Currently, the crude oil from outstations (O/STN) wellsite contributes more than 30% of the total Sirikit Oilfileds (S1) production and will be increased to 50% of total production of Sirikit Oilfileds. According to the production profile of the NTM-A areas, NTM-A Onshore permanent production facilities are more likely to handle the higher gross production rate to up 20,000 BPD. Thus, it is essential to debottleneck NTM-A to handle the new gross production rate. The existing capacity of NTM-A permanent production facilities is 13,000 BPD. In order to debottleneck NTM-A's capacity to 20,000 BPD, the capacities of the production separators, the indirect gas fired heaters, the storage tanks, the water injection system, and the utilities were re-verified at different percent water cuts. To minimize the project cost, all of new equipment was designed by our in-house engineering team. Lessons learned from the previous projects were taken into account and incorporated with the new design.
{"title":"Unlock Oil Production in Production Facility by in House and Lean Design with Significant Cost Saving","authors":"Auttapon Rungchaya, Pimpisa Pechvijitra, Arak Yongchooyot, Kantkanit Watanakun, Saranee Nitayaphan, Anoma Chutrapukdeekul","doi":"10.2523/iptc-22732-ea","DOIUrl":"https://doi.org/10.2523/iptc-22732-ea","url":null,"abstract":"\u0000 \u0000 \u0000 Currently, the crude oil from outstations (O/STN) wellsite contributes more than 30% of the total Sirikit Oilfileds (S1) production and will be increased to 50% of total production of Sirikit Oilfileds. According to the production profile of the NTM-A areas, NTM-A Onshore permanent production facilities are more likely to handle the higher gross production rate to up 20,000 BPD. Thus, it is essential to debottleneck NTM-A to handle the new gross production rate.\u0000 \u0000 \u0000 \u0000 The existing capacity of NTM-A permanent production facilities is 13,000 BPD. In order to debottleneck NTM-A's capacity to 20,000 BPD, the capacities of the production separators, the indirect gas fired heaters, the storage tanks, the water injection system, and the utilities were re-verified at different percent water cuts. To minimize the project cost, all of new equipment was designed by our in-house engineering team. Lessons learned from the previous projects were taken into account and incorporated with the new design.\u0000","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129605592","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}
M. Aldawsari, Abdullah Alsulaim, R. Khamatdinov, Johannes Vossen
Nowadays tight oil and gas reservoirs all around the world are increasingly exploited using wells where hydraulic fracturing is an essential technique to enable commercial productivity. In the case of a low permeability sandstone gas reservoir, understanding geological environment and selection of the optimal hydraulic fracturing design and implementation is key to obtain sustainable flow rates. Analysis of performed frac jobs and well performance across one field with 6 gas offset wells is reviewed in this paper. Wells analyzed in this paper were all drilled into a shaly sandstone reservoir, with a high probability of including a favorable net-to-gross ratio of reservoir quality sandstones. The reservoir properties of these sandstone formations vary from a well to another with an average reservoir pressure of 5,500 psi – 8,500 psi, average reservoir temperature of 300 deg F, average reservoir porosity of 6-10% and average permeability between 0.5 – 4 mD. These reservoir properties are indication of tight reservoir where hydraulic fracturing is an essential technique to enable commercial productivity from the wells as well as controlling proppant and sands flowback. In most cases, 20/40 HSP and 20/40 RC-HSP proppant types were used in frac operations to provide the required conductivity in the reservoir and also control the proppant and sand from being flowed back to the surface. In addition to the proppant type, high final proppant concentration was also one of the key parameters to ensure proppant packing is achieved at the end of the job and help minimizing proppant flow back. High level analysis of the wells production histories across the field will help to determine main factors affecting the well performance.
{"title":"Hydraulic Fracturing Practices for Sustainable Production in Gas Wells: Approach, Methodology, Results, and Comparison with Offset Gas Wells Case Histories","authors":"M. Aldawsari, Abdullah Alsulaim, R. Khamatdinov, Johannes Vossen","doi":"10.2523/iptc-23077-ea","DOIUrl":"https://doi.org/10.2523/iptc-23077-ea","url":null,"abstract":"\u0000 Nowadays tight oil and gas reservoirs all around the world are increasingly exploited using wells where hydraulic fracturing is an essential technique to enable commercial productivity. In the case of a low permeability sandstone gas reservoir, understanding geological environment and selection of the optimal hydraulic fracturing design and implementation is key to obtain sustainable flow rates. Analysis of performed frac jobs and well performance across one field with 6 gas offset wells is reviewed in this paper.\u0000 Wells analyzed in this paper were all drilled into a shaly sandstone reservoir, with a high probability of including a favorable net-to-gross ratio of reservoir quality sandstones. The reservoir properties of these sandstone formations vary from a well to another with an average reservoir pressure of 5,500 psi – 8,500 psi, average reservoir temperature of 300 deg F, average reservoir porosity of 6-10% and average permeability between 0.5 – 4 mD. These reservoir properties are indication of tight reservoir where hydraulic fracturing is an essential technique to enable commercial productivity from the wells as well as controlling proppant and sands flowback. In most cases, 20/40 HSP and 20/40 RC-HSP proppant types were used in frac operations to provide the required conductivity in the reservoir and also control the proppant and sand from being flowed back to the surface. In addition to the proppant type, high final proppant concentration was also one of the key parameters to ensure proppant packing is achieved at the end of the job and help minimizing proppant flow back.\u0000 High level analysis of the wells production histories across the field will help to determine main factors affecting the well performance.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125882596","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}
Ramy Saadeldin, H. Gamal, S. Elkatatny, A. Abdulraheem, D. A. Al Shehri
During the drilling operations and because of the harsh downhole drilling environment, the drill string suffered from downhole vibrations that affect the drilling operation and equipment. This problem is greatly affecting the downhole tools (wear and tear), hole problems (wash-out), mechanical energy loss, and ineffective drilling performance. Extra non-productive time to address these complications during the operation, and hence, extra cost. Detecting the drillstring vibrations during drilling through the downhole sensors is costly due to the extra service and downhole sensors. Currently, the new-technology-based solutions are providing huge capabilities to deal intelligently with the data, and machine learning applications provide high computational competencies to learn and correlate the parameters for technical complex problems. Consequently, the objective of this paper is to develop a machine learning model for predicting the drillstring vibration while drilling using machine learning via artificial neural networks (ANN) for horizontal section drilling. The developed ANN model was designed to only implement the surface rig sensors drilling data as inputs to predict the downhole drilling vibrations (axial, lateral, and torsional). The research used 5000 data set from drilling operation of a horizontal section. The model accuracy was evaluated using two metrics and the obtained results after optimizing the ANN model parameters showed a high accuracy with a correlation coefficient R higher than 0.97 and average absolute percentage error below 2.6%. Based on these results, a developed ANN algorithm can predict vibration while drilling using only surface drilling parameters which ends up with saving the deployment of the downhole sensors.
{"title":"Intelligent Prediction of Downhole Drillstring Vibrations in Horizontal Wells by Employing Artificial Neural Network","authors":"Ramy Saadeldin, H. Gamal, S. Elkatatny, A. Abdulraheem, D. A. Al Shehri","doi":"10.2523/iptc-23027-ms","DOIUrl":"https://doi.org/10.2523/iptc-23027-ms","url":null,"abstract":"\u0000 During the drilling operations and because of the harsh downhole drilling environment, the drill string suffered from downhole vibrations that affect the drilling operation and equipment. This problem is greatly affecting the downhole tools (wear and tear), hole problems (wash-out), mechanical energy loss, and ineffective drilling performance. Extra non-productive time to address these complications during the operation, and hence, extra cost. Detecting the drillstring vibrations during drilling through the downhole sensors is costly due to the extra service and downhole sensors. Currently, the new-technology-based solutions are providing huge capabilities to deal intelligently with the data, and machine learning applications provide high computational competencies to learn and correlate the parameters for technical complex problems. Consequently, the objective of this paper is to develop a machine learning model for predicting the drillstring vibration while drilling using machine learning via artificial neural networks (ANN) for horizontal section drilling. The developed ANN model was designed to only implement the surface rig sensors drilling data as inputs to predict the downhole drilling vibrations (axial, lateral, and torsional). The research used 5000 data set from drilling operation of a horizontal section. The model accuracy was evaluated using two metrics and the obtained results after optimizing the ANN model parameters showed a high accuracy with a correlation coefficient R higher than 0.97 and average absolute percentage error below 2.6%. Based on these results, a developed ANN algorithm can predict vibration while drilling using only surface drilling parameters which ends up with saving the deployment of the downhole sensors.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114460363","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 H.T.M.S Underwater Learning Sites Project is initiated in 2010 with the main objectives to rehabilitate marine ecology by reusing the decommissioned battleships, namely H.T.M.S. Prab and H.T.M.S. Sattakut, as a new home of marine life and sessile organisms, to enrich the marine biodiversity, to be the learning sites of marine life in long-term basis, and to create new diving sites to attract the tourists, reduce the effects on natural coral reefs from harmful activities such as tourist boat anchoring or mooring onto them, scuba diving damage by touching or stirring up sand sediments, as well as generate a considerable income for local communities. PTTEP has engaged government agencies, academic institutions, local businesses, and communities to consider the most suitable structure to be used as a new underwater learning site. In 2011, after studying man-made reefs and ensuring the minimal impact on marine ecology, two decommissioned ships offered by the Royal Thai Navy were placed underwater at Koh Ngam Noi and Koh Tao in southern Thailand, the world's famous scuba diving destinations. The underwater ecosystem and biodiversity study has also been conducted before and after the installation of two ships including the study on environmental impact, marine biodiversity, and impact on natural coral reefs. The study in 2018 showing the increasing number of small fish from 10 species in 2011 to more than 60 species that reflected the increasing of marine ecology and biodiversity. A recent study shows that these man-made diving sites helped reducing number of touching coral reefs for 16,058,800 times since 2014. Moreover, there was no significant impact on the conditions of the seabed in every area studied. The number of tourists and divers are growing up 37.7% at Koh Ngam Noi, Chumphon province and 18.8% at Koh Tao, Surat Thani province which were able to boost community's economy. The project has generated income to local communities with more than 413 million THB (12.5 million USD) or 59 million THB (1.8 million USD) annually. In 2017, the project was measured by using Social Return on Investment (SROI) method with the satisfied outcome as 5.34:1 (THB) which means for every 1 THB invested in the program, created 5.34 THB in societal benefit. Moreover, the project has generated positive media exposure through activities with PR value of over 55.7 million THB (1.7 million USD) since 2011, raising awareness on marine ecology conservation and contribution to the company's reputation. These battleship-man-made dive sites will be in service for more than 60 years and the study on marine ecology and biodiversity will be continuously conducted from time to time to ensure the sustainability in marine ecology. The achievement of this project benefits to petroleum industry by creating public perception and understanding of man-made reef which could be beneficial to Rigs-to-Reefs, as the sound practice of converting decommissioned
{"title":"Final Mission of Battleships: A Beginning of Hope for New Lives","authors":"Bussaban Cheencharoen, Suphachittra Thongchavee, Sasithorn Tangthienkul, Supphapong Pongjit, Piyawat Sujirachato","doi":"10.2523/iptc-22709-ea","DOIUrl":"https://doi.org/10.2523/iptc-22709-ea","url":null,"abstract":"\u0000 \u0000 \u0000 The H.T.M.S Underwater Learning Sites Project is initiated in 2010 with the main objectives to rehabilitate marine ecology by reusing the decommissioned battleships, namely H.T.M.S. Prab and H.T.M.S. Sattakut, as a new home of marine life and sessile organisms, to enrich the marine biodiversity, to be the learning sites of marine life in long-term basis, and to create new diving sites to attract the tourists, reduce the effects on natural coral reefs from harmful activities such as tourist boat anchoring or mooring onto them, scuba diving damage by touching or stirring up sand sediments, as well as generate a considerable income for local communities.\u0000 \u0000 \u0000 \u0000 PTTEP has engaged government agencies, academic institutions, local businesses, and communities to consider the most suitable structure to be used as a new underwater learning site. In 2011, after studying man-made reefs and ensuring the minimal impact on marine ecology, two decommissioned ships offered by the Royal Thai Navy were placed underwater at Koh Ngam Noi and Koh Tao in southern Thailand, the world's famous scuba diving destinations. The underwater ecosystem and biodiversity study has also been conducted before and after the installation of two ships including the study on environmental impact, marine biodiversity, and impact on natural coral reefs.\u0000 \u0000 \u0000 \u0000 The study in 2018 showing the increasing number of small fish from 10 species in 2011 to more than 60 species that reflected the increasing of marine ecology and biodiversity. A recent study shows that these man-made diving sites helped reducing number of touching coral reefs for 16,058,800 times since 2014. Moreover, there was no significant impact on the conditions of the seabed in every area studied. The number of tourists and divers are growing up 37.7% at Koh Ngam Noi, Chumphon province and 18.8% at Koh Tao, Surat Thani province which were able to boost community's economy. The project has generated income to local communities with more than 413 million THB (12.5 million USD) or 59 million THB (1.8 million USD) annually. In 2017, the project was measured by using Social Return on Investment (SROI) method with the satisfied outcome as 5.34:1 (THB) which means for every 1 THB invested in the program, created 5.34 THB in societal benefit. Moreover, the project has generated positive media exposure through activities with PR value of over 55.7 million THB (1.7 million USD) since 2011, raising awareness on marine ecology conservation and contribution to the company's reputation.\u0000 \u0000 \u0000 \u0000 These battleship-man-made dive sites will be in service for more than 60 years and the study on marine ecology and biodiversity will be continuously conducted from time to time to ensure the sustainability in marine ecology. The achievement of this project benefits to petroleum industry by creating public perception and understanding of man-made reef which could be beneficial to Rigs-to-Reefs, as the sound practice of converting decommissioned ","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134368519","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper explains how digital enabler can help an organization enhance the Safety, Security, Health, and Environmental (SSHE) awareness of employees and contractors and compliance with SSHE requirements. The unique features of digital enabler are creatively designed to provide a set of solutions for managing SSHE data that meet the needs of the oil and gas industry. It is an innovative digital solution that helps the organization achieve excellent SSHE performance. The PTTEP digital enabler, iSSHE, is developed to support the SSHE management system and respond to current and emerging SSHE challenges. It can help an organization collect, manage, and analyze SSHE data to prevent incidents while maintaining operations, complying with regulatory changes, and improving sustainability. Reporting SSHE data is just the beginning. With iSSHE, on the other hand, we can shift our focus from reactive compliance with applicable requirements to proactive performance management with an integrated SSHE management approach. The goal of iSSHE is to ensure SSHE data and resources are well-collected, managed, and shared across business units to fuel forward-looking results for continuous SSHE performance improvement. This integrated approach connects stakeholders, information, and insights across the entire risk value chain. iSSHE solution combines a responsive, configurable, and intuitive cloud-based platform. It enables better decisions and optimizes SSHE performance. Adopting SSHE digital technology transforms all SSHE-related information and implementation by replacing non-digital or manual processes with digital ones. The key benefits of utilizing digital enablers to support the SSHE management system are as follows: Reducing the scope for errors in data reporting Saving time while increasing productivity Improving SSHE performance Connecting employees and contractors across different departments and locations in the organization Standardizing and centralizing SSHE data Lessening risks and building safety awareness Helping manage regulations and stay compliant Serving to predict future performance with analytics of historical data Driving insights that enable better and more sustainability decisions
{"title":"Utilizing Digital Enabler to Attain Excellent Safety, Security, Health, and Environmental Performance","authors":"Wannoptida Tiengtrong, Rachamon Suwannaposi, Chagun Klunngien","doi":"10.2523/iptc-22717-ea","DOIUrl":"https://doi.org/10.2523/iptc-22717-ea","url":null,"abstract":"\u0000 This paper explains how digital enabler can help an organization enhance the Safety, Security, Health, and Environmental (SSHE) awareness of employees and contractors and compliance with SSHE requirements. The unique features of digital enabler are creatively designed to provide a set of solutions for managing SSHE data that meet the needs of the oil and gas industry. It is an innovative digital solution that helps the organization achieve excellent SSHE performance.\u0000 The PTTEP digital enabler, iSSHE, is developed to support the SSHE management system and respond to current and emerging SSHE challenges. It can help an organization collect, manage, and analyze SSHE data to prevent incidents while maintaining operations, complying with regulatory changes, and improving sustainability. Reporting SSHE data is just the beginning. With iSSHE, on the other hand, we can shift our focus from reactive compliance with applicable requirements to proactive performance management with an integrated SSHE management approach.\u0000 The goal of iSSHE is to ensure SSHE data and resources are well-collected, managed, and shared across business units to fuel forward-looking results for continuous SSHE performance improvement. This integrated approach connects stakeholders, information, and insights across the entire risk value chain.\u0000 iSSHE solution combines a responsive, configurable, and intuitive cloud-based platform. It enables better decisions and optimizes SSHE performance. Adopting SSHE digital technology transforms all SSHE-related information and implementation by replacing non-digital or manual processes with digital ones.\u0000 The key benefits of utilizing digital enablers to support the SSHE management system are as follows:\u0000 Reducing the scope for errors in data reporting Saving time while increasing productivity Improving SSHE performance Connecting employees and contractors across different departments and locations in the organization Standardizing and centralizing SSHE data Lessening risks and building safety awareness Helping manage regulations and stay compliant Serving to predict future performance with analytics of historical data Driving insights that enable better and more sustainability decisions","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133617536","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}
Suthasinee Jinarakpong, S. Punpruk, S. Kumseranee, Thirawat Sanitmuang, Nopphan Rattanasombattawee
Reinforced Thermoplastic Pipe (RTP) is one of the solutions considered using instead of metal pipe to avoid the corrosion problem. As RTP is a non-metallic pipe that is subjected to damage or deformation when get fire. A protective fireproof system is required to protect RTP from cellulosic fire for at least 2 hours. and pipe surface temperature not over 82 °C per RTP specification and should be reusable and has a long service life. From the performance test results, there are two materials of PFP (Passive Fire Projection) that passed the requirement. One is intumescent (Composite fiber glass fabric with external polyurethane "PU" coating 0.7 mm.) and the other one is rockwool insulation (Reflective heat guard 3 mm. + Rockwool insulation 50 mm. + Aluminium 1 mm.). The rising of the surface temperature of the Reinforced Thermoplastic Pipe (RTP) is in the acceptable criteria. The RTP pipe appearance is still in good condition. For PFP appearance, the intumescent will be damaged after burning while rockwool insulation is not changed and is reusable. In terms of material cost, the price of intumescent including material cost and installation cost is lower by about 20%. Both options are interesting and shall be considered again for usage purposes. Replacement of metal pipe with spoolable pipe with PFP has advantages in terms of low maintenance cost and higher corrosion resistance. The Reinforced Thermoplastic Pipe with PFP can be installed on existing pipe support with enough space for inspection. This solution can eliminate the weak point of RTP and allows the application of RTP without pull through carbon steel pipe. The PFP rockwool insulation is a good option to protect pipeline damage from unpredictable fire with low material and installation costs.
增强热塑性塑料管材(RTP)是替代金属管材避免腐蚀问题的解决方案之一。由于RTP是一种非金属管道，在火灾中容易损坏或变形。需要一个保护性防火系统来保护RTP免受纤维素燃烧至少2小时。根据RTP规范，管道表面温度不超过82°C，应可重复使用，使用寿命长。从性能测试结果来看，有两种PFP (Passive Fire Projection)材料通过了要求。一种是膨胀型(复合纤维玻璃布外涂聚氨酯“PU”0.7 mm)，另一种是岩棉保温(反射热罩3mm . +岩棉保温50mm . +铝1mm .)。增强热塑性管(RTP)表面温度的上升在可接受的范围内。RTP管外观仍然完好。对于PFP外观，燃烧后会损坏膨胀体，而岩棉保温不改变，可重复使用。在材料成本方面，膨胀的价格包括材料成本和安装成本降低了20%左右。这两种选择都很有趣，应该再次考虑使用目的。PFP用线轴管代替金属管具有维护成本低、耐腐蚀性能高等优点。带有PFP的增强热塑性管可以安装在现有的管道支架上，并有足够的空间进行检查。这种解决方案可以消除RTP的弱点，使RTP的应用不需要通过碳钢管进行拉拔。PFP岩棉保温材料是一种很好的选择，可以保护管道免受不可预测的火灾的损害，而且材料和安装成本都很低。
{"title":"Innovative Fireproof Insulation for Safe Operation of Non-Metallic Pipe","authors":"Suthasinee Jinarakpong, S. Punpruk, S. Kumseranee, Thirawat Sanitmuang, Nopphan Rattanasombattawee","doi":"10.2523/iptc-23082-ea","DOIUrl":"https://doi.org/10.2523/iptc-23082-ea","url":null,"abstract":"\u0000 Reinforced Thermoplastic Pipe (RTP) is one of the solutions considered using instead of metal pipe to avoid the corrosion problem. As RTP is a non-metallic pipe that is subjected to damage or deformation when get fire. A protective fireproof system is required to protect RTP from cellulosic fire for at least 2 hours. and pipe surface temperature not over 82 °C per RTP specification and should be reusable and has a long service life.\u0000 From the performance test results, there are two materials of PFP (Passive Fire Projection) that passed the requirement. One is intumescent (Composite fiber glass fabric with external polyurethane \"PU\" coating 0.7 mm.) and the other one is rockwool insulation (Reflective heat guard 3 mm. + Rockwool insulation 50 mm. + Aluminium 1 mm.). The rising of the surface temperature of the Reinforced Thermoplastic Pipe (RTP) is in the acceptable criteria. The RTP pipe appearance is still in good condition. For PFP appearance, the intumescent will be damaged after burning while rockwool insulation is not changed and is reusable. In terms of material cost, the price of intumescent including material cost and installation cost is lower by about 20%. Both options are interesting and shall be considered again for usage purposes. Replacement of metal pipe with spoolable pipe with PFP has advantages in terms of low maintenance cost and higher corrosion resistance. The Reinforced Thermoplastic Pipe with PFP can be installed on existing pipe support with enough space for inspection. This solution can eliminate the weak point of RTP and allows the application of RTP without pull through carbon steel pipe. The PFP rockwool insulation is a good option to protect pipeline damage from unpredictable fire with low material and installation costs.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133947222","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}
Baosen Zhang, Xin Jin, Yitian Xiao, Yunzhe Hou, Jin Meng, Zhenkai Huang, Meng Han
Quantitative identification of sandstone microscopic images is an essential task for sandstone reservoir characterization. The widely-used classical Gazzi-Dickinson point-counting method can be subjective, inconsistent and time-consuming. Furthermore, by directly putting labeled microscopic images of all rock types into image recognition models for training, most previous studies did not address the petrographic principle of artificial identification. In this study, U-Net and U-Net++ semantic segmentation networks that incorporated the sandstone petrographic principle in quantitative identification of sandstone was introduced. Automatic identification of sandstone microscopic images requires prior knowledge learned from the identified sandstones with similar compositions. First, hundreds of thin-sections of typical sandstone reservoirs were selected from several key petroleum basins in China. Second, one-to-one single and orthogonal polarized images were taken for them. Third, the annotation software was used to label the type of each skeleton grain, including quartz, feldspar, lithic fragment and pore. Finally, 480 sets of data, each of which includes single and orthogonal polarized images and their ".json" format annotation results, were obtained for training and testing of the U-Net model to quantitatively analyze sandstone microscopic images. Within the 480 sets of data, 6798 sandstone skeleton grains, including 4542 quartzes, 796 feldspars, 1248 lithic fragments and 212 pores were labeled. The sandstone thin-section quantitative identification model trained by 392 data sets achieved a training accuracy of 96% with the intersection over union at 78% for quartz, and a training accuracy of 88% with the intersection over union at 56% for lithic fragments. The remaining 88 data sets were used for testing, and the accuracy was 87% with its intersection over union at 74% for quartz and a training accuracy of 77% with the intersection over union at 54% for lithic fragments. As a classic fully convolutional network that excels in processing medical images, the U-Net or U-Net++ semantic segmentation network has also performed very well in quantitative identification of sandstone microscopic images. After the proportion of each sandstone skeleton grain has been identified, the simple subdivision descriptive petrographic classification of the sandstone was determined according to the classic Dickinson sandstone taxonomic criteria. In other words, most current deep learning algorithms classify sandstones at the bulk rock level, but this U-Net model has been extended to the mineral level for comprehensive identification. Our vision-based sandstone lithology identification model has not only improved the accuracy of artificial identification but also reduced the instability and subjectivity of the traditional manual processing and expert decision-making approach. In the future, we plan to increase the number and coverage of labeled thin-section images
{"title":"Quantitative Identification of Sandstone Lithology Based On Thin-Section Micrographs Using the U-net and U-net++ Semantic Segmentation Network","authors":"Baosen Zhang, Xin Jin, Yitian Xiao, Yunzhe Hou, Jin Meng, Zhenkai Huang, Meng Han","doi":"10.2523/iptc-22865-ea","DOIUrl":"https://doi.org/10.2523/iptc-22865-ea","url":null,"abstract":"\u0000 Quantitative identification of sandstone microscopic images is an essential task for sandstone reservoir characterization. The widely-used classical Gazzi-Dickinson point-counting method can be subjective, inconsistent and time-consuming. Furthermore, by directly putting labeled microscopic images of all rock types into image recognition models for training, most previous studies did not address the petrographic principle of artificial identification. In this study, U-Net and U-Net++ semantic segmentation networks that incorporated the sandstone petrographic principle in quantitative identification of sandstone was introduced.\u0000 Automatic identification of sandstone microscopic images requires prior knowledge learned from the identified sandstones with similar compositions. First, hundreds of thin-sections of typical sandstone reservoirs were selected from several key petroleum basins in China. Second, one-to-one single and orthogonal polarized images were taken for them. Third, the annotation software was used to label the type of each skeleton grain, including quartz, feldspar, lithic fragment and pore. Finally, 480 sets of data, each of which includes single and orthogonal polarized images and their \".json\" format annotation results, were obtained for training and testing of the U-Net model to quantitatively analyze sandstone microscopic images.\u0000 Within the 480 sets of data, 6798 sandstone skeleton grains, including 4542 quartzes, 796 feldspars, 1248 lithic fragments and 212 pores were labeled. The sandstone thin-section quantitative identification model trained by 392 data sets achieved a training accuracy of 96% with the intersection over union at 78% for quartz, and a training accuracy of 88% with the intersection over union at 56% for lithic fragments. The remaining 88 data sets were used for testing, and the accuracy was 87% with its intersection over union at 74% for quartz and a training accuracy of 77% with the intersection over union at 54% for lithic fragments. As a classic fully convolutional network that excels in processing medical images, the U-Net or U-Net++ semantic segmentation network has also performed very well in quantitative identification of sandstone microscopic images. After the proportion of each sandstone skeleton grain has been identified, the simple subdivision descriptive petrographic classification of the sandstone was determined according to the classic Dickinson sandstone taxonomic criteria. In other words, most current deep learning algorithms classify sandstones at the bulk rock level, but this U-Net model has been extended to the mineral level for comprehensive identification. Our vision-based sandstone lithology identification model has not only improved the accuracy of artificial identification but also reduced the instability and subjectivity of the traditional manual processing and expert decision-making approach.\u0000 In the future, we plan to increase the number and coverage of labeled thin-section images","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133080912","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}
Multi-stage frac completions are frequently used to increase well productivity and meet the ever-growing energy demand. Commonly, each stage is isolated with a plug and these plugs need to be milled when the well is ready to be flowed back. Milling and flowback operations require extreme vigilance and close monitoring. This paper explains the use of a multiphase flowmeter to optimize milling and flowback operations and save water in deep, tight carbonate horizontal gas wells. Frac plug milling operations are best performed in balanced well conditions. Underbalance conditions cause unwanted gas flow with solids at surface, which will cause equipment damage, if not maanged well. Overbalance conditions result in excessive precious underground water loss and hinder wellbore clean-out. A multiphase flow meter was used at the wellhead to monitor fluid return rate during milling. By integrating coiled tubing pump rate, depth and pressure measurements with the multiphase meter readings, downhole well conditions were assessed and the milling parameters were optimized. Additinoally, flowback conditions were also measured and analyzed in real-time to optimize choke strategy to maximize water recovery and minimize flowback duration. Multiphase meters were used during milling and flowback operations for several horizontal gas wells with multistage frac completions. During milling, both water and Nitrogen were pumped into the wellbore to lighten the hydrostatic head and avoid fluid losses while circulating for wellbore clean-out. The operation efficiency was assessed based on the return rate of individual fluids at surface. Fluid losses into the formation and reservoir influx were quantified. The multiphase meter measurements allowed the operators to adjust choke size and wellhead pressure to maintain balanced conditions, and control the water-nitrogen pump rates. Accurately measuring oil, water and gas flow rates with high resolution also helped with determining the choke bean-up strategy to maximize frac fluid recovery for increased fracture conductivity, while minimizing the flowback duration. Monitoring the ratios of produced fluid rates helped evaluate the wellbore clean-up performance and take necessary action to increase clean-up efficiency. Changing well productivity over time was also quantified in real-time, which allowed to optimize the flowback end time with maximum achievable well productivity, without waiting to recover all the frac fluid. The data helped quantify the wellbore productivity with respect to the frac fluid recovery. The practices explained in this paper can improve frac plug milling and flowback operations. By closely monitoring surface returns through the multiphase meter, it will preserve valuable underground water resources, maximize fracture conductivity and wellbore productivity especially in sub-hydrostatic reservoirs, which are challenging to mill.
{"title":"Improving Frac-Plug Milling and Flowback Efficiency Through Multiphase Metering Application in Deep and Tight Carbonate Horizontal Gas Wells","authors":"Qassim I. Hashim, Fahad M. Ajmi, S. Sarac","doi":"10.2523/iptc-23081-ea","DOIUrl":"https://doi.org/10.2523/iptc-23081-ea","url":null,"abstract":"\u0000 Multi-stage frac completions are frequently used to increase well productivity and meet the ever-growing energy demand. Commonly, each stage is isolated with a plug and these plugs need to be milled when the well is ready to be flowed back. Milling and flowback operations require extreme vigilance and close monitoring. This paper explains the use of a multiphase flowmeter to optimize milling and flowback operations and save water in deep, tight carbonate horizontal gas wells.\u0000 Frac plug milling operations are best performed in balanced well conditions. Underbalance conditions cause unwanted gas flow with solids at surface, which will cause equipment damage, if not maanged well. Overbalance conditions result in excessive precious underground water loss and hinder wellbore clean-out. A multiphase flow meter was used at the wellhead to monitor fluid return rate during milling. By integrating coiled tubing pump rate, depth and pressure measurements with the multiphase meter readings, downhole well conditions were assessed and the milling parameters were optimized. Additinoally, flowback conditions were also measured and analyzed in real-time to optimize choke strategy to maximize water recovery and minimize flowback duration.\u0000 Multiphase meters were used during milling and flowback operations for several horizontal gas wells with multistage frac completions. During milling, both water and Nitrogen were pumped into the wellbore to lighten the hydrostatic head and avoid fluid losses while circulating for wellbore clean-out. The operation efficiency was assessed based on the return rate of individual fluids at surface. Fluid losses into the formation and reservoir influx were quantified. The multiphase meter measurements allowed the operators to adjust choke size and wellhead pressure to maintain balanced conditions, and control the water-nitrogen pump rates.\u0000 Accurately measuring oil, water and gas flow rates with high resolution also helped with determining the choke bean-up strategy to maximize frac fluid recovery for increased fracture conductivity, while minimizing the flowback duration. Monitoring the ratios of produced fluid rates helped evaluate the wellbore clean-up performance and take necessary action to increase clean-up efficiency. Changing well productivity over time was also quantified in real-time, which allowed to optimize the flowback end time with maximum achievable well productivity, without waiting to recover all the frac fluid. The data helped quantify the wellbore productivity with respect to the frac fluid recovery.\u0000 The practices explained in this paper can improve frac plug milling and flowback operations. By closely monitoring surface returns through the multiphase meter, it will preserve valuable underground water resources, maximize fracture conductivity and wellbore productivity especially in sub-hydrostatic reservoirs, which are challenging to mill.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"118 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116372154","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}
M. S. Magna Detto Calcaterra, M. Brignoli, G. Carpineta, Pierluigi Sedda
Hydraulic fracturing has been an industry standard for the past decades; however, most recent applications are performed in extreme down-hole conditions: complex stresses regime, extended reach sections, abnormal pressure and temperature gradients proved to be strenuous challenges, especially with limited time and budgets. This paper explores the challenges of designing, completing and fracturing High Temperature (HT) tight reservoirs. A novel approach to the problem was mandatory to account for thermal effects on stress regime to increase overall chances of success of stimulation treatments. This multi-disciplinary method interconnects petro-physics, rock mechanics, fluid dynamics and operations by combining data from literature and from the field with the purpose of providing a tailored solution to the new challenges ahead. Hydraulic fracturing in High Temperature reservoirs is indeed a demanding task, for which specialized products have been developed throughout time, such as for example, HT fracturing fluids. However, despite accounting for HT gradients, sometimes the outcomes of hydraulic fracturing activity were surprising or inexplicable; sometimes, even disappointing. Therefore, "post-mortem" reviews are often a must-do: data coming from the field and post-treatments results are analysed from scratch, wiping out any known-fact about the specific well and revising all the possible root causes for the anomalous behaviours. Petro-physical data, tectonic regime, stresses, hydraulic fracturing geometry and diagnostics were entirely accounted for to provide an explanation of the final well results, ultimately resulting in more questions than answers, as it so often happens with science. In drilling operations, the thermal effect of cold fluids on fracture gradients and its influence on losses has been deeply investigated, becoming an industry best practice. However, the effect of cool-down due to fluid injection at high rates with hydraulic fracturing applications are not captured by dedicated literature and, even less, by modelling softwares. As a result, a non-conventional approach to the creation of a geo-mechanical model that could take into account the thermal effect of cold frac fluids injection was elaborated and several sensitivities to understand fracture propagation mechanism were performed, highlighting a wide range of variability which is attributable to the influence of temperature on stress regime. High temperature reservoirs proved easier to frac than expected due to the decrease in terms of pressure required to initialize a fracture. However, this phenomenon could hide potential dangers when it is required to contain such fracture in the targeted interval. The correct modelling of such effect is of extreme importance to forecast fracture geometry, proppant placement and final conductivity requiring to re-adapt and re-adjust field-proven, industry-standardized hydraulic fracturing models and practices to match results with
{"title":"An Innovative Study to Predict Fracture Propagation in High Temperature Reservoirs with In-Situ Stresses Regime Affected by Cold Fluids Injections","authors":"M. S. Magna Detto Calcaterra, M. Brignoli, G. Carpineta, Pierluigi Sedda","doi":"10.2523/iptc-22747-ms","DOIUrl":"https://doi.org/10.2523/iptc-22747-ms","url":null,"abstract":"\u0000 Hydraulic fracturing has been an industry standard for the past decades; however, most recent applications are performed in extreme down-hole conditions: complex stresses regime, extended reach sections, abnormal pressure and temperature gradients proved to be strenuous challenges, especially with limited time and budgets.\u0000 This paper explores the challenges of designing, completing and fracturing High Temperature (HT) tight reservoirs. A novel approach to the problem was mandatory to account for thermal effects on stress regime to increase overall chances of success of stimulation treatments. This multi-disciplinary method interconnects petro-physics, rock mechanics, fluid dynamics and operations by combining data from literature and from the field with the purpose of providing a tailored solution to the new challenges ahead.\u0000 Hydraulic fracturing in High Temperature reservoirs is indeed a demanding task, for which specialized products have been developed throughout time, such as for example, HT fracturing fluids. However, despite accounting for HT gradients, sometimes the outcomes of hydraulic fracturing activity were surprising or inexplicable; sometimes, even disappointing. Therefore, \"post-mortem\" reviews are often a must-do: data coming from the field and post-treatments results are analysed from scratch, wiping out any known-fact about the specific well and revising all the possible root causes for the anomalous behaviours. Petro-physical data, tectonic regime, stresses, hydraulic fracturing geometry and diagnostics were entirely accounted for to provide an explanation of the final well results, ultimately resulting in more questions than answers, as it so often happens with science.\u0000 In drilling operations, the thermal effect of cold fluids on fracture gradients and its influence on losses has been deeply investigated, becoming an industry best practice. However, the effect of cool-down due to fluid injection at high rates with hydraulic fracturing applications are not captured by dedicated literature and, even less, by modelling softwares. As a result, a non-conventional approach to the creation of a geo-mechanical model that could take into account the thermal effect of cold frac fluids injection was elaborated and several sensitivities to understand fracture propagation mechanism were performed, highlighting a wide range of variability which is attributable to the influence of temperature on stress regime.\u0000 High temperature reservoirs proved easier to frac than expected due to the decrease in terms of pressure required to initialize a fracture. However, this phenomenon could hide potential dangers when it is required to contain such fracture in the targeted interval. The correct modelling of such effect is of extreme importance to forecast fracture geometry, proppant placement and final conductivity requiring to re-adapt and re-adjust field-proven, industry-standardized hydraulic fracturing models and practices to match results with ","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121185275","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}
M. Thanaa, Anwar Almihdawi, Ezequias Lopez, Ashish Fadtare, Mohammed Fauzan Ansari, Altaf Al-Shammari, K. Al-Failkawi, M. Al-Khaldy, A. Hussein, Pattan Kp Majeedkhan, Mohamed Khamis
Quality Cementation across production sections consisting of depleted/weaker formations is the main challenge in Kuwait. Usage of conventional cement slurry over 15.8 ppg will lead to losses and poor zonal isolation. Newly designed 12.5 ppg enhanced compressive strength cement slurry was proposed to achieve desired zonal isolation and well integrity while avoiding losses and unnecessary remedial jobs. Strategy was formulated to minimize exposure of weaker formations for higher ECDs during cementation. Conventional 15.8PPG tail slurry was replaced with 12.5PPG Ultra high compressive strength (4000psi) cement slurry. New slurry design helped to carry out cementation job without any losses while achieving rapid compressive strength and excellent cement bond across production casing. The technology is based on three radical changes in the conventional way of designing cement Slurry of Substitution of part of the cement volume with inert agents of low specific weight, High packing density using solids of different sizes, and Reduction of water volume required. The job was performed safely and successfully, no losses was observed during and after the cementing job while getting pure cement returns at surface during both stages of cement job. CBL/VDL was performed 24 hrs after the cement job; and the results were excellent. The main advantages of this technology are: Ø High resistance to compression: Once the slurry has set, it is capable of developing compressive strength values similar to heavier conventional slurry. Ø Low reactivity: Most of the elements used are chemically inert, this facilitates the design of the slurry by reducing adverse chemical reactions. Ø Low Shrinkage of Cement: Due to the reduction of the volume of the Portland cement in the slurry, the shrinkage of the set cement is reduced, which allows a better adherence of this to the formation and to the Casing. Ø Mix-ability: Does not require special equipment for its preparation, as if foamed cements require it. Three case histories will be presented with all data and evidence, showing design phase, planning phase, execution phase and results obtained with all logs were showing the excellent results were achieved. This technology has several applications in the industry, which can be executed satisfactorily.
{"title":"First Implementation of Ultra High Compressive Strength 12.5 ppg Cement Slurry in Production String in Kuwait Oilfields","authors":"M. Thanaa, Anwar Almihdawi, Ezequias Lopez, Ashish Fadtare, Mohammed Fauzan Ansari, Altaf Al-Shammari, K. Al-Failkawi, M. Al-Khaldy, A. Hussein, Pattan Kp Majeedkhan, Mohamed Khamis","doi":"10.2523/iptc-23104-ea","DOIUrl":"https://doi.org/10.2523/iptc-23104-ea","url":null,"abstract":"\u0000 Quality Cementation across production sections consisting of depleted/weaker formations is the main challenge in Kuwait. Usage of conventional cement slurry over 15.8 ppg will lead to losses and poor zonal isolation. Newly designed 12.5 ppg enhanced compressive strength cement slurry was proposed to achieve desired zonal isolation and well integrity while avoiding losses and unnecessary remedial jobs.\u0000 Strategy was formulated to minimize exposure of weaker formations for higher ECDs during cementation. Conventional 15.8PPG tail slurry was replaced with 12.5PPG Ultra high compressive strength (4000psi) cement slurry. New slurry design helped to carry out cementation job without any losses while achieving rapid compressive strength and excellent cement bond across production casing. The technology is based on three radical changes in the conventional way of designing cement Slurry of Substitution of part of the cement volume with inert agents of low specific weight, High packing density using solids of different sizes, and Reduction of water volume required.\u0000 The job was performed safely and successfully, no losses was observed during and after the cementing job while getting pure cement returns at surface during both stages of cement job. CBL/VDL was performed 24 hrs after the cement job; and the results were excellent. The main advantages of this technology are: Ø High resistance to compression: Once the slurry has set, it is capable of developing compressive strength values similar to heavier conventional slurry. Ø Low reactivity: Most of the elements used are chemically inert, this facilitates the design of the slurry by reducing adverse chemical reactions. Ø Low Shrinkage of Cement: Due to the reduction of the volume of the Portland cement in the slurry, the shrinkage of the set cement is reduced, which allows a better adherence of this to the formation and to the Casing. Ø Mix-ability: Does not require special equipment for its preparation, as if foamed cements require it.\u0000 Three case histories will be presented with all data and evidence, showing design phase, planning phase, execution phase and results obtained with all logs were showing the excellent results were achieved. This technology has several applications in the industry, which can be executed satisfactorily.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132548643","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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