CO2-enhanced oil recovery (EOR) was started in 1950. Low sweep efficiency and early breakthrough issues were associated with the CO2-EOR system. Foam-EOR was introduced to improve the sweep efficiency instead of polymers to avoid formation damage caused by polymers. Foam stability reduces in high-salinity environments, high-temperature formations (>212°F), and in contact with crude oil. The present study the using of nanoparticles and viscoelastic surfactants (VES) to improve foam mobility control for EOR application. This paper study the CO2-foam stability with using alpha olefin sulfonate (AOS) as a foaming agent and the change on the mobility-reduction factor (MRF) for different foam solutions by adding nanoparticles and VES. To achieve this objective, foam-stability for different solutions was measured at 77 and 150°F using high-pressure view chamber (HPVC). Interfacial tension measurements were conducted to investigate the destabilizing effect of crude oil on the different foam systems. Coreflood experiments were conducted using Buff Berea sandstone cores at 150°F, saturated initially with a dead-crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions. Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves both foam stability and MRF. In contact with crude oil, unstable oil-in-water emulsion formed inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. The interfacial tension measurements revealed positive values for the spreading and the bridging coefficients. Hence, the crude oil spread over the gas-water interface, and lamella films were unstable due to the bridging of oil droplets. The oil recovery from the conventional waterflooding (as a secondary recovery before foam injection) was 48% of the original oil-in-place. From the series coreflood experiments, AOS was not able to enhance the oil recovery. However, more oil was recovered in the presence of nanoparticles (12 %) and VES (18%). Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.
{"title":"Stability Improvement of CO2 Foam for Enhanced Oil Recovery Applications Using Nanoparticles and Viscoelastic Surfactants","authors":"A. Ibrahim, H. Nasr-El-Din","doi":"10.2118/191251-MS","DOIUrl":"https://doi.org/10.2118/191251-MS","url":null,"abstract":"\u0000 CO2-enhanced oil recovery (EOR) was started in 1950. Low sweep efficiency and early breakthrough issues were associated with the CO2-EOR system. Foam-EOR was introduced to improve the sweep efficiency instead of polymers to avoid formation damage caused by polymers. Foam stability reduces in high-salinity environments, high-temperature formations (>212°F), and in contact with crude oil. The present study the using of nanoparticles and viscoelastic surfactants (VES) to improve foam mobility control for EOR application.\u0000 This paper study the CO2-foam stability with using alpha olefin sulfonate (AOS) as a foaming agent and the change on the mobility-reduction factor (MRF) for different foam solutions by adding nanoparticles and VES. To achieve this objective, foam-stability for different solutions was measured at 77 and 150°F using high-pressure view chamber (HPVC). Interfacial tension measurements were conducted to investigate the destabilizing effect of crude oil on the different foam systems. Coreflood experiments were conducted using Buff Berea sandstone cores at 150°F, saturated initially with a dead-crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions.\u0000 Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves both foam stability and MRF. In contact with crude oil, unstable oil-in-water emulsion formed inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. The interfacial tension measurements revealed positive values for the spreading and the bridging coefficients. Hence, the crude oil spread over the gas-water interface, and lamella films were unstable due to the bridging of oil droplets. The oil recovery from the conventional waterflooding (as a secondary recovery before foam injection) was 48% of the original oil-in-place. From the series coreflood experiments, AOS was not able to enhance the oil recovery. However, more oil was recovered in the presence of nanoparticles (12 %) and VES (18%).\u0000 Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124308065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Mehranfar, L. Marquez, R. Altman, Hassan Kolivand, Rodrigo Orantes, O. Espinola
The objective of this work is to present a comprehensive workflow to optimize the value of a hydrocarbon asset evaluation project under high degrees of uncertainty. This workflow is applicable to both conventional and unconventional assets. However, because of the considerable level of subsurface uncertainty and high initial costs (mainly due to drilling and hydraulic fracturing operations), unconventional resources are good examples for demonstrating the benefits of the workflow. For the case of an unconventional asset, well spacing and perforation cluster spacing are usually the decision parameters that need to be optimized to increase its value. The workflow begins with the construction of a representative base case single well gas simulation model for production history matching. Petrophysical, geological, geomechanical, stimulation, completions and production data are interpreted and analyzed together to better understand drivers that could be influencing the production. If this can be repeated with several wells in the block with sufficient production data, the process is enriched as so the level of confidence, as the range of history-matching parameters from these different wells across the block can be captured for sensitivity and uncertainty analysis. Several sets of sensitivities and uncertainty runs are then performed to get a probabilistic production profile in the presence of the most influential parameters. It is important to highlight that usually, the limited number of wells, short production histories, different dynamic behavior in neighboring blocks and the lack of necessary data to help understand well performance all contribute to the high uncertainty in predicting production. Given the high cost of drilling and hydraulic fracturing and on the other hand the high gas price in Argentina, optimizing well spacing and cluster spacing are critical parameters in the process of unconventional resource evaluation considering the high degree of uncertainty.
{"title":"Optimization under Uncertainty for Reliable Unconventional Play Evaluation. A Case Study in Vaca Muerta Shale Gas Blocks, Argentina","authors":"R. Mehranfar, L. Marquez, R. Altman, Hassan Kolivand, Rodrigo Orantes, O. Espinola","doi":"10.2118/191272-MS","DOIUrl":"https://doi.org/10.2118/191272-MS","url":null,"abstract":"\u0000 The objective of this work is to present a comprehensive workflow to optimize the value of a hydrocarbon asset evaluation project under high degrees of uncertainty. This workflow is applicable to both conventional and unconventional assets. However, because of the considerable level of subsurface uncertainty and high initial costs (mainly due to drilling and hydraulic fracturing operations), unconventional resources are good examples for demonstrating the benefits of the workflow. For the case of an unconventional asset, well spacing and perforation cluster spacing are usually the decision parameters that need to be optimized to increase its value.\u0000 The workflow begins with the construction of a representative base case single well gas simulation model for production history matching. Petrophysical, geological, geomechanical, stimulation, completions and production data are interpreted and analyzed together to better understand drivers that could be influencing the production. If this can be repeated with several wells in the block with sufficient production data, the process is enriched as so the level of confidence, as the range of history-matching parameters from these different wells across the block can be captured for sensitivity and uncertainty analysis. Several sets of sensitivities and uncertainty runs are then performed to get a probabilistic production profile in the presence of the most influential parameters. It is important to highlight that usually, the limited number of wells, short production histories, different dynamic behavior in neighboring blocks and the lack of necessary data to help understand well performance all contribute to the high uncertainty in predicting production.\u0000 Given the high cost of drilling and hydraulic fracturing and on the other hand the high gas price in Argentina, optimizing well spacing and cluster spacing are critical parameters in the process of unconventional resource evaluation considering the high degree of uncertainty.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"111 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124049324","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives. Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately. Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite. Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.
{"title":"Effect of Temperature, Phase Change, and Chemical Additive on Wettability Alteration During Steam Applications in Sands and Carbonates","authors":"R. Pratama, T. Babadagli","doi":"10.2118/191188-MS","DOIUrl":"https://doi.org/10.2118/191188-MS","url":null,"abstract":"\u0000 One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives.\u0000 Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately.\u0000 Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite.\u0000 Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130643641","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa. The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive. Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%. The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.
{"title":"An Integrated Method for Forecasting Well Deliverability in Gas Condensate Reservoirs with Bottom Aquifer Drive","authors":"Abdulaziz Ellafi, R. Flori, S. Dunn-Norman","doi":"10.2118/191269-MS","DOIUrl":"https://doi.org/10.2118/191269-MS","url":null,"abstract":"\u0000 Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa.\u0000 The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive.\u0000 Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%.\u0000 The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127131344","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. T. Al-Murayri, A. Hassan, Dawood S. Kamal, G. Batôt, A. Cuenca, Jessica Butron, A. Kantzas, G. Suzanne
Foam has been extensively investigated as a method to improve the mobility control of non-condensable gases in the EOR context. Recently, there has been renewed interest in foam applied to steam injections. However, steam is a condensable gas and thus steam-foam requires special analyses that differ from classical foam assessments. This work presents the coreflood results of a steam-foam process evaluation for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait. Using specifically designed foaming surfactants, coreflood tests in the absence and presence of heavy crude oil are performed in native sandpack cores under RQLF reservoir conditions (220°C; 360 psi). In order to limit steam condensation due to the build-up of the foam pressure, steam has been supplemented with a small amount of non-condensable gas (nitrogen, about 1 - 5 mol.%). Interstitial velocity was decreased from 40 ft/day down to 1 ft/day (CWE). Phase equilibria at the core inlet were estimated based on thermodynamics flash calculations. From these calculations inlet steam quality was varied from 10 to 70 wt.%. In absence of oil, the apparent viscosity of the generated steam-foam is measured between 25 and 50 cP, depending on the interstitial velocity and inlet steam quality. Indeed, beside the classical shear-thickening behaviour observed with the decreasing flow rates, the critical or optimal steam quality is found to be closed to 30 wt.%. Furthermore, even at higher steam quality the foam is still stable and efficient with a viscosity higher than 25 cP. Experiments in the presence of crude oil were carried out under the same conditions in native cores at a steam residual oil saturation of 7% and 13%. These experiments showed that the optimal steam quality is shifted to approximatively 10 wt.%. Furthermore, the foam flow curve shows a shear-thinning behavior that is elaborated upon. Finally, the viscosity in the presence of heavy crude oil of the generated steam-foam is within the range of 7 to 22 cP, depending on the oil saturation and on the injection conditions. Considering the oil viscosity (2 to 3 cP) under the same conditions, this means that the foam effect should translate into efficient improved conformance control of the steam within the reservoir. For the first time, an efficient and stable steam-foam is generated in coreflood experiments. The generated foam achieved high apparent viscosities, even in the presence of oil, and this has not been reported in the literature to date. The results presented here are far more than a proof of concept as they bring new evidences regarding steam-foam efficiency and mechanisms with heavy crude oil.
{"title":"Steam-Foam Assessment Using Native Cores from the Ratqa Lower Fars RQLF Heavy Oil Reservoir in Kuwait to De-Risk Field-Scale Deployment","authors":"M. T. Al-Murayri, A. Hassan, Dawood S. Kamal, G. Batôt, A. Cuenca, Jessica Butron, A. Kantzas, G. Suzanne","doi":"10.2118/191190-MS","DOIUrl":"https://doi.org/10.2118/191190-MS","url":null,"abstract":"\u0000 Foam has been extensively investigated as a method to improve the mobility control of non-condensable gases in the EOR context. Recently, there has been renewed interest in foam applied to steam injections. However, steam is a condensable gas and thus steam-foam requires special analyses that differ from classical foam assessments. This work presents the coreflood results of a steam-foam process evaluation for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.\u0000 Using specifically designed foaming surfactants, coreflood tests in the absence and presence of heavy crude oil are performed in native sandpack cores under RQLF reservoir conditions (220°C; 360 psi). In order to limit steam condensation due to the build-up of the foam pressure, steam has been supplemented with a small amount of non-condensable gas (nitrogen, about 1 - 5 mol.%). Interstitial velocity was decreased from 40 ft/day down to 1 ft/day (CWE). Phase equilibria at the core inlet were estimated based on thermodynamics flash calculations. From these calculations inlet steam quality was varied from 10 to 70 wt.%. In absence of oil, the apparent viscosity of the generated steam-foam is measured between 25 and 50 cP, depending on the interstitial velocity and inlet steam quality. Indeed, beside the classical shear-thickening behaviour observed with the decreasing flow rates, the critical or optimal steam quality is found to be closed to 30 wt.%. Furthermore, even at higher steam quality the foam is still stable and efficient with a viscosity higher than 25 cP. Experiments in the presence of crude oil were carried out under the same conditions in native cores at a steam residual oil saturation of 7% and 13%. These experiments showed that the optimal steam quality is shifted to approximatively 10 wt.%. Furthermore, the foam flow curve shows a shear-thinning behavior that is elaborated upon. Finally, the viscosity in the presence of heavy crude oil of the generated steam-foam is within the range of 7 to 22 cP, depending on the oil saturation and on the injection conditions. Considering the oil viscosity (2 to 3 cP) under the same conditions, this means that the foam effect should translate into efficient improved conformance control of the steam within the reservoir.\u0000 For the first time, an efficient and stable steam-foam is generated in coreflood experiments. The generated foam achieved high apparent viscosities, even in the presence of oil, and this has not been reported in the literature to date. The results presented here are far more than a proof of concept as they bring new evidences regarding steam-foam efficiency and mechanisms with heavy crude oil.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"160 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122067926","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study focuses on the ability of complex colloidal solution to stabilize a heavy oil-brine Pickering emulsion by changing the activity at the interface between heavy oil and brine. After testing many different combinations of anionic and cationic surfactants and nano-particles, we formulated the best stability options and created oil-in-water Pickering emulsions stabilized by silica, a cationic surfactant [dodecyltrimethylammonium bromide (DTAB)], and an anionic surfactant [alcohol propoxy sulfate (Alfoterra S23-7S-90)]. Then, various core flooding experiments were conducted in order to demonstrate the practical ability of the created emulsion system and observe its capacity to enhance oil recovery. Rate-dependency flooding tests were also conducted to determine the optimal flow rate required for heavy oil production through emulsification for different permeability media. Ultimately, slim tube sandpack flooding experiment at the optimal rate was conducted to confirm in-situ emulsion generation and to support the potential use of the chemical combination in the heavy oil industry.
{"title":"Improvement of Microemulsion Generation and Stability Using New Generation Chemicals and Nano Materials During Waterflooding as a Cost-Efficient Heavy-Oil Recovery Method","authors":"Jungin Lee, T. Babadagli","doi":"10.2118/191171-MS","DOIUrl":"https://doi.org/10.2118/191171-MS","url":null,"abstract":"\u0000 This study focuses on the ability of complex colloidal solution to stabilize a heavy oil-brine Pickering emulsion by changing the activity at the interface between heavy oil and brine. After testing many different combinations of anionic and cationic surfactants and nano-particles, we formulated the best stability options and created oil-in-water Pickering emulsions stabilized by silica, a cationic surfactant [dodecyltrimethylammonium bromide (DTAB)], and an anionic surfactant [alcohol propoxy sulfate (Alfoterra S23-7S-90)]. Then, various core flooding experiments were conducted in order to demonstrate the practical ability of the created emulsion system and observe its capacity to enhance oil recovery. Rate-dependency flooding tests were also conducted to determine the optimal flow rate required for heavy oil production through emulsification for different permeability media. Ultimately, slim tube sandpack flooding experiment at the optimal rate was conducted to confirm in-situ emulsion generation and to support the potential use of the chemical combination in the heavy oil industry.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126965865","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Given that some fractured reservoirs have poorly connected natural fractures, the conventional Warren and Root model (1963) may not applicable. To narrow this gap, we introduce a numerical method to build a dual-porosity model for those reservoirs. To verify this numerical model, we perform a case study with a semianalytical model (SPE-187290-MS) for a discretely fractured reservoir. During the model verification, the pressure response from this numerical model are compared to the semianalytical results for fractured reservoirs with poorly connected fractures. It is found that the difference between the pressure responses obtained by these two models is negligible. Results show that pressure transient behaviors of wells with intersecting fracture exhibit completely different flow regimes with those without intersecting fracture. Bilinear flow, linear flow, transient flow, and pseudo-radial flow may progressively occur for intersecting fracture. A radial flow in matrix occurs for discrete fractures, before the impacts of nature fractures exhibit. Once these impacts are detected, the pressure derivatives show a dual-porosity feature "V-shape", which is virtually quite different from that in Warren and Root's dual-porosity model.
{"title":"A Numerical Model for Pressure Transient Analysis in Fractured Reservoirs with Poorly Connected Fractures","authors":"Hongyang Chu, X. Liao, Zhiming Chen, Youwei He, Jiandong Zou, Jiali Zhang, J. Zhao, Jiaxin Wei","doi":"10.2118/191246-MS","DOIUrl":"https://doi.org/10.2118/191246-MS","url":null,"abstract":"\u0000 Given that some fractured reservoirs have poorly connected natural fractures, the conventional Warren and Root model (1963) may not applicable. To narrow this gap, we introduce a numerical method to build a dual-porosity model for those reservoirs. To verify this numerical model, we perform a case study with a semianalytical model (SPE-187290-MS) for a discretely fractured reservoir. During the model verification, the pressure response from this numerical model are compared to the semianalytical results for fractured reservoirs with poorly connected fractures. It is found that the difference between the pressure responses obtained by these two models is negligible. Results show that pressure transient behaviors of wells with intersecting fracture exhibit completely different flow regimes with those without intersecting fracture. Bilinear flow, linear flow, transient flow, and pseudo-radial flow may progressively occur for intersecting fracture. A radial flow in matrix occurs for discrete fractures, before the impacts of nature fractures exhibit. Once these impacts are detected, the pressure derivatives show a dual-porosity feature \"V-shape\", which is virtually quite different from that in Warren and Root's dual-porosity model.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"195 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124338087","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Matrix acidizing is a remedial well stimulation that done to overcome formation damage near wellbore or improve the permeability. Although acidizing treatments are proven and abundant there is still inherit from formation damage when pumped. Acid-induced asphaltene sludging is becoming an increasing cause of oil well stimulation Failure. The objective of the paper is to evaluate the performance of coconut oil as a bio-oil dispersant against commercial dispersants in preventing asphaltene sludge while acidizing carbonate cores with 15 wt.% HCl and a chelating agent. A Kuwaiti crude oil was used in this study has an API of 38° and 2% asphaltene content. The crude oil was characterized by a variety of analytical techniques including total acid and base numbers (TAN, TBN), saturates, aromatics, resins and asphaltene analysis (SARA), density, viscosity and elemental analysis. Indiana limestone cores were used with average porosity of 16% and permeability ranges (9-13) md. X-ray diffraction (XRD) was used to analyze the mineral and clay content in the cores. Sludge tests were used to examine the acid and oil compatibility using anaging cell under 500 psi and 160°F with oil to an acid ratio of 1:1. Coreflooding experiments under reservoir condition were done with the selected two acid systems, 15 wt. % HCl and achelating agent. Indiana limestone cores with a permeability of 7-12 md were initially saturated with the crude oil then acid was injected until breakthrough. The injected acid volume was recorded and CT-scan imaging of the cores after the acid treatment was used to evaluate the structure and the propagation of the wormhole. The effluent fluids were analyzed by inductively coupled plasma (ICP) and pH measurements. The results for a Kuwaiti crude oil showed the formation of 13 wt% sludge with 15 wt% HCl and it increased to 19 and 30 wt% with increasing acid concentrations to 20 and 28 wt%, respectively. The presence of iron(III) in the system increased the sludge precipitation to 17.8 wt% at 15 wt% HCl and 3,000 ppm iron concentration. The sludging decreased to 7.5 wt% by adding 300 ppm coconut oil to the system. The formation of asphaltene sludge in the carbonate acidizing retards the wormhole propagation. Hence, the injected acid volume to the breakthrough decreased from 1 to 0.4 by adding 300 ppm coconut oil to the acid system. A conical wormhole was formed with the injection of 15 wt% HCl, comparing to a uniform wormhole in the presence of coconut on the acid system. In the case of stimulating the cores with achelating agent (20 wt% GLDA), the coconut oil exceeds the expectations with the minimum pore volume needed to breakthrough compared to the GLDA alone or with the chemical dispersant B. This study concluded that the use of dispersant can help reduce the asphaltene sludge and create better acid propagation through the core. The results can be employed to design the optimum acid formulation and create the desired wormhole in carbonate
{"title":"Bio-Oil Dispersants Effectiveness on AsphalteneSludge During Carbonate Acidizing Treatment","authors":"Hessah O. Alrashidi, A. Ibrahim, H. Nasr-El-Din","doi":"10.2118/191165-MS","DOIUrl":"https://doi.org/10.2118/191165-MS","url":null,"abstract":"\u0000 Matrix acidizing is a remedial well stimulation that done to overcome formation damage near wellbore or improve the permeability. Although acidizing treatments are proven and abundant there is still inherit from formation damage when pumped. Acid-induced asphaltene sludging is becoming an increasing cause of oil well stimulation Failure.\u0000 The objective of the paper is to evaluate the performance of coconut oil as a bio-oil dispersant against commercial dispersants in preventing asphaltene sludge while acidizing carbonate cores with 15 wt.% HCl and a chelating agent. A Kuwaiti crude oil was used in this study has an API of 38° and 2% asphaltene content. The crude oil was characterized by a variety of analytical techniques including total acid and base numbers (TAN, TBN), saturates, aromatics, resins and asphaltene analysis (SARA), density, viscosity and elemental analysis. Indiana limestone cores were used with average porosity of 16% and permeability ranges (9-13) md. X-ray diffraction (XRD) was used to analyze the mineral and clay content in the cores. Sludge tests were used to examine the acid and oil compatibility using anaging cell under 500 psi and 160°F with oil to an acid ratio of 1:1. Coreflooding experiments under reservoir condition were done with the selected two acid systems, 15 wt. % HCl and achelating agent. Indiana limestone cores with a permeability of 7-12 md were initially saturated with the crude oil then acid was injected until breakthrough. The injected acid volume was recorded and CT-scan imaging of the cores after the acid treatment was used to evaluate the structure and the propagation of the wormhole. The effluent fluids were analyzed by inductively coupled plasma (ICP) and pH measurements.\u0000 The results for a Kuwaiti crude oil showed the formation of 13 wt% sludge with 15 wt% HCl and it increased to 19 and 30 wt% with increasing acid concentrations to 20 and 28 wt%, respectively. The presence of iron(III) in the system increased the sludge precipitation to 17.8 wt% at 15 wt% HCl and 3,000 ppm iron concentration. The sludging decreased to 7.5 wt% by adding 300 ppm coconut oil to the system. The formation of asphaltene sludge in the carbonate acidizing retards the wormhole propagation. Hence, the injected acid volume to the breakthrough decreased from 1 to 0.4 by adding 300 ppm coconut oil to the acid system. A conical wormhole was formed with the injection of 15 wt% HCl, comparing to a uniform wormhole in the presence of coconut on the acid system. In the case of stimulating the cores with achelating agent (20 wt% GLDA), the coconut oil exceeds the expectations with the minimum pore volume needed to breakthrough compared to the GLDA alone or with the chemical dispersant B.\u0000 This study concluded that the use of dispersant can help reduce the asphaltene sludge and create better acid propagation through the core. The results can be employed to design the optimum acid formulation and create the desired wormhole in carbonate ","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"84 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124520817","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Water is ubiquitous within the shale reservoirs and mainly stored in the hydrophilic clay minerals. The water distribution characteristics are important for the gas-in-place and gas production. In our work, water vapor adsorption on montmorillonite (Mt), kaolinite (Kaol) and illite (Il) were performed to investigate the water adsorption behaviors. Then, the samples were conducted with N2 gas-adsorption techniques to investigate the effect of adsorbed water on pore structure characteristics. The results show that (1) the PSD curves under different RH condition has validated the condensation effect and also demonstrated the heterogeneity of water distribution which varies with the pore scale. Under a certain moisture condition (RH=98%), the small pores (approximately less than 5nm) are blocked with the capillary water while large pores are covered with the adsorbed water film. (2) The pre-adsorbed water occupied more pore volume with the increasing of RH, the corresponding quantitative water saturation based on the nanopore size distribution of moisture-equilibration samples can reach to 51.99%, 71.43% and 46.15% at RH of 98% for Mt, Kaol and Il, respectively. The numerical range is enough to represent the value of actual reservoir. (3) The contribution of clay minerals to the methane adsorption capacity is over overestimated in dry condtion. Under certain water saturation, the smaller pore is filled with capillary water while larger pores are covered with water film, the adsorption forces is changing from solid-gas interaction to liquid-gas interaction. This phenomenon also give the reasonable explanation to the critical water content, Up to a this point, the further increasing of water content would not affected the methane adsorption ability. Therefore, the adsorption for clay minerals can be negligible comparing with the hydrophobic organic pores.
{"title":"The Role of Adsorbed Water on Pore Structure Characteristics and Methane Adsorption of Shale Clay","authors":"Dong Feng, Xingfang Li, Chaojie Zhao, Jing Li, Qing Liu, Minxia He, Wen Zhao, Jiazheng Qin","doi":"10.2118/191233-MS","DOIUrl":"https://doi.org/10.2118/191233-MS","url":null,"abstract":"\u0000 Water is ubiquitous within the shale reservoirs and mainly stored in the hydrophilic clay minerals. The water distribution characteristics are important for the gas-in-place and gas production. In our work, water vapor adsorption on montmorillonite (Mt), kaolinite (Kaol) and illite (Il) were performed to investigate the water adsorption behaviors. Then, the samples were conducted with N2 gas-adsorption techniques to investigate the effect of adsorbed water on pore structure characteristics. The results show that (1) the PSD curves under different RH condition has validated the condensation effect and also demonstrated the heterogeneity of water distribution which varies with the pore scale. Under a certain moisture condition (RH=98%), the small pores (approximately less than 5nm) are blocked with the capillary water while large pores are covered with the adsorbed water film. (2) The pre-adsorbed water occupied more pore volume with the increasing of RH, the corresponding quantitative water saturation based on the nanopore size distribution of moisture-equilibration samples can reach to 51.99%, 71.43% and 46.15% at RH of 98% for Mt, Kaol and Il, respectively. The numerical range is enough to represent the value of actual reservoir. (3) The contribution of clay minerals to the methane adsorption capacity is over overestimated in dry condtion. Under certain water saturation, the smaller pore is filled with capillary water while larger pores are covered with water film, the adsorption forces is changing from solid-gas interaction to liquid-gas interaction. This phenomenon also give the reasonable explanation to the critical water content, Up to a this point, the further increasing of water content would not affected the methane adsorption ability. Therefore, the adsorption for clay minerals can be negligible comparing with the hydrophobic organic pores.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128771507","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Very limited studies were done on the superheated steam-assisted-gravity-drainage (SAGD) process. Besides, study of the effect of physical heating of steam at different state on the productivity during the SAGD process has not been reported. In this paper, a numerical model is proposed to reveal the effect of physical heating on the productivity of a horizontal well pair during the SAGD process. Results show that: (a) the temperature increase of superheated steam plays a weak influence on the productivity of a horizontal well pair during the SAGD process. (b) the heated area increases with the steam quality, while the increase of the heated area under superheated steam injection is not obvious compared with the heated area when the steam quality is equal to 1.0. (c) as the mobility of oil in the steam chamber increases, the fraction of oil produced from the steam chamber increases, and the pressure near the production well increases. (d) when the steam quality increases or becomes superheated steam, the mobility of the oil in the steam chamber increases, and the supply rate of oil near the production well gradually become larger than the decrease rate of oil in the same region induced by elastic energy. This study provides a The paper offers a comprehensive insight into the SAGD process, and helps petroleum engineers for SAGD project design in heavy oil reserves.
{"title":"Effect of Steam State on the Productivity of a Horizontal Well Pair During the Steam-Assisted-Gravity-Drainage Process: Physical Aspect Analysis","authors":"Lin Zhao, Hanqiao Jiang, Fengrui Sun, Junjian Li","doi":"10.2118/191173-MS","DOIUrl":"https://doi.org/10.2118/191173-MS","url":null,"abstract":"\u0000 Very limited studies were done on the superheated steam-assisted-gravity-drainage (SAGD) process. Besides, study of the effect of physical heating of steam at different state on the productivity during the SAGD process has not been reported.\u0000 In this paper, a numerical model is proposed to reveal the effect of physical heating on the productivity of a horizontal well pair during the SAGD process. Results show that: (a) the temperature increase of superheated steam plays a weak influence on the productivity of a horizontal well pair during the SAGD process. (b) the heated area increases with the steam quality, while the increase of the heated area under superheated steam injection is not obvious compared with the heated area when the steam quality is equal to 1.0. (c) as the mobility of oil in the steam chamber increases, the fraction of oil produced from the steam chamber increases, and the pressure near the production well increases. (d) when the steam quality increases or becomes superheated steam, the mobility of the oil in the steam chamber increases, and the supply rate of oil near the production well gradually become larger than the decrease rate of oil in the same region induced by elastic energy. This study provides a\u0000 The paper offers a comprehensive insight into the SAGD process, and helps petroleum engineers for SAGD project design in heavy oil reserves.","PeriodicalId":415543,"journal":{"name":"Day 2 Tue, June 26, 2018","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125168939","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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