A proven approach in exploration management is to establish multi-disciplinary Basin Analysis (BA) Teams that follow industry best practices and standardized procedures to deliver geologic risk assessments to both management and asset teams. Team members have the ability to provide a combination of specific technical expertise that is used to develop long-term foundation knowledge of basins and plays, but at the same time enables them to react to management and asset team requests for rapid assessments such as block and prospect risking/ranking and investigations of specific geologic challenges. In this paper, we review requirements for the establishment of successful Basin Analysis (BA) teams and provide examples of methodologies, strategies and technical workflows that are being applied to address exploration challenges in the three main exploration target areas in Ukraine, the Western Black Sea (WBS), the Dieper-Donets Basin (DDB) and the Carpathians are in Western Ukraine. For each of these target areas, we provide an example of a BA Team strategy that is followed to address specific exploration challenges. The application of industry standard best practices in exploration by a dedicated expert team and close cooperation with asset and technical teams within the organisation ensures that these engagements will make an important contribution to improve the efficiency and success rates of exploration activities in Ukraine.
{"title":"Strategic Value of Basin Analysis Teams in Exploration – Applications in Ukraine","authors":"B. Wygrala, I. Karpenko, F. R. Monreal","doi":"10.2118/208528-ms","DOIUrl":"https://doi.org/10.2118/208528-ms","url":null,"abstract":"\u0000 A proven approach in exploration management is to establish multi-disciplinary Basin Analysis (BA) Teams that follow industry best practices and standardized procedures to deliver geologic risk assessments to both management and asset teams. Team members have the ability to provide a combination of specific technical expertise that is used to develop long-term foundation knowledge of basins and plays, but at the same time enables them to react to management and asset team requests for rapid assessments such as block and prospect risking/ranking and investigations of specific geologic challenges.\u0000 In this paper, we review requirements for the establishment of successful Basin Analysis (BA) teams and provide examples of methodologies, strategies and technical workflows that are being applied to address exploration challenges in the three main exploration target areas in Ukraine, the Western Black Sea (WBS), the Dieper-Donets Basin (DDB) and the Carpathians are in Western Ukraine. For each of these target areas, we provide an example of a BA Team strategy that is followed to address specific exploration challenges. The application of industry standard best practices in exploration by a dedicated expert team and close cooperation with asset and technical teams within the organisation ensures that these engagements will make an important contribution to improve the efficiency and success rates of exploration activities in Ukraine.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77512541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Zambrano, M. Sadivnyk, Yevhen Makar, C. Cavalleri, D. Rose
Formation evaluation using cased-hole logs is a primary option for re-evaluating old wells in brownfields or contingency logging in new wells. Its consistency with a robust open hole evaluation is vital for its future implementation in field development. This work describes detailed open- and cased- hole evaluation workflows integrating different advanced subsurface measurements and alternative interpretation techniques to reduce the uncertainties of deriving the main petrophysical properties across the conventional and tight gas reservoirs in the Dnieper-Donets basin. Since not all open-hole measurements can be recorded behind casing and some of the cased hole logs are not characterized for open hole conditions, it is not always possible to implement the same evaluation techniques for measurements done in open hole and cased hole. Nevertheless, different measurements provide different formation responses that supplement their gaps from one another. A wireline data acquisition strategy has been elaborated to carry out formation evaluation workflows using open- and cased-hole data independently but learning from each other. The methodology is based on novel and non-standard evaluation techniques that use measurements from advanced wireline technology such as nuclear magnetic resonance (NMR) and advanced pulsed neutron spectroscopy logs. The methodology was applied to log data recorded on the Visean and Serpukhovian (Lower Carboniferous) productive gas zones, characterized by porosity (5-15pu) and permeability (0.1-100mD). The principal challenge for the formation evaluation of these reservoirs is deriving an accurate estimation of porosity, which requires removing the gas and matrix effects on the log responses. An inaccurate porosity estimation will result in an inaccurate permeability and water saturation, and the problem worsens in low-porosity rocks. In the open hole, the porosity computation from the Density-Magnetic Resonance (DMR) technique has proven to be more accurate in comparison with common single porosity methods. The same problem is addressed in cased hole conditions with the advanced pulsed neutron spectroscopy logs and a novel technique that combines the thermal neutron elastic scattering and fast neutron cross sections to obtain a gas-free and matrix-corrected porosity, as well as a resistivity independent gas saturation. The consistency of petrophysical properties independently estimated from the two separate workflows add confidence to the approach, and this is reflected in the gas production obtained from the perforated intervals. This script describes in detail the open- and cased- hole formation evaluation workflows and the wireline technology and methodologies applied. Actual examples illustrate the effectiveness of these quantitative approaches in the Dnieper-Donets basin.
{"title":"Open- and Cased- Hole Formation Evaluation Workflows Running Together for Reducing Uncertainties in Gas Reservoirs: An Acquisition Data and Evaluation Strategy in Dnieper-Donets Basin, Ukraine","authors":"R. Zambrano, M. Sadivnyk, Yevhen Makar, C. Cavalleri, D. Rose","doi":"10.2118/208558-ms","DOIUrl":"https://doi.org/10.2118/208558-ms","url":null,"abstract":"\u0000 Formation evaluation using cased-hole logs is a primary option for re-evaluating old wells in brownfields or contingency logging in new wells. Its consistency with a robust open hole evaluation is vital for its future implementation in field development. This work describes detailed open- and cased- hole evaluation workflows integrating different advanced subsurface measurements and alternative interpretation techniques to reduce the uncertainties of deriving the main petrophysical properties across the conventional and tight gas reservoirs in the Dnieper-Donets basin.\u0000 Since not all open-hole measurements can be recorded behind casing and some of the cased hole logs are not characterized for open hole conditions, it is not always possible to implement the same evaluation techniques for measurements done in open hole and cased hole. Nevertheless, different measurements provide different formation responses that supplement their gaps from one another. A wireline data acquisition strategy has been elaborated to carry out formation evaluation workflows using open- and cased-hole data independently but learning from each other. The methodology is based on novel and non-standard evaluation techniques that use measurements from advanced wireline technology such as nuclear magnetic resonance (NMR) and advanced pulsed neutron spectroscopy logs.\u0000 The methodology was applied to log data recorded on the Visean and Serpukhovian (Lower Carboniferous) productive gas zones, characterized by porosity (5-15pu) and permeability (0.1-100mD). The principal challenge for the formation evaluation of these reservoirs is deriving an accurate estimation of porosity, which requires removing the gas and matrix effects on the log responses. An inaccurate porosity estimation will result in an inaccurate permeability and water saturation, and the problem worsens in low-porosity rocks. In the open hole, the porosity computation from the Density-Magnetic Resonance (DMR) technique has proven to be more accurate in comparison with common single porosity methods. The same problem is addressed in cased hole conditions with the advanced pulsed neutron spectroscopy logs and a novel technique that combines the thermal neutron elastic scattering and fast neutron cross sections to obtain a gas-free and matrix-corrected porosity, as well as a resistivity independent gas saturation. The consistency of petrophysical properties independently estimated from the two separate workflows add confidence to the approach, and this is reflected in the gas production obtained from the perforated intervals.\u0000 This script describes in detail the open- and cased- hole formation evaluation workflows and the wireline technology and methodologies applied. Actual examples illustrate the effectiveness of these quantitative approaches in the Dnieper-Donets basin.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81618651","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}
Rechitsa multi-play oilfield is located within the Rechitsko-Vishanskaya subregional area of local uplifts of the Rechitsko-Vishanskaya tectonic stage of the Northern structural zone of the Pripyat Trough in the Republic of Belarus. Since 2014, Production Association Belorusneft has been conducting integrated research to study oil bearing capacity of sediments within rock Units I-III, which were previously considered to have no potential. Since then, the lithological and petrophysical, pyrolytic, and geomechanical features of the structure of these sediments have been studied. The research has confirmed the initial hypothesis that the studied sediments are unconventional reservoirs with source-rock genesis and contain hydrocarbons both of their own genesis and those which migrated from other rocks. The results of drilling and completion of horizontal exploration wells with multi-stage hydraulic fracturing confirmed the potential for obtaining commercial oil from the sediments of the unconventional reservoirs. At the same time, there were doubts about the optimal placement of the horizontal wells, the choice of completion strategy, and if the well performance lived up to the actual maximum potential of these sediments. The paper sums up the main results of implementing an integrated program for studying unconventional reservoirs of the Rechitsa oilfield, as well as of drilling and operating production wells to date.
{"title":"The Results of an Integrated Study of Unconventional Reservoirs and a First Attempt at their Development","authors":"A. Kudryashov","doi":"10.2118/208524-ms","DOIUrl":"https://doi.org/10.2118/208524-ms","url":null,"abstract":"\u0000 Rechitsa multi-play oilfield is located within the Rechitsko-Vishanskaya subregional area of local uplifts of the Rechitsko-Vishanskaya tectonic stage of the Northern structural zone of the Pripyat Trough in the Republic of Belarus. Since 2014, Production Association Belorusneft has been conducting integrated research to study oil bearing capacity of sediments within rock Units I-III, which were previously considered to have no potential. Since then, the lithological and petrophysical, pyrolytic, and geomechanical features of the structure of these sediments have been studied. The research has confirmed the initial hypothesis that the studied sediments are unconventional reservoirs with source-rock genesis and contain hydrocarbons both of their own genesis and those which migrated from other rocks. The results of drilling and completion of horizontal exploration wells with multi-stage hydraulic fracturing confirmed the potential for obtaining commercial oil from the sediments of the unconventional reservoirs. At the same time, there were doubts about the optimal placement of the horizontal wells, the choice of completion strategy, and if the well performance lived up to the actual maximum potential of these sediments.\u0000 The paper sums up the main results of implementing an integrated program for studying unconventional reservoirs of the Rechitsa oilfield, as well as of drilling and operating production wells to date.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90624751","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}
O. Burachok, D. Pershyn, O. Kondrat, S. Matkivskyi, Y. Bikman
Majority of gas-condensate reservoir discoveries in Dnieper-Donets Basin (Ukraine), is characterized by limited composition only up to C5+, phase behavior studied by non-equilibrium, so called differential condensation PVT experiment, combined with the uncertainty in condensate production allocation to individual wells, makes the direct application of the results in modern PVT modeling software not possible. The new method, based on the Engler distillation test (ASTM86) for definition of pseudo-components combined with synthetic creation of liquid saturation curve for CVD experiment, was proposed and successfully applied for different gas-condensate reservoirs in the area of study. The quality control (QC) of the PVT model is further performed by applying material-balance method on a single-cell simulation model for exported black-oil PVT formulation when needed. The method proved being useful for modeling of multiple gas-condensate reservoirs of Dnieper-Donets Basin with different potential condensate yields varying from 30 to 700 g/m3 and as an example presented for two reservoir fluids with 108 and 536 g/m3. Results of numerical simulation studies were within the engineering accuracy in comparison to historically observed values. The investigation showed that a representative fluid model can be create in the cases when no detailed fluid composition or required laboratory experiments are available. PVT model can be efficiently validated and QC-ed by performing material-balance type numeric simulation constructed with one cell. However, the proper fluid sampling and PVT cell laboratory experiments are still major requirements for precise reservoir fluid characterization and equation of state (EOS) modeling.
{"title":"Theoretical and Methodological Features for Gas-condensate PVT Fluid Modelling with Limited Data","authors":"O. Burachok, D. Pershyn, O. Kondrat, S. Matkivskyi, Y. Bikman","doi":"10.2118/208519-ms","DOIUrl":"https://doi.org/10.2118/208519-ms","url":null,"abstract":"\u0000 Majority of gas-condensate reservoir discoveries in Dnieper-Donets Basin (Ukraine), is characterized by limited composition only up to C5+, phase behavior studied by non-equilibrium, so called differential condensation PVT experiment, combined with the uncertainty in condensate production allocation to individual wells, makes the direct application of the results in modern PVT modeling software not possible. The new method, based on the Engler distillation test (ASTM86) for definition of pseudo-components combined with synthetic creation of liquid saturation curve for CVD experiment, was proposed and successfully applied for different gas-condensate reservoirs in the area of study. The quality control (QC) of the PVT model is further performed by applying material-balance method on a single-cell simulation model for exported black-oil PVT formulation when needed.\u0000 The method proved being useful for modeling of multiple gas-condensate reservoirs of Dnieper-Donets Basin with different potential condensate yields varying from 30 to 700 g/m3 and as an example presented for two reservoir fluids with 108 and 536 g/m3. Results of numerical simulation studies were within the engineering accuracy in comparison to historically observed values. The investigation showed that a representative fluid model can be create in the cases when no detailed fluid composition or required laboratory experiments are available. PVT model can be efficiently validated and QC-ed by performing material-balance type numeric simulation constructed with one cell. However, the proper fluid sampling and PVT cell laboratory experiments are still major requirements for precise reservoir fluid characterization and equation of state (EOS) modeling.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89808854","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}
Complex hydrocarbon charging and distribution in which reservoirs are filled by oil and gas phases with different densities and genetic types inter-fingering within the basin, are common phenomena, and often attributed to vertical migration. This paper discusses the factors that control vertical hydrocarbon migration and presents modelling of the hydrocarbon charging and entrapment history in a tertiary basin in Southeast Asia as a case study. According to the Young-Laplace flow theory of the secondary hydrocarbon migration mechanics, migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. In this study, the invasion percolation simulation algorithm, based on the Young-Laplace flow, was used. During the simulation, three-dimensional (3D) seismic data were used as the high-resolution base grid for migration to capture the effect of both structure and facies heterogeneities on fluid flow. A model of an unfaulted system was presented to make the case. In the study area there is inter-fingering between oil and gas across different formations; most oils are trapped in the deeper formation, oil and gas inter-fingering occurs in the middle formation, and the upper formation contains mostly gas. This arrangement is possible because of the interplay between the expelled fluid buoyancy and relatively weak intra-formational seals within the basin. The modeling results were then calibrated to known accumulations or fluid presence in wells. In a basin dominated by a vertical migration regime, hydrocarbons are prevented from travelling far from the kitchen, thus decreasing prospectivity away from the kitchen. Through a case study, this paper helps to understand the factors that influence hydrocarbon retention and migration that control fluid distribution within a basin. Eventually the study helps geologists to understand prospectivity risking related to hydrocarbon charging, which is one of the main risks in exploration especially in mature basins.
{"title":"Hydrocarbon Retention and the Case for Vertical Migration","authors":"G. Kaeng, K. Evans, F. Bebb, R. Head","doi":"10.2118/208526-ms","DOIUrl":"https://doi.org/10.2118/208526-ms","url":null,"abstract":"\u0000 Complex hydrocarbon charging and distribution in which reservoirs are filled by oil and gas phases with different densities and genetic types inter-fingering within the basin, are common phenomena, and often attributed to vertical migration. This paper discusses the factors that control vertical hydrocarbon migration and presents modelling of the hydrocarbon charging and entrapment history in a tertiary basin in Southeast Asia as a case study.\u0000 According to the Young-Laplace flow theory of the secondary hydrocarbon migration mechanics, migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. In this study, the invasion percolation simulation algorithm, based on the Young-Laplace flow, was used. During the simulation, three-dimensional (3D) seismic data were used as the high-resolution base grid for migration to capture the effect of both structure and facies heterogeneities on fluid flow.\u0000 A model of an unfaulted system was presented to make the case. In the study area there is inter-fingering between oil and gas across different formations; most oils are trapped in the deeper formation, oil and gas inter-fingering occurs in the middle formation, and the upper formation contains mostly gas. This arrangement is possible because of the interplay between the expelled fluid buoyancy and relatively weak intra-formational seals within the basin. The modeling results were then calibrated to known accumulations or fluid presence in wells. In a basin dominated by a vertical migration regime, hydrocarbons are prevented from travelling far from the kitchen, thus decreasing prospectivity away from the kitchen.\u0000 Through a case study, this paper helps to understand the factors that influence hydrocarbon retention and migration that control fluid distribution within a basin. Eventually the study helps geologists to understand prospectivity risking related to hydrocarbon charging, which is one of the main risks in exploration especially in mature basins.","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":"81006333","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}
Natural gas fields that are being developed in Ukraine, mainly relate to the high and medium permeability reservoirs, most of which are at the final stage of field life. In this situation one of the main sources of additional gas production is unconventional fields. This paper presents the analysis of challenges concerning development of low-permeable reservoirs and experimental results of conducted research, which provide the opportunity to establish technologies for enhance gas recovery factor. For this purpose, a series of laboratory experiments were carried out on the sand packed models of gas field with different permeability (from 9.7 to 93 mD) using natural gas. The pressure in the experiments varied from 1 to 10 MPa, temperature – 22-60 °C. According to the features of low-permeable gas fields development the research of displacement desorption with carbon dioxide and inert gas stripping by nitrogen was conducted. These studies also revealed the influence of pressure, temperature, reservoir permeability and non-hydrocarbon gases injection rate on the course of adsorption-desorption processes and their impact on the gas recovery factor. According to the experimental results of relative adsorption capacity determination it can be concluded that the carbon dioxide usage as the displacement agent can lead to producing adsorbed gas by more than 30% than by using nitrogen. To remove the adsorbed gas just reservoir pressure lowering is not enough due to the nature of adsorption isotherms. Particularly at pressure decreasing by 8-10 times compared to initial reservoir pressure only about 30-40% of the total amount of initially adsorbed gas is desorbed. And at considerable reservoir pressure reduction the further deposit development is not economically profitable. According to the results it was found that in the case of nitrogen usage the most effective method is full voidage replacement at injection pressure of 0.8 of the initial reservoir pressure, and in case of carbon dioxide usage - full voidage replacement method at pressure of 0.6 of the initial reservoir pressure. Taking into account availability of N2 and CO2, N2injection is recommended for further implementation. The influence of displacement agent injection pressure on gas recovery was experimentally proved. The physical sense of the processes taking place during natural gas desorption stimulation by non-hydrocarbon gases was justified. The effect of temperature, pressure and reservoir permeability on methane adsorption capacity were determined. The mathematical model for estimating adsorbed gas amount depending on the reservoir parameters was developed. Obtained results were summarized and recommendations for practical implementation of elaborated technological solutions were suggested.
{"title":"Low-Permeable Reservoirs as High Potential Assets for EGR","authors":"N. Hedzyk, O. Kondrat","doi":"10.2118/208555-ms","DOIUrl":"https://doi.org/10.2118/208555-ms","url":null,"abstract":"\u0000 Natural gas fields that are being developed in Ukraine, mainly relate to the high and medium permeability reservoirs, most of which are at the final stage of field life. In this situation one of the main sources of additional gas production is unconventional fields. This paper presents the analysis of challenges concerning development of low-permeable reservoirs and experimental results of conducted research, which provide the opportunity to establish technologies for enhance gas recovery factor.\u0000 For this purpose, a series of laboratory experiments were carried out on the sand packed models of gas field with different permeability (from 9.7 to 93 mD) using natural gas. The pressure in the experiments varied from 1 to 10 MPa, temperature – 22-60 °C. According to the features of low-permeable gas fields development the research of displacement desorption with carbon dioxide and inert gas stripping by nitrogen was conducted. These studies also revealed the influence of pressure, temperature, reservoir permeability and non-hydrocarbon gases injection rate on the course of adsorption-desorption processes and their impact on the gas recovery factor.\u0000 According to the experimental results of relative adsorption capacity determination it can be concluded that the carbon dioxide usage as the displacement agent can lead to producing adsorbed gas by more than 30% than by using nitrogen. To remove the adsorbed gas just reservoir pressure lowering is not enough due to the nature of adsorption isotherms. Particularly at pressure decreasing by 8-10 times compared to initial reservoir pressure only about 30-40% of the total amount of initially adsorbed gas is desorbed. And at considerable reservoir pressure reduction the further deposit development is not economically profitable.\u0000 According to the results it was found that in the case of nitrogen usage the most effective method is full voidage replacement at injection pressure of 0.8 of the initial reservoir pressure, and in case of carbon dioxide usage - full voidage replacement method at pressure of 0.6 of the initial reservoir pressure. Taking into account availability of N2 and CO2, N2injection is recommended for further implementation.\u0000 The influence of displacement agent injection pressure on gas recovery was experimentally proved. The physical sense of the processes taking place during natural gas desorption stimulation by non-hydrocarbon gases was justified. The effect of temperature, pressure and reservoir permeability on methane adsorption capacity were determined. The mathematical model for estimating adsorbed gas amount depending on the reservoir parameters was developed. Obtained results were summarized and recommendations for practical implementation of elaborated technological solutions were suggested.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87496195","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}
Khor Siew Hiang, Petrunyak Volodymyr, Yevgen A. Melnyk, Prykhodchenko Oleksii, Stefaniv Viktor, Dogar Andrew, Ojukwu Michael, Viscaino Andres
The adoption of an integrated asset modeling approach was explored to kick-start the corporate digital transformation strategy for its oil and gas section. Besides the integrated asset model, the digital initiatives included predictive maintenance, well performance optimization, and a flow assurance advisor aimed at daily production operations and maintenance, creating a pathway to the digital oilfield (DOF). The integrated asset model would be the main pillar of DOF realization and implementation, its offered technology aimed at short-term, medium-term, and long-term planning. The adopted well-proven integrated asset modeling methodology enabled a geological complex with a high-fidelity physics reservoir model, multiple interdependent wells, pipeline networks, process facility models to be integrated seamlessly on a single platform for validation of its existing production operation strategy and field development plan. The black-oil reservoir model was history matched, and the production network models had detailed wellbore and pipeline hydraulics calibrated with the latest well-test data. The compositional fluid modeling allowed the capture of any flow assurance issues that arose across the networks, which were mapped to the corresponding process facility models with physical specifications and operational constraints defined. A fully integrated asset model was developed for the studied asset, where liquid/vapor tables were prepared for black-oil delumping (Ghorayeb and Holmes, 2005) of the reservoir models to surface network models (Mora et al. 2015), while fluid models of both production network and process models were validated before mapping to ensure fluid fidelity. The availability of this integrated asset model with an embedded spreadsheet program incorporating some simple economic calculations allowed the flexibility of short-term production optimization and long-term asset planning, which was focused to provide all the vital valuable inputs to better field management, fast and accurate decision making, and optimum safe operation of process units in meeting the sales contract. The integrated asset model offered a platform for engineers from different domains to collaborate with aligned common operational and planning objectives. It empowered assessments of production operation strategy and field development scenarios conducted at full field level from pore to process. The customized reporting, the ability to connect to other tools, and to push results to dashboards helped to kick-start the corporate digital transformation strategy.
{"title":"Adoption of Integrated Asset Modeling Approach to Kick-Start the Corporate Digital Transformation Strategy","authors":"Khor Siew Hiang, Petrunyak Volodymyr, Yevgen A. Melnyk, Prykhodchenko Oleksii, Stefaniv Viktor, Dogar Andrew, Ojukwu Michael, Viscaino Andres","doi":"10.2118/208525-ms","DOIUrl":"https://doi.org/10.2118/208525-ms","url":null,"abstract":"\u0000 The adoption of an integrated asset modeling approach was explored to kick-start the corporate digital transformation strategy for its oil and gas section. Besides the integrated asset model, the digital initiatives included predictive maintenance, well performance optimization, and a flow assurance advisor aimed at daily production operations and maintenance, creating a pathway to the digital oilfield (DOF). The integrated asset model would be the main pillar of DOF realization and implementation, its offered technology aimed at short-term, medium-term, and long-term planning.\u0000 The adopted well-proven integrated asset modeling methodology enabled a geological complex with a high-fidelity physics reservoir model, multiple interdependent wells, pipeline networks, process facility models to be integrated seamlessly on a single platform for validation of its existing production operation strategy and field development plan. The black-oil reservoir model was history matched, and the production network models had detailed wellbore and pipeline hydraulics calibrated with the latest well-test data. The compositional fluid modeling allowed the capture of any flow assurance issues that arose across the networks, which were mapped to the corresponding process facility models with physical specifications and operational constraints defined.\u0000 A fully integrated asset model was developed for the studied asset, where liquid/vapor tables were prepared for black-oil delumping (Ghorayeb and Holmes, 2005) of the reservoir models to surface network models (Mora et al. 2015), while fluid models of both production network and process models were validated before mapping to ensure fluid fidelity. The availability of this integrated asset model with an embedded spreadsheet program incorporating some simple economic calculations allowed the flexibility of short-term production optimization and long-term asset planning, which was focused to provide all the vital valuable inputs to better field management, fast and accurate decision making, and optimum safe operation of process units in meeting the sales contract.\u0000 The integrated asset model offered a platform for engineers from different domains to collaborate with aligned common operational and planning objectives. It empowered assessments of production operation strategy and field development scenarios conducted at full field level from pore to process. The customized reporting, the ability to connect to other tools, and to push results to dashboards helped to kick-start the corporate digital transformation strategy.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81593125","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper proposes a set of methods for selecting the type of sand control screen and optimizing the accuracy in heavy oil Wells, which take into account the requirements of sand control and productivity protection in heavy oil Wells. Sand retaining experiments are carried out with slotted screen, wire wrapped screen and metal filter screen under the condition of oil and water mixed sand carrying flow. In order to optimize the sand control screen suitable for heavy oil well, this paper uses the weighted average method to quantitatively evaluate the flow performance, sand retention performance and oil conductivity of the screen. Then, repeat the experiment by changing the accuracy of the screen to optimize the accuracy. The experimental results show that the permeability of the three kinds of sand control screens is about 2μm2 when only heavy oil plugging occurs. Under the combined plugging action of formation sand and heavy oil, the slotted screen has the highest permeability, and its conductivity to heavy oil is 10% higher than that of the other two screens. The silk-wound screen has the best sand retention performance, with a sand retention rate of more than 90%. Through the quantitative evaluation of the sand control performance of three kinds of screens in different production stages of heavy oil Wells, the slit screen is selected as the optimal screen. For simulated formation sand with a median particle size of 250μm, the optimal sand control accuracy is 200μm. This paper provides a quantitative optimization method of screen type and accuracy for sand control design of sand-producing heavy oil Wells, so as to maximize the productivity under the premise of ensuring sand-producing control of heavy oil Wells.
{"title":"Experimental Study on Type and Accuracy Optimization of Sand Control in Sand-Producing Heavy Oil Well","authors":"Jian-hua Bai, Yugang Zhou, Huaxiao Wu, Shunchao Zhao, Baobing Shang, T. Fang","doi":"10.2118/208563-ms","DOIUrl":"https://doi.org/10.2118/208563-ms","url":null,"abstract":"\u0000 This paper proposes a set of methods for selecting the type of sand control screen and optimizing the accuracy in heavy oil Wells, which take into account the requirements of sand control and productivity protection in heavy oil Wells.\u0000 Sand retaining experiments are carried out with slotted screen, wire wrapped screen and metal filter screen under the condition of oil and water mixed sand carrying flow. In order to optimize the sand control screen suitable for heavy oil well, this paper uses the weighted average method to quantitatively evaluate the flow performance, sand retention performance and oil conductivity of the screen. Then, repeat the experiment by changing the accuracy of the screen to optimize the accuracy.\u0000 The experimental results show that the permeability of the three kinds of sand control screens is about 2μm2 when only heavy oil plugging occurs. Under the combined plugging action of formation sand and heavy oil, the slotted screen has the highest permeability, and its conductivity to heavy oil is 10% higher than that of the other two screens. The silk-wound screen has the best sand retention performance, with a sand retention rate of more than 90%. Through the quantitative evaluation of the sand control performance of three kinds of screens in different production stages of heavy oil Wells, the slit screen is selected as the optimal screen. For simulated formation sand with a median particle size of 250μm, the optimal sand control accuracy is 200μm.\u0000 This paper provides a quantitative optimization method of screen type and accuracy for sand control design of sand-producing heavy oil Wells, so as to maximize the productivity under the premise of ensuring sand-producing control of heavy oil Wells.","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90447864","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}
Michael Nashaat, K. Ghorayeb, M. Zhiyenkulov, Abdur Rahman Shah, O. Lukin, Roman Madatov, Hassan Kolivand, D. Grytsai, Viacheslav Filatov
Opishnyanske Field is a mature Ukrainian gas field that began producing in 1972 from three formations: Visean, Serpukhovian, and Bashkirian. A reservoir simulation study was implemented to understand the movement of the water in the reservoir and to maximize the field recovery. Some wells showed high water production at their late life and this was the key question that we wanted to understand. If this was a water breakthrough, which means that the aquifer water swept the gas in the reservoir and reached these wells, then there is little potential left in this field. If this was not a water breakthrough, there could still exist some unswept areas to be produced. The second key question was to understand the aquifer strength and direction to be integrated into the simulation model. The field has different sources of data that could be used to understand the water movement in the reservoir, which are: Observed production data Water analysis reports (surface water salinity and density measurements) Production logging data Pressure data and geological maps to understand the communication between the wells Although different sources of data are available, each one has a level of inaccuracy, which was the key challenge. The field also has some other challenges, such as: Commingled production Contradiction between the observed water/gas ratio (WGR) and water analysis data Limited water analysis data points in some wells Issues with backallocation of the observed data. Integrating all the available data had a significant effect on understating the water behavior. Data analysis and integration resulted in excluding all the data anomalies and reaching a good understating regarding: The wells that are showing a water breakthrough Aquifer strength and direction
{"title":"Integrating Various Sources of Indicators and Water Measurements Data of Different Degree of Uncertainty: Understanding Aquifer Encroachment and Resulted Water Breakthrough to Gas Producers","authors":"Michael Nashaat, K. Ghorayeb, M. Zhiyenkulov, Abdur Rahman Shah, O. Lukin, Roman Madatov, Hassan Kolivand, D. Grytsai, Viacheslav Filatov","doi":"10.2118/208556-ms","DOIUrl":"https://doi.org/10.2118/208556-ms","url":null,"abstract":"\u0000 Opishnyanske Field is a mature Ukrainian gas field that began producing in 1972 from three formations: Visean, Serpukhovian, and Bashkirian. A reservoir simulation study was implemented to understand the movement of the water in the reservoir and to maximize the field recovery. Some wells showed high water production at their late life and this was the key question that we wanted to understand. If this was a water breakthrough, which means that the aquifer water swept the gas in the reservoir and reached these wells, then there is little potential left in this field. If this was not a water breakthrough, there could still exist some unswept areas to be produced. The second key question was to understand the aquifer strength and direction to be integrated into the simulation model.\u0000 The field has different sources of data that could be used to understand the water movement in the reservoir, which are:\u0000 Observed production data Water analysis reports (surface water salinity and density measurements) Production logging data Pressure data and geological maps to understand the communication between the wells\u0000 Although different sources of data are available, each one has a level of inaccuracy, which was the key challenge. The field also has some other challenges, such as:\u0000 Commingled production Contradiction between the observed water/gas ratio (WGR) and water analysis data Limited water analysis data points in some wells Issues with backallocation of the observed data.\u0000 Integrating all the available data had a significant effect on understating the water behavior. Data analysis and integration resulted in excluding all the data anomalies and reaching a good understating regarding:\u0000 The wells that are showing a water breakthrough Aquifer strength and direction","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87213875","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}
C. Cavalleri, Y. Akashev, S. Ahmad, Sviatoslav Yuras, Vasyl Karpyn, Ibrahim A. Abdelatif
Several gas fields from the Carpathian Foredeep basin are characterized by high heterogeneity of rock quality. It is critical to understand the characteristics of pore architecture and mineralogy to quantify the rock's storage capacity and productivity. Field "A" is characterized by thin low-resistivity shale-sand laminations, which poses technical challenges to conventional evaluation methods. Until recently, only conventional local logging suites were deployed, and cutoffs-based interpretation was applied. Core analysis was not done. The Ukrainian segment of the Carpathian fold belt and foredeep is located in the westernmost part of the country, bordering Poland, Slovakia, and Romania. A few fields are situated in the foreland basin but most of the production comes from the fold belt, where complex structural traps are in a series of nappe units. Many of the fields were found based on an understanding of the surface geology alone. The presence of anisotropic layers with a predominance of very thin beds and intercalation of shale, siltstone, and sands with low resistivity contrast between water and gas significantly affects the definition of the reservoir properties and potential. Recently, the use of modern logs was mandated to obtain reliable information. In this study, we analyze and discuss the applicability and results of using advanced technology and tailored logs interpretation methods adapted for the local conditions. These methods were applied in different cases in 2019-2021 and enabled building the first robust petrophysical model for these types of reservoirs. Tri-axial resistivity measurements combined with high resolution density and neutron porosity logs optimally defined the porosity and saturations within the thin bedded sequences. Water volumes and textural parameters were computed from dielectric dispersion measurements. Pores system's heterogeneity and grain sorting, free fluid content and downhole testing optimization was performed using high-resolution nuclear magnetic resonance logs. The ability to measure formation pressure in the thin layers help understanding connectivity and deliverability of the reservoirs. The integration of these log measurements enabled unlocking the true properties of the anisotropic layers and quantify the hydrocarbons in place. High-definition borehole imager and dipole sonic logs complemented the petrophysical logs analysis and assisted the geomechanics and geophysics modeling. The addition of pulsed neutron spectroscopy logging further reduced the evaluation uncertainties providing an independent assessment of gas presence and proper control on mineralogy and matrix effects on the log responses to further refine the computation of total and effective porosity, and volumes within the thin sands. Finally, accurate reservoir summations were calculated and used together with producibility estimates and rock mechanical properties to guide the completion and production strategy. This paper pr
{"title":"Advanced Formation Evaluation Approaches in Complex Low-Resistivity Thin Shale Sand Laminations: Success Case Histories from Western Ukraine","authors":"C. Cavalleri, Y. Akashev, S. Ahmad, Sviatoslav Yuras, Vasyl Karpyn, Ibrahim A. Abdelatif","doi":"10.2118/208513-ms","DOIUrl":"https://doi.org/10.2118/208513-ms","url":null,"abstract":"\u0000 Several gas fields from the Carpathian Foredeep basin are characterized by high heterogeneity of rock quality. It is critical to understand the characteristics of pore architecture and mineralogy to quantify the rock's storage capacity and productivity. Field \"A\" is characterized by thin low-resistivity shale-sand laminations, which poses technical challenges to conventional evaluation methods. Until recently, only conventional local logging suites were deployed, and cutoffs-based interpretation was applied. Core analysis was not done.\u0000 The Ukrainian segment of the Carpathian fold belt and foredeep is located in the westernmost part of the country, bordering Poland, Slovakia, and Romania. A few fields are situated in the foreland basin but most of the production comes from the fold belt, where complex structural traps are in a series of nappe units. Many of the fields were found based on an understanding of the surface geology alone. The presence of anisotropic layers with a predominance of very thin beds and intercalation of shale, siltstone, and sands with low resistivity contrast between water and gas significantly affects the definition of the reservoir properties and potential.\u0000 Recently, the use of modern logs was mandated to obtain reliable information. In this study, we analyze and discuss the applicability and results of using advanced technology and tailored logs interpretation methods adapted for the local conditions. These methods were applied in different cases in 2019-2021 and enabled building the first robust petrophysical model for these types of reservoirs.\u0000 Tri-axial resistivity measurements combined with high resolution density and neutron porosity logs optimally defined the porosity and saturations within the thin bedded sequences. Water volumes and textural parameters were computed from dielectric dispersion measurements. Pores system's heterogeneity and grain sorting, free fluid content and downhole testing optimization was performed using high-resolution nuclear magnetic resonance logs.\u0000 The ability to measure formation pressure in the thin layers help understanding connectivity and deliverability of the reservoirs. The integration of these log measurements enabled unlocking the true properties of the anisotropic layers and quantify the hydrocarbons in place. High-definition borehole imager and dipole sonic logs complemented the petrophysical logs analysis and assisted the geomechanics and geophysics modeling. The addition of pulsed neutron spectroscopy logging further reduced the evaluation uncertainties providing an independent assessment of gas presence and proper control on mineralogy and matrix effects on the log responses to further refine the computation of total and effective porosity, and volumes within the thin sands.\u0000 Finally, accurate reservoir summations were calculated and used together with producibility estimates and rock mechanical properties to guide the completion and production strategy.\u0000 This paper pr","PeriodicalId":11215,"journal":{"name":"Day 2 Wed, November 24, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86958806","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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