoir with an aquifer located in the Changxing gas reservoir.The results indicate that a semi-logarithmic linear relationship is obtained between the WGR and productivity decrease.When the WGR increases from 0.5 to 15m3/104m3,damage caused by liquid phase decreases to 59%.The tendency of gas productivity in the Changxing gas reservoir was obtained so that it decreases as reservoir pressure decreases and increases as the WGR decreases.The gradient of the gas productivity deduction increases as the WGR increases.By the end of the data analysis,two linear equations indicating the relationship between gas productivity and reservoir pressure and the relationship between gas productivity and the water gas ratio are obtained:QAOF?A1lnWGRB1 and QAOF?A2lnPB2,respectively.展开更多
The low cost of the injected solvent,which can be also recovered and recycled,and the applicability of VAPEX technique in thin reservoirs are among the main advantages of VAPEX process compared to thermal heavy oil re...The low cost of the injected solvent,which can be also recovered and recycled,and the applicability of VAPEX technique in thin reservoirs are among the main advantages of VAPEX process compared to thermal heavy oil recovery techniques.In this research,an extensive experimental investigation is carried out to first evaluate the technical feasibility of utilization of various solvents for VAPEX process.Then the effect of drainage height on the stabilized drainage rate in VAPEX process was studied by conducting series of experiments in two large-scale 2D VAPEX models of 24.5 cm and 47.5 cm heights.Both models were packed with low permeability Ottawa sand(#530)and saturated with a heavy oil sample from Saskatchewan heavy oil reservoirs with viscosity of 5650 mPa s.Propane,butane,methane,carbon dioxide,propane/carbon dioxide(70%/30%)and propane/methane(70%/30%)were considered as respective solvents for the experiments,and a total of twelve VAPEX tests were carried out.Moreover,separate experiments were carried out at the end of each VAPEX experiment to measure the asphaltene precipitation at various locations of the VAPEX models.It was found that injecting propane would result in the highest drainage rate and oil recovery factor.Further analysis of results showed stabilized drainage rate significantly increased in the larger physical model.展开更多
CO_(2) flooding is one of the most promising techniques to enhance both light and heavy oil recovery.In light oil recovery,the production pressure in CO_(2) flooding in general keeps constant in order to maintain the ...CO_(2) flooding is one of the most promising techniques to enhance both light and heavy oil recovery.In light oil recovery,the production pressure in CO_(2) flooding in general keeps constant in order to maintain the miscibility of injected CO_(2) and crude oil;while in heavy oil recovery,a depleting pressure scheme may be able to induce foamy oil flow,thus the oil recovery could be further enhanced.In this study,different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one.Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO_(2) flooding strategies.For the core-flooding experiments,1500 mD sandstone cores,formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition(55℃ and 11 MPa)were used.Before each CO_(2) flooding test,early stage water-flooding was conducted until the water cut reached 90%.Different CO_(2) injection rates and production pressure control strategies were tested through core-flooding experiments.Experimental results indicated that a slower CO_(2) injection rate(2 ml/min)led to a higher recovery factor from 31.1%to 36.7%,compared with a high CO_(2) injection rate of 7 ml/min;for the effects of different production strategies,a constant production pressure at the production port yielded a recovery factor of 31.1%;while a pressure depletion with 47.2 kPa/min at the production port yielded 7%more oil recovery;and the best pressure control scheme in which the production pressure keeping constant during CO_(2) injection period,then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5%of the initial OOIP.For the numerical simulations study,the same oil relative permeability curve was applied to match the experimental results to all tests.Different gas relative permeability curves were obtained when the production pressure schemes are different.A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases.The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes.Through this study,it is suggested that the pressure control scheme can be optimized in order to maximize the CO_(2) injection performance for enhanced heavy oil recovery.展开更多
文摘The preservation of the integrity of CO_(2) injection wells holds immense significance for the efficacy of Carbon Capture and Storage (CCS) projects.This is attributable to the fact that a wellbore exhibiting robust mechanical and flow integrity substantially diminishes the likelihood of CO_(2) leakage into the overlying aquifer or release to the atmosphere,thereby curtailing associated risks.Given the potential hazards and repercussions stemming from the failure of CO_(2) injection wells,encompassing environmental catastrophes,financial implications,and health risks,it is imperative to earnestly address these challenges through adept management and monitoring protocols.This study aims to advance the current understanding and enhance the management of wellbore integrity issues in CO_(2) injection wells.Accordingly,this review paper undertakes a thorough exploration of the primary factors influencing wellbore integrity in CO_(2) injection wells.Furthermore,it delineates a pressing necessity for more exhaustive investigations regarding the influence of CO_(2) injection rate,CO_(2) purity,and wellbore geometry on wellbore integrity.
基金supported by the Natural Science Foundation of Sichuan“Settlement and Transport Mechanism of Biomimetic Dandelion Proppant in Fracture” (No.23NSFSC5596)the China Postdoctoral Science Foundation (No.2023M742904)。
文摘Low-permeability reservoirs are generally characterized by low porosity and low permeability.Obtaining high production using the traditional method is technologically challenging because it yields a low reservoir recovery factor.In recent years,hydraulic fracturing technology is widely applied for efficiently exploiting and developing low-permeability reservoirs using a low-viscosity fluid as a fracturing fluid.However,the transportation of the proppant is inefficient in the low-viscosity fluid,and the proppant has a low piling-up height in fracture channels.These key challenges restrict the fluid(natural gas or oil)flow in fracture channels and their functional flow areas,reducing the profits of hydrocarbon exploitation.This study aimed to explore and develop a novel dandelion-bionic proppant by modifying the surface of the proppant and the fiber.Its structure was similar to that of dandelion seeds,and it had high transport and stacking efficiency in low-viscosity liquids compared with the traditional proppant.Moreover,the transportation efficiency of this newly developed proppant was investigated experimentally using six different types of fracture models(tortuous fracture model,rough fracture model,narrow fracture model,complex fracture model,large-scale single fracture model,and small-scale single fracture model).Experimental results indicated that,compared with the traditional proppant,the transportation efficiency and the packing area of the dandelion-based bionic proppant significantly improved in tap water or low-viscosity fluid.Compared with the traditional proppant,the dandelionbased bionic proppant had 0.1-4 times longer transportation length,0.3-5 times higher piling-up height,and 2-10 times larger placement area.The newly developed proppant also had some other extraordinary features.The tortuosity of the fracture did not influence the transportation of the novel proppant.This proppant could easily enter the branch fracture and narrow fracture with a high packing area in rough surface fractures.Based on the aforementioned characteristics,this novel proppant technique could improve the proppant transportation efficiency in the low-viscosity fracturing fluid and increase the ability of the proppant to enter the secondary fracture.This study might provide a new solution for effectively exploiting low-permeability hydrocarbon reservoirs.
基金supported by the National Key Research and Development Program of China under grant(2022YFE0206700)the financial support by the National Natural Science Foundation of China(52004320)the Science Foundation of China University of Petroleum,Beijing(2462021QNXZ012 and 2462021YJRC012)。
文摘Subsurface geothermal energy storage has greater potential than other energy storage strategies in terms of capacity scale and time duration.Carbon dioxide(CO_(2))is regarded as a potential medium for energy storage due to its superior thermal properties.Moreover,the use of CO_(2)plumes for geothermal energy storage mitigates the greenhouse effect by storing CO_(2)in geological bodies.In this work,an integrated framework is proposed for synergistic geothermal energy storage and CO_(2)sequestration and utilization.Within this framework,CO_(2)is first injected into geothermal layers for energy accumulation.The resultant high-energy CO_(2)is then introduced into a target oil reservoir for CO_(2)utilization and geothermal energy storage.As a result,CO_(2)is sequestrated in the geological oil reservoir body.The results show that,as high-energy CO_(2)is injected,the average temperature of the whole target reservoir is greatly increased.With the assistance of geothermal energy,the geological utilization efficiency of CO_(2)is higher,resulting in a 10.1%increase in oil displacement efficiency.According to a storage-potential assessment of the simulated CO_(2)site,110 years after the CO_(2)injection,the utilization efficiency of the geological body will be as high as 91.2%,and the final injection quantity of the CO_(2)in the site will be as high as 9.529×10^(8)t.After 1000 years sequestration,the supercritical phase dominates in CO_(2)sequestration,followed by the liquid phase and then the mineralized phase.In addition,CO_(2)sequestration accounting for dissolution trapping increases significantly due to the presence of residual oil.More importantly,CO_(2)exhibits excellent performance in storing geothermal energy on a large scale;for example,the total energy stored in the studied geological body can provide the yearly energy supply for over 3.5×10^(7) normal households.Application of this integrated approach holds great significance for large-scale geothermal energy storage and the achievement of carbon neutrality.
文摘In order to improve oil recovery, Enhanced Oil Recovery (EOR) techniques have been applied to several light and medium oil reservoirs. This research was directed towards the development of chemical flooding methods for such reservoirs. The main objective of this experimental work was to investigate the efficiency of introducing various types of Ionic Liquids (ILs), 1-Ethyl-3-methylimidazolium Chloride [EMIM][Cl], 1-Benzyl-3-methylimidazolium Chloride [BenzMIM][Cl], and Trihexyltetradecylphosphonium Chloride [THTDPh][Cl] on the Recovery Factor (RF) of medium oil (Weyburn oil, 30.25 API°) at room temperature. The series of flooding experiments were carried out by introducing a slug of IL mixtures. Results demonstrated that maximum oil recovery factor was obtained when [EMIM][Cl] was added in the displacing fluid. Further investigations have been conducted to examine the effect of ILs concentrations on the recovery mechanisms by measuring Surface Tension (SFT), pH, and viscosity of the displacing phases. Finally, the effect of theses ILs in wettability alteration was examined.
文摘This paper demonstrates the use of a commercial simulator as a tool with which to optimize the SAGD （steam-assisted gravity drainage） start-up phase process. The factors affecting the start-up phase are the prime targets. Among the key investigated factors are wellbore geometry effects, reservoir heterogeneity and circulation phase length. Each of the parameters was investigated via steam chamber development observation along the well pair length and the cross sections in the mid, toe and heel areas. In addition, the cumulative recovery in given time, steam-to-oil ratio and CDOR （calendar day oil rate） production data are used to backup the observations produced in the simulated model. Furthermore, an additional component developed during the research is a statistical modification of a layer cake model with which to create a heterogeneous reservoir to represent real reservoir conditions, based on Monte Carlo＇s simulation.
文摘Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery optimization, has taken a prominent role in resource management. Chemical flooding has proved to be one of the most efficient EOR techniques. This study investigated the potential of employing Ionic Liquids (ILs) as alternative chemical agents for improving oil recovery. There is very little attention paid to employing this technique as well as few experimental and simulation studies. Consequently, very limited data are available. Since pilot and field studies are relatively expensive and time consuming, a numerical simulation study using CMG-STARS simulator was utilized to explore the efficiency of employing 1-Ethyl-3-Methyl-Imidazolium Acetate ([EMIM][Ac]) and 1-Benzyl-3-meth- limidazolium chloride ([BenzMIM][Cl]) with respect to improving medium oil recovery. Eight different lab-scale sandpack flooding experiments were selected to develop a numerical model to obtain the history matching of the experimental flooding results using CMG-CMOST. We observed that the main challenge was tuning the relative permeability curves to achieve a successful match for the oil recovery factor. Finally, a sensitivity study was performed to examine the effect of the chemical injection rate, the chemical concentration, the slug size, and the initiation time on oil recovery. The results showed a noticeable increase in the oil RF when injecting IL compared to conventional waterflooding.
文摘Surfactant/alkali flooding is one of the best chemical flooding methods to enhance the oil Recovery Factor(RF).In this research,Ionic Liquid/Alkali(ILA)mixtures were chosen to represent a form of chemical flooding experiments.The selected Ionic Liquids(ILs),{[EMIM][Cl],[THTDPH][Cl],[EMIM][Ac],[BzMIM][Cl],[DMIM][Cl],[BzMIM][TOS],[dMIM][TOS]and[MPyr][TOS]},were introduced to investigate their efficiency in improving heavy oil(14o API)RF from the sand packs.Besides,the use of mixtures of the same ionic liquids and brine(3.37 wt.% salts)with an alkali(Sodium Bicarbonate[NaHCO3])were also investigated.In this experimental study,the flooding process started with injecting about 3.2 Pore Volumes(PVs)of only brine,followed by one PV of the chemical composites,and flushed with two PVs of formation brine.The study discussed the influence of cation type,anion type,the structure of the ILs,and the effect of combining ILs/alkali on the RF.The results revealed that the proposed chemical mixtures are effective in enhancing the recovery factor.ILs with shorter alkyl chain and more aromatic rings are noticeably more efficient in enhancing the RF.Finding the optimum composition of([DMIM][Cl]+NaHCO3)the chemical slug increased the additional RF up to 31.55(%OOIP).Also,increasing the slug size to two PVs improved the RF to 42.13(%OOIP).The recovery factor mechanism was explained and supported by measuring the effect of IL types on the viscosity,Surface Tension(SFT),and Zeta Potential(ZP)of the mixture.
文摘The prediction of formation pore pressure and fracture pressure gradients is a significant step towards the drilling plan.In this study,the formation pressures of twelve wells from NC98 field-Sirte Basin(Waha Oil Company)were calculated by employing empirical methods,Eaton's equations,that depend on the real drilling and well-logging data.Regarding the results,the normal pore pressure in the NC98 field in Sirte basin is 9.89 kPa/m(0.437 Psi/ft),and it is extending from the top of the wells in the investigated area to 2134 m(7,000 ft).A subnormal to normal pore pressure zone is noticed in the interval of 2134 m to 2743 m(7,000 ft.-9,000 ft).Then,slightly subnormal to somewhat abnormal(overpressure)region is seen from 2743–3414(9,000 ft.-11,200 ft).Beyond to that depth and down to the top of the reservoir,the overpressure zone was clearly observed.Based on the results,the casing seating depth and the equivalent mud weight were simply determined for the area of study.
文摘A Trombe wall-heating system is used to absorb solar energy to heat buildings.Different parameters affect the system performance for optimal heating.This study evaluated the performance of four machine learning algorithms—linear regression,k-nearest neighbors,random forest,and decision tree—for predicting the room temperature in a Trombe wall system.The accuracy of the algorithms was assessed using R^(2)and root mean squared error(RMSE)values.The results demonstrated that the k-nearest neighbors and random forest algorithms exhibited superior performance,with R^(2)and RMSE values of 1 and 0.In contrast,linear regression and decision tree showed weaker performance.These findings highlight the potential of advanced machine learning algorithms for accurate room temperature prediction in Trombe wall systems,enabling informed design decisions to enhance energy efficiency.
基金funded by the Petroleum Technological Research Centre(PTRC),MITACS,and graduate studies at the University of Regina.
文摘In recent years,the demand for heavy oil has increased due to its abundant availability and low cost.However,the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility.Therefore,various methods have been developed to enhance the recovery of heavy oil,including the use of catalysts.This study has created a unique simulation approach that uses liquid catalysts(LCs)to improve heavy oil recovery.In this work,laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery.CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments(water flooding and liquid catalyst flooding in tertiary recovery mode).Moreover,a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters.Finally,oil production optimization is performed using a genetic algorithm(particle swarm optimization)by selecting the optimum-operating parameters.In comparison to typical water flooding,the results revealed a discernible rise in the heavy oil recovery factor(RF)when injecting LCs.The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%.The injection rate,slug size,and injection temperature were found to be significant factors in optimizing the production of heavy oil.This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.
文摘In this paper,the bubble-point pressures and pseudo bubble-point pressures of various heavy crude oil-solvent systems were measured and studied by conducting the constant-composition-expansion(CCE)tests,during which the test pressure was depleted in a stepwise manner.A total of fourteen CCE tests were performed for five heavy crude oil-CO_(2)systems,four heavy crude oil-CH_(4)systems,and five heavy crude oil-C_(3)H_(8)systems,respectively.All the CCE tests were conducted by using a pressure-volume-temperature(PVT)system.It was found that for most heavy crude oil-solvent systems with relatively low solvent concentrations,the measured PVT cell pressure vs.molar volume(Pcell-nmix)data in the CCE tests had three distinct regions,which were one-liquid phase region(Regions I),foamy-oil region(Region II)and two-phase region(Region III).Accordingly,the PVT cell pressure at the intersection point of Regions I and II was referred to as the measured bubble-point pressure,whereas the PVT cell pressure at the intersection point of Regions II and III was termed as the measured pseudo bubble-point pressure.For some heavy crude oil-solvent systems with high solvent concentrations,however,the measured Pcell-nmix data may have two regions only.In this special case,the PVT cell pressure at the intersection point of the two regions was considered as the measured bubble-point pressure and no pseudo bubble-point pressure could be obtained.It was also found that the heavy crude oil-CH_(4)system had not only the highest bubble-point pressure and pseudo bubble-point pressure but also the largest difference between the bubble-point pressure and pseudo bubble-point pressure,in comparison with the heavy crude oil-CO_(2)system and the heavy crude oil-C_(3)H_(8)system at the same solvent concentration.These facts indicate that CH_(4)not only is the most volatile solvent but also can remain as dispersed gas bubbles to induce the most stable foamy oil in the largest pressure range after it is nucleated from a live heavy oil.
文摘Carbon Capture,Utilization and Storage(CCUS)plays a key role in addressing two important problems of our life-time:(i)climate-change and(ii)energy security.An International Energy Agency(IEA)study reports that there is a significant opportunity of storing up to 360 Gt of CO_(2)through enhanced oil recovery(EOR)applications over the next 50 years.This is also an opportunity to potentially and simultaneously increase oil production by up to 375 billion barrels at the same time[1].From the perspective of life cycle assessment,the total emission of CO_(2)per unit energy produced from the oil produced by CO_(2)EOR flooding is much less than that from natural gas[2].
基金The Petroleum Technology Research Centre (PTRC),MITACSgraduate studies at the University of Regina all provided funding for this study
文摘Surfactant flooding is a well-known chemical approach for enhancing oil recovery.Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions.Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO_(2)co-injection because they generate stable foam,reduce the interfacial tension(IFT)between water and oil,cause emulsions to spontaneously form,change the wettability of porous media,and change the characteristics of flow.In the current work,the simultaneous injection of SiO_(2),Al2O3 nanoparticles,anionic surfactant SDS,and CO_(2)in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery.IFT(interfacial tension)was reduced by 44%when the nanoparticles and SDS(2000 ppm)were added,compared to a reduction of roughly 57%with SDS only.SDS-stabilized CO_(2)foam flooding,however,is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil.To assess foam's potential to shift CO_(2)from the high permeability zone(the thief zone)into the low permeability zone,directly visualizing micromodel flooding was successfully executed(upswept oil-rich zone).Based on typical reservoir permeability fluctuations,the permeability contrast(defined as the ratio of high permeability to low permeability)for the micromodel flooding was selected.However,the results of the experiment demonstrated that by utilizing SDS and nanoparticles,minimal IFT was reached.The addition of nanoparticles to surfactant solutions,however,greatly boosted oil recovery,according to the findings of flooding studies.The ultimate oil recovery was generally improved more by the anionic surfactant(SDS)solution including nanoparticles than by the anionic surfactant(SDS)alone.
基金This research is funded by graduate studies of the University of Regina,Petroleum Technology Research Centre(PTRC),and MITACS.
文摘Surfactant foam stability gets a lot of interest while posing a significant obstacle to many industrial operations.One of the viable solutions for addressing gas mobility concerns and boosting reservoir fluid sweep efficiency during solvent-based enhanced heavy oil recovery processes is foam formation.The synergistic effect of nanoparticles and surfactants in a porous reservoir media can help create a more durable and sturdier foam.This study aims to see how well a combination of the nanoparticles(NPs)and surfactant can generate foam for controlling gas mobility and improving oil recovery.This research looked at the effects of silicon and aluminum oxide nanoparticles on the bulk and dynamic stability of sodium dodecyl surfactant(SDS)-foam in the presence and absence of oil.Normalized foam height,liquid drainage,half-decay life,nanoparticle deposition,and bubble size distribution of the generated foams with time were used to assess static foam stability in the bulk phase,while dynamic stability was studied in the micromodel.To understand the processes of foam stabilization by nanoparticles,the microscopic images of foam and the shape of bubbles were examined.When nanoparticles were applied in foamability testing in bulk and dynamic phase,the foam generation and stability were improved by 23%and 17%,respectively.In comparison to surfactant alone,adding nanoparticles to surfactant solutions leads to a more significant pressure drop of 17.34 psi for SiO_(2)and 14.86 psi for Al_(2)O_(3)NPs and,as a result,a higher reduction in gas mobility which ultimately assists in enhancing oil recovery.
基金The authors acknowledge the technical and financial support of the National Natural Science Foundation of China study titled“Study on thewater invasion mechanism of fracture gas condensate reservoirs with bottom water”(Grant No.51374269)the Chongqing Science and Technology Research project titled“The effect of fracturing fluid on the productivity of ultra-low water cut shale gas wells”(Grant No.KJ1601333).
文摘The production process in the gas reservoir with an aquifer is complex.With gas production,aquifer water could possibly flow into the production well and accumulate within the well bore,which leads to a lower production rate and may even block the producer.However,few studies in the literature investigate the damage caused by the liquid phase in this kind of reservoir or predict gas productivity using the relationship between reservoir pressure and water gas ratio(WGR).For this reason,it is important to know the effects of the formation of liquid phase behavior on production when an aquifer is present under a gas reservoir.From the results of published literature reviews,we found that studies focused on the production of a gas reservoir with bottom water.Nevertheless,for gas well damage from the liquid phase behavior,we found that there was no statistical data or mathematical model of the relationship between reservoir pressure and the gas oil ratio(GOR),which affects production.In this research,based on the theory of fluid flow in porous media,a new mathematical model of water and gas production and a new equation on gas well productivity is developed.To verify the model and equation,gas production data collected from the field are applied.By analyzing the typical gas reservoir with bottom water and the collected data,influences from the liquid phase behavior are shown.In this way,mathematical relationships between reservoir pressure and the WGR and between the GOR and production decline were obtained.The new gas productivity model is derived from the gas and water pseudo pressure functions,which can be applied to analyze well damage caused by the liquid phase.In order to verify the mathematical model,production data were collected from a typical gas reservoir with an aquifer located in the Changxing gas reservoir.The results indicate that a semi-logarithmic linear relationship is obtained between the WGR and productivity decrease.When the WGR increases from 0.5 to 15m3/104m3,damage caused by liquid phase decreases to 59%.The tendency of gas productivity in the Changxing gas reservoir was obtained so that it decreases as reservoir pressure decreases and increases as the WGR decreases.The gradient of the gas productivity deduction increases as the WGR increases.By the end of the data analysis,two linear equations indicating the relationship between gas productivity and reservoir pressure and the relationship between gas productivity and the water gas ratio are obtained:QAOF?A1lnWGRB1 and QAOF?A2lnPB2,respectively.
文摘The low cost of the injected solvent,which can be also recovered and recycled,and the applicability of VAPEX technique in thin reservoirs are among the main advantages of VAPEX process compared to thermal heavy oil recovery techniques.In this research,an extensive experimental investigation is carried out to first evaluate the technical feasibility of utilization of various solvents for VAPEX process.Then the effect of drainage height on the stabilized drainage rate in VAPEX process was studied by conducting series of experiments in two large-scale 2D VAPEX models of 24.5 cm and 47.5 cm heights.Both models were packed with low permeability Ottawa sand(#530)and saturated with a heavy oil sample from Saskatchewan heavy oil reservoirs with viscosity of 5650 mPa s.Propane,butane,methane,carbon dioxide,propane/carbon dioxide(70%/30%)and propane/methane(70%/30%)were considered as respective solvents for the experiments,and a total of twelve VAPEX tests were carried out.Moreover,separate experiments were carried out at the end of each VAPEX experiment to measure the asphaltene precipitation at various locations of the VAPEX models.It was found that injecting propane would result in the highest drainage rate and oil recovery factor.Further analysis of results showed stabilized drainage rate significantly increased in the larger physical model.
基金The authors would like to acknowledge the Petroleum Technology Research Centre(PTRC)for the financial support.Numerical simulation support from Sam Hong,Hongyang Wang and Xiaolong Peng in our research group is highly appreciated.
文摘CO_(2) flooding is one of the most promising techniques to enhance both light and heavy oil recovery.In light oil recovery,the production pressure in CO_(2) flooding in general keeps constant in order to maintain the miscibility of injected CO_(2) and crude oil;while in heavy oil recovery,a depleting pressure scheme may be able to induce foamy oil flow,thus the oil recovery could be further enhanced.In this study,different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one.Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO_(2) flooding strategies.For the core-flooding experiments,1500 mD sandstone cores,formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition(55℃ and 11 MPa)were used.Before each CO_(2) flooding test,early stage water-flooding was conducted until the water cut reached 90%.Different CO_(2) injection rates and production pressure control strategies were tested through core-flooding experiments.Experimental results indicated that a slower CO_(2) injection rate(2 ml/min)led to a higher recovery factor from 31.1%to 36.7%,compared with a high CO_(2) injection rate of 7 ml/min;for the effects of different production strategies,a constant production pressure at the production port yielded a recovery factor of 31.1%;while a pressure depletion with 47.2 kPa/min at the production port yielded 7%more oil recovery;and the best pressure control scheme in which the production pressure keeping constant during CO_(2) injection period,then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5%of the initial OOIP.For the numerical simulations study,the same oil relative permeability curve was applied to match the experimental results to all tests.Different gas relative permeability curves were obtained when the production pressure schemes are different.A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases.The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes.Through this study,it is suggested that the pressure control scheme can be optimized in order to maximize the CO_(2) injection performance for enhanced heavy oil recovery.
