The offshore segments of the Pre-Dobrogea foredeep is absolutely unexplored, there is no a single well penetrated Paleozoic units within offshore areas. This study, a deep dive into petroleum system evolution of similar foredeep basin based on a 3D basin modeling was performed in order to get understanding of petroleum systems and geology of offshore segment of Pre-Dobrogea. Western edge of East European craton is about 1450 km takes from Western Black sea shore to Southern shore of Baltic sea. This area within Ukraine includes Pre-Dobrogea foredeep basin, Pre-Carpathian foredeep basin (Bylche-Volytsa foredeep), Lviv Paleozoic basin and extensive Paleozoic margin called Volyno-Podillia area (Figure 1). All mentioned basins have similar sedimentary history, similar dynamics of tectonic evolution, proven petroleum systems of almost the same age, discovered commercial and sub-commercial accumulations and are heavily underexplored and undervalued. 3D basin modeling as a primary exploration technique was applied to mentioned basins in order to identify common features in tectonic development, in sedimentation and evolution of petroleum systems. Identified basins’ similar features now could be extrapolated to underexplored formations and areas within the study area. Figure 1 Western margin of East European Craton with marked areas of study (edited after Mikołajczak, 2016)
{"title":"Preservation and Destruction of Accumulations in Petroleum Systems of Western Margin of East European Craton","authors":"I. Karpenko, Oleksii Karpenko","doi":"10.2118/208542-ms","DOIUrl":"https://doi.org/10.2118/208542-ms","url":null,"abstract":"\u0000 The offshore segments of the Pre-Dobrogea foredeep is absolutely unexplored, there is no a single well penetrated Paleozoic units within offshore areas. This study, a deep dive into petroleum system evolution of similar foredeep basin based on a 3D basin modeling was performed in order to get understanding of petroleum systems and geology of offshore segment of Pre-Dobrogea. Western edge of East European craton is about 1450 km takes from Western Black sea shore to Southern shore of Baltic sea. This area within Ukraine includes Pre-Dobrogea foredeep basin, Pre-Carpathian foredeep basin (Bylche-Volytsa foredeep), Lviv Paleozoic basin and extensive Paleozoic margin called Volyno-Podillia area (Figure 1). All mentioned basins have similar sedimentary history, similar dynamics of tectonic evolution, proven petroleum systems of almost the same age, discovered commercial and sub-commercial accumulations and are heavily underexplored and undervalued. 3D basin modeling as a primary exploration technique was applied to mentioned basins in order to identify common features in tectonic development, in sedimentation and evolution of petroleum systems. Identified basins’ similar features now could be extrapolated to underexplored formations and areas within the study area.\u0000 Figure 1 Western margin of East European Craton with marked areas of study (edited after Mikołajczak, 2016)","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79569307","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The successful penetration of oil and gas formations by a horizontal well depends on the accuracy of the forecast of the depth and angle of the layers’ dip at the entry point. Methods and mathematical algorithms for predicting the geometric behavior of formations during drilling of a horizontal well at the stage of its approach to the entry point into target productive horizons are developed. The relationship between the formation dip, their stratigraphic thickness, and apparent vertical thickness in vertical and sub-horizontal wells is considered. It is shown that even small angles of inclination can lead to a significant influence on the prediction of the point of formation opening by a horizontal well. A detailed correlation of the offset well section with a horizontal well one while drilling was used for the analysis. A method for predicting the depth of disclose of the target formation by a horizontal well based on the change in the apparent vertical thickness is shown. A mathematical algorithm for calculating the apparent bedding angle on the basis of initial and while drilling data has been obtained. The calculated bedding angle allows predicting the depth of the target formation penetration with a horizontal well. The proposed method for predicting the horizontal well landing point depth allows avoiding errors associated with non-horizontal layering. The use of the proposed technique when drilling a number of horizontal wells in the oil fields of the Dnieper-Donets Basin (DDB) and the Pre-Carpathian Foredeep made it possible to determine with high accuracy the apparent bedding angle, even at their small values. The calculations made it possible to predict the depth of entry into the target formation during drilling with high accuracy. This is especially important in the context of small oil deposits, where it is impossible to make significant adjustments to the lateral position of the horizontal part of the wellbore. The predicted depths of the entry points into the formations were confirmed by the drilling results. The use of the proposed method makes it possible to perform high-quality geosteering while drilling horizontal wells at the stage of approaching the target formation entry point using the minimum data set. The simplicity of the method allows you to quickly analyze the geological section penetrated by a horizontal well and determine its geometric behavior. This approach makes it possible to successfully open pay formations with horizontal wells even without using a pilot well.
{"title":"Predicting of the Geometrical Behavior of Formations in Subsurface Based on the Analysis of LWD/MWD Data While Drilling Horizontal Wells","authors":"S. Tyvonchuk","doi":"10.2118/208511-ms","DOIUrl":"https://doi.org/10.2118/208511-ms","url":null,"abstract":"\u0000 The successful penetration of oil and gas formations by a horizontal well depends on the accuracy of the forecast of the depth and angle of the layers’ dip at the entry point. Methods and mathematical algorithms for predicting the geometric behavior of formations during drilling of a horizontal well at the stage of its approach to the entry point into target productive horizons are developed.\u0000 The relationship between the formation dip, their stratigraphic thickness, and apparent vertical thickness in vertical and sub-horizontal wells is considered. It is shown that even small angles of inclination can lead to a significant influence on the prediction of the point of formation opening by a horizontal well. A detailed correlation of the offset well section with a horizontal well one while drilling was used for the analysis. A method for predicting the depth of disclose of the target formation by a horizontal well based on the change in the apparent vertical thickness is shown. A mathematical algorithm for calculating the apparent bedding angle on the basis of initial and while drilling data has been obtained. The calculated bedding angle allows predicting the depth of the target formation penetration with a horizontal well.\u0000 The proposed method for predicting the horizontal well landing point depth allows avoiding errors associated with non-horizontal layering. The use of the proposed technique when drilling a number of horizontal wells in the oil fields of the Dnieper-Donets Basin (DDB) and the Pre-Carpathian Foredeep made it possible to determine with high accuracy the apparent bedding angle, even at their small values. The calculations made it possible to predict the depth of entry into the target formation during drilling with high accuracy. This is especially important in the context of small oil deposits, where it is impossible to make significant adjustments to the lateral position of the horizontal part of the wellbore. The predicted depths of the entry points into the formations were confirmed by the drilling results.\u0000 The use of the proposed method makes it possible to perform high-quality geosteering while drilling horizontal wells at the stage of approaching the target formation entry point using the minimum data set.\u0000 The simplicity of the method allows you to quickly analyze the geological section penetrated by a horizontal well and determine its geometric behavior. This approach makes it possible to successfully open pay formations with horizontal wells even without using a pilot well.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74286926","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Popescu, Rebecca Head, T. Ferriday, K. Evans, J. Montero, Jiazuo Zhang, Gwynfor Jones, G. Kaeng
This paper presents advancements in machine learning and cloud deployment that enable rapid and accurate automated lithology interpretation. A supervised machine learning technique is described that enables rapid, consistent, and accurate lithology prediction alongside quantitative uncertainty from large wireline or logging-while-drilling (LWD) datasets. To leverage supervised machine learning, a team of geoscientists and petrophysicists made detailed lithology interpretations of wells to generate a comprehensive training dataset. Lithology interpretations were based on applying determinist cross-plotting by utilizing and combining various raw logs. This training dataset was used to develop a model and test a machine learning pipeline. The pipeline was applied to a dataset previously unseen by the algorithm, to predict lithology. A quality checking process was performed by a petrophysicist to validate new predictions delivered by the pipeline against human interpretations. Confidence in the interpretations was assessed in two ways. The prior probability was calculated, a measure of confidence in the input data being recognized by the model. Posterior probability was calculated, which quantifies the likelihood that a specified depth interval comprises a given lithology. The supervised machine learning algorithm ensured that the wells were interpreted consistently by removing interpreter biases and inconsistencies. The scalability of cloud computing enabled a large log dataset to be interpreted rapidly; >100 wells were interpreted consistently in five minutes, yielding >70% lithological match to the human petrophysical interpretation. Supervised machine learning methods have strong potential for classifying lithology from log data because: 1) they can automatically define complex, non-parametric, multi-variate relationships across several input logs; and 2) they allow classifications to be quantified confidently. Furthermore, this approach captured the knowledge and nuances of an interpreter's decisions by training the algorithm using human-interpreted labels. In the hydrocarbon industry, the quantity of generated data is predicted to increase by >300% between 2018 and 2023 (IDC, Worldwide Global DataSphere Forecast, 2019–2023). Additionally, the industry holds vast legacy data. This supervised machine learning approach can unlock the potential of some of these datasets by providing consistent lithology interpretations rapidly, allowing resources to be used more effectively.
本文介绍了机器学习和云部署方面的进展，这些进展可以实现快速、准确的自动岩性解释。介绍了一种监督式机器学习技术，该技术可以快速、一致、准确地预测岩性，同时消除大型电缆或随钻测井(LWD)数据集的定量不确定性。为了利用监督式机器学习，一个由地球科学家和岩石物理学家组成的团队对油井进行了详细的岩性解释，以生成一个全面的训练数据集。岩性解释是利用和组合各种原始测井资料，采用确定性交叉标绘方法进行的。该训练数据集用于开发模型和测试机器学习管道。该管道被应用于算法以前未见过的数据集，以预测岩性。一名岩石物理学家进行了质量检查，以验证管道提供的新预测与人类解释的不同。人们用两种方式评估对这些解释的信心。计算先验概率，即模型识别输入数据的置信度。计算后验概率，量化指定深度区间包含给定岩性的可能性。监督式机器学习算法通过消除解释器的偏差和不一致性，确保了井的解释一致性。云计算的可扩展性使大型日志数据集能够快速解释;在5分钟内连续解释了100口井，与人类岩石物理解释的岩性匹配度超过70%。有监督机器学习方法在从测井数据中分类岩性方面具有很大的潜力，因为:1)它们可以自动定义多个输入测井数据之间复杂的、非参数的、多变量的关系;2)它们允许分类被自信地量化。此外，这种方法通过使用人工解释的标签训练算法来捕获解释器决策的知识和细微差别。在油气行业，预计从2018年到2023年，生成的数据量将增加300%以上(IDC, Worldwide Global DataSphere Forecast, 2019-2023)。此外，该行业还拥有大量遗留数据。这种有监督的机器学习方法可以通过快速提供一致的岩性解释来释放其中一些数据集的潜力，从而更有效地利用资源。
{"title":"Using Supervised Machine Learning Algorithms for Automated Lithology Prediction from Wireline Log Data","authors":"M. Popescu, Rebecca Head, T. Ferriday, K. Evans, J. Montero, Jiazuo Zhang, Gwynfor Jones, G. Kaeng","doi":"10.2118/208559-ms","DOIUrl":"https://doi.org/10.2118/208559-ms","url":null,"abstract":"\u0000 This paper presents advancements in machine learning and cloud deployment that enable rapid and accurate automated lithology interpretation. A supervised machine learning technique is described that enables rapid, consistent, and accurate lithology prediction alongside quantitative uncertainty from large wireline or logging-while-drilling (LWD) datasets.\u0000 To leverage supervised machine learning, a team of geoscientists and petrophysicists made detailed lithology interpretations of wells to generate a comprehensive training dataset. Lithology interpretations were based on applying determinist cross-plotting by utilizing and combining various raw logs. This training dataset was used to develop a model and test a machine learning pipeline. The pipeline was applied to a dataset previously unseen by the algorithm, to predict lithology. A quality checking process was performed by a petrophysicist to validate new predictions delivered by the pipeline against human interpretations.\u0000 Confidence in the interpretations was assessed in two ways. The prior probability was calculated, a measure of confidence in the input data being recognized by the model. Posterior probability was calculated, which quantifies the likelihood that a specified depth interval comprises a given lithology.\u0000 The supervised machine learning algorithm ensured that the wells were interpreted consistently by removing interpreter biases and inconsistencies. The scalability of cloud computing enabled a large log dataset to be interpreted rapidly; >100 wells were interpreted consistently in five minutes, yielding >70% lithological match to the human petrophysical interpretation.\u0000 Supervised machine learning methods have strong potential for classifying lithology from log data because: 1) they can automatically define complex, non-parametric, multi-variate relationships across several input logs; and 2) they allow classifications to be quantified confidently. Furthermore, this approach captured the knowledge and nuances of an interpreter's decisions by training the algorithm using human-interpreted labels.\u0000 In the hydrocarbon industry, the quantity of generated data is predicted to increase by >300% between 2018 and 2023 (IDC, Worldwide Global DataSphere Forecast, 2019–2023). Additionally, the industry holds vast legacy data. This supervised machine learning approach can unlock the potential of some of these datasets by providing consistent lithology interpretations rapidly, allowing resources to be used more effectively.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80086396","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}
Enhancing the production in liquid-loaded horizontal natural gas wells using an acoustic liquid atomizer tool is proposed as a possible artificial lift method. The more liquid that is converted to droplets, the more available gas is able to carry the liquid to the surface, resulting in an increase in production. The acoustic atomizer was selected to be the atomization device as it can create very small droplets at certain frequencies leading to a mist flow. The contribution of this research includes obtaining experimental data using different laboratory procedures for horizontal and slightly inclined tubulars. Two-phase (gas and water) injection stream lines are joined to the test section to introduce gas and water at desired rates. An ultrasonic atomizer inside the test section is used to better understand the atomization mechanism as an artificial lift technique. Several experiments with varying factors influencing the acoustic properties are tested including varying liquid and gas rates, four different frequencies, two different flow pipe inclination angles, and two different acoustic device orientations. The results show that when using frequencies of 62 and 62.5 kHz, the outcomes were almost identical for horizontal and slightly inclined pipe. Both frequencies reduced liquid film accumulation by 1% at lower (0.001 m/s) and higher (0.0168 m/s) liquid velocities while gas velocity was kept at 14 m/s. The performance of the acoustic tool was highly dependent on the orientation of the tool inside the flow loop due to its atomizer geometry, shape and size. Sprayers facing up (0°, original case) helped the droplets to be carried by the gas since the gas occupies the top portion of the pipe and did not block the atomizer. The sprayers failed to work while facing the bottom of the pipe (180°) due to water accumulating around the sprayers, plugging the atomizer and hindering it from working. Using an orientation of 90° (sprayers facing sideways) provided better results and positive impact in reducing the liquid film level. The efficiency of the tool decreases in slightly inclined wells. As more liquid quantity accumulated in the well, the atomization technique seems to be slow in reducing the liquid film height. This research presents a set of diverse experimental data to suggest acoustic atomization might be used as a possible artificial lift technique in horizontal wells. The technique shows a 1-4% improvement which might be experimental error or in experimental control. Thus, the device used in the lab needs improvement to work as efficiently as other artificial lift techniques to possibly enhance production.
{"title":"Experimental Investigation of Acoustic Atomization in Liquid Loading Horizontal Gas Wells","authors":"Eiman Al Munif, J. Miskimins","doi":"10.2118/208560-ms","DOIUrl":"https://doi.org/10.2118/208560-ms","url":null,"abstract":"\u0000 Enhancing the production in liquid-loaded horizontal natural gas wells using an acoustic liquid atomizer tool is proposed as a possible artificial lift method. The more liquid that is converted to droplets, the more available gas is able to carry the liquid to the surface, resulting in an increase in production. The acoustic atomizer was selected to be the atomization device as it can create very small droplets at certain frequencies leading to a mist flow.\u0000 The contribution of this research includes obtaining experimental data using different laboratory procedures for horizontal and slightly inclined tubulars. Two-phase (gas and water) injection stream lines are joined to the test section to introduce gas and water at desired rates. An ultrasonic atomizer inside the test section is used to better understand the atomization mechanism as an artificial lift technique. Several experiments with varying factors influencing the acoustic properties are tested including varying liquid and gas rates, four different frequencies, two different flow pipe inclination angles, and two different acoustic device orientations.\u0000 The results show that when using frequencies of 62 and 62.5 kHz, the outcomes were almost identical for horizontal and slightly inclined pipe. Both frequencies reduced liquid film accumulation by 1% at lower (0.001 m/s) and higher (0.0168 m/s) liquid velocities while gas velocity was kept at 14 m/s. The performance of the acoustic tool was highly dependent on the orientation of the tool inside the flow loop due to its atomizer geometry, shape and size. Sprayers facing up (0°, original case) helped the droplets to be carried by the gas since the gas occupies the top portion of the pipe and did not block the atomizer. The sprayers failed to work while facing the bottom of the pipe (180°) due to water accumulating around the sprayers, plugging the atomizer and hindering it from working. Using an orientation of 90° (sprayers facing sideways) provided better results and positive impact in reducing the liquid film level. The efficiency of the tool decreases in slightly inclined wells. As more liquid quantity accumulated in the well, the atomization technique seems to be slow in reducing the liquid film height.\u0000 This research presents a set of diverse experimental data to suggest acoustic atomization might be used as a possible artificial lift technique in horizontal wells. The technique shows a 1-4% improvement which might be experimental error or in experimental control. Thus, the device used in the lab needs improvement to work as efficiently as other artificial lift techniques to possibly enhance production.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79605478","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}
CO2 migration and trapping in saline aquifers involves the injection of a non-wetting fluid that displaces the in-situ brine, a process that is often termed ‘drainage’ in reservoir flow dynamics. With respect to simulation, however, this process is more typical of regional basin modelling and percolating hydrocarbon migration. In this study, we applied the invasion percolation method commonly used in hydrocarbon migration modelling to the CO2 injection operation at the Sleipner storage site. We applied a CO2 migration model that was simulated using a modified invasion percolation algorithm, based upon the Young-Laplace principle of fluid flow. This algorithm assumes that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy (driving) and capillary (restrictive) forces. Entrapment occurs when rock capillary threshold pressure exceeds fluid buoyancy pressure. Leaking occurs when fluid buoyancy pressure exceeds rock capillary threshold pressure. This is now widely understood to be an accurate description of basin-scale hydrocarbon migration and reservoir filling. The geological and geophysical analysis of the Sleipner CO2 plume anatomy, as observed from the seismic data, suggested that the distribution of CO2 was strongly affected by the geological heterogeneity of the storage formation. In the simulation model, the geological heterogeneity were honored by taking the original resolution of the seismic volume as the base grid. The model was then run at an ultra-fast simulation time in a matter of seconds or minutes per realization, which allowed multiple scenarios to be performed for uncertainty analysis. It was then calibrated to the CO2 plume distribution observed on seismic, and achieved an accurate match. The paper establishes that the physical principle of CO2 flow dynamics follows the Young-Laplace flow physics. It is then argued that this method is most suitable for the regional site screening and characterization, as well as for site-specific injectivity and containment analysis in saline aquifers.
{"title":"Using Basin Modelling to Understand Injected CO2 Migration and Trapping Mechanisms: A Case Study from the Sleipner CO2 Storage Operation","authors":"G. Kaeng, K. Evans, F. Bebb, Rebecca Head","doi":"10.2118/208544-ms","DOIUrl":"https://doi.org/10.2118/208544-ms","url":null,"abstract":"\u0000 CO2 migration and trapping in saline aquifers involves the injection of a non-wetting fluid that displaces the in-situ brine, a process that is often termed ‘drainage’ in reservoir flow dynamics. With respect to simulation, however, this process is more typical of regional basin modelling and percolating hydrocarbon migration. In this study, we applied the invasion percolation method commonly used in hydrocarbon migration modelling to the CO2 injection operation at the Sleipner storage site.\u0000 We applied a CO2 migration model that was simulated using a modified invasion percolation algorithm, based upon the Young-Laplace principle of fluid flow. This algorithm assumes that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy (driving) and capillary (restrictive) forces. Entrapment occurs when rock capillary threshold pressure exceeds fluid buoyancy pressure. Leaking occurs when fluid buoyancy pressure exceeds rock capillary threshold pressure. This is now widely understood to be an accurate description of basin-scale hydrocarbon migration and reservoir filling.\u0000 The geological and geophysical analysis of the Sleipner CO2 plume anatomy, as observed from the seismic data, suggested that the distribution of CO2 was strongly affected by the geological heterogeneity of the storage formation. In the simulation model, the geological heterogeneity were honored by taking the original resolution of the seismic volume as the base grid. The model was then run at an ultra-fast simulation time in a matter of seconds or minutes per realization, which allowed multiple scenarios to be performed for uncertainty analysis. It was then calibrated to the CO2 plume distribution observed on seismic, and achieved an accurate match.\u0000 The paper establishes that the physical principle of CO2 flow dynamics follows the Young-Laplace flow physics. It is then argued that this method is most suitable for the regional site screening and characterization, as well as for site-specific injectivity and containment analysis in saline aquifers.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81896505","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Karachaganak field is a massive reef carbonate structure. The main reservoir is of the late Devonian-Carboniferous age, where sequence stratigraphic cycles of progradation and aggradation defining the growth stages of the carbonate build-up have been revealed. Vertical and horizontal semiconductive barriers was identified in the reservoir during the field development. It was assumed that these barriers are located at the boundaries of the changing depositional cycles, which took place during the reef structure growth. According to the simulation results on a sector model of the reservoir it was determined that the pressure barriers can be developed due to different fracture intensities observed in the reservoir and not because of rock property as such. The reason for the different fracture densities may be associated with compaction during primary diagenesis and may have a sync-depositional nature, which can be seen on carbonate structure outcrops.
{"title":"Understanding of Vertical and Horizontal Pressure Barriers in the Naturally Fractured Carbonate Field","authors":"A. Ibragimov, Nurbolat Kalmuratov","doi":"10.2118/208548-ms","DOIUrl":"https://doi.org/10.2118/208548-ms","url":null,"abstract":"\u0000 The Karachaganak field is a massive reef carbonate structure. The main reservoir is of the late Devonian-Carboniferous age, where sequence stratigraphic cycles of progradation and aggradation defining the growth stages of the carbonate build-up have been revealed. Vertical and horizontal semiconductive barriers was identified in the reservoir during the field development. It was assumed that these barriers are located at the boundaries of the changing depositional cycles, which took place during the reef structure growth. According to the simulation results on a sector model of the reservoir it was determined that the pressure barriers can be developed due to different fracture intensities observed in the reservoir and not because of rock property as such. The reason for the different fracture densities may be associated with compaction during primary diagenesis and may have a sync-depositional nature, which can be seen on carbonate structure outcrops.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76294167","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 common problem in oil and gas field is premature and excessive water production through higher permeable thief zone, faults, water conning or channeling and natural or induced fracture. Excessive water production impacts the economics of a well through increasing rate of corrosion, emulsion and scale formation, consequently shortening its production life and lowering flowing wellhead pressure. There are several techniques used to control excessive water production such as chemical and mechanical. In this work a novel chemical approach was followed to tackle excessive water production in Taq Taq oil field located in Kurdistan Region Iraq. Water production into the reservoir was determined to be through the fractures as the reservoir units are highly fractured carbonates. Therefore, the chemicals designed by this work were to reduce excessive water production selectively and fracture connectivity in the zones where excessive water production is expected. Three nano-solutions have been prepared and investigated for their rheological properties. Only one is selected and met the field screening criteria. The composition of the nano-solutions were mainly polyacrylamide mixed with nano composite of cement, clay and inorganic cross-linker. All nano-solution underwent extensive screening and studied for their mechanical strength, toughness and tensile module. Results showed that nano-solutions strength increases with increasing the nano concentration. Similarly, their viscosity and degradation resistance are improved noticeably with nano composites. The scanning Electron Microscopy (SEM) was also used to characterized the nano size and distribution studied by this work.
{"title":"Nano Chemical Design for Excessive Water Production Control in Taq Taq Oil Field","authors":"Sakar Soka, H. Sidiq","doi":"10.2118/208546-ms","DOIUrl":"https://doi.org/10.2118/208546-ms","url":null,"abstract":"\u0000 A common problem in oil and gas field is premature and excessive water production through higher permeable thief zone, faults, water conning or channeling and natural or induced fracture. Excessive water production impacts the economics of a well through increasing rate of corrosion, emulsion and scale formation, consequently shortening its production life and lowering flowing wellhead pressure. There are several techniques used to control excessive water production such as chemical and mechanical.\u0000 In this work a novel chemical approach was followed to tackle excessive water production in Taq Taq oil field located in Kurdistan Region Iraq. Water production into the reservoir was determined to be through the fractures as the reservoir units are highly fractured carbonates. Therefore, the chemicals designed by this work were to reduce excessive water production selectively and fracture connectivity in the zones where excessive water production is expected.\u0000 Three nano-solutions have been prepared and investigated for their rheological properties. Only one is selected and met the field screening criteria. The composition of the nano-solutions were mainly polyacrylamide mixed with nano composite of cement, clay and inorganic cross-linker. All nano-solution underwent extensive screening and studied for their mechanical strength, toughness and tensile module. Results showed that nano-solutions strength increases with increasing the nano concentration. Similarly, their viscosity and degradation resistance are improved noticeably with nano composites.\u0000 The scanning Electron Microscopy (SEM) was also used to characterized the nano size and distribution studied by this work.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76057534","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The advantage of cable deployed electric submersible pump (CDESP) systems are beginning to be understood and realized as experience has been gained with the deployment and retrieval of these systems. Cable deployed ESP systems have at times been touted as a temporary system for failed conventional ESP systems. Long-term successes have demonstrated the value of permanently installed CDESP systems, which provide the benefit of reduced production deferral, less costly change-out, and reduced HSE risk. The decision to change from conventional ESP to a rigless CDESP system is not necessarily a simple conclusion. The decision must consider technical, economic, and operational considerations to gain the full benefit from the technology. The learnings developed over multiple deployments and retrievals will benefit decision makers in the evaluation of the technology use. The technology application presented in the paper sheds the light on a journey to develop and bring alternative ESP deployment from concept to reality, overcoming technical and operational challenges. The current CDESP requires a rig to initially construct the permanent completion to accept the rigless CDESP system. Production rates requirements determine the ESP size, and in turn the tubing and wellhead size. Pressure control equipment is installed on top of the Christmas tree. Rigless installation and retrieval of the CDESP is performed on an elevated tower with the wellhead in place. The tower design has been improved to allow the production flowline to remain in place. A minimum of two well barriers, with one barrier well kill fluid, are in place at all times. A key learning of the killed well CDESP system is the need to understand the potential changes to the reservoir after sustained production in planning the replacement of a failed ESP. Kill fluid losses can be higher than expected with restorative well cleanup and production. Actual deployment or retrieval time can be improved with successive change-outs. Long-term operational robustness of the CDESP is proven with a system continuing to operate after 5 years of cumulative operations. This paper shares the lessons learned from an early technology adopter with multiple deployment and retrievals in various well environments including highly fractured reservoirs and high hydrogen sulfide wells.
{"title":"Overcoming Deployment and Retrieval Challenges with Killed Well Cable Deployed Electric Submersible Pump Systems – Lessons Learned from Five Years of CDESP History","authors":"Jinjiang Xiao, Mulad Winaro, Mohammas Eissa, Akram Mahmoud","doi":"10.2118/208551-ms","DOIUrl":"https://doi.org/10.2118/208551-ms","url":null,"abstract":"\u0000 The advantage of cable deployed electric submersible pump (CDESP) systems are beginning to be understood and realized as experience has been gained with the deployment and retrieval of these systems. Cable deployed ESP systems have at times been touted as a temporary system for failed conventional ESP systems. Long-term successes have demonstrated the value of permanently installed CDESP systems, which provide the benefit of reduced production deferral, less costly change-out, and reduced HSE risk.\u0000 The decision to change from conventional ESP to a rigless CDESP system is not necessarily a simple conclusion. The decision must consider technical, economic, and operational considerations to gain the full benefit from the technology. The learnings developed over multiple deployments and retrievals will benefit decision makers in the evaluation of the technology use. The technology application presented in the paper sheds the light on a journey to develop and bring alternative ESP deployment from concept to reality, overcoming technical and operational challenges.\u0000 The current CDESP requires a rig to initially construct the permanent completion to accept the rigless CDESP system. Production rates requirements determine the ESP size, and in turn the tubing and wellhead size. Pressure control equipment is installed on top of the Christmas tree. Rigless installation and retrieval of the CDESP is performed on an elevated tower with the wellhead in place. The tower design has been improved to allow the production flowline to remain in place. A minimum of two well barriers, with one barrier well kill fluid, are in place at all times. A key learning of the killed well CDESP system is the need to understand the potential changes to the reservoir after sustained production in planning the replacement of a failed ESP. Kill fluid losses can be higher than expected with restorative well cleanup and production. Actual deployment or retrieval time can be improved with successive change-outs. Long-term operational robustness of the CDESP is proven with a system continuing to operate after 5 years of cumulative operations.\u0000 This paper shares the lessons learned from an early technology adopter with multiple deployment and retrievals in various well environments including highly fractured reservoirs and high hydrogen sulfide wells.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72947379","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}
Eiman Al Munif, Ahmed A. Alrashed, Kanat Karatayev, J. Miskimins, Yilin Fan
Liquid loading is a major challenge in natural gas wells. Enhancing the production in liquid loading natural gas wells using an acoustic liquid atomizer tool is proposed as a possible artificial lift method. The effect of different droplet sizes on the transport efficiency and the performance of the proposed technique during production are studied using Computational Fluid Dynamics (CFD) simulation. Also, the liquid behavior and fluid dynamics after applying the atomization mechanism are reviewed. In the model, the tool is placed axially in the middle of the gas/air flowing wellbore. To reduce computational time, the tool and pipe are cut symmetrically. The pipe diameter is 4 in, and the four injectors diameters are each 0.04 in. The orientation of the injectors is set to 90° with the sprayers facing sideways, while water liquid droplets are injected from the tool surface into the air flow at angles from 45° to the flow direction. Unstructured hybrid mesh is used to allow the cells to assemble freely within the complex geometry. Sensitivity tests were conducted with droplet sizes ranging between 30-300 µm. The CFD results showed that water liquid droplets of size 30 µm followed the pathway along the tool surface due to the low mass of the droplets and high air velocity. This phenomenon is called wall impingement and occurs where the droplets are very small and clustering on the wall. The 200 and 300 µm water liquid droplets kept their inertial high chaotic movements in all directions within the computational fluid domain due to the increased weight of the droplets. These larger sized droplets withstand the backpressure from high turbulent air velocity and tend to keep their inertial turbulent movement. This research presents a set of CFD results to further evaluate acoustic atomization as a possible artificial lift technique. This technique has never been commercially applied in the oil and gas industry, and continued evaluation of such methods is a vital addition to the industry as it brings the potential for new lower cost artificial lift technologies. If completely developed, this technique can bring a cost-effective solution compared to conventional artificial lift methods.
{"title":"Modeling the Effects of Various Liquid Droplet Sizes in Acoustic Deliquification Techniques","authors":"Eiman Al Munif, Ahmed A. Alrashed, Kanat Karatayev, J. Miskimins, Yilin Fan","doi":"10.2118/208520-ms","DOIUrl":"https://doi.org/10.2118/208520-ms","url":null,"abstract":"\u0000 Liquid loading is a major challenge in natural gas wells. Enhancing the production in liquid loading natural gas wells using an acoustic liquid atomizer tool is proposed as a possible artificial lift method. The effect of different droplet sizes on the transport efficiency and the performance of the proposed technique during production are studied using Computational Fluid Dynamics (CFD) simulation. Also, the liquid behavior and fluid dynamics after applying the atomization mechanism are reviewed.\u0000 In the model, the tool is placed axially in the middle of the gas/air flowing wellbore. To reduce computational time, the tool and pipe are cut symmetrically. The pipe diameter is 4 in, and the four injectors diameters are each 0.04 in. The orientation of the injectors is set to 90° with the sprayers facing sideways, while water liquid droplets are injected from the tool surface into the air flow at angles from 45° to the flow direction. Unstructured hybrid mesh is used to allow the cells to assemble freely within the complex geometry. Sensitivity tests were conducted with droplet sizes ranging between 30-300 µm.\u0000 The CFD results showed that water liquid droplets of size 30 µm followed the pathway along the tool surface due to the low mass of the droplets and high air velocity. This phenomenon is called wall impingement and occurs where the droplets are very small and clustering on the wall. The 200 and 300 µm water liquid droplets kept their inertial high chaotic movements in all directions within the computational fluid domain due to the increased weight of the droplets. These larger sized droplets withstand the backpressure from high turbulent air velocity and tend to keep their inertial turbulent movement.\u0000 This research presents a set of CFD results to further evaluate acoustic atomization as a possible artificial lift technique. This technique has never been commercially applied in the oil and gas industry, and continued evaluation of such methods is a vital addition to the industry as it brings the potential for new lower cost artificial lift technologies. If completely developed, this technique can bring a cost-effective solution compared to conventional artificial lift methods.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88832310","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}
I. Karpenko, I. Ischenko, Olha Nikolenko, F. Rodrigues, Serhii Levonyuk, Vitalii Glon, B. Wygrala, V. Privalov
The Ukrainian sector of the Western Black Sea (WBS) is one of the last remaining exploration frontiers in Europe. This area, which includes shelf to deepwater environments, is underexplored with no drilling of targets in water depths exceeding 100 meters. That is why, the Ukrainian sector of the WBS is attractive for exploration, especially in the context of new play types and targets such as biogenic gas. These hydrocarbon formations have been proven by neighboring Romania and Turkey in the areas adjacent to Ukrainian waters. Therefore, a rigorous Basin Analysis program has been initiated to assess the petroleum systems and play risks in the entire Ukrainian sector of the WBS. The goals of this program are: 1) to establish a regional geoscience foundation following best industrial practices in exploration; 2) to enable establishing more accurate risking and ranking procedures for an exploration portfolio and 3) to provide critical support for the analysis of a new generation of seismic data that is currently being acquired. In this paper the initial scope of work is presented.
{"title":"Basins Analysis and Petroleum Systems Modeling of Western Black Sea, Ukrainian Sector","authors":"I. Karpenko, I. Ischenko, Olha Nikolenko, F. Rodrigues, Serhii Levonyuk, Vitalii Glon, B. Wygrala, V. Privalov","doi":"10.2118/208527-ms","DOIUrl":"https://doi.org/10.2118/208527-ms","url":null,"abstract":"\u0000 The Ukrainian sector of the Western Black Sea (WBS) is one of the last remaining exploration frontiers in Europe. This area, which includes shelf to deepwater environments, is underexplored with no drilling of targets in water depths exceeding 100 meters. That is why, the Ukrainian sector of the WBS is attractive for exploration, especially in the context of new play types and targets such as biogenic gas. These hydrocarbon formations have been proven by neighboring Romania and Turkey in the areas adjacent to Ukrainian waters.\u0000 Therefore, a rigorous Basin Analysis program has been initiated to assess the petroleum systems and play risks in the entire Ukrainian sector of the WBS. The goals of this program are: 1) to establish a regional geoscience foundation following best industrial practices in exploration; 2) to enable establishing more accurate risking and ranking procedures for an exploration portfolio and 3) to provide critical support for the analysis of a new generation of seismic data that is currently being acquired. In this paper the initial scope of work is presented.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80086346","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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