Kalyanaraman Venugopal, D. Shastri, Suryanarayanan Radhakrishnan, R. Krishnamoorti
The upstream oil and gas industry's digital transformation over the last few years has accelerated because of the COVID-19 pandemic. Data analytics and machine learning are key components of this digital transformation and have become essential skills for experienced petrotechnical professionals (PTPs) and aspiring entrants into the field. The objective of our work was to design and deliver a practical, engaging, and online microcredential certification program in upstream energy data analytics for PTPs. The program was conceived as a collaboration between academia (University of Houston's UH Energy) and industry (NExT, a Schlumberger company). It was designed as three belt levels (Bronze, Silver, and Gold), each containing three stackable badges of 12 to 15 hours duration per badge. Key design points included Identifying an online platform for administration Delivering convenient, interactive, live online sessions Delivering hybrid classes blending lectures and hands-on laboratories Designing laboratories using upstream datasets across various stages of oilfield expertise Administering test and quizzes, Kaggle competitions, and team projects. The program contents were designed incorporating appropriate instructional design practices for effective online class delivery. The design and delivery of the laboratories using a code-free approach by leveraging visual programming offers PTPs and new entrants a unique opportunity to learn data analytics concepts without the traditional concern of learning to code. Additionally, the collaboration between academia and industry enables delivering a program that combines academic rigor with application of the skills and knowledge to solve problems facing the industry using the real-world datasets. As a pilot program, all three badges of the Bronze belt were scheduled and successfully delivered during July and August 2020, as six 2-hour sessions per badge. From a total of 26 students registered in badge 1, 24 completed it, resulting in a completion rate of 92%. Out of these students, 19 registered and completed badge 2 and badge 3, resulting in the completion rates of 100%. Based on the success of the pilot program, a second delivery of the Bronze belt with 18 participants was offered from October 2020 through January 2021. All 18 participants completed all three badges. Feedback from participants attests to the success of the pilot program as seen in the following excerpts: "A very good course and instructors. I have already recommended the course to a friend and I will continue to be an advocate for the course." "Teachers are very receptive to questions and it is a joy to hear their lectures." "I found the University of Houston course to be both highly engaging and incredibly informative. The course teaches basic principles of data science without being bogged down by the specific coding language."
{"title":"An Online Microcredential Certification Program to Upskill Petrotechnical Professionals in Data Analytics and Machine Learning with an Upstream Oil and Gas Industry Focus","authors":"Kalyanaraman Venugopal, D. Shastri, Suryanarayanan Radhakrishnan, R. Krishnamoorti","doi":"10.2118/205921-ms","DOIUrl":"https://doi.org/10.2118/205921-ms","url":null,"abstract":"\u0000 The upstream oil and gas industry's digital transformation over the last few years has accelerated because of the COVID-19 pandemic. Data analytics and machine learning are key components of this digital transformation and have become essential skills for experienced petrotechnical professionals (PTPs) and aspiring entrants into the field. The objective of our work was to design and deliver a practical, engaging, and online microcredential certification program in upstream energy data analytics for PTPs.\u0000 The program was conceived as a collaboration between academia (University of Houston's UH Energy) and industry (NExT, a Schlumberger company). It was designed as three belt levels (Bronze, Silver, and Gold), each containing three stackable badges of 12 to 15 hours duration per badge. Key design points included\u0000 Identifying an online platform for administration Delivering convenient, interactive, live online sessions Delivering hybrid classes blending lectures and hands-on laboratories Designing laboratories using upstream datasets across various stages of oilfield expertise Administering test and quizzes, Kaggle competitions, and team projects.\u0000 The program contents were designed incorporating appropriate instructional design practices for effective online class delivery. The design and delivery of the laboratories using a code-free approach by leveraging visual programming offers PTPs and new entrants a unique opportunity to learn data analytics concepts without the traditional concern of learning to code. Additionally, the collaboration between academia and industry enables delivering a program that combines academic rigor with application of the skills and knowledge to solve problems facing the industry using the real-world datasets.\u0000 As a pilot program, all three badges of the Bronze belt were scheduled and successfully delivered during July and August 2020, as six 2-hour sessions per badge. From a total of 26 students registered in badge 1, 24 completed it, resulting in a completion rate of 92%. Out of these students, 19 registered and completed badge 2 and badge 3, resulting in the completion rates of 100%. Based on the success of the pilot program, a second delivery of the Bronze belt with 18 participants was offered from October 2020 through January 2021. All 18 participants completed all three badges. Feedback from participants attests to the success of the pilot program as seen in the following excerpts:\u0000 \"A very good course and instructors. I have already recommended the course to a friend and I will continue to be an advocate for the course.\" \"Teachers are very receptive to questions and it is a joy to hear their lectures.\" \"I found the University of Houston course to be both highly engaging and incredibly informative. The course teaches basic principles of data science without being bogged down by the specific coding language.\"","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82358422","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}
An offshore well located in Indonesia required rigless installation of an insertable progressive cavity pump (I-PCP) as a cost-effective solution to restore production while eliminating the need to retrieve the upper completion for extensive maintenance. The well had been previously completed with a conventional progressive cavity pump (PCP) as an integral part of the completion and was placed offline for approximately one year due to mechanical failure of downhole components. Typical I-PCP anchoring methods were not feasible alternatives for this application. A pump-seating nipple (PSN) insertable seal stack could not be used due to the lack of a PSN at the required I-PCP setting depth, and a mechanical J-slot anchoring device could not be deployed because rod conveyance from an offshore barge is subject to constant heave, which results in fluctuating axial loads and rod position, which would pose the risk of prematurely activating a mechanical J-slot anchor during deployment. An inflatable packer anchoring system was selected as a solution to the operational challenges encountered in this application. The system comprises inflatable packer technology, a hydraulically-actuated anchoring slip mechanism, seal cups, and a shearable intake sub. Conveyed on sucker rods, the system provides the required pressure competence to confirm tubing integrity and enable a complete hydraulic setting sequence. The first ever offshore installation of this system proved its optimal functionality by successfully anchoring an I-PCP inside 3-1/2" production tubing riglessly from an offshore barge. The system was set by applying pressure via the tubing-rod annulus, and the well was immediately placed into production. After being shut-in for more than one year, this unique solution provided the well operator with a safe and low-cost alternative to reestablish production while eliminating the need for a workover rig. The objective of this paper is to provide a case study analysis of the first offshore deployment of this technology, discuss its potential for optimizing PCP/I-PCP completion designs, and explain the economic and operational benefits of associated rigless well intervention operations in comparison to current alternative methods.
{"title":"First Ever Offshore Deployment of an Inflatable Packer Anchoring System for Rigless Installation of an Insertable Progressive Cavity Pump: A Case Study","authors":"Alejandro Osorio, F. Ford","doi":"10.2118/206228-ms","DOIUrl":"https://doi.org/10.2118/206228-ms","url":null,"abstract":"\u0000 An offshore well located in Indonesia required rigless installation of an insertable progressive cavity pump (I-PCP) as a cost-effective solution to restore production while eliminating the need to retrieve the upper completion for extensive maintenance. The well had been previously completed with a conventional progressive cavity pump (PCP) as an integral part of the completion and was placed offline for approximately one year due to mechanical failure of downhole components. Typical I-PCP anchoring methods were not feasible alternatives for this application. A pump-seating nipple (PSN) insertable seal stack could not be used due to the lack of a PSN at the required I-PCP setting depth, and a mechanical J-slot anchoring device could not be deployed because rod conveyance from an offshore barge is subject to constant heave, which results in fluctuating axial loads and rod position, which would pose the risk of prematurely activating a mechanical J-slot anchor during deployment.\u0000 An inflatable packer anchoring system was selected as a solution to the operational challenges encountered in this application. The system comprises inflatable packer technology, a hydraulically-actuated anchoring slip mechanism, seal cups, and a shearable intake sub. Conveyed on sucker rods, the system provides the required pressure competence to confirm tubing integrity and enable a complete hydraulic setting sequence.\u0000 The first ever offshore installation of this system proved its optimal functionality by successfully anchoring an I-PCP inside 3-1/2\" production tubing riglessly from an offshore barge. The system was set by applying pressure via the tubing-rod annulus, and the well was immediately placed into production. After being shut-in for more than one year, this unique solution provided the well operator with a safe and low-cost alternative to reestablish production while eliminating the need for a workover rig.\u0000 The objective of this paper is to provide a case study analysis of the first offshore deployment of this technology, discuss its potential for optimizing PCP/I-PCP completion designs, and explain the economic and operational benefits of associated rigless well intervention operations in comparison to current alternative methods.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85753380","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 objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models. While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation. The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker. The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally. The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.
{"title":"Issue with Stone-II Three Phase Permeability Model, and A Novel Robust Fundamentals-Based Alternative to It","authors":"S. Gupta","doi":"10.2118/205883-ms","DOIUrl":"https://doi.org/10.2118/205883-ms","url":null,"abstract":"\u0000 The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models.\u0000 While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation.\u0000 The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker.\u0000 The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally.\u0000 The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79882607","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}
Is this the end of petroleum engineering as we know it? This prescient question led to the most downloaded paper from onepetro.org in 2019. The events of 2020 resulted in massive layoffs, decreased hiring and many fewer students studying petroleum engineering. In the 2019 paper the authors claimed that the future would hold fewer petroleum engineering jobs and very different types of jobs. This paper incorporates a broader range of data and proposes some specific ways to improve prospects for the discipline of petroleum engineering. The opportunity for a near-term recovery is very high as the world overcomes COVID-19 issues, oil demand recovers and the impact of chronic underinvestment in oil and gas production looms. The world's largest producers have very different abilities to respond to a near-term uptick in demand. Energy transition pressures continue to cap growth in demand; however, demand for petroleum engineers is expected to grow under almost every scenario, but not to pre-2015 levels. Increased demand in CCUS and jobs that improve sustainability of oil and gas will continue to outpace conventional jobs. Data analytics will play an increasingly large role in engineering activities. The "Is it the end?" paper started with a question, a question that I first heard asked in 1977 at the SPE Annual Fall Technical Conference and Exhibition in Denver to 1972 SPE President M. Scott Kraemer. I have heard it many times since then and asked it many times. "Would you recommend that your son or daughter study petroleum engineering?" The answer to that question was pretty easy and unanimously positive in 1977. Keep this question in mind as we review what has happened since the prior paper came out.
这是我们所知道的石油工程的终结吗?这个有先见之明的问题导致了2019年onepetro.org上下载最多的论文。2020年的事件导致大规模裁员，招聘减少，学习石油工程的学生减少。在2019年的论文中，作者声称，未来石油工程工作岗位将减少，工作类型将非常不同。本文结合了更广泛的数据，并提出了改善石油工程学科前景的一些具体方法。随着全球克服COVID-19问题，石油需求复苏以及石油和天然气生产长期投资不足的影响迫在眉睫，近期复苏的机会非常高。全球最大的石油生产商应对近期需求上升的能力各不相同。能源转型压力继续限制需求增长;然而，对石油工程师的需求预计在几乎所有情况下都将增长，但不会达到2015年之前的水平。CCUS需求的增加以及提高油气可持续性的工作岗位将继续超过传统工作岗位。数据分析将在工程活动中发挥越来越大的作用。这篇论文以一个问题开始，我第一次听到这个问题是1977年在丹佛举行的SPE年度秋季技术会议和展览上向1972年SPE主席M. Scott Kraemer提出的。从那以后，我听过很多次，也问过很多次。“你会建议你的儿子或女儿学习石油工程吗?”这个问题的答案很简单，在1977年得到了一致的肯定。当我们回顾上一篇论文发表以来发生的事情时，请记住这个问题。
{"title":"It's Not the End of Petroleum Engineering","authors":"D. Meehan","doi":"10.2118/206269-ms","DOIUrl":"https://doi.org/10.2118/206269-ms","url":null,"abstract":"\u0000 Is this the end of petroleum engineering as we know it? This prescient question led to the most downloaded paper from onepetro.org in 2019. The events of 2020 resulted in massive layoffs, decreased hiring and many fewer students studying petroleum engineering. In the 2019 paper the authors claimed that the future would hold fewer petroleum engineering jobs and very different types of jobs. This paper incorporates a broader range of data and proposes some specific ways to improve prospects for the discipline of petroleum engineering.\u0000 The opportunity for a near-term recovery is very high as the world overcomes COVID-19 issues, oil demand recovers and the impact of chronic underinvestment in oil and gas production looms. The world's largest producers have very different abilities to respond to a near-term uptick in demand. Energy transition pressures continue to cap growth in demand; however, demand for petroleum engineers is expected to grow under almost every scenario, but not to pre-2015 levels. Increased demand in CCUS and jobs that improve sustainability of oil and gas will continue to outpace conventional jobs. Data analytics will play an increasingly large role in engineering activities.\u0000 The \"Is it the end?\" paper started with a question, a question that I first heard asked in 1977 at the SPE Annual Fall Technical Conference and Exhibition in Denver to 1972 SPE President M. Scott Kraemer. I have heard it many times since then and asked it many times. \"Would you recommend that your son or daughter study petroleum engineering?\" The answer to that question was pretty easy and unanimously positive in 1977. Keep this question in mind as we review what has happened since the prior paper came out.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78024942","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}
Unconventional reservoirs, mainly shale oil and natural gas, will continue to significantly help meet the ever-growing energy demands of global markets. Being complex in nature and having ultra-tight producing zones, unconventionals depends on effective well completion and stimulation treatments in order to be successful and economical. Within the last decade, thousands of unconventional wells have been drilled, completed and produced in North America. The scope of this work is exploring the primary impact of completion parameters such as lateral length, frac type, number of stages, proppant and fluid volume effect on the production performance of the wells in unconventional fields. The key attributes in completion, stimulation, and production for the wells were considered in machine learning workflow for building predictive models. Predictive models based on Neural Networks, Support Vector Machines or Decision Tree Based ensemble models, serves as mapping function from completion parameters to production in each well in the field. The completion parameters were analyzed in the workflow with respect to feature engineering and interpretation. This analysis resulted in key performance indicators for the region. Then the optimum values for the best production performing completions were identified for each well. Predictive models in the workflow were analyzed in accuracy and best model is used to understand the impact of completion parameters on the production rates. This study outlines an overall machine learning workflow, from feature engineering to interpretation of the machine learning models to quantify the effects of completion parameters on the production rate of the wells in unconventional fields
{"title":"Well Completion Optimization in Unconventional Reservoirs Using Machine Learning Methods","authors":"S. Baki, C. Temizel, Serkan Dursun","doi":"10.2118/206241-ms","DOIUrl":"https://doi.org/10.2118/206241-ms","url":null,"abstract":"\u0000 Unconventional reservoirs, mainly shale oil and natural gas, will continue to significantly help meet the ever-growing energy demands of global markets. Being complex in nature and having ultra-tight producing zones, unconventionals depends on effective well completion and stimulation treatments in order to be successful and economical. Within the last decade, thousands of unconventional wells have been drilled, completed and produced in North America. The scope of this work is exploring the primary impact of completion parameters such as lateral length, frac type, number of stages, proppant and fluid volume effect on the production performance of the wells in unconventional fields.\u0000 The key attributes in completion, stimulation, and production for the wells were considered in machine learning workflow for building predictive models. Predictive models based on Neural Networks, Support Vector Machines or Decision Tree Based ensemble models, serves as mapping function from completion parameters to production in each well in the field. The completion parameters were analyzed in the workflow with respect to feature engineering and interpretation.\u0000 This analysis resulted in key performance indicators for the region. Then the optimum values for the best production performing completions were identified for each well. Predictive models in the workflow were analyzed in accuracy and best model is used to understand the impact of completion parameters on the production rates. This study outlines an overall machine learning workflow, from feature engineering to interpretation of the machine learning models to quantify the effects of completion parameters on the production rate of the wells in unconventional fields","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86624411","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. Ladmia, Younes bin Darak Al Blooshi, A. Alobedli, Dragoljub Zivanov, M. Kuliyev, Eric Deblais, Manal Al Beshr, Ahmed Al Shmakhy, Fouad Abdullsalam, Amer El Bekshy, M. Almarzooqi, Sahid Maulana, Amirul Bin Ali, Hela Douik, Bashaer Al Jaberi, A. Abdelkerim
The expected profiles of the water produced from the mature ADNOC fields in the coming years imply a 5-fold increase and the OPEX of the produced / injected water will increase considerably. This requires in-situ water separation and reinjection. The objective is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production. The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is high. A new water management tool called downhole separation technology was developed. It separates Oil & Gas from produced water inside the wellbore and injects the produced water into the disposal wells. The Downhole Oil Water Separation Technology is one of the key development strategies that will reduce the handling Produced water, improve the recovery, and minimize field development cost by eliminating surface water treatment and disposal well. The main benefits for DHOWS are to accelerate Oil Offtake, reduce Production Cost, Lower Water Production and Improve facility Utilization. DHOWS require specific criteria to meet the objectives of the well. Multi-disciplined inputs are needed to properly install effective DHOWS, but robust design often brings strong performance. This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates cost effectively while meeting completion requirements and adhering to reservoir management guidelines.
{"title":"Downhole Oil Water Separation to Handle Produced Water Study Case Onshore & Offshore Fields Abu Dhabi","authors":"A. Ladmia, Younes bin Darak Al Blooshi, A. Alobedli, Dragoljub Zivanov, M. Kuliyev, Eric Deblais, Manal Al Beshr, Ahmed Al Shmakhy, Fouad Abdullsalam, Amer El Bekshy, M. Almarzooqi, Sahid Maulana, Amirul Bin Ali, Hela Douik, Bashaer Al Jaberi, A. Abdelkerim","doi":"10.2118/205996-ms","DOIUrl":"https://doi.org/10.2118/205996-ms","url":null,"abstract":"\u0000 The expected profiles of the water produced from the mature ADNOC fields in the coming years imply a 5-fold increase and the OPEX of the produced / injected water will increase considerably. This requires in-situ water separation and reinjection. The objective is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production.\u0000 The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is high. A new water management tool called downhole separation technology was developed. It separates Oil & Gas from produced water inside the wellbore and injects the produced water into the disposal wells. The Downhole Oil Water Separation Technology is one of the key development strategies that will reduce the handling Produced water, improve the recovery, and minimize field development cost by eliminating surface water treatment and disposal well. The main benefits for DHOWS are to accelerate Oil Offtake, reduce Production Cost, Lower Water Production and Improve facility Utilization. DHOWS require specific criteria to meet the objectives of the well. Multi-disciplined inputs are needed to properly install effective DHOWS, but robust design often brings strong performance. This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates cost effectively while meeting completion requirements and adhering to reservoir management guidelines.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89948223","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}
Philipp Brednev, M. Elesin, Yuriy S. Berezovskiy, D. Metelkin, G. Volkov, M. Firsin, I. Mukminov
This article deals with the issues related to development of petroleum resources of Western Siberia and looks at one of the most promising development targets – reservoirs of the Achimov Formation. In particular, it discusses geological features of the Achimov rocks, and the difficulties faced by oil companies in development of the Achimov reservoirs due to their low economic viability if traditional approaches to well construction are applied. To make development of such reservoirs economical, new and non-trivial solutions need to be looked for. One of the most promising of them is considered to be multi-hole wells the construction of which allows oil companies to improve the Capex to cumulative production ratio. At the pre-FEED stage the project, geological, hydrodynamic and geomechanical models of the reservoir were built, the most efficient borehole parameters and trajectories were defined, and the optimal hydraulic frac design, number of stages and parameters were selected. The article describes specifics of the work carried out when preparing for pilot tests of the technology, such as:requirements for defining the well profile and selecting the optimal lifting capacity of the drilling rig,selection of a suitable complexity level for the double-hole well design among those considered which meets the drilling requirements,performance of bench tests to confirm operability of the TAML-3 equipment. Further, the article describes results of drilling, completing and commissioning the first double-hole well at the Vyngayakhskoye field, discusses the issues faced when using the completion equipment at the TAML-3 level, and the lessons learned from this project. It also presents results of putting the double-hole well on-stream and compares its production characteristics with those of single-hole horizontal wells drilled within the same well cluster. The experience gained has shown that building the discussed type of wells is technically feasible, and there is a wide potential for improving efficiency of this work through respective organizational and technical measures. The conclusion to this article describes Gazprom Neft long-term plans to build several new wells of this design, and the technology development options such as increasing the length of horizontal segments for both holes and using high-rate multi-stage hydraulic fracturing.
{"title":"The Experience of Drilling TAML-3 Well with Mutistage Fracturing on the Low Permeability Deposits of the West Siberia","authors":"Philipp Brednev, M. Elesin, Yuriy S. Berezovskiy, D. Metelkin, G. Volkov, M. Firsin, I. Mukminov","doi":"10.2118/205905-ms","DOIUrl":"https://doi.org/10.2118/205905-ms","url":null,"abstract":"\u0000 This article deals with the issues related to development of petroleum resources of Western Siberia and looks at one of the most promising development targets – reservoirs of the Achimov Formation. In particular, it discusses geological features of the Achimov rocks, and the difficulties faced by oil companies in development of the Achimov reservoirs due to their low economic viability if traditional approaches to well construction are applied. To make development of such reservoirs economical, new and non-trivial solutions need to be looked for. One of the most promising of them is considered to be multi-hole wells the construction of which allows oil companies to improve the Capex to cumulative production ratio. At the pre-FEED stage the project, geological, hydrodynamic and geomechanical models of the reservoir were built, the most efficient borehole parameters and trajectories were defined, and the optimal hydraulic frac design, number of stages and parameters were selected.\u0000 The article describes specifics of the work carried out when preparing for pilot tests of the technology, such as:requirements for defining the well profile and selecting the optimal lifting capacity of the drilling rig,selection of a suitable complexity level for the double-hole well design among those considered which meets the drilling requirements,performance of bench tests to confirm operability of the TAML-3 equipment.\u0000 Further, the article describes results of drilling, completing and commissioning the first double-hole well at the Vyngayakhskoye field, discusses the issues faced when using the completion equipment at the TAML-3 level, and the lessons learned from this project. It also presents results of putting the double-hole well on-stream and compares its production characteristics with those of single-hole horizontal wells drilled within the same well cluster.\u0000 The experience gained has shown that building the discussed type of wells is technically feasible, and there is a wide potential for improving efficiency of this work through respective organizational and technical measures.\u0000 The conclusion to this article describes Gazprom Neft long-term plans to build several new wells of this design, and the technology development options such as increasing the length of horizontal segments for both holes and using high-rate multi-stage hydraulic fracturing.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90211172","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}
Ultrasonic imaging based tools have been used for long for delivering high-resolution, comprehensive real-time confirmation of the pipe-to-cement bond quality and downhole pipe condition. However, for comprehensive analysis of cement barriers in challenging scenarios like lightweight cement and for better distinction between different annular materials downhole, a multi-physics evaluation has been developed which combines the measurements taken in thickness-mode with measurements taken in flexural-mode of the casing. Signals from these independent measurements are then processed to provide robust interpretation of solid-liquid-gas behind casing using acquired flexural attenuation and acoustic impedance data. The information provided by the flexural attenuation is related to the state of the material in contact with the casing and does not probe deeper into the cement sheath. However, the pulse radiated by the flexural wave packet into the annulus may be reflected by the third interface, the interface with the formation or outer casing. The inner casing is fairly transparent to this reflected pulse so that it can also be picked by the receivers with significant amplitude. Since this reflected pulse propagate through the thickness of the annulus layer it may bring valuable information about the annulus geometry and material, and about the formation or outer casing geometry. This paper demonstrates third interface echo principles and showcases several case studies for evaluating the outer casing geometry, annular material characterization, casing cut and pull depth suggestion and determining open hole size.
{"title":"Demystifying Openhole and Outer Casing Geometry and Annulus Material Characterization with Third Interface Echo TIE Response","authors":"Apoorva Kumar, Gaurav Agrawal, Kamaljeet Singh, Nitesh Kumar, Shaktim Dutta","doi":"10.2118/206323-ms","DOIUrl":"https://doi.org/10.2118/206323-ms","url":null,"abstract":"\u0000 Ultrasonic imaging based tools have been used for long for delivering high-resolution, comprehensive real-time confirmation of the pipe-to-cement bond quality and downhole pipe condition. However, for comprehensive analysis of cement barriers in challenging scenarios like lightweight cement and for better distinction between different annular materials downhole, a multi-physics evaluation has been developed which combines the measurements taken in thickness-mode with measurements taken in flexural-mode of the casing. Signals from these independent measurements are then processed to provide robust interpretation of solid-liquid-gas behind casing using acquired flexural attenuation and acoustic impedance data.\u0000 The information provided by the flexural attenuation is related to the state of the material in contact with the casing and does not probe deeper into the cement sheath. However, the pulse radiated by the flexural wave packet into the annulus may be reflected by the third interface, the interface with the formation or outer casing. The inner casing is fairly transparent to this reflected pulse so that it can also be picked by the receivers with significant amplitude. Since this reflected pulse propagate through the thickness of the annulus layer it may bring valuable information about the annulus geometry and material, and about the formation or outer casing geometry.\u0000 This paper demonstrates third interface echo principles and showcases several case studies for evaluating the outer casing geometry, annular material characterization, casing cut and pull depth suggestion and determining open hole size.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89827250","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}
Transverse relaxation (T2) times measured by multi-frequency, multi-gradient nuclear magnetic resonance (NMR) logging tools are affected by diffusion-induced enhanced relaxation which reduces the sensitivity to pore size in slow-relaxing formations such as macroporous carbonates and complicates the integration with zero-gradient core NMR data. We propose a solution for eliminating the diffusion-related uncertainties using intrinsic T2 distributions, obtained by a new inversion-forward modeling-inversion (IFMI) method, for carbonate pore typing applications. The NMR logs presented in this paper are based on data measured at five frequencies where the static magnetic field gradient varies from 26 to 55 G/cm. The high-quality echo signals are processed using a three-step IFMI differential signal analysis approach which nullifies diffusion effects due to the tool gradient and the potentially present internal gradient caused by paramagnetic minerals in the formation. The resulting diffusion-free intrinsic T2 distribution accentuates fine pore size variations and allows better discernment of micro-, meso-, and macropore systems of complex carbonate reservoirs. Multi-frequency NMR data, acquired in multiple wells, were processed and analyzed in several ways. First, apparent T2 distributions were obtained separately for individual frequencies. Discrepancies between the results of different frequencies clearly indicated that in macro- and mesoporous carbonates the diffusion effect is significant even with TE=0.3ms. This leads a peak broadening observed in the apparent T2 spectrum from conventional NMR processing, where echo trains from different frequencies are averaged in time-domain prior to the inversion. With the IFMI processing, individual-frequency echo trains are first pre-processed using a 2D NMR inversion whose results are used to forward model a diffusion-free echo train without prior assumptions on reservoir fluid diffusivity D. A second inversion, applied on the diffusion-free echo train, yields the intrinsic T2 distribution. The intrinsic T2 distribution has a noticeably higher spectral resolution in carbonate formations where diffusion effect is significant. The intrinsic T2 logs are expected to be more consistent with other gradient-free NMR measurements such as core NMR or LWD NMR data sets.
{"title":"Eliminating Diffusion Effects from NMR Logging Data for Enhanced Carbonate Pore Typing","authors":"G. Hursán, Wei Shao, R. Balliet, Yasir Farooq","doi":"10.2118/206233-ms","DOIUrl":"https://doi.org/10.2118/206233-ms","url":null,"abstract":"\u0000 Transverse relaxation (T2) times measured by multi-frequency, multi-gradient nuclear magnetic resonance (NMR) logging tools are affected by diffusion-induced enhanced relaxation which reduces the sensitivity to pore size in slow-relaxing formations such as macroporous carbonates and complicates the integration with zero-gradient core NMR data. We propose a solution for eliminating the diffusion-related uncertainties using intrinsic T2 distributions, obtained by a new inversion-forward modeling-inversion (IFMI) method, for carbonate pore typing applications.\u0000 The NMR logs presented in this paper are based on data measured at five frequencies where the static magnetic field gradient varies from 26 to 55 G/cm. The high-quality echo signals are processed using a three-step IFMI differential signal analysis approach which nullifies diffusion effects due to the tool gradient and the potentially present internal gradient caused by paramagnetic minerals in the formation. The resulting diffusion-free intrinsic T2 distribution accentuates fine pore size variations and allows better discernment of micro-, meso-, and macropore systems of complex carbonate reservoirs.\u0000 Multi-frequency NMR data, acquired in multiple wells, were processed and analyzed in several ways. First, apparent T2 distributions were obtained separately for individual frequencies. Discrepancies between the results of different frequencies clearly indicated that in macro- and mesoporous carbonates the diffusion effect is significant even with TE=0.3ms. This leads a peak broadening observed in the apparent T2 spectrum from conventional NMR processing, where echo trains from different frequencies are averaged in time-domain prior to the inversion. With the IFMI processing, individual-frequency echo trains are first pre-processed using a 2D NMR inversion whose results are used to forward model a diffusion-free echo train without prior assumptions on reservoir fluid diffusivity D. A second inversion, applied on the diffusion-free echo train, yields the intrinsic T2 distribution. The intrinsic T2 distribution has a noticeably higher spectral resolution in carbonate formations where diffusion effect is significant. The intrinsic T2 logs are expected to be more consistent with other gradient-free NMR measurements such as core NMR or LWD NMR data sets.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79460844","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}
During perforating operations, identifying the orientation of fiber cable accurately is critical for maintaining the integrity of permanently installed fiber.Beyond completions,it alsoprovides insights into how the casings get twisted and how the mechanical stability of the casing is altered as the string is run in the hole. The drilling and completion system is as unique as the aspect ratio and length/diameter is very high. This puzzles the researchers in modeling forces, stresses, stretch, and twists. To aid the accurate prediction in the position of the casing, radial orientation of downhole fiber optic cables canbe used. The clear images obtained by mapping the equipmentoutside thecasing provides not only how the casings get twisted after running in but also provide improved risk mitigation for perforating operations.The orientation angle of the casing versus depthis then analyzed to get the finaltwist and pitch of the twist of the casing. Several wells datawere analyzed to get a comprehensive view of the casingtwist as the casings were run and versus the model prediction. The raw data obtained using the pulsed-eddy current time-domain decay at each station are used for the analysis. Each installed cable detection clamp (CDC) is placed above a casing centralizer located 2' above each joint of casing that had a clamp installed.This simplifies the process of locating the depth of each CDC. A casing collar locator easily identifies the casingjoints.Further, the data are used to find the casing rotation. Several wells showed normal casing rotation of 2–3 wraps along the lateral and onewell showed more than 12 wraps. Several reasons were considered and analyzed including the wellbore spiraling, borehole torsion,and additional mechanical forces applied duringrunning the casing. The coupling of the geometrical and mechanical twist and mechanical stability of the string are discussed in the paper withmathematical underpinnings. In thecase of abnormal prediction, additional mechanical forcesandgeometrical considerations were overlapped and comparedagainst the torque and drag model prediction.It has also beenfound that in some wells where the wellbore torsion washigh,it resulted in a complete twist of 360° atthe heel and in some cases negative trend.
{"title":"Casing Twist Insight Through Fiber Cable","authors":"Robello Samuel, Stuart Wood, G. Olin","doi":"10.2118/206201-ms","DOIUrl":"https://doi.org/10.2118/206201-ms","url":null,"abstract":"\u0000 During perforating operations, identifying the orientation of fiber cable accurately is critical for maintaining the integrity of permanently installed fiber.Beyond completions,it alsoprovides insights into how the casings get twisted and how the mechanical stability of the casing is altered as the string is run in the hole. The drilling and completion system is as unique as the aspect ratio and length/diameter is very high. This puzzles the researchers in modeling forces, stresses, stretch, and twists.\u0000 To aid the accurate prediction in the position of the casing, radial orientation of downhole fiber optic cables canbe used. The clear images obtained by mapping the equipmentoutside thecasing provides not only how the casings get twisted after running in but also provide improved risk mitigation for perforating operations.The orientation angle of the casing versus depthis then analyzed to get the finaltwist and pitch of the twist of the casing. Several wells datawere analyzed to get a comprehensive view of the casingtwist as the casings were run and versus the model prediction.\u0000 The raw data obtained using the pulsed-eddy current time-domain decay at each station are used for the analysis. Each installed cable detection clamp (CDC) is placed above a casing centralizer located 2' above each joint of casing that had a clamp installed.This simplifies the process of locating the depth of each CDC. A casing collar locator easily identifies the casingjoints.Further, the data are used to find the casing rotation. Several wells showed normal casing rotation of 2–3 wraps along the lateral and onewell showed more than 12 wraps. Several reasons were considered and analyzed including the wellbore spiraling, borehole torsion,and additional mechanical forces applied duringrunning the casing. The coupling of the geometrical and mechanical twist and mechanical stability of the string are discussed in the paper withmathematical underpinnings. In thecase of abnormal prediction, additional mechanical forcesandgeometrical considerations were overlapped and comparedagainst the torque and drag model prediction.It has also beenfound that in some wells where the wellbore torsion washigh,it resulted in a complete twist of 360° atthe heel and in some cases negative trend.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85043051","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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