Harvesting vast amounts of data has long been identified as an enabler of operational performance. The measurement of key performance indicators is a routine practice in well construction, but a systematic way of statistically analyzing performance against a large data bank of offset wells is not a common practice. The performance of statistical analysis in real time is even more rare. With the introduction of edge computing, devices capable of complex analytical functions in physical proximity to sensors and operations, this practice can be realized. Two case studies are presented: rate of penetration (ROP) and amount of vibration per run. Hypothesis testing is a statistical method in which a sampled dataset is compared against an idealized or status quo model. This model is built using many samples from a population. The characteristics of the population are then inferred from these samples. The model is built in centers where large amounts of data are available. These models are then transferred to an edge device in the field. The device collects real-time data and compares results to the status quo model. In the two cases presented, hypothesis testing was used to determine maximum and minimum levels of ROP and downhole vibration. This information is used to determine the effectiveness of new drilling practices, technologies, or methodologies. Because calculations are performed in real time, changes to drilling practices can be adopted quickly. The ROP case was performed at a US operating unit; the vibration case was performed in a Middle East unit. The models showed what improvement values should be. It was revealing to find wells that were thought to be poor performers were actually well within the population normal. Wells were also found that were thought to be good performers, but where new drilling methods were used, actually fell within the population model and thus suggested that the new methods had not affected performance. By performing this analysis on the edge device, operations can make changes early in such a way that results fall outside the status quo model and deliver real performance improvements. The paper presents the novel use of statistical models calculated in data centers in conjunction with real-time operations. Similar approaches in technical and physics modeling exist in which models are produced in the office and used in the field. However, building models for operations management, from a large bank of offset data, and performing analysis in the field with real-time data is a not common practice. This paper shows both technology and statistical methods that provide a valid scientific framework for operational performance improvement.
{"title":"Using Hypothesis Testing to Evaluate Key Performance Indicators in Real Time: An Edge Computing Use Case","authors":"P. Kowalchuk","doi":"10.2118/195023-MS","DOIUrl":"https://doi.org/10.2118/195023-MS","url":null,"abstract":"\u0000 Harvesting vast amounts of data has long been identified as an enabler of operational performance. The measurement of key performance indicators is a routine practice in well construction, but a systematic way of statistically analyzing performance against a large data bank of offset wells is not a common practice. The performance of statistical analysis in real time is even more rare. With the introduction of edge computing, devices capable of complex analytical functions in physical proximity to sensors and operations, this practice can be realized. Two case studies are presented: rate of penetration (ROP) and amount of vibration per run.\u0000 Hypothesis testing is a statistical method in which a sampled dataset is compared against an idealized or status quo model. This model is built using many samples from a population. The characteristics of the population are then inferred from these samples. The model is built in centers where large amounts of data are available. These models are then transferred to an edge device in the field. The device collects real-time data and compares results to the status quo model. In the two cases presented, hypothesis testing was used to determine maximum and minimum levels of ROP and downhole vibration. This information is used to determine the effectiveness of new drilling practices, technologies, or methodologies. Because calculations are performed in real time, changes to drilling practices can be adopted quickly.\u0000 The ROP case was performed at a US operating unit; the vibration case was performed in a Middle East unit. The models showed what improvement values should be. It was revealing to find wells that were thought to be poor performers were actually well within the population normal. Wells were also found that were thought to be good performers, but where new drilling methods were used, actually fell within the population model and thus suggested that the new methods had not affected performance. By performing this analysis on the edge device, operations can make changes early in such a way that results fall outside the status quo model and deliver real performance improvements.\u0000 The paper presents the novel use of statistical models calculated in data centers in conjunction with real-time operations. Similar approaches in technical and physics modeling exist in which models are produced in the office and used in the field. However, building models for operations management, from a large bank of offset data, and performing analysis in the field with real-time data is a not common practice. This paper shows both technology and statistical methods that provide a valid scientific framework for operational performance improvement.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87582078","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}
Conventional production logging tools proved to be efficient in vertical wells. When it comes to work in horizontal laterals production logging becomes much more complex. Common challenges are layered flow of reservoir fluid, deviation, wellbore accessibility, and stagnant zones along lateral. The tracer technology features a synthesis of a combination of marker-reporters made of a few quantum dots and a mixture of the polymer-based chemical composition. Quantum dots are nanocrystals produced using the process called colloidal synthesis. A single quantum dot is compounded of few hundred atoms and as small as 2-10 nanometer in diameter. Colloidal quantum dots irradiated with a laser emit light of different colors due to quantum confinement. The emittance of a particular specter of light can be detected using flow cytometry method. Several quantum dots joined together creates a unique and traceable marker-reporters element. There could be many unique tracer signatures (over 60). Utilization of quantum dots exclude any chance of misinterpretation while identifying tracers in samples of formation fluid. To achive superior accuracy in tracer identification we use software based on "machine learning". Qualitative and quantitative analysis of quantum dot marker-reporters in samples of formation fluid allows making informed conclusions about the performance of productive intervals of a horizontal well. Application of the technology showed the following benefits: the possibility of monitoring inflows for a long time, in contrast to a one-time logging operation; a significantly lower resource intensity and cost; confidence in conditions when the traditional downhole logging operations are complicated. Quantum dot tracer technology allows solving a number of problems, such as: post-fracturing inflow profile evaluation extended in time; assessment of each production interval in regard to water and oil production; optimization of technical solutions for well completions in the early stages of field development, such as number of ports; analysis of hydrocarbons extraction ratio; detailed information in the analysis of mutual influence of neighbouring wells in the oilfield. The application of the technology is particularly effective in the early diagnosis of water breakthrough, which allows enough time to choose the right technology for water shut off operation. Ultimately, this fact reflects in declining production rates and increasing incurred costs Major benefit is an ability to monitor production per zone at any time during five (5) years after deploying tracer-containing material downhole. Implementation of the technology is time efficient and does not require field equipment as well as crew for operation, which reflects on operating costs carried by customers.
{"title":"Production Logging Using Quantum Dots Tracers®","authors":"Alexey Anopov, K. Ovchinnikov, A. Katashov","doi":"10.2118/195048-MS","DOIUrl":"https://doi.org/10.2118/195048-MS","url":null,"abstract":"\u0000 Conventional production logging tools proved to be efficient in vertical wells. When it comes to work in horizontal laterals production logging becomes much more complex. Common challenges are layered flow of reservoir fluid, deviation, wellbore accessibility, and stagnant zones along lateral. The tracer technology features a synthesis of a combination of marker-reporters made of a few quantum dots and a mixture of the polymer-based chemical composition. Quantum dots are nanocrystals produced using the process called colloidal synthesis. A single quantum dot is compounded of few hundred atoms and as small as 2-10 nanometer in diameter. Colloidal quantum dots irradiated with a laser emit light of different colors due to quantum confinement. The emittance of a particular specter of light can be detected using flow cytometry method. Several quantum dots joined together creates a unique and traceable marker-reporters element. There could be many unique tracer signatures (over 60). Utilization of quantum dots exclude any chance of misinterpretation while identifying tracers in samples of formation fluid. To achive superior accuracy in tracer identification we use software based on \"machine learning\". Qualitative and quantitative analysis of quantum dot marker-reporters in samples of formation fluid allows making informed conclusions about the performance of productive intervals of a horizontal well. Application of the technology showed the following benefits: the possibility of monitoring inflows for a long time, in contrast to a one-time logging operation; a significantly lower resource intensity and cost; confidence in conditions when the traditional downhole logging operations are complicated. Quantum dot tracer technology allows solving a number of problems, such as: post-fracturing inflow profile evaluation extended in time; assessment of each production interval in regard to water and oil production; optimization of technical solutions for well completions in the early stages of field development, such as number of ports; analysis of hydrocarbons extraction ratio; detailed information in the analysis of mutual influence of neighbouring wells in the oilfield. The application of the technology is particularly effective in the early diagnosis of water breakthrough, which allows enough time to choose the right technology for water shut off operation. Ultimately, this fact reflects in declining production rates and increasing incurred costs Major benefit is an ability to monitor production per zone at any time during five (5) years after deploying tracer-containing material downhole. Implementation of the technology is time efficient and does not require field equipment as well as crew for operation, which reflects on operating costs carried by customers.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87997691","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}
The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age. The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales. This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms. The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel. Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).
{"title":"Effects of Reservoir Connectivity with Underlying Mauddud Reservoir and Sand Distribution on Developing Wara Reservoir in the Bahrain Field","authors":"Nadia Nemmawi, D. Michael, Yusuf Buali","doi":"10.2118/194816-MS","DOIUrl":"https://doi.org/10.2118/194816-MS","url":null,"abstract":"\u0000 The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age.\u0000 The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales.\u0000 This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms.\u0000 The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel.\u0000 Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86772994","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}
Peng Chen, Yingcao Zhou, Junjie Wang, Chen Lei, Li Wanjun, Guobin Yang
Tight and extra-low permeability reservoir was usually explored by use of normal underbalanced drilling if the wellbore is stable and the formation pressure is clear. However, precise underbalanced MPD is the optimal technical solution in case the borehole is unstable and the formation pressure is unclear. Moreover, the precise underbalanced MPD would be effective for reservoir protection, enhancement of hydrocarbon discovery, improvement of ROP as well as reduction of well control risk. No oil and gas show were found by previous conventional drilling in a tight granitic basement of Indonesia. The first exploratory well was planned to explore the broken belt of the basement to discover the oil and gas zone, increase drilling efficiency, prevent lost circulation at crushed zone of the basement and minimize drilling troubles by utilization of precise underbalanced MPD in the potential target zone. Underbalanced MPD was achieved by use of low density water-in-oil drilling fluid, and the bottomhole underbalanced pressure fluctuation was accurately and effectively controlled. Underbalanced MPD operation was smoothly completed. Drilling with ignition under balanced managed pressure, connecting triples under balanced managed pressure, and tripping under balanced managed pressure were implemented. Slight under balanced condition of the bottomhole pressure during MPD operation was realized. The backpressure of the wellhead was accurately controlled between 55-135psi during precise MPD operation. 57 times of total accumulate successful ignition lasted 240 hours, which accounts for 80% of the total drilling time. The rate of penetration in tight target granitic formation under balanced drilling was improved and reached 10.8ft/hr. Neither losses nor overflow were detected during underbalanced MPD. Safe and high efficient drilling was realized. Good oil and gas show were observed. Abundant natural gas produced during underbalanced MPD. The basement hydrocarbon reservoir has been obtained important discovery. Application of precise MPD technology could accomplish reservoir discovery and protection, wellbore stability and reduction of well control risk. It prevents ordinary underbalanced drilling from change over traditional overbalanced drilling due to unable to satisfy the safe drilling which would result in secondary damage to the reservoir so as to improve integrated drilling efficiency.
{"title":"Underbalanced MPD of an Exploratory Well in Tight and Extra-Low Permeability Reservoir","authors":"Peng Chen, Yingcao Zhou, Junjie Wang, Chen Lei, Li Wanjun, Guobin Yang","doi":"10.2118/195087-MS","DOIUrl":"https://doi.org/10.2118/195087-MS","url":null,"abstract":"\u0000 Tight and extra-low permeability reservoir was usually explored by use of normal underbalanced drilling if the wellbore is stable and the formation pressure is clear. However, precise underbalanced MPD is the optimal technical solution in case the borehole is unstable and the formation pressure is unclear. Moreover, the precise underbalanced MPD would be effective for reservoir protection, enhancement of hydrocarbon discovery, improvement of ROP as well as reduction of well control risk.\u0000 No oil and gas show were found by previous conventional drilling in a tight granitic basement of Indonesia. The first exploratory well was planned to explore the broken belt of the basement to discover the oil and gas zone, increase drilling efficiency, prevent lost circulation at crushed zone of the basement and minimize drilling troubles by utilization of precise underbalanced MPD in the potential target zone. Underbalanced MPD was achieved by use of low density water-in-oil drilling fluid, and the bottomhole underbalanced pressure fluctuation was accurately and effectively controlled.\u0000 Underbalanced MPD operation was smoothly completed. Drilling with ignition under balanced managed pressure, connecting triples under balanced managed pressure, and tripping under balanced managed pressure were implemented. Slight under balanced condition of the bottomhole pressure during MPD operation was realized. The backpressure of the wellhead was accurately controlled between 55-135psi during precise MPD operation. 57 times of total accumulate successful ignition lasted 240 hours, which accounts for 80% of the total drilling time. The rate of penetration in tight target granitic formation under balanced drilling was improved and reached 10.8ft/hr. Neither losses nor overflow were detected during underbalanced MPD. Safe and high efficient drilling was realized. Good oil and gas show were observed. Abundant natural gas produced during underbalanced MPD. The basement hydrocarbon reservoir has been obtained important discovery.\u0000 Application of precise MPD technology could accomplish reservoir discovery and protection, wellbore stability and reduction of well control risk. It prevents ordinary underbalanced drilling from change over traditional overbalanced drilling due to unable to satisfy the safe drilling which would result in secondary damage to the reservoir so as to improve integrated drilling efficiency.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90666849","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}
Yan Jin, G. Jin, Shujath Ali Syed, M. Jin, S. R. Hussaini
Subsurface unconventional shale samples are always scarce. Outcrop analogs are often used as an alternative to enhance the understanding of the corresponding reservoir formation. One assumption is usually made that rock composition and properties between the outcrop and subsurface samples remain the same or similar, despite differences in their burial and diagenetic histories. This paper presents a comparative case study to investigate the similarities and differences in rock properties between outcrop and subsurface samples from the same formation. Two subsurface and two outcrop samples from the Lower Silurian Longmaxi formation in Sichuan Basin of China were characterized to determine their mineralogical, geochemical, petrophysical, elastic and mechanical properties. Micro-CT images showed that one subsurface sample was drilled normal to the bedding, while other three samples were parallel to the bedding. Two subsurface samples differ in their mineralogy – the horizontal sample is clay-dominant, while the other one is predominantly comprise of quartz, dolomite and calcite minerals, very similar to two outcrop samples. All four samples are thermally immature and their Tmax is less than 435 °C. Subsurface samples have the highest TOC of 3.75% but relatively lower HI and OI. Other pyrolysis parameters are very similar between subsurface and outcrop samples. All samples have very low porosity of less than 2.5% and permeability of less than 9 nD, although subsurface samples have a relatively higher value. The discrepancy in mineralogical composition, especially the clay content, results in different elastic and mechanical behavior of outcrop and subsurface samples. The subsurface sample is highly anisotropic in both compressional and shear wave anisotropy due to the large amount of clay minerals, while one outcrop sample exhibits the strong shear wave anisotropy only and the other one is almost isotropic. Subsurface samples have lower values of Young's modulus, peak stress, Mohr-Coulomb failure parameters and unconfined compressive strength than outcrop samples.
{"title":"Characterization and Comparison of Outcrop and Subsurface Unconventional Shale Samples","authors":"Yan Jin, G. Jin, Shujath Ali Syed, M. Jin, S. R. Hussaini","doi":"10.2118/194709-MS","DOIUrl":"https://doi.org/10.2118/194709-MS","url":null,"abstract":"\u0000 Subsurface unconventional shale samples are always scarce. Outcrop analogs are often used as an alternative to enhance the understanding of the corresponding reservoir formation. One assumption is usually made that rock composition and properties between the outcrop and subsurface samples remain the same or similar, despite differences in their burial and diagenetic histories. This paper presents a comparative case study to investigate the similarities and differences in rock properties between outcrop and subsurface samples from the same formation.\u0000 Two subsurface and two outcrop samples from the Lower Silurian Longmaxi formation in Sichuan Basin of China were characterized to determine their mineralogical, geochemical, petrophysical, elastic and mechanical properties. Micro-CT images showed that one subsurface sample was drilled normal to the bedding, while other three samples were parallel to the bedding. Two subsurface samples differ in their mineralogy – the horizontal sample is clay-dominant, while the other one is predominantly comprise of quartz, dolomite and calcite minerals, very similar to two outcrop samples. All four samples are thermally immature and their Tmax is less than 435 °C. Subsurface samples have the highest TOC of 3.75% but relatively lower HI and OI. Other pyrolysis parameters are very similar between subsurface and outcrop samples. All samples have very low porosity of less than 2.5% and permeability of less than 9 nD, although subsurface samples have a relatively higher value.\u0000 The discrepancy in mineralogical composition, especially the clay content, results in different elastic and mechanical behavior of outcrop and subsurface samples. The subsurface sample is highly anisotropic in both compressional and shear wave anisotropy due to the large amount of clay minerals, while one outcrop sample exhibits the strong shear wave anisotropy only and the other one is almost isotropic. Subsurface samples have lower values of Young's modulus, peak stress, Mohr-Coulomb failure parameters and unconfined compressive strength than outcrop samples.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76851220","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}
Moataz O. Abu-Al-Saud, S. Esmaeilzadeh, H. Tchelepi
Understanding the effect of injected water salinity is becoming crucial, as it has been shown to have a strong impact on the efficiency of oil recovery process. Various experiments have concluded that carbonate wettability is altered when the water ionic-composition is changed. In this work, a numerical investigation of an oil blob mobilized by water is conducted inside a single pore. The presented model studies the synergy effect of multiphase flow and water salinity at the pore level. To model the multiphase flow at the pore-scale, the full hydrodynamic Navier-Stokes equations are solved using direct numerical simulation (DNS). The effect of brine ionic-composition is examined through the electric double layer effect. Experimental zeta potential values, published in the literature, of crude oil/water and water/carbonate interfaces have been employed in the model, which capture the water salinity effect. The simulation results show that the water wetting film surrounding the oil-droplet collapses to an adsorbed nanometer water layer when high salinity water is used. As a result, a large pressure gradient is required to mobilize the oil inside the pore and overcome the attractive surface forces between the oil/water and water/carbonate interfaces. For low-salinity injected water, the carbonate surface becomes more water-wet. The wetting film surrounding the oil blob becomes stable due to the repulsive electric double layer force. Therefore, less energy is required to mobilize the oil blob inside the pore compared to high water salinity. The effect of solid roughness and injected water flow rate are also studied, which show to have a strong impact on the oil displacement efficiency. The novelty of the numerical method lies in efficiently capturing the nanoscale effect of the electric double layer in pore-scale multiphase flow at the microscale. The simulation results provide fundamental insights on the efficiency of low-salinity waterflooding at the pore level.
{"title":"Insights into the Impact of Water Salinity on Multiphase Flow at the Pore-Scale in Carbonate Formations","authors":"Moataz O. Abu-Al-Saud, S. Esmaeilzadeh, H. Tchelepi","doi":"10.2118/194985-MS","DOIUrl":"https://doi.org/10.2118/194985-MS","url":null,"abstract":"\u0000 Understanding the effect of injected water salinity is becoming crucial, as it has been shown to have a strong impact on the efficiency of oil recovery process. Various experiments have concluded that carbonate wettability is altered when the water ionic-composition is changed. In this work, a numerical investigation of an oil blob mobilized by water is conducted inside a single pore. The presented model studies the synergy effect of multiphase flow and water salinity at the pore level.\u0000 To model the multiphase flow at the pore-scale, the full hydrodynamic Navier-Stokes equations are solved using direct numerical simulation (DNS). The effect of brine ionic-composition is examined through the electric double layer effect. Experimental zeta potential values, published in the literature, of crude oil/water and water/carbonate interfaces have been employed in the model, which capture the water salinity effect.\u0000 The simulation results show that the water wetting film surrounding the oil-droplet collapses to an adsorbed nanometer water layer when high salinity water is used. As a result, a large pressure gradient is required to mobilize the oil inside the pore and overcome the attractive surface forces between the oil/water and water/carbonate interfaces. For low-salinity injected water, the carbonate surface becomes more water-wet. The wetting film surrounding the oil blob becomes stable due to the repulsive electric double layer force. Therefore, less energy is required to mobilize the oil blob inside the pore compared to high water salinity. The effect of solid roughness and injected water flow rate are also studied, which show to have a strong impact on the oil displacement efficiency.\u0000 The novelty of the numerical method lies in efficiently capturing the nanoscale effect of the electric double layer in pore-scale multiphase flow at the microscale. The simulation results provide fundamental insights on the efficiency of low-salinity waterflooding at the pore level.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84658836","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}
V. Beunat, N. Pannacci, G. Batôt, N. Gland, E. Chevallier, A. Cuenca
Foam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows. A new coreflooding set-up is designed for ‘mesoscopic’ cores (2.5 cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions (up to 200 bar and 60 °C). This set-up was first validated by repeating experiments performed previously on classical corefloods with 4 cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration. All experiments were performed with Clashach sandstones cores having approximatively 16 % porosity and 600 mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638 kg/m3 at P = 160 bar, T = 60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities. All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30 % in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without. Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopely provide some guidance for future foam studies and raise awareness on the importance of these parameters.
泡沫工艺旨在通过气体流动性控制来提高气基注入方法的效率。它们已成功应用于各种EOR环境，包括co2 EOR的CCUS、稠油油藏的注蒸汽以及裂缝性油藏。这种工艺的成功取决于多种因素，其中表面活性剂、油和岩石之间的相互作用起着关键作用。本研究的目的是通过关注润湿性和含油饱和度对二氧化碳泡沫流动行为的影响来提供初步答案。新的岩心驱油装置专为“介观”岩心(直径2.5 cm)设计，以便进行泡沫配方筛选，并在储层条件下(高达200 bar和60°C)进行更快的泡沫注入测试。该装置首先通过重复先前在直径为4厘米的经典岩心驱替中进行的实验进行了验证。在相同的操作条件下，在显著减少测试持续时间的情况下，获得了迁移率降低方面的类似结果。所有实验均采用了孔隙度约为16%、渗透率约为600 mD的Clashach砂岩岩心。研究了两种气体组成:(1)稠密的超临界CO2(在P = 160 bar, T = 60℃时密度为638 kg/m3)和(2)CO2和CH4的非稠密气体混合物。对于每种气体成分，进行了四次泡沫注入测试:两次在水湿岩石样品上进行，另外两次在原油老化岩心样品上进行，并且在没有和存在石油的情况下进行。阴离子表面活性剂配方与气体共注入，气体分数为0.7。泡沫流变是通过扫描间隙速度来测量泡沫表观粘度来评估的。在致密条件下进行的所有测试都强调了强泡沫的产生，其呈现剪切变薄的流变行为;表观粘度随间隙速度的幂律而减小。观察到润湿性对泡沫表观粘度的影响，在润湿性改变的岩石样品中，泡沫表观粘度下降了30%。当样品最初在Swi饱和时，表观粘度水平总体保持不变，但有油的泡沫初始形成动力学比没有油的慢。泡沫驱实验有时只是在有油的情况下进行，而不考虑润湿性的影响，润湿性似乎与油饱和度本身一样重要，甚至更重要。这些结果有望为今后的泡沫研究提供一些指导，并提高人们对这些参数重要性的认识。
{"title":"Study on the Impact of Core Wettability and Oil Saturation on the Rheological Behavior of CO2-Foams","authors":"V. Beunat, N. Pannacci, G. Batôt, N. Gland, E. Chevallier, A. Cuenca","doi":"10.2118/194963-MS","DOIUrl":"https://doi.org/10.2118/194963-MS","url":null,"abstract":"\u0000 Foam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows.\u0000 A new coreflooding set-up is designed for ‘mesoscopic’ cores (2.5 cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions (up to 200 bar and 60 °C). This set-up was first validated by repeating experiments performed previously on classical corefloods with 4 cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration.\u0000 All experiments were performed with Clashach sandstones cores having approximatively 16 % porosity and 600 mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638 kg/m3 at P = 160 bar, T = 60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities.\u0000 All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30 % in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without.\u0000 Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopely provide some guidance for future foam studies and raise awareness on the importance of these parameters.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80273303","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}
Ali K. Alhuraishawy, Xindi Sun, B. Bai, Mingzhen Wei, A. Almansour
The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. The main objective of this study was to determine whether the coupling technologies can improve conformance control in fractured sandstone reservoirs. Before the study was conducted, the effects of low salinity waterflooding, number of fractures, and PPG strength were studied. The PPG was injected into the fracture at a flow rate of 2.0 ml/min. Brine was injected at a different flow rate after PPG placement to test the effect of flow rate on the PPG's plugging efficiency. Laboratory experiments showed that the oil recovery factor and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. However, the PPG extruded pressure decreased when the PPG swelled in a low-brine concentration. At a high-flow rate, there was no significant effect on the Frrw. Coupling two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.
{"title":"Conformance Control Improvement by Coupling Microgel and Low Salinity Waterflooding in Fractured Reservoirs","authors":"Ali K. Alhuraishawy, Xindi Sun, B. Bai, Mingzhen Wei, A. Almansour","doi":"10.2118/194767-MS","DOIUrl":"https://doi.org/10.2118/194767-MS","url":null,"abstract":"\u0000 The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency.\u0000 The main objective of this study was to determine whether the coupling technologies can improve conformance control in fractured sandstone reservoirs. Before the study was conducted, the effects of low salinity waterflooding, number of fractures, and PPG strength were studied. The PPG was injected into the fracture at a flow rate of 2.0 ml/min. Brine was injected at a different flow rate after PPG placement to test the effect of flow rate on the PPG's plugging efficiency. Laboratory experiments showed that the oil recovery factor and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. However, the PPG extruded pressure decreased when the PPG swelled in a low-brine concentration. At a high-flow rate, there was no significant effect on the Frrw. Coupling two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90967142","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}
Asmaa Al-Obaidli, A. Al-Nasheet, F. Snasiri, O. Al-Shammari, Asrar Al-Shammari, S. Sinha, Y. Amjad, Doris L. González, Fabio Gonzalez
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery
{"title":"Understanding Reservoir Fluid Behavior to Mitigate Risk Associated to Asphaltene Deposition in the Reservoir Rock Near to Asphaltene Onset Pressure AOP in the Magwa Marrat Depleted Reservoir","authors":"Asmaa Al-Obaidli, A. Al-Nasheet, F. Snasiri, O. Al-Shammari, Asrar Al-Shammari, S. Sinha, Y. Amjad, Doris L. González, Fabio Gonzalez","doi":"10.2118/195065-MS","DOIUrl":"https://doi.org/10.2118/195065-MS","url":null,"abstract":"\u0000 The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential\u0000 Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study.\u0000 Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia.\u0000 Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78991381","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}
A heterogeneous and complex carbonate reservoir consists of many sub-layers. Each layer has unique characteristics. To enable comprehensive reservoir characterization, logging while-drilling technologies comprising high-resolution electrical imager, magnetic resonance and formation pressure tester were deployed. The integration of logging data had delivered detailed interpretation and proposes of a new workflow for best practice to advance reservoir performance and to optimize completion design. Magnetic resonance was acquired with dual-wait time enabled T2 polarization to differentiate between moveable water and hydrocarbon. After acquisition, standard deliverables were porosity and permeability index. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Following good test results from the formation pressure tester, the permeability index from magnetic resonance was calibrated to mobility. Then rock quality was interpreted based on Lorenz Plot and permeability-calibrated to effective porosity ratio. The ratio was classified to high, low and no flow unit zones. The classification based on gradient of the ratio. Steeper gradient inferred high flow, lower gradient inferred low flow and flat gradient inferred no flow. To advance reservoir characterizations, flow unit zones were integrated to sedimentary facies interpretation. The interpretation was conducted based on high-resolution electrical imager. The analyzed reservoir was divided in 23 flow units. The flow units were useful to identify reservoir compartments. Similar flow units were combined into one compartment. There are 3 intervals of high flow, 3 to 4 intervals of low flow and 4 intervals of no flow. The interval definition was used to design the completion. For best point of the completion within the intervals, high resolution electrical imager interpretation had added valuable input. Categories for best point in this particular study were homogeneous and less-cemented facies. The interval for best point would be varies based in completion strategy. The expectation result of the integrated logging data was to deliver maximum and stable flow rate with efficient completion design and advance the understanding of reservoir characterization. In addition, sedimentary facies interpretation was being correlated with the fluid flow behavior. In high-density cement intervals, permeability is low. In porous high-resistive sedimentary facies, the permeability is high. This inferred, the matrix and cement in the formation were affecting the fluid flow behavior. The integration of logging data had resulted comprehensive reservoir characterization. The integration lead to completion optimization to advance reservoir performance and develop a comprehensive workflow. The workflow had combined petrophysical analysis, reservoir information and geological interpretation. This workflow would be best practice to be implement to advance complex c
{"title":"Advancing Carbonate Complex Reservoir Characterizations Using Integrated Logging Technologies","authors":"H. Ibrahim, C. Nugroho, M. Ghioca, L. Việt","doi":"10.2118/194866-MS","DOIUrl":"https://doi.org/10.2118/194866-MS","url":null,"abstract":"\u0000 A heterogeneous and complex carbonate reservoir consists of many sub-layers. Each layer has unique characteristics. To enable comprehensive reservoir characterization, logging while-drilling technologies comprising high-resolution electrical imager, magnetic resonance and formation pressure tester were deployed. The integration of logging data had delivered detailed interpretation and proposes of a new workflow for best practice to advance reservoir performance and to optimize completion design.\u0000 Magnetic resonance was acquired with dual-wait time enabled T2 polarization to differentiate between moveable water and hydrocarbon. After acquisition, standard deliverables were porosity and permeability index. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Following good test results from the formation pressure tester, the permeability index from magnetic resonance was calibrated to mobility. Then rock quality was interpreted based on Lorenz Plot and permeability-calibrated to effective porosity ratio. The ratio was classified to high, low and no flow unit zones. The classification based on gradient of the ratio. Steeper gradient inferred high flow, lower gradient inferred low flow and flat gradient inferred no flow. To advance reservoir characterizations, flow unit zones were integrated to sedimentary facies interpretation. The interpretation was conducted based on high-resolution electrical imager.\u0000 The analyzed reservoir was divided in 23 flow units. The flow units were useful to identify reservoir compartments. Similar flow units were combined into one compartment. There are 3 intervals of high flow, 3 to 4 intervals of low flow and 4 intervals of no flow. The interval definition was used to design the completion. For best point of the completion within the intervals, high resolution electrical imager interpretation had added valuable input. Categories for best point in this particular study were homogeneous and less-cemented facies. The interval for best point would be varies based in completion strategy. The expectation result of the integrated logging data was to deliver maximum and stable flow rate with efficient completion design and advance the understanding of reservoir characterization. In addition, sedimentary facies interpretation was being correlated with the fluid flow behavior. In high-density cement intervals, permeability is low. In porous high-resistive sedimentary facies, the permeability is high. This inferred, the matrix and cement in the formation were affecting the fluid flow behavior.\u0000 The integration of logging data had resulted comprehensive reservoir characterization. The integration lead to completion optimization to advance reservoir performance and develop a comprehensive workflow. The workflow had combined petrophysical analysis, reservoir information and geological interpretation. This workflow would be best practice to be implement to advance complex c","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79452748","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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