This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214950, “Limitations and Fallacies of Carbon Capture and Storage and Impact on Oil and Gas Production,” by S.M. Farouq Ali, SPE, and Mohamed Y. Soliman, SPE, University of Houston. The paper has not been peer reviewed. In the complete paper, the authors write that, while carbon capture and storage (CCS) initiatives are affecting oil and gas operations profoundly, such efforts have had little perceptible effect on atmospheric CO2, which continues to increase. The paper aims to show that current CCS regimens have serious technical and fiscal constraints and questionable validity, stating that, globally, CCS has not increased beyond approximately 0.1% of global CO2 emissions in the past 20 years. The paper offers partial solutions and concludes that, while oil and gas will continue to be important energy sources beyond the foreseeable future, oil companies will accomplish the needed CCS. The authors write that, while CCS efforts have been pursued for 4 decades, little has been achieved. For the past 20 years, the percentage of CO2 captured and stored is less than 0.1% of the CO2 emitted worldwide, if one considers CO2 enhanced oil recovery (EOR) projects to be CSS—which, the authors write, is a fallacy. They emphasize that CCS means injection with no production. The key to CCS success, they write, is major governmental subsidization, by whatever terminology it is known, and that means taxpayer money. Sweeping decisions that have a profound effect on oil and gas production and petroleum engineering education are being made based on predictions of an increase in CO2 concentration in the atmosphere in various time frames. The problem of world CO2 emissions capture is gigantic. To appreciate the magnitude of the problem, imagine that 1 year’s CO2 emissions (40 billion tonnes) are captured, compressed and liquified, and injected into a reservoir the size of the Ghawar oil field, the largest reservoir in the world, with the entire pore space (approximately 0.5 Tcf) available for storage. In this hypothetical, nine such reservoirs would be required every year. Presumably, such storage space can be found, but collecting the CO2 and bringing it to a storage site is a highly complex task. For example, in a sequestration effort in a building complex in New York, the CO2 is separated, liquified, and trucked to a storage site to be injected underground, which is impractical. Often, the example of the Nordic countries (mainly Denmark, Sweden, and Norway) is cited as evidence of successful emissions reduction. But the total population of these countries is approximately the same as that of metropolitan Mumbai in India. Carbon capture use and storage (CCUS) implies that the CO2 produced by various processes is captured and used for EOR. This accounts for approximately 30% of the 230 mtpa of CO2 captured globally. CCS means that any CO2 pr
{"title":"Study Examines Limitations of CCS and Their Effect on Oil and Gas Production","authors":"C. Carpenter","doi":"10.2118/0724-0102-jpt","DOIUrl":"https://doi.org/10.2118/0724-0102-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214950, “Limitations and Fallacies of Carbon Capture and Storage and Impact on Oil and Gas Production,” by S.M. Farouq Ali, SPE, and Mohamed Y. Soliman, SPE, University of Houston. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the complete paper, the authors write that, while carbon capture and storage (CCS) initiatives are affecting oil and gas operations profoundly, such efforts have had little perceptible effect on atmospheric CO2, which continues to increase. The paper aims to show that current CCS regimens have serious technical and fiscal constraints and questionable validity, stating that, globally, CCS has not increased beyond approximately 0.1% of global CO2 emissions in the past 20 years. The paper offers partial solutions and concludes that, while oil and gas will continue to be important energy sources beyond the foreseeable future, oil companies will accomplish the needed CCS.\u0000 \u0000 \u0000 \u0000 The authors write that, while CCS efforts have been pursued for 4 decades, little has been achieved. For the past 20 years, the percentage of CO2 captured and stored is less than 0.1% of the CO2 emitted worldwide, if one considers CO2 enhanced oil recovery (EOR) projects to be CSS—which, the authors write, is a fallacy. They emphasize that CCS means injection with no production. The key to CCS success, they write, is major governmental subsidization, by whatever terminology it is known, and that means taxpayer money. Sweeping decisions that have a profound effect on oil and gas production and petroleum engineering education are being made based on predictions of an increase in CO2 concentration in the atmosphere in various time frames.\u0000 \u0000 \u0000 \u0000 The problem of world CO2 emissions capture is gigantic. To appreciate the magnitude of the problem, imagine that 1 year’s CO2 emissions (40 billion tonnes) are captured, compressed and liquified, and injected into a reservoir the size of the Ghawar oil field, the largest reservoir in the world, with the entire pore space (approximately 0.5 Tcf) available for storage. In this hypothetical, nine such reservoirs would be required every year. Presumably, such storage space can be found, but collecting the CO2 and bringing it to a storage site is a highly complex task. For example, in a sequestration effort in a building complex in New York, the CO2 is separated, liquified, and trucked to a storage site to be injected underground, which is impractical. Often, the example of the Nordic countries (mainly Denmark, Sweden, and Norway) is cited as evidence of successful emissions reduction. But the total population of these countries is approximately the same as that of metropolitan Mumbai in India.\u0000 \u0000 \u0000 \u0000 Carbon capture use and storage (CCUS) implies that the CO2 produced by various processes is captured and used for EOR. This accounts for approximately 30% of the 230 mtpa of CO2 captured globally. CCS means that any CO2 pr","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"41 20","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141709759","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume
{"title":"Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage","authors":"C. Carpenter","doi":"10.2118/0724-0108-jpt","DOIUrl":"https://doi.org/10.2118/0724-0108-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission.\u0000 \u0000 \u0000 \u0000 Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute.\u0000 \u0000 \u0000 \u0000 The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available.\u0000 Reservoir Engineering of GHS.\u0000 GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs.\u0000 GHS in SCs.\u0000 SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage.\u0000 The storage capacity of caverns in Germany is determined by their volume","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141701980","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 efficient management of increasing water cuts in oil fields is paramount for sustaining profitability and minimizing environmental impact. This article presents a comprehensive case study conducted by Saudi Aramco, focusing on the integration of hybrid flotation technology into a gravity water/oil separator (WOSEP) to enhance deoiling efficiency and reduce operational costs and carbon emissions. The retrofit involved merging enhanced gravity separation with induced gas flotation (IGF) within the same vessel, resulting in significant improvements in deoiling capacity, outlet oil-in-water content reduction, and operational efficiency. Detailed insights into the design, operation, and performance of hybrid flotation systems are provided, offering valuable guidance for similar initiatives in the petroleum industry. Petroleum production facilities face escalating challenges with increasing water-production rates during crude-oil extraction, particularly in waterflooding operations for secondary oil recovery. This trend not only escalates operational costs but also intensifies environmental concerns, particularly regarding energy consumption and carbon emissions associated with water-handling processes. In response to these challenges, Saudi Aramco embarked on a pioneering initiative to enhance water-deoiling efficiency by integrating hybrid flotation technology into a conventional gravity WOSEP. This case study presents a comprehensive analysis of the design, implementation, and outcomes of this transformative project, offering valuable insights for the broader petroleum industry. The upgrade process commenced with an assessment of the existing WOSEP system and its operational challenges. Recognizing the impending capacity constraints and escalating oil-in-water content, Saudi Aramco’s engineering team opted for a holistic approach that combined enhanced gravity separation with IGF within the same vessel. The retrofit involved reconfiguring the internal components of the WOSEP to accommodate the hybrid flotation system, including the installation of advanced plate-pack internals for gravity separation and the integration of IGF cells for additional oil removal. Rigorous testing and optimization procedures were conducted to ensure seamless integration and optimal performance of the hybrid system. In a typical gas/oil separation plant, the initial phase involves the extraction of crude oil, associated gas, and produced water from wells via a production manifold. These constituents are then directed to a three-phase separator, also known as a high-pressure production trap (HPPT). In the HPPT, free water droplets are separated from the oil through gravity separation, aided by demulsifier injection at the production header. The separated free water is discharged to a WOSEP, typically a gravity separator, for deoiling.
{"title":"Advancing Water Deoiling Efficiency in Petroleum Production: A Comprehensive Case Study of Hybrid Flotation Technology Integration","authors":"R. White, A. Alhamoud","doi":"10.2118/0724-0058-jpt","DOIUrl":"https://doi.org/10.2118/0724-0058-jpt","url":null,"abstract":"\u0000 \u0000 The efficient management of increasing water cuts in oil fields is paramount for sustaining profitability and minimizing environmental impact. This article presents a comprehensive case study conducted by Saudi Aramco, focusing on the integration of hybrid flotation technology into a gravity water/oil separator (WOSEP) to enhance deoiling efficiency and reduce operational costs and carbon emissions.\u0000 The retrofit involved merging enhanced gravity separation with induced gas flotation (IGF) within the same vessel, resulting in significant improvements in deoiling capacity, outlet oil-in-water content reduction, and operational efficiency. Detailed insights into the design, operation, and performance of hybrid flotation systems are provided, offering valuable guidance for similar initiatives in the petroleum industry.\u0000 \u0000 \u0000 \u0000 Petroleum production facilities face escalating challenges with increasing water-production rates during crude-oil extraction, particularly in waterflooding operations for secondary oil recovery. This trend not only escalates operational costs but also intensifies environmental concerns, particularly regarding energy consumption and carbon emissions associated with water-handling processes.\u0000 In response to these challenges, Saudi Aramco embarked on a pioneering initiative to enhance water-deoiling efficiency by integrating hybrid flotation technology into a conventional gravity WOSEP.\u0000 This case study presents a comprehensive analysis of the design, implementation, and outcomes of this transformative project, offering valuable insights for the broader petroleum industry.\u0000 \u0000 \u0000 \u0000 The upgrade process commenced with an assessment of the existing WOSEP system and its operational challenges. Recognizing the impending capacity constraints and escalating oil-in-water content, Saudi Aramco’s engineering team opted for a holistic approach that combined enhanced gravity separation with IGF within the same vessel. The retrofit involved reconfiguring the internal components of the WOSEP to accommodate the hybrid flotation system, including the installation of advanced plate-pack internals for gravity separation and the integration of IGF cells for additional oil removal. Rigorous testing and optimization procedures were conducted to ensure seamless integration and optimal performance of the hybrid system.\u0000 \u0000 \u0000 \u0000 In a typical gas/oil separation plant, the initial phase involves the extraction of crude oil, associated gas, and produced water from wells via a production manifold. These constituents are then directed to a three-phase separator, also known as a high-pressure production trap (HPPT). In the HPPT, free water droplets are separated from the oil through gravity separation, aided by demulsifier injection at the production header. The separated free water is discharged to a WOSEP, typically a gravity separator, for deoiling.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"22 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699987","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214647, “Operational Experience From the Implementation of 21 Wells With Nonmetallic-Based Downhole Tubing: From Pilot to Large-Scale Implementation,” by Mohamad H. Ahmad, ADNOC. The paper has not been peer reviewed. Tubular glass-reinforced-epoxy (GRE) lining technology has been applied globally since the 1960s in eliminating downhole tubular corrosion. Compared with conventional carbon steel, which can experience frequent failure, GRE-lined carbon steel provides long-lasting protection, resulting in huge savings in life-cycle cost. The operator implemented this technology for a successful trial of water-disposal wells. In the complete paper, the authors share the data from caliper logs run into, and the inspection of tubing pulled from, these disposal wells after 4 years in service. A growing emphasis on water disposal was inevitable because so much water was being produced with increased water cut and production. ADNOC Onshore operates almost 200 water-disposal wells. However, corrosion has been a common problem in these wells, such that a failure has been reported every 1–2 years. Use of corrosion-prone carbon steel for disposal strings has led to integrity issues and the need for expensive workover jobs that could cost between $1.5 million and $2 million per job. Since 2014, the operator has run 19 water-disposal wells with GRE-lined carbon steel strings. No failures have been reported, and inspections have been successful. Fiberglass tubular lining protects the internal surface of the tubing or casing inside the steel joint. Cement is pumped into the annulus between the GRE-liner outer diameter (OD) and the steel‑pipe inner diameter (ID). The final product is a completely corrosion-protected string, even under the connection area, where accessories called flares and corrosion barrier rings (CBRs) are installed (Fig. 1). The mechanical capability of the system is maintained by the steel pipe, while the internal fiberglass liner provides reliable corrosion resistance. Fiberglass Liner. The fiberglass liner shows excellent resistance in corrosive environments. As per tested and as per the manufacturer’s data sheets, the fiberglass lining system can be used in temperatures of up to 145°C, depending on hydrogen sulfide and CO2 levels in the flowing fluid. Besides being corrosion‑resistant, fiberglass lining improves the flow rate of the flowing water or oil because of the superior surface-energy properties and manufacturing quality of the liner material. The thickness of the liner varies according to the tubing size (diameter). Cement. The cement transfer applies pressure directly to the steel pipe. The cement does not bond the fiberglass liner to the steel and allows relative micromovement between the fiberglass liner and the steel pipe resulting from the difference in the thermal expansion coefficient of these two ma
本文由 JPT 技术编辑 Chris Carpenter 撰写，包含 SPE 214647 号论文 "21 口油井使用非金属井下油管的运行经验 "的要点，作者是 ADNOC 的 Mohamad H. Ahmad：ADNOC 的 Mohamad H. Ahmad 撰写。该论文未经同行评审。 自 20 世纪 60 年代以来，全球一直在应用管状玻璃纤维增强环氧树脂（GRE）内衬技术来消除井下油管腐蚀。与经常出现故障的传统碳钢相比，内衬 GRE 的碳钢可提供持久的保护，从而大大节省生命周期成本。运营商在一次成功的水处理井试验中采用了这项技术。在这篇完整的论文中，作者分享了这些弃水井在使用 4 年后的卡尺测井数据，以及从这些弃水井中抽出的油管的检查结果。 随着减产和增产，生产出大量的水，因此越来越重视水处理是不可避免的。ADNOC 陆上公司运营着近 200 口弃水井。然而，腐蚀一直是这些水井的常见问题，每隔 1-2 年就会报告一次故障。使用易腐蚀的碳钢制作排水串导致了完整性问题，需要进行昂贵的修井作业，每次作业的成本可能在 150 万美元到 200 万美元之间。 自 2014 年以来，运营商已使用 GRE 内衬碳钢绳运行了 19 口弃水井。没有任何故障报告，检查也很成功。玻璃纤维管衬里可保护钢接头内的油管或套管内表面。水泥被泵入 GRE 内衬管外径（OD）与钢管内径（ID）之间的环形空间。最终产品是一根完全防腐蚀的管串，甚至在连接区域下方也是如此，在连接区域安装了称为扩口和防腐蚀环（CBR）的附件（图 1）。钢管保持了系统的机械性能，而内部的玻璃纤维内衬则提供了可靠的防腐蚀性能。玻璃纤维内衬。玻璃纤维内衬在腐蚀环境中表现出卓越的耐腐蚀性。根据测试和制造商的数据表，玻璃纤维内衬系统可在高达 145°C 的温度下使用，具体取决于流体中的硫化氢和二氧化碳含量。除了耐腐蚀之外，玻璃纤维衬里还能提高水或油的流速，这是因为衬里材料具有优异的表面能量特性和制造质量。内衬的厚度因管道尺寸（直径）而异。水泥。水泥输送将压力直接施加到钢管上。水泥不会将玻璃纤维内衬粘合到钢管上，而是允许玻璃纤维内衬和钢管之间因这两种材料的热膨胀系数不同而产生相对微动。水泥呈碱性，可中和玻璃纤维-钢管环形空间中可能存在的迁移酸性气体；这进一步降低了碳钢管腐蚀的可能性。
{"title":"Nonmetallic-Based Tubulars Provide Superior Integrity, Cost Savings","authors":"C. Carpenter","doi":"10.2118/0724-0082-jpt","DOIUrl":"https://doi.org/10.2118/0724-0082-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214647, “Operational Experience From the Implementation of 21 Wells With Nonmetallic-Based Downhole Tubing: From Pilot to Large-Scale Implementation,” by Mohamad H. Ahmad, ADNOC. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Tubular glass-reinforced-epoxy (GRE) lining technology has been applied globally since the 1960s in eliminating downhole tubular corrosion. Compared with conventional carbon steel, which can experience frequent failure, GRE-lined carbon steel provides long-lasting protection, resulting in huge savings in life-cycle cost. The operator implemented this technology for a successful trial of water-disposal wells. In the complete paper, the authors share the data from caliper logs run into, and the inspection of tubing pulled from, these disposal wells after 4 years in service.\u0000 \u0000 \u0000 \u0000 A growing emphasis on water disposal was inevitable because so much water was being produced with increased water cut and production. ADNOC Onshore operates almost 200 water-disposal wells. However, corrosion has been a common problem in these wells, such that a failure has been reported every 1–2 years.\u0000 Use of corrosion-prone carbon steel for disposal strings has led to integrity issues and the need for expensive workover jobs that could cost between $1.5 million and $2 million per job.\u0000 \u0000 \u0000 \u0000 Since 2014, the operator has run 19 water-disposal wells with GRE-lined carbon steel strings. No failures have been reported, and inspections have been successful.\u0000 Fiberglass tubular lining protects the internal surface of the tubing or casing inside the steel joint. Cement is pumped into the annulus between the GRE-liner outer diameter (OD) and the steel‑pipe inner diameter (ID). The final product is a completely corrosion-protected string, even under the connection area, where accessories called flares and corrosion barrier rings (CBRs) are installed (Fig. 1). The mechanical capability of the system is maintained by the steel pipe, while the internal fiberglass liner provides reliable corrosion resistance.\u0000 Fiberglass Liner.\u0000 The fiberglass liner shows excellent resistance in corrosive environments. As per tested and as per the manufacturer’s data sheets, the fiberglass lining system can be used in temperatures of up to 145°C, depending on hydrogen sulfide and CO2 levels in the flowing fluid.\u0000 Besides being corrosion‑resistant, fiberglass lining improves the flow rate of the flowing water or oil because of the superior surface-energy properties and manufacturing quality of the liner material. The thickness of the liner varies according to the tubing size (diameter).\u0000 Cement.\u0000 The cement transfer applies pressure directly to the steel pipe. The cement does not bond the fiberglass liner to the steel and allows relative micromovement between the fiberglass liner and the steel pipe resulting from the difference in the thermal expansion coefficient of these two ma","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"26 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141716719","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}
For millennia, Zoroastrian fire worshippers traveled on pilgrimage to pray at temples built where methane seeping from deep underground caused flames to burst from the earth on the Absheron Peninsula near Baku, the capital of today’s Azerbaijan. The Venetian merchant Marco Polo observed such mysterious fires and puddles of oil that bubbled or even gushed as fountains to the surface as he trekked along the Silk Road through the Caucasus Mountains in the 13th century. In a travelogue written in 1298, The Travels of Marco Polo, he is said to have described: “Near the Georgian border there is a spring from which gushes a stream of oil in such abundance that a hundred ships may load here at once. This oil is not good to eat, but it is good for burning and as a salve for men and camels affected with itch or scab.” He was referring to the Khanates of Azerbaijan, a part of the Persian Empire in Marco Polo’s time but absorbed in 1806 into the Russian Empire whose czars took an interest in financing early oil production—hand dug and exported on camel back. Its high paraffin content was valued for producing kerosene lamp oil and lubricants including cannon grease. As the Industrial Revolution swept from West to East in the mid-19th century, many of the innovations and business systems around which the modern oil and gas industry were soon to coalesce were tested in the ancient “Land of Fire.” Czar Nicholas I (1825–1855) financed the world’s first mechanically drilled oil well in 1846 using a cable-tool percussion drilling method. A 21-m-deep (69 ft) exploration well was the result. This happened a decade before Edwin Drake added steam-engine power to a mechanical drill to put Titusville, Pennsylvania, on the map in 1859, as described in the Branobel History archives. By 1871, with Nicholas’ son, the reformer Alexander II now on the Russian throne, boreholes had replaced buckets across the Bibi-Heybat and Balakhani oil fields. The arrival from Sweden in the 1870s of Alfred Nobel’s brothers, Ludvig and Robert, brought a step change to Azerbaijan in terms of industrial innovation, construction, and logistics such that by 1900 Azerbaijan was producing 50% of the world’s oil, historical sources agree. Alexander II had abolished the state monopoly on oil production in 1869, opening the door to foreign industrialists and their capital. Robert Nobel obliged and opened the joint stock Branobel Co. in 1878 with a partner from a weapons plant in the Russian town of Izhevsk. He put down share capital of 3 million rubles ($30,000 in today’s money) to register Tovarishestvo Neftyanogo Proizvodstva Bratyev Nobel—in English, The Brothers Nobel Paraffin Production Company (aka Branobel). The transformation of Baku’s oil fields into a capitalist production sector had begun in 1872 with the auction of 15 blocks in the Balakhani oil field and two blocks in Bibi-Heybat, according to a history prepared by Azerbaijan’s Ministry of Energy in 2020. This drove a
{"title":"Azerbaijan—The Land of Unquenchable Fire","authors":"Patricia Szymczak","doi":"10.2118/0724-0018-jpt","DOIUrl":"https://doi.org/10.2118/0724-0018-jpt","url":null,"abstract":"\u0000 \u0000 For millennia, Zoroastrian fire worshippers traveled on pilgrimage to pray at temples built where methane seeping from deep underground caused flames to burst from the earth on the Absheron Peninsula near Baku, the capital of today’s Azerbaijan.\u0000 The Venetian merchant Marco Polo observed such mysterious fires and puddles of oil that bubbled or even gushed as fountains to the surface as he trekked along the Silk Road through the Caucasus Mountains in the 13th century.\u0000 In a travelogue written in 1298, The Travels of Marco Polo, he is said to have described: “Near the Georgian border there is a spring from which gushes a stream of oil in such abundance that a hundred ships may load here at once. This oil is not good to eat, but it is good for burning and as a salve for men and camels affected with itch or scab.”\u0000 He was referring to the Khanates of Azerbaijan, a part of the Persian Empire in Marco Polo’s time but absorbed in 1806 into the Russian Empire whose czars took an interest in financing early oil production—hand dug and exported on camel back. Its high paraffin content was valued for producing kerosene lamp oil and lubricants including cannon grease.\u0000 \u0000 \u0000 \u0000 As the Industrial Revolution swept from West to East in the mid-19th century, many of the innovations and business systems around which the modern oil and gas industry were soon to coalesce were tested in the ancient “Land of Fire.”\u0000 Czar Nicholas I (1825–1855) financed the world’s first mechanically drilled oil well in 1846 using a cable-tool percussion drilling method. A 21-m-deep (69 ft) exploration well was the result. This happened a decade before Edwin Drake added steam-engine power to a mechanical drill to put Titusville, Pennsylvania, on the map in 1859, as described in the Branobel History archives.\u0000 By 1871, with Nicholas’ son, the reformer Alexander II now on the Russian throne, boreholes had replaced buckets across the Bibi-Heybat and Balakhani oil fields.\u0000 The arrival from Sweden in the 1870s of Alfred Nobel’s brothers, Ludvig and Robert, brought a step change to Azerbaijan in terms of industrial innovation, construction, and logistics such that by 1900 Azerbaijan was producing 50% of the world’s oil, historical sources agree.\u0000 Alexander II had abolished the state monopoly on oil production in 1869, opening the door to foreign industrialists and their capital.\u0000 Robert Nobel obliged and opened the joint stock Branobel Co. in 1878 with a partner from a weapons plant in the Russian town of Izhevsk. He put down share capital of 3 million rubles ($30,000 in today’s money) to register Tovarishestvo Neftyanogo Proizvodstva Bratyev Nobel—in English, The Brothers Nobel Paraffin Production Company (aka Branobel).\u0000 The transformation of Baku’s oil fields into a capitalist production sector had begun in 1872 with the auction of 15 blocks in the Balakhani oil field and two blocks in Bibi-Heybat, according to a history prepared by Azerbaijan’s Ministry of Energy in 2020.\u0000 This drove a","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"16 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141709380","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214855, “Integrated Multiphase-Flow Modeling for Downhole Pressure Predictions,” by Abdullah Alkhezzi and Yilin Fan, SPE, Colorado School of Mines. The paper has not been peer reviewed. This work presents an integrated multiphase flow model for downhole pressure predictions. The aim of the model is to produce more-accurate downhole pressure predictions under wide flowing conditions while maintaining a simple form. As a component of the integrated model, an improved two-fluid model for segregated flow is proposed. Results of the two-fluid segregated model are compared with five state-of-the-art existing models, while results of the integrated model are compared with three models. Throughout the life of the well, knowing bottomhole flowing pressure (Pwf) and the pressure profile of the wellbore are of great significance. Unfortunately, deploying downhole pressure gauges to obtain Pwfreadings is often not economical or practical. The common practice is to apply hydraulic models to predict Pwfgiven surface measurements. The prediction of such behavior is simple when dealing with single-phase fluid flow. Unfortunately, this condition is rare in the petroleum industry. The existence of multiple phases introduces multiple complexities hindering the accuracy of downhole pressure predictions. To account for such variations, fluid-property models must be integrated into the calculation procedure. The complexity, coupled with field-data scarcity, results in the deficiency of work that evaluates point models on actual wells. In this work, the authors evaluated the performance of a few widely used multiphase-flow point-based models on actual field data using a marching algorithm and developed a simplified, yet more precise, integrated model. Data Set Description. In this study, data points were collected for two main purposes. First, experimental data sets were collected to model and improve the segregated flow model. Second, field data were collected to test the integrated multiphase model. To improve the segregated flow model, 1,478 experimental data points were obtained from various sources in the literature. To evaluate the integrated multiphase flow model, 313 data points from two main sources of data were used (literature and actual field data). In total, four data sets were obtained from the literature and one was obtained from Civitas Resources. Integrated Model Description. The multiphase-flow point model incorporated in the authors’ integrated modeling consists of three main components: critical gas velocity estimation for the onset of liquid loading and hydraulic multiphase flow models before and after the onset of liquid loading. The proposed model characterizes the flow based on whether liquid loading occurs. The onset of liquid loading corresponds with the transition of the flow pattern from segregated to intermittent
本文由 JPT 技术编辑 Chris Carpenter 撰写，包含 SPE 214855 号论文 "用于井下压力预测的综合多相流建模 "的要点，作者 Abdullah Alkhezzi 和 Yilin Fan，SPE，科罗拉多矿业学院。该论文未经同行评审。 该论文介绍了一种用于井下压力预测的综合多相流模型。该模型的目的是在保持简单形式的同时，对宽流动条件下的井下压力进行更精确的预测。作为综合模型的一个组成部分，提出了一种改进的隔离流双流体模型。将双流体隔离模型的结果与五个最先进的现有模型进行了比较，同时将综合模型的结果与三个模型进行了比较。 在油井的整个生命周期中，了解井底流动压力（Pwf）和井筒压力剖面具有重要意义。遗憾的是，部署井下压力计来获取 Pwf 值往往既不经济也不实用。通常的做法是根据地面测量结果，应用水力模型来预测 Pwf。在处理单相流体流动时，这种行为的预测很简单。遗憾的是，这种情况在石油工业中并不多见。多相流的存在带来了多种复杂性，妨碍了井下压力预测的准确性。为了考虑这些变化，必须在计算过程中加入流体性质模型。这种复杂性加上油田数据的匮乏，导致在实际油井中评估点模型的工作十分缺乏。在这项工作中，作者使用行进算法评估了几个广泛使用的基于实际油田数据的多相流点模型的性能，并开发了一个简化但更精确的集成模型。 数据集描述。在这项研究中，收集数据点主要有两个目的。首先，收集实验数据集以建立和改进隔离流模型。其次，收集实地数据来测试综合多相模型。为了改进离析流模型，我们从各种文献资料中获取了 1,478 个实验数据点。为了评估综合多相流模型，使用了来自两个主要数据来源（文献和实际现场数据）的 313 个数据点。共有四组数据来自文献，一组数据来自 Civitas Resources。综合模型描述。作者的综合建模中包含的多相流点模型由三个主要部分组成：液体加载开始时的临界气体速度估算以及液体加载开始前后的水力多相流模型。所提出的模型根据是否发生液体加载来描述流动特征。液体加载的开始与流动模式从分离流向间歇流的转变相对应。在表层气体速度估计低于临界气体速度、流动被认为是间歇或气泡流动时，将使用漂移-流动模型，该模型在液体体积较大的流动模式中效果良好。该模型的另一个优点是能够捕捉逆流流动。类似于漂移-流动的均质方法使过程变得简单、连续，同时通过滑动捕捉到一些物理现象。对于表层气体速度大于临界气体速度的点，应使用双流体模型。
{"title":"Integrated Multiphase-Flow Modeling Technique Yields Accurate Downhole Pressure Predictions","authors":"C. Carpenter","doi":"10.2118/0724-0074-jpt","DOIUrl":"https://doi.org/10.2118/0724-0074-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214855, “Integrated Multiphase-Flow Modeling for Downhole Pressure Predictions,” by Abdullah Alkhezzi and Yilin Fan, SPE, Colorado School of Mines. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 This work presents an integrated multiphase flow model for downhole pressure predictions. The aim of the model is to produce more-accurate downhole pressure predictions under wide flowing conditions while maintaining a simple form. As a component of the integrated model, an improved two-fluid model for segregated flow is proposed. Results of the two-fluid segregated model are compared with five state-of-the-art existing models, while results of the integrated model are compared with three models.\u0000 \u0000 \u0000 \u0000 Throughout the life of the well, knowing bottomhole flowing pressure (Pwf) and the pressure profile of the wellbore are of great significance. Unfortunately, deploying downhole pressure gauges to obtain Pwfreadings is often not economical or practical. The common practice is to apply hydraulic models to predict Pwfgiven surface measurements. The prediction of such behavior is simple when dealing with single-phase fluid flow. Unfortunately, this condition is rare in the petroleum industry.\u0000 The existence of multiple phases introduces multiple complexities hindering the accuracy of downhole pressure predictions. To account for such variations, fluid-property models must be integrated into the calculation procedure. The complexity, coupled with field-data scarcity, results in the deficiency of work that evaluates point models on actual wells.\u0000 In this work, the authors evaluated the performance of a few widely used multiphase-flow point-based models on actual field data using a marching algorithm and developed a simplified, yet more precise, integrated model.\u0000 \u0000 \u0000 \u0000 Data Set Description.\u0000 In this study, data points were collected for two main purposes. First, experimental data sets were collected to model and improve the segregated flow model. Second, field data were collected to test the integrated multiphase model. To improve the segregated flow model, 1,478 experimental data points were obtained from various sources in the literature.\u0000 To evaluate the integrated multiphase flow model, 313 data points from two main sources of data were used (literature and actual field data). In total, four data sets were obtained from the literature and one was obtained from Civitas Resources.\u0000 Integrated Model Description.\u0000 The multiphase-flow point model incorporated in the authors’ integrated modeling consists of three main components: critical gas velocity estimation for the onset of liquid loading and hydraulic multiphase flow models before and after the onset of liquid loading. The proposed model characterizes the flow based on whether liquid loading occurs.\u0000 The onset of liquid loading corresponds with the transition of the flow pattern from segregated to intermittent ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"352 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141707789","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23491, “Role of Ecosystem Partners To Make Nonmetallic Downhole Tubulars a Reality,” by Ahmed Aladawy, SPE, and Ameen Malkawi, SPE, Baker Hughes, and Omar El Shamy, SPE, Novel Non-Metallic Solutions. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Nonmetallic (NM) downhole tubulars offer a longer lifetime than their steel counterparts while eliminating corrosion concerns and lowering total cost of ownership. Making them a reality, however, requires a rigorous ecosystem with multidisciplinary skill sets and technology expertise. The complete paper discusses the challenges that face the development of such tubulars starting from academia and research institutes to complement expertise and computer computational power and moving through to material suppliers and manufacturing facilities for pipe prototyping. NM pipes also can include metallic elements, where a hybrid system of NM layers is incorporated into multilayered pipe structures that assume specific roles, similar to a metallic pressure armor layer in subsea flexible risers, jumpers, and flowlines. Another example is polymer-lined steel rigid pipes with glass-fiber reinforced epoxy (GRE), or a dual-layer thermoplastic-lined reinforced pipe (Fig. 1). Composite-based NM pipes can broadly be categorized into reinforced thermoplastic pipe (RTP) and reinforced thermoset pipe (RTR), with glass-fiber reinforced plastic pipe (GRP) and GRE considered a subset of RTR. RTP consists of thermoplastic matrices and layers that can soften after heating and can harden when cooled in a reversible process, thus having the potential to recycle. Because of the flexibility of thermoplastic polymer, RTP pipes up to hundreds of meters long can be spooled on reels and deployed through rigless operation, with reduced system cost and deployment time. This synopsis will concentrate, as does the complete paper, on RTP. RTP pipe design can be classified as unbonded, semibonded, or fully bonded. Essentially, three layers of constituents for RTP exist: the inner layer is a fluid barrier (liner), the second layer is a load-bearing component (reinforcement), and the outer layer is external protection (cover). Unbonded RTP pipe means that the layers are not heat-fused to one another during manufacturing and are free to move between layers. This type of RTP pipe usually is low to medium in pressure rating, especially with regard to collapse rating, but also is lower in manufacturing cost and is suitable in onshore applications for fluid transportation. To increase the pressure rating, semibonded RTP pipes can be considered if pipe thickness is a limitation. For offshore and downhole applications, however, where higher pressure and temperature ratings are required, fully bonded RTP pipes, more commonly known as thermoplastic composite pipes, are preferred to han
{"title":"Partnerships Crucial in Developing Nonmetallic Downhole Tubulars","authors":"C. Carpenter","doi":"10.2118/0724-0079-jpt","DOIUrl":"https://doi.org/10.2118/0724-0079-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23491, “Role of Ecosystem Partners To Make Nonmetallic Downhole Tubulars a Reality,” by Ahmed Aladawy, SPE, and Ameen Malkawi, SPE, Baker Hughes, and Omar El Shamy, SPE, Novel Non-Metallic Solutions. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 Nonmetallic (NM) downhole tubulars offer a longer lifetime than their steel counterparts while eliminating corrosion concerns and lowering total cost of ownership. Making them a reality, however, requires a rigorous ecosystem with multidisciplinary skill sets and technology expertise. The complete paper discusses the challenges that face the development of such tubulars starting from academia and research institutes to complement expertise and computer computational power and moving through to material suppliers and manufacturing facilities for pipe prototyping.\u0000 \u0000 \u0000 \u0000 NM pipes also can include metallic elements, where a hybrid system of NM layers is incorporated into multilayered pipe structures that assume specific roles, similar to a metallic pressure armor layer in subsea flexible risers, jumpers, and flowlines. Another example is polymer-lined steel rigid pipes with glass-fiber reinforced epoxy (GRE), or a dual-layer thermoplastic-lined reinforced pipe (Fig. 1).\u0000 Composite-based NM pipes can broadly be categorized into reinforced thermoplastic pipe (RTP) and reinforced thermoset pipe (RTR), with glass-fiber reinforced plastic pipe (GRP) and GRE considered a subset of RTR. RTP consists of thermoplastic matrices and layers that can soften after heating and can harden when cooled in a reversible process, thus having the potential to recycle. Because of the flexibility of thermoplastic polymer, RTP pipes up to hundreds of meters long can be spooled on reels and deployed through rigless operation, with reduced system cost and deployment time. This synopsis will concentrate, as does the complete paper, on RTP.\u0000 RTP pipe design can be classified as unbonded, semibonded, or fully bonded. Essentially, three layers of constituents for RTP exist: the inner layer is a fluid barrier (liner), the second layer is a load-bearing component (reinforcement), and the outer layer is external protection (cover). Unbonded RTP pipe means that the layers are not heat-fused to one another during manufacturing and are free to move between layers. This type of RTP pipe usually is low to medium in pressure rating, especially with regard to collapse rating, but also is lower in manufacturing cost and is suitable in onshore applications for fluid transportation. To increase the pressure rating, semibonded RTP pipes can be considered if pipe thickness is a limitation. For offshore and downhole applications, however, where higher pressure and temperature ratings are required, fully bonded RTP pipes, more commonly known as thermoplastic composite pipes, are preferred to han","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"39 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141715250","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates. To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field. West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation. The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes. The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle
本文由 JPT 技术编辑 Chris Carpenter 撰写，收录了 OTC 34832 号论文 "成功试用创新井下氢气发生器系统以刺激难以恢复的地层：该论文未经同行评审。版权归 2024 年海洋技术大会所有。 完整论文中描述的试点试验的目的是提供一种经济的解决方案，以开发作业者油田中的致密和难以恢复的地层。这些资产是一项重大挑战，因为它们的采收率低（1%-3%），可用的常规刺激技术成本高，收入低，而且无法维持生产率。 为了建立致密油和重油地层的综合激励解决方案，我们提出了使用活性单原子氢能提高近井筒渗透率的概念。该技术基于两种独特的氢反应剂（HRA）之间的原位放热多级化学反应产生的井下氢。这种反应会产生大量热能、活性氢以及其他热活性气体和酸蒸汽。HRA 化合物的选择及其数量和浓度是根据每个领域的具体情况而定的。 西科威特（WK）业务案例。西科威特地区的 M 油层是一个碳酸盐岩多裂缝致密储层，多年来一直在生产，但采收率开始下降。其中一些油井因致密地层特征和低压而出现生产率低的问题。即使采用常规酸性激励措施，也无法长时间维持生产。该储油层的碳酸盐岩储油层厚度为 300 英尺，70% 的石油位于顶层。该油藏被归类为致密油藏（平均渗透率小于 0.1-10 md，孔隙度为 10-25%），有 10 层多层裂缝。尽管在 M 油层钻探了许多垂直井、水平井和多边井，但采收率仅为 1-3%。石油被认为是非粘性的（28 cp，21 °API）。目前的刺激方法包括常规酸性刺激和多级压裂，前者的效果不佳，后者的效果则好坏参半。科威特北部（NK）业务案例。该地区的致密 T 层储层连通性差。含水层的支撑作用极小，导致储层压力迅速下降。总体而言，石油流动性低、API 重力差和渗透率低是 T 层石油开采的主要障碍，此外还有储层异质性，如面分布、断裂模式和压力机制。该地层由沉积在碳酸盐岩斜坡上的致密石灰岩组成。储油层分为三个主要地层单元（上层，约 110 英尺；中层，约 60 英尺；下层，约 16 英尺）。储油层的孔隙度约为 14%，渗透率约为 14 md，充满了相对较低的 API 碳氢化合物（19-22 °API）。
{"title":"Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait","authors":"C. Carpenter","doi":"10.2118/0724-0096-jpt","DOIUrl":"https://doi.org/10.2118/0724-0096-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference.\u0000 \u0000 \u0000 \u0000 The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates.\u0000 \u0000 \u0000 \u0000 To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field.\u0000 \u0000 \u0000 \u0000 West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation.\u0000 The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API).\u0000 Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best.\u0000 North Kuwait (NK) Business Case.\u0000 The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes.\u0000 The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"100 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141695687","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214488, “Mechanical Evaluation and Intervention in Nonmetallic Tubulars Using Current Technologies,” by Mohamed Larbi Zeghlache, SPE, and Khaled Al-Muhammadi, Saudi Aramco, and Iqbal Pervaiz, SPE, Baker Hughes, et al. The paper has not been peer reviewed. With increasing interest in nonmetallic products, such as fiberglass tubing, for downhole applications, ensuring well integrity in a similar way as is achieved for standard carbon steel completions is essential. One important aspect of well integrity is the ability to routinely access the downhole condition of the tubing and perform basic interventions. The complete paper demonstrates testing and validation of different mechanical evaluations of the integrity of fiberglass tubing using logging and intervention tools. Fiber-reinforced polymer composites have been used efficiently for various structural applications, including primary structures for which safety is a major design requirement. Fiber-reinforced laminate is very sensitive to out-of-plane loading, however, because it exhibits relatively low transverse properties. The resulting impact damage in fiber-reinforced polymer composite usually reduces its postimpact mechanical properties. The damage phenomenology in fiber-reinforced polymer composites involves many different mechanisms of degradation. Contrary to metallic materials, fiber-reinforced polymer composites can experience damage evolution followed by a catastrophic failure without prior notice. The inspection and monitoring of such damage during a structure’s lifetime are very challenging. Moreover, classical nondestructive testing techniques are difficult to implement for real-time structural health monitoring (SHM). It is, therefore, important to develop a reliable SHM technique that can both increase safety and reduce operational costs by optimizing inspection and repair. Of common barrier-inspection technologies, cement evaluation using sonic and ultrasonic measurements is very challenging across coated or nonmetallic casing. In the case of nonmetallic pipes such as fiberglass and composite pipes, this measurement is yet to be investigated for proper transducer design and signal processing. Magnetic and electromagnetic technologies cannot be used for casing inspection because the pipe material is an insulator and prevents any current flow. The simplest and most straightforward technologies remaining are mechanical tools for inner wall inspection. For this reason, testing was conducted to evaluate the effectiveness of multifinger caliper (MFC) logging in fiberglass casing and to simulate intervention operation through puncher and cutter services. An MFC is a mechanical tool that provides, through its fingers, high-resolution accurate radial measurements of internal diameter of tubing or casing string. MFCs are used to detect very small changes to the i
{"title":"Study Conducts Mechanical Evaluation of Nonmetallic Tubulars","authors":"C. Carpenter","doi":"10.2118/0724-0085-jpt","DOIUrl":"https://doi.org/10.2118/0724-0085-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214488, “Mechanical Evaluation and Intervention in Nonmetallic Tubulars Using Current Technologies,” by Mohamed Larbi Zeghlache, SPE, and Khaled Al-Muhammadi, Saudi Aramco, and Iqbal Pervaiz, SPE, Baker Hughes, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 With increasing interest in nonmetallic products, such as fiberglass tubing, for downhole applications, ensuring well integrity in a similar way as is achieved for standard carbon steel completions is essential. One important aspect of well integrity is the ability to routinely access the downhole condition of the tubing and perform basic interventions. The complete paper demonstrates testing and validation of different mechanical evaluations of the integrity of fiberglass tubing using logging and intervention tools.\u0000 \u0000 \u0000 \u0000 Fiber-reinforced polymer composites have been used efficiently for various structural applications, including primary structures for which safety is a major design requirement. Fiber-reinforced laminate is very sensitive to out-of-plane loading, however, because it exhibits relatively low transverse properties. The resulting impact damage in fiber-reinforced polymer composite usually reduces its postimpact mechanical properties. The damage phenomenology in fiber-reinforced polymer composites involves many different mechanisms of degradation. Contrary to metallic materials, fiber-reinforced polymer composites can experience damage evolution followed by a catastrophic failure without prior notice. The inspection and monitoring of such damage during a structure’s lifetime are very challenging. Moreover, classical nondestructive testing techniques are difficult to implement for real-time structural health monitoring (SHM). It is, therefore, important to develop a reliable SHM technique that can both increase safety and reduce operational costs by optimizing inspection and repair.\u0000 \u0000 \u0000 \u0000 Of common barrier-inspection technologies, cement evaluation using sonic and ultrasonic measurements is very challenging across coated or nonmetallic casing. In the case of nonmetallic pipes such as fiberglass and composite pipes, this measurement is yet to be investigated for proper transducer design and signal processing. Magnetic and electromagnetic technologies cannot be used for casing inspection because the pipe material is an insulator and prevents any current flow. The simplest and most straightforward technologies remaining are mechanical tools for inner wall inspection. For this reason, testing was conducted to evaluate the effectiveness of multifinger caliper (MFC) logging in fiberglass casing and to simulate intervention operation through puncher and cutter services.\u0000 \u0000 \u0000 \u0000 An MFC is a mechanical tool that provides, through its fingers, high-resolution accurate radial measurements of internal diameter of tubing or casing string. MFCs are used to detect very small changes to the i","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"51 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699229","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 article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23730,“Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field,” by Guido Bascialla, SPE, ADNOC, and Coriolan Rat and Soham Sheth, SLB, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Compositional reservoir simulation is a time-intensive activity demanding complex physics. In the complete paper, the authors review the advantages of machine learning (ML) in complex compositional reservoir simulations to determine fluid properties such as critical temperature and saturation pressure. An ML approach to predict critical temperatures during simulation based on the Heidemann-Khalil method is implemented, resulting in more-accurate results with lower computational cost, outperforming the standard method and improving performance on a giant field model with compositional gradient and miscible gas injection. The case study refers to a giant offshore carbonate field composed of multiple reservoirs. Production is currently in a rampup phase; crestal miscible hydrocarbon gas injection was implemented soon after startup. The availability of high-potential gas producers as a source of makeup gas and the placement of peripheral water injectors maintains the reservoir pressure above minimum miscibility pressure. All reservoirs show complex variable slope compositional gradients along thick oil columns of hundreds of feet (Fig. 1). To match the fluid behavior and the variation of fluid properties with depth, the equation of state needs at least nine components. The rock quality mainly is controlled by diagenesis. Thirteen rock types were modeled. The permeability can change up to four log cycles for the same porosity. Most of the reservoirs are highly heterogeneous, with features such as high-permeability streaks and baffle zones. A wide range of capillary pressure curves is present; these mainly depend on permeability and lithology. Most development wells were completed with inflow control devices (ICDs) to control gas and water breakthroughs and optimize oil production. The combination of numerous ICDs and long slanted production intervals (i.e., thousands of feet) make wellbore-reservoir coupling critical for proper history matching and forecasting. The model grid size in the horizontal direction is 328 ft, which is considered optimal according to simulated sensitivities. The vertical layering is very fine in order to capture the reservoir heterogeneity; the cell thickness ranges from 1 to 1.5 ft. This results in a model with 3.5 million active cells, which makes the simulation performance and run time very challenging when coupled with compositional gradient and ICDs. In this section of the complete paper, the authors review why accurate phase labeling is important in compositional simulation and how it can lead to convergence problems, par
本文由JPT技术编辑Chris Carpenter撰写，收录了IPTC 23730号论文 "Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field "的要点，作者是Guido Bascialla、SPE、ADNOC、Coriolan Rat和SolB的Soham Sheth等人。 该论文未经同行评审。版权归 2024 年国际石油技术大会所有。 成分储层模拟是一项时间密集型活动，需要复杂的物理学知识。在这篇完整的论文中，作者回顾了机器学习（ML）在复杂成分储层模拟中的优势，以确定临界温度和饱和压力等流体属性。论文基于 Heidemann-Khalil 方法，采用 ML 方法在模拟过程中预测临界温度，结果更精确，计算成本更低，优于标准方法，并提高了具有成分梯度和混杂气注入的巨型油气田模型的性能。 案例研究涉及一个由多个储层组成的巨型海上碳酸盐岩油田。目前正处于增产阶段；启动后不久就实施了嵴晶混溶碳氢化合物气体注入。高潜力产气机作为补充气源，外围注水器的布置使储层压力保持在最低混溶压力之上。沿数百英尺厚的油柱，所有储层都显示出复杂的变斜率成分梯度（图 1）。为了与流体行为和流体性质随深度的变化相匹配，状态方程至少需要九个组成部分。岩石质量主要由成岩作用控制。模拟了 13 种岩石类型。在孔隙度相同的情况下，渗透率最多可变化四个测井周期。大多数储层高度异质，具有高渗透率条纹和挡板带等特征。毛管压力曲线的范围很广，主要取决于渗透率和岩性。大多数开发井都安装了流入控制装置（ICD），以控制气体和水的突破，优化石油生产。大量的 ICD 和较长的倾斜生产间隔（即数千英尺）使得井筒-储层耦合对于正确的历史匹配和预测至关重要。水平方向上的模型网格尺寸为 328 英尺，根据模拟敏感性，该尺寸被认为是最佳的。为了捕捉储层的异质性，垂直分层非常细；单元厚度在 1 到 1.5 英尺之间。这导致模型有 350 万个活动单元，当与成分梯度和 ICD 相结合时，模拟性能和运行时间都非常具有挑战性。 在完整论文的这一部分，作者回顾了为什么精确的相位标注在成分模拟中非常重要，以及它如何导致收敛问题，特别是在有气体注入的情况下。在一个使用复杂假流体模型的简单模型上，将传统方法与 ML 方法进行了比较，以突出在更复杂的模拟模型中可能出现的问题。
{"title":"Physics-Informed Machine Learning Applied to Complex Compositional Model in a Giant Field","authors":"C. Carpenter","doi":"10.2118/0724-0068-jpt","DOIUrl":"https://doi.org/10.2118/0724-0068-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23730,“Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field,” by Guido Bascialla, SPE, ADNOC, and Coriolan Rat and Soham Sheth, SLB, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 Compositional reservoir simulation is a time-intensive activity demanding complex physics. In the complete paper, the authors review the advantages of machine learning (ML) in complex compositional reservoir simulations to determine fluid properties such as critical temperature and saturation pressure. An ML approach to predict critical temperatures during simulation based on the Heidemann-Khalil method is implemented, resulting in more-accurate results with lower computational cost, outperforming the standard method and improving performance on a giant field model with compositional gradient and miscible gas injection.\u0000 \u0000 \u0000 \u0000 The case study refers to a giant offshore carbonate field composed of multiple reservoirs. Production is currently in a rampup phase; crestal miscible hydrocarbon gas injection was implemented soon after startup. The availability of high-potential gas producers as a source of makeup gas and the placement of peripheral water injectors maintains the reservoir pressure above minimum miscibility pressure. All reservoirs show complex variable slope compositional gradients along thick oil columns of hundreds of feet (Fig. 1). To match the fluid behavior and the variation of fluid properties with depth, the equation of state needs at least nine components.\u0000 The rock quality mainly is controlled by diagenesis. Thirteen rock types were modeled. The permeability can change up to four log cycles for the same porosity. Most of the reservoirs are highly heterogeneous, with features such as high-permeability streaks and baffle zones. A wide range of capillary pressure curves is present; these mainly depend on permeability and lithology.\u0000 Most development wells were completed with inflow control devices (ICDs) to control gas and water breakthroughs and optimize oil production. The combination of numerous ICDs and long slanted production intervals (i.e., thousands of feet) make wellbore-reservoir coupling critical for proper history matching and forecasting. The model grid size in the horizontal direction is 328 ft, which is considered optimal according to simulated sensitivities. The vertical layering is very fine in order to capture the reservoir heterogeneity; the cell thickness ranges from 1 to 1.5 ft. This results in a model with 3.5 million active cells, which makes the simulation performance and run time very challenging when coupled with compositional gradient and ICDs.\u0000 \u0000 \u0000 \u0000 In this section of the complete paper, the authors review why accurate phase labeling is important in compositional simulation and how it can lead to convergence problems, par","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"1973 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141707434","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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