Digital well construction tools are becoming more widely considered today for well design planning, enabling automated engineering and simultaneous team collaboration under a single solution. This paper shows the results of using a digital well construction planning solution during a project’s conceptual planning stage. This method shortens the time needed to estimate the well times and risk profile for a drilling campaign by applying smart engines to quickly and accurately perform critical offset analysis for defined well types that is required for project sanction. With this solution, the Offset Well Analysis (OWA) process is done automatically based on the location of the planned well, trajectory and well architecture. Various information and reports (both subsurface and surface data) from neighboring wells is stored in cloud solutions, enabling ease of access and data reliability for both large or smaller scale data storage. The software selects the most relevant offset wells, displays the risk analysis and generates the stick chart. For a conceptual design, the risk levels can be manually set higher due to potential unknowns in surface and subsurface risks which can later be refined. Quick validation of the well design allows the engineer to design a conceptual drilling campaign quickly and more efficiently. The solution minimizes the time to perform probabilistic time and risk estimations. It reduces the risk of biased decision making due to manual input and design. This allows for better-informed decisions on project feasibility, alignment of stakeholders, increased design reliability as well as reducing the amount of time and resources invested in OWA. The work presented here is aimed at sharing the experience of applying a digital well construction planning solution specifically on the conceptual project stage and discuss the value it adds to the well design process.
{"title":"Application of Digital Well Construction Planning Tool During Well Conceptualization Phase","authors":"Costeno Hugo, Kandasamy Rajeswary, Telles Jose, Camacho Jacob, Medina Diego, Gori Freddy, Garcia Hector, Vilchez Omar","doi":"10.2118/206248-ms","DOIUrl":"https://doi.org/10.2118/206248-ms","url":null,"abstract":"\u0000 Digital well construction tools are becoming more widely considered today for well design planning, enabling automated engineering and simultaneous team collaboration under a single solution. This paper shows the results of using a digital well construction planning solution during a project’s conceptual planning stage. This method shortens the time needed to estimate the well times and risk profile for a drilling campaign by applying smart engines to quickly and accurately perform critical offset analysis for defined well types that is required for project sanction.\u0000 With this solution, the Offset Well Analysis (OWA) process is done automatically based on the location of the planned well, trajectory and well architecture. Various information and reports (both subsurface and surface data) from neighboring wells is stored in cloud solutions, enabling ease of access and data reliability for both large or smaller scale data storage. The software selects the most relevant offset wells, displays the risk analysis and generates the stick chart. For a conceptual design, the risk levels can be manually set higher due to potential unknowns in surface and subsurface risks which can later be refined. Quick validation of the well design allows the engineer to design a conceptual drilling campaign quickly and more efficiently.\u0000 The solution minimizes the time to perform probabilistic time and risk estimations. It reduces the risk of biased decision making due to manual input and design. This allows for better-informed decisions on project feasibility, alignment of stakeholders, increased design reliability as well as reducing the amount of time and resources invested in OWA.\u0000 The work presented here is aimed at sharing the experience of applying a digital well construction planning solution specifically on the conceptual project stage and discuss the value it adds to the well design process.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73085663","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}
Mauricio Sotomayor, Hassan J. Alshaer, Xiongyu Chen, Krishna K. Panthi, M. Balhoff, K. Mohanty
Harsh conditions, such as high temperature (>100 oC) and high salinity (>50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.
{"title":"Surfactant-Polymer Formulations for EOR in High Temperature High Salinity Carbonate Reservoirs","authors":"Mauricio Sotomayor, Hassan J. Alshaer, Xiongyu Chen, Krishna K. Panthi, M. Balhoff, K. Mohanty","doi":"10.2118/206321-ms","DOIUrl":"https://doi.org/10.2118/206321-ms","url":null,"abstract":"\u0000 Harsh conditions, such as high temperature (>100 oC) and high salinity (>50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"111 3S 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75774427","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. Jenkins, Santosh Gopi, J. Hoshowski, Warinthon Lertpornsuksawat, Jennifer Jackson, Thomas Wilson
The presence of hydrogen sulfide (H2S) gas occurs naturally, or can be introduced via bacteria contamination, in oil and gas reservoirs worldwide. There are several options for the removal of H2S from produced oil and gas ranging from fixed assets that scrub H2S to chemical injection at the wellsite. The area of interest for many operators is in the continuous application of non-reversible chemical H2S scavengers as an easy, reliable and cost-effective solution. The majority of the non-reversible chemical H2S scavenger market is based on triazine technology derived from the reaction products of formaldehyde and amines. In recent past, there has been an active industry wide search to improve the overall performance of H2S scavengers. Major topics for improvement include: Increased H2S scavenging capacityReduction of nitrogen contamination of crude oilReduction of scale formationElimination of by-product depositionAddressing existing environmental, health and safety concernsMinimization of products/reaction by-products disposal Conversely, some of the biggest hurdles with new H2S scavengers are ensuring fast kinetic reaction rates, system compatibility, consumption rates, minimal precipitation of scavenger/by-products, scalable manufacturing and competitive economics. Many new products have been proposed by chemical manufactures but often are not able to deliver enough benefits to warrant a change from the industry standard triazine. One potential solution is to pull through a technology from a different industry that already has established production, in significant volumes, for use in oilfield applications. Ideally, the new product would offer better performance versus the incumbent, a reduction in nitrogen content and minimize solids formation and deposition. A product identified several years ago as a potential replacement was an oxazolidine derivative referred to as MBO (3,3’-methylenebis(5-methyloxazolidine)). However, MBO has had limited application in the field until recently. MBO offers some of the same benefits as triazine but outperforms the incumbent technology by increasing the consumption of H2S per mole of scavenger, reducing the nitrogen content in crude oil, reducing the by-product deposition potential. Moreover, MBO is already produced in large manufacturing quantities. In this paper we will discuss details about the chemistry and increased formaldehyde content, laboratory results related to performance, system compatibilities, decreased transportation cost and confirmation of field application on large scale that supports the usage of this alternative H2S scavenger to standard triazine. H2S scavengers are used to mitigate the risks presented by H2S. They react with H2S in the liquid phase to form non-hazardous, non-reactive species that are often water soluble and thus disposed with water. Monoethanolamine (MEA) triazine (hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine) is the most widely used scavenger. It is less toxic than mo
{"title":"Application of a New H2S Scavenger with Improved Performance in The Field","authors":"A. Jenkins, Santosh Gopi, J. Hoshowski, Warinthon Lertpornsuksawat, Jennifer Jackson, Thomas Wilson","doi":"10.2118/206057-ms","DOIUrl":"https://doi.org/10.2118/206057-ms","url":null,"abstract":"The presence of hydrogen sulfide (H2S) gas occurs naturally, or can be introduced via bacteria contamination, in oil and gas reservoirs worldwide. There are several options for the removal of H2S from produced oil and gas ranging from fixed assets that scrub H2S to chemical injection at the wellsite. The area of interest for many operators is in the continuous application of non-reversible chemical H2S scavengers as an easy, reliable and cost-effective solution. The majority of the non-reversible chemical H2S scavenger market is based on triazine technology derived from the reaction products of formaldehyde and amines. In recent past, there has been an active industry wide search to improve the overall performance of H2S scavengers. Major topics for improvement include: Increased H2S scavenging capacityReduction of nitrogen contamination of crude oilReduction of scale formationElimination of by-product depositionAddressing existing environmental, health and safety concernsMinimization of products/reaction by-products disposal\u0000 Conversely, some of the biggest hurdles with new H2S scavengers are ensuring fast kinetic reaction rates, system compatibility, consumption rates, minimal precipitation of scavenger/by-products, scalable manufacturing and competitive economics. Many new products have been proposed by chemical manufactures but often are not able to deliver enough benefits to warrant a change from the industry standard triazine. One potential solution is to pull through a technology from a different industry that already has established production, in significant volumes, for use in oilfield applications. Ideally, the new product would offer better performance versus the incumbent, a reduction in nitrogen content and minimize solids formation and deposition. A product identified several years ago as a potential replacement was an oxazolidine derivative referred to as MBO (3,3’-methylenebis(5-methyloxazolidine)). However, MBO has had limited application in the field until recently. MBO offers some of the same benefits as triazine but outperforms the incumbent technology by increasing the consumption of H2S per mole of scavenger, reducing the nitrogen content in crude oil, reducing the by-product deposition potential. Moreover, MBO is already produced in large manufacturing quantities. In this paper we will discuss details about the chemistry and increased formaldehyde content, laboratory results related to performance, system compatibilities, decreased transportation cost and confirmation of field application on large scale that supports the usage of this alternative H2S scavenger to standard triazine.\u0000 H2S scavengers are used to mitigate the risks presented by H2S. They react with H2S in the liquid phase to form non-hazardous, non-reactive species that are often water soluble and thus disposed with water. Monoethanolamine (MEA) triazine (hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine) is the most widely used scavenger. It is less toxic than mo","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79318274","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}
Jhon Robert Ortiz Requena, Maryvi Martinez, Fatma AlShehhi, Fareed Ahmad Daudpota, A. Fawzy
X Field located in the United Arab Emirates has been developed since 1970's by waterflooding as secondary recovery strategy. As water front advances into oil bank, the well operation practice commonly adopted in many fields for oil wells cutting water has consisted in reducing choke aperture in an attempt to control the water cut trend. However, in wells producing moderate to high water cut, this practice has proven to generate excess water settling in the bottom of the wellbore leading to premature inactivation of the wells. The reservoir Z in the north of X Field, is a black oil block operated by peripheral and pattern waterflooding. The production wells have been operating by natural lifting since first oil and will continue in natural flow until the Artificial Lift projects are commissioned within a few years. Meanwhile, the field production plateau has been increased arising challenges of production sustainability due to higher risk of acceleration of water breakthrough and consequently higher number of wells becoming inactive earlier. This led to re-assess the Well and Reservoir management strategy to define improved practices oriented to maximize the natural life cycle of wet wells and ensure the compliance of the field production quota. As a result, a new well management approach was devised and adopted to identify and optimize at the earliest stage, wells potentially affected by water loading mismanage. Conceptually, this new practice consisted in comprehensively analyzing well operating conditions, which ultimately generated a flow operating window that improved the multiphase flow performance in wellbores, minimized water slippage avoiding it to settle down and its associated problems, whilst respecting the compliance of technical guidelines for optimum reservoir management. Based on observations and data gathered from portable testing jobs, saturation logs, PLT and production monitoring; a methodology referred in this work as Critical Flow Analysis, has been successfully implemented in several naturally flowing wells with water cuts ranging from 15 – 40 % in Reservoir Z in X Field, which resulted in prolonged natural life, extra oil recovered, and avoided the negative impact of inactive string count on the Field Management KPI. The Critical Flow analysis has been a comprehensive well management evaluation and operation philosophy in Reservoir Z which helped to manage more efficiently and in cost-saving fashion the performance of oil wells located in high risk areas, in addition to contribute with stablishing best practices for well and reservoir management that could be extended to analog fields in the area.
{"title":"Improving Well and Reservoir Management Practice Through New Flow Control Philosophy that Prolongs the Life of Production Wells Affected by Water Breakthrough in A Giant Carbonate Oil Field, Abu Dhabi, United Arab Emirates","authors":"Jhon Robert Ortiz Requena, Maryvi Martinez, Fatma AlShehhi, Fareed Ahmad Daudpota, A. Fawzy","doi":"10.2118/205978-ms","DOIUrl":"https://doi.org/10.2118/205978-ms","url":null,"abstract":"\u0000 X Field located in the United Arab Emirates has been developed since 1970's by waterflooding as secondary recovery strategy. As water front advances into oil bank, the well operation practice commonly adopted in many fields for oil wells cutting water has consisted in reducing choke aperture in an attempt to control the water cut trend. However, in wells producing moderate to high water cut, this practice has proven to generate excess water settling in the bottom of the wellbore leading to premature inactivation of the wells.\u0000 The reservoir Z in the north of X Field, is a black oil block operated by peripheral and pattern waterflooding. The production wells have been operating by natural lifting since first oil and will continue in natural flow until the Artificial Lift projects are commissioned within a few years. Meanwhile, the field production plateau has been increased arising challenges of production sustainability due to higher risk of acceleration of water breakthrough and consequently higher number of wells becoming inactive earlier. This led to re-assess the Well and Reservoir management strategy to define improved practices oriented to maximize the natural life cycle of wet wells and ensure the compliance of the field production quota. As a result, a new well management approach was devised and adopted to identify and optimize at the earliest stage, wells potentially affected by water loading mismanage. Conceptually, this new practice consisted in comprehensively analyzing well operating conditions, which ultimately generated a flow operating window that improved the multiphase flow performance in wellbores, minimized water slippage avoiding it to settle down and its associated problems, whilst respecting the compliance of technical guidelines for optimum reservoir management.\u0000 Based on observations and data gathered from portable testing jobs, saturation logs, PLT and production monitoring; a methodology referred in this work as Critical Flow Analysis, has been successfully implemented in several naturally flowing wells with water cuts ranging from 15 – 40 % in Reservoir Z in X Field, which resulted in prolonged natural life, extra oil recovered, and avoided the negative impact of inactive string count on the Field Management KPI.\u0000 The Critical Flow analysis has been a comprehensive well management evaluation and operation philosophy in Reservoir Z which helped to manage more efficiently and in cost-saving fashion the performance of oil wells located in high risk areas, in addition to contribute with stablishing best practices for well and reservoir management that could be extended to analog fields in the area.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84914862","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}
Managed pressure drilling (MPD) has a reputation for enhancing drilling performance. However, in this study, we use it as a technology for making undrillable wells drillable. In the deepwater of the Mediterranean of Egypt, a gas field has been producing for few years. Water broke through in one well, thus, we must drill a new well to compensate for the reduction in production. Years of production led to pressure depletion, which makes it difficult to drill this well conventionally. In this study, we will discuss the combination of MPD and wellbore strengthening (WS). In addition, we will discuss the challenges we met while drilling and how we tackled them, and the best practices and recommendations for similar applications. The 12¼" × 13½" hole section passed depleted sands, followed by a pressure ramp. First, we drilled the depleted sands and confirmed the pressure ramp top. To strengthen the sand, we spotted a stress-cage pill of 645 bbls with a total concentration of 29 ppb. In addition, we conducted a formation integrity test (FIT), but its value was lower than the required value to drill to the section target depth (TD). Then, we switched to MPD and increased the mud weight. MPD in annular pressure control mode (AP) enabled us to walk the edge as near as possible to the impossible. Drilling this section was challenging due to the narrow mud weight window (MWW). We faced kick-loss cycles, where we had high-gas levels (from 20% to 55%) while drilling with a loss rate from 60 to 255 bph, at the same time. The 8½″ × 9½″ hole section will cover a depleted reservoir. Therefore, we decided to use the MPD to drill this section. To widen the MWW, we decided to stress-caging the hole, as we drill. We loaded the active-mud system with stress-cage materials totaling 39 ppb. We drilled the hole section while keeping the bottom hole pressure (BHP) at 14.6 ppg. We drilled using MPD by maintaining 525-psi surface back pressure (SBP). We used the SBP mode (semi-auto mode) to add connections, resulting in minor background gases and minor losses. This study discusses the application of a novel combination of MPD and WS. It emphasizes how MPD can integrate with other technologies to offer a practical solution to future drilling challenges in deepwater-drilling environments.
{"title":"The Innovative Integration of Wellbore Strengthening and Managed-Pressure Drilling Redraw the Line Between Undrillable and Drillable - Case Study from Offshore Mediterranean Deepwater","authors":"M. El-Husseiny, T. El-Fakharany, S. Khaled","doi":"10.2118/206230-ms","DOIUrl":"https://doi.org/10.2118/206230-ms","url":null,"abstract":"\u0000 Managed pressure drilling (MPD) has a reputation for enhancing drilling performance. However, in this study, we use it as a technology for making undrillable wells drillable.\u0000 In the deepwater of the Mediterranean of Egypt, a gas field has been producing for few years. Water broke through in one well, thus, we must drill a new well to compensate for the reduction in production. Years of production led to pressure depletion, which makes it difficult to drill this well conventionally.\u0000 In this study, we will discuss the combination of MPD and wellbore strengthening (WS). In addition, we will discuss the challenges we met while drilling and how we tackled them, and the best practices and recommendations for similar applications.\u0000 The 12¼\" × 13½\" hole section passed depleted sands, followed by a pressure ramp. First, we drilled the depleted sands and confirmed the pressure ramp top. To strengthen the sand, we spotted a stress-cage pill of 645 bbls with a total concentration of 29 ppb. In addition, we conducted a formation integrity test (FIT), but its value was lower than the required value to drill to the section target depth (TD). Then, we switched to MPD and increased the mud weight. MPD in annular pressure control mode (AP) enabled us to walk the edge as near as possible to the impossible. Drilling this section was challenging due to the narrow mud weight window (MWW). We faced kick-loss cycles, where we had high-gas levels (from 20% to 55%) while drilling with a loss rate from 60 to 255 bph, at the same time.\u0000 The 8½″ × 9½″ hole section will cover a depleted reservoir. Therefore, we decided to use the MPD to drill this section. To widen the MWW, we decided to stress-caging the hole, as we drill. We loaded the active-mud system with stress-cage materials totaling 39 ppb. We drilled the hole section while keeping the bottom hole pressure (BHP) at 14.6 ppg. We drilled using MPD by maintaining 525-psi surface back pressure (SBP). We used the SBP mode (semi-auto mode) to add connections, resulting in minor background gases and minor losses.\u0000 This study discusses the application of a novel combination of MPD and WS. It emphasizes how MPD can integrate with other technologies to offer a practical solution to future drilling challenges in deepwater-drilling environments.","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":"85083372","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}
Since emerging more than a century ago, petroleum engineering (PE) education has increasingly kept its popularity despite significant downturns in the industry. During these downturn periods, observed at least four times since the 1973 oil crisis, structural changes in university programs have been considered. On the other hand, during the "heyday" periods, institutions have had to tackle enormous demand from industry, severely increased enrollments, and reestablish resources to provide a proper service. In light of these observations and while experiencing the fifth downturn period over the last five decades, it is time again to ask the same question: "Shall we continue with the same PE education model or radically shift to a new model?" In this paper, after reviewing more than fifty articles published over the last 85 years reporting the attempts made towards reshaping PE education, an option of restructuring PE programs is discussed. This option is less oil industry (and oil prices) dependent and more of a "general" engineering education program with an emphasis on the "geoscience" or "subsurface" engineering aspects of the PE discipline. Detailed discussions focus on curriculum updates to address the industry practice of "subsurface" related engineering applications. Viability of this option was discussed from industry, academia, and students’ perspective. This restructuring option requires substantial changes to curricula, skill development, and teaching and learning styles. Fundamentals are essential to include in PE education similar to other general (or major) engineering disciplines such as mechanical, civil, chemical, and electrical engineering. The essential elements of engineering skills such as creative design, decision making, problem description and solving, management under high degree of uncertainty, and data collection and processing for optimization are to be included in the new model. Finally, the model proposed is critically discussed and analyzed from different perspectives (industry, academia, and students) considering current and prospected subsurface engineering applications.
{"title":"Reassessment of Petroleum Engineering Education: Is It the End of an Era or a New Start?","authors":"T. Babadagli","doi":"10.2118/205964-ms","DOIUrl":"https://doi.org/10.2118/205964-ms","url":null,"abstract":"\u0000 Since emerging more than a century ago, petroleum engineering (PE) education has increasingly kept its popularity despite significant downturns in the industry. During these downturn periods, observed at least four times since the 1973 oil crisis, structural changes in university programs have been considered. On the other hand, during the \"heyday\" periods, institutions have had to tackle enormous demand from industry, severely increased enrollments, and reestablish resources to provide a proper service. In light of these observations and while experiencing the fifth downturn period over the last five decades, it is time again to ask the same question: \"Shall we continue with the same PE education model or radically shift to a new model?\"\u0000 In this paper, after reviewing more than fifty articles published over the last 85 years reporting the attempts made towards reshaping PE education, an option of restructuring PE programs is discussed. This option is less oil industry (and oil prices) dependent and more of a \"general\" engineering education program with an emphasis on the \"geoscience\" or \"subsurface\" engineering aspects of the PE discipline. Detailed discussions focus on curriculum updates to address the industry practice of \"subsurface\" related engineering applications. Viability of this option was discussed from industry, academia, and students’ perspective.\u0000 This restructuring option requires substantial changes to curricula, skill development, and teaching and learning styles. Fundamentals are essential to include in PE education similar to other general (or major) engineering disciplines such as mechanical, civil, chemical, and electrical engineering. The essential elements of engineering skills such as creative design, decision making, problem description and solving, management under high degree of uncertainty, and data collection and processing for optimization are to be included in the new model. Finally, the model proposed is critically discussed and analyzed from different perspectives (industry, academia, and students) considering current and prospected subsurface engineering applications.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"17 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":"85540678","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}
Abdullatif Al-Majdli, Carlos Caicedo Martinez, Sarah Al-Dughaishem
Oil production in North Kuwait (NK) asset highly relies on artificial lift systems. The predominant method of artificial lift in NK is electrical submersible pump (ESP). Corrosion is one of the major issues for wells equipped with ESP in NK field. Over 20% of the all pulled ESPs in 2019 and 2020 in NK field were due to corrosion of the completion or the ESP string. With an increase in ESP population in NK, a proactive corrosion mitigation is essential to reduce the number of ESP wells requiring workover. Historic data of the pulled ESPs in NK revealed that most of the corrosion cases were found in the tubing as opposed to the ESP components. Although there are multiple factors that can cause corrosion in NK, the driving force was identified to be the presence of CO2 (sweet corrosion). Corrosion rates have been enhanced by other factors such as stray current and galvanic couples. In this paper, multiple methods have been suggested to minimize and prevent the corrosion issue such as selecting the optimal completion and ESP metallurgy (ex. corrosion resistant alloy), installing internally glass reinforced epoxy lined carbon steel tubing, and installing a sacrificial anode whenever applicable.
{"title":"Corrosion Challenges on Electrical Submersible Pump Wells in the North Kuwait Field","authors":"Abdullatif Al-Majdli, Carlos Caicedo Martinez, Sarah Al-Dughaishem","doi":"10.2118/206068-ms","DOIUrl":"https://doi.org/10.2118/206068-ms","url":null,"abstract":"\u0000 Oil production in North Kuwait (NK) asset highly relies on artificial lift systems. The predominant method of artificial lift in NK is electrical submersible pump (ESP). Corrosion is one of the major issues for wells equipped with ESP in NK field. Over 20% of the all pulled ESPs in 2019 and 2020 in NK field were due to corrosion of the completion or the ESP string. With an increase in ESP population in NK, a proactive corrosion mitigation is essential to reduce the number of ESP wells requiring workover. Historic data of the pulled ESPs in NK revealed that most of the corrosion cases were found in the tubing as opposed to the ESP components. Although there are multiple factors that can cause corrosion in NK, the driving force was identified to be the presence of CO2 (sweet corrosion). Corrosion rates have been enhanced by other factors such as stray current and galvanic couples. In this paper, multiple methods have been suggested to minimize and prevent the corrosion issue such as selecting the optimal completion and ESP metallurgy (ex. corrosion resistant alloy), installing internally glass reinforced epoxy lined carbon steel tubing, and installing a sacrificial anode whenever applicable.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81958952","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a method to identify switch time from end of linear flow (telf) to transition or boundary-dominated flow (BDF) by utilizing multiple diagnostic plots including a Modified Fetkovich type curve (Eleiott et al. 2019). In this study, we analyzed publicly available production data to analyze transient linear flow behavior and boundary-dominated flow from multiple unconventional reservoirs. This method applies a log-log plot of rate versus time combined with a log-log plot of rate versus material balance time (MBT). In addition to log-log plots, a specialized plot of rate versus square root of time is used to confirm telf. A plot of MBT versus actual time, t, is provided to convert material balance time to actual time, and vice versa. The Modified Fetkovich type curve is used to estimate decline parameters and reservoir properties. Applications of this method using monthly production data from Bakken and Permian Shale areas are presented in this work. Utilizing public data, our comprehensive review of approximately 800 multi-staged fractured horizontal wells (MFHW) from North American unconventional reservoirs found many of them exhibiting linear flow production characteristics. To identify end of linear flow, a log-log plot of rate versus time alone is not sufficient, especially when a well is not operated in a consistent manner. This paper shows using additional diagnostic plots such as rate versus MBT and specialized plots can assist interpreters to better identify end of linear flow. With the end of linear flow determined for these wells, the interpreter can use the telf to forecast future production and estimate reservoir properties using the modified type curve. These diagnostic plots can be added to existing production analysis tools so that engineers can analyze changes in flow regimes in a timely manner, have better understanding of how to forecast their wells, and reduce the uncertainty in estimated ultimate recoveries related to decline parameters.
本文提出了一种方法，通过利用包括修正Fetkovich型曲线(Eleiott et al. 2019)在内的多个诊断图来识别从线性流(telf)到过渡或边界主导流(BDF)的切换时间。在这项研究中，我们分析了公开可用的生产数据，以分析多个非常规油藏的瞬态线性流动行为和边界主导流动。该方法应用速率与时间的对数-对数图结合速率与物料平衡时间(MBT)的对数-对数图。除了对数-对数图之外，还使用速率与时间平方根的专门图来确认telf。提供了MBT与实际时间的关系图t，用于将物料平衡时间转换为实际时间，反之亦然。采用修正Fetkovich型曲线估计递减参数和储层物性。该方法应用于Bakken和Permian页岩地区的月度生产数据。利用公开数据，我们对来自北美非常规油藏的约800口多级压裂水平井(MFHW)进行了综合评估，发现其中许多井表现出线性流动生产特征。为了确定线性流动的结束，单靠速率与时间的对数-对数图是不够的，特别是当一口井的作业方式不一致时。本文表明，使用额外的诊断图，如比率与MBT和专门的图，可以帮助口译员更好地识别线性流的末端。在确定了这些井的线性流动结束后，解释器可以使用telf预测未来产量，并使用修改后的类型曲线估计储层性质。这些诊断图可以添加到现有的生产分析工具中，以便工程师能够及时分析流动状态的变化，更好地了解如何预测他们的井，并减少与递减参数相关的估计最终采收率的不确定性。
{"title":"Application of Multiple Diagnostic Plots to Identify End of Linear Flow in Unconventional Reservoirs","authors":"H. Pratikno, W. J. Lee, Cesario K. Torres","doi":"10.2118/205906-ms","DOIUrl":"https://doi.org/10.2118/205906-ms","url":null,"abstract":"\u0000 This paper presents a method to identify switch time from end of linear flow (telf) to transition or boundary-dominated flow (BDF) by utilizing multiple diagnostic plots including a Modified Fetkovich type curve (Eleiott et al. 2019). In this study, we analyzed publicly available production data to analyze transient linear flow behavior and boundary-dominated flow from multiple unconventional reservoirs.\u0000 This method applies a log-log plot of rate versus time combined with a log-log plot of rate versus material balance time (MBT). In addition to log-log plots, a specialized plot of rate versus square root of time is used to confirm telf. A plot of MBT versus actual time, t, is provided to convert material balance time to actual time, and vice versa. The Modified Fetkovich type curve is used to estimate decline parameters and reservoir properties. Applications of this method using monthly production data from Bakken and Permian Shale areas are presented in this work.\u0000 Utilizing public data, our comprehensive review of approximately 800 multi-staged fractured horizontal wells (MFHW) from North American unconventional reservoirs found many of them exhibiting linear flow production characteristics. To identify end of linear flow, a log-log plot of rate versus time alone is not sufficient, especially when a well is not operated in a consistent manner. This paper shows using additional diagnostic plots such as rate versus MBT and specialized plots can assist interpreters to better identify end of linear flow. With the end of linear flow determined for these wells, the interpreter can use the telf to forecast future production and estimate reservoir properties using the modified type curve.\u0000 These diagnostic plots can be added to existing production analysis tools so that engineers can analyze changes in flow regimes in a timely manner, have better understanding of how to forecast their wells, and reduce the uncertainty in estimated ultimate recoveries related to decline parameters.","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":"81967277","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}
Yuelin Shen, Sameer Bhoite, Zhengxin Zhang, Wei Chen, Sylvain Chambon, Sameh Ibrahim, David Conn, David L. Smith, Cen Chen, Shadi Mussa
It is common to have measured depth exceeding 20,000 ft for unconventional oil and gas wells. To ensure the pressure pulse can be detected on the surface, many MWD tools have been designed to generate mud pressure pulse with very large amplitude. While the large pressure pulse solved the problem of sending the measured information up to the surface, it creates significant impact on drilling system energy variation and downhole drilling dynamics. This paper focuses on understanding the effects using big data and drilling system modeling. When a commonly used MWD tool generates mud pulse sequence, it chokes the flow path at designed patterns. This creates mud flow variation in the mud motor below the MWD tool. It also generates axial force variations due to pressure changes, which affect WOB. These changes cause the motor and the bit to experience significant rpm variations. The combined rpm variation and WOB variation often excite more severe axial and lateral shock and vibration. These effects are quantified by thousands of high-frequency downhole datasets and advanced numerical modeling. In the high-frequency downhole datasets, some of them are obtained from BHAs with MWD tools generating large mud pressure pulse, and some of them are obtained from BHAs with MWD tools generating smaller mud pressure pulse or transmitting the measurements using electromagnetic signal. Statistics of rpm variation and axial and lateral shock and vibrations are compared. It clearly shows that the BHAs utilizing large mud pressure pulse experience more severe torsional, axial, and lateral vibrations. When looking into specific datasets, it showed that mud pressure pulse could cause the motor to lose more than half of its rpm during the flow choking phase. Typical datasets indicate that mud pressure pulse correlates to severe high-frequency torsional oscillation (HFTO) in motorized rotary steerable BHA. An advanced transient drilling dynamics model was built to simulate the whole drilling system subjecting to mud pressure pulse incurred loading conditions. It was found that large-magnitude mud pressure pulse induced more stick/slip and axial and lateral vibrations as recorded in downhole high-frequency data. The increased rotational, axial, and lateral vibrations correspond to more loading variations in the mud motor components and PDC cutters on the drill bit. These variations could cause accelerated damage to the drill bit and downhole tools. In summary, large mud pressure pulse utilized by some MWD tools introduces significant rpm variation and shock and vibration, which is quantified by big data and further demonstrated by drilling system modeling. The information could help make decisions on BHA design and tool selection to achieve improved drilling performance and reduce the risk of premature tool failure.
{"title":"Understand the Effect of Mud Pulse on Drilling Dynamics Using Big Data and Numerical Modeling","authors":"Yuelin Shen, Sameer Bhoite, Zhengxin Zhang, Wei Chen, Sylvain Chambon, Sameh Ibrahim, David Conn, David L. Smith, Cen Chen, Shadi Mussa","doi":"10.2118/206157-ms","DOIUrl":"https://doi.org/10.2118/206157-ms","url":null,"abstract":"\u0000 It is common to have measured depth exceeding 20,000 ft for unconventional oil and gas wells. To ensure the pressure pulse can be detected on the surface, many MWD tools have been designed to generate mud pressure pulse with very large amplitude. While the large pressure pulse solved the problem of sending the measured information up to the surface, it creates significant impact on drilling system energy variation and downhole drilling dynamics. This paper focuses on understanding the effects using big data and drilling system modeling.\u0000 When a commonly used MWD tool generates mud pulse sequence, it chokes the flow path at designed patterns. This creates mud flow variation in the mud motor below the MWD tool. It also generates axial force variations due to pressure changes, which affect WOB. These changes cause the motor and the bit to experience significant rpm variations. The combined rpm variation and WOB variation often excite more severe axial and lateral shock and vibration. These effects are quantified by thousands of high-frequency downhole datasets and advanced numerical modeling.\u0000 In the high-frequency downhole datasets, some of them are obtained from BHAs with MWD tools generating large mud pressure pulse, and some of them are obtained from BHAs with MWD tools generating smaller mud pressure pulse or transmitting the measurements using electromagnetic signal. Statistics of rpm variation and axial and lateral shock and vibrations are compared. It clearly shows that the BHAs utilizing large mud pressure pulse experience more severe torsional, axial, and lateral vibrations. When looking into specific datasets, it showed that mud pressure pulse could cause the motor to lose more than half of its rpm during the flow choking phase. Typical datasets indicate that mud pressure pulse correlates to severe high-frequency torsional oscillation (HFTO) in motorized rotary steerable BHA. An advanced transient drilling dynamics model was built to simulate the whole drilling system subjecting to mud pressure pulse incurred loading conditions. It was found that large-magnitude mud pressure pulse induced more stick/slip and axial and lateral vibrations as recorded in downhole high-frequency data. The increased rotational, axial, and lateral vibrations correspond to more loading variations in the mud motor components and PDC cutters on the drill bit. These variations could cause accelerated damage to the drill bit and downhole tools.\u0000 In summary, large mud pressure pulse utilized by some MWD tools introduces significant rpm variation and shock and vibration, which is quantified by big data and further demonstrated by drilling system modeling. The information could help make decisions on BHA design and tool selection to achieve improved drilling performance and reduce the risk of premature tool failure.","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":"79660347","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}
Pipe cutting operations are often a critical part of stuck pipe situations, well interventions and plug and abandon operations which all need to remove cut sections of pipe from the well. Unlike traditional ‘blade’ style e-line cutters, which can jam under pipe compression or explosive pipe cutters, which need to dress-over the jagged cut by the rig, a new electric line mechanical cutter's unique design enables performance even if the pipe is under compression, in tension or is neutral. It can also perform multiple cuts in the same run, while creating a clean and machined cut with tool-entry friendly shape. This paper will describe the technology of the new generation cutter, present two case histories; one of multiple cuts of stuck drill pipe, per each run in hole, from Germany and one of a critical tubing cut from a subsea well in Nigeria, using electric wireline and tractor conveyed services for many tasks traditionally performed with coiled tubing in highly deviated wells. These "light vs heavy" solutions can often be done off-line from the rig.
{"title":"Well Cutting Without Explosives with Multiple Cuts on a Single Run","authors":"H. Ghannam, H. Mourani, B. Schwanitz","doi":"10.2118/206158-ms","DOIUrl":"https://doi.org/10.2118/206158-ms","url":null,"abstract":"\u0000 Pipe cutting operations are often a critical part of stuck pipe situations, well interventions and plug and abandon operations which all need to remove cut sections of pipe from the well. Unlike traditional ‘blade’ style e-line cutters, which can jam under pipe compression or explosive pipe cutters, which need to dress-over the jagged cut by the rig, a new electric line mechanical cutter's unique design enables performance even if the pipe is under compression, in tension or is neutral. It can also perform multiple cuts in the same run, while creating a clean and machined cut with tool-entry friendly shape.\u0000 This paper will describe the technology of the new generation cutter, present two case histories; one of multiple cuts of stuck drill pipe, per each run in hole, from Germany and one of a critical tubing cut from a subsea well in Nigeria, using electric wireline and tractor conveyed services for many tasks traditionally performed with coiled tubing in highly deviated wells. These \"light vs heavy\" solutions can often be done off-line from the rig.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"145 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80448640","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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