Matthew S. Jackson, D. A. Howell, J. R. Bailey, Srinivasan Rajagopalan, A. Ozekcin, G. Inglish, C. Allen
Two novel wear-resistant, low-friction coatings were evaluated on sucker rod couplings in both laboratory and field settings. Laboratory testing simulated cyclic downhole motion while applying a realistic side loading of 74 lbs. force to mimic conditions in which tubing wear typically occurs. Standard spray-metal couplings were compared with coated couplings to assess tubing and coupling wear after 450,000 cycles. Three wells with high tubing failure frequencies were selected as field candidates for the coated couplings to assess their impact on tubing failure frequency. The coupling placement in the rod string targeted known areas of high wear in the production tubing of each well. Laboratory results showed that both coatings reduced tubing wear substantially when compared with the standard spray-metal couplings. Coating A reduced wear by a factor of 2X, and Coating B reduced wear by a factor of 6.6X, with the tubing still within drift ID after 450,000 cycles. During the lab tests, 0.0023 inches of material were removed from Coating A and 0.0001 inches was removed from Coating B. During field trials, Coating A increased the tubing life from an average of 5 to 20 (4X) months without failure in the two wells tested, at which point the field trial was ended. Coating B increased the tubing life from 6 to 19 (3.1X) months in the single sand producing well in which it was tested. Coating A was tested in a well with low sand concentration and Coating B was tested in a well with substantial sand present, showing that Coating B was able to perform in a more abrasive environment. In summary, the described coatings drastically reduced tubing wear in the lab which also translated directly into a reduction in frequency of costly tubing repair workovers. This paper presents how novel wear-resistant friction-reducing coated couplings can improve performance of problematic sucker rod pump wells that experience a high frequency of tubing failures due to wear.
{"title":"Wear Resistant, Friction Reducing Coatings Reduce Tubing Wear in Sucker Rod Couplings Application: Lab Testing and Field Trial Results","authors":"Matthew S. Jackson, D. A. Howell, J. R. Bailey, Srinivasan Rajagopalan, A. Ozekcin, G. Inglish, C. Allen","doi":"10.2118/191617-MS","DOIUrl":"https://doi.org/10.2118/191617-MS","url":null,"abstract":"\u0000 Two novel wear-resistant, low-friction coatings were evaluated on sucker rod couplings in both laboratory and field settings. Laboratory testing simulated cyclic downhole motion while applying a realistic side loading of 74 lbs. force to mimic conditions in which tubing wear typically occurs. Standard spray-metal couplings were compared with coated couplings to assess tubing and coupling wear after 450,000 cycles. Three wells with high tubing failure frequencies were selected as field candidates for the coated couplings to assess their impact on tubing failure frequency. The coupling placement in the rod string targeted known areas of high wear in the production tubing of each well.\u0000 Laboratory results showed that both coatings reduced tubing wear substantially when compared with the standard spray-metal couplings. Coating A reduced wear by a factor of 2X, and Coating B reduced wear by a factor of 6.6X, with the tubing still within drift ID after 450,000 cycles. During the lab tests, 0.0023 inches of material were removed from Coating A and 0.0001 inches was removed from Coating B. During field trials, Coating A increased the tubing life from an average of 5 to 20 (4X) months without failure in the two wells tested, at which point the field trial was ended. Coating B increased the tubing life from 6 to 19 (3.1X) months in the single sand producing well in which it was tested. Coating A was tested in a well with low sand concentration and Coating B was tested in a well with substantial sand present, showing that Coating B was able to perform in a more abrasive environment.\u0000 In summary, the described coatings drastically reduced tubing wear in the lab which also translated directly into a reduction in frequency of costly tubing repair workovers. This paper presents how novel wear-resistant friction-reducing coated couplings can improve performance of problematic sucker rod pump wells that experience a high frequency of tubing failures due to wear.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"103 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91055374","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}
Ongoing growth in the volume of raw data generated by digitized oil and gas operations has been widely documented (Spath, 2014). What may be less apparent is that the industry is also authoring dramatically more unstructured content—interpretations, learnings, case studies, etc.—on an annual basis. This is not surprising, as anecdotal evidence suggests that most decisions are taken on the basis of unstructured data (Quaadgras & Beath, 2011) (Garland, 2017) (Palkowsky, 2005) (Haines, Shaughnessy, & Briggs, 2006) (Hollingsworth & Schey, 2017). At the Society of Petroleum Engineers, the number of new papers published annually has followed an exponential growth curve that doubles approximately every 10-11 years, beginning as far back as the early 1950's.
{"title":"AI Supports Information Discovery and Analysis in an SPE Research Portal","authors":"E. Schoen, Reid G. Smith, John Boden","doi":"10.2118/191758-MS","DOIUrl":"https://doi.org/10.2118/191758-MS","url":null,"abstract":"\u0000 Ongoing growth in the volume of raw data generated by digitized oil and gas operations has been widely documented (Spath, 2014). What may be less apparent is that the industry is also authoring dramatically more unstructured content—interpretations, learnings, case studies, etc.—on an annual basis. This is not surprising, as anecdotal evidence suggests that most decisions are taken on the basis of unstructured data (Quaadgras & Beath, 2011) (Garland, 2017) (Palkowsky, 2005) (Haines, Shaughnessy, & Briggs, 2006) (Hollingsworth & Schey, 2017). At the Society of Petroleum Engineers, the number of new papers published annually has followed an exponential growth curve that doubles approximately every 10-11 years, beginning as far back as the early 1950's.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86468709","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}
Currently, as oil and gas companies continue to face risk of volatility in oil prices, production optimization and maintenance play a critical role in driving operational excellence for the industry while maintaining good profit margins. E&P companies must maintain a focus on reducing unit cost/barrel. This can be achieved by reducing operating costs, increasing production, and reducing downtime. We propose a recommendation engine driven by artificial intelligence (AI) that seamlessly integrates subsurface information and production characteristics for knowledge extraction needed to optimize production operations across conventional and unconventional assets. We used a three-phase approach to designing and building an advisory system that ingests data, learns patterns, and feeds these learnings from the data into different functional workflows necessary for improving the efficiency and effectiveness of production operations. The system uses these mechanisms of knowledge extraction, statistical learning, and contextual adaptation as it evolves into an autonomous asset optimization system that can proactively recommend actions for effective decision making to lower the unit cost/barrel.
{"title":"Artificial Intelligence–Driven Asset Optimizer","authors":"Supriya Gupta, Abhishek Sharma, A. Abubakar","doi":"10.2118/191551-MS","DOIUrl":"https://doi.org/10.2118/191551-MS","url":null,"abstract":"\u0000 Currently, as oil and gas companies continue to face risk of volatility in oil prices, production optimization and maintenance play a critical role in driving operational excellence for the industry while maintaining good profit margins. E&P companies must maintain a focus on reducing unit cost/barrel. This can be achieved by reducing operating costs, increasing production, and reducing downtime. We propose a recommendation engine driven by artificial intelligence (AI) that seamlessly integrates subsurface information and production characteristics for knowledge extraction needed to optimize production operations across conventional and unconventional assets. We used a three-phase approach to designing and building an advisory system that ingests data, learns patterns, and feeds these learnings from the data into different functional workflows necessary for improving the efficiency and effectiveness of production operations. The system uses these mechanisms of knowledge extraction, statistical learning, and contextual adaptation as it evolves into an autonomous asset optimization system that can proactively recommend actions for effective decision making to lower the unit cost/barrel.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85683618","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}
Pengpeng Qi, H. Lashgari, Haishan Luo, M. Delshad, G. Pope, M. Balhoff
Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.
{"title":"Simulation of Viscoelastic Polymer Flooding - From the Lab to the Field","authors":"Pengpeng Qi, H. Lashgari, Haishan Luo, M. Delshad, G. Pope, M. Balhoff","doi":"10.2118/191498-MS","DOIUrl":"https://doi.org/10.2118/191498-MS","url":null,"abstract":"\u0000 Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80442362","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}
Within the Oil and Gas industry the use of Acoustics data for flow rate estimation is increasingly being explored. One technique is to consider the total spectral power of the signal within a specific frequency range, known as an FBE. The FBE, along with measured Flow rates, can then be used to build a simple regression model to estimate the flow rate. We collect acoustic data using Distributed Acoustic Sensing, DAS, and find that the recorded FBE generally contains some corrupted data and outliers. This may be due to well shut-in periods or other physical phenomena, or it may be due to issues in the DAS recording itself. These outliers can have a detrimental effect on the calibration of any predictive model and lead to biased flow predictions. We combat this by calibrating out model using Robust Regression techniques, such as Least Absolute Deviation, which are less influenced by outliers. Another practical concern is choosing the correct frequency band for the FBE. This can be done by evaluating the model performance on a training set, however we find that the signal quality within a band can diminish over time necessitating a change in the band used. Our challenge is to find a way to identify when a band is likely to be giving poor predictions. We do this by looking at the ratios between different FBE bands, we find that under normal conditions these are highly correlated, however for certain bands this correlation is lost over time. This can be used to determine when it is time to switch to use a different band. This paper contains the motivation and results of these techniques as they are applied to flow prediction in a gas producing well which has been part of a long-term flow monitoring project.
{"title":"Robust Regression and Band Switching to Improve DAS Flow Estimates","authors":"Tim Park, R. Paleja, M. Wojtaszek","doi":"10.2118/191721-MS","DOIUrl":"https://doi.org/10.2118/191721-MS","url":null,"abstract":"\u0000 Within the Oil and Gas industry the use of Acoustics data for flow rate estimation is increasingly being explored. One technique is to consider the total spectral power of the signal within a specific frequency range, known as an FBE. The FBE, along with measured Flow rates, can then be used to build a simple regression model to estimate the flow rate. We collect acoustic data using Distributed Acoustic Sensing, DAS, and find that the recorded FBE generally contains some corrupted data and outliers. This may be due to well shut-in periods or other physical phenomena, or it may be due to issues in the DAS recording itself. These outliers can have a detrimental effect on the calibration of any predictive model and lead to biased flow predictions. We combat this by calibrating out model using Robust Regression techniques, such as Least Absolute Deviation, which are less influenced by outliers. Another practical concern is choosing the correct frequency band for the FBE. This can be done by evaluating the model performance on a training set, however we find that the signal quality within a band can diminish over time necessitating a change in the band used. Our challenge is to find a way to identify when a band is likely to be giving poor predictions. We do this by looking at the ratios between different FBE bands, we find that under normal conditions these are highly correlated, however for certain bands this correlation is lost over time. This can be used to determine when it is time to switch to use a different band. This paper contains the motivation and results of these techniques as they are applied to flow prediction in a gas producing well which has been part of a long-term flow monitoring project.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88826892","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}
A. Andrade, M. Chango, G. Atahualpa, R. Correa, G. Corona, Byron Calvopina, J. Pico
This paper presents an analysis of the effectiveness of various downhole completion designs in reducing or deferring water production in a mature field under the presence of an active strong aquifer reservoir. The results of completions using nozzle inflow control devices (ICDs) and fluidic diode autonomous ICDs (AICDs) are compared with conventional openhole and slotted liner completions. As all of these designs were installed in the same field/reservoir, the comparisons provide a meaningful and representative analysis of well production performance to assist in the identification of the most appropriate completion design for future wells and the production optimization of existing ones. The designed vs. actual production performance of inflow control completions providing water control (ICD/AICD) is presented and discussed. The methodology was developed from comparative analysis results of conventional openhole and slotted liner vs. ICD and AICD completions. The analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR) and water cut (WC) and used diagnostic plots to identify the water production mechanisms, historical drawdown (DD), productivity index (PI), and production cumulative performance (oil and water). The corrective actions are described, including operational procedures to reduce skin damage and screen plugging implemented in the Villano-23HST2 (V-23HST2) well, which is the longest horizontal well drilled in Ecuador and completed using AICDs; these corrective actions were based on lessons learned from the Villano-22D (V-22D) well, which included appropriate fluid [brine/oil-based mud (OBM)] conditioning, fluid displacement, filter cake removal, and compatibility testing between screens and the fluid in which the bottomhole assembly (BHA) was deployed. Additionally, this paper evaluates the importance of the design phase, emphasizing the importance of comparing preliminary data (permeability and water saturation) compared to actual results obtained from the initial production test. Finally, as good production results largely depend on successful operational procedures and execution, lessons learned and best practices for deploying downhole completions in future operations for the Villano field in Ecuador are discussed. Although many studies compare ICDs vs. conventional completions, few compare different inflow control technologies, such as ICDs vs. AICDs, within the same reservoir and with similar well conditions. This paper compares various inflow control technologies in the same field with cumulative production data, which verifies the effectiveness of each completion design. Based on these results, a validated methodology for ICD and AICD simulations and design is also described as the basis for achieving good production results.
{"title":"Production Performance of Multiple Completion Designs: Openhole, Slotted Liner, ICD, and AICD: A Case Study for Water Control in Villano Field, Ecuador","authors":"A. Andrade, M. Chango, G. Atahualpa, R. Correa, G. Corona, Byron Calvopina, J. Pico","doi":"10.2118/191635-MS","DOIUrl":"https://doi.org/10.2118/191635-MS","url":null,"abstract":"\u0000 This paper presents an analysis of the effectiveness of various downhole completion designs in reducing or deferring water production in a mature field under the presence of an active strong aquifer reservoir. The results of completions using nozzle inflow control devices (ICDs) and fluidic diode autonomous ICDs (AICDs) are compared with conventional openhole and slotted liner completions. As all of these designs were installed in the same field/reservoir, the comparisons provide a meaningful and representative analysis of well production performance to assist in the identification of the most appropriate completion design for future wells and the production optimization of existing ones. The designed vs. actual production performance of inflow control completions providing water control (ICD/AICD) is presented and discussed.\u0000 The methodology was developed from comparative analysis results of conventional openhole and slotted liner vs. ICD and AICD completions. The analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR) and water cut (WC) and used diagnostic plots to identify the water production mechanisms, historical drawdown (DD), productivity index (PI), and production cumulative performance (oil and water). The corrective actions are described, including operational procedures to reduce skin damage and screen plugging implemented in the Villano-23HST2 (V-23HST2) well, which is the longest horizontal well drilled in Ecuador and completed using AICDs; these corrective actions were based on lessons learned from the Villano-22D (V-22D) well, which included appropriate fluid [brine/oil-based mud (OBM)] conditioning, fluid displacement, filter cake removal, and compatibility testing between screens and the fluid in which the bottomhole assembly (BHA) was deployed. Additionally, this paper evaluates the importance of the design phase, emphasizing the importance of comparing preliminary data (permeability and water saturation) compared to actual results obtained from the initial production test. Finally, as good production results largely depend on successful operational procedures and execution, lessons learned and best practices for deploying downhole completions in future operations for the Villano field in Ecuador are discussed.\u0000 Although many studies compare ICDs vs. conventional completions, few compare different inflow control technologies, such as ICDs vs. AICDs, within the same reservoir and with similar well conditions. This paper compares various inflow control technologies in the same field with cumulative production data, which verifies the effectiveness of each completion design. Based on these results, a validated methodology for ICD and AICD simulations and design is also described as the basis for achieving good production results.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76795362","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}
Jianjun Zhu, Zhihua Wang, Haiwen Zhu, R. Cuamatzi-Meléndez, Jose Alberto Martinez-Farfan, Zhang Jiecheng, Hong-quan Zhang
As an artificial lift method for high-flow-rate oil production, electrical submersible pumps’ (ESP) performance surfers from gas entrainment, a frequently encountered phenomenon in ESPs. When it occurs, ESPs can experience moderate or severe head degradation accompanied with production rate reduction, gas locking and flow instabilities. For the design and operation of an ESP-based production system, the accurate model is needed to predict ESP boosting pressure under gassy flow conditions. In this paper, a simplified mechanistic model is proposed to model gas-liquid flow inside a rotating ESP. The model not only maps flow patterns in ESPs but also captures the multiphase flow characteristics in terms of in-situ gas void fraction, boosting pressure, bubble size, etc. The experimental facility for testing ESP gas-liquid performance comprises of a 3″ stainless steel fully closed liquid flow loop and ½″ semi-open gas flow loop. A radial-type ESP with 14 stages, assembled in series, was horizontally mounted on the testing rig. Pressure ports were drilled at each stage to measure stage-by-stage pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive gas was vented and the liquid continues circulation. Experimental data were acquired with two types of tests (mapping tests and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure etc. were controlled in the experiments. The new model starts form from Euler equations, and introduces a best-match flowrate at which the flow direction at ESP impeller outlet matches the designed flow direction. The mismatch of velocity triangle in a rotating impeller results from the varying liquid flow rates. Losses due to flow direction change, friction, and leakage etc., were incorporated in the model. Based on the force balance on a stable gas bubble in a centrifugal flow field, the in-situ gas void fraction inside a rotating ESP impeller can be estimated, from which the gas-liquid mixture density is calculated. The predicted ESP boosting pressures match the corresponding experimental measurements with acceptable accuracy.
{"title":"Mechanistic Modeling of Electrical Submersible Pump ESP Boosting Pressure Under Gassy Flow Conditions and Experimental Validation","authors":"Jianjun Zhu, Zhihua Wang, Haiwen Zhu, R. Cuamatzi-Meléndez, Jose Alberto Martinez-Farfan, Zhang Jiecheng, Hong-quan Zhang","doi":"10.2118/191638-MS","DOIUrl":"https://doi.org/10.2118/191638-MS","url":null,"abstract":"\u0000 As an artificial lift method for high-flow-rate oil production, electrical submersible pumps’ (ESP) performance surfers from gas entrainment, a frequently encountered phenomenon in ESPs. When it occurs, ESPs can experience moderate or severe head degradation accompanied with production rate reduction, gas locking and flow instabilities. For the design and operation of an ESP-based production system, the accurate model is needed to predict ESP boosting pressure under gassy flow conditions. In this paper, a simplified mechanistic model is proposed to model gas-liquid flow inside a rotating ESP. The model not only maps flow patterns in ESPs but also captures the multiphase flow characteristics in terms of in-situ gas void fraction, boosting pressure, bubble size, etc.\u0000 The experimental facility for testing ESP gas-liquid performance comprises of a 3″ stainless steel fully closed liquid flow loop and ½″ semi-open gas flow loop. A radial-type ESP with 14 stages, assembled in series, was horizontally mounted on the testing rig. Pressure ports were drilled at each stage to measure stage-by-stage pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive gas was vented and the liquid continues circulation. Experimental data were acquired with two types of tests (mapping tests and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure etc. were controlled in the experiments.\u0000 The new model starts form from Euler equations, and introduces a best-match flowrate at which the flow direction at ESP impeller outlet matches the designed flow direction. The mismatch of velocity triangle in a rotating impeller results from the varying liquid flow rates. Losses due to flow direction change, friction, and leakage etc., were incorporated in the model. Based on the force balance on a stable gas bubble in a centrifugal flow field, the in-situ gas void fraction inside a rotating ESP impeller can be estimated, from which the gas-liquid mixture density is calculated. The predicted ESP boosting pressures match the corresponding experimental measurements with acceptable accuracy.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86863676","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}
Ram R. Ratnakar, A. Venkatraman, A. Kalra, B. Dindoruk
Geological storage of CO2 in deep saline aquifers has become a well-accepted method for CO2 sequestration. CO2-solubility in these brine solutions is one of the most important factors in determining the amount of CO2 sequestered in these aquifers. Since the type of salt can significantly alter the CO2-solubility in brine solutions, the impact of water chemistry on CO2 solubility is investigated in this work and results are compared against experimental observations. The current work for predicting solubility of a gas in brine solution containing various salts is based on the extension of well-known Setschenow relation that has been commonly used for salts with monovalent ions. In this research, we extend the Setschenow approach by expressing the solubility in terms of ionic strengths and molar concentrations of each salt. The method also characterizes each component (e.g., gas, anions and cations) against the experimental measurements. A simple methodology, developed with a theoretical framework, is presented to predict the impact of different types of salts on solubility of CO2. This approach can be extended to any type of gases or other solutes (e.g. CH4, H2S etc.) in brine solutions. In particular, The gas solubility in brines is expressed in terms of molar components and ionic strength of each salt. The expression contains unique/characteristic parameters for each component (gas, anions and cations). These parameters for anions and cations of typical formation water (present in oil/gas reservoirs) and CO2/novel solvents are obtained from literature or using regression on experimental data.Results of CO2-solubility were compared with published data in literature, demonstrating that the methodology (presented in the work) can predict the effect of water-chemistry on solubility predictions.The proposed method was tested for a novel solvent (dimethyl ether) and comparison with experimental solubility data show an excellent match between the predictions and measurements.
{"title":"On the Prediction of Gas Solubility in Brine Solutions for Applications of CO2 Capture and Sequestration","authors":"Ram R. Ratnakar, A. Venkatraman, A. Kalra, B. Dindoruk","doi":"10.2118/191541-MS","DOIUrl":"https://doi.org/10.2118/191541-MS","url":null,"abstract":"\u0000 Geological storage of CO2 in deep saline aquifers has become a well-accepted method for CO2 sequestration. CO2-solubility in these brine solutions is one of the most important factors in determining the amount of CO2 sequestered in these aquifers. Since the type of salt can significantly alter the CO2-solubility in brine solutions, the impact of water chemistry on CO2 solubility is investigated in this work and results are compared against experimental observations.\u0000 The current work for predicting solubility of a gas in brine solution containing various salts is based on the extension of well-known Setschenow relation that has been commonly used for salts with monovalent ions. In this research, we extend the Setschenow approach by expressing the solubility in terms of ionic strengths and molar concentrations of each salt. The method also characterizes each component (e.g., gas, anions and cations) against the experimental measurements.\u0000 A simple methodology, developed with a theoretical framework, is presented to predict the impact of different types of salts on solubility of CO2. This approach can be extended to any type of gases or other solutes (e.g. CH4, H2S etc.) in brine solutions. In particular, The gas solubility in brines is expressed in terms of molar components and ionic strength of each salt. The expression contains unique/characteristic parameters for each component (gas, anions and cations). These parameters for anions and cations of typical formation water (present in oil/gas reservoirs) and CO2/novel solvents are obtained from literature or using regression on experimental data.Results of CO2-solubility were compared with published data in literature, demonstrating that the methodology (presented in the work) can predict the effect of water-chemistry on solubility predictions.The proposed method was tested for a novel solvent (dimethyl ether) and comparison with experimental solubility data show an excellent match between the predictions and measurements.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91083684","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}
During the development phase of a gas field, the abnormal pressure in a dolomitic limestone formation demanded an extremely high mud weight to control the well. The casing design of this case-study field has entailed the installation of a 7″ × 9-5/8″ liner hanger in combination with a liner top packer followed by a tieback to surface. Due to this hole section being directly above the pay zone, it is crucial that the liner installation and the wellbore integrity are not compromised for the subsequent well completion. The downhole pressure conditions require a drilling mud weight up to 157 pcf (~ 21 ppg), where solids content could reach as high as 49% using conventional weighing materials. For a liner deployment, this means that the high concentration of solids can cause plugging in the setting ports of conventional hydraulic liner hanger and running tool system. Additionally, the thin balance between ECDs and the formation fracture pressures in this field generated events of severe fluid loss during the liner deployment or while cementing. A liner not fully supported by cement — due to severe fluid loss during cementation — can experience ballooning, and be unable to withstand piston forces acting against the liner top packer during well completion operations. These forces can, in some cases, exceed the ratings of the liner top packer's hold-down slips, therefore allowing the packing element of the liner top packer to not set properly. For these reasons, an optimized deployment strategy was planned and implemented to address these challenges. It included improvements to the hydraulic liner hanger and running tool system, calculations to simulate an optimal running speed of the liner, enhanced procedures for liner deployment and cementation, including revised setting procedures for the liner hanger slips, and modifications to drill pipe wiper plug design. The objective of this paper is to detail the benefits of implementation, detailed pre-job planning, improvements for optimal drilling mud properties and modifications to the liner hanger system, and procedures that resulted in successful deployments of liners in this field. In addition, a case study will be shared as a way to institute lessons learned and best practices.
{"title":"Deployment of Liner Systems in Extreme High Mud Weight Environments in Gas Wells","authors":"A. H. Oqaili, A. Alluhaydan, P. C. Ezi, A. Tirado","doi":"10.2118/191594-MS","DOIUrl":"https://doi.org/10.2118/191594-MS","url":null,"abstract":"\u0000 During the development phase of a gas field, the abnormal pressure in a dolomitic limestone formation demanded an extremely high mud weight to control the well. The casing design of this case-study field has entailed the installation of a 7″ × 9-5/8″ liner hanger in combination with a liner top packer followed by a tieback to surface. Due to this hole section being directly above the pay zone, it is crucial that the liner installation and the wellbore integrity are not compromised for the subsequent well completion.\u0000 The downhole pressure conditions require a drilling mud weight up to 157 pcf (~ 21 ppg), where solids content could reach as high as 49% using conventional weighing materials. For a liner deployment, this means that the high concentration of solids can cause plugging in the setting ports of conventional hydraulic liner hanger and running tool system. Additionally, the thin balance between ECDs and the formation fracture pressures in this field generated events of severe fluid loss during the liner deployment or while cementing. A liner not fully supported by cement — due to severe fluid loss during cementation — can experience ballooning, and be unable to withstand piston forces acting against the liner top packer during well completion operations. These forces can, in some cases, exceed the ratings of the liner top packer's hold-down slips, therefore allowing the packing element of the liner top packer to not set properly.\u0000 For these reasons, an optimized deployment strategy was planned and implemented to address these challenges. It included improvements to the hydraulic liner hanger and running tool system, calculations to simulate an optimal running speed of the liner, enhanced procedures for liner deployment and cementation, including revised setting procedures for the liner hanger slips, and modifications to drill pipe wiper plug design.\u0000 The objective of this paper is to detail the benefits of implementation, detailed pre-job planning, improvements for optimal drilling mud properties and modifications to the liner hanger system, and procedures that resulted in successful deployments of liners in this field. In addition, a case study will be shared as a way to institute lessons learned and best practices.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81684129","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}
ESPs are a main type of artificial lift being used to unload current horizontal unconventional wells. Due to their high cost and high failure rate an operator must implement them in the most efficient manner possible. This paper addresses a way to create a solution to make ESPs more efficient by using compression at surface. Current ways of handling gas through ESPs are insufficient utilizing variable speed drives (VSDs). Additional gas handling equipment installed in ESPs have also encountered mixed results as designs continue to be tinkered to improve gas handling. One area that has not been researched extensively is utilizing compression to drawdown the casing annulus of a well on ESP. A preferential path of less static head pressure allows the gas to be drawn up the annulus rather than handled through the pump. Thereby alleviating gas handling problems in the ESP and raising the FL over the pump. The paper presents two case studies in Oklahoma involving ESP compression assistance up the annulus: one is a case study of an unconventional well of the Mississippi Lime with a low FL and moderate gas production, the second is an unconventional well in the Meramec formation with large amounts of gas production that was increased with the assistance of a compressor to the ESP. Data was collected over a six-week period and ESP performance is compared before and after the surface compressor installation for case 1. In case 2, well performance is compared for 3 different artificial lift setups: gas lift, ESP, and compression assisted ESP over a 3-month period. Both case studies show benefits for utilizing surface compression with an ESP. The biggest benefits were found to be increased production and reduced operating cost by extending ESP longevity.
{"title":"Improving ESP Production Through Compression","authors":"P. Munding, J. Hudson","doi":"10.2118/191486-MS","DOIUrl":"https://doi.org/10.2118/191486-MS","url":null,"abstract":"\u0000 ESPs are a main type of artificial lift being used to unload current horizontal unconventional wells. Due to their high cost and high failure rate an operator must implement them in the most efficient manner possible. This paper addresses a way to create a solution to make ESPs more efficient by using compression at surface.\u0000 Current ways of handling gas through ESPs are insufficient utilizing variable speed drives (VSDs). Additional gas handling equipment installed in ESPs have also encountered mixed results as designs continue to be tinkered to improve gas handling. One area that has not been researched extensively is utilizing compression to drawdown the casing annulus of a well on ESP. A preferential path of less static head pressure allows the gas to be drawn up the annulus rather than handled through the pump. Thereby alleviating gas handling problems in the ESP and raising the FL over the pump.\u0000 The paper presents two case studies in Oklahoma involving ESP compression assistance up the annulus: one is a case study of an unconventional well of the Mississippi Lime with a low FL and moderate gas production, the second is an unconventional well in the Meramec formation with large amounts of gas production that was increased with the assistance of a compressor to the ESP. Data was collected over a six-week period and ESP performance is compared before and after the surface compressor installation for case 1. In case 2, well performance is compared for 3 different artificial lift setups: gas lift, ESP, and compression assisted ESP over a 3-month period.\u0000 Both case studies show benefits for utilizing surface compression with an ESP. The biggest benefits were found to be increased production and reduced operating cost by extending ESP longevity.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79385932","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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