Hamad Al-Rashidi, A. Jamsheer, Talal AL-Azmi, Batoul Muhsain, A. Abu-Eida, Badriya Al-Methen, Saad Mousa, Faseil AL-Harbi, Bruce Duncan, Abdul-Aziz Safar, Waled AL-Azmi, W. Desoky, Fahad AL-Sabah, Musaeb AL-Yaseen, Mohsen AL-Hajri, Bandar AL-Mutwa, Hisham AL-Awadhi, Dwane Almeida, Farooq AL-Zanki
The strategy of the Kuwait Oil Company (KOC) is to implement key/emerging technologies at a country wide scale to meet future oil demand and production targets as planned in KPC 2040 strategy through overcome the field's challenges. KOC's Optimization strategy focuses on: Increased and optimize oil production from production optimizationsExtension of field life Production interruption associated with pressure build up in reservoir, wellbore and flow lines have observed among many wells in West Kuwait fields perforated in Upper Burgan formation, which has a great impact on the company strategy. Tight emulsion phenomena is consider one the most challenging problems in West Kuwait wells due to the nature of asphaltenic crudes and high water cut production percentage. Traditional approaches to reduce high pressure and break the emulsion phase through injecting chemical near wellhead or in annuls is usually not successful in most cases and require large amount of chemical. Due to the complexity of this issue, a novel approach was used in this study to identify the main causes of oil production reduction and overcome the challenge to maximize oil production in West Kuwait fields.
{"title":"Lesson Learned from Production Enhancement Pilot for Medium Oil Viscosity Formation in Minagish Oil Field Kuwait","authors":"Hamad Al-Rashidi, A. Jamsheer, Talal AL-Azmi, Batoul Muhsain, A. Abu-Eida, Badriya Al-Methen, Saad Mousa, Faseil AL-Harbi, Bruce Duncan, Abdul-Aziz Safar, Waled AL-Azmi, W. Desoky, Fahad AL-Sabah, Musaeb AL-Yaseen, Mohsen AL-Hajri, Bandar AL-Mutwa, Hisham AL-Awadhi, Dwane Almeida, Farooq AL-Zanki","doi":"10.2118/197865-ms","DOIUrl":"https://doi.org/10.2118/197865-ms","url":null,"abstract":"\u0000 The strategy of the Kuwait Oil Company (KOC) is to implement key/emerging technologies at a country wide scale to meet future oil demand and production targets as planned in KPC 2040 strategy through overcome the field's challenges. KOC's Optimization strategy focuses on: Increased and optimize oil production from production optimizationsExtension of field life\u0000 Production interruption associated with pressure build up in reservoir, wellbore and flow lines have observed among many wells in West Kuwait fields perforated in Upper Burgan formation, which has a great impact on the company strategy. Tight emulsion phenomena is consider one the most challenging problems in West Kuwait wells due to the nature of asphaltenic crudes and high water cut production percentage. Traditional approaches to reduce high pressure and break the emulsion phase through injecting chemical near wellhead or in annuls is usually not successful in most cases and require large amount of chemical. Due to the complexity of this issue, a novel approach was used in this study to identify the main causes of oil production reduction and overcome the challenge to maximize oil production in West Kuwait fields.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73647605","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}
Decades ago, scientists believed that the adult brain is fully formed and unchanged. However, it was found recently that the brain is adaptive and can change in both forms: physical and functional forms. This phenomenon is called (neuroplasticity). In simple terms, the neurons (i.e. brain cells) can create newer connections (i.e. physical form) and have better performance (functionality); or go the opposite way. Scientists are greatly interested in this re-wiring characteristic because it can help people with brain injuries to have substantial recovery; and very recently to understand how people can be happier, more engaged and productive at work. Majority of research available is linking neuroplasticity with how to make employees happier and more productive at work. When people work with positive mindset; productivity, engagement, innovation and creativity improve. However, happiness is still misunderstood as a major drive of performance, due to variety of definition of happiness by scholars (Achor, 2012). Happiness is a positive psychological state that had been found to be related to work performance and engagement. Work engagement is also a positive psychological state defined by feelings of being energetic, empowered, satisfied and being absorbed in the state of being totally engaged at work (Schaufeli, 2012). Engagement had been extensively studied due to its positive outcome on personal and organizational levels; such as: reduce absenteeism, preventing burnout, increase productivity, having less errors and occupational injuries and accidents, innovation and creativity and having better financial results (Burke & Cooper, 2016). The following article demonstrates a field experiment which was conducted on approximately 50 employees working in a technical support department for the drilling function in ADNOC Onshore, Abu Dhabi, The United Arab Emirates. The activities are a series of ongoing interactive and team building events that started with the beginning of the year 2019; aiming to provide a positive work environment that enhance bonds between team members, creating positive mindset, and encouraging innovation and creativity.
{"title":"Applying Brain Science to Achieve Organizational Success","authors":"Amal Al Halyan, Abeer Al Badi, Bashayer Al Hosani","doi":"10.2118/197532-ms","DOIUrl":"https://doi.org/10.2118/197532-ms","url":null,"abstract":"\u0000 Decades ago, scientists believed that the adult brain is fully formed and unchanged. However, it was found recently that the brain is adaptive and can change in both forms: physical and functional forms. This phenomenon is called (neuroplasticity). In simple terms, the neurons (i.e. brain cells) can create newer connections (i.e. physical form) and have better performance (functionality); or go the opposite way. Scientists are greatly interested in this re-wiring characteristic because it can help people with brain injuries to have substantial recovery; and very recently to understand how people can be happier, more engaged and productive at work.\u0000 Majority of research available is linking neuroplasticity with how to make employees happier and more productive at work. When people work with positive mindset; productivity, engagement, innovation and creativity improve. However, happiness is still misunderstood as a major drive of performance, due to variety of definition of happiness by scholars (Achor, 2012).\u0000 Happiness is a positive psychological state that had been found to be related to work performance and engagement. Work engagement is also a positive psychological state defined by feelings of being energetic, empowered, satisfied and being absorbed in the state of being totally engaged at work (Schaufeli, 2012). Engagement had been extensively studied due to its positive outcome on personal and organizational levels; such as: reduce absenteeism, preventing burnout, increase productivity, having less errors and occupational injuries and accidents, innovation and creativity and having better financial results (Burke & Cooper, 2016).\u0000 The following article demonstrates a field experiment which was conducted on approximately 50 employees working in a technical support department for the drilling function in ADNOC Onshore, Abu Dhabi, The United Arab Emirates. The activities are a series of ongoing interactive and team building events that started with the beginning of the year 2019; aiming to provide a positive work environment that enhance bonds between team members, creating positive mindset, and encouraging innovation and creativity.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72937239","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}
Mohd Anwar Mohamed Latif, M. Bedewi, A. Abdullayev, Noura Al Saadi, Babar Saleem, Ahmed Mohamed Al Bairaq, Ammar Faqqas Al Ameri
A giant gas field consisting of six stacked carbonate reservoirs of Lower Cretaceous age with gas caps and non-associated gas where the production follows a depletion scheme is discussed. The field has a production history of more than 30 years with more than 150 gas condensate wells flowing to a common surface network, which means production decline is inevitable. This study assesses various mitigation actions to extend the plateau or minimize the anticipated inevitable production decline, and optimize costs while adhering to a service level agreement (SLA) with the consumer gas plant. This paper illustrates how the use of an integrated asset model (IAM) as a digital twin of the actual asset can help provide a holistic approach for evaluating critical investment decisions. The proposed mitigation actions were mainly focused on surface facilities because gas fields are sensitive to backpressure; the mitigation actions were primarily geared toward reducing backpressure to remedy the anticipated production decline. Gas plant inlet/outlet pressure reduction proved to provide significant plateau extension. This finding was verified by means of field trials. Intermittent and weak producers responded positively to the implementation of wellhead compression during the IAM simulation; consequently, a pilot was implemented in the field to verify the simulation conclusion. IAM also proved that adding 20 new infill wells would help accelerate gas production, if necessary; but, it requires further economic justification before implementation. Simulating scenarios, such as the segregation of wells currently sharing flowlines, had a minor effect to overall field production. A previous reconfiguration of compressors within the compression stations proved beneficial in mitigating production decline and accelerating gas volume. However, because of operational risks and associated costs, future reconfigurations showed minimum impact. A significant portion of the study was focused on modeling the downtime of various components of the asset surface facilities as per the integrated shutdown plan (ISDP) and identifying alternative routes to minimize overall gas production disruption and to adhere to the SLA commitment. The focus on precisely simulating the operational side of the field was enabled by the use of IAM as a digital twin of the actual asset. In addition to the usual simulation benefits, such as the assessment of various sensitivities before implementing significant investments in real life, this holistic approach can help realize cost-saving opportunities and help ensure future adherence to the contracted gas rate.
{"title":"Holistic Approach to Prolong Giant Onshore Abu Dhabi Gas Field Production Plateau and Optimize CAPEX/OPEX Using an Integrated Asset Model as a Digital Twin","authors":"Mohd Anwar Mohamed Latif, M. Bedewi, A. Abdullayev, Noura Al Saadi, Babar Saleem, Ahmed Mohamed Al Bairaq, Ammar Faqqas Al Ameri","doi":"10.2118/197659-ms","DOIUrl":"https://doi.org/10.2118/197659-ms","url":null,"abstract":"\u0000 A giant gas field consisting of six stacked carbonate reservoirs of Lower Cretaceous age with gas caps and non-associated gas where the production follows a depletion scheme is discussed. The field has a production history of more than 30 years with more than 150 gas condensate wells flowing to a common surface network, which means production decline is inevitable.\u0000 This study assesses various mitigation actions to extend the plateau or minimize the anticipated inevitable production decline, and optimize costs while adhering to a service level agreement (SLA) with the consumer gas plant.\u0000 This paper illustrates how the use of an integrated asset model (IAM) as a digital twin of the actual asset can help provide a holistic approach for evaluating critical investment decisions.\u0000 The proposed mitigation actions were mainly focused on surface facilities because gas fields are sensitive to backpressure; the mitigation actions were primarily geared toward reducing backpressure to remedy the anticipated production decline.\u0000 Gas plant inlet/outlet pressure reduction proved to provide significant plateau extension. This finding was verified by means of field trials. Intermittent and weak producers responded positively to the implementation of wellhead compression during the IAM simulation; consequently, a pilot was implemented in the field to verify the simulation conclusion. IAM also proved that adding 20 new infill wells would help accelerate gas production, if necessary; but, it requires further economic justification before implementation.\u0000 Simulating scenarios, such as the segregation of wells currently sharing flowlines, had a minor effect to overall field production. A previous reconfiguration of compressors within the compression stations proved beneficial in mitigating production decline and accelerating gas volume. However, because of operational risks and associated costs, future reconfigurations showed minimum impact.\u0000 A significant portion of the study was focused on modeling the downtime of various components of the asset surface facilities as per the integrated shutdown plan (ISDP) and identifying alternative routes to minimize overall gas production disruption and to adhere to the SLA commitment.\u0000 The focus on precisely simulating the operational side of the field was enabled by the use of IAM as a digital twin of the actual asset. In addition to the usual simulation benefits, such as the assessment of various sensitivities before implementing significant investments in real life, this holistic approach can help realize cost-saving opportunities and help ensure future adherence to the contracted gas rate.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75568843","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}
Jose Miguel Dorival Vargas, Pável Zuloaga Molero, Elizabeth Segama Candiotti, E. Gomez
This paper discusses the historical evolution and future performance of wellbore dynamics in a multilayered gas condensate well (100 MMSCFD) in the Camisea Field - Peru. The analysis included the modeling of water vapor content produced within the gas condensate stream and its multiphase behavior and interaction with other fluids inside the borehole through the reservoir depletion under commingled production. The goal of this study is to quantify the impact of the wellbore dynamics in well deliverability and the effective recovery of hydrocarbons for each individual layer, and propose actions to achieve an optimum production scheme. The approach is based on the modeling and matching of dynamic behavior of the wellbore and individual layers with the observed data during 9 years. For this purpose a dynamic wellbore model was built using OLGA. The inputs to the model are: 1) the properties for each productive layer characterized using multirate test combined with PLT logs to get the individual IPR's; 2) the model of the reservoir fluid to properly represent the retrograde condensation and the behavior of water in the vapor phase; and 3) the liquid levels in the wellbore from historical PLTs and density logs. In the field case studied, the analysis showed that the water vapor present in the fluid stream is a fundamental key to understand the evolution of fluid levels inside the wellbore. This is quite important since the water in the gas phase is not usually included in the EOS for reservoir simulation purposes and its impact in the wellbore dynamics is neglected because of the very low BSW (less than 1%). For the well that has been studied, the analysis revealed that the lower zone was prone to stop producing due to the higher productivity of the upper reservoirs. Consequently, the increase in liquid level was a result of the production decrease and not vice versa. After the lower layer stopped producing, it was observed that there was a quicker increase of the liquid column between the upper and lower reservoirs. This column was mostly condensate but it was gradually replaced by water in the liquid phase, which came from the vapor phase produced in the upper reservoirs. This slow replacement represents a more restrictive condition for the lower reservoir, as the column becomes denser. This study allowed for the understanding the complex interaction between retrograde condensation and water vapor behavior with the wellbore dynamics. The study also describes the process of the liquid accumulation during the decline of production of multilayered reservoirs which was successfully matched with observed data. As a result of the analysis, a new completion scheme was proposed to effectively recover the hydrocarbons in the layers affected by liquid loading issues.
{"title":"Dynamic Wellbore Modeling for Multilayered Gas Condensate Wells with Water Vapor Content Using Olga: A Case Study in Camisea Field.","authors":"Jose Miguel Dorival Vargas, Pável Zuloaga Molero, Elizabeth Segama Candiotti, E. Gomez","doi":"10.2118/197701-ms","DOIUrl":"https://doi.org/10.2118/197701-ms","url":null,"abstract":"\u0000 This paper discusses the historical evolution and future performance of wellbore dynamics in a multilayered gas condensate well (100 MMSCFD) in the Camisea Field - Peru. The analysis included the modeling of water vapor content produced within the gas condensate stream and its multiphase behavior and interaction with other fluids inside the borehole through the reservoir depletion under commingled production. The goal of this study is to quantify the impact of the wellbore dynamics in well deliverability and the effective recovery of hydrocarbons for each individual layer, and propose actions to achieve an optimum production scheme.\u0000 The approach is based on the modeling and matching of dynamic behavior of the wellbore and individual layers with the observed data during 9 years. For this purpose a dynamic wellbore model was built using OLGA. The inputs to the model are: 1) the properties for each productive layer characterized using multirate test combined with PLT logs to get the individual IPR's; 2) the model of the reservoir fluid to properly represent the retrograde condensation and the behavior of water in the vapor phase; and 3) the liquid levels in the wellbore from historical PLTs and density logs.\u0000 In the field case studied, the analysis showed that the water vapor present in the fluid stream is a fundamental key to understand the evolution of fluid levels inside the wellbore. This is quite important since the water in the gas phase is not usually included in the EOS for reservoir simulation purposes and its impact in the wellbore dynamics is neglected because of the very low BSW (less than 1%). For the well that has been studied, the analysis revealed that the lower zone was prone to stop producing due to the higher productivity of the upper reservoirs. Consequently, the increase in liquid level was a result of the production decrease and not vice versa. After the lower layer stopped producing, it was observed that there was a quicker increase of the liquid column between the upper and lower reservoirs. This column was mostly condensate but it was gradually replaced by water in the liquid phase, which came from the vapor phase produced in the upper reservoirs. This slow replacement represents a more restrictive condition for the lower reservoir, as the column becomes denser.\u0000 This study allowed for the understanding the complex interaction between retrograde condensation and water vapor behavior with the wellbore dynamics. The study also describes the process of the liquid accumulation during the decline of production of multilayered reservoirs which was successfully matched with observed data. As a result of the analysis, a new completion scheme was proposed to effectively recover the hydrocarbons in the layers affected by liquid loading issues.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74762967","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}
More than 40 million people around the world are victims of modern slavery, 25 million of them in forced labour (ILO, 2017); most of these working in the supply chains of global business. If we are to achieve the UN Sustainable Development Goal 8 – Decent Work and Economic Growth – and its target to "eradicate forced labour, end modern slavery and human trafficking" - by 2030, businesses and governments must do more to address these issues. In 2014 only 4 countries were taking steps to develop legislation and investigate forced labour in business and government supply chains, in 2018 that had increased to 36 countries. Aside from being the right thing to do, the commercial case for improving labour rights and worker welfare is compelling. When workers are happy and engaged, they tend to work more safely and efficiently, and the risk of delays and disputes is minimised. To tackle this issue, Petrofac worked with our supply chain partners to understand the realities – and address the issues. Through Petrofac's due diligence, we know that our main human rights vulnerability is through our supply chain and, more specifically, its employment of low-skilled migrant workers from ‘high risk’ countries. And, of particular concern are the practices of any agents they use, which may include the charging of excessive recruitment fees, unconsented retention of passports and the risk of contract discrepancies during recruitment. To address potential risks identified through our due diligence, a labour rights and worker welfare programme was implemented. Group wide initiatives such as development and roll-out of Labour Rights and Worker Welfare Standards, were supported at site by a ‘labour rights toolkit’ that included: Supply chain training to highlight why we need to get these issues right.Monitoring across our projects to understand the extent of the issues.Implementation arrangements drawn up collaboratively with our supply chain partners to establish protections for migrant workers, andA programme of oversight to assure compliance. To date we have seen a progressively improving picture of both awareness and management of the issues on our projects. The Employer Pays Principle is being implemented down the supply chain, ensuring employing companies (not workers) pay for the cost of recruitment, thereby reducing the debt workers incur in their search for work. Retention of passports only occurs with worker consent, and workers have unrestricted access to their documents and freedom of movement. Employment contracts are also in a language workers understand (or that has been properly explained to them), so they are aware of the terms of their employment and more able to assert their rights. The programme is currently being rolled out across Petrofac. We are increasing our engagement with industry to share good practice and are committed to working in partnership with our clients and supply chain to ensure human rights are respected across our business
{"title":"Turning Challenge into Opportunity - Enhancing Worker Labour Rights Through Supply Chain Collaboration","authors":"Gregory Ross","doi":"10.2118/197835-ms","DOIUrl":"https://doi.org/10.2118/197835-ms","url":null,"abstract":"\u0000 More than 40 million people around the world are victims of modern slavery, 25 million of them in forced labour (ILO, 2017); most of these working in the supply chains of global business. If we are to achieve the UN Sustainable Development Goal 8 – Decent Work and Economic Growth – and its target to \"eradicate forced labour, end modern slavery and human trafficking\" - by 2030, businesses and governments must do more to address these issues. In 2014 only 4 countries were taking steps to develop legislation and investigate forced labour in business and government supply chains, in 2018 that had increased to 36 countries.\u0000 Aside from being the right thing to do, the commercial case for improving labour rights and worker welfare is compelling. When workers are happy and engaged, they tend to work more safely and efficiently, and the risk of delays and disputes is minimised. To tackle this issue, Petrofac worked with our supply chain partners to understand the realities – and address the issues.\u0000 Through Petrofac's due diligence, we know that our main human rights vulnerability is through our supply chain and, more specifically, its employment of low-skilled migrant workers from ‘high risk’ countries. And, of particular concern are the practices of any agents they use, which may include the charging of excessive recruitment fees, unconsented retention of passports and the risk of contract discrepancies during recruitment.\u0000 To address potential risks identified through our due diligence, a labour rights and worker welfare programme was implemented. Group wide initiatives such as development and roll-out of Labour Rights and Worker Welfare Standards, were supported at site by a ‘labour rights toolkit’ that included: Supply chain training to highlight why we need to get these issues right.Monitoring across our projects to understand the extent of the issues.Implementation arrangements drawn up collaboratively with our supply chain partners to establish protections for migrant workers, andA programme of oversight to assure compliance.\u0000 To date we have seen a progressively improving picture of both awareness and management of the issues on our projects. The Employer Pays Principle is being implemented down the supply chain, ensuring employing companies (not workers) pay for the cost of recruitment, thereby reducing the debt workers incur in their search for work. Retention of passports only occurs with worker consent, and workers have unrestricted access to their documents and freedom of movement. Employment contracts are also in a language workers understand (or that has been properly explained to them), so they are aware of the terms of their employment and more able to assert their rights.\u0000 The programme is currently being rolled out across Petrofac. We are increasing our engagement with industry to share good practice and are committed to working in partnership with our clients and supply chain to ensure human rights are respected across our business","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78728490","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The fully integrated modelling of subsurface seismic and well data with outcropping surface geological data is a challenge in which the application of modern technologies which involves the standardisation of datasets on different scales and from different sources plays a key role. In this paper we present an example of the Paleozoic of the Ahnet Basin in Algeria where a prospect generation exercise was undertaken integrating data from 2d and 3d seismic volumes, logs and core data from previously drilled wells, maps of outcropping geology, and high-resolution remote sensing datasets. The geology of the area is well known from previous studies on both surface geology and well data, and comprises a Paleozoic series unconformably resting on infra-Cambrian relative basement, and made up of clastic sedimentary series with intercalation of limestone sediments ranging from Cambrian to Devonian Age, which comprise various gas bearing tight reservoirs some of which producing in this part of the Basin. These are present in anticlinal structures of Hercynian Age which are partly eroded and covered by Cretaceous bioclastic limestones. The anticlines show a deformational history reflecting an interference of differently oriented Hercynian transpressional deformation patterns overprinted by later stage, Alpine reactivations. Our integrated geological analyses permitted to propose a new updated view on the geological history of the area. This includes the reconstruction of the structural deformation of the Hercynian anticlines, and the reconstruction of the post-Hercynian geological evolution including structural reactivation, showing tilting and upheaval of the area in Alpine and Recent times. An extensive interpretation of outcropping geological structures was performed using high resolution satellite images and specific image processing. This was calibrated with available high-quality geological maps and some later additional limited geological surveys. Detailed well log correlations and seismic interpretation 2d and 3d seismic data provided a detailed framework of subsurface structures. The datasets on surface vand subsurface originally coming from different digital sources were integrated in one uniform interpretation environment using best practice standardization which permitted to drive the seismic interpretation and depth modelling, by carefully calibration with outcropping features such as bedding dip, fault trends and fold axis trends. Applying regional velocity modelling this permitted to correctly map the geological structures and prospects in the area, and perform an articulated exercise of Prospective and Contingent Resources estimates. The application of an integrated geoscientific workflow deploying up-to-date technologies which integrate GIS with a surface-subsurface 3d modelling space shows the validity of new developments of the 4th Industrial Revolution in the planning of E&P Prospect evaluation.
{"title":"Fully Integrated Modelling of Subsurface, Remote Sensing and Outcrop Geology; Prospect Generation in the Paleozoic of the Ahnet Basin Algeria","authors":"J. V. Dijk, H. Guney","doi":"10.2118/197224-ms","DOIUrl":"https://doi.org/10.2118/197224-ms","url":null,"abstract":"\u0000 The fully integrated modelling of subsurface seismic and well data with outcropping surface geological data is a challenge in which the application of modern technologies which involves the standardisation of datasets on different scales and from different sources plays a key role. In this paper we present an example of the Paleozoic of the Ahnet Basin in Algeria where a prospect generation exercise was undertaken integrating data from 2d and 3d seismic volumes, logs and core data from previously drilled wells, maps of outcropping geology, and high-resolution remote sensing datasets.\u0000 The geology of the area is well known from previous studies on both surface geology and well data, and comprises a Paleozoic series unconformably resting on infra-Cambrian relative basement, and made up of clastic sedimentary series with intercalation of limestone sediments ranging from Cambrian to Devonian Age, which comprise various gas bearing tight reservoirs some of which producing in this part of the Basin. These are present in anticlinal structures of Hercynian Age which are partly eroded and covered by Cretaceous bioclastic limestones. The anticlines show a deformational history reflecting an interference of differently oriented Hercynian transpressional deformation patterns overprinted by later stage, Alpine reactivations. Our integrated geological analyses permitted to propose a new updated view on the geological history of the area. This includes the reconstruction of the structural deformation of the Hercynian anticlines, and the reconstruction of the post-Hercynian geological evolution including structural reactivation, showing tilting and upheaval of the area in Alpine and Recent times.\u0000 An extensive interpretation of outcropping geological structures was performed using high resolution satellite images and specific image processing. This was calibrated with available high-quality geological maps and some later additional limited geological surveys. Detailed well log correlations and seismic interpretation 2d and 3d seismic data provided a detailed framework of subsurface structures. The datasets on surface vand subsurface originally coming from different digital sources were integrated in one uniform interpretation environment using best practice standardization which permitted to drive the seismic interpretation and depth modelling, by carefully calibration with outcropping features such as bedding dip, fault trends and fold axis trends. Applying regional velocity modelling this permitted to correctly map the geological structures and prospects in the area, and perform an articulated exercise of Prospective and Contingent Resources estimates.\u0000 The application of an integrated geoscientific workflow deploying up-to-date technologies which integrate GIS with a surface-subsurface 3d modelling space shows the validity of new developments of the 4th Industrial Revolution in the planning of E&P Prospect evaluation.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77702374","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}
Amjed Hassan, O. Alade, M. Mahmoud, Abdulaziz Al-Majed
In the petroleum industry, deposition of hydrocarbon wax is one the critical problems. Wax can deposit and accumulate inside the well completion, surface facilities and transportation pipelines. Wax deposition can lead to significant pressure drop in the production system and may result in stopping the hydrocarbon production. Several treatments are used to remove the deposited wax and improve the hydrocarbon flow. This paper presents a new and cost-effective technique for removing the wax deposition from the production system. In this work, inexpensive and environmentally-friendly fluids have been used for wax removal. Chemicals that able to generate heat and pressure at certain condition were used. In this study, thermochemical fluids were utilized to remove the accumulate wax in the production tubing. Actual wax from Arabian oil field was used to mimic the real condition of wax deposition. Thermochemical solutions that consist of two chemical reagents were used to remove the accumulated wax in a production tubing. The used chemical can react at certain condition and generate significant amount of heat and pressure. Temperature up to 500°F and pressure up to 2000 psi can be in-situ generated due to the thermochemical reaction. The chemical reaction can be triggered using acetic acid as an activating agent, to reduce the operational time for wax removal. The results showed that, more than 95% of the deposited wax can be removed using thermochemical solutions. The in-situ generated heat is able to liquefy the precipitated wax, then, the induced pressure due to the chemical reaction can flush the wax out of the production tubing. The used chemicals did not result in any damage in the pipeline, no corrosion or precipitation was observed in the production tubing. Also, the generated pressure due to thermochemical treatment did not reduce the pipe integrity, no pipe enlargement or damage was induced in the treated samples. This study presents a novel and high-performance treatment for wax removal using thermochemical fluids. The used chemicals can remove the wax from production tubing, surface facilities, and transportation pipelines; without affecting the integrity of the production system. The thermochemical fluids can be used at harsh situation of high temperature and high salinity condition. The obtained results show that there is a good potential for field application of this work in the next few months.
{"title":"A Novel Technique for Removing Wax Deposition in the Production System Using Thermochemical Fluids","authors":"Amjed Hassan, O. Alade, M. Mahmoud, Abdulaziz Al-Majed","doi":"10.2118/197323-ms","DOIUrl":"https://doi.org/10.2118/197323-ms","url":null,"abstract":"\u0000 In the petroleum industry, deposition of hydrocarbon wax is one the critical problems. Wax can deposit and accumulate inside the well completion, surface facilities and transportation pipelines. Wax deposition can lead to significant pressure drop in the production system and may result in stopping the hydrocarbon production. Several treatments are used to remove the deposited wax and improve the hydrocarbon flow. This paper presents a new and cost-effective technique for removing the wax deposition from the production system. In this work, inexpensive and environmentally-friendly fluids have been used for wax removal. Chemicals that able to generate heat and pressure at certain condition were used.\u0000 In this study, thermochemical fluids were utilized to remove the accumulate wax in the production tubing. Actual wax from Arabian oil field was used to mimic the real condition of wax deposition. Thermochemical solutions that consist of two chemical reagents were used to remove the accumulated wax in a production tubing. The used chemical can react at certain condition and generate significant amount of heat and pressure. Temperature up to 500°F and pressure up to 2000 psi can be in-situ generated due to the thermochemical reaction. The chemical reaction can be triggered using acetic acid as an activating agent, to reduce the operational time for wax removal.\u0000 The results showed that, more than 95% of the deposited wax can be removed using thermochemical solutions. The in-situ generated heat is able to liquefy the precipitated wax, then, the induced pressure due to the chemical reaction can flush the wax out of the production tubing. The used chemicals did not result in any damage in the pipeline, no corrosion or precipitation was observed in the production tubing. Also, the generated pressure due to thermochemical treatment did not reduce the pipe integrity, no pipe enlargement or damage was induced in the treated samples.\u0000 This study presents a novel and high-performance treatment for wax removal using thermochemical fluids. The used chemicals can remove the wax from production tubing, surface facilities, and transportation pipelines; without affecting the integrity of the production system. The thermochemical fluids can be used at harsh situation of high temperature and high salinity condition. The obtained results show that there is a good potential for field application of this work in the next few months.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80040210","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}
Fatima Al Awadhi, A. Al-Ameri, Ahmed Mohamed Al Bairaq, I. Mohamed, E. Latypov, M. Sudarev, Y. Pramudyo
The study was conducted for Giant Gas-Condensate reservoir under Recycling mode in order to achieve the high condensate recovery and maintain the reservoir pressure by sectorize the reservoir into the different sectors. Especially with under-injection mode when no make-up gas is availableor sellable gas is required. The available amount of gas for injection should be properly distributed across the reservoir to maintain the reservoir pressure where it is most required and same time to prevent the early gas breakthrough. The study was aimed to sectorize the reservoir into thedifferent sectors which will lead to improve the reservoir management including the re-distribution of injection and full field development strategies. The two approached have been created for sectorization: first approachwas based on the geological definition and second approach was based on the well level optimization. Many reservoir data have been utilized in this study including the surface facilities layout. Initially, the available geological data such as Facies has been used to generate the above explained approaches. The actual tracer and other production/injection data used to confirm the above explained sectorization. Finally, the simulation model was re-build to address the sectorization. Moreover, several sensitives were simulated assume the 50%-80% RecycleRatio to come up with the optimum setup for gas injection distribution for the existing wells including the newly 2018 commissioned peripheral gasinjectors. This work has resulted in positive outcome with few millions additional condensate recovery with zero investment. According the outcomes analysis the implementation plan is designed with allowable per each gas injector.
{"title":"State of the Art Approach on Mega Rich Gas Condensate Development: Sectorization Approach - Case Study, ADNOC Onshore Fields, UAE","authors":"Fatima Al Awadhi, A. Al-Ameri, Ahmed Mohamed Al Bairaq, I. Mohamed, E. Latypov, M. Sudarev, Y. Pramudyo","doi":"10.2118/197934-ms","DOIUrl":"https://doi.org/10.2118/197934-ms","url":null,"abstract":"\u0000 The study was conducted for Giant Gas-Condensate reservoir under Recycling mode in order to achieve the high condensate recovery and maintain the reservoir pressure by sectorize the reservoir into the different sectors. Especially with under-injection mode when no make-up gas is availableor sellable gas is required. The available amount of gas for injection should be properly distributed across the reservoir to maintain the reservoir pressure where it is most required and same time to prevent the early gas breakthrough. The study was aimed to sectorize the reservoir into thedifferent sectors which will lead to improve the reservoir management including the re-distribution of injection and full field development strategies.\u0000 The two approached have been created for sectorization: first approachwas based on the geological definition and second approach was based on the well level optimization. Many reservoir data have been utilized in this study including the surface facilities layout.\u0000 Initially, the available geological data such as Facies has been used to generate the above explained approaches. The actual tracer and other production/injection data used to confirm the above explained sectorization. Finally, the simulation model was re-build to address the sectorization. Moreover, several sensitives were simulated assume the 50%-80% RecycleRatio to come up with the optimum setup for gas injection distribution for the existing wells including the newly 2018 commissioned peripheral gasinjectors.\u0000 This work has resulted in positive outcome with few millions additional condensate recovery with zero investment. According the outcomes analysis the implementation plan is designed with allowable per each gas injector.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80972050","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 carbonates, predicting permeability values for gridded reservoir models is very challenging as it involves both the difficult characterization of a very heterogeneous medium, the uncertain extrapolation far from well data, and the up-scaling concern. The quantification of effective permeability for model gridblocks using small scale data from plug measurements or log interpretation is a recurrent concern since the change of support for permeability has proved to be definitively non linear. When a well test interpretation is available, it gives the evolution of the permeability in the vicinity of the wells for a volume much larger than the volumes characterized by cores and logs. In that case, the consistency has to be found between the transient pressure analysis-derived large scale equivalent permeability and the small scale permeability issued from conventional core analysis or log interpretation. It is known that the upscaling can be expressed as some power average of the permeability distribution, and that an analytical formula relates the horizontal permeability in the volume investigated by the well test and the original small-scale permeability distribution in this volume. However, the relation between the upscaling law and the permeability structures is usually documented for a few number of structures, leading to recurrent problems when large scale permeability has to be extrapolated outside the volume explored by the well test. A new formulation of the power averaging coefficient has been proposed, which relates the power averaging coefficient to the geostatistical description of the permeability structures, the direction of the flow, and the volume for which the equivalent permeability is computed. The new methodology has been applied to the Buissonniere field laboratory, a site from the ALBION R&D Project. Thanks to a characterization at an unusual scale, the integration of geological, petrophysical, geophysical and pressure transient data has successfully validated the use of this new formulation.
{"title":"Permeability Upscaling in Carbonates. An Integrated Case Study From the Albion R&D Project","authors":"G. Massonnat, C. Danquigny, J. Rolando","doi":"10.2118/197122-ms","DOIUrl":"https://doi.org/10.2118/197122-ms","url":null,"abstract":"\u0000 In carbonates, predicting permeability values for gridded reservoir models is very challenging as it involves both the difficult characterization of a very heterogeneous medium, the uncertain extrapolation far from well data, and the up-scaling concern. The quantification of effective permeability for model gridblocks using small scale data from plug measurements or log interpretation is a recurrent concern since the change of support for permeability has proved to be definitively non linear. When a well test interpretation is available, it gives the evolution of the permeability in the vicinity of the wells for a volume much larger than the volumes characterized by cores and logs. In that case, the consistency has to be found between the transient pressure analysis-derived large scale equivalent permeability and the small scale permeability issued from conventional core analysis or log interpretation.\u0000 It is known that the upscaling can be expressed as some power average of the permeability distribution, and that an analytical formula relates the horizontal permeability in the volume investigated by the well test and the original small-scale permeability distribution in this volume. However, the relation between the upscaling law and the permeability structures is usually documented for a few number of structures, leading to recurrent problems when large scale permeability has to be extrapolated outside the volume explored by the well test.\u0000 A new formulation of the power averaging coefficient has been proposed, which relates the power averaging coefficient to the geostatistical description of the permeability structures, the direction of the flow, and the volume for which the equivalent permeability is computed. The new methodology has been applied to the Buissonniere field laboratory, a site from the ALBION R&D Project. Thanks to a characterization at an unusual scale, the integration of geological, petrophysical, geophysical and pressure transient data has successfully validated the use of this new formulation.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84091707","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
CO2 flooding is well-known to be an effective EOR method and has been successfully implemented around the world. In heterogeneous formations, CO2 foam has been utilized to achieve conformance and mobility control. However, the foam performance degrades significantly at high saline environments. Ethoxylated amines have been reported to be successful in high pressure-high temperature (HPHT) conditions. This paper investigates the results obtained from a study of the foamability and foam stability at varying salinities, initial pH, and surfactant concentration. The surfactant is evaluated to provide optimum concentration, salinity, and a pH level for better foam performance during EOR applications. Bottle shake tests achieved the objectives of this paper. Different salinities of brine, ranging from 0 to 25 wt%, mixed with the surfactant, with concentrations of 0.1 to 1 wt%, helped in the investigation of the foam performance. The bottle shake tests were conducted to prescreen the surfactant concentration, salinity, and pH level, at ambient conditions. Sodium chloride was used to prepare the solutions. The bottle shake tests indicated that, in terms of foam half-life, the optimal surfactant concentration was 0.25 wt% for salinities of 0 to 15 wt% NaCl. Moreover, at this salinity range, the lowering of the surfactant solution's pH had a detrimental effect on the foam stability. The faster collapse of the foam at lower pH could be attributed to the repulsive interactions between the amine headgroups. The optimum initial pH was between 6 and 6.5 for salinity between 0 to 15 wt% NaCl. However, for higher salinity environment, 15 to 25 wt% NaCl, foam stability at low pH shows drastic improvement over its counterpart at lower salinities. At these high salinities, the optimal surfactant concentration was 0.50 wt%. The application of the ethoxylated amine surfactant at different salinity levels has not been studied in detail. The application of this surfactant needs to be evaluated for optimum concentration, pH, and salinity. The effect of the surfactant's initial pH on the foamability and foam half-life has not been investigated. This paper addresses these gaps in literature and provides an optimized composition that can be applied for EOR operations.
{"title":"Evaluation of an Ethoxylated Amine Surfactant for CO2-Foam Stability at High Salinity Conditions","authors":"L. Le, R. Ramanathan, H. Nasr-El-Din","doi":"10.2118/197515-ms","DOIUrl":"https://doi.org/10.2118/197515-ms","url":null,"abstract":"\u0000 CO2 flooding is well-known to be an effective EOR method and has been successfully implemented around the world. In heterogeneous formations, CO2 foam has been utilized to achieve conformance and mobility control. However, the foam performance degrades significantly at high saline environments. Ethoxylated amines have been reported to be successful in high pressure-high temperature (HPHT) conditions. This paper investigates the results obtained from a study of the foamability and foam stability at varying salinities, initial pH, and surfactant concentration.\u0000 The surfactant is evaluated to provide optimum concentration, salinity, and a pH level for better foam performance during EOR applications. Bottle shake tests achieved the objectives of this paper. Different salinities of brine, ranging from 0 to 25 wt%, mixed with the surfactant, with concentrations of 0.1 to 1 wt%, helped in the investigation of the foam performance. The bottle shake tests were conducted to prescreen the surfactant concentration, salinity, and pH level, at ambient conditions. Sodium chloride was used to prepare the solutions.\u0000 The bottle shake tests indicated that, in terms of foam half-life, the optimal surfactant concentration was 0.25 wt% for salinities of 0 to 15 wt% NaCl. Moreover, at this salinity range, the lowering of the surfactant solution's pH had a detrimental effect on the foam stability. The faster collapse of the foam at lower pH could be attributed to the repulsive interactions between the amine headgroups. The optimum initial pH was between 6 and 6.5 for salinity between 0 to 15 wt% NaCl. However, for higher salinity environment, 15 to 25 wt% NaCl, foam stability at low pH shows drastic improvement over its counterpart at lower salinities. At these high salinities, the optimal surfactant concentration was 0.50 wt%.\u0000 The application of the ethoxylated amine surfactant at different salinity levels has not been studied in detail. The application of this surfactant needs to be evaluated for optimum concentration, pH, and salinity. The effect of the surfactant's initial pH on the foamability and foam half-life has not been investigated. This paper addresses these gaps in literature and provides an optimized composition that can be applied for EOR operations.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82184396","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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