R. Minakhmetova, I. Aslanyan, V. Nagimov, Llnur Shigapov, V. Kosolapov, V. Virt
Today, oil reservoirs with a gas cap on top are mainly developed by drilling horizontal wells of various design. In the course of well operation, early increase in gas-oil ratio or water cut can often be observed. These may be caused by both well integrity failure and the geology feature of the target formation when formation water breaks through from the bottom of the producing formation and gas inflows from the top of the reservoir as a result of coning. One of the ways of controlling unwanted water and gas production sources and reservoir fluid production rates is monitoring of production profiles along the horizontal sections of the well using a reservoir-oriented production logging survey. This paper describes an example of such monitoring at a horizontal well drilled into the oil-rim reservoir at the Novoportovskoye field. The paper provides the results of a series of logging surveys performed in 2, 18 and 24 months after the well commissioning. The first (reference) survey was performed at the earliest stage of the well production; the second and the third ones - when the gas-oil ratio started to increase. The advanced production logging survey included high-precision temperature logging, distributed capacitance measurements and spectral acoustic logging. The spectral acoustic logging data identified the producing intervals of the reservoir along the horizontal section of the well. According to the first survey results, the production fluid was flowing uniformly along the wellbore. The third and second surveys had identified the intervals of gas breakthrough in the reservoir. After all the survey results had been compared to one another, it was identified that the gas breakthrough could have been localized even during the first logging survey. In each survey, the multiphase inflow profiling was perfomed using a temperature modelling. Information generated as a result of production logging survey in the horizontal well allows localizing and predicting gas breakthroughs in wells drilled in oil rims. Using this data, such gas breakthroughs may be immediately prevented. The data can also be used when designing new wells to increase the efficiency of development of such fields.
{"title":"Multiphase Inflow Monitoring in Horizontal Wells Producing from Oil Rims Based on the Advanced Production Logging Suite Data","authors":"R. Minakhmetova, I. Aslanyan, V. Nagimov, Llnur Shigapov, V. Kosolapov, V. Virt","doi":"10.2118/196921-ms","DOIUrl":"https://doi.org/10.2118/196921-ms","url":null,"abstract":"\u0000 Today, oil reservoirs with a gas cap on top are mainly developed by drilling horizontal wells of various design. In the course of well operation, early increase in gas-oil ratio or water cut can often be observed. These may be caused by both well integrity failure and the geology feature of the target formation when formation water breaks through from the bottom of the producing formation and gas inflows from the top of the reservoir as a result of coning.\u0000 One of the ways of controlling unwanted water and gas production sources and reservoir fluid production rates is monitoring of production profiles along the horizontal sections of the well using a reservoir-oriented production logging survey. This paper describes an example of such monitoring at a horizontal well drilled into the oil-rim reservoir at the Novoportovskoye field. The paper provides the results of a series of logging surveys performed in 2, 18 and 24 months after the well commissioning. The first (reference) survey was performed at the earliest stage of the well production; the second and the third ones - when the gas-oil ratio started to increase. The advanced production logging survey included high-precision temperature logging, distributed capacitance measurements and spectral acoustic logging. The spectral acoustic logging data identified the producing intervals of the reservoir along the horizontal section of the well. According to the first survey results, the production fluid was flowing uniformly along the wellbore. The third and second surveys had identified the intervals of gas breakthrough in the reservoir. After all the survey results had been compared to one another, it was identified that the gas breakthrough could have been localized even during the first logging survey. In each survey, the multiphase inflow profiling was perfomed using a temperature modelling.\u0000 Information generated as a result of production logging survey in the horizontal well allows localizing and predicting gas breakthroughs in wells drilled in oil rims. Using this data, such gas breakthroughs may be immediately prevented. The data can also be used when designing new wells to increase the efficiency of development of such fields.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79045643","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. Kunakova, F. G. Usmanova, I. Vorozhtsova, Iuliia Vladislavovna Lanchuk
Hydrocarbons production in gas-lift wells of the Eastern section of the Orenburg oil and gas condensate field (ESOOGCF) is complicated by gas hydrates formation in oilwell tubing, shutoff-opening and control valves and gas lift system. In order to prevent hydrate formation, continuous supply of methanol is used, causing additional economic costs and environmental risks. Therefore, it is important to search for new more effective reagents to remove and prevent gas hydrate formation. The aim of this work was to choose the most effective inhibitors of hydrate formation for ESOOGCF conditions. The study was carried out among thermodynamic and kinetic inhibitors for gas hydrates formation. Due to different mechanism of inhibitors action, various approaches were used to evaluate their effectiveness. Experimental conditions were as close as possible to the field ones: the model gas-liquid mixture was used, the appropriate temperature and pressure conditions were determined. Thermodynamic inhibitors which reduce hydrate formation temperature were kept at a constant temperature in the GHA 350 autoclave under continuous stirring: temperature T=2°C and initial pressure 50 atm. during 12 hours. The study of kinetic inhibitors that slow down the process of hydrate formation due to adsorption on hydrate crystals was carried out by polythermic method in the temperature range from 8°C to −15°C using the RCS6 equipment with initial pressure 30 bar. The effectiveness of inhibitors was evaluated by initial temperature of absorption of hydrate-forming gas due to hydrate formation. It was proved by pressure drop in the system. In the process of studying of thermodynamic inhibitors, the formation of hydrates in the system could also be recorded visually. As a result of the experiments it was found that thermodynamic inhibitors better prevent hydrate formation in the conditions of ESOOGCF at concentrations of 15% or 20% by volume in produced water as almost all of the reagents studied showed high efficiency. Among kinetic inhibitors, only two reagents showed positive results in hydrate formation reduce at volume concentrations of 2.5% and 5% of the amount of produced water. All manufacturers whose reagents successfully passed laboratory tests were invited to participate in field tests. For today field tests of two reagents of different types of action have been carried out. During these tests the minimum effective concentration of a thermodynamic inhibitor was determined - 164 L/day. For comparison, methanol consumption before the field tests was 500 L/day despite the fact that the reagent is not inferior to him in technical terms. The minimum effective dosage of the kinetic inhibitor of hydrate formation according to the results of field tests was 50 L/day. Thus, the application of thermodynamic and kinetic inhibitors of hydrate formation is economically profitable under the same technical parameters of the base reagent. The conditions of ea
{"title":"Approaches to the Selection of Effective Inhibitors of Gas Hydrate Formation","authors":"A. Kunakova, F. G. Usmanova, I. Vorozhtsova, Iuliia Vladislavovna Lanchuk","doi":"10.2118/196781-ms","DOIUrl":"https://doi.org/10.2118/196781-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Hydrocarbons production in gas-lift wells of the Eastern section of the Orenburg oil and gas condensate field (ESOOGCF) is complicated by gas hydrates formation in oilwell tubing, shutoff-opening and control valves and gas lift system. In order to prevent hydrate formation, continuous supply of methanol is used, causing additional economic costs and environmental risks. Therefore, it is important to search for new more effective reagents to remove and prevent gas hydrate formation. The aim of this work was to choose the most effective inhibitors of hydrate formation for ESOOGCF conditions. The study was carried out among thermodynamic and kinetic inhibitors for gas hydrates formation.\u0000 \u0000 \u0000 \u0000 Due to different mechanism of inhibitors action, various approaches were used to evaluate their effectiveness. Experimental conditions were as close as possible to the field ones: the model gas-liquid mixture was used, the appropriate temperature and pressure conditions were determined. Thermodynamic inhibitors which reduce hydrate formation temperature were kept at a constant temperature in the GHA 350 autoclave under continuous stirring: temperature T=2°C and initial pressure 50 atm. during 12 hours. The study of kinetic inhibitors that slow down the process of hydrate formation due to adsorption on hydrate crystals was carried out by polythermic method in the temperature range from 8°C to −15°C using the RCS6 equipment with initial pressure 30 bar.\u0000 \u0000 \u0000 \u0000 The effectiveness of inhibitors was evaluated by initial temperature of absorption of hydrate-forming gas due to hydrate formation. It was proved by pressure drop in the system. In the process of studying of thermodynamic inhibitors, the formation of hydrates in the system could also be recorded visually. As a result of the experiments it was found that thermodynamic inhibitors better prevent hydrate formation in the conditions of ESOOGCF at concentrations of 15% or 20% by volume in produced water as almost all of the reagents studied showed high efficiency. Among kinetic inhibitors, only two reagents showed positive results in hydrate formation reduce at volume concentrations of 2.5% and 5% of the amount of produced water. All manufacturers whose reagents successfully passed laboratory tests were invited to participate in field tests. For today field tests of two reagents of different types of action have been carried out. During these tests the minimum effective concentration of a thermodynamic inhibitor was determined - 164 L/day. For comparison, methanol consumption before the field tests was 500 L/day despite the fact that the reagent is not inferior to him in technical terms. The minimum effective dosage of the kinetic inhibitor of hydrate formation according to the results of field tests was 50 L/day. Thus, the application of thermodynamic and kinetic inhibitors of hydrate formation is economically profitable under the same technical parameters of the base reagent.\u0000 \u0000 \u0000 \u0000 The conditions of ea","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82119307","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}
D. Sugaipov, O. Ushmaev, M. Fedorov, A. N. Nikitin, I. V. Kovalenko, D. A. Samolovov
The purpose of the work is to present the experience of PJSC "Gazpromneft" in the oil rims development and formed on its basis the strategy of involving in the economically viable development of this type of hydrocarbon reserves. The paper considers various approaches, such as depletion, injection of gas and water into the oil rim, back injection into the gas cap of produced associated petroleum gas from the rim, simultaneous production of oil and gas, etc. Practical examples are given in management and technological decisions in solving various problems in the development of oil rims in order to maximize the economic efficiency of projects and the main recommendations are formed. The conclusions are that one of the key drivers of the success of the development of oil rims is an integrated approach to development management. It is concluded that the successful development of such deposits is possible under the condition of monetization of all hydrocarbon products. The paper notes that, given the significant volume of construction, technological risks and long-term projects, successful implementation of projects for the development of oil rims requires a clear, long-term and stable state tax policy for companies engaged in the development of the resource base of such hydrocarbon reserves.
{"title":"Integrated Approach to the Development of Low-Thickness Oil Rims in Western Siberia","authors":"D. Sugaipov, O. Ushmaev, M. Fedorov, A. N. Nikitin, I. V. Kovalenko, D. A. Samolovov","doi":"10.2118/196747-ru","DOIUrl":"https://doi.org/10.2118/196747-ru","url":null,"abstract":"\u0000 The purpose of the work is to present the experience of PJSC \"Gazpromneft\" in the oil rims development and formed on its basis the strategy of involving in the economically viable development of this type of hydrocarbon reserves. The paper considers various approaches, such as depletion, injection of gas and water into the oil rim, back injection into the gas cap of produced associated petroleum gas from the rim, simultaneous production of oil and gas, etc. Practical examples are given in management and technological decisions in solving various problems in the development of oil rims in order to maximize the economic efficiency of projects and the main recommendations are formed.\u0000 The conclusions are that one of the key drivers of the success of the development of oil rims is an integrated approach to development management. It is concluded that the successful development of such deposits is possible under the condition of monetization of all hydrocarbon products. The paper notes that, given the significant volume of construction, technological risks and long-term projects, successful implementation of projects for the development of oil rims requires a clear, long-term and stable state tax policy for companies engaged in the development of the resource base of such hydrocarbon reserves.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87528236","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}
Y. Kaipov, S. Tyatyushkin, Oleg Kulyatin, Alexander Lomukhin, S. Romashkin
This paper presents The Exploration Well test solution under high pressure and low permeability. The work shows a new approach to the qualitative and quantitative description of the low permeability horizons by conducting the well testing before and after hydraulic fracturing. To provide a high degree of reliability, safety and efficiency in terms of time and quality of the received information the special combination of high-tech downhole tools was used. The previous experience of conducting the well testing in exploration wells at the Yamal-Nenets Autonomous Region showed difficulties due to the deep bedding, low permeability and abnormally high formation pressure. These types of formations require conducting the hydraulic fracturing to obtain the commercial flow at surface. During the well test after the hydraulic fracturing in a low-permeable reservoir usually it is not possible to achieve infinitely-acting radial flow regime within the allocated time which does not allow to estimate the actual horizontal permeability of the formation. To perform the complex well testing and effective hydraulic fracturing the combination of downhole tools, run-in hole on a tubing, including the perforating guns, packer, autonomous pressure gauges, downhole valves (tubing and circulation valves) controlled from the surface, was used. To assess the reservoir permeability the well testing was carried out with the inflow period without natural flow to the surface and pressure build-up shut-in at the bottom before creating the hydraulic fracture. As a result, the formation pressure, permeability and skin-factor are estimated. During this study, a multi-cycle valve controlled with a low-pressure impulse in the annulus played the major role in conducting several inflow periods, pressure build-ups with downhole shut-in and lifting the formation fluid to the surface by reverse circulating through the circulation valve. Before conducting the hydraulic fracturing, three mini-frac tests were carried out with injection of hydraulic fracturing fluid into the reservoir and recording the pressure fall-off with downhole shut-in. As a result of this period the fracture closure pressure, reservoir pressure, mobility and the effectiveness of fracturing fluid were estimated. After hydraulic fracturing, flowing periods were conducted to assess the well productivity with a created fracture. These well testing activities were carried out successfully in a safe manner and achieved reservoir evaluation objectives. This article discusses the unique experience and lessons learned from conducting the well testing with hydraulic fracturing using high-tech downhole equipment to achieve the successful results in low permeability reservoirs.
{"title":"How not to fail during the Reservoir Test for Low Permeability Formation: Case Study","authors":"Y. Kaipov, S. Tyatyushkin, Oleg Kulyatin, Alexander Lomukhin, S. Romashkin","doi":"10.2118/196843-ms","DOIUrl":"https://doi.org/10.2118/196843-ms","url":null,"abstract":"\u0000 This paper presents The Exploration Well test solution under high pressure and low permeability. The work shows a new approach to the qualitative and quantitative description of the low permeability horizons by conducting the well testing before and after hydraulic fracturing. To provide a high degree of reliability, safety and efficiency in terms of time and quality of the received information the special combination of high-tech downhole tools was used.\u0000 The previous experience of conducting the well testing in exploration wells at the Yamal-Nenets Autonomous Region showed difficulties due to the deep bedding, low permeability and abnormally high formation pressure.\u0000 These types of formations require conducting the hydraulic fracturing to obtain the commercial flow at surface. During the well test after the hydraulic fracturing in a low-permeable reservoir usually it is not possible to achieve infinitely-acting radial flow regime within the allocated time which does not allow to estimate the actual horizontal permeability of the formation.\u0000 To perform the complex well testing and effective hydraulic fracturing the combination of downhole tools, run-in hole on a tubing, including the perforating guns, packer, autonomous pressure gauges, downhole valves (tubing and circulation valves) controlled from the surface, was used.\u0000 To assess the reservoir permeability the well testing was carried out with the inflow period without natural flow to the surface and pressure build-up shut-in at the bottom before creating the hydraulic fracture. As a result, the formation pressure, permeability and skin-factor are estimated. During this study, a multi-cycle valve controlled with a low-pressure impulse in the annulus played the major role in conducting several inflow periods, pressure build-ups with downhole shut-in and lifting the formation fluid to the surface by reverse circulating through the circulation valve.\u0000 Before conducting the hydraulic fracturing, three mini-frac tests were carried out with injection of hydraulic fracturing fluid into the reservoir and recording the pressure fall-off with downhole shut-in. As a result of this period the fracture closure pressure, reservoir pressure, mobility and the effectiveness of fracturing fluid were estimated.\u0000 After hydraulic fracturing, flowing periods were conducted to assess the well productivity with a created fracture.\u0000 These well testing activities were carried out successfully in a safe manner and achieved reservoir evaluation objectives.\u0000 This article discusses the unique experience and lessons learned from conducting the well testing with hydraulic fracturing using high-tech downhole equipment to achieve the successful results in low permeability reservoirs.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86350313","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}
D. Cotrell, T. Hoeink, Elijah Odusina, Sachin Ghorpade, S. Stolyarov
In the current state of the oil and gas industry, unconventional resources are a significant source of the total production output. Unconventional wells remain profitable at various price points, because initial stimulation treatments can be tailored to changing market conditions, reflecting completion costs and (estimated) hydrocarbon prices. The same holds true for re-stimulation of already producing wells. Stimulation treatment "opens" up the subsurface to ultimately allow for better drainage of the reservoir hydrocarbons. The primary stimulation treatment currently in use is hydraulic fracturing, in which the wellbore is broken up into multiple stages, and highly pressurized fluid (oftentimes water) is pumped into each stage of the wellbore. This causes fractures to propagate away from the wellbore, which in turn enhances the local reservoir permeability and allows for economical production. Historically, the number of stages, and clusters per stage, for hydraulic stimulation has been based on wellbore horizontal length (e.g., 200 ft or 400 ft), or much valued previous experience in the same or similar area, as well as other investment considerations. Over time, a strong tendency has developed to place stages and clusters closer together to improve production. However, it is reasonable to assume that there will be a point beyond which adding another stage becomes more expensive than what is gained by increased production revenue from the greater stage count (i.e., less profitable depending on the time of investment). This scenario frames a classic optimization problem which is solved using Monte Carlo methods. Results show that optimal stimulation treatment configurations are robust for many objective functions related to the fracturing process (e.g., propped length and propped height). However, we find that objective functions related to production, production revenue, and profit often provide different optimum treatment configurations, and that those optima shift with respect to the considered timeframe. Because business decisions will ultimately be based on profit decisions over a given time span, we propose utilizing the appropriate objective function together with an integrated modeling approach such as presented here.
{"title":"Completion Design Optimization for Unconventional Wells Using Large Scale Computational Science","authors":"D. Cotrell, T. Hoeink, Elijah Odusina, Sachin Ghorpade, S. Stolyarov","doi":"10.2118/196980-ms","DOIUrl":"https://doi.org/10.2118/196980-ms","url":null,"abstract":"In the current state of the oil and gas industry, unconventional resources are a significant source of the total production output. Unconventional wells remain profitable at various price points, because initial stimulation treatments can be tailored to changing market conditions, reflecting completion costs and (estimated) hydrocarbon prices. The same holds true for re-stimulation of already producing wells. Stimulation treatment \"opens\" up the subsurface to ultimately allow for better drainage of the reservoir hydrocarbons. The primary stimulation treatment currently in use is hydraulic fracturing, in which the wellbore is broken up into multiple stages, and highly pressurized fluid (oftentimes water) is pumped into each stage of the wellbore. This causes fractures to propagate away from the wellbore, which in turn enhances the local reservoir permeability and allows for economical production. Historically, the number of stages, and clusters per stage, for hydraulic stimulation has been based on wellbore horizontal length (e.g., 200 ft or 400 ft), or much valued previous experience in the same or similar area, as well as other investment considerations. Over time, a strong tendency has developed to place stages and clusters closer together to improve production. However, it is reasonable to assume that there will be a point beyond which adding another stage becomes more expensive than what is gained by increased production revenue from the greater stage count (i.e., less profitable depending on the time of investment). This scenario frames a classic optimization problem which is solved using Monte Carlo methods. Results show that optimal stimulation treatment configurations are robust for many objective functions related to the fracturing process (e.g., propped length and propped height). However, we find that objective functions related to production, production revenue, and profit often provide different optimum treatment configurations, and that those optima shift with respect to the considered timeframe. Because business decisions will ultimately be based on profit decisions over a given time span, we propose utilizing the appropriate objective function together with an integrated modeling approach such as presented here.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73357483","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. Pavlov, N. Pavlyukov, A. Krasnikov, M. Lushev, T. Eltsov
Effective assessment of the stress-strain state of the near wellbore zone is one of the key problems in the process of modeling the stability of the wellbore walls. Drilling mud infiltrates permeable rocks during the drilling process. This causes a change in the elastic-strength properties of rocks and, accordingly, the redistribution of tension around the well. At present, there are no computational methods that take into account the effect of saturation fluids on the change in the elastic-strength properties. A unified system approach for the implementation of this type of research when changing infiltration fluids is not developed yet. In this paper, we study the effect of various types of drilling mud on the elastic-strength properties of core samples, which are equivalents of rocks (composite samples made of different sand and clay cement facies). Measurements of porosity, acoustic properties, ultimate strength for uniaxial compression, and static Young's modulus at different samples saturation are made. Studies of the elastic-strength properties of the samples are performed after 48 and 168 hours soaked in the drilling fluids. According to the study, the relative change in the dynamic Young's modulus with various sample saturation is 13.4-27.7%, the static young modulus (compression) is 19-40%, the dynamic Poisson ratio is 1.4-14.6% and the uniaxial compression strength is 28-35%. The data obtained indicate a significant effect of the saturating fluid on the elastic and strength properties of materials. A numerical one-dimensional simulation of the stability of the borehole walls is performed, taking into account the type of saturating fluid and the relative change in the elastic-strength properties. The results indicate a change in the stability of the wellbore walls; the indicators of the change in the equivalents of the collapse gradient and hydraulic fracturing are 0.2-0.3 g / cm3. A change in Young's modulus of 30% affects the design parameters of a hydraulic fracturing fracture – by width up to 100%, by half length up to 50%.
{"title":"Evaluation of the Saturating Fluid Effect on the Composite Materials Elastic-Strength Properties","authors":"V. Pavlov, N. Pavlyukov, A. Krasnikov, M. Lushev, T. Eltsov","doi":"10.2118/196898-ms","DOIUrl":"https://doi.org/10.2118/196898-ms","url":null,"abstract":"\u0000 Effective assessment of the stress-strain state of the near wellbore zone is one of the key problems in the process of modeling the stability of the wellbore walls. Drilling mud infiltrates permeable rocks during the drilling process. This causes a change in the elastic-strength properties of rocks and, accordingly, the redistribution of tension around the well. At present, there are no computational methods that take into account the effect of saturation fluids on the change in the elastic-strength properties. A unified system approach for the implementation of this type of research when changing infiltration fluids is not developed yet.\u0000 In this paper, we study the effect of various types of drilling mud on the elastic-strength properties of core samples, which are equivalents of rocks (composite samples made of different sand and clay cement facies). Measurements of porosity, acoustic properties, ultimate strength for uniaxial compression, and static Young's modulus at different samples saturation are made. Studies of the elastic-strength properties of the samples are performed after 48 and 168 hours soaked in the drilling fluids. According to the study, the relative change in the dynamic Young's modulus with various sample saturation is 13.4-27.7%, the static young modulus (compression) is 19-40%, the dynamic Poisson ratio is 1.4-14.6% and the uniaxial compression strength is 28-35%. The data obtained indicate a significant effect of the saturating fluid on the elastic and strength properties of materials.\u0000 A numerical one-dimensional simulation of the stability of the borehole walls is performed, taking into account the type of saturating fluid and the relative change in the elastic-strength properties. The results indicate a change in the stability of the wellbore walls; the indicators of the change in the equivalents of the collapse gradient and hydraulic fracturing are 0.2-0.3 g / cm3. A change in Young's modulus of 30% affects the design parameters of a hydraulic fracturing fracture – by width up to 100%, by half length up to 50%.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"145 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74142110","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}
We present an approach of passive acoustic logging data interpretation to estimate wellbore fluid holdup variation along the wellbore due to the fluid inflow. The algorithm uses machine learning methods for the analysis of acoustic fields generated, in particular, by flow noise in the reservoir near wellbore zone. The method is designed using acoustic fields generated by numerical simulations. The study of simulation results shows the significant influence of wellbore resonances on acoustic field spectrograms and on intensity distributions along the wellbore. The interpretation results demonstrate that the suggested machine learning model predicts water holdup in a zone after the water inflow with high accuracy. The predictions of water holdup before the water inflow interval are less accurate because resonance characteristics are less sensitive to them. We also studied the influence of passive acoustic logging data distortion by contaminating noise on the model learning and on prediction accuracy for the developed interpretation algorithm. As expected, the estimation of water holdup before the water inflow interval is more sensitive to signal interference. The novelty of the suggested approach to passive acoustic logging data interpretation is in using resonance structures of the acoustic noise spatial frequency characteristics to locate the inflow interval and to estimate the oil and water volume fractions. The resonances contain a clear fingerprint of the fluid holdup variation in wellbore fluid, as shown by our study, and the corresponding information can be interpreted by the machine learning algorithms.
{"title":"Estimation of Fluid Phase Composition Variation Along the Wellbore by Analyzing Passive Acoustic Logging Data","authors":"N. Mutovkin, D. Mikhailov, I. Sofronov","doi":"10.2118/196845-ms","DOIUrl":"https://doi.org/10.2118/196845-ms","url":null,"abstract":"\u0000 We present an approach of passive acoustic logging data interpretation to estimate wellbore fluid holdup variation along the wellbore due to the fluid inflow. The algorithm uses machine learning methods for the analysis of acoustic fields generated, in particular, by flow noise in the reservoir near wellbore zone. The method is designed using acoustic fields generated by numerical simulations. The study of simulation results shows the significant influence of wellbore resonances on acoustic field spectrograms and on intensity distributions along the wellbore.\u0000 The interpretation results demonstrate that the suggested machine learning model predicts water holdup in a zone after the water inflow with high accuracy. The predictions of water holdup before the water inflow interval are less accurate because resonance characteristics are less sensitive to them. We also studied the influence of passive acoustic logging data distortion by contaminating noise on the model learning and on prediction accuracy for the developed interpretation algorithm. As expected, the estimation of water holdup before the water inflow interval is more sensitive to signal interference.\u0000 The novelty of the suggested approach to passive acoustic logging data interpretation is in using resonance structures of the acoustic noise spatial frequency characteristics to locate the inflow interval and to estimate the oil and water volume fractions. The resonances contain a clear fingerprint of the fluid holdup variation in wellbore fluid, as shown by our study, and the corresponding information can be interpreted by the machine learning algorithms.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81905905","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}
Rafael Pino, Amr Abouhamed, Ajay Addagalla, Hesham El Dakroury
Most high temperature (HT) wells are drilled with oil or synthetic-based drilling fluids (O/SBM) for a variety of reasons. These O/SBM drilling fluids are naturally lubricious due to the hydrocarbon continuous phase, which also contributes to improved wellbore stability, as the fluids are relatively inert to the formations being drilled. These fluids also have acceptable temperature stability and drilling performance, which makes them suitable for several applications. Downhole losses with O/SBM can be costly and difficult to cure. Additional O/SBM can be mixed at the rig site, but this requires a supply of base oil to be available and the fluid can take time to prepare. The ideal scenario is to have a facility close to the rig location that can supply the high volumes of premixed O/SBM and base oil required. Exploratory wells are often drilled in remote locations with no convenient liquid mud plant close by to service the O/SBM requirements. Acquisition of good quality logging data from exploratory wells is crucial to understanding the field potential for commercial development. Some of the more sophisticated logging tools available in the industry are incompatible or difficult to run and interpret in an O/SBM environment. In such cases a water based drilling fluid (WBM) can be the solution. The logistic requirement for WBM is significantly lower than for O/SBM, as chemicals can be stored on location and water can be supplied from a nearby water well. WBM is much simpler to prepare than O/SBM, so WBM can be quickly prepared as required, and WBM downhole losses can often be cured more easily. Typical polymer-based WBM does not have high temperature stability, and is usually restricted to wells where the bottomhole temperature is less than 300°F. This paper will discuss the design, testing, and field application of a WBM for HT applications. To design a temperature stable HT-WBM fluid requires the use of drilling chemicals that can function adequately in a harsh environment. These wells required temperature tolerant polymers that provide an acceptable rheological profile and controlled fluid loss, so the wells can be safely drilled with no major complications. The HT-WBM was used to successfully drill, core, log, and case wells with bottomhole temperatures higher than 375°F.
{"title":"Not Too Hot to Handle: Water Based Fluid Drills High Temperature Wells","authors":"Rafael Pino, Amr Abouhamed, Ajay Addagalla, Hesham El Dakroury","doi":"10.2118/196796-ms","DOIUrl":"https://doi.org/10.2118/196796-ms","url":null,"abstract":"\u0000 Most high temperature (HT) wells are drilled with oil or synthetic-based drilling fluids (O/SBM) for a variety of reasons. These O/SBM drilling fluids are naturally lubricious due to the hydrocarbon continuous phase, which also contributes to improved wellbore stability, as the fluids are relatively inert to the formations being drilled. These fluids also have acceptable temperature stability and drilling performance, which makes them suitable for several applications. Downhole losses with O/SBM can be costly and difficult to cure. Additional O/SBM can be mixed at the rig site, but this requires a supply of base oil to be available and the fluid can take time to prepare. The ideal scenario is to have a facility close to the rig location that can supply the high volumes of premixed O/SBM and base oil required.\u0000 Exploratory wells are often drilled in remote locations with no convenient liquid mud plant close by to service the O/SBM requirements. Acquisition of good quality logging data from exploratory wells is crucial to understanding the field potential for commercial development. Some of the more sophisticated logging tools available in the industry are incompatible or difficult to run and interpret in an O/SBM environment. In such cases a water based drilling fluid (WBM) can be the solution. The logistic requirement for WBM is significantly lower than for O/SBM, as chemicals can be stored on location and water can be supplied from a nearby water well. WBM is much simpler to prepare than O/SBM, so WBM can be quickly prepared as required, and WBM downhole losses can often be cured more easily. Typical polymer-based WBM does not have high temperature stability, and is usually restricted to wells where the bottomhole temperature is less than 300°F.\u0000 This paper will discuss the design, testing, and field application of a WBM for HT applications. To design a temperature stable HT-WBM fluid requires the use of drilling chemicals that can function adequately in a harsh environment.\u0000 These wells required temperature tolerant polymers that provide an acceptable rheological profile and controlled fluid loss, so the wells can be safely drilled with no major complications. The HT-WBM was used to successfully drill, core, log, and case wells with bottomhole temperatures higher than 375°F.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79695393","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}
Muhammad Tahir, R. Hincapie, Hendrik Foedisch, G. Strobel, L. Ganzer
Design of Smart-Water can be economically attractive owing the presence of excessive water resources (seawater). This paper aims to design Smart-Water in order to analyze its impact on remaining oil saturation reduction and hence improved oil recovery. Moreover, this study evaluates and define the synergies and benefits between high salt smart water and polymer flooding. The paper combines an extensive rheological characterization and core-flooding experiments; performing fluid optimization (change in brine composition and polymer concentration). Synthetic seawater (SSW) is used as the base brine. Optimization is perform by adding/removing specific chemical components in the SSW. Overall, five brines are utilized: 1) SSW, 2) 2*SSW, 3) SSW with double sulphates 3) SSW with quadruple sulphates and 5) SSW without NaCl. Brine 1 and 2 are used as the formation brines, whereas brine 3 to 5 are used as the injection brines to analyze impact of SO4-2 and Na+1 on remaining oil saturation reduction. Secondary and tertiary-mode experiments are performed to evaluate the feasibility of applying Smart-Water injection and its synergies with polymer flood. Smart water with spiked sulphates changed the interfacial tension compare to synthetic seawater. Henceforth smart water injection has contributed to extra oil recovery, resulting on a reduction of the remaining oil saturation due to the improved interfacial rheology and slightly higher IFT. Optimized Smart Water with spiked amount of sulphate has produced the highest oil recovery in secondary mode compared to other brines (in case of both formation brines). Furthermore, higher concentration of the divalent cations in formation brine and spiked amount of Na+1 in injected brine has resulted the significant decrease in remaining oil saturation (2*SSW as formation brine). Combination of smart water and polymer flood has shown significant reduction in remaining oil saturation. Polymer injection after smart water with spiked sulphates has contributed to significant extra oil recovery compare to the other brines owing to the combined effect of improved interfacial rheology and enhanced polymer viscoelasticity.
{"title":"Potential Benefits of Fluid Optimization for Combined Smart-Water and Polymer Flooding: Impact on Remaining Oil Saturation","authors":"Muhammad Tahir, R. Hincapie, Hendrik Foedisch, G. Strobel, L. Ganzer","doi":"10.2118/196763-ms","DOIUrl":"https://doi.org/10.2118/196763-ms","url":null,"abstract":"\u0000 Design of Smart-Water can be economically attractive owing the presence of excessive water resources (seawater). This paper aims to design Smart-Water in order to analyze its impact on remaining oil saturation reduction and hence improved oil recovery. Moreover, this study evaluates and define the synergies and benefits between high salt smart water and polymer flooding. The paper combines an extensive rheological characterization and core-flooding experiments; performing fluid optimization (change in brine composition and polymer concentration).\u0000 Synthetic seawater (SSW) is used as the base brine. Optimization is perform by adding/removing specific chemical components in the SSW. Overall, five brines are utilized: 1) SSW, 2) 2*SSW, 3) SSW with double sulphates 3) SSW with quadruple sulphates and 5) SSW without NaCl. Brine 1 and 2 are used as the formation brines, whereas brine 3 to 5 are used as the injection brines to analyze impact of SO4-2 and Na+1 on remaining oil saturation reduction. Secondary and tertiary-mode experiments are performed to evaluate the feasibility of applying Smart-Water injection and its synergies with polymer flood.\u0000 Smart water with spiked sulphates changed the interfacial tension compare to synthetic seawater. Henceforth smart water injection has contributed to extra oil recovery, resulting on a reduction of the remaining oil saturation due to the improved interfacial rheology and slightly higher IFT. Optimized Smart Water with spiked amount of sulphate has produced the highest oil recovery in secondary mode compared to other brines (in case of both formation brines). Furthermore, higher concentration of the divalent cations in formation brine and spiked amount of Na+1 in injected brine has resulted the significant decrease in remaining oil saturation (2*SSW as formation brine). Combination of smart water and polymer flood has shown significant reduction in remaining oil saturation. Polymer injection after smart water with spiked sulphates has contributed to significant extra oil recovery compare to the other brines owing to the combined effect of improved interfacial rheology and enhanced polymer viscoelasticity.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83976538","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}
Xi Changfeng, Qi Zongyao, Liu Tong, Z. Yunjun, Zhao Fang, Qingsen Yu, D. Shen, Li Xiuluan
Currently Block J6 is in the later stage of steam flooding after 27 years’ steam injection, its recovery factor is about 50%, and the water cut is more than 95%. Particularly, the present steam oil ratio is about 12 m3(CWE)/t which has reached the economic limit and is in ineffective development. Cores from four post steam flooding drilling wells show that only top 2-3m of the total 25-30m pay zone has a steam chamber which is the main steam channel and its residual oil saturation is about 20%, the other 22-27m pay zone is displaced by hot water and its oil saturation is 40-55%. A 3D physical simulation show the conventional steam flooding with full interval perforation quickly broke through from the top of reservoir, and the steam oil ratio rose rapidly from 5 m3(CWE)/t to 10 m3(CWE)/t. The recovery factor was only 20.1% at the time of steam breakthrough, and then it was in the phase of high steam oil ratio for a long time. During CO2 assisted steam flooding the whole perforated producer is switched into a low half perforated well, and the recovery factor increases from 20.1% to 81.1%, the steam oil ratio is 3.3m3(CWE)/t. There are three characteristics in CO2 assisted steam flooding stage, firstly there is a steam and CO2 assisted gravity drainage mode, steam chamber expands from the top 2-3cm to the total 20cm oil layer. Secondly, there is a stable emulsion foam oil, its water cut is 60-70%, CO2 liquid ratio is about 5:1 Sm3/t, CO2 is a kind of dispersed bubble so it is much more than the dissolved CO2 liquid ratio 2:1 Sm3/t. Thirdly, CO2 lows the heatloss to overburden and keeps the formation pressure. The calculation shows that the heat loss can be reduced by more than 10% in the top layer. A pilot test including 9 well patterns(49 wells) has been established, and its recovery factor will be up to 75%, and the steam oil ratio will up to 2 m3(CWE)/t, a good production performance is predicted optimistically.
{"title":"CO2 Assisted Steam Flooding Technology after Steam Flooding - A Case Study in Block J6 of Xinjiang Oilfield","authors":"Xi Changfeng, Qi Zongyao, Liu Tong, Z. Yunjun, Zhao Fang, Qingsen Yu, D. Shen, Li Xiuluan","doi":"10.2118/196767-ms","DOIUrl":"https://doi.org/10.2118/196767-ms","url":null,"abstract":"\u0000 Currently Block J6 is in the later stage of steam flooding after 27 years’ steam injection, its recovery factor is about 50%, and the water cut is more than 95%. Particularly, the present steam oil ratio is about 12 m3(CWE)/t which has reached the economic limit and is in ineffective development. Cores from four post steam flooding drilling wells show that only top 2-3m of the total 25-30m pay zone has a steam chamber which is the main steam channel and its residual oil saturation is about 20%, the other 22-27m pay zone is displaced by hot water and its oil saturation is 40-55%. A 3D physical simulation show the conventional steam flooding with full interval perforation quickly broke through from the top of reservoir, and the steam oil ratio rose rapidly from 5 m3(CWE)/t to 10 m3(CWE)/t. The recovery factor was only 20.1% at the time of steam breakthrough, and then it was in the phase of high steam oil ratio for a long time. During CO2 assisted steam flooding the whole perforated producer is switched into a low half perforated well, and the recovery factor increases from 20.1% to 81.1%, the steam oil ratio is 3.3m3(CWE)/t. There are three characteristics in CO2 assisted steam flooding stage, firstly there is a steam and CO2 assisted gravity drainage mode, steam chamber expands from the top 2-3cm to the total 20cm oil layer. Secondly, there is a stable emulsion foam oil, its water cut is 60-70%, CO2 liquid ratio is about 5:1 Sm3/t, CO2 is a kind of dispersed bubble so it is much more than the dissolved CO2 liquid ratio 2:1 Sm3/t. Thirdly, CO2 lows the heatloss to overburden and keeps the formation pressure. The calculation shows that the heat loss can be reduced by more than 10% in the top layer. A pilot test including 9 well patterns(49 wells) has been established, and its recovery factor will be up to 75%, and the steam oil ratio will up to 2 m3(CWE)/t, a good production performance is predicted optimistically.","PeriodicalId":10977,"journal":{"name":"Day 2 Wed, October 23, 2019","volume":"101 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-10-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80617676","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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