F. Zausa, L. Besenzoni, Alessandro Caia, Seda Mizrak
The disaster of Macondo of 2010 changed the rules in reliability and safety standards during drilling operations. New regulations were developed in order to improve the control level on blowout risk, and all upstream operators adopted innovative technologies capable to reduce the potential risk of uncontrolled release, either by decreasing its frequency of occurrence or the expected impacts. The objective of this paper is to present a Quantitative Risk Analysis (QRA) of well blowout and measure the beneficial contribution of intervention technologies in terms of expected reduction of spill volume and associated costs. The QRA is applied to any kind of well operation (drilling, completion, workover, light intervention) and well type. The methodology relies upon different risk analysis techniques able to quantify the residual blowout risk, as well as the mitigation provided by each technology. Through Fault Tree Analysis (FTA), a value of blowout probability is calculated for each well operation. The initial blowout condition is associated with a blowout flow rate, calculated with fluid dynamic computational models depending on well flow path and release point into the environment. The evolution of each release scenario is then studied with the use of Event Tree Analysis (ETA), where a set of events, able to reduce or stop the flow, are considered with their probability of success and occurrence time (well bridging, water coning, surface intervention through killing/capping techniques, relief well operations). The value of each intervention is estimated through Decision Tree Analysis (DTA), calculating the amount of spill volume reduction and avoided spill costs. Results of spill volume and cost reduction are calculated for a set of specific wells, considering the application of killing/capping systems as well as Eni innovative technologies. The benefit of these interventions is measured in terms of Expected Monetary Value (EMV) in relation to a potential release extinguished by a relief well, which is the decisive intervention to stop the blowout, considered as the worst case scenario. Surface interventions with killing/capping techniques are the major contributors to the reduction of blowout impacts, and all additional measures which can be adopted should act in the fastest way possible before the arrival of heavy capping stack system. The main innovative contribution of the proposed QRA methodology is the association of an expected economic value to post-blowout mitigation techniques, which takes into account all possible uncertainties related to their success and intervention time. Moreover, by evaluating an economic impact of the residual spill cost, it is possible to prioritize and increase the overall efficiency of the oil spill response plan for each operational and geographical context, and improve the control on blowout risk mitigation process.
{"title":"Quantitative Evaluation of Well Blowout Risk and Oil Spill Mitigation Measures","authors":"F. Zausa, L. Besenzoni, Alessandro Caia, Seda Mizrak","doi":"10.2118/207962-ms","DOIUrl":"https://doi.org/10.2118/207962-ms","url":null,"abstract":"\u0000 The disaster of Macondo of 2010 changed the rules in reliability and safety standards during drilling operations. New regulations were developed in order to improve the control level on blowout risk, and all upstream operators adopted innovative technologies capable to reduce the potential risk of uncontrolled release, either by decreasing its frequency of occurrence or the expected impacts. The objective of this paper is to present a Quantitative Risk Analysis (QRA) of well blowout and measure the beneficial contribution of intervention technologies in terms of expected reduction of spill volume and associated costs.\u0000 The QRA is applied to any kind of well operation (drilling, completion, workover, light intervention) and well type. The methodology relies upon different risk analysis techniques able to quantify the residual blowout risk, as well as the mitigation provided by each technology. Through Fault Tree Analysis (FTA), a value of blowout probability is calculated for each well operation. The initial blowout condition is associated with a blowout flow rate, calculated with fluid dynamic computational models depending on well flow path and release point into the environment. The evolution of each release scenario is then studied with the use of Event Tree Analysis (ETA), where a set of events, able to reduce or stop the flow, are considered with their probability of success and occurrence time (well bridging, water coning, surface intervention through killing/capping techniques, relief well operations). The value of each intervention is estimated through Decision Tree Analysis (DTA), calculating the amount of spill volume reduction and avoided spill costs.\u0000 Results of spill volume and cost reduction are calculated for a set of specific wells, considering the application of killing/capping systems as well as Eni innovative technologies. The benefit of these interventions is measured in terms of Expected Monetary Value (EMV) in relation to a potential release extinguished by a relief well, which is the decisive intervention to stop the blowout, considered as the worst case scenario. Surface interventions with killing/capping techniques are the major contributors to the reduction of blowout impacts, and all additional measures which can be adopted should act in the fastest way possible before the arrival of heavy capping stack system.\u0000 The main innovative contribution of the proposed QRA methodology is the association of an expected economic value to post-blowout mitigation techniques, which takes into account all possible uncertainties related to their success and intervention time. Moreover, by evaluating an economic impact of the residual spill cost, it is possible to prioritize and increase the overall efficiency of the oil spill response plan for each operational and geographical context, and improve the control on blowout risk mitigation process.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"489 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77054725","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to study various methods that can be implemented on existing or new tanks to achieve an extended endorsement period (e.g. 20 years plus) for Crude Oil Floating Roof Storage Tanks. This extended period is necessary in order to overcome anticipated future challenges in tank availability due to (i) increased production and loading, (ii) stretched major overhaul (MOH) duration due to unforeseen delays in MOH works, (iii) corrosion in bottom plates, etc. An extensive research based on international API Standard 653 "Tank Inspection, Repair, Alteration, and Reconstruction" was conducted to achieve this extended period. Initially, some COS tanks aspects were assessed based on API SPEC 653 (2014, Addendum 2, May 2020) to achieve this new Tanks Endorsement Vision, such as: (a) studying the currently applied Corrosion Protection Barriers to the COS tanks and their effectiveness to the endorsement period, (b) the adequacy of commonly applied Corrosion Protection Barriers with respect to the endorsement period, and (c) exploring possible enhancements on COS Tanks Corrosion Protection Barriers, and Monitoring systems to extend tanks endorsement period. Based on API SPEC 653 (2014, Addendum 2, May 2020), currently applied tank safeguards were found inadequate to achieve the 20 years plus tank endorsement period requirement. In order to extend tanks endorsement period, additional safeguards shall be implemented, with special attention to tank bottom plates (soil side), since corrosion problems are mostly exhibited in tank bottom plates from the soil/oil side. Multiple solutions for corrosion safeguards were explored and recommended as part of this study such as the installation of a CP system under COS tanks, as well as installation of a corrosion monitoring system, and performing routine in-service inspections for COS tanks (internal and external) as per API SPEC 653 (2014, Addendum 2, May 2020), etc. Overall, this paper provides an insight on the calculation method of tanks endorsement period, and possible tank corrosion safeguards and controls that can be implemented to extend the COS tanks endorsement period to at least 20 years. Results and recommendations studied in this paper will benefit the Oil and Gas Industry and help in overcoming future challenges.
{"title":"Tanks Assurance and Endorsement Extension Strategy","authors":"Sahar Abdul-Karim Khattab, Marwa Sami Alsheebani","doi":"10.2118/207694-ms","DOIUrl":"https://doi.org/10.2118/207694-ms","url":null,"abstract":"\u0000 The objective of this paper is to study various methods that can be implemented on existing or new tanks to achieve an extended endorsement period (e.g. 20 years plus) for Crude Oil Floating Roof Storage Tanks. This extended period is necessary in order to overcome anticipated future challenges in tank availability due to (i) increased production and loading, (ii) stretched major overhaul (MOH) duration due to unforeseen delays in MOH works, (iii) corrosion in bottom plates, etc. An extensive research based on international API Standard 653 \"Tank Inspection, Repair, Alteration, and Reconstruction\" was conducted to achieve this extended period. Initially, some COS tanks aspects were assessed based on API SPEC 653 (2014, Addendum 2, May 2020) to achieve this new Tanks Endorsement Vision, such as: (a) studying the currently applied Corrosion Protection Barriers to the COS tanks and their effectiveness to the endorsement period, (b) the adequacy of commonly applied Corrosion Protection Barriers with respect to the endorsement period, and (c) exploring possible enhancements on COS Tanks Corrosion Protection Barriers, and Monitoring systems to extend tanks endorsement period. Based on API SPEC 653 (2014, Addendum 2, May 2020), currently applied tank safeguards were found inadequate to achieve the 20 years plus tank endorsement period requirement. In order to extend tanks endorsement period, additional safeguards shall be implemented, with special attention to tank bottom plates (soil side), since corrosion problems are mostly exhibited in tank bottom plates from the soil/oil side. Multiple solutions for corrosion safeguards were explored and recommended as part of this study such as the installation of a CP system under COS tanks, as well as installation of a corrosion monitoring system, and performing routine in-service inspections for COS tanks (internal and external) as per API SPEC 653 (2014, Addendum 2, May 2020), etc. Overall, this paper provides an insight on the calculation method of tanks endorsement period, and possible tank corrosion safeguards and controls that can be implemented to extend the COS tanks endorsement period to at least 20 years. Results and recommendations studied in this paper will benefit the Oil and Gas Industry and help in overcoming future challenges.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"710 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74762257","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. F. Fathalla, M. A. Al Hosani, I. Mohamed, A. A. Al Bairaq, Djamal Kherroubi, A. Abdullayev, Allen Roopal
An onshore gas field contains several gas wells which have low–intermittent production rates. The poor production has been attributed to liquid loading issue in the wellbore. This study will investigate the impact of optimizing the tubing and liner completion design to improve the gas production rates from the wells. Numerous sensitivity runs are carried out with varying tubing and liner dimensions, to identity optimal downhole completions design. The study begins by identifying weak wells having severe gas production problems. Once the weak wells have been identified, wellbore schematics for those wells are studied. Simulation runs are performed with the current downhole completion design and this will be used as the base case. Several completion designs are considered to minimize the effect of liquid loading in the wells; these include reducing the tubing diameter but keeping the existing liner diameter the same, keeping the original tubing diameter the same but only reducing the liner diameter, extending the tubing to the Total Depth (TD) while keeping the original tubing diameter, and extending a reduced diameter tubing string to the TD. The primary cause of the liquid loading seems to be the reduced velocity of the incoming gas from the reservoir as it flows through the wellbore. A simulation study was performed using the various completion designs to optimize the well completion and achieve higher gas velocities in the weak wells. The results of the study showed significant improvement in gas production rates when the tubing diameter and liner diameter were reduced, providing further evidence that increased velocity of the incoming fluids due to restricted flow led to less liquid loading. The paper demonstrates the impact of downhole completion design on the productivity of the gas wells. The study shows that revisiting the existing completion designs and optimizing them using commercial simulators can lead to significant improvement in well production rates. It is also noted that restricting the flow near the sand face increases the velocity of the incoming fluid and reduces liquid loading in the wells.
{"title":"Optimizing Tubing and Liner Completion Design to Improve Gas Production from Existing Wells: Case Study for ADNOC Onshore Field Abu Dhabi, UAE","authors":"M. F. Fathalla, M. A. Al Hosani, I. Mohamed, A. A. Al Bairaq, Djamal Kherroubi, A. Abdullayev, Allen Roopal","doi":"10.2118/207430-ms","DOIUrl":"https://doi.org/10.2118/207430-ms","url":null,"abstract":"\u0000 An onshore gas field contains several gas wells which have low–intermittent production rates. The poor production has been attributed to liquid loading issue in the wellbore. This study will investigate the impact of optimizing the tubing and liner completion design to improve the gas production rates from the wells. Numerous sensitivity runs are carried out with varying tubing and liner dimensions, to identity optimal downhole completions design.\u0000 The study begins by identifying weak wells having severe gas production problems. Once the weak wells have been identified, wellbore schematics for those wells are studied. Simulation runs are performed with the current downhole completion design and this will be used as the base case. Several completion designs are considered to minimize the effect of liquid loading in the wells; these include reducing the tubing diameter but keeping the existing liner diameter the same, keeping the original tubing diameter the same but only reducing the liner diameter, extending the tubing to the Total Depth (TD) while keeping the original tubing diameter, and extending a reduced diameter tubing string to the TD.\u0000 The primary cause of the liquid loading seems to be the reduced velocity of the incoming gas from the reservoir as it flows through the wellbore. A simulation study was performed using the various completion designs to optimize the well completion and achieve higher gas velocities in the weak wells. The results of the study showed significant improvement in gas production rates when the tubing diameter and liner diameter were reduced, providing further evidence that increased velocity of the incoming fluids due to restricted flow led to less liquid loading.\u0000 The paper demonstrates the impact of downhole completion design on the productivity of the gas wells. The study shows that revisiting the existing completion designs and optimizing them using commercial simulators can lead to significant improvement in well production rates. It is also noted that restricting the flow near the sand face increases the velocity of the incoming fluid and reduces liquid loading in the wells.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83802272","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}
While many companies have embarked on their digital transformation journeys implementing different forms of "Digital Twins" to cover specific business processes and challenges, their main challenge has been integrating these disparate Digital Twin projects into one single combined view to create significant new value and competitive advantage for the business. To be effective, the Digital Twin needs to be capable of supporting the entire asset lifecycle from the early phases of a capital project to operations and maintenance up to asset retirement, leveraging the same data in a platform able to support the end-to-end process. This paper looks at several approaches, which large owner operators at different levels of organizational information management maturity have used to build their Enterprise Scale Digital Twin strategies. It uses the lessons learned to highlight the successes and failures of these strategies and recommended approaches going forward. The results observed, identify that whilst there is a reasonably standard roadmap for approaching the development of Digital Twins most customers begin at different points along that journey. It also highlights that the end goal may not be the same across an Enterprise and that by taking the development of a Digital Twin as a series of incremental steps, independent of the starting point, serves to accelerate the journey by driving an increase in the organizational maturity in terms of People, Process and Technology and an improvement in data quality. One of the key components in any strategy was the ability to manage the information standard for the Digital Twin at an Enterprise level, for both greenfield and brownfield organizations and assets. The paper concludes the benefits of technical and commercial scalability and the requirements to get a solid manageable and trustworthy core of information should be at the heart of any Enterprise-wide Digital Twin strategy. This is contrary to the common approach of building a single detailed Proof of Concept (PoC) addressing as many use cases as possible and then templatizing that as an approach to repeat around the Enterprise, which often leads to failure on additional deployments where the maturity and challenges are different.
{"title":"Success Factors of an Enterprise-Wide Digital Twin Strategy","authors":"Steve Parvin","doi":"10.2118/207248-ms","DOIUrl":"https://doi.org/10.2118/207248-ms","url":null,"abstract":"\u0000 While many companies have embarked on their digital transformation journeys implementing different forms of \"Digital Twins\" to cover specific business processes and challenges, their main challenge has been integrating these disparate Digital Twin projects into one single combined view to create significant new value and competitive advantage for the business.\u0000 To be effective, the Digital Twin needs to be capable of supporting the entire asset lifecycle from the early phases of a capital project to operations and maintenance up to asset retirement, leveraging the same data in a platform able to support the end-to-end process.\u0000 This paper looks at several approaches, which large owner operators at different levels of organizational information management maturity have used to build their Enterprise Scale Digital Twin strategies.\u0000 It uses the lessons learned to highlight the successes and failures of these strategies and recommended approaches going forward. The results observed, identify that whilst there is a reasonably standard roadmap for approaching the development of Digital Twins most customers begin at different points along that journey.\u0000 It also highlights that the end goal may not be the same across an Enterprise and that by taking the development of a Digital Twin as a series of incremental steps, independent of the starting point, serves to accelerate the journey by driving an increase in the organizational maturity in terms of People, Process and Technology and an improvement in data quality. One of the key components in any strategy was the ability to manage the information standard for the Digital Twin at an Enterprise level, for both greenfield and brownfield organizations and assets.\u0000 The paper concludes the benefits of technical and commercial scalability and the requirements to get a solid manageable and trustworthy core of information should be at the heart of any Enterprise-wide Digital Twin strategy. This is contrary to the common approach of building a single detailed Proof of Concept (PoC) addressing as many use cases as possible and then templatizing that as an approach to repeat around the Enterprise, which often leads to failure on additional deployments where the maturity and challenges are different.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83818504","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}
Nasser AlAskari, Muhamad Zaki, Ahmed Aljanahi, Hamed AlGhadhban, E.A.E. Ali, V. Stashevsky
Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation
{"title":"Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures","authors":"Nasser AlAskari, Muhamad Zaki, Ahmed Aljanahi, Hamed AlGhadhban, E.A.E. Ali, V. Stashevsky","doi":"10.2118/207306-ms","DOIUrl":"https://doi.org/10.2118/207306-ms","url":null,"abstract":"\u0000 Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency).\u0000 Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match.\u0000 Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance.\u0000 Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83040221","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}
F. Figueroa, Gustavo Mejías, J. Frias, Bonifacio Brito, Diana L. Velázquez, Carmen J. Ramírez, F. Téllez, Juan Briceño, J. Salas, Ángel Olivares, Georgina Olán, Andrés Flores, Jesús Arroyo, John E. Busteed, René Hernández, J. Gonzalez
Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.
{"title":"Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico","authors":"F. Figueroa, Gustavo Mejías, J. Frias, Bonifacio Brito, Diana L. Velázquez, Carmen J. Ramírez, F. Téllez, Juan Briceño, J. Salas, Ángel Olivares, Georgina Olán, Andrés Flores, Jesús Arroyo, John E. Busteed, René Hernández, J. Gonzalez","doi":"10.2118/207332-ms","DOIUrl":"https://doi.org/10.2118/207332-ms","url":null,"abstract":"\u0000 Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone.\u0000 Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected.\u0000 The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84551140","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}
Many oil & gas companies embarked on their Digital Transformation (DX) journeys with rapid adoption of emerging digital technologies. Successful digital transformation initiatives are necessary for Oil/Gas Companies to improve efficiencies, streamline their operations and meet pressing challenges for cost reduction, increased efficiency, and improved safety. Oil & Gas fields and processing facilities require robust and reliable telecommunication infrastructure to support the application of much needed digital technologies. The availability of high-speed connectivity has been a challenge for many Oil/Gas companies operating in remote or hazardous locations. The latest Fifth Generation cellular technology (5 G) addresses such essential Oil/Gas requirements as increased speeds/bandwidths, very low network latencies, ultra-reliable communications, and the capacity to handle large number of users. 5G is designed around following technologies: Small (micro) cells requiring less power,Higher frequencies offering bigger data handling capacities,Cloud and Edge Computing for low network latencies and added security. These 5G design features will enable numerous Oil/Gas applications such as Industrial Robots/Drones, Virtual/Augmented Reality, Video Surveillance with Artificial Intelligence (AI) features (Face Recognition, Object Recognition & intelligent Image processing), Remote Asset Management, Industrial IoT communication between Sensors, Gateways and Device Controllers, Pipeline Leak Detection Systems, Telemetry and SCADA. 5G is therefore poised to be a key enabler in Digital Transformation. The UAE has an advanced telecom infrastructure that offers customers high speed fibre optic connectivity. UAE telecom operators have also been quick to deploy 5G in main cities. Etisalat for example is running a 5G pilot on Das Island with ADNOC Offshore and a major Network Supplier to test potential use cases of the technology in the O&G industry. The push for 5G in O&G will benefit from cooperation between the O&G industry, the telecom operators and technology providers. The role of Governments and the Telecom Regulators can further accelerate adoption through allocation of frequency spectrum to enable 5G Private Network model of deployment. The private network model is crucial for the Oil & Gas industry in view of the special requirements, nature and remoteness of oil and gas installations.
{"title":"The Use of 5G Technologies in the Digital Transformation of the Oil/Gas Industry","authors":"Sadik Jadir Al-Jadir","doi":"10.2118/207529-ms","DOIUrl":"https://doi.org/10.2118/207529-ms","url":null,"abstract":"\u0000 Many oil & gas companies embarked on their Digital Transformation (DX) journeys with rapid adoption of emerging digital technologies. Successful digital transformation initiatives are necessary for Oil/Gas Companies to improve efficiencies, streamline their operations and meet pressing challenges for cost reduction, increased efficiency, and improved safety.\u0000 Oil & Gas fields and processing facilities require robust and reliable telecommunication infrastructure to support the application of much needed digital technologies. The availability of high-speed connectivity has been a challenge for many Oil/Gas companies operating in remote or hazardous locations. The latest Fifth Generation cellular technology (5 G) addresses such essential Oil/Gas requirements as increased speeds/bandwidths, very low network latencies, ultra-reliable communications, and the capacity to handle large number of users.\u0000 5G is designed around following technologies: Small (micro) cells requiring less power,Higher frequencies offering bigger data handling capacities,Cloud and Edge Computing for low network latencies and added security.\u0000 These 5G design features will enable numerous Oil/Gas applications such as Industrial Robots/Drones, Virtual/Augmented Reality, Video Surveillance with Artificial Intelligence (AI) features (Face Recognition, Object Recognition & intelligent Image processing), Remote Asset Management, Industrial IoT communication between Sensors, Gateways and Device Controllers, Pipeline Leak Detection Systems, Telemetry and SCADA. 5G is therefore poised to be a key enabler in Digital Transformation.\u0000 The UAE has an advanced telecom infrastructure that offers customers high speed fibre optic connectivity. UAE telecom operators have also been quick to deploy 5G in main cities. Etisalat for example is running a 5G pilot on Das Island with ADNOC Offshore and a major Network Supplier to test potential use cases of the technology in the O&G industry.\u0000 The push for 5G in O&G will benefit from cooperation between the O&G industry, the telecom operators and technology providers. The role of Governments and the Telecom Regulators can further accelerate adoption through allocation of frequency spectrum to enable 5G Private Network model of deployment. The private network model is crucial for the Oil & Gas industry in view of the special requirements, nature and remoteness of oil and gas installations.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72885830","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}
Subba Ramarao Rachapudi Venkata, N. Reddicharla, S. Alshehhi, Indra Utama, S. A. Al Nuimi, Dávid Gönczi, Oussema Toumi, Eleonora Pechorskaya, Georg Schweiger, Franz Führer
Matured hydrocarbon fields are continuously deteriorating and selection of well interventions turn into critical task with an objective of achieving higher business value. Time consuming simulation models and classical decision-making approach making it difficult to rapidly identify the best underperforming, potential rig and rig-less candidates. Therefore, the objective of this paper is to demonstrate the automated solution with data driven machine learning (ML) & AI assisted workflows to prioritize the intervention opportunities that can deliver higher sustainable oil rate and profitability. The solution consists of establishing a customized database using inputs from various sources including production & completion data, flat files and simulation models. Automation of Data gathering along with technical and economical calculations were implemented to overcome the repetitive and less added value tasks. Second layer of solution includes configuration of tailor-made workflows to conduct the analysis of well performance, logs, output from simulation models (static reservoir model, well models) along with historical events. Further these workflows were combination of current best practices of an integrated assessment of subsurface opportunities through analytical computations along with machine learning driven techniques for ranking the well intervention opportunities with consideration of complexity in implementation. The automated process outcome is a comprehensive list of future well intervention candidates like well conversion to gas lift, water shutoff, stimulation and nitrogen kick-off opportunities. The opportunity ranking is completed with AI assisted supported scoring system that takes input from technical, financial and implementation risk scores. In addition, intuitive dashboards are built and tailored with the involvement of management and engineering departments to track the opportunity maturation process. The advisory system has been implemented and tested in a giant mature field with over 300 wells. The solution identified more techno-economical feasible opportunities within hours instead of weeks or months with reduced risk of failure resulting into an improved economic success rate. The first set of opportunities under implementation and expected a gain of 2.5MM$ with in first one year and expected to have reoccurring gains in subsequent years. The ranked opportunities are incorporated into the business plan, RMP plans and drilling & workover schedule in accordance to field development targets. This advisory system helps in maximizing the profitability and minimizing CAPEX and OPEX. This further maximizes utilization of production optimization models by 30%. Currently the system was implemented in one of ADNOC Onshore field and expected to be scaled to other fields based on consistent value creation. A hybrid approach of physics and machine learning based solution led to the development of automated workflows to identify and
{"title":"Artificial Intelligence Assisted Well Portfolio Optimization - An Automated Reservoir Management Advisory System to Maximize the Asset Value - Case Study from ADNOC Onshore","authors":"Subba Ramarao Rachapudi Venkata, N. Reddicharla, S. Alshehhi, Indra Utama, S. A. Al Nuimi, Dávid Gönczi, Oussema Toumi, Eleonora Pechorskaya, Georg Schweiger, Franz Führer","doi":"10.2118/207274-ms","DOIUrl":"https://doi.org/10.2118/207274-ms","url":null,"abstract":"\u0000 Matured hydrocarbon fields are continuously deteriorating and selection of well interventions turn into critical task with an objective of achieving higher business value. Time consuming simulation models and classical decision-making approach making it difficult to rapidly identify the best underperforming, potential rig and rig-less candidates. Therefore, the objective of this paper is to demonstrate the automated solution with data driven machine learning (ML) & AI assisted workflows to prioritize the intervention opportunities that can deliver higher sustainable oil rate and profitability.\u0000 The solution consists of establishing a customized database using inputs from various sources including production & completion data, flat files and simulation models. Automation of Data gathering along with technical and economical calculations were implemented to overcome the repetitive and less added value tasks. Second layer of solution includes configuration of tailor-made workflows to conduct the analysis of well performance, logs, output from simulation models (static reservoir model, well models) along with historical events. Further these workflows were combination of current best practices of an integrated assessment of subsurface opportunities through analytical computations along with machine learning driven techniques for ranking the well intervention opportunities with consideration of complexity in implementation.\u0000 The automated process outcome is a comprehensive list of future well intervention candidates like well conversion to gas lift, water shutoff, stimulation and nitrogen kick-off opportunities. The opportunity ranking is completed with AI assisted supported scoring system that takes input from technical, financial and implementation risk scores. In addition, intuitive dashboards are built and tailored with the involvement of management and engineering departments to track the opportunity maturation process.\u0000 The advisory system has been implemented and tested in a giant mature field with over 300 wells. The solution identified more techno-economical feasible opportunities within hours instead of weeks or months with reduced risk of failure resulting into an improved economic success rate. The first set of opportunities under implementation and expected a gain of 2.5MM$ with in first one year and expected to have reoccurring gains in subsequent years. The ranked opportunities are incorporated into the business plan, RMP plans and drilling & workover schedule in accordance to field development targets. This advisory system helps in maximizing the profitability and minimizing CAPEX and OPEX. This further maximizes utilization of production optimization models by 30%. Currently the system was implemented in one of ADNOC Onshore field and expected to be scaled to other fields based on consistent value creation.\u0000 A hybrid approach of physics and machine learning based solution led to the development of automated workflows to identify and","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90620123","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}
Ameen Malkawi, S. Ganti, Zahra Aleid, Hussain Sharrofna, Naeem Minhas, Nicholas Barta
This paper discusses the considerations taken into account before printing additively manufactured (AM) parts, the challenges faced during the printing process, and the standards, methods, and techniques by which the parts are qualified for use. We discuss the four major categories of AM powder bed fusion (PBF) qualification process namely feedstock qualification, machine and process qualification, material qualification, and part qualification. We discuss what each of these qualification processes entails and provide suggestions where appropriate. In this paper, the activity and direction within the international standards community to help drive the widespread adoption of AM technology in various industries is also discussed.
{"title":"Considerations and challenges of qualifying a metal powder bed fusion 3D printing process","authors":"Ameen Malkawi, S. Ganti, Zahra Aleid, Hussain Sharrofna, Naeem Minhas, Nicholas Barta","doi":"10.2118/207628-ms","DOIUrl":"https://doi.org/10.2118/207628-ms","url":null,"abstract":"\u0000 This paper discusses the considerations taken into account before printing additively manufactured (AM) parts, the challenges faced during the printing process, and the standards, methods, and techniques by which the parts are qualified for use. We discuss the four major categories of AM powder bed fusion (PBF) qualification process namely feedstock qualification, machine and process qualification, material qualification, and part qualification. We discuss what each of these qualification processes entails and provide suggestions where appropriate.\u0000 In this paper, the activity and direction within the international standards community to help drive the widespread adoption of AM technology in various industries is also discussed.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77202135","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}
Yuan Liu, L. Mu, Zhengfeng Zhao, Xianwen Li, P. Enkababian
Well completion has evolved rapidly in the past two decades, as multistage completion has become the predominant practice to complete a well in many places. Although innovation in completion tool technology has been continuous in recent years, there are still gaps in the well completion optimization practice. In this paper, we add additional dimensions to well completion technology by incorporating geoengineering, measurement while pumping, and data mining, and we have evidence to show that those additional elements help to improve our understanding, on-site efficiency, and overall performance. Multistage completion optimization is about where and how to complete a well. Different methods were employed in the past, and even with a better-engineered completion design where both reservoir and completion quality are honored, there are still area for improvement. For example, 1) geological properties are not qualitatively utilized in the completion design; 2) real-time operational feedback during the execution phase is inadequate for in-time decisions for completion and fracturing adjustment; 3) the completion-to-well-performance cycle is so long that the learning curve is not fast enough, and too many influential factors are hidden in the details. Three extra dimensions were added to address the improvement areas. Geoengineering adds "space information" in enabling geological properties from a 3D space grid to be projected onto the wellbore as geology quality (GQ) so that the information can be used together with reservoir and completion quality (RQ and CQ) quantitatively to improve the fracturing treatment design. Measurement while pumping (MWP) adds "timely feedback" in that real-time operational feedback—either from the wellbore via high-frequency pressure monitoring or from the target zones via microseismic data in offset horizontal monitoring wells—can help with the completion and fracture diagnosis and decision making on-site. Data mining adds "pattern recognition" in that reservoir and operation data are collected and analyzed to generate a systematic understanding of the reservoir complexity, paving the way for the improved planning of future well completions in the same region. Each of the solutions comes with specific case studies in our work. Geoengineering, MWP, and data mining add three dimensions to the current well completion practice. In our case studies, these approaches have demonstrated the capability to improve the accuracy of the design, increase confidence in the execution, and accelerate the learning curve from evaluation. The extra dimensions added to the current completion practice are essentially space, time, and pattern, and together, they help to define the direction of future innovations for completion optimization.
{"title":"Adding Extra Dimensions for Completion Consideration: Case Studies with Geoengineering, Measurement While Pumping, and Data Mining","authors":"Yuan Liu, L. Mu, Zhengfeng Zhao, Xianwen Li, P. Enkababian","doi":"10.2118/207916-ms","DOIUrl":"https://doi.org/10.2118/207916-ms","url":null,"abstract":"\u0000 Well completion has evolved rapidly in the past two decades, as multistage completion has become the predominant practice to complete a well in many places. Although innovation in completion tool technology has been continuous in recent years, there are still gaps in the well completion optimization practice. In this paper, we add additional dimensions to well completion technology by incorporating geoengineering, measurement while pumping, and data mining, and we have evidence to show that those additional elements help to improve our understanding, on-site efficiency, and overall performance.\u0000 Multistage completion optimization is about where and how to complete a well. Different methods were employed in the past, and even with a better-engineered completion design where both reservoir and completion quality are honored, there are still area for improvement. For example, 1) geological properties are not qualitatively utilized in the completion design; 2) real-time operational feedback during the execution phase is inadequate for in-time decisions for completion and fracturing adjustment; 3) the completion-to-well-performance cycle is so long that the learning curve is not fast enough, and too many influential factors are hidden in the details.\u0000 Three extra dimensions were added to address the improvement areas. Geoengineering adds \"space information\" in enabling geological properties from a 3D space grid to be projected onto the wellbore as geology quality (GQ) so that the information can be used together with reservoir and completion quality (RQ and CQ) quantitatively to improve the fracturing treatment design. Measurement while pumping (MWP) adds \"timely feedback\" in that real-time operational feedback—either from the wellbore via high-frequency pressure monitoring or from the target zones via microseismic data in offset horizontal monitoring wells—can help with the completion and fracture diagnosis and decision making on-site. Data mining adds \"pattern recognition\" in that reservoir and operation data are collected and analyzed to generate a systematic understanding of the reservoir complexity, paving the way for the improved planning of future well completions in the same region. Each of the solutions comes with specific case studies in our work.\u0000 Geoengineering, MWP, and data mining add three dimensions to the current well completion practice. In our case studies, these approaches have demonstrated the capability to improve the accuracy of the design, increase confidence in the execution, and accelerate the learning curve from evaluation. The extra dimensions added to the current completion practice are essentially space, time, and pattern, and together, they help to define the direction of future innovations for completion optimization.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77351233","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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