Predicting stuck pipe problems during oil and gas drilling operation is one of the most complex problems in the drilling business. The complexity of the problem is driven not only by the complexity of the natural factors, but it extends to the nature of the drilling operation itself. The drilling operation is continuously influenced by a dynamic smart system. The dynamic part of the system is impacted by natural forces like formation related characteristics, and also is impacted by human activities during the operation such as drilling, tripping and hole cleaning. The smartness of this system is driven by the fact that the operation is controlled by a number of experts, i.e. drilling engineers, trying to run the best sequence of operations using best operation parameters to achieve operation objective. At the top of that, the engineers can change their operation plan whenever they find it necessary to address any operational condition, including a potential stuck pipe problem. In this paper we prove the stuck pipe prediction problem is not a binary classification problem. Instead, we define the stuck pipe prediction problem as a multi-class problem which takes into consideration the dynamic nature of the drilling operation. A reinforcement learning based algorithm is proposed to solve the redefined problem, and its performance and evaluation results is shared in details. The accuracy of the developed algorithm in terms of detecting true stuck pipe events is shown. The results will compare the performance of different machine learning algorithms, which is then used to justify the selection of the best performing method. In addition, we show the accuracy performance improvement through time by employing the feedback channel to retrain the model. The presented method is using a reinforcement logic, in which the solution is connected to the operation reporting to label the solution prediction for false and true predictions. This information is then used to return the neural networks to learn new operational patterns to enhance accuracy.
{"title":"Novel Stuck Pipe Troubles Prediction Model Using Reinforcement Learning","authors":"M. Alzahrani, Bader M. Alotaibi, Beshir M. Aman","doi":"10.2523/iptc-22151-ms","DOIUrl":"https://doi.org/10.2523/iptc-22151-ms","url":null,"abstract":"\u0000 Predicting stuck pipe problems during oil and gas drilling operation is one of the most complex problems in the drilling business. The complexity of the problem is driven not only by the complexity of the natural factors, but it extends to the nature of the drilling operation itself. The drilling operation is continuously influenced by a dynamic smart system. The dynamic part of the system is impacted by natural forces like formation related characteristics, and also is impacted by human activities during the operation such as drilling, tripping and hole cleaning. The smartness of this system is driven by the fact that the operation is controlled by a number of experts, i.e. drilling engineers, trying to run the best sequence of operations using best operation parameters to achieve operation objective. At the top of that, the engineers can change their operation plan whenever they find it necessary to address any operational condition, including a potential stuck pipe problem.\u0000 In this paper we prove the stuck pipe prediction problem is not a binary classification problem. Instead, we define the stuck pipe prediction problem as a multi-class problem which takes into consideration the dynamic nature of the drilling operation. A reinforcement learning based algorithm is proposed to solve the redefined problem, and its performance and evaluation results is shared in details. The accuracy of the developed algorithm in terms of detecting true stuck pipe events is shown. The results will compare the performance of different machine learning algorithms, which is then used to justify the selection of the best performing method. In addition, we show the accuracy performance improvement through time by employing the feedback channel to retrain the model. The presented method is using a reinforcement logic, in which the solution is connected to the operation reporting to label the solution prediction for false and true predictions. This information is then used to return the neural networks to learn new operational patterns to enhance accuracy.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84559220","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. Mohamed, M. Waqas, J. Ahmed, Amro Abdel-halim, Shujaat Ali, Aysha Alhamedi, Arit Igogo, Yatindra Bhushan
Repeated time-lapse Walkaway VSP (vertical seismic profile) were acquired as part of CO2 WAG EOR pilot monitoring in an onshore carbonate field in the UAE. The Baseline survey followed by two monitors were acquired, one after 6 months of water injection and another after 3 years of CO2/Water injection cycles. Objectives were to monitor CO2 and Water fronts between injector and producer, in addition to assess source and receiver repeatability. Feasibility study was performed to estimate 4D effects due to petrophysical changes in the reservoir, resulting from Water and/or Gas injection. After performing the survey design for receiver and source positions, 36 level 3C receivers at 7.6 m spacing array were deployed few hundred meters above the reservoir. Baseline and Monitor-1 survey were acquired with 186 source points at 25 m spacing, with maximum offset of 3000 m from wellhead in both directions along NW-SE line, however, Monitor-2 had 10 source points less in NW direction due to surface restrictions. Excellent data quality with good repeatability was achieved. Final images around reservoir showed no visible seismic 4D changes along Walkaway VSP orientation post injection during period between Baseline and Monitor-1, possibly due to fluid transmission not proceeding along this orientation, or it was too early to detect anomalies in the vicinity. This paper presents Baseline/Monitor-2 processing results. 3C VSP processing was performed while taking into consideration Baseline and Monitor-2 data NRMS (normalized root mean square) and predictability at major processing steps. Customized processing workflow was applied for wavefield separation and deconvolution. VSP geometry is lacking high angle first arrivals to directly estimate overburden shales anisotropy parameters, which was addressed by incorporating the values from literature. Cross-equalization was performed pre-migration i.e. scalars computed on downgoing wavefield and applied on upgoing wavefield. Time-lapse analysis was performed pre-migration i.e. on NMO (normal move out) corrected data after flattening at overburden shales to remove any time shift effects from the overburden. Time shifts were noticed across receivers in the overburden shales in Walkaway VSP and validated by Zero-Offset VSP extracted from the Walkaway VSP. The observed time shifts were small with no amplitude differences on NMO corrected data at the reservoir. In the migrated images, amplitude difference observed were possibly due to these time shifts, these slight time changes are stacked in the migration process and hence compounded with the 4D amplitude signature of the images. Time-lapse feasibility studies are available in the literature however; actual time-lapse seismic surveys are very limited in the UAE. This study will help the operators to deploy borehole seismic technology for time-lapse monitoring in the Middle East carbonate reservoirs. Processing workflow was optimized, highlighting challenges and l
{"title":"First Time Lapse Walkaway VSP Monitoring of CO2 WAG EOR Pilot, Challenges and Learnings from Onshore Carbonate Field UAE","authors":"M. Mohamed, M. Waqas, J. Ahmed, Amro Abdel-halim, Shujaat Ali, Aysha Alhamedi, Arit Igogo, Yatindra Bhushan","doi":"10.2523/iptc-22631-ms","DOIUrl":"https://doi.org/10.2523/iptc-22631-ms","url":null,"abstract":"\u0000 Repeated time-lapse Walkaway VSP (vertical seismic profile) were acquired as part of CO2 WAG EOR pilot monitoring in an onshore carbonate field in the UAE. The Baseline survey followed by two monitors were acquired, one after 6 months of water injection and another after 3 years of CO2/Water injection cycles. Objectives were to monitor CO2 and Water fronts between injector and producer, in addition to assess source and receiver repeatability.\u0000 Feasibility study was performed to estimate 4D effects due to petrophysical changes in the reservoir, resulting from Water and/or Gas injection. After performing the survey design for receiver and source positions, 36 level 3C receivers at 7.6 m spacing array were deployed few hundred meters above the reservoir. Baseline and Monitor-1 survey were acquired with 186 source points at 25 m spacing, with maximum offset of 3000 m from wellhead in both directions along NW-SE line, however, Monitor-2 had 10 source points less in NW direction due to surface restrictions. Excellent data quality with good repeatability was achieved.\u0000 Final images around reservoir showed no visible seismic 4D changes along Walkaway VSP orientation post injection during period between Baseline and Monitor-1, possibly due to fluid transmission not proceeding along this orientation, or it was too early to detect anomalies in the vicinity. This paper presents Baseline/Monitor-2 processing results.\u0000 3C VSP processing was performed while taking into consideration Baseline and Monitor-2 data NRMS (normalized root mean square) and predictability at major processing steps. Customized processing workflow was applied for wavefield separation and deconvolution. VSP geometry is lacking high angle first arrivals to directly estimate overburden shales anisotropy parameters, which was addressed by incorporating the values from literature. Cross-equalization was performed pre-migration i.e. scalars computed on downgoing wavefield and applied on upgoing wavefield. Time-lapse analysis was performed pre-migration i.e. on NMO (normal move out) corrected data after flattening at overburden shales to remove any time shift effects from the overburden.\u0000 Time shifts were noticed across receivers in the overburden shales in Walkaway VSP and validated by Zero-Offset VSP extracted from the Walkaway VSP. The observed time shifts were small with no amplitude differences on NMO corrected data at the reservoir. In the migrated images, amplitude difference observed were possibly due to these time shifts, these slight time changes are stacked in the migration process and hence compounded with the 4D amplitude signature of the images.\u0000 Time-lapse feasibility studies are available in the literature however; actual time-lapse seismic surveys are very limited in the UAE. This study will help the operators to deploy borehole seismic technology for time-lapse monitoring in the Middle East carbonate reservoirs. Processing workflow was optimized, highlighting challenges and l","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83380192","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. Hussain, A. Amao, K. Al-Ramadan, L. Babalola, John T. Humphrey
Previous studies have shown that by applying multivariate statistical analysis to chemostratigraphy, indistinct sequence stratigraphic correlations can be enhanced. Chemofacies and correlatable chemozones can be defined within highly homogenous strata, using specially designed statistical algorithms. In this study, we first investigated the better performing of linear and non-linear dimensionality reduction techniques in analyzing geochemical datasets for chemofacies and chemozones development. The general applicability of this conceptual model for sequence stratigraphic correlations, was subsequently tested. The results show that the linear method was able to account for 63% of input data variance while the non-linear technique accounted for 100% of the variance. In addition, the linear techniques are better utilized to establish chemofacies, whereas the non-linear techniques considerably perform better in establishing correlatable chemozones, while also improving accuracy.
{"title":"Chemostratigraphy Enables Correlations and Reservoir Characterization with High Resolution Elemental Data","authors":"M. Hussain, A. Amao, K. Al-Ramadan, L. Babalola, John T. Humphrey","doi":"10.2523/iptc-21919-ea","DOIUrl":"https://doi.org/10.2523/iptc-21919-ea","url":null,"abstract":"\u0000 Previous studies have shown that by applying multivariate statistical analysis to chemostratigraphy, indistinct sequence stratigraphic correlations can be enhanced. Chemofacies and correlatable chemozones can be defined within highly homogenous strata, using specially designed statistical algorithms. In this study, we first investigated the better performing of linear and non-linear dimensionality reduction techniques in analyzing geochemical datasets for chemofacies and chemozones development. The general applicability of this conceptual model for sequence stratigraphic correlations, was subsequently tested. The results show that the linear method was able to account for 63% of input data variance while the non-linear technique accounted for 100% of the variance. In addition, the linear techniques are better utilized to establish chemofacies, whereas the non-linear techniques considerably perform better in establishing correlatable chemozones, while also improving accuracy.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87129582","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}
Nouf H. Alotaibi, Awoye Lawson-Jack, K. Smith, Salako Olaoluwa, Gonzalo Chinea
The objective of this paper is to evaluate the formation damage mechanisms on carbonate porous media due to the effect of solids (high-density Mn3O4 and BaSO4 weighting materials) and other particles dispersed in workover fluids. Barite (BaSO4) and Manganese Tetroxide (Mn3O4) are both highly dense compounds (4.5 – 4.8 g/cm3) with particle size of approximately 50 and 5 microns (μm) respectively, which can significantly impact permeability due to solids invasion. A formation damage lab simulator was utilized to take selected core samples up to reservoir conditions. Initially, XRD/XRF and a baseline CT scan of the reservoir core plugs were conducted prior to core flooding. Differential pressures along core samples were measured at controlled flowrates during nitrogen gas flooding carried out before and after the workover fluid application and also, after removal of the filter cake formed by the workover fluid. Darcy's equation was used to calculate permeability values, and core plug CT scans post-floods were used to assist with the interpretation of the associated formation damage mechanism. This study shows that the presence of solids inside the porous media physically plugging fluid pathways and a thick external filter cake due to high fluid filtration are the main mechanisms that contributed to the reduced return permeability observed on the core plug samples. The internal filter cake associated with the penetration of filtrate and solid particles into the pores had a greater effect on the observed permeability reduction compared to that of the external filter cake. The characteristics of the filter cake is strongly controlled by the mud particle type, size, and concentration. The combination of Manganese Tetroxide (Mn3O4) based workover fluid filter cake and the carbonate rock sample's face had low permeability causing a larger pressure drop and a lower productivity compared to the Barite (BaSO4) based filter cake in interaction with the same rock type. The permeability of the filter cake was lowered with decreased filtration.
{"title":"Damage Mechanism of High-Density Mn3O4/ BaSO4 Based Workover Fluids in Carbonate Reservoirs","authors":"Nouf H. Alotaibi, Awoye Lawson-Jack, K. Smith, Salako Olaoluwa, Gonzalo Chinea","doi":"10.2523/iptc-22033-ea","DOIUrl":"https://doi.org/10.2523/iptc-22033-ea","url":null,"abstract":"\u0000 The objective of this paper is to evaluate the formation damage mechanisms on carbonate porous media due to the effect of solids (high-density Mn3O4 and BaSO4 weighting materials) and other particles dispersed in workover fluids. Barite (BaSO4) and Manganese Tetroxide (Mn3O4) are both highly dense compounds (4.5 – 4.8 g/cm3) with particle size of approximately 50 and 5 microns (μm) respectively, which can significantly impact permeability due to solids invasion.\u0000 A formation damage lab simulator was utilized to take selected core samples up to reservoir conditions. Initially, XRD/XRF and a baseline CT scan of the reservoir core plugs were conducted prior to core flooding. Differential pressures along core samples were measured at controlled flowrates during nitrogen gas flooding carried out before and after the workover fluid application and also, after removal of the filter cake formed by the workover fluid. Darcy's equation was used to calculate permeability values, and core plug CT scans post-floods were used to assist with the interpretation of the associated formation damage mechanism.\u0000 This study shows that the presence of solids inside the porous media physically plugging fluid pathways and a thick external filter cake due to high fluid filtration are the main mechanisms that contributed to the reduced return permeability observed on the core plug samples. The internal filter cake associated with the penetration of filtrate and solid particles into the pores had a greater effect on the observed permeability reduction compared to that of the external filter cake. The characteristics of the filter cake is strongly controlled by the mud particle type, size, and concentration. The combination of Manganese Tetroxide (Mn3O4) based workover fluid filter cake and the carbonate rock sample's face had low permeability causing a larger pressure drop and a lower productivity compared to the Barite (BaSO4) based filter cake in interaction with the same rock type. The permeability of the filter cake was lowered with decreased filtration.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87236736","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}
In the last two decades, oil and gas operators and service companies are moving towards a more proactive rather than reactive mode in the drilling process optimization following the use of remote operating centers (ROCs) for rapid problem identification, assessment and mitigation. The methodologies adopted may be different across companies or regions but the underlying objective for most is to drill wells efficiently in a cost-effective manner. In spite of the rapid and continuous development of real time monitoring protocols, there are still gaps in the use of these aggregated data and information obtained from ROCs to achieve fully integrated drilling process modeling and optimization in real time. The paper highlights the importance of a full-integrated approach to using real time drilling engineering and optimization methodology in order to gain valuable insights that allow operational teams to execute wells with minimal non-productive Developing a functional real time drilling engineering methodology requires several years of failing fast and evolving towards a more improved performance organization where preemptive actions can be taken before problems occur. The methodology begins with performing full-integrated geomechanics study to understand the underlying geological uncertainties, stresses and faulting regimes within the area. The results from the geomechanical study form the basis for the detailed design of the casing, mud, cement, drillstring as well as the interaction of all these artifacts in order to develop operating parameters for well execution. Detailed drilling engineering road maps along with its associate risk matrices are developed to determine the operating ranges and bases of monitoring. During real time execution, these models including the 1-D geomechanical model, BHA design & modeling, casing design, fluids design, cementing design are updated continuously as more data become available in real time. The real time drilling engineering analysis coupled with integrated in-house and real-time center (iROC) personnel, 24/7 support provides immediate recommendations that can eliminate and avoid potential undesirable drilling events such as stuck pipes, lost circulations, and downhole tool failures. By applying this integrated methodology in the Gulf of Mexico, a significant improvement in technical efficiency and by extension the operational efficiencies in performance through implementing same goals(s) focus, objectives aligned with collaborative planning, integrated 24/7 real-time operations support and solutions, execution and delivering correct and detailed communication protocols with united focal points across multiple stake holders. This resulted in completed well construction phase eight days ahead of schedule, with zero safety incidents. This study validates the value of integrated services approach with focal point leadership using the right communication protocols with 24/7 monitoring and proactive support, i
{"title":"Real-Time Drilling Engineering: Operating Envelope, Workflow and Implementation in Challenging Environments","authors":"Samuel Ighalo","doi":"10.2523/iptc-22047-ms","DOIUrl":"https://doi.org/10.2523/iptc-22047-ms","url":null,"abstract":"\u0000 In the last two decades, oil and gas operators and service companies are moving towards a more proactive rather than reactive mode in the drilling process optimization following the use of remote operating centers (ROCs) for rapid problem identification, assessment and mitigation. The methodologies adopted may be different across companies or regions but the underlying objective for most is to drill wells efficiently in a cost-effective manner. In spite of the rapid and continuous development of real time monitoring protocols, there are still gaps in the use of these aggregated data and information obtained from ROCs to achieve fully integrated drilling process modeling and optimization in real time. The paper highlights the importance of a full-integrated approach to using real time drilling engineering and optimization methodology in order to gain valuable insights that allow operational teams to execute wells with minimal non-productive\u0000 Developing a functional real time drilling engineering methodology requires several years of failing fast and evolving towards a more improved performance organization where preemptive actions can be taken before problems occur. The methodology begins with performing full-integrated geomechanics study to understand the underlying geological uncertainties, stresses and faulting regimes within the area. The results from the geomechanical study form the basis for the detailed design of the casing, mud, cement, drillstring as well as the interaction of all these artifacts in order to develop operating parameters for well execution. Detailed drilling engineering road maps along with its associate risk matrices are developed to determine the operating ranges and bases of monitoring. During real time execution, these models including the 1-D geomechanical model, BHA design & modeling, casing design, fluids design, cementing design are updated continuously as more data become available in real time. The real time drilling engineering analysis coupled with integrated in-house and real-time center (iROC) personnel, 24/7 support provides immediate recommendations that can eliminate and avoid potential undesirable drilling events such as stuck pipes, lost circulations, and downhole tool failures.\u0000 By applying this integrated methodology in the Gulf of Mexico, a significant improvement in technical efficiency and by extension the operational efficiencies in performance through implementing same goals(s) focus, objectives aligned with collaborative planning, integrated 24/7 real-time operations support and solutions, execution and delivering correct and detailed communication protocols with united focal points across multiple stake holders. This resulted in completed well construction phase eight days ahead of schedule, with zero safety incidents.\u0000 This study validates the value of integrated services approach with focal point leadership using the right communication protocols with 24/7 monitoring and proactive support, i","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87341956","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}
Juhaida M. Johar, Maung Maung Myo Thant, T. M. Y. Tuan Mahmud, T. Z. T Aziz, M. F. Che Daud
Lately, one of the terminals in Peninsular Malaysia receives hydrocarbon with fine sand content from multiple offshore feeders. Majority of the sand particles size is below 16 µm with the presence of mercury and TENORM. Sand accumulates, causes erosion, and clogs the equipment and instrumentation devices installed. It has also impacted gas and condensate export specifications. The paper presents a techno-economic evaluation of sand management solution for the terminal to meet an export specification of maximum 5 µm sand particle size both in gas and condensate stream. The evaluation started with sand data establishment such as sand particle size distribution and sand concentration via online sand sampling. Sand Transport and Erosion Modelling Study was conducted using combination of PETRONAS owned Sand Suite Technology and commercial software for quantitative evaluation of sand mapping, deposition, and erosion within the facility. A total of eleven (11) proven sand technologies at various locations were screened and four (4) technologies were selected as a basis to develop solution options. Via Concept Select Methodology, the evaluations conducted based on Risk Ranking Criteria, CAPEX, OPEX and Schedule. The estimated performance for the selected option was quantified and sand disposal strategy was determined. An In-Vessel Cyclonic Device is proposed in the existing Condensate Separators and Cartridge Filter at upstream of the Condensate Metering. Gas System will be provided with new Cartridge Filters. These technologies are commercially proven to meet an export specification of 5µm. The proven technology for this application does not differ much for the last few years. New technologies are recommended to be deployed in the terminal and the performance of these technologies are quantified and compared. As the terminal was not originally designed to receive sand, sampling improvement is also proposed to collect more sand data prior to next engineering phase and to measure performance of the proposed technologies. The results from this study show that current technology could provide a solution to manage fine sand both in gas and condensate. PETRONAS in-house technologies are compared and could be a better option in reducing OPEX and operators’ exposure to hazardous components thus minimizing the impact of transported fine sand on surface equipment in general.
{"title":"Integrated Approach to Solving Sand Issues at Onshore Terminal","authors":"Juhaida M. Johar, Maung Maung Myo Thant, T. M. Y. Tuan Mahmud, T. Z. T Aziz, M. F. Che Daud","doi":"10.2523/iptc-22449-ms","DOIUrl":"https://doi.org/10.2523/iptc-22449-ms","url":null,"abstract":"\u0000 Lately, one of the terminals in Peninsular Malaysia receives hydrocarbon with fine sand content from multiple offshore feeders. Majority of the sand particles size is below 16 µm with the presence of mercury and TENORM. Sand accumulates, causes erosion, and clogs the equipment and instrumentation devices installed. It has also impacted gas and condensate export specifications. The paper presents a techno-economic evaluation of sand management solution for the terminal to meet an export specification of maximum 5 µm sand particle size both in gas and condensate stream.\u0000 The evaluation started with sand data establishment such as sand particle size distribution and sand concentration via online sand sampling. Sand Transport and Erosion Modelling Study was conducted using combination of PETRONAS owned Sand Suite Technology and commercial software for quantitative evaluation of sand mapping, deposition, and erosion within the facility. A total of eleven (11) proven sand technologies at various locations were screened and four (4) technologies were selected as a basis to develop solution options. Via Concept Select Methodology, the evaluations conducted based on Risk Ranking Criteria, CAPEX, OPEX and Schedule. The estimated performance for the selected option was quantified and sand disposal strategy was determined.\u0000 An In-Vessel Cyclonic Device is proposed in the existing Condensate Separators and Cartridge Filter at upstream of the Condensate Metering. Gas System will be provided with new Cartridge Filters. These technologies are commercially proven to meet an export specification of 5µm. The proven technology for this application does not differ much for the last few years. New technologies are recommended to be deployed in the terminal and the performance of these technologies are quantified and compared. As the terminal was not originally designed to receive sand, sampling improvement is also proposed to collect more sand data prior to next engineering phase and to measure performance of the proposed technologies.\u0000 The results from this study show that current technology could provide a solution to manage fine sand both in gas and condensate. PETRONAS in-house technologies are compared and could be a better option in reducing OPEX and operators’ exposure to hazardous components thus minimizing the impact of transported fine sand on surface equipment in general.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88327589","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. Klimov, R. Ramazanov, Nadir Husein, Vishwajit Upadhye, A. Drobot, A.Y. Bydzan, R. Gazizov
The proportion of hard-to-recover reserves is currently increasing and reached more than 65% of total conventional hydrocarbon reserves. This results in an increasing number of horizontal wells put into operation. When evaluating the hydrocarbon recovery efficiency in horizontal wells, and, consequently, the effectiveness of the development of gas condensate field, the key task is to evaluate the well productivity. To accomplish this task, it is necessary to obtain the reservoir fluid production profile for each interval. Conventional well logging methods with proven efficiency in vertical wells, in case of horizontal wells, will require costly asset-heavy applications such as coiled tubing and wireline conveyed production logging tools, and Y-tool bypass systems if pump is used. In addition, the logging data interpretation in the case of horizontal wells is less reliable due to the multiphase flow and variations of the fluid flow rate. The fluorescent -based nanomaterial production profiling surveillance technology can be used as a viable solution to this problem, which enables cheaper and more effective means of the development of hard-to-recover reserves. This technology assumes that tracers are placed downhole in various forms, such as marker tapes for lower completions, markers in the polymer coating of the proppant used for multi-stage hydraulic fracturing, and markers placed as fluid additive in fracturing fluids or matrix acidizing fluids during the production enhancement interventions. The fundamental difference between nanomaterial tracers production profiling and traditional logging methods is that the former offers the possibility to monitor the production at frac ports in the well for a long period of time with far less equipment and manpower, reduces HSE and operational risks and reduces operating cost.
{"title":"Dynamic Production Surveillance Method Effect in a Gas Condensate Horizontal Wells","authors":"M. Klimov, R. Ramazanov, Nadir Husein, Vishwajit Upadhye, A. Drobot, A.Y. Bydzan, R. Gazizov","doi":"10.2523/iptc-22261-ms","DOIUrl":"https://doi.org/10.2523/iptc-22261-ms","url":null,"abstract":"\u0000 The proportion of hard-to-recover reserves is currently increasing and reached more than 65% of total conventional hydrocarbon reserves. This results in an increasing number of horizontal wells put into operation. When evaluating the hydrocarbon recovery efficiency in horizontal wells, and, consequently, the effectiveness of the development of gas condensate field, the key task is to evaluate the well productivity. To accomplish this task, it is necessary to obtain the reservoir fluid production profile for each interval. Conventional well logging methods with proven efficiency in vertical wells, in case of horizontal wells, will require costly asset-heavy applications such as coiled tubing and wireline conveyed production logging tools, and Y-tool bypass systems if pump is used. In addition, the logging data interpretation in the case of horizontal wells is less reliable due to the multiphase flow and variations of the fluid flow rate.\u0000 The fluorescent -based nanomaterial production profiling surveillance technology can be used as a viable solution to this problem, which enables cheaper and more effective means of the development of hard-to-recover reserves. This technology assumes that tracers are placed downhole in various forms, such as marker tapes for lower completions, markers in the polymer coating of the proppant used for multi-stage hydraulic fracturing, and markers placed as fluid additive in fracturing fluids or matrix acidizing fluids during the production enhancement interventions.\u0000 The fundamental difference between nanomaterial tracers production profiling and traditional logging methods is that the former offers the possibility to monitor the production at frac ports in the well for a long period of time with far less equipment and manpower, reduces HSE and operational risks and reduces operating cost.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85487073","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}
Chao Zhou, Xu Zhao, Yashu Chen, Zhifa Wang, Eduardo Gramajo, R. Rached, Changpeng Hu
Autonomous inflow control device (AICD) completion has been applied in many conventional oil and gas reservoirs and has effectively controlled the water invasion. However, the method for designing and optimizing of AICD in sour gas reservoirs is still lacking. The objective of the proposed paper is to establish a numerical simulation and optimization method to evaluate and optimize the performance of AICD completion in water-bearing sour gas reservoirs. Firstly, a sulfur deposition saturation model is established considering non-darcy flow and stress sensitivity in sour gas reservoirs, meanwhile, time-varying skin factor is introduced to represent the influence of sulfur deposition on permeability. Secondly, a new type of AICD is designed, which has large flow channels and vortex chamber to satisfy the need of restraining water invasion and sulfur plugging in sour gas reservoirs. Finally, a reservoir-wellbore simulation method is established, which considers the sulfur deposition in the reservoir and the new AICDs in the wellbore, then the key parameters of AICD is optimized by orthogonal test and range analysis. The results of the numerical simulation show that the simulation and optimization method can effectively optimized the key parameters of AICD and the optimized AICD completion has good water invasion restriction capacity in water-bearing sour gas reservoirs. The optimized AICD completion causes little additional pressure drop compared to perforation completion in sour gas reservoirs, and the maximum additional pressure drop is less than 0.67 MPa, which means the optimized AICD completion is able to control water invasion as well as maintain normal gas production of sour gas wells. Besides, the optimized AICD completion decreases both the daily water production and the cumulative water production compared to perforation completion in sour gas reservoirs. In the last stage of the tenth year prediction period, the cumulative water production with AICD completion decreases by about 22.7% compared to that with perforation completion. In conclusion, the simulation and optimization method can be used for guiding the rational application of AICD completion in water-bearing sour gas reservoirs.
{"title":"Design and Optimization of Autonomous Inflow Control Device in Water-Bearing Sour Gas Reservoirs","authors":"Chao Zhou, Xu Zhao, Yashu Chen, Zhifa Wang, Eduardo Gramajo, R. Rached, Changpeng Hu","doi":"10.2523/iptc-22415-ms","DOIUrl":"https://doi.org/10.2523/iptc-22415-ms","url":null,"abstract":"\u0000 Autonomous inflow control device (AICD) completion has been applied in many conventional oil and gas reservoirs and has effectively controlled the water invasion. However, the method for designing and optimizing of AICD in sour gas reservoirs is still lacking. The objective of the proposed paper is to establish a numerical simulation and optimization method to evaluate and optimize the performance of AICD completion in water-bearing sour gas reservoirs. Firstly, a sulfur deposition saturation model is established considering non-darcy flow and stress sensitivity in sour gas reservoirs, meanwhile, time-varying skin factor is introduced to represent the influence of sulfur deposition on permeability. Secondly, a new type of AICD is designed, which has large flow channels and vortex chamber to satisfy the need of restraining water invasion and sulfur plugging in sour gas reservoirs. Finally, a reservoir-wellbore simulation method is established, which considers the sulfur deposition in the reservoir and the new AICDs in the wellbore, then the key parameters of AICD is optimized by orthogonal test and range analysis. The results of the numerical simulation show that the simulation and optimization method can effectively optimized the key parameters of AICD and the optimized AICD completion has good water invasion restriction capacity in water-bearing sour gas reservoirs. The optimized AICD completion causes little additional pressure drop compared to perforation completion in sour gas reservoirs, and the maximum additional pressure drop is less than 0.67 MPa, which means the optimized AICD completion is able to control water invasion as well as maintain normal gas production of sour gas wells. Besides, the optimized AICD completion decreases both the daily water production and the cumulative water production compared to perforation completion in sour gas reservoirs. In the last stage of the tenth year prediction period, the cumulative water production with AICD completion decreases by about 22.7% compared to that with perforation completion. In conclusion, the simulation and optimization method can be used for guiding the rational application of AICD completion in water-bearing sour gas reservoirs.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89982110","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}
Corrosion is a naturally occurring phenomenon commonly defined as the destructive attack of a metal that results from a chemical or electrochemical reaction with its environment. The effect of corrosion in the oil and gas industry leads to economic loss, a loss of containment and associated impact on HSE and asset integrity. There are many technologies to bring the oil to the surface. Rod or Beam pumps are the most common form of artificial lift for oil wells in onshore oilfields. They are simple machines that have a long and well documented history in the industry and are economically inexpensive. Corrosion inhibitors are commonly used to mitigate electrochemical corrosion in the oilfield. When added in small quantities to an aggressive medium, these chemicals inhibit corrosion by changing the surface conditions of the metal surface. In downhole systems, the prevailing conditions may be very severe, resulting in high corrosion rates. Corrosion inhibitors can be applied downhole, however, the selection and application of a corrosion inhibitor for downhole is typically more challenging than for a surface application. The paper gives a brief view on the selection of the suitable corrosion inhibitor that meets the well condition. It will explain how to select the best application methods for downhole corrosion on Rod Wells. The paper also demonstrates how the downhole treatment for rod wells is carried out giving in depth details of the method that has been used. It will present the results of a downhole treatment case and make recommendations for a performance monitoring program to optimize a treatment program ensuring its success. Finally, the paper concludes with a case history of downhole corrosion inhibitor application from an onshore field in the Middle East with 550 producing wells, where downhole corrosion inhibitor was successfully applied to 165 wells, leading to a major reduction in tubing corrosion failures
{"title":"Selection, Implementation and Monitoring of Corrosion Inhibitors for Downhole Chemical Treatment on Rod/Beam Pump Wells Bahrain Fields","authors":"Z. Ouled Ameur, Abdulla AlThawadi, Borislav Grbic","doi":"10.2523/iptc-22329-ms","DOIUrl":"https://doi.org/10.2523/iptc-22329-ms","url":null,"abstract":"\u0000 Corrosion is a naturally occurring phenomenon commonly defined as the destructive attack of a metal that results from a chemical or electrochemical reaction with its environment. The effect of corrosion in the oil and gas industry leads to economic loss, a loss of containment and associated impact on HSE and asset integrity. There are many technologies to bring the oil to the surface. Rod or Beam pumps are the most common form of artificial lift for oil wells in onshore oilfields. They are simple machines that have a long and well documented history in the industry and are economically inexpensive. Corrosion inhibitors are commonly used to mitigate electrochemical corrosion in the oilfield. When added in small quantities to an aggressive medium, these chemicals inhibit corrosion by changing the surface conditions of the metal surface. In downhole systems, the prevailing conditions may be very severe, resulting in high corrosion rates. Corrosion inhibitors can be applied downhole, however, the selection and application of a corrosion inhibitor for downhole is typically more challenging than for a surface application. The paper gives a brief view on the selection of the suitable corrosion inhibitor that meets the well condition. It will explain how to select the best application methods for downhole corrosion on Rod Wells. The paper also demonstrates how the downhole treatment for rod wells is carried out giving in depth details of the method that has been used. It will present the results of a downhole treatment case and make recommendations for a performance monitoring program to optimize a treatment program ensuring its success. Finally, the paper concludes with a case history of downhole corrosion inhibitor application from an onshore field in the Middle East with 550 producing wells, where downhole corrosion inhibitor was successfully applied to 165 wells, leading to a major reduction in tubing corrosion failures","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83516713","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}
Alawi G. Alalsayednassir, P. Berger, Charlotte Bergfloedt, Ronald Schmitz, Ryan Schmitz, Séan Emery
Digitization and automation have been areas of increasing focus in the drilling industry in recent years. One critical area of drilling operations that has been largely overlooked in the drive to digitization is the assessment of drill bit wear and damage. The International Association of Drilling Contractors (IADC) drill bit dull grading standard is the current industry reference to document the condition of a dull drill bit. Since these protocols rely on human interaction and judgement, the resulting data is limited in terms of its accuracy, its consistency, and its comparability. As a result, the usefulness of this data in improving how bits are designed and operated is also limited. This paper describes an experience of a new system, which involves scanning a drill bit, and digitally analysing the results, thereby overcoming the limitations of the current protocols. The implementation of the drill bit scanner and dull bit grading software services will contribute greatly to improve the inspection, and classification of drill bits. Furthermore, it will enable to monitor drill bit performance, and optimize drilling processes by utilizing the data provided by the system. The system described incorporates the automated generation of a digital three-dimensional visualization of a dull bit, which is then analysed digitally to assess wear and damage, on an individual cutter basis, as well as on an overall bit basis. Since the process is automated and digital in nature, the uncertainties related to human interaction and judgement in the process typically used today are eliminated. This data can then be used to identify drilling dysfunctions, and modify drilling procedures accordingly to optimize performance, as well as to identify potential improvements in drill bit design. Examples of digital dull bit analyses demonstrate that the bit wear data obtained from the system is much more detailed, more accurate, more consistent, and more comparable than the methods employed today. The resulting data is also much more suited to analytics, as well as other types of analyses, with a view to improving bit designs, identifying drilling dysfunctions causing bit damage, and optimizing drilling operating parameters to improve performance.
{"title":"AI-Enabled, Automated Digital Dull Bit Analysis - Field Experience","authors":"Alawi G. Alalsayednassir, P. Berger, Charlotte Bergfloedt, Ronald Schmitz, Ryan Schmitz, Séan Emery","doi":"10.2523/iptc-22001-ea","DOIUrl":"https://doi.org/10.2523/iptc-22001-ea","url":null,"abstract":"\u0000 Digitization and automation have been areas of increasing focus in the drilling industry in recent years. One critical area of drilling operations that has been largely overlooked in the drive to digitization is the assessment of drill bit wear and damage. The International Association of Drilling Contractors (IADC) drill bit dull grading standard is the current industry reference to document the condition of a dull drill bit. Since these protocols rely on human interaction and judgement, the resulting data is limited in terms of its accuracy, its consistency, and its comparability. As a result, the usefulness of this data in improving how bits are designed and operated is also limited.\u0000 This paper describes an experience of a new system, which involves scanning a drill bit, and digitally analysing the results, thereby overcoming the limitations of the current protocols. The implementation of the drill bit scanner and dull bit grading software services will contribute greatly to improve the inspection, and classification of drill bits. Furthermore, it will enable to monitor drill bit performance, and optimize drilling processes by utilizing the data provided by the system.\u0000 The system described incorporates the automated generation of a digital three-dimensional visualization of a dull bit, which is then analysed digitally to assess wear and damage, on an individual cutter basis, as well as on an overall bit basis. Since the process is automated and digital in nature, the uncertainties related to human interaction and judgement in the process typically used today are eliminated. This data can then be used to identify drilling dysfunctions, and modify drilling procedures accordingly to optimize performance, as well as to identify potential improvements in drill bit design.\u0000 Examples of digital dull bit analyses demonstrate that the bit wear data obtained from the system is much more detailed, more accurate, more consistent, and more comparable than the methods employed today. The resulting data is also much more suited to analytics, as well as other types of analyses, with a view to improving bit designs, identifying drilling dysfunctions causing bit damage, and optimizing drilling operating parameters to improve performance.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79704767","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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