High-quality images from an LWD ultrasonic imaging tool are used to identify natural and induced fractures and optimize hydraulic fracturing practices in wells drilled with oil-based mud. A newly designed LWD ultrasonic imager was developed due to the high demand for acquiring high-quality wellbore images in oil-based mud environments where traditional resistivity tools usually do not provide the desired detailed. Characterization of natural and induced fractures, and wellbore geometry are used to identify and characterize formation characteristics just hours after the well reaches TD. This enables the timely detection of fracture dominated zones enabling optimization of the ongoing hydraulic fracturing operations. The ultrasonic imager provides 360-degree measurements of travel time and amplitude around the wellbore, taking advantage of the rotation of the drill string; the travel time measurements are used to provide a high-resolution caliper and the amplitude is used to detect formation features such as bedding planes, fractures and borehole breakouts. The image acquisition while drilling in high rate-of-penetration (ROP) and high revolutions per minute (RPM) scenarios allows the downhole logging sensor to acquire azimuthal data in a cost-efficient scenario which does not require additional rig downtime after the well is drilled. The characterization of the natural fracture network and induced fractures helps to better assess their potential interaction with hydraulic fractures and thus allowing the implementation of hydraulic fracturing practices that allow porosity and permeability enhancement in virgin areas of the field. The application of unique LWD technology which allow for timely reservoir characterization to further enhance completions optimization provides reservoir productivity enhancement without affecting drilling operations in unconventional shale reservoirs.
{"title":"Characterizing Fractures to Improve Hydraulic Fracturing Efficiency in Shale Reservoirs Through use of an LWD Ultrasonic Imager Designed for Oil-Based Mud Environments","authors":"C. Amorocho, C. Langford","doi":"10.2523/iptc-19845-ms","DOIUrl":"https://doi.org/10.2523/iptc-19845-ms","url":null,"abstract":"\u0000 High-quality images from an LWD ultrasonic imaging tool are used to identify natural and induced fractures and optimize hydraulic fracturing practices in wells drilled with oil-based mud.\u0000 A newly designed LWD ultrasonic imager was developed due to the high demand for acquiring high-quality wellbore images in oil-based mud environments where traditional resistivity tools usually do not provide the desired detailed. Characterization of natural and induced fractures, and wellbore geometry are used to identify and characterize formation characteristics just hours after the well reaches TD. This enables the timely detection of fracture dominated zones enabling optimization of the ongoing hydraulic fracturing operations.\u0000 The ultrasonic imager provides 360-degree measurements of travel time and amplitude around the wellbore, taking advantage of the rotation of the drill string; the travel time measurements are used to provide a high-resolution caliper and the amplitude is used to detect formation features such as bedding planes, fractures and borehole breakouts.\u0000 The image acquisition while drilling in high rate-of-penetration (ROP) and high revolutions per minute (RPM) scenarios allows the downhole logging sensor to acquire azimuthal data in a cost-efficient scenario which does not require additional rig downtime after the well is drilled. The characterization of the natural fracture network and induced fractures helps to better assess their potential interaction with hydraulic fractures and thus allowing the implementation of hydraulic fracturing practices that allow porosity and permeability enhancement in virgin areas of the field.\u0000 The application of unique LWD technology which allow for timely reservoir characterization to further enhance completions optimization provides reservoir productivity enhancement without affecting drilling operations in unconventional shale reservoirs.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124292735","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}
Viscoelastic surfactant (VES) gels are used for well stimulation. Breakers such as ethylene glycol mono butyl ether, are compounds that reduce viscosity of VES gels, and are required after the stimulation job to prevent formation damage. The focus here was to delineate the steps involved in the breaking of a VES gel in the presence of model oils. It also aimed to determine the effect of increasing aliphatic chain length on the gel breaking rate. A sulfobetaine VES (40 g/L) was mixed with calcium chloride (600 mM) and three model oils (280 mM) in water. The model oils were n-decane, n-dodecane, and n-hexadecane. The complex viscosity (frequency-dependent viscosity) with time was measured for at most 24 hours at 10 rad.s-1 and strain of 2 % using a rheometer. The rheological experiments were conducted at 50 °C. The viscosity of the VES/oil mixtures increased with time and reached a maximum. The magnitude of the maximum viscosity was dependent on the oil. In the presence of n-decane and n-dodecane, the maximum viscosity steadily dropped for a few minutes before a sharp drop occurred. The drop continued until the viscosity was close to 1 cp. Meanwhile, n-hexadecane increased the viscosity and steadily dropped for 24 hours. The complex viscosity after 24 hours was > 150 cp. The time it took for the gel to break depended on the type of oil. The breakage time increased in the following order: n-decane
{"title":"Kinetics of Breaking of a Sulfobetaine Viscoelastic Surfactant Gel in the Presence of Model Oils","authors":"L. T. Fogang, T. Sølling, M. Kamal, A. Sultan","doi":"10.2523/iptc-19925-ms","DOIUrl":"https://doi.org/10.2523/iptc-19925-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Viscoelastic surfactant (VES) gels are used for well stimulation. Breakers such as ethylene glycol mono butyl ether, are compounds that reduce viscosity of VES gels, and are required after the stimulation job to prevent formation damage. The focus here was to delineate the steps involved in the breaking of a VES gel in the presence of model oils. It also aimed to determine the effect of increasing aliphatic chain length on the gel breaking rate.\u0000 \u0000 \u0000 \u0000 A sulfobetaine VES (40 g/L) was mixed with calcium chloride (600 mM) and three model oils (280 mM) in water. The model oils were n-decane, n-dodecane, and n-hexadecane. The complex viscosity (frequency-dependent viscosity) with time was measured for at most 24 hours at 10 rad.s-1 and strain of 2 % using a rheometer. The rheological experiments were conducted at 50 °C.\u0000 \u0000 \u0000 \u0000 The viscosity of the VES/oil mixtures increased with time and reached a maximum. The magnitude of the maximum viscosity was dependent on the oil. In the presence of n-decane and n-dodecane, the maximum viscosity steadily dropped for a few minutes before a sharp drop occurred. The drop continued until the viscosity was close to 1 cp. Meanwhile, n-hexadecane increased the viscosity and steadily dropped for 24 hours. The complex viscosity after 24 hours was > 150 cp. The time it took for the gel to break depended on the type of oil. The breakage time increased in the following order: n-decane<n-dodecane<n-hexadecane.\u0000 \u0000 \u0000 \u0000 The paper advances understanding of how VES used for well stimulation in carbonate reservoirs are being broken. The study will facilitate the design of well stimulation jobs that require VES and breakers by providing information on what kind of oils are required for the job, and how much time required for the VES solution to turn into a gel and then break.\u0000","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116749854","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}
Molecular diamonds, known as diamondoids are naturally occurring hydrocarbon compounds found in crude-oil and rock extracts. Diamondoids feature unique thermal stability owing to the carbon cage-like backbone structures. Therefore, unlike classical geochemical compounds, diamondoids provide a robust molecular-marker for fingerprinting hydrocarbon fluids and assessing thermal maturity. In this study, we present the application of quantitative extended diamondoid analysis (QEDA), together with compound-specific isotope analysis of diamondoid hydrocarbons (CSIA-D) recovered from the major USA unconventional reservoirs. The application of diamondoids is demonstrated for three major unconventional reservoirs of North America. A collection of crude oils, condensates, and rock-extracts were examined from Shale formations including the Eagle Ford and Woodford Shales. Core and fluid samples are located within three major US basins including Maverick, Permian and Anadarko basins. Hydrocarbons were analyzed using gas chromatography-mass spectrometry analytical method for measuring the absolute concentrations of diamondoid and biomarker compounds. Further, diamondoid-isolates were analyzed using isotope ratio mass spectrometry equipped with gas chromatography for CSIA-D. Diamondoids composition provides a unique geochemical tool for the unconventional reservoir, in detecting petroleum mixing and fingerprinting fluids of various maturities. In the Anadarko Basin, the Woodford Shale produced oils in central Oklahoma show a dual signature of elevated diamondoid abundance together with the biomarkers, suggesting hydrocarbon mixing of black-oils and cracked dry and wet gas. Moreover, Eagle Ford fluids produced from the Maverick Basin are mature hydrocarbons lacking biomarkers to allocate their zone of production. Diamondoid fingerprints allowed for tracking their production through time and identifying the sweet-spot depth in which most hydrocarbons were contributing. In the Permian Basin, diamondoid fingerprints were used to establish unmixed end-members from oils produced from the Woodford Shale, Eilenberg Carbonate and Pennsylvanian shale, and identify highly mature mixed oil commingled between the Woodford Shale and Ellenburger carbonate source rocks. Identification of the sweet-spots and allocating produced hydrocarbons are crucial factors in the successes of unconventional plays. Most produced fluids in major US unconventional reservoirs are at high levels of thermal maturity, at which classical biomarkers are either absent or in very low concentrations; whereas, diamondoids are abundant, providing a novel technique to fingerprint fluids throughout the range of different maturity stages. In unconventional reservoir operation, diamondoids can be used in time-lapse geochemistry as a cost-effective tool along with other seismic-based techniques.
{"title":"Diamondoids in Tracing Petroleum Systems: Case Studies from the Unconventional Reservoirs of North America","authors":"I. Atwah, M. Moldowan, J. Dahl","doi":"10.2523/iptc-19748-ms","DOIUrl":"https://doi.org/10.2523/iptc-19748-ms","url":null,"abstract":"\u0000 Molecular diamonds, known as diamondoids are naturally occurring hydrocarbon compounds found in crude-oil and rock extracts. Diamondoids feature unique thermal stability owing to the carbon cage-like backbone structures. Therefore, unlike classical geochemical compounds, diamondoids provide a robust molecular-marker for fingerprinting hydrocarbon fluids and assessing thermal maturity. In this study, we present the application of quantitative extended diamondoid analysis (QEDA), together with compound-specific isotope analysis of diamondoid hydrocarbons (CSIA-D) recovered from the major USA unconventional reservoirs.\u0000 The application of diamondoids is demonstrated for three major unconventional reservoirs of North America. A collection of crude oils, condensates, and rock-extracts were examined from Shale formations including the Eagle Ford and Woodford Shales. Core and fluid samples are located within three major US basins including Maverick, Permian and Anadarko basins. Hydrocarbons were analyzed using gas chromatography-mass spectrometry analytical method for measuring the absolute concentrations of diamondoid and biomarker compounds. Further, diamondoid-isolates were analyzed using isotope ratio mass spectrometry equipped with gas chromatography for CSIA-D.\u0000 Diamondoids composition provides a unique geochemical tool for the unconventional reservoir, in detecting petroleum mixing and fingerprinting fluids of various maturities. In the Anadarko Basin, the Woodford Shale produced oils in central Oklahoma show a dual signature of elevated diamondoid abundance together with the biomarkers, suggesting hydrocarbon mixing of black-oils and cracked dry and wet gas. Moreover, Eagle Ford fluids produced from the Maverick Basin are mature hydrocarbons lacking biomarkers to allocate their zone of production. Diamondoid fingerprints allowed for tracking their production through time and identifying the sweet-spot depth in which most hydrocarbons were contributing. In the Permian Basin, diamondoid fingerprints were used to establish unmixed end-members from oils produced from the Woodford Shale, Eilenberg Carbonate and Pennsylvanian shale, and identify highly mature mixed oil commingled between the Woodford Shale and Ellenburger carbonate source rocks.\u0000 Identification of the sweet-spots and allocating produced hydrocarbons are crucial factors in the successes of unconventional plays. Most produced fluids in major US unconventional reservoirs are at high levels of thermal maturity, at which classical biomarkers are either absent or in very low concentrations; whereas, diamondoids are abundant, providing a novel technique to fingerprint fluids throughout the range of different maturity stages. In unconventional reservoir operation, diamondoids can be used in time-lapse geochemistry as a cost-effective tool along with other seismic-based techniques.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132547446","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}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19977-abstract
Ghazi D. AlQahtani, W. Shaker, Menhal Ismail, Shaalan Tareq, Ayub Jibran, Hoti Saud
Multilateral wells may vary in the number of laterals from two to even more than ten laterals. To control production on a lateral level, advance completion equipment, such as Inflow Control Valves (ICVs) and dual ported Permanent Down-hole Monitoring Systems (PDHMS) for real-time pressure measurements, are installed in the motherbore against each lateral to regulate reservoir fluids into the production tubing of the well from individual or collective set of laterals. Multilateral wells equipped with advance completion tools become complex wells (hereinafter called the "complex wells") in reservoir engineering. Recent complex wells involve multiple designs and architecture for which the reservoir exposure for laterals sums can be thousands of meters. A new generation of smart multilateral well completions are Manara type wells where the laterals are divided into a number of segments or compartments using oil swell packers and Manara stations are placed against each segment for quantifying liquid rate, water cut and real-time reservoir pressure measurements. Each station is equipped with electrical control valve for controlling unwanted fluid production at a segment level. In this work, a new workflow is established to model and history match Manara well with complex modeling features using the GigaPOWERS (GP) simulator and a compositional full field model. The established segment level history matching workflow includes four important milestones to achieve. The first is advance well completion design at which the physical well completion details are translated and converted into a grid based completion details with the help of pre-processing tools. The second step covers the generation of three complex well-related input files for the GP simulator. The third step is the process of validating high frequency performance data including flow rate, choke size and pressure for the complex well stations. The last step involves conducting the history matching exercise on a segment level for every individual station to achieve the final history match model. The conventional history match procedure includes generally three levels to match; field, group and well. In this workflow, station level match is done for the first time with a full field compositional model with a size of more than 61 million grid cells. The high definition history match is achieved at segment level for six stations that constitute a trilateral well with high frequency performance data. Complex well modeling in GP includes pressure drop calculations for several components. The pressure drops are related to friction, gravity, acceleration and advanced tools (i.e. ICV). Modeling a complex well involves several pre- and post-simulation environment features at the segment level that should work in complete consistency. The achieved outcome enables a business impact evaluation for an accurate value proposition for complex well incremental rates, cash flow streams and sensitivity predi
{"title":"High Definition Modeling for Complex Multilateral Well with Smart Completions","authors":"Ghazi D. AlQahtani, W. Shaker, Menhal Ismail, Shaalan Tareq, Ayub Jibran, Hoti Saud","doi":"10.2523/iptc-19977-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19977-abstract","url":null,"abstract":"\u0000 Multilateral wells may vary in the number of laterals from two to even more than ten laterals. To control production on a lateral level, advance completion equipment, such as Inflow Control Valves (ICVs) and dual ported Permanent Down-hole Monitoring Systems (PDHMS) for real-time pressure measurements, are installed in the motherbore against each lateral to regulate reservoir fluids into the production tubing of the well from individual or collective set of laterals. Multilateral wells equipped with advance completion tools become complex wells (hereinafter called the \"complex wells\") in reservoir engineering. Recent complex wells involve multiple designs and architecture for which the reservoir exposure for laterals sums can be thousands of meters.\u0000 A new generation of smart multilateral well completions are Manara type wells where the laterals are divided into a number of segments or compartments using oil swell packers and Manara stations are placed against each segment for quantifying liquid rate, water cut and real-time reservoir pressure measurements. Each station is equipped with electrical control valve for controlling unwanted fluid production at a segment level. In this work, a new workflow is established to model and history match Manara well with complex modeling features using the GigaPOWERS (GP) simulator and a compositional full field model. The established segment level history matching workflow includes four important milestones to achieve. The first is advance well completion design at which the physical well completion details are translated and converted into a grid based completion details with the help of pre-processing tools. The second step covers the generation of three complex well-related input files for the GP simulator. The third step is the process of validating high frequency performance data including flow rate, choke size and pressure for the complex well stations. The last step involves conducting the history matching exercise on a segment level for every individual station to achieve the final history match model.\u0000 The conventional history match procedure includes generally three levels to match; field, group and well. In this workflow, station level match is done for the first time with a full field compositional model with a size of more than 61 million grid cells. The high definition history match is achieved at segment level for six stations that constitute a trilateral well with high frequency performance data. Complex well modeling in GP includes pressure drop calculations for several components. The pressure drops are related to friction, gravity, acceleration and advanced tools (i.e. ICV).\u0000 Modeling a complex well involves several pre- and post-simulation environment features at the segment level that should work in complete consistency. The achieved outcome enables a business impact evaluation for an accurate value proposition for complex well incremental rates, cash flow streams and sensitivity predi","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121235345","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 study intends to propose parameter adjustment for economic evaluation in considering abandonment expenditures (ABEX) during front end loading (FEL) of discovered petroleum resources. In maturing a petroleum field development, abandonment and decommissioning of wells and facilities requires consideration during FEL. FEL, long adopted by prominent E&P players worldwide is used to support capital investment decision-making where value i.e. expected monetary wealth is measured and evaluated by Discounted Cash Flow (DCF) analysis. However, the DCF approach is outdated and flawed where it does not capture fluctuation well. This study reviews ABEX of sub-commercial contingent resources or shelved projects and economic evaluation method used in the author's organization and their parameters, identifying relevant and applicable adjustments that could be made associated to ABEX. Combining the revised ABEX with a modified economic model, a proposed set of categorical adjustments to is produced. The results show that the ABEX of the previously sub-commercial projects yield a more competitive number with revised semi-detailed estimates and different escalation and inflation approaches. Additionally, a standardized assumption for abandonment year before cessation of production is recommended to provide a more realistic evaluation of when ABEX is actually required to incur. These, in turn, improves the Net Present Value (NPV) of the projects tested as well as their viability and rank towards being sanctioned for development.
{"title":"Improvement of the Upstream Project Valuation in Consideration of Abandonment Expenditure ABEX Uncertainties","authors":"Azureen Alya Abu Bakar","doi":"10.2118/199174-ms","DOIUrl":"https://doi.org/10.2118/199174-ms","url":null,"abstract":"\u0000 This study intends to propose parameter adjustment for economic evaluation in considering abandonment expenditures (ABEX) during front end loading (FEL) of discovered petroleum resources. In maturing a petroleum field development, abandonment and decommissioning of wells and facilities requires consideration during FEL. FEL, long adopted by prominent E&P players worldwide is used to support capital investment decision-making where value i.e. expected monetary wealth is measured and evaluated by Discounted Cash Flow (DCF) analysis. However, the DCF approach is outdated and flawed where it does not capture fluctuation well. This study reviews ABEX of sub-commercial contingent resources or shelved projects and economic evaluation method used in the author's organization and their parameters, identifying relevant and applicable adjustments that could be made associated to ABEX. Combining the revised ABEX with a modified economic model, a proposed set of categorical adjustments to is produced. The results show that the ABEX of the previously sub-commercial projects yield a more competitive number with revised semi-detailed estimates and different escalation and inflation approaches. Additionally, a standardized assumption for abandonment year before cessation of production is recommended to provide a more realistic evaluation of when ABEX is actually required to incur. These, in turn, improves the Net Present Value (NPV) of the projects tested as well as their viability and rank towards being sanctioned for development.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-12-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125546075","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. Repetto, S. Gorini, G. Nutricato, L. Torri, P. Cavassi, Maria Ornella Zucchetto, C. Guglielmo, E. Gravante, N. McIntosh, Roberto Balistrieri
This paper describes Eni's experience in the application of a Fibreglass liner used as a corrosion barrier in well tubing and the tests performed in high erosion conditions. Liner is made of a Glassfibre Reinforced Epoxy (GRE) resin, inserted in Carbon Steel tubing used in both oil production and water injection wells. Following many successful experiences in these applications, Eni decided to look at what additional requirements would be needed to prove GRE as an alternative material to high grade Corrosion Resistant Alloys (CRA's) for installation in high velocity gas wells. The GRE liner was selected as cost effective alternative to high alloyed materials starting from 2005, where GRE was successful in reducing onshore workover costs and extending the life of Carbon Steel tubing in oil producer wells with high CO2 and water cut, to the more recent installation offshore Norway in Water Injection wells where due to high corrosiveness of the injection fluid. The paper will summarise the testing and the appalication range of GRE in corrosive CO2 and H2S environments and also, through collaboration with Milan Polytechnic, the high flow direct impact erosional testing, utilising a continuous flow loop and nozzle directed solids impingement testing system. Various impinging angles, times and velocities were used during the testing. The results showed GRE to have a good resistance to the solid particles erosion in comparison to the similar tests carried out on Inconel Nickel Alloy material and confirms the potential use of GRE as a corrosion resistance material when combined with Carbon Steel tubulars and alternative to high CRA materials in producer wells. Together with economic evaluations, the paper presents the characteristics of the GRE technology, the acceptable range of field conditions and will highlight feedback for the sites it has been applied.
{"title":"The Application of a Fiberglass Liner in Well Tubing as Cost Effective Material Option in High Velocity Production Wells","authors":"C. Repetto, S. Gorini, G. Nutricato, L. Torri, P. Cavassi, Maria Ornella Zucchetto, C. Guglielmo, E. Gravante, N. McIntosh, Roberto Balistrieri","doi":"10.2118/197215-ms","DOIUrl":"https://doi.org/10.2118/197215-ms","url":null,"abstract":"\u0000 This paper describes Eni's experience in the application of a Fibreglass liner used as a corrosion barrier in well tubing and the tests performed in high erosion conditions.\u0000 Liner is made of a Glassfibre Reinforced Epoxy (GRE) resin, inserted in Carbon Steel tubing used in both oil production and water injection wells.\u0000 Following many successful experiences in these applications, Eni decided to look at what additional requirements would be needed to prove GRE as an alternative material to high grade Corrosion Resistant Alloys (CRA's) for installation in high velocity gas wells.\u0000 The GRE liner was selected as cost effective alternative to high alloyed materials starting from 2005, where GRE was successful in reducing onshore workover costs and extending the life of Carbon Steel tubing in oil producer wells with high CO2 and water cut, to the more recent installation offshore Norway in Water Injection wells where due to high corrosiveness of the injection fluid.\u0000 The paper will summarise the testing and the appalication range of GRE in corrosive CO2 and H2S environments and also, through collaboration with Milan Polytechnic, the high flow direct impact erosional testing, utilising a continuous flow loop and nozzle directed solids impingement testing system. Various impinging angles, times and velocities were used during the testing. The results showed GRE to have a good resistance to the solid particles erosion in comparison to the similar tests carried out on Inconel Nickel Alloy material and confirms the potential use of GRE as a corrosion resistance material when combined with Carbon Steel tubulars and alternative to high CRA materials in producer wells.\u0000 Together with economic evaluations, the paper presents the characteristics of the GRE technology, the acceptable range of field conditions and will highlight feedback for the sites it has been applied.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131251783","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：