Circulation loss is one of the most serious and complex hindrances for normal and safe drilling operations. Detecting the layer at which the circulation loss has occurred is important for formulating technical measures related to leakage prevention and plugging and reducing the wastage because of circulation loss as much as possible. Unfortunately, because of the lack of a general method for predicting the potential location of circulation loss during drilling, most current procedures depend on the plugging test. Therefore, the aim of this study was to use an Artificial Intelligence (AI)-based method to screen and process the historical data of 240 wells and 1029 original well loss cases in a localized area of southwestern China and to perform data mining. Using comparative analysis involving the Genetic Algorithm-Back Propagation (GA-BP) neural network and random forest optimization algorithms, we proposed an efficient real-time model for predicting leakage layer locations. For this purpose, data processing and correlation analysis were first performed using existing data to improve the effects of data mining. The well history data was then divided into training and testing sets in a 3:1 ratio. The parameter values of the BP were then corrected as per the network training error, resulting in the final output of a prediction value with a globally optimal solution. The standard random forest model is a particularly capable model that can deal with high-dimensional data without feature selection. To evaluate and confirm the generated model, the model is applied to eight oil wells in a well site in southwestern China. Empirical results demonstrate that the proposed method can satisfy the requirements of actual application to drilling and plugging operations and is able to accurately predict the locations of leakage layers.
{"title":"Prediction of drilling leakage locations based on optimized neural networks and the standard random forest method","authors":"Su Junlin, Zhao Yang, He Tao, Luo Pingya","doi":"10.2516/OGST/2021003","DOIUrl":"https://doi.org/10.2516/OGST/2021003","url":null,"abstract":"Circulation loss is one of the most serious and complex hindrances for normal and safe drilling operations. Detecting the layer at which the circulation loss has occurred is important for formulating technical measures related to leakage prevention and plugging and reducing the wastage because of circulation loss as much as possible. Unfortunately, because of the lack of a general method for predicting the potential location of circulation loss during drilling, most current procedures depend on the plugging test. Therefore, the aim of this study was to use an Artificial Intelligence (AI)-based method to screen and process the historical data of 240 wells and 1029 original well loss cases in a localized area of southwestern China and to perform data mining. Using comparative analysis involving the Genetic Algorithm-Back Propagation (GA-BP) neural network and random forest optimization algorithms, we proposed an efficient real-time model for predicting leakage layer locations. For this purpose, data processing and correlation analysis were first performed using existing data to improve the effects of data mining. The well history data was then divided into training and testing sets in a 3:1 ratio. The parameter values of the BP were then corrected as per the network training error, resulting in the final output of a prediction value with a globally optimal solution. The standard random forest model is a particularly capable model that can deal with high-dimensional data without feature selection. To evaluate and confirm the generated model, the model is applied to eight oil wells in a well site in southwestern China. Empirical results demonstrate that the proposed method can satisfy the requirements of actual application to drilling and plugging operations and is able to accurately predict the locations of leakage layers.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"11 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86750039","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Steady state relative permeability experiments are performed by co-injection of two fluids through core plug samples. Effective relative permeabilities can be calculated from the stabilized pressure drop using Darcy’s law and linked to the corresponding average saturation of the core. These estimated relative permeability points will be accurate only if capillary end effects and transient effects are negligible. This work presents general analytical solutions for calculation of spatial saturation and pressure gradient profiles, average saturation, pressure drop and relative permeabilities for a core at steady state when capillary end effects are significant. We derive an intuitive and general “intercept” method for correcting steady state relative permeability measurements for capillary end effects: plotting average saturation and inverse effective relative permeability (of each phase) against inverse total rate will give linear trends at high total rates and result in corrected relative permeability points when extrapolated to zero inverse total rate (infinite rate). We derive a formal proof and generalization of the method proposed by Gupta and Maloney (2016) [SPE Reserv. Eval. Eng. 19, 02, 316–330], also extending the information obtained from the analysis, especially allowing to calculate capillary pressure. It is shown how the slopes of the lines are related to the saturation functions allowing to scale all test data for all conditions to the same straight lines. Two dimensionless numbers are obtained that directly express how much the average saturation is changed and the effective relative permeabilities are reduced compared to values unaffected by end effects. The numbers thus quantitatively and intuitively express the influence of end effects. A third dimensionless number is derived providing a universal criterion for when the intercept method is valid, directly stating that the end effect profile has reached the inlet. All the dimensionless numbers contain a part depending only on saturation functions, injected flow fraction and viscosity ratio and a second part containing constant known fluid, rock and system parameters such as core length, porosity, interfacial tension, total rate, etc. The former parameters determine the saturation range and shape of the saturation profile, while the latter number determines how much the profile is compressed towards the outlet. End effects cause the saturation profile and average saturation to shift towards the saturation where capillary pressure is zero and the effective relative permeabilities to be reduced compared to the true relative permeabilities. This shift is greater at low total rate and gives a false impression of rate-dependent relative permeabilities. The method is demonstrated with multiple examples. Methodologies for deriving relative permeability and capillary pressure systematically and consistently, even based on combining data from tests with different fluid and core properties, a
{"title":"Analytical modeling and correction of steady state relative permeability experiments with capillary end effects – An improved intercept method, scaling and general capillary numbers","authors":"P. Andersen","doi":"10.2516/ogst/2021045","DOIUrl":"https://doi.org/10.2516/ogst/2021045","url":null,"abstract":"Steady state relative permeability experiments are performed by co-injection of two fluids through core plug samples. Effective relative permeabilities can be calculated from the stabilized pressure drop using Darcy’s law and linked to the corresponding average saturation of the core. These estimated relative permeability points will be accurate only if capillary end effects and transient effects are negligible. This work presents general analytical solutions for calculation of spatial saturation and pressure gradient profiles, average saturation, pressure drop and relative permeabilities for a core at steady state when capillary end effects are significant. We derive an intuitive and general “intercept” method for correcting steady state relative permeability measurements for capillary end effects: plotting average saturation and inverse effective relative permeability (of each phase) against inverse total rate will give linear trends at high total rates and result in corrected relative permeability points when extrapolated to zero inverse total rate (infinite rate). We derive a formal proof and generalization of the method proposed by Gupta and Maloney (2016) [SPE Reserv. Eval. Eng. 19, 02, 316–330], also extending the information obtained from the analysis, especially allowing to calculate capillary pressure. It is shown how the slopes of the lines are related to the saturation functions allowing to scale all test data for all conditions to the same straight lines. Two dimensionless numbers are obtained that directly express how much the average saturation is changed and the effective relative permeabilities are reduced compared to values unaffected by end effects. The numbers thus quantitatively and intuitively express the influence of end effects. A third dimensionless number is derived providing a universal criterion for when the intercept method is valid, directly stating that the end effect profile has reached the inlet. All the dimensionless numbers contain a part depending only on saturation functions, injected flow fraction and viscosity ratio and a second part containing constant known fluid, rock and system parameters such as core length, porosity, interfacial tension, total rate, etc. The former parameters determine the saturation range and shape of the saturation profile, while the latter number determines how much the profile is compressed towards the outlet. End effects cause the saturation profile and average saturation to shift towards the saturation where capillary pressure is zero and the effective relative permeabilities to be reduced compared to the true relative permeabilities. This shift is greater at low total rate and gives a false impression of rate-dependent relative permeabilities. The method is demonstrated with multiple examples. Methodologies for deriving relative permeability and capillary pressure systematically and consistently, even based on combining data from tests with different fluid and core properties, a","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"472 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77529264","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Supercharging in the vicinity of a borehole is an important factor that affects formation damage and drilling safety, and the filter cake growth process has a significant impact on supercharging in the vicinity of the borehole. However, existing models that predict pore pressure distribution overlook dynamic filter cake growth. Thus, an analytical supercharging model was developed that considers time-dependent filter cake effects, and this model was verified using a two-dimensional numerical model. The influences of filter cake, formation, and filtrate properties on supercharging were investigated systematically. The results indicate that time-dependent filter cake effects have significant influence on supercharging. Supercharging increases in the early stage but decreases over time because of the dynamic growth of filter cake, and the supercharging magnitude decreases along the radial direction. Because of filter cake growth, the magnitude of supercharging falls quickly across the filter cake, and the decreased magnitude of pore pressure caused by the filter cake increases. Supercharging in low-permeability formations is more obvious and the faster rate of filter cake growth, a lower filtrate viscosity and faster reduction rate of filter cake permeability can help to weaken supercharging. The order of importance of influencing factors on supercharging is overbalance pressure > formation permeability > formation porosity ≈ filtrate viscosity > filter cake permeability attenuation coefficient > initial filter cake permeability control ratio > filter cake growth coefficient > filter cake porosity. To alleviate supercharging in the vicinity of the borehole, adopting drilling fluids that allow a filter cake to form quickly, optimizing drilling fluid with a lower filtrate viscosity, keeping a smaller overbalance pressure, and precise operation at the rig site are suggested for low-permeability formations during drilling.
{"title":"Transient response of near-wellbore supercharging during filter cake growth","authors":"Tianshou Ma, Nian Peng, Ping Chen, Yang Liu","doi":"10.2516/ogst/2021028","DOIUrl":"https://doi.org/10.2516/ogst/2021028","url":null,"abstract":"Supercharging in the vicinity of a borehole is an important factor that affects formation damage and drilling safety, and the filter cake growth process has a significant impact on supercharging in the vicinity of the borehole. However, existing models that predict pore pressure distribution overlook dynamic filter cake growth. Thus, an analytical supercharging model was developed that considers time-dependent filter cake effects, and this model was verified using a two-dimensional numerical model. The influences of filter cake, formation, and filtrate properties on supercharging were investigated systematically. The results indicate that time-dependent filter cake effects have significant influence on supercharging. Supercharging increases in the early stage but decreases over time because of the dynamic growth of filter cake, and the supercharging magnitude decreases along the radial direction. Because of filter cake growth, the magnitude of supercharging falls quickly across the filter cake, and the decreased magnitude of pore pressure caused by the filter cake increases. Supercharging in low-permeability formations is more obvious and the faster rate of filter cake growth, a lower filtrate viscosity and faster reduction rate of filter cake permeability can help to weaken supercharging. The order of importance of influencing factors on supercharging is overbalance pressure > formation permeability > formation porosity ≈ filtrate viscosity > filter cake permeability attenuation coefficient > initial filter cake permeability control ratio > filter cake growth coefficient > filter cake porosity. To alleviate supercharging in the vicinity of the borehole, adopting drilling fluids that allow a filter cake to form quickly, optimizing drilling fluid with a lower filtrate viscosity, keeping a smaller overbalance pressure, and precise operation at the rig site are suggested for low-permeability formations during drilling.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"43 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79385410","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The nonlinear differential equation describing flow of a constant compressibility liquid in a porous medium is examined in terms of the Kirchhoff and Cole-Hopf transformations. A quantitative measure of the applicability of representing flow by a slightly compressible liquid – which leads to a linear differential equation, the Theis equation – is identified. The classical Theis problem and the finite-well-radius problem in a system that is infinite in its areal extent are used as prototypes to address concepts discussed. This choice is dictated by the ubiquity of solutions that depend on these archetypal examples for examining transient diffusion. Notwithstanding that the Kirchhoff and Cole-Hopf transformations arrive at a linear differential equation, for the specific purposes of this work – the estimation of the hydraulic properties of rocks, the Kirchhoff transformation is much more advantageous in a number of ways; these are documented. Insights into the structure of the nonlinear solution are provided. The results of this work should prove useful in many contexts of mathematical physics though developed in the framework of applications pertaining to the earth sciences.
{"title":"Addressing nonlinear transient diffusion in porous media through transformations","authors":"R. Raghavan, Chih-Cheng Chen","doi":"10.2516/ogst/2021064","DOIUrl":"https://doi.org/10.2516/ogst/2021064","url":null,"abstract":"The nonlinear differential equation describing flow of a constant compressibility liquid in a porous medium is examined in terms of the Kirchhoff and Cole-Hopf transformations. A quantitative measure of the applicability of representing flow by a slightly compressible liquid – which leads to a linear differential equation, the Theis equation – is identified. The classical Theis problem and the finite-well-radius problem in a system that is infinite in its areal extent are used as prototypes to address concepts discussed. This choice is dictated by the ubiquity of solutions that depend on these archetypal examples for examining transient diffusion. Notwithstanding that the Kirchhoff and Cole-Hopf transformations arrive at a linear differential equation, for the specific purposes of this work – the estimation of the hydraulic properties of rocks, the Kirchhoff transformation is much more advantageous in a number of ways; these are documented. Insights into the structure of the nonlinear solution are provided. The results of this work should prove useful in many contexts of mathematical physics though developed in the framework of applications pertaining to the earth sciences.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"1 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82362968","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Jian Han, Pan Gao, Zhimin Cao, Jing Li, Sijie Wang, Can Yang
Unconventional remaining oil and gas resources such as tight oil, shale oil, and coalbed gas are currently the focus of the exploration and development of major oil fields all over the world. Therefore, to make best understand of target reservoirs, enhancing the vertical resolution of well log data is crucial important. However, in the face of the continuous low-level fluctuations of international oil price, large scale use of expensive high resolution well logging hardware tools has always been unaffordable and unacceptable. In another aspect, traditional well log interpolation methods can always not realize high reliable information enhancement for crucial high frequency components. In this paper, in order to improve the well log data super-resolution performance, we propose for the first time to employ Locally Linear Embedding (LLE) technique to reveal the nonlinear mapping relationship between 2-times-scale-difference well log data. Several super resolution experiments with well log data from a given area of Daqing Oil field, China, were conducted. Experimental results illustrated that the proposed LLE-based method can efficiently achieve more reliable super-resolution results than other state-of-the-art methods.
{"title":"Well log data super-resolution based on locally linear embedding","authors":"Jian Han, Pan Gao, Zhimin Cao, Jing Li, Sijie Wang, Can Yang","doi":"10.2516/ogst/2021042","DOIUrl":"https://doi.org/10.2516/ogst/2021042","url":null,"abstract":"Unconventional remaining oil and gas resources such as tight oil, shale oil, and coalbed gas are currently the focus of the exploration and development of major oil fields all over the world. Therefore, to make best understand of target reservoirs, enhancing the vertical resolution of well log data is crucial important. However, in the face of the continuous low-level fluctuations of international oil price, large scale use of expensive high resolution well logging hardware tools has always been unaffordable and unacceptable. In another aspect, traditional well log interpolation methods can always not realize high reliable information enhancement for crucial high frequency components. In this paper, in order to improve the well log data super-resolution performance, we propose for the first time to employ Locally Linear Embedding (LLE) technique to reveal the nonlinear mapping relationship between 2-times-scale-difference well log data. Several super resolution experiments with well log data from a given area of Daqing Oil field, China, were conducted. Experimental results illustrated that the proposed LLE-based method can efficiently achieve more reliable super-resolution results than other state-of-the-art methods.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"48 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89269342","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This contribution deals with about selective conversion of heavy gas oils into middle distillates fuels that meet ultra-low sulfur and aromatic compound quality standards by using a novel NiWRu/TiO2–γAl2O3 catalyst under typical hydrotreatment conditions. A diesel fuel fraction having sulfur, nitrogen and aromatics compound content of about 50 ppm, 10 ppm and 15 v%, respectively, was obtained when the reactor was operated at T = 370 °C, P = 12.4 MPa, LHSV = 0.5 h−1 and H2/hydrocarbon ratio = 800 Nm3/m3. Titanium and ruthenium additives used in the preparation of the NiWRu/TiO2–γAl2O3 catalyst, remarkably improved the catalytic activities for the hydrogenolysis, hydrogenation and hydrocracking reactions compared to the reference NiW/γAl2O3 catalyst. The coprecipitation of titanium and aluminum hydroxides produced a catalyst support having greater surface area, pore volume and surface acidity. An improvement in mechanical properties of the support extrudates was also observed. Characterization analysis by XPS, AUGER and XRD techniques of the TiO2–γAl2O3 support suggested the formation of an aluminum-titanate mixed phase (AlxTiyOz) having a non-well-defined stoichiometry. The NiW/TiO2–γAl2O3 and NiWRu/TiO2–γAl2O3 exhibited a greater surface dispersion of the supported nickel and tungsten species compared to the NiW/γAl2O3 catalyst. The promoter effect of ruthenium on the NiW bimetallic system caused a strong increase in both hydrogenolysis and hydrogenation reactions. Hydrodenitrogenation and hydrocracking reactions were also favored by the increase in the hydrogenation capacity and in the surface acidity of the catalyst. The highest conversion levels for all investigated reactions were obtained when the NiWRu/TiO2–γAl2O3 catalyst was prepared by co-impregnation of Ni and Ru in a second step. This catalyst showed sulfur tolerance properties when the reaction was conducted in the presence of different H2S partial pressures. The catalytic behavior of the NiWRu/TiO2–γAl2O3 catalyst was explained by the existence of a promoting effect between separated Ni and Ru sulfides species and the NiWS phase (dual mechanism).
{"title":"Conversion of heavy gasoil into ultra-low sulfur and aromatic diesel over NiWRu/TiO2–γAl2O3 catalysts: Role of titanium and ruthenium on improving catalytic activity","authors":"R. P. Silvy, S. K. Lageshetty","doi":"10.2516/ogst/2020084","DOIUrl":"https://doi.org/10.2516/ogst/2020084","url":null,"abstract":"This contribution deals with about selective conversion of heavy gas oils into middle distillates fuels that meet ultra-low sulfur and aromatic compound quality standards by using a novel NiWRu/TiO2–γAl2O3 catalyst under typical hydrotreatment conditions. A diesel fuel fraction having sulfur, nitrogen and aromatics compound content of about 50 ppm, 10 ppm and 15 v%, respectively, was obtained when the reactor was operated at T = 370 °C, P = 12.4 MPa, LHSV = 0.5 h−1 and H2/hydrocarbon ratio = 800 Nm3/m3. Titanium and ruthenium additives used in the preparation of the NiWRu/TiO2–γAl2O3 catalyst, remarkably improved the catalytic activities for the hydrogenolysis, hydrogenation and hydrocracking reactions compared to the reference NiW/γAl2O3 catalyst. The coprecipitation of titanium and aluminum hydroxides produced a catalyst support having greater surface area, pore volume and surface acidity. An improvement in mechanical properties of the support extrudates was also observed. Characterization analysis by XPS, AUGER and XRD techniques of the TiO2–γAl2O3 support suggested the formation of an aluminum-titanate mixed phase (AlxTiyOz) having a non-well-defined stoichiometry. The NiW/TiO2–γAl2O3 and NiWRu/TiO2–γAl2O3 exhibited a greater surface dispersion of the supported nickel and tungsten species compared to the NiW/γAl2O3 catalyst. The promoter effect of ruthenium on the NiW bimetallic system caused a strong increase in both hydrogenolysis and hydrogenation reactions. Hydrodenitrogenation and hydrocracking reactions were also favored by the increase in the hydrogenation capacity and in the surface acidity of the catalyst. The highest conversion levels for all investigated reactions were obtained when the NiWRu/TiO2–γAl2O3 catalyst was prepared by co-impregnation of Ni and Ru in a second step. This catalyst showed sulfur tolerance properties when the reaction was conducted in the presence of different H2S partial pressures. The catalytic behavior of the NiWRu/TiO2–γAl2O3 catalyst was explained by the existence of a promoting effect between separated Ni and Ru sulfides species and the NiWS phase (dual mechanism).","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"67 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-12-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79843006","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.
{"title":"Experimental study of combined low salinity and surfactant flooding effect on oil recovery","authors":"Abdulmecit Araz, Farad Kamyabi","doi":"10.2118/175614-MS","DOIUrl":"https://doi.org/10.2118/175614-MS","url":null,"abstract":"A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection.\u0000In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation.\u0000The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding.\u0000Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"65 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-12-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84432750","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ahmed Alalimi, Lin Pan, M. A. Al-qaness, A. Ewees, Xiao Wang, M. A. Abd Elaziz
In China, Tahe Triassic oil field block 9 reservoir was discovered in 2002 by drilling wells S95 and S100. The distribution of the reservoir sand body is not clear. Therefore, it is necessary to study and to predict oil production from this oil field. In this study, we propose an improved Random Vector Functional Link (RVFL) network to predict oil production from Tahe oil field in China. The Spherical Search Optimizer (SSO) is applied to optimize the RVFL and to enhance its performance, where SSO works as a local search method that improved the parameters of the RVFL. We used a historical dataset of this oil field from 2002 to 2014 collected by a local partner. Our proposed model, called SSO-RVFL, has been evaluated with extensive comparisons to several optimization methods. The outcomes showed that, SSO-RVFL achieved accurate predictions and the SSO outperformed several optimization methods.
{"title":"Optimized Random Vector Functional Link network to predict oil production from Tahe oil field in China","authors":"Ahmed Alalimi, Lin Pan, M. A. Al-qaness, A. Ewees, Xiao Wang, M. A. Abd Elaziz","doi":"10.2516/ogst/2020081","DOIUrl":"https://doi.org/10.2516/ogst/2020081","url":null,"abstract":"In China, Tahe Triassic oil field block 9 reservoir was discovered in 2002 by drilling wells S95 and S100. The distribution of the reservoir sand body is not clear. Therefore, it is necessary to study and to predict oil production from this oil field. In this study, we propose an improved Random Vector Functional Link (RVFL) network to predict oil production from Tahe oil field in China. The Spherical Search Optimizer (SSO) is applied to optimize the RVFL and to enhance its performance, where SSO works as a local search method that improved the parameters of the RVFL. We used a historical dataset of this oil field from 2002 to 2014 collected by a local partner. Our proposed model, called SSO-RVFL, has been evaluated with extensive comparisons to several optimization methods. The outcomes showed that, SSO-RVFL achieved accurate predictions and the SSO outperformed several optimization methods.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"37 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85789013","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
I. Prundeanu, C. Chelariu, David Rafael Contreras Perez
The precise landing and steering of horizontal wells using conventional mudlogging and Logging While Drilling (LWD) data is a particular challenge for the Lebăda Field, offshore Romania. The use of a new technique of elemental geochemistry analysis (or chemosteering) became an option for the identification of Cenomanian, Turonian–Coniacian–Santonian, Campanian and Eocene strata. This has enabled more accurate placement of the horizontal development wells within the desired reservoir target interval. Geochemical data enabled the identification of chemostratigraphic zones C1, C2, C3 and zone R that correspond to the reservoir section. The application is a result of the geochemical zonation performed using elements and ratios that are sensitive to depositional environment, sea level change, heavy mineral concentrations and siliciclastic input namely: Sr/Ca, Zr/Th, Si/Zr and Si/K. In ascending stratigraphic order, the ratio thresholds of zone C3 are Zr/Th > 11, Sr/Ca > 1.1, Si/Zr < 22 and Si/K < 19, while zone R corresponds to 5.5 < Zr/Th < 11, Sr/Ca < 1.1, Si/Zr > 22 and Si/K > 19. C2 zone is defined by Zr/Th < 5.5, Sr/Ca > 1.1, Si/Zr < 22 and Si/K < 19 and C1 zone is characterized by Si/Zr > 22 and Si/K > 19. The selected geochemical ratios indicate a strong geochemical zonation. In the case of offset wells, 85.9% of the data confirmed the proposed classification and 89.4% for the real-time application case. The zone R shows a strong contrast with the surrounding formations facilitating critical decisions during well placement and geosteering, increasing the reservoir exposure by 28%. The quantitative approach delivered very valuable results, providing a solid foundation to define correlation and well landing intervals. Simultaneously, the cost of the method represents a fraction of the LWD cost and 0.15% of the total project cost, making it very cost effective and a standard approach for future projects.
{"title":"Elemental geochemistry of the Upper Cretaceous reservoir and surrounding formations applied in geosteering of horizontal wells, Lebăda Field – Western Black Sea","authors":"I. Prundeanu, C. Chelariu, David Rafael Contreras Perez","doi":"10.2516/ogst/2020083","DOIUrl":"https://doi.org/10.2516/ogst/2020083","url":null,"abstract":"The precise landing and steering of horizontal wells using conventional mudlogging and Logging While Drilling (LWD) data is a particular challenge for the Lebăda Field, offshore Romania. The use of a new technique of elemental geochemistry analysis (or chemosteering) became an option for the identification of Cenomanian, Turonian–Coniacian–Santonian, Campanian and Eocene strata. This has enabled more accurate placement of the horizontal development wells within the desired reservoir target interval. Geochemical data enabled the identification of chemostratigraphic zones C1, C2, C3 and zone R that correspond to the reservoir section. The application is a result of the geochemical zonation performed using elements and ratios that are sensitive to depositional environment, sea level change, heavy mineral concentrations and siliciclastic input namely: Sr/Ca, Zr/Th, Si/Zr and Si/K. In ascending stratigraphic order, the ratio thresholds of zone C3 are Zr/Th > 11, Sr/Ca > 1.1, Si/Zr < 22 and Si/K < 19, while zone R corresponds to 5.5 < Zr/Th < 11, Sr/Ca < 1.1, Si/Zr > 22 and Si/K > 19. C2 zone is defined by Zr/Th < 5.5, Sr/Ca > 1.1, Si/Zr < 22 and Si/K < 19 and C1 zone is characterized by Si/Zr > 22 and Si/K > 19. The selected geochemical ratios indicate a strong geochemical zonation. In the case of offset wells, 85.9% of the data confirmed the proposed classification and 89.4% for the real-time application case. The zone R shows a strong contrast with the surrounding formations facilitating critical decisions during well placement and geosteering, increasing the reservoir exposure by 28%. The quantitative approach delivered very valuable results, providing a solid foundation to define correlation and well landing intervals. Simultaneously, the cost of the method represents a fraction of the LWD cost and 0.15% of the total project cost, making it very cost effective and a standard approach for future projects.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"20 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81601198","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
W. Shi, Yuedong Yao, Shiqing Cheng, He Li, Mi Wang, Nan Cui, Chengwei Zhang, Hong Li, Kun Tu, Zhiliang Shi
Pressure response behavior of two-layered reservoir with a vertical mixed boundary is easy to be mistaken for that of the radial composite reservoir or dual-pore reservoir. It is difficult to fit the pressure response curve and easy to obtain abnormal parameter values using a misunderstood model. In this paper, we present the interpretation of three different types of pressure responses of vertical mixed boundary reservoir by our proposed models, where the diagnostic window and feature value are captured for different mixed boundary types. Results show that the mixed boundary with closed boundary and infinite-acting boundary induces the fake pressure response of a radial composite reservoir with poor permeability outer zone. The mixed boundary with the main constant-pressure and non-main closed boundary produces a fake pressure response of a dual-porosity reservoir. The diagnostic window of pressure response curves shape can easily capture the mixed boundary type, and the feature value of the feature values of pressure response value can quickly obtain the permeability ration of one layer. Aiming at different representative types of pressure response cases in the western Sichuan XC gas field, China, we innovatively analyze them from a different perspective and get a new understanding of pressure response behavior of vertical mixed boundary, which provides a guideline for the interpretation of layered oil and gas reservoir with the complex boundary in the vertical direction.
{"title":"Investigation on the pressure response behavior of two-layer vertical mixed boundary reservoir: field cases in Western Sichuan XC gas field, China","authors":"W. Shi, Yuedong Yao, Shiqing Cheng, He Li, Mi Wang, Nan Cui, Chengwei Zhang, Hong Li, Kun Tu, Zhiliang Shi","doi":"10.2516/ogst/2020082","DOIUrl":"https://doi.org/10.2516/ogst/2020082","url":null,"abstract":"Pressure response behavior of two-layered reservoir with a vertical mixed boundary is easy to be mistaken for that of the radial composite reservoir or dual-pore reservoir. It is difficult to fit the pressure response curve and easy to obtain abnormal parameter values using a misunderstood model. In this paper, we present the interpretation of three different types of pressure responses of vertical mixed boundary reservoir by our proposed models, where the diagnostic window and feature value are captured for different mixed boundary types. Results show that the mixed boundary with closed boundary and infinite-acting boundary induces the fake pressure response of a radial composite reservoir with poor permeability outer zone. The mixed boundary with the main constant-pressure and non-main closed boundary produces a fake pressure response of a dual-porosity reservoir. The diagnostic window of pressure response curves shape can easily capture the mixed boundary type, and the feature value of the feature values of pressure response value can quickly obtain the permeability ration of one layer. Aiming at different representative types of pressure response cases in the western Sichuan XC gas field, China, we innovatively analyze them from a different perspective and get a new understanding of pressure response behavior of vertical mixed boundary, which provides a guideline for the interpretation of layered oil and gas reservoir with the complex boundary in the vertical direction.","PeriodicalId":19424,"journal":{"name":"Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles","volume":"58 1","pages":""},"PeriodicalIF":1.5,"publicationDate":"2020-12-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78164705","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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