Wangrong He, Houfeng He, Haoran Zheng, Pengcheng Liu
The thermal development process for light oil reservoirs using air injection technology is to release heat through low-temperature oxidation (LTO) between the injected air and crude oil and gradually increase the reaction zone’s temperature to displace crude oil. However, existing LTO experimental methods for air injection do not adequately capture the characteristics of LTO and struggle to directly obtain LTO kinetic parameters at low temperatures. In this paper, we used light oil samples from the Huabei Oilfield, China, as the studied objects and proposed innovative methods for obtaining and calculating LTO kinetic parameters. Further, we validated the feasibility of the proposed methods through experimental and numerical simulations. The results indicate that the lower limit temperature at which oxidation parameters can be directly measured through the accelerating rate calorimeter (ARC) experiments is 124°C. We matched the calculations from the ARC experiment curve-extension method for kinetic parameters with the results from both the high-pressure thermogravimetric analyzers (HP-TGA) experiment and the ramped thermal oxidizer (RTO) experiment. The fit between these results indicates that three methods are suitable for obtaining LTO parameters and can be used to derive chemical equations for LTO reactions in numerical simulation models. The simulation results from the reservoir scale indicate that, following air injection into the light oil reservoir, the peak temperature at the leading edge of the high-temperature zone reaches 370.9°C. The interaction between crude oil and air remains in the LTO phase, facilitating a sustained thermal accumulation within the reservoir. This study can provide a reference for reservoir development under similar conditions.
{"title":"Experimental Study on Low-Temperature-Oxidation Parameters and Simulations of Exothermic Process during Air Injection in Light Oil Reservoirs","authors":"Wangrong He, Houfeng He, Haoran Zheng, Pengcheng Liu","doi":"10.2118/219766-pa","DOIUrl":"https://doi.org/10.2118/219766-pa","url":null,"abstract":"\u0000 The thermal development process for light oil reservoirs using air injection technology is to release heat through low-temperature oxidation (LTO) between the injected air and crude oil and gradually increase the reaction zone’s temperature to displace crude oil. However, existing LTO experimental methods for air injection do not adequately capture the characteristics of LTO and struggle to directly obtain LTO kinetic parameters at low temperatures. In this paper, we used light oil samples from the Huabei Oilfield, China, as the studied objects and proposed innovative methods for obtaining and calculating LTO kinetic parameters. Further, we validated the feasibility of the proposed methods through experimental and numerical simulations. The results indicate that the lower limit temperature at which oxidation parameters can be directly measured through the accelerating rate calorimeter (ARC) experiments is 124°C. We matched the calculations from the ARC experiment curve-extension method for kinetic parameters with the results from both the high-pressure thermogravimetric analyzers (HP-TGA) experiment and the ramped thermal oxidizer (RTO) experiment. The fit between these results indicates that three methods are suitable for obtaining LTO parameters and can be used to derive chemical equations for LTO reactions in numerical simulation models. The simulation results from the reservoir scale indicate that, following air injection into the light oil reservoir, the peak temperature at the leading edge of the high-temperature zone reaches 370.9°C. The interaction between crude oil and air remains in the LTO phase, facilitating a sustained thermal accumulation within the reservoir. This study can provide a reference for reservoir development under similar conditions.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140759670","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Lei Hou, Derek Elsworth, Peibin Gong, Xiaobing Bian, Lei Zhang
Sand screenout, the most frequent incident during hydraulic fracturing, is one of the major threats to operational safety and efficiency. Screenout occurs when advancing hydraulic fractures are blocked by injected proppant-slurry, stall, and develop fluid overpressure. Because massive wells are still being hydraulically fractured every year, operational safety has become a critical and urgent issue that has always been overshadowed by the whether-or-not controversy. However, the suddenness and unheralded surprise of screenout make it extremely difficult to predict and handle. Previous efforts attempt to predict screenout as discrete events by interpreting injection pressure directly. We propose and then demonstrate a self-updating (via data and experience augmentation) and customizable (numerical models and algorithms) data-driven strategy of real-time monitoring and management for screenout based on records of shale gas fracturing. Two new indicators—proppant filling index (PFI) and safest fracturing pump rate (SFPR)—are improved and then integrated into the strategy. The PFI reveals the mismatch between injected proppant and hydraulic fractures and provides a continuous time-historical risk assessment of screenout. A pretrained ensemble learning model is applied to process the geological and hydraulic measurements in real time for the PFI evolution curve during fracturing operations. Integrated with the SFPR, a stepwise pump rate regulation strategy is deployed successfully to mitigate sand screenout for field applications. Four field trials are elaborated, which are representative cases exhibiting the data-driven approach to monitor and manage sand screenout during hydraulic fracturing.
{"title":"Integration of Real-Time Monitoring and Data Analytics to Mitigate Sand Screenouts During Fracturing Operations","authors":"Lei Hou, Derek Elsworth, Peibin Gong, Xiaobing Bian, Lei Zhang","doi":"10.2118/219747-pa","DOIUrl":"https://doi.org/10.2118/219747-pa","url":null,"abstract":"\u0000 Sand screenout, the most frequent incident during hydraulic fracturing, is one of the major threats to operational safety and efficiency. Screenout occurs when advancing hydraulic fractures are blocked by injected proppant-slurry, stall, and develop fluid overpressure. Because massive wells are still being hydraulically fractured every year, operational safety has become a critical and urgent issue that has always been overshadowed by the whether-or-not controversy. However, the suddenness and unheralded surprise of screenout make it extremely difficult to predict and handle. Previous efforts attempt to predict screenout as discrete events by interpreting injection pressure directly. We propose and then demonstrate a self-updating (via data and experience augmentation) and customizable (numerical models and algorithms) data-driven strategy of real-time monitoring and management for screenout based on records of shale gas fracturing. Two new indicators—proppant filling index (PFI) and safest fracturing pump rate (SFPR)—are improved and then integrated into the strategy. The PFI reveals the mismatch between injected proppant and hydraulic fractures and provides a continuous time-historical risk assessment of screenout. A pretrained ensemble learning model is applied to process the geological and hydraulic measurements in real time for the PFI evolution curve during fracturing operations. Integrated with the SFPR, a stepwise pump rate regulation strategy is deployed successfully to mitigate sand screenout for field applications. Four field trials are elaborated, which are representative cases exhibiting the data-driven approach to monitor and manage sand screenout during hydraulic fracturing.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140767476","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. Hmadeh, Andriani Manataki, M. Jaculli, B. Elahifar, S. Sangesland
The use of bismuth alloys as a barrier material for plugging and abandonment (P&A) has gained traction in the literature due to the large number of wells scheduled to be plugged and abandoned. In addition, many questions have been raised regarding the sealing efficiency of cement in the long run. Within this context, this work performs a thorough study of the sealability of plugs made with the eutectic bismuth-tin alloy. This effort is divided into three fronts: laboratory tests to verify the pressure resistance and leakage rate of these plugs, microscopy analyses to corroborate the tests’ insights through observations of the alloy microstructure, and numerical simulations to capture and model the involved phenomena aiming to reproduce real well scenarios in the future. Results show that bismuth-tin plugs exhibit better pressure resistance and lesser leakage rates than cement plugs, which indicates that this material is a suitable candidate. Better sealing properties are achieved when the plugs are set under higher curing pressures than the atmospheric pressure, an observation that is confirmed when observing the microstructures formed. Finally, a suitable material model that captures the expansion upon solidification is proposed, and the effect of thermal expansion on the plug and pipe assembly is observed.
{"title":"A Sealability Study on Bismuth-Tin Alloys for Plugging and Abandonment of Wells","authors":"L. Hmadeh, Andriani Manataki, M. Jaculli, B. Elahifar, S. Sangesland","doi":"10.2118/219744-pa","DOIUrl":"https://doi.org/10.2118/219744-pa","url":null,"abstract":"\u0000 The use of bismuth alloys as a barrier material for plugging and abandonment (P&A) has gained traction in the literature due to the large number of wells scheduled to be plugged and abandoned. In addition, many questions have been raised regarding the sealing efficiency of cement in the long run. Within this context, this work performs a thorough study of the sealability of plugs made with the eutectic bismuth-tin alloy. This effort is divided into three fronts: laboratory tests to verify the pressure resistance and leakage rate of these plugs, microscopy analyses to corroborate the tests’ insights through observations of the alloy microstructure, and numerical simulations to capture and model the involved phenomena aiming to reproduce real well scenarios in the future. Results show that bismuth-tin plugs exhibit better pressure resistance and lesser leakage rates than cement plugs, which indicates that this material is a suitable candidate. Better sealing properties are achieved when the plugs are set under higher curing pressures than the atmospheric pressure, an observation that is confirmed when observing the microstructures formed. Finally, a suitable material model that captures the expansion upon solidification is proposed, and the effect of thermal expansion on the plug and pipe assembly is observed.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140795381","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.
{"title":"Fluid Spontaneous Imbibition Under the Influence of Osmotic Pressure in Deep Coalbed Methane Reservoir in the Ordos Basin, China","authors":"Ruying Ma, Yanbin Yao, Xiaona Zhang, Xuguang Dai, Zefan Wang, Xiaoxiao Sun","doi":"10.2118/219751-pa","DOIUrl":"https://doi.org/10.2118/219751-pa","url":null,"abstract":"\u0000 The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140794392","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Uncertainty in geological models usually leads to large uncertainty in the predictions of risk-related system properties and/or risk metrics (e.g., CO2 plumes and CO2/brine leakage rates) at a geologic CO2 storage site. Different types of data (e.g., point measurements from monitoring wells and spatial data from 4D seismic surveys) can be leveraged or assimilated to reduce the risk predictions. In this work, we develop a novel framework for spatial data assimilation and risk forecasting. Under the U.S. Department of Energy’s National Risk Assessment Partnership (NRAP), we have developed a framework using an ensemble-based data assimilation approach for spatial data assimilation and forecasting. In particular, we took CO2 saturation maps interpreted from 4D seismic surveys as inputs for spatial data assimilation. Three seismic surveys at Years 1, 3, and 5 were considered in this study. Accordingly, three saturation maps were generated for data assimilation. The impact from the level of data noise was also investigated in this work. Our results show increased similarity between the updated reservoir models and the “ground-truth” model with the increased number of seismic surveys. Predictive accuracy in CO2 saturation plume increases with the increased number of seismic surveys as well. We also observed that with the increase in the level of data noise from 1% to 10%, the difference between the updated models and the ground truth does not increase significantly. Similar observations were made for the prediction of CO2 plume distribution at the end of the CO2 injection period by increasing the data noise.
{"title":"Assimilation of Geophysics-Derived Spatial Data for Model Calibration in Geologic CO2 Sequestration","authors":"Bailian Chen, Misael Morales, Zhiwei Ma, Qinjun Kang, Rajesh Pawar","doi":"10.2118/212975-pa","DOIUrl":"https://doi.org/10.2118/212975-pa","url":null,"abstract":"\u0000 Uncertainty in geological models usually leads to large uncertainty in the predictions of risk-related system properties and/or risk metrics (e.g., CO2 plumes and CO2/brine leakage rates) at a geologic CO2 storage site. Different types of data (e.g., point measurements from monitoring wells and spatial data from 4D seismic surveys) can be leveraged or assimilated to reduce the risk predictions. In this work, we develop a novel framework for spatial data assimilation and risk forecasting. Under the U.S. Department of Energy’s National Risk Assessment Partnership (NRAP), we have developed a framework using an ensemble-based data assimilation approach for spatial data assimilation and forecasting. In particular, we took CO2 saturation maps interpreted from 4D seismic surveys as inputs for spatial data assimilation. Three seismic surveys at Years 1, 3, and 5 were considered in this study. Accordingly, three saturation maps were generated for data assimilation. The impact from the level of data noise was also investigated in this work. Our results show increased similarity between the updated reservoir models and the “ground-truth” model with the increased number of seismic surveys. Predictive accuracy in CO2 saturation plume increases with the increased number of seismic surveys as well. We also observed that with the increase in the level of data noise from 1% to 10%, the difference between the updated models and the ground truth does not increase significantly. Similar observations were made for the prediction of CO2 plume distribution at the end of the CO2 injection period by increasing the data noise.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140785215","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Tingting Qiu, Yunsheng Wei, Haijun Yan, Minhua Cheng, Pengcheng Liu
Based on the nonlinear relationship between the cumulative gas production and the total pressure difference, a segmental material balance equation was applied, and an improved flow material balance (FMB) equation was proposed to calculate the dynamic reserves of shale gas reservoirs with a variable gas drainage radius. In the early stage, the shale gas well drainage radius gradually increased. The spread range of the formation pressure increased, but fractures gradually closed because of the enhancement of the effective stress. This resulted in stress sensitivity. In the middle to late stages, the gas drainage radius can be regarded as unchanged. The rate of increase in the pressure spreading range decreased, and the rate of decrease in the fracture closure decreased. The stress sensitivity can be ignored. To explain these phenomena, a segmental material balance equation was established. Furthermore, an improved FMB equation was obtained based on the productivity equation using the potential superposition theorem, and the drainage radius of horizontal wells was regarded as a variable for the last dynamic reserve calculation. Finally, the dynamic reserves of four shale gas wells were calculated. The comparison indicated that the proposed improved equation predictions agreed more closely with actual development experience than the conventional models based on the dynamic recovery rate calculation and the correlation coefficient obtained by data fitting. The proposed method improves the dynamic reserve calculations and contributes to well productivity evaluation.
{"title":"Improved Flow Material Balance Equation for Dynamic Reserve Calculation Considering Variable Gas Drainage Radius in Shale Gas Reservoirs","authors":"Tingting Qiu, Yunsheng Wei, Haijun Yan, Minhua Cheng, Pengcheng Liu","doi":"10.2118/219750-pa","DOIUrl":"https://doi.org/10.2118/219750-pa","url":null,"abstract":"\u0000 Based on the nonlinear relationship between the cumulative gas production and the total pressure difference, a segmental material balance equation was applied, and an improved flow material balance (FMB) equation was proposed to calculate the dynamic reserves of shale gas reservoirs with a variable gas drainage radius. In the early stage, the shale gas well drainage radius gradually increased. The spread range of the formation pressure increased, but fractures gradually closed because of the enhancement of the effective stress. This resulted in stress sensitivity. In the middle to late stages, the gas drainage radius can be regarded as unchanged. The rate of increase in the pressure spreading range decreased, and the rate of decrease in the fracture closure decreased. The stress sensitivity can be ignored. To explain these phenomena, a segmental material balance equation was established. Furthermore, an improved FMB equation was obtained based on the productivity equation using the potential superposition theorem, and the drainage radius of horizontal wells was regarded as a variable for the last dynamic reserve calculation. Finally, the dynamic reserves of four shale gas wells were calculated. The comparison indicated that the proposed improved equation predictions agreed more closely with actual development experience than the conventional models based on the dynamic recovery rate calculation and the correlation coefficient obtained by data fitting. The proposed method improves the dynamic reserve calculations and contributes to well productivity evaluation.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140772875","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dongyoung Yoon, P. Ashok, Eric van Oort, P. Annaiyappa, Shungo Abe, Akira Ebitani
Although mud pumps are considered to be critical rig equipment, their health monitoring currently still relies on infrequent human observation and monitoring. This approach often fails to detect pump damage at an early stage, resulting in nonproductive time (NPT) and increased well construction costs when initial damage progresses and pumps go down unexpectedly and catastrophically. Automated approaches to condition-based maintenance (CBM) of mud pumps to date have failed due to the lack of a generalized solution applicable to any pump type and/or operating conditions. This paper presents a field-validated universally applicable solution to mud pump CBM. The system uses a sensor package that includes acoustic emission sensors and accelerometers in combination with anomaly detection deep learning data analysis to pinpoint any abnormal behavior of the pump and its components. The deep learning models are trained with undamaged normal state data only, and a damage score characterizing the extent of damage to the mud pump is calculated to identify the earliest signs of damage. The system can then generate alerts to notify the rig crew of the damage level of key mud pump components, prompting proactive maintenance actions. Field tests were conducted while drilling an unconventional shale well in west Texas, USA, and a geothermal well in Japan (i.e., two very different drilling operations) to verify the feasibility and general applicability of the developed pump CBM solution. Sensors were attached to pump modules, and data were collected and analyzed using the deep learning models during drilling operations. During the field tests, different hyperparameters and features were compared to select the most effective ones for identifying damage while at the same time delivering low false positive rates (i.e., false alarms during normal state pump operation). The system required only several hours of normal state data for training with no prior pump information. Moreover, it correctly identified the degradation of the pump, swabs, and valves and produced early alerts several hours (in the range of 0.5–17 hours) before actual pump maintenance action was taken by the rig crew. This generally applicable pump CBM system eliminates the environmental, health, and safety concerns that can occur during human-based observations of mud pump health and avoids unnecessary NPT associated with catastrophic pump failures. The final version of this system will be a fully self-contained magnetically attachable box containing sensors and a processor, generating simple indicators for recommending proactive pump maintenance tasks when needed.
{"title":"Field Validation of a Universally Applicable Condition-Based Maintenance System for Mud Pumps","authors":"Dongyoung Yoon, P. Ashok, Eric van Oort, P. Annaiyappa, Shungo Abe, Akira Ebitani","doi":"10.2118/212564-pa","DOIUrl":"https://doi.org/10.2118/212564-pa","url":null,"abstract":"\u0000 Although mud pumps are considered to be critical rig equipment, their health monitoring currently still relies on infrequent human observation and monitoring. This approach often fails to detect pump damage at an early stage, resulting in nonproductive time (NPT) and increased well construction costs when initial damage progresses and pumps go down unexpectedly and catastrophically. Automated approaches to condition-based maintenance (CBM) of mud pumps to date have failed due to the lack of a generalized solution applicable to any pump type and/or operating conditions.\u0000 This paper presents a field-validated universally applicable solution to mud pump CBM. The system uses a sensor package that includes acoustic emission sensors and accelerometers in combination with anomaly detection deep learning data analysis to pinpoint any abnormal behavior of the pump and its components. The deep learning models are trained with undamaged normal state data only, and a damage score characterizing the extent of damage to the mud pump is calculated to identify the earliest signs of damage. The system can then generate alerts to notify the rig crew of the damage level of key mud pump components, prompting proactive maintenance actions.\u0000 Field tests were conducted while drilling an unconventional shale well in west Texas, USA, and a geothermal well in Japan (i.e., two very different drilling operations) to verify the feasibility and general applicability of the developed pump CBM solution. Sensors were attached to pump modules, and data were collected and analyzed using the deep learning models during drilling operations. During the field tests, different hyperparameters and features were compared to select the most effective ones for identifying damage while at the same time delivering low false positive rates (i.e., false alarms during normal state pump operation). The system required only several hours of normal state data for training with no prior pump information. Moreover, it correctly identified the degradation of the pump, swabs, and valves and produced early alerts several hours (in the range of 0.5–17 hours) before actual pump maintenance action was taken by the rig crew.\u0000 This generally applicable pump CBM system eliminates the environmental, health, and safety concerns that can occur during human-based observations of mud pump health and avoids unnecessary NPT associated with catastrophic pump failures. The final version of this system will be a fully self-contained magnetically attachable box containing sensors and a processor, generating simple indicators for recommending proactive pump maintenance tasks when needed.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140762939","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. R. Fassihi, R. Moore, P. Pereira Almao, S. Mehta, M. Ursenbach, D. Mallory
As part of greenhouse gas reduction initiatives, there have been many publications on carbon sequestration, reducing the carbon footprint of oil and gas operations, and generating carbonless fuel [e.g., hydrogen (H2)] by means of in-situ processes. In-situ upgrading (ISU) can help with these aspects by converting bitumen and heavy oil into low sulfur, low N2, and low asphaltene products, generating fewer emissions and producing hydrogen as a byproduct, thus helping with utilization of vast resources of energy that would otherwise be wasted due to extreme measures of no fossil fuel policies. In addition, such processes could produce more valuable products, enhanced shipping/pipelining, and less demanding downstream processing. In this paper, we provide new insights into the results of several combustion tube tests that were performed for Alberta Ingenuity Centre for In Situ Energy, using different heavy oils with fresh supported catalysts. The catalysts were placed in the production end of the combustion tube so oil would pass over the catalyst bed before being produced. In practice, solid catalyst particles could be placed into the oil-bearing formation adjacent to the producing wellbore, ensuring that crude oil will flow over the catalysts during oil production. In this paper, we use many laboratory results that have never been published before. The objective is to understand whether using catalysts has merit in our future oil production activities under the current environmental restrictions. A commercial Ni/Mo catalyst was used in these tests. The results of these tests indicated at least temporary significant occurrence of reactions such as hydroprocessing (HP) and hydrotreating reactions, such as hydrocracking, hydrodesulfurization (HDS), hydrodenitrogenation (HDN), and hydrodeoxygenation. They also generated a significant volume of hydrogen in situ. We will discuss the impact of pressure, temperature, water injection, and dispersed vs. supported catalysts on the degree of oil upgrading. Also, the key parameters that could impact in-situ hydrogen generation will be presented. Specifically, the role of reactions such as aquathermolysis, thermal cracking, water-gas shift (WGS, defined later) reaction, and coke gasification will willbe discussed. Note that the products of these reactions could undergo additional methanation (ME) reactions, which could reduce the H2 concentration in the produced gas. Finally, methods of upscaling these results to the field conditions will be presented.
{"title":"New Insights on Catalysts-Supported In-Situ Upgrading of Heavy Oil and Hydrogen Generation during In-Situ Combustion Oil Recovery","authors":"M. R. Fassihi, R. Moore, P. Pereira Almao, S. Mehta, M. Ursenbach, D. Mallory","doi":"10.2118/215092-pa","DOIUrl":"https://doi.org/10.2118/215092-pa","url":null,"abstract":"\u0000 As part of greenhouse gas reduction initiatives, there have been many publications on carbon sequestration, reducing the carbon footprint of oil and gas operations, and generating carbonless fuel [e.g., hydrogen (H2)] by means of in-situ processes. In-situ upgrading (ISU) can help with these aspects by converting bitumen and heavy oil into low sulfur, low N2, and low asphaltene products, generating fewer emissions and producing hydrogen as a byproduct, thus helping with utilization of vast resources of energy that would otherwise be wasted due to extreme measures of no fossil fuel policies. In addition, such processes could produce more valuable products, enhanced shipping/pipelining, and less demanding downstream processing.\u0000 In this paper, we provide new insights into the results of several combustion tube tests that were performed for Alberta Ingenuity Centre for In Situ Energy, using different heavy oils with fresh supported catalysts. The catalysts were placed in the production end of the combustion tube so oil would pass over the catalyst bed before being produced. In practice, solid catalyst particles could be placed into the oil-bearing formation adjacent to the producing wellbore, ensuring that crude oil will flow over the catalysts during oil production. In this paper, we use many laboratory results that have never been published before. The objective is to understand whether using catalysts has merit in our future oil production activities under the current environmental restrictions. A commercial Ni/Mo catalyst was used in these tests. The results of these tests indicated at least temporary significant occurrence of reactions such as hydroprocessing (HP) and hydrotreating reactions, such as hydrocracking, hydrodesulfurization (HDS), hydrodenitrogenation (HDN), and hydrodeoxygenation. They also generated a significant volume of hydrogen in situ.\u0000 We will discuss the impact of pressure, temperature, water injection, and dispersed vs. supported catalysts on the degree of oil upgrading. Also, the key parameters that could impact in-situ hydrogen generation will be presented. Specifically, the role of reactions such as aquathermolysis, thermal cracking, water-gas shift (WGS, defined later) reaction, and coke gasification will willbe discussed. Note that the products of these reactions could undergo additional methanation (ME) reactions, which could reduce the H2 concentration in the produced gas. Finally, methods of upscaling these results to the field conditions will be presented.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140781227","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Operating at high speeds can have the benefit of increasing the capability of pumps to enhance surface or downhole production of fluids with high gas volume fraction (GVF). This study presents the performance envelope of a high-speed helico-axial pump (HAP) operating at high GVFs (>80%). The ultimate aim of the physical tests was to ascertain the operating capabilities of the pump for potential scaleup to a field prototype. The HAP housing outer diameter was 5.38 in. and operated at a rotational speed of 6,000 rev/min. Air and water were the test fluids, with an average pump intake and a discharge temperature of 28°C. The fluid volume flow rates were varied while maintaining 46 psig at the HAP intake. The liquid and total intake volume flow rates varied from 128 B/D to 664 B/D and 4,941 B/D to 7,593 B/D, respectively. The corresponding dimensionless pressure boost (DPB), GVF, liquid flow coefficients (LFCs), and total flow coefficients (TFCs) were recorded. Additional parameters noted were the percentage of electric current draw to full-load motor current by the HAP motor and the percentage of electric power input to full load power to the HAP motor. The results showed that the HAP had a stable operation during the tests for intake GVF range of 91–98%. The corresponding pump DPB was in the range of 0.0138–0.0751. These values being positive indicated the capability of the HAP to boost fluid pressure even for such high intake gas content and avoid pump gas lock. The results also showed that for a given intake GVF, the HAP DPB increased with decreasing LFC. For a given LFC, the DPB decreased with increasing intake GVF. The percent electric input power to the HAP motor varied between 28% and 64% of full-load motor power. It was observed to strongly increase with decreasing LFC at a given intake GVF and very strongly decrease with increasing intake GVF at a given LFC. The associated percent electric current draw by the HAP motor was seen to vary between 24% and 53% of full-load motor current. Its variation with LFC and intake GVF was similar to those of the percent electric power input. The DPB, percent electric current, and power draw by the HAP motor variations with TFC for a given intake GVF were similar to those of the LFCs. In conclusion, the HAP demonstrated the capability to boost fluid pressure when handling high GVF flows. It is being scaled up to a field prototype to handle higher volume flow rates of high GVF gas-liquid mixtures. This study mainly highlights the method to extend the gas-handling capability of a HAP by operating it at high speeds. Optimal hydraulic design and proper conditioning of the inlet flow components were also incorporated into the HAP architecture. Expanding the HAP operating envelope to handle high-GVF flows significantly unlocks the potential for field operators to maximize hydrocarbon production from high-gas content applications. This, in turn, increases the economic bottom line from the field asset.
{"title":"Performance Envelope of a 538-Series High-Speed Helico-Axial Pump for High-Gas-Volume-Fraction Operation","authors":"C. Ejim, Jinjiang Xiao, Woon Lee, Wilson Zabala","doi":"10.2118/213740-pa","DOIUrl":"https://doi.org/10.2118/213740-pa","url":null,"abstract":"\u0000 Operating at high speeds can have the benefit of increasing the capability of pumps to enhance surface or downhole production of fluids with high gas volume fraction (GVF). This study presents the performance envelope of a high-speed helico-axial pump (HAP) operating at high GVFs (>80%). The ultimate aim of the physical tests was to ascertain the operating capabilities of the pump for potential scaleup to a field prototype.\u0000 The HAP housing outer diameter was 5.38 in. and operated at a rotational speed of 6,000 rev/min. Air and water were the test fluids, with an average pump intake and a discharge temperature of 28°C. The fluid volume flow rates were varied while maintaining 46 psig at the HAP intake. The liquid and total intake volume flow rates varied from 128 B/D to 664 B/D and 4,941 B/D to 7,593 B/D, respectively. The corresponding dimensionless pressure boost (DPB), GVF, liquid flow coefficients (LFCs), and total flow coefficients (TFCs) were recorded. Additional parameters noted were the percentage of electric current draw to full-load motor current by the HAP motor and the percentage of electric power input to full load power to the HAP motor.\u0000 The results showed that the HAP had a stable operation during the tests for intake GVF range of 91–98%. The corresponding pump DPB was in the range of 0.0138–0.0751. These values being positive indicated the capability of the HAP to boost fluid pressure even for such high intake gas content and avoid pump gas lock. The results also showed that for a given intake GVF, the HAP DPB increased with decreasing LFC. For a given LFC, the DPB decreased with increasing intake GVF. The percent electric input power to the HAP motor varied between 28% and 64% of full-load motor power. It was observed to strongly increase with decreasing LFC at a given intake GVF and very strongly decrease with increasing intake GVF at a given LFC. The associated percent electric current draw by the HAP motor was seen to vary between 24% and 53% of full-load motor current. Its variation with LFC and intake GVF was similar to those of the percent electric power input. The DPB, percent electric current, and power draw by the HAP motor variations with TFC for a given intake GVF were similar to those of the LFCs. In conclusion, the HAP demonstrated the capability to boost fluid pressure when handling high GVF flows. It is being scaled up to a field prototype to handle higher volume flow rates of high GVF gas-liquid mixtures.\u0000 This study mainly highlights the method to extend the gas-handling capability of a HAP by operating it at high speeds. Optimal hydraulic design and proper conditioning of the inlet flow components were also incorporated into the HAP architecture. Expanding the HAP operating envelope to handle high-GVF flows significantly unlocks the potential for field operators to maximize hydrocarbon production from high-gas content applications. This, in turn, increases the economic bottom line from the field asset.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140793065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Can Cai, Wenyang Cao, Xianpeng Yang, Pei Zhang, Lang Zeng, Shengwen Zhou
The drilling industry is paying increasing attention to deep and ultradeep wells because of the gradual decline and depletion of recoverable resources on the shallow surface. However, the difficulty of conventional mechanical rock-breaking grows significantly with increasing drilling depth. It has been found that the effect of a high-pressure water jet combined with a polycrystalline diamond compact (PDC) cutter is significant and can greatly increase the efficacy of rock breaking. A composite rock-breaking experimental device with a high-pressure jet was designed to carry out composite rock-breaking experiments. Meanwhile, a composite rock-breaking numerical model of high-pressure water jet-PDC cutter was created by smoothed particle hydrodynamics/finite element method (SPH/FEM). After verifying the reliability of the numerical model through experiments, the key factors, including rock stress field, cutting force, and jet field, were extracted to analyze the composite rock-breaking mechanism. The results show that the enhancing effect of jet impact on rock breaking is mainly reflected in three aspects: (1) The high-pressure water jet can create a groove and crater on the rock surface, effectively unloading the rock stress at the bottom of the well and increasing the area of rock damage; (2) PDC cutter vibration can be efficiently reduced with high-pressure jet; and (3) the rock debris in front of the cutter is cleaned in time, avoiding the waste of energy caused by the secondary cutting and reducing the temperature rise of the PDC cutter. Besides, it has been investigated how parameters like jet pressure, nozzle diameter, impact distance, and cutting depth influence the effect of jet rock breaking. The findings indicate that the best rock-breaking efficiency and economy occur at jet pressures of 30–40 MPa. Correspondingly, in terms of nozzle angle, nozzle diameter, and impact distance, the ideal ranges are 60°, 1.0–1.5 mm, and 10 mm, respectively, wherein the ideal impact distance is approximately 10 times the nozzle diameter. This research is critical for the advancement of high-pressure jet drilling technology and the design of supporting drill bits.
{"title":"Study on Composite Rock-Breaking Mechanism of Ultrahigh-Pressure Water Jet–PDC Cutter","authors":"Can Cai, Wenyang Cao, Xianpeng Yang, Pei Zhang, Lang Zeng, Shengwen Zhou","doi":"10.2118/219752-pa","DOIUrl":"https://doi.org/10.2118/219752-pa","url":null,"abstract":"\u0000 The drilling industry is paying increasing attention to deep and ultradeep wells because of the gradual decline and depletion of recoverable resources on the shallow surface. However, the difficulty of conventional mechanical rock-breaking grows significantly with increasing drilling depth. It has been found that the effect of a high-pressure water jet combined with a polycrystalline diamond compact (PDC) cutter is significant and can greatly increase the efficacy of rock breaking. A composite rock-breaking experimental device with a high-pressure jet was designed to carry out composite rock-breaking experiments. Meanwhile, a composite rock-breaking numerical model of high-pressure water jet-PDC cutter was created by smoothed particle hydrodynamics/finite element method (SPH/FEM). After verifying the reliability of the numerical model through experiments, the key factors, including rock stress field, cutting force, and jet field, were extracted to analyze the composite rock-breaking mechanism. The results show that the enhancing effect of jet impact on rock breaking is mainly reflected in three aspects: (1) The high-pressure water jet can create a groove and crater on the rock surface, effectively unloading the rock stress at the bottom of the well and increasing the area of rock damage; (2) PDC cutter vibration can be efficiently reduced with high-pressure jet; and (3) the rock debris in front of the cutter is cleaned in time, avoiding the waste of energy caused by the secondary cutting and reducing the temperature rise of the PDC cutter. Besides, it has been investigated how parameters like jet pressure, nozzle diameter, impact distance, and cutting depth influence the effect of jet rock breaking. The findings indicate that the best rock-breaking efficiency and economy occur at jet pressures of 30–40 MPa. Correspondingly, in terms of nozzle angle, nozzle diameter, and impact distance, the ideal ranges are 60°, 1.0–1.5 mm, and 10 mm, respectively, wherein the ideal impact distance is approximately 10 times the nozzle diameter. This research is critical for the advancement of high-pressure jet drilling technology and the design of supporting drill bits.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140789140","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：