Céleste Odier, M. Kerdraon, Emie Lacombe, E. Delamaide
In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found. In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature. Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C. Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application. In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature. To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.
{"title":"Very High Temperatures Steam Foam Additives","authors":"Céleste Odier, M. Kerdraon, Emie Lacombe, E. Delamaide","doi":"10.2118/207464-ms","DOIUrl":"https://doi.org/10.2118/207464-ms","url":null,"abstract":"\u0000 In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found.\u0000 In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature.\u0000 Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C.\u0000 Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application.\u0000 In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature.\u0000 To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83784166","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}
In recent years, various industries become increasingly aware of the importance of mental health. Mental health is closely related to the management of psychosocial hazards in the workplace. The oil and gas industry is considered to be one of the laggards in the management of workers’ psychosocial hazards and mental health even though mental health is considered to affect workers’ health and operational safety. Workplace bullying is a phenomenon that can give adverse effects to individual workers and the organization. For workers, bullying can interfere with physical health, psychological stress, and satisfaction with life and work. This paper discusses prevalence of workplace bullying, psychological stress, and satisfaction with life of workers in the upstream oil and gas industry. The phenomenon experienced by workers on Sites is compared with the experience of the office workers in this paper, with no significant differences found between the incidence of bullying and satisfaction with life between the two populations. On the other hand, there is a significant difference in the psychological stress and chronic diseases reported by the respondents. Site workers experience higher psychological stress and more reported chronic health disorders than the office workers.
{"title":"Comparison of Psychological Distress, Life Satisfaction and Workplace Bullying Between Site and Office Workers in Oil and Gas Industry","authors":"D. Kusumawati, D. Erwandi, F. Lestari, A. Kadir","doi":"10.2118/208002-ms","DOIUrl":"https://doi.org/10.2118/208002-ms","url":null,"abstract":"\u0000 In recent years, various industries become increasingly aware of the importance of mental health. Mental health is closely related to the management of psychosocial hazards in the workplace. The oil and gas industry is considered to be one of the laggards in the management of workers’ psychosocial hazards and mental health even though mental health is considered to affect workers’ health and operational safety. Workplace bullying is a phenomenon that can give adverse effects to individual workers and the organization. For workers, bullying can interfere with physical health, psychological stress, and satisfaction with life and work. This paper discusses prevalence of workplace bullying, psychological stress, and satisfaction with life of workers in the upstream oil and gas industry. The phenomenon experienced by workers on Sites is compared with the experience of the office workers in this paper, with no significant differences found between the incidence of bullying and satisfaction with life between the two populations. On the other hand, there is a significant difference in the psychological stress and chronic diseases reported by the respondents. Site workers experience higher psychological stress and more reported chronic health disorders than the office workers.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80149721","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}
Saif Al Aufi, H. A. Lawati, A. Ismail, Sajad Al Lawati, Christian Koepchen, Salma Al Sabahy
Petroleum Development of Oman (PDO) has grown rapidly over the past few years and is seen as an innovative organization and a leading company within the Middle East when it comes to applying best practice, adding value to the economical and societal development of the Sultanate of Oman through many Knowledge Management (KM) activities. As the Sultanate's leading Oil and gas exploration and production company it is the central engine of the Sultanate's economy. Key to the success of our Digital KM Program has been focus on the importance of developing the human intellectual capital elements to nurture, develop and sustain our people as key assets. PDO is aware of the potential value of the Enterprise Information and the robust data as showcased In the Figure-1 which can be transformed into knowledge that can be turned and can be used to gain the business benefits such as a competitive advantage, cost minimization, innovation.
{"title":"Digital Ways of Working: PDO Knowledge Management Program","authors":"Saif Al Aufi, H. A. Lawati, A. Ismail, Sajad Al Lawati, Christian Koepchen, Salma Al Sabahy","doi":"10.2118/207465-ms","DOIUrl":"https://doi.org/10.2118/207465-ms","url":null,"abstract":"\u0000 Petroleum Development of Oman (PDO) has grown rapidly over the past few years and is seen as an innovative organization and a leading company within the Middle East when it comes to applying best practice, adding value to the economical and societal development of the Sultanate of Oman through many Knowledge Management (KM) activities. As the Sultanate's leading Oil and gas exploration and production company it is the central engine of the Sultanate's economy. Key to the success of our Digital KM Program has been focus on the importance of developing the human intellectual capital elements to nurture, develop and sustain our people as key assets.\u0000 PDO is aware of the potential value of the Enterprise Information and the robust data as showcased In the Figure-1 which can be transformed into knowledge that can be turned and can be used to gain the business benefits such as a competitive advantage, cost minimization, innovation.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91401854","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. Voskresenskiy, N. Bukhanov, M. A. Kuntsevich, O. Popova, Alexey S. Goncharov
We propose a methodology to improve rock type classification using machine learning (ML) techniques and to reveal causal inferences between reservoir quality and well log measurements. Rock type classification is an essential step in accurate reservoir modeling and forecasting. Machine learning approaches allow to automate rock type classification based on different well logs and core data. In order to choose the best model which does not progradate uncertainty further into the workflow it is important to interpret machine learning results. Feature importance and feature selection methods are usually employed for that. We propose an extension to existing approaches - model agnostic sensitivity algorithm based on Shapley values. The paper describes a full workflow to rock type prediction using well log data: from data preparation, model building, feature selection to causal inference analysis. We made ML models that classify rock types using well logs (sonic, gamma, density, photoelectric and resistivity) from 21 wells as predictors and conduct a causal inference analysis between reservoir quality and well logs responses using Shapley values (a concept from a game theory). As a result of feature selection, we obtained predictors which are statistically significant and at the same time relevant in causal relation context. Macro F1-score of the best obtained models for both cases is 0.79 and 0.85 respectively. It was found that the ML models can infer domain knowledge, which allows us to confirm the adequacy of the built ML model for rock types prediction. Our insight was to recognize the need to properly account for the underlying causal structure between the features and rock types in order to derive meaningful and relevant predictors that carry a significant amount of information contributing to the final outcome. Also, we demonstrate the robustness of revealed patterns by applying the Shapley values methodology to a number of ML models and show consistency in order of the most important predictors. Our analysis shows that machine learning classifiers gaining high accuracy tend to mimic physical principles behind different logging tools, in particular: the longer the travel time of an acoustic wave the higher probability that media is represented by reservoir rock and vice versa. On the contrary lower values of natural radioactivity and density of rock highlight the presence of a reservoir. The article presents causal inference analysis of ML classification models using Shapley values on 2 real-world reservoirs. The rock class labels from core data are used to train a supervised machine learning algorithm to predict classes from well log response. The aim of supervised learning is to label a small portion of a dataset and allow the algorithm to automate the rest. Such data-driven analysis may optimize well logging, coring, and core analysis programs. This algorithm can be extended to any other reservoir to improve rock type prediction. The
{"title":"Rock Type Classification Models Interpretability Using Shapley Values","authors":"A. Voskresenskiy, N. Bukhanov, M. A. Kuntsevich, O. Popova, Alexey S. Goncharov","doi":"10.2118/207707-ms","DOIUrl":"https://doi.org/10.2118/207707-ms","url":null,"abstract":"\u0000 We propose a methodology to improve rock type classification using machine learning (ML) techniques and to reveal causal inferences between reservoir quality and well log measurements. Rock type classification is an essential step in accurate reservoir modeling and forecasting. Machine learning approaches allow to automate rock type classification based on different well logs and core data. In order to choose the best model which does not progradate uncertainty further into the workflow it is important to interpret machine learning results. Feature importance and feature selection methods are usually employed for that. We propose an extension to existing approaches - model agnostic sensitivity algorithm based on Shapley values.\u0000 The paper describes a full workflow to rock type prediction using well log data: from data preparation, model building, feature selection to causal inference analysis. We made ML models that classify rock types using well logs (sonic, gamma, density, photoelectric and resistivity) from 21 wells as predictors and conduct a causal inference analysis between reservoir quality and well logs responses using Shapley values (a concept from a game theory). As a result of feature selection, we obtained predictors which are statistically significant and at the same time relevant in causal relation context.\u0000 Macro F1-score of the best obtained models for both cases is 0.79 and 0.85 respectively. It was found that the ML models can infer domain knowledge, which allows us to confirm the adequacy of the built ML model for rock types prediction. Our insight was to recognize the need to properly account for the underlying causal structure between the features and rock types in order to derive meaningful and relevant predictors that carry a significant amount of information contributing to the final outcome. Also, we demonstrate the robustness of revealed patterns by applying the Shapley values methodology to a number of ML models and show consistency in order of the most important predictors.\u0000 Our analysis shows that machine learning classifiers gaining high accuracy tend to mimic physical principles behind different logging tools, in particular: the longer the travel time of an acoustic wave the higher probability that media is represented by reservoir rock and vice versa. On the contrary lower values of natural radioactivity and density of rock highlight the presence of a reservoir.\u0000 The article presents causal inference analysis of ML classification models using Shapley values on 2 real-world reservoirs. The rock class labels from core data are used to train a supervised machine learning algorithm to predict classes from well log response. The aim of supervised learning is to label a small portion of a dataset and allow the algorithm to automate the rest. Such data-driven analysis may optimize well logging, coring, and core analysis programs. This algorithm can be extended to any other reservoir to improve rock type prediction.\u0000 The","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89241124","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}
Zeeshan Tariq, A. Alnakhli, A. Abdulraheem, M. Mahmoud
Brownfields and depleting conventional resources of fossil fuel energy are not enough to fulfill the tremendously increasing energy demands around the globe. Unconventional oil and gas resources are creating a huge impact on the enhancement of the global economy. Tight rocks are usually located in deep and high-strength formations. In this study, numerical simulation results on a new thermochemical fracturing approach is presented. The new fracturing approach was implemented to reduce the breakdown pressure of the unconventional tight formations. The hydraulic fracturing experiments presented in this study were carried out on ultra-tight cement block samples. The permeability of the block samples was less than 0.005mD. Thermochemical fracturing was carried out by a thermochemical fluids that caused a rapid exothermic reaction which resulted in the instantaneous generation of heat and pressure. Different salts of nitrogen such as sodium nitrite and ammonium chloride were used as a thermochemical fluid. The instantaneous generation of the heat and pressure caused the creation of micro-cracks. The fracturing results revealed that the novel thermochemical fracturing was able to reduce the breakdown pressure in ultra-tight cement from 1095 psi to 705 psi. The reference breakdown pressure was recorded from the conventional fracturing technique. A finite element (FEM) analysis was conducted using commercial software ABAQUS. In FEM, two approaches were used to model the thermochemical fractures namely, cohesive zone modeling (CZM) and concrete damage plasticity models (CDP). The sensitivity analysis of peak pressure and time to reach the peak pressure is also presented in this study. The sensitivity analysis can help in better designing thermochemical fluids that could lead to the maximum generation of micro-cracks and multiple fractures.
{"title":"Core Scale FEM Modeling of Thermochemical Fracturing on Cement Cube Samples","authors":"Zeeshan Tariq, A. Alnakhli, A. Abdulraheem, M. Mahmoud","doi":"10.2118/208095-ms","DOIUrl":"https://doi.org/10.2118/208095-ms","url":null,"abstract":"\u0000 Brownfields and depleting conventional resources of fossil fuel energy are not enough to fulfill the tremendously increasing energy demands around the globe. Unconventional oil and gas resources are creating a huge impact on the enhancement of the global economy. Tight rocks are usually located in deep and high-strength formations. In this study, numerical simulation results on a new thermochemical fracturing approach is presented. The new fracturing approach was implemented to reduce the breakdown pressure of the unconventional tight formations. The hydraulic fracturing experiments presented in this study were carried out on ultra-tight cement block samples. The permeability of the block samples was less than 0.005mD. Thermochemical fracturing was carried out by a thermochemical fluids that caused a rapid exothermic reaction which resulted in the instantaneous generation of heat and pressure. Different salts of nitrogen such as sodium nitrite and ammonium chloride were used as a thermochemical fluid. The instantaneous generation of the heat and pressure caused the creation of micro-cracks. The fracturing results revealed that the novel thermochemical fracturing was able to reduce the breakdown pressure in ultra-tight cement from 1095 psi to 705 psi. The reference breakdown pressure was recorded from the conventional fracturing technique. A finite element (FEM) analysis was conducted using commercial software ABAQUS. In FEM, two approaches were used to model the thermochemical fractures namely, cohesive zone modeling (CZM) and concrete damage plasticity models (CDP). The sensitivity analysis of peak pressure and time to reach the peak pressure is also presented in this study. The sensitivity analysis can help in better designing thermochemical fluids that could lead to the maximum generation of micro-cracks and multiple fractures.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88337448","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}
Saugata Gon, Christopher Russell, Kasper K.J. Baack, Heather Blackwood, A. Hase
Paraffin deposition is a common challenge for production facilities globally where production fluid/process surface temperature cools down and reach below the wax appearance temperature (WAT) of the oil. Although chemical treatment is used widely for suitable mitigation of wax deposition, conventional test methods like cold finger often fail to recommend the right product for the field. The current study will present development of two new technologies PARA-Window and Dynamic Paraffin Deposition Cell (DPDC)to address such limitations. Large temperature gradient between bulk oil and cold surface has been identified as a major limitation of cold finger. To address this, PARA-Window has been developed to capture the paraffin deposition at a more realistic temperature gradient (5°C) between the bulk oil and surface temperature using a NIR optical probe. Absence of brine and lack of shear has been identified as another limitation of cold finger technique. DPDC has been developed to study paraffin deposition and chemical effectiveness in presence of brine. Specially designed cells are placed horizontally inside a shaker bath to achieve good mixing between oil and water for DPDC application. A prior study by Russell et al., (2019) showed the effectiveness of PARA-Window in capturing deposition phenomena of higher molecular weight paraffin chains that resemble closely to field deposits under narrow temperature gradient around WAT. Conventional test methods fail to capture meaningful product differentiation in most oils under such conditions and hence can only recommend a crystal modifier type of paraffin chemistries. PARA-Window technique can expand product selection to other type of paraffin chemistries (paraffin crystal modifiers, dispersants and solvents) as shown earlier by Russell et al., (2021). The usage of DPDC allows us to create a dynamic mixing condition inside the test cells with both oil and water under a condition similar to production pipe systems. This allows DPDC to assess water effect on paraffin chemistries (crystal modifiers and dispersants). This study presents the usage of these two new technologies to screen performance of different types of paraffin chemistries on select oils and their advantages over cold finger. The results identify how mimicking field conditions using these new technologies can capture new insights into paraffin products.
{"title":"Addressing Paraffin Deposition Challenges Through New Technologies","authors":"Saugata Gon, Christopher Russell, Kasper K.J. Baack, Heather Blackwood, A. Hase","doi":"10.2118/207789-ms","DOIUrl":"https://doi.org/10.2118/207789-ms","url":null,"abstract":"\u0000 Paraffin deposition is a common challenge for production facilities globally where production fluid/process surface temperature cools down and reach below the wax appearance temperature (WAT) of the oil. Although chemical treatment is used widely for suitable mitigation of wax deposition, conventional test methods like cold finger often fail to recommend the right product for the field. The current study will present development of two new technologies PARA-Window and Dynamic Paraffin Deposition Cell (DPDC)to address such limitations.\u0000 Large temperature gradient between bulk oil and cold surface has been identified as a major limitation of cold finger. To address this, PARA-Window has been developed to capture the paraffin deposition at a more realistic temperature gradient (5°C) between the bulk oil and surface temperature using a NIR optical probe. Absence of brine and lack of shear has been identified as another limitation of cold finger technique. DPDC has been developed to study paraffin deposition and chemical effectiveness in presence of brine. Specially designed cells are placed horizontally inside a shaker bath to achieve good mixing between oil and water for DPDC application.\u0000 A prior study by Russell et al., (2019) showed the effectiveness of PARA-Window in capturing deposition phenomena of higher molecular weight paraffin chains that resemble closely to field deposits under narrow temperature gradient around WAT. Conventional test methods fail to capture meaningful product differentiation in most oils under such conditions and hence can only recommend a crystal modifier type of paraffin chemistries. PARA-Window technique can expand product selection to other type of paraffin chemistries (paraffin crystal modifiers, dispersants and solvents) as shown earlier by Russell et al., (2021). The usage of DPDC allows us to create a dynamic mixing condition inside the test cells with both oil and water under a condition similar to production pipe systems. This allows DPDC to assess water effect on paraffin chemistries (crystal modifiers and dispersants).\u0000 This study presents the usage of these two new technologies to screen performance of different types of paraffin chemistries on select oils and their advantages over cold finger. The results identify how mimicking field conditions using these new technologies can capture new insights into paraffin products.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79780656","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}
Maryam Humaid Al Wahaybi, Roeland van Gilst, Fathiya Hilal Salmi, Taimur Al Wadhahi, S. Azri, Abir Mahruqi, Qais Ali Siyabi, S. Mahajan, Khalid Abdullah Mahrouqi, Nabil Salim AL Siyabi
The MicroSeismic (MS) events, also referred to as tremors or induced seismicity, can be triggered by reservoir depletion and compaction as a result of hydrocarbon production with time. In order to measure and locate the MS events in the Field A; Petroleum Development of Oman (PDO) installed many downhole geophones and accelerometers across the field since 2011. The monitoring network allows subsurface teams to understand magnitude, location and depth of the events. Till the end of 2019 a total of 5,597 MS events were recorded and analysed. In 2020 a new Standard Operating Procedure (SOP) was established moving away from a partly manual data information system to an automated real-time data system named PetroAlert (this is ESG invention). The SOP also defines a clear step-by-step action plan and line-of-sight using a color code system (Traffic Light System). The key challenges that needed to be overcome were: 1) problem breakdown, goals and root causes and 2) data integration and IT infrastructure. The first challenge was overcome by utilizing Lean and organizing a KAIZEN event to ensure objectives were clear to all involved team members. The second challenge was solved in consultation with our external event processing contractor the Engineering Seismology Group (ESG) and the PDO geophysics teams (Exploration Directorate). PDO behaviors: –Speed: the new automated alert system is much Leaner and efficient compared to the previous manual system saving 100s of man hours per year. The line-of-sight captured in the SOP makes it clear for the team how to respond and who to inform in case of significant MicroSeismic events.–Leadership: the Gas Team has lead the change with other compaction team members. In principle all information was available but needed to be combined into a simple alert system with appropriate data filtering.–Team work: without teamwork inside PDO with the Lean team, the specialist geophysicist and our external contractor ESG we would not have succeeded. Several Lean sessions (KAIZEN, Gemba, and huddles) were organised to ensure all team members were well informed on the progress and deadlines for the project. The digital transformation in MicroSeismic monitoring in Field A protects 200+ staff in the field and multiple hundreds BOE production in both Natih and Shuaiba Reservoirs. This work can be replicated for other fields in PDO impacted by compaction (Field B and Field C) to increase the success even further. Also it can be replicated worldwide.
{"title":"Utilizing Lean & Machine Learning to Monitor and Managing Production Induced Subsidence in a Mature Oil and Gas Field and to Ensure Safety of 200+ Field Staff and Safeguard More Than 200 Mln BOE Natih & Shuaiba","authors":"Maryam Humaid Al Wahaybi, Roeland van Gilst, Fathiya Hilal Salmi, Taimur Al Wadhahi, S. Azri, Abir Mahruqi, Qais Ali Siyabi, S. Mahajan, Khalid Abdullah Mahrouqi, Nabil Salim AL Siyabi","doi":"10.2118/208147-ms","DOIUrl":"https://doi.org/10.2118/208147-ms","url":null,"abstract":"\u0000 The MicroSeismic (MS) events, also referred to as tremors or induced seismicity, can be triggered by reservoir depletion and compaction as a result of hydrocarbon production with time. In order to measure and locate the MS events in the Field A; Petroleum Development of Oman (PDO) installed many downhole geophones and accelerometers across the field since 2011. The monitoring network allows subsurface teams to understand magnitude, location and depth of the events. Till the end of 2019 a total of 5,597 MS events were recorded and analysed. In 2020 a new Standard Operating Procedure (SOP) was established moving away from a partly manual data information system to an automated real-time data system named PetroAlert (this is ESG invention). The SOP also defines a clear step-by-step action plan and line-of-sight using a color code system (Traffic Light System).\u0000 The key challenges that needed to be overcome were: 1) problem breakdown, goals and root causes and 2) data integration and IT infrastructure. The first challenge was overcome by utilizing Lean and organizing a KAIZEN event to ensure objectives were clear to all involved team members. The second challenge was solved in consultation with our external event processing contractor the Engineering Seismology Group (ESG) and the PDO geophysics teams (Exploration Directorate).\u0000 PDO behaviors: –Speed: the new automated alert system is much Leaner and efficient compared to the previous manual system saving 100s of man hours per year. The line-of-sight captured in the SOP makes it clear for the team how to respond and who to inform in case of significant MicroSeismic events.–Leadership: the Gas Team has lead the change with other compaction team members. In principle all information was available but needed to be combined into a simple alert system with appropriate data filtering.–Team work: without teamwork inside PDO with the Lean team, the specialist geophysicist and our external contractor ESG we would not have succeeded. Several Lean sessions (KAIZEN, Gemba, and huddles) were organised to ensure all team members were well informed on the progress and deadlines for the project.\u0000 The digital transformation in MicroSeismic monitoring in Field A protects 200+ staff in the field and multiple hundreds BOE production in both Natih and Shuaiba Reservoirs. This work can be replicated for other fields in PDO impacted by compaction (Field B and Field C) to increase the success even further. Also it can be replicated worldwide.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80070537","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}
Petrus In ‘T Panhuis, Adel El Sabagh, H. Coppes, J. Meyers, Niels Van der Werff, Faiza Al Jadeedi, D. Suryanto, Kauthar Al Habsi
This article will show how a standardized rule-based approach was used by Petroleum Development Oman (PDO) to shorten the cycle time required to mature the opportunity of implementing waterflood developments in small-to-medium sized satellite oil fields in the South of the Sultanate of Oman. The standardized concept relies on a common development strategy for a portfolio of satellite fields with similar reservoir and fluid characteristics that are still under depletion or in the early stage of waterflood. The targets are early monetization, driving cost efficiency through standardization & replication, and increasing recovery factor through the accelerated implementation of field-wide waterflood. This is achieved by leveraging excess capacity in existing facilities, applying analytical workflows for forecasting, standardizing well design and urban planning, and by applying the learnings and best practices from nearby fields that already have mature developments.
{"title":"Standardized Development Planning for Satellite Fields in the South of the Sultanate of Oman","authors":"Petrus In ‘T Panhuis, Adel El Sabagh, H. Coppes, J. Meyers, Niels Van der Werff, Faiza Al Jadeedi, D. Suryanto, Kauthar Al Habsi","doi":"10.2118/207439-ms","DOIUrl":"https://doi.org/10.2118/207439-ms","url":null,"abstract":"\u0000 This article will show how a standardized rule-based approach was used by Petroleum Development Oman (PDO) to shorten the cycle time required to mature the opportunity of implementing waterflood developments in small-to-medium sized satellite oil fields in the South of the Sultanate of Oman. The standardized concept relies on a common development strategy for a portfolio of satellite fields with similar reservoir and fluid characteristics that are still under depletion or in the early stage of waterflood. The targets are early monetization, driving cost efficiency through standardization & replication, and increasing recovery factor through the accelerated implementation of field-wide waterflood. This is achieved by leveraging excess capacity in existing facilities, applying analytical workflows for forecasting, standardizing well design and urban planning, and by applying the learnings and best practices from nearby fields that already have mature developments.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76356038","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}
Abdullah Salim Shuely, H. Sheibani, Hawraa Al Lawati, Patrick Ezechie, Roeland van Gilst, N. Siyabi, Dawood Al Kharusi, N. Marhoon, Louisa Al Otani, Taha Lawati
A rich condensate gas field is located in the North of Oman, which penetrated the Amin sandstone reservoir at 4015 TVDmss. A study was conducted in the field and showed there is ¾ of GIIP trapped with paleo imbibition - over geological time - gas by the water encroachment in an approximately 80 m thick Paleo-Residual Gas zone (PRG), with very low mobility of hydrocarbons and high residual gas saturations. In order to mitigate the shortcomings of such unfavorable subsurface conditions, the study proposed Gas-Aquifer-Rate Management (i.e. co-production of gas and water) utilizing existing flank wells, as a potential field improvement option. The key business drivers for this project are to re-mobilize gas from PRG flank wells and to safeguard existing NFA by Aquifer pump off and production from high rate crestal wells. The optimum gas well deliquification method has been identified based on the highest UR considering connected GIIP and well completion size. The outcome of the study indicated that the ESP technology combined with well retubing was recommended as the optimum solution. Two wells have been selected as ESP candidates to test the new technology to produce water at deep depth (4000m) and high temperature (155°C). A special slim ESP was designed for this purpose. A successful pilot was completed in one well and gave conclusive results. The test showed that the well produced 3K m3/d of gas and 83 m3/d of liquid with 95% BSW. The second pilot is currently in the commissioning phase. The successful outcomes of the pilot succeeding in connecting the gas and restoring wells back with economic production rates will lead to expedite a full field implementation plan. This project will add a significant economic value of positive NPV at low UTC. This paper will highlight the full story of the PRG and ESP technology implementation and describe in details the entire process starting from the artificial lift selection, well candidate selection screening criteria, critical success factors, operating parameters, life-time cycle and the test results of gas and condensate and water production. Also, the learning and challenges in operating the ESP will be shared.
{"title":"Successful Development of Residual Gas Condensate Reservoir using First ESP in Deep High Pressure and Temperature in Rich Gas Condensate Wells","authors":"Abdullah Salim Shuely, H. Sheibani, Hawraa Al Lawati, Patrick Ezechie, Roeland van Gilst, N. Siyabi, Dawood Al Kharusi, N. Marhoon, Louisa Al Otani, Taha Lawati","doi":"10.2118/207502-ms","DOIUrl":"https://doi.org/10.2118/207502-ms","url":null,"abstract":"\u0000 A rich condensate gas field is located in the North of Oman, which penetrated the Amin sandstone reservoir at 4015 TVDmss. A study was conducted in the field and showed there is ¾ of GIIP trapped with paleo imbibition - over geological time - gas by the water encroachment in an approximately 80 m thick Paleo-Residual Gas zone (PRG), with very low mobility of hydrocarbons and high residual gas saturations.\u0000 In order to mitigate the shortcomings of such unfavorable subsurface conditions, the study proposed Gas-Aquifer-Rate Management (i.e. co-production of gas and water) utilizing existing flank wells, as a potential field improvement option. The key business drivers for this project are to re-mobilize gas from PRG flank wells and to safeguard existing NFA by Aquifer pump off and production from high rate crestal wells.\u0000 The optimum gas well deliquification method has been identified based on the highest UR considering connected GIIP and well completion size. The outcome of the study indicated that the ESP technology combined with well retubing was recommended as the optimum solution. Two wells have been selected as ESP candidates to test the new technology to produce water at deep depth (4000m) and high temperature (155°C). A special slim ESP was designed for this purpose.\u0000 A successful pilot was completed in one well and gave conclusive results. The test showed that the well produced 3K m3/d of gas and 83 m3/d of liquid with 95% BSW. The second pilot is currently in the commissioning phase. The successful outcomes of the pilot succeeding in connecting the gas and restoring wells back with economic production rates will lead to expedite a full field implementation plan. This project will add a significant economic value of positive NPV at low UTC.\u0000 This paper will highlight the full story of the PRG and ESP technology implementation and describe in details the entire process starting from the artificial lift selection, well candidate selection screening criteria, critical success factors, operating parameters, life-time cycle and the test results of gas and condensate and water production. Also, the learning and challenges in operating the ESP will be shared.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75161702","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}
J. Heredia, Jan Egil Tengesdal, Rune Hobberstad, J. Marck, Harald Kleivenes, M. Ngueguim
A pilot program for automated directional drilling was implemented as a part of the roll out plan in Norway to drill three dimensional wells in an automated mode, where steering commands were carried out automatically by the automation platform. The rollout plan also targeted the use of remote operations to allow personnel to be relocated from the rig location into remote drilling centers. The goal of the program was to optimize the directional drilling performance by assessing the benefits of automation using the latest rotary steerable system technologies and machine learning smart algorithms to predict and manipulated the BHA performance, as well as the ability to predict the best drilling parameters for hole cleaning. The automation was implemented on three different rigs and the data was compared with the drilling performance from the last two years, with three dimensional wells drilled in the conventional method. The main benefits between drilling wells in the conventional method versus drilling wells with the new drilling automation model include the following. Reduce the overall cost per meter – Improve the rate of penetration – Improve running casings Consistence process adherence – Reduce human errors – Reduce POB without sacrificing lost of technical experience Optimize workforce resources – Allows continuity of service (COVID-19 restrictions) Drilling automation can drill smoother wells by reducing the friction factors and tortuosity. This is translated in direct cost savings per meter and reduction in the overall well delivery time, with the advantage of performing the execution and monitoring of the well performance remotely. This new drilling model open the door of new opportunities, especially for the challenges where the work force resources, and drilling performance is a priority for the operations.
{"title":"Drilling Automation – Benefits of the New Drilling Model","authors":"J. Heredia, Jan Egil Tengesdal, Rune Hobberstad, J. Marck, Harald Kleivenes, M. Ngueguim","doi":"10.2118/207429-ms","DOIUrl":"https://doi.org/10.2118/207429-ms","url":null,"abstract":"\u0000 A pilot program for automated directional drilling was implemented as a part of the roll out plan in Norway to drill three dimensional wells in an automated mode, where steering commands were carried out automatically by the automation platform. The rollout plan also targeted the use of remote operations to allow personnel to be relocated from the rig location into remote drilling centers.\u0000 The goal of the program was to optimize the directional drilling performance by assessing the benefits of automation using the latest rotary steerable system technologies and machine learning smart algorithms to predict and manipulated the BHA performance, as well as the ability to predict the best drilling parameters for hole cleaning.\u0000 The automation was implemented on three different rigs and the data was compared with the drilling performance from the last two years, with three dimensional wells drilled in the conventional method.\u0000 The main benefits between drilling wells in the conventional method versus drilling wells with the new drilling automation model include the following.\u0000 Reduce the overall cost per meter – Improve the rate of penetration – Improve running casings Consistence process adherence – Reduce human errors – Reduce POB without sacrificing lost of technical experience Optimize workforce resources – Allows continuity of service (COVID-19 restrictions)\u0000 Drilling automation can drill smoother wells by reducing the friction factors and tortuosity. This is translated in direct cost savings per meter and reduction in the overall well delivery time, with the advantage of performing the execution and monitoring of the well performance remotely.\u0000 This new drilling model open the door of new opportunities, especially for the challenges where the work force resources, and drilling performance is a priority for the operations.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77310194","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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