Weishu Zhao, Xiao Jinjiang, Hussain Saiood, Abdulrahman B. Otaibi, Jin Huang, F. Chang
Electric Submersible Pumps (ESP) are common artificial lift equipment for boosting well productions. One of the challenges faced with ESP applications is the ESP system reliability. High percentage of ESP failures resulted from problems of packer penetrators that locate beneath the ESP packers. These failures could be attributed to the corrosion of the power delivery systems by highly corrosive chemicals and harsh downhole conditions. A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive environments. Mixture of low-density polymeric materials can be pumped through the bypass tubing. The mixture has lower density than downhole fluids so that it travels upwards in the wellbore. Under high temperature in the well, a rigid gel system forms and isolates the electric connector from the hostile chemicals thus providing a better protection. The rigid low density gel system was tested in the lab scale. The tested fluid system comprises of colloidal particles and thermal plastic microspheres. The colloidal particles forms a rigid gel under elevated temperature while the thermal plastic microspheres act as light weight fillers. Gelation tests are conducted under different temperature and pressure conditions. The system has a lower density than crude oil and the gelation process can be controlled by chemical concentration. Sealing effects with the presence of crude oil are tested in rusty metal pipe to imitate casing material. A wellbore injection physical simulator was also setup to observe the flow dynamics and chemical reaction that could take place in the wellbore. The field trial test was performed after a through engineering design. Coiled tubing (CT) was selected as the optimum solution for intervention and placing the fluid system. Mixture of low-density materials and gelling agent were prepared on the surface and then pumped into the targeted section utilizing 2.0" coiled-tubing (CT) nozzles. Conventional bottomhole assembly was utilized to seal the tubing section and divert the fluid system to annulus.
{"title":"Chemical Solution to ESP Packer Penetrator Corrosion Problem","authors":"Weishu Zhao, Xiao Jinjiang, Hussain Saiood, Abdulrahman B. Otaibi, Jin Huang, F. Chang","doi":"10.2523/iptc-19633-ms","DOIUrl":"https://doi.org/10.2523/iptc-19633-ms","url":null,"abstract":"\u0000 Electric Submersible Pumps (ESP) are common artificial lift equipment for boosting well productions. One of the challenges faced with ESP applications is the ESP system reliability. High percentage of ESP failures resulted from problems of packer penetrators that locate beneath the ESP packers. These failures could be attributed to the corrosion of the power delivery systems by highly corrosive chemicals and harsh downhole conditions. A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive environments. Mixture of low-density polymeric materials can be pumped through the bypass tubing. The mixture has lower density than downhole fluids so that it travels upwards in the wellbore. Under high temperature in the well, a rigid gel system forms and isolates the electric connector from the hostile chemicals thus providing a better protection.\u0000 The rigid low density gel system was tested in the lab scale. The tested fluid system comprises of colloidal particles and thermal plastic microspheres. The colloidal particles forms a rigid gel under elevated temperature while the thermal plastic microspheres act as light weight fillers. Gelation tests are conducted under different temperature and pressure conditions. The system has a lower density than crude oil and the gelation process can be controlled by chemical concentration. Sealing effects with the presence of crude oil are tested in rusty metal pipe to imitate casing material. A wellbore injection physical simulator was also setup to observe the flow dynamics and chemical reaction that could take place in the wellbore.\u0000 The field trial test was performed after a through engineering design. Coiled tubing (CT) was selected as the optimum solution for intervention and placing the fluid system. Mixture of low-density materials and gelling agent were prepared on the surface and then pumped into the targeted section utilizing 2.0\" coiled-tubing (CT) nozzles. Conventional bottomhole assembly was utilized to seal the tubing section and divert the fluid system to annulus.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132429973","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}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19993-abstract
Reem Alsadoun, Mohammad Al Momen, Hongtao Luo
All producing wells experience reservoir pressure depletion which will ultimately cause production to cease. However, the accumulation of wellbore liquid known as liquid loading can reduce production at a faster rate bringing forward the end of well life. In theory, there are many works written on liquid loading in unconventional wells however, these assumptions are challenged when implemented in the field. The aim of this paper is to investigate the relationship between empirical and mechanistic methods used to determine liquid loading critical rates for volatile oil and gas condensate wells, improving liquid loading forecast workflow for future wells. The study was carried on a wide Pressure, Volume, and Temperature (PVT) window with varying compositions ranging from gas condensate to volatile oils. Wells with liquid loading exhibit sharp drops and fluctuations in production. Due to the wide variation in composition however, correlations used must be varied whilst accounting for both composition and horizontal configuration of the well. Using Nodal Analysis methods, Inflow Performance Relationships (IPR) and Vertical Lift Profile (VLP) curves were created from different correlation models fitted for multiple wells selected for this study to optimize well performance. By combining theoretical analysis and field practices for estimating liquid loading critical rate, the appropriate workflow was determined for the volatile oil and gas condensate wells. When comparing the critical rate for liquid loading calculated from theoretical methods against actual rates seen in the field, an inconsistency was observed between the two values for several wells. By establishing a relationship between field estimate and theoretical calculations, liquid loading was forecasted with greater certainty for varying PVT windows. When the liquid loading rate is determined earlier on, the production efficiency can be improved by deploying unloading measures, increasing the well’s producing life, and ultimately alleviating economic losses. By investigating, we were able to establish a suitable process to predict liquid loading critical rates for volatile oil and gas condensate wells. This workflow can be utilized by production engineers to arrange for liquid loading mitigation increasing well life and improving well economics.
{"title":"Prediction of Liquid Loading in Gas Condensate and Volatile Oil Wells for Unconventional Reservoirs","authors":"Reem Alsadoun, Mohammad Al Momen, Hongtao Luo","doi":"10.2523/iptc-19993-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19993-abstract","url":null,"abstract":"\u0000 All producing wells experience reservoir pressure depletion which will ultimately cause production to cease. However, the accumulation of wellbore liquid known as liquid loading can reduce production at a faster rate bringing forward the end of well life. In theory, there are many works written on liquid loading in unconventional wells however, these assumptions are challenged when implemented in the field. The aim of this paper is to investigate the relationship between empirical and mechanistic methods used to determine liquid loading critical rates for volatile oil and gas condensate wells, improving liquid loading forecast workflow for future wells.\u0000 The study was carried on a wide Pressure, Volume, and Temperature (PVT) window with varying compositions ranging from gas condensate to volatile oils. Wells with liquid loading exhibit sharp drops and fluctuations in production. Due to the wide variation in composition however, correlations used must be varied whilst accounting for both composition and horizontal configuration of the well. Using Nodal Analysis methods, Inflow Performance\u0000 Relationships (IPR) and Vertical Lift Profile (VLP) curves were created from different correlation models fitted for multiple wells selected for this study to optimize well performance. By combining theoretical analysis and field practices for estimating liquid loading critical rate, the appropriate workflow was determined for the volatile oil and gas condensate wells.\u0000 When comparing the critical rate for liquid loading calculated from theoretical methods against actual rates seen in the field, an inconsistency was observed between the two values for several wells. By establishing a relationship between field estimate and theoretical calculations, liquid loading was forecasted with greater certainty for varying PVT windows. When the liquid loading rate is determined earlier on, the production efficiency can be improved by deploying unloading measures, increasing the well’s producing life, and ultimately alleviating economic losses. By investigating, we were able to establish a suitable process to predict liquid loading critical rates for volatile oil and gas condensate wells. This workflow can be utilized by production engineers to arrange for liquid loading mitigation increasing well life and improving well economics.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114777457","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}
Pub Date : 2020-01-13DOI: 10.2523/iptc-20200-abstract
P. Bangert
The NOx and SOx output of a combined heat and power plant is studied with the aim of replacing the physical sensor array with a mathematical formula that can compute the emissions rather than measure them. The model is determined using machine learning from historical measurements and uses neural networks. As the model can be cheaply deployed, will not drift, and will not malfunction or fail, the model has significant added value over a physical sensor. We find that the accuracy of the model is comparable to the accuracy of the measurement and is thus suitable for a full replacement.
{"title":"Determining NOx And SOx Emissions by Soft Sensor","authors":"P. Bangert","doi":"10.2523/iptc-20200-abstract","DOIUrl":"https://doi.org/10.2523/iptc-20200-abstract","url":null,"abstract":"\u0000 The NOx and SOx output of a combined heat and power plant is studied with the aim of replacing the physical sensor array with a mathematical formula that can compute the emissions rather than measure them. The model is determined using machine learning from historical measurements and uses neural networks. As the model can be cheaply deployed, will not drift, and will not malfunction or fail, the model has significant added value over a physical sensor. We find that the accuracy of the model is comparable to the accuracy of the measurement and is thus suitable for a full replacement.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115247526","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}
Z. Alali, Abdullah Musharraf, M. A. El-Fattah, V. Mathiesen
The main objective of this paper to present a pragmatic approach of managing excessive surface gas production in a heterogeneous reservoir setting through implementation of autonomous inflow control valves (AICV) technology. The gas production from the field is influenced by the presence of gas cap adding extra level of reservoir heterogeneity, which need to be properly characterized and managed. The field can be characterized through integration of multiple static and dynamic data including; fluid data, dynamic pressure profile and pressure transient analysis. The area of interest with high gas production was further investigated for viable options to manage gas production and improve oil sweep conformance. AICV technology was successfully introduced in one of the horizontal wells with high GOR to shut-off unwanted gas production zones across the lateral. Results have shown that the autonomous inflow control valve (AICV) was capable of sealing off sections with high gas production at completion joint while the oil production will continue producing from other zone along the lateral ensuring optimum oil production and recovery by being oil viscosity dependent. High GOR was ultimately controlled by yielding a significant reduction in surface gas production. Additionally, this reduction was accompanied by improved oil sweep efficiency. This paper represents a viable solution to manage gas production and improve oil sweep efficiency in a heterogeneous reservoir setting associated with a free gas production. The AICV combines the best from passive inflow control device (ICD), Autonomous ICD and smart wells (ICV). This fit for purpose technology allows for autonomous oil re-production after gas breakthrough with minimal surface intervention. The AICV design is adapted to the reservoir conditions and requirements in the relevant field.
{"title":"Gas Production Optimization Using AICV Technology","authors":"Z. Alali, Abdullah Musharraf, M. A. El-Fattah, V. Mathiesen","doi":"10.2523/iptc-20195-ms","DOIUrl":"https://doi.org/10.2523/iptc-20195-ms","url":null,"abstract":"\u0000 The main objective of this paper to present a pragmatic approach of managing excessive surface gas production in a heterogeneous reservoir setting through implementation of autonomous inflow control valves (AICV) technology. The gas production from the field is influenced by the presence of gas cap adding extra level of reservoir heterogeneity, which need to be properly characterized and managed.\u0000 The field can be characterized through integration of multiple static and dynamic data including; fluid data, dynamic pressure profile and pressure transient analysis. The area of interest with high gas production was further investigated for viable options to manage gas production and improve oil sweep conformance. AICV technology was successfully introduced in one of the horizontal wells with high GOR to shut-off unwanted gas production zones across the lateral.\u0000 Results have shown that the autonomous inflow control valve (AICV) was capable of sealing off sections with high gas production at completion joint while the oil production will continue producing from other zone along the lateral ensuring optimum oil production and recovery by being oil viscosity dependent. High GOR was ultimately controlled by yielding a significant reduction in surface gas production. Additionally, this reduction was accompanied by improved oil sweep efficiency.\u0000 This paper represents a viable solution to manage gas production and improve oil sweep efficiency in a heterogeneous reservoir setting associated with a free gas production. The AICV combines the best from passive inflow control device (ICD), Autonomous ICD and smart wells (ICV). This fit for purpose technology allows for autonomous oil re-production after gas breakthrough with minimal surface intervention. The AICV design is adapted to the reservoir conditions and requirements in the relevant field.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125943865","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The lack of high-resolution subsurface images from poor seismic imaging quality leads to inaccurate AVO/AVAz analysis and fault interpretation, which are critical for reserves estimation and de-risking any imminent drilling decisions. In a developing filed, acquiring and processing a new seismic data often falls outside the time frame of ongoing field development, as it will require great efforts in overcoming logistics challenges along with additional costs. In this case study, in offshore Abu Dhabi, revisiting the vintage data with careful and detailed reprocessing whilst utilizing the latest technologies has proven to be an effective, practical and cost-efficient method in improving the fault resolution and reservoir characterization. In this case study, it is observed that the deeper events in the vintage data were masked by the strong surface wave energy. The irregular acquisition geometry of the seismic data caused the aliasing of the surface wave. The application of harsh de-noising techniques in the vintage processing further deteriorated the fault definition. Thus, to tackle the aliasing problem, 5D trace densification and regularization was applied to increase the input data and create a de-aliased surface wave model. This allowed for subsequent subtraction of the strong surface wave, without damaging the body wave. Further cascaded surface wave attenuation algorithm improved the image quality. Modern fault preserving residual noise attenuation was applied along with 5D Fourier reconstruction mitigated the residual noise content. It has been proven in the case study that multi-dimensional data densification and 5D reconstruction of the signal enhanced the fault delineation. By leveraging the modern signal-processing innovations, the final results produced a better overall reflection image focused on the angle/azimuth stacks suitable for fault interpretation, AVO and AVAz analysis. In conclusion, poorly vintage seismic data has been shown to possess a high value despite its irregular geometry and low resolution.
{"title":"Wide-azimuth OBC Seismic Data Optimization for AVO and AVAz Analysis, Offshore Abu Dhabi, UAE","authors":"A. Almheiri, H. Miyamoto, M. Mahgoub","doi":"10.2523/iptc-19618-ms","DOIUrl":"https://doi.org/10.2523/iptc-19618-ms","url":null,"abstract":"\u0000 The lack of high-resolution subsurface images from poor seismic imaging quality leads to inaccurate AVO/AVAz analysis and fault interpretation, which are critical for reserves estimation and de-risking any imminent drilling decisions. In a developing filed, acquiring and processing a new seismic data often falls outside the time frame of ongoing field development, as it will require great efforts in overcoming logistics challenges along with additional costs. In this case study, in offshore Abu Dhabi, revisiting the vintage data with careful and detailed reprocessing whilst utilizing the latest technologies has proven to be an effective, practical and cost-efficient method in improving the fault resolution and reservoir characterization.\u0000 In this case study, it is observed that the deeper events in the vintage data were masked by the strong surface wave energy. The irregular acquisition geometry of the seismic data caused the aliasing of the surface wave. The application of harsh de-noising techniques in the vintage processing further deteriorated the fault definition. Thus, to tackle the aliasing problem, 5D trace densification and regularization was applied to increase the input data and create a de-aliased surface wave model. This allowed for subsequent subtraction of the strong surface wave, without damaging the body wave. Further cascaded surface wave attenuation algorithm improved the image quality. Modern fault preserving residual noise attenuation was applied along with 5D Fourier reconstruction mitigated the residual noise content.\u0000 It has been proven in the case study that multi-dimensional data densification and 5D reconstruction of the signal enhanced the fault delineation. By leveraging the modern signal-processing innovations, the final results produced a better overall reflection image focused on the angle/azimuth stacks suitable for fault interpretation, AVO and AVAz analysis. In conclusion, poorly vintage seismic data has been shown to possess a high value despite its irregular geometry and low resolution.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123438967","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}
D. Thomas, Paul Bireta, Kevin McVey, D. Segal, M. Hudson, Bu-Hulaiyem Sami, Sabadell Gabriel
Treatment and management of oil-impacted wastes (e.g. tank bottoms, clarifier or pit sludge, oil-impacted soils) poses significant technical and financial challenges at exploration and production (E&P) facilities. Often these materials are distant from waste disposal or treatment facilities or are inaccessible to the equipment necessary for treatment. Further, the size of treatment facilities and associated costs may make treatment of these wastes unviable. Heated Overland Thermal Treatment Pad (Hottpad), is a novel, cost-effective and easily scaled solution for oil impacted wastes at E&P sites that has been developed and field demonstrated. Hottpad consists of a metal pad with metal or dirt-bermed walls, which is then covered with oily waste material or oil-impacted soil for subsequent treatment via smouldering combustion. Since initial deployment in 2016, the technology has been further improved and refined to target two applications of interest; i) small, portable systems designed for treatment of stranded wastes and ii) centralized, bespoke scale treatment facilities. Both systems are designed for on-site treatment with conversion of wastes to materials suitable for reuse. The current Hottpad configuration is the culmination of more than 8 years of collaborative research, technology development, refinement and improvement. Hottpad has been demonstrated to be highly effective at meeting remediation goals, is cost-effective, and is a more sustainable and lower risk alternative to the traditional means of treatment that rely on off-site transport of impacted materials.
{"title":"A Novel, Cost Effective and Easily Scaled Solution for On-Site Treatment of Oily Wastes","authors":"D. Thomas, Paul Bireta, Kevin McVey, D. Segal, M. Hudson, Bu-Hulaiyem Sami, Sabadell Gabriel","doi":"10.2523/19951-ms","DOIUrl":"https://doi.org/10.2523/19951-ms","url":null,"abstract":"\u0000 Treatment and management of oil-impacted wastes (e.g. tank bottoms, clarifier or pit sludge, oil-impacted soils) poses significant technical and financial challenges at exploration and production (E&P) facilities. Often these materials are distant from waste disposal or treatment facilities or are inaccessible to the equipment necessary for treatment. Further, the size of treatment facilities and associated costs may make treatment of these wastes unviable.\u0000 Heated Overland Thermal Treatment Pad (Hottpad), is a novel, cost-effective and easily scaled solution for oil impacted wastes at E&P sites that has been developed and field demonstrated. Hottpad consists of a metal pad with metal or dirt-bermed walls, which is then covered with oily waste material or oil-impacted soil for subsequent treatment via smouldering combustion. Since initial deployment in 2016, the technology has been further improved and refined to target two applications of interest; i) small, portable systems designed for treatment of stranded wastes and ii) centralized, bespoke scale treatment facilities. Both systems are designed for on-site treatment with conversion of wastes to materials suitable for reuse.\u0000 The current Hottpad configuration is the culmination of more than 8 years of collaborative research, technology development, refinement and improvement. Hottpad has been demonstrated to be highly effective at meeting remediation goals, is cost-effective, and is a more sustainable and lower risk alternative to the traditional means of treatment that rely on off-site transport of impacted materials.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116539975","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Qaidam Basin is located in the northeastern part of the Qinghai-Tibet Plateau (or Tibetan Plateau). It is the world's highest altitude petroliferous basin (the altitude is usually more than 3000m above sea level). But this basin is more famous for its ‘double complex’ in terms of surface and subsurface structures. Our study areas, YingXi and YingZhong are located at the southwest of YingXiongling structural belt within the Qaidam basin. From the , we can see the "double complex" structures very clearly. The surface is full of wind erosion mountains . The serious elevation variation proposes huge challenge for seismic data acquisition, statics correction and near surface modeling. Meanwhile the subsurface is thrusted severely . The shallow part is thrusted with detachment faults and mainly comprised of severely deformed fold and Shizgou fault, which is the main fault of the survey. The horizon offset across it is usually quite large up to 2km. The study zone is more than 4000m deep where it is thrusted into imbricate fans with very strong overlying structural disturbing. The structure is cut by several groups of low angle faults. This kind of geological condition may produce quite good traps for oil and gas. Besides the overlying salt layers of the study zone extend to certain range which can be very good seal to prevent the oil and gas from migrating upward along Shizgou fault. These extremely complex geological situations cause a series of world-class E&P difficulties, such as how to obtain better seismic image, where to drill exploration wells, how to design and drill horizontal development wells with higher success rate, and how to submit OOIP or Reserve to the country for so complex region, etc. But to solve these difficulties, one thing is the key, i.e. the accurate structural delineation. This also the final goal of our work. In this paper we will discuss and show how we reach it by integrated Geophysical & Geological modeling.
{"title":"Integrated Geophysical & Geological Modeling to Conquer World-Class E&P Difficulties on Qinghai-Tibet Plateau","authors":"Yongcang Dong, Chenqing Tan, Haifeng Wang, Yanming Tong, Yongsheng Wang, Chuan Wu, B. Guan","doi":"10.2523/iptc-19650-ms","DOIUrl":"https://doi.org/10.2523/iptc-19650-ms","url":null,"abstract":"\u0000 The Qaidam Basin is located in the northeastern part of the Qinghai-Tibet Plateau (or Tibetan Plateau). It is the world's highest altitude petroliferous basin (the altitude is usually more than 3000m above sea level). But this basin is more famous for its ‘double complex’ in terms of surface and subsurface structures.\u0000 Our study areas, YingXi and YingZhong are located at the southwest of YingXiongling structural belt within the Qaidam basin. From the , we can see the \"double complex\" structures very clearly. The surface is full of wind erosion mountains . The serious elevation variation proposes huge challenge for seismic data acquisition, statics correction and near surface modeling. Meanwhile the subsurface is thrusted severely . The shallow part is thrusted with detachment faults and mainly comprised of severely deformed fold and Shizgou fault, which is the main fault of the survey. The horizon offset across it is usually quite large up to 2km. The study zone is more than 4000m deep where it is thrusted into imbricate fans with very strong overlying structural disturbing. The structure is cut by several groups of low angle faults. This kind of geological condition may produce quite good traps for oil and gas. Besides the overlying salt layers of the study zone extend to certain range which can be very good seal to prevent the oil and gas from migrating upward along Shizgou fault.\u0000 These extremely complex geological situations cause a series of world-class E&P difficulties, such as how to obtain better seismic image, where to drill exploration wells, how to design and drill horizontal development wells with higher success rate, and how to submit OOIP or Reserve to the country for so complex region, etc. But to solve these difficulties, one thing is the key, i.e. the accurate structural delineation. This also the final goal of our work. In this paper we will discuss and show how we reach it by integrated Geophysical & Geological modeling.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130206400","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}
H. Darabi, Xiang Zhai, A. Kianinejad, Zheren Ma, D. Castineira, R. Toronyi
Many important business decisions and planning in unconventional reservoirs rely on a reliable forecast on well performance. Common practices like statistical type curves, analytical methods, and numerical simulation are not well suited to incorporate all the complexities involving rock/fluid properties, geological parameters, artificial lift systems, well and completion designs, etc. In this work, we introduce a novel "Augmented AI" (Artificial Intelligence) workflow for reliable forecasting of unconventional well performance and show its impact on decision making. Augmented AI represents smart integration of artificial intelligence and domain knowledge. In the application of well performance forecast, a smart DCA algorithm automatically estimates the short- and long-term performance of the historical wells; a spectrum of well attributes are aggregated/transformed with the consideration of uncertainty and robustness for training and prediction. Boosting and bootstrap tree-based models are ensembled to maximize the model generalization capability. In contrast to the commonly seen black-box modeling practices, the factor-specific impacts are deconvoluted, allowing for validation of the underlying physics. Furthermore, this gives guidelines for future well planning and completion designs. A case study is presented, where the workflow is implemented. Multi-disciplinary data (logs, completions, maps, fluid properties, etc.) from thousands of wells were integrated. During the feature engineering step, raw data was converted to a set of meaningful parameters leveraging the domain knowledge. As an example, some of the features were combined, some were transformed, and others were normalized. Then a machine learning model was created using an ensemble approach. The models showed a good model accuracy on the training, testing, and validation dataset. Leveraging the predictive model, thousands of field development opportunities including new vertical wells, new horizontal wells, recompletions, and completion optimization were identified that resulted in increased production, increased reserves, and improved capital efficiency. Using the model explanation techniques, the impact of various parameters on the well performance was quantified that resulted in best practices for future drilling and completion design.
{"title":"Augmented AI Framework for Well Performance Prediction and Opportunity Identification in Unconventional Reservoirs","authors":"H. Darabi, Xiang Zhai, A. Kianinejad, Zheren Ma, D. Castineira, R. Toronyi","doi":"10.2523/iptc-20099-ms","DOIUrl":"https://doi.org/10.2523/iptc-20099-ms","url":null,"abstract":"\u0000 Many important business decisions and planning in unconventional reservoirs rely on a reliable forecast on well performance. Common practices like statistical type curves, analytical methods, and numerical simulation are not well suited to incorporate all the complexities involving rock/fluid properties, geological parameters, artificial lift systems, well and completion designs, etc. In this work, we introduce a novel \"Augmented AI\" (Artificial Intelligence) workflow for reliable forecasting of unconventional well performance and show its impact on decision making. Augmented AI represents smart integration of artificial intelligence and domain knowledge. In the application of well performance forecast, a smart DCA algorithm automatically estimates the short- and long-term performance of the historical wells; a spectrum of well attributes are aggregated/transformed with the consideration of uncertainty and robustness for training and prediction. Boosting and bootstrap tree-based models are ensembled to maximize the model generalization capability. In contrast to the commonly seen black-box modeling practices, the factor-specific impacts are deconvoluted, allowing for validation of the underlying physics. Furthermore, this gives guidelines for future well planning and completion designs. A case study is presented, where the workflow is implemented. Multi-disciplinary data (logs, completions, maps, fluid properties, etc.) from thousands of wells were integrated. During the feature engineering step, raw data was converted to a set of meaningful parameters leveraging the domain knowledge. As an example, some of the features were combined, some were transformed, and others were normalized. Then a machine learning model was created using an ensemble approach. The models showed a good model accuracy on the training, testing, and validation dataset. Leveraging the predictive model, thousands of field development opportunities including new vertical wells, new horizontal wells, recompletions, and completion optimization were identified that resulted in increased production, increased reserves, and improved capital efficiency. Using the model explanation techniques, the impact of various parameters on the well performance was quantified that resulted in best practices for future drilling and completion design.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131325375","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}
Aizaz Khalid, N. Molero, Ghassan Hassan, Eric Lovie, Rao Shafin Ali Khan
In southern Pakistan, most wells in mature fields do not flow naturally and require delivery of supplemental energy into the wellbore through an artificial lift system. The existing portfolio of techniques, however, faces technical and economic challenges. Operators have tried numerous methods of deliquification such as soap injection, jet pumps, electrical submersible pumps, and conventional gas lift (GL). Those solutions differ in methodology and efficiency, but they unfortunately have failed either technically or economically in Pakistan. Because reviving dead wells is key to maximizing production with the most efficient and cost-effective method in Pakistan, a detailed screening of candidate wells was carried out to identify innovative artificial lift solutions. The deployment of GL valves using coiled tubing (CT) soon emerged as the best option, because it offered the highest returns in a cost-benefit analysis. Coiled tubing gas lift (CTGL) is a rigless solution that enables setting GL valves at the required depth, during any stage of a well life. It allows gas to be injected through CT with production through the CT-to-tubing annulus. This technology is also retrievable and replaceable when needed. Two pilot wells, that had been shut in since 2015, were selected from four shortlisted candidates through nodal analysis. Each system consisted of one CT string with multiple stations of unloading and orifice valves, spaced out at depths engineered to maximize each well’s productivity. In addition to a GL valve, each station included two CT external connectors and one self-aligning connector, which enabled efficient and safe connection between both CT ends during the deployment of the CTGL station. Additionally, specific CT pressure control equipment and wellhead adapters were used to secure and hang the CT string in the production tree and provide connection with the gas injection facilities at the surface. The first installation was conducted in a vertical well originally completed 4 1/2-in. monobore, deploying 1 1/2-in. CT string with four CTGL stations. The second installation was performed with 1 1/4-in. CT and five CTGL stations in a well originally completed with 7-in. liner and 2 7/8-in. production tubing. The wells were commissioned using existing surface infrastructure and were unloaded smoothly until the production stabilized at optimum rates near 420 B/D and 325 B/D respectively. This innovative artificial lift technique represents an effective and economical solution to restart production in mature fields where conventional artificial lift methods challenge well economics. This approach greatly rests on a thorough candidate selection process. The design and installation of two new CTGL systems was a first in the Middle East region and helped identify numerous best practices and lessons learned, which will speed up implementation of the methodology in other parts of the world.
{"title":"Coiled Tubing Gas Lift: An Innovative Solution for Reviving Dead Wells in Southern Pakistan","authors":"Aizaz Khalid, N. Molero, Ghassan Hassan, Eric Lovie, Rao Shafin Ali Khan","doi":"10.2523/19930-abstract","DOIUrl":"https://doi.org/10.2523/19930-abstract","url":null,"abstract":"\u0000 In southern Pakistan, most wells in mature fields do not flow naturally and require delivery of supplemental energy into the wellbore through an artificial lift system. The existing portfolio of techniques, however, faces technical and economic challenges. Operators have tried numerous methods of deliquification such as soap injection, jet pumps, electrical submersible pumps, and conventional gas lift (GL). Those solutions differ in methodology and efficiency, but they unfortunately have failed either technically or economically in Pakistan.\u0000 Because reviving dead wells is key to maximizing production with the most efficient and cost-effective method in Pakistan, a detailed screening of candidate wells was carried out to identify innovative artificial lift solutions. The deployment of GL valves using coiled tubing (CT) soon emerged as the best option, because it offered the highest returns in a cost-benefit analysis. Coiled tubing gas lift (CTGL) is a rigless solution that enables setting GL valves at the required depth, during any stage of a well life. It allows gas to be injected through CT with production through the CT-to-tubing annulus. This technology is also retrievable and replaceable when needed.\u0000 Two pilot wells, that had been shut in since 2015, were selected from four shortlisted candidates through nodal analysis. Each system consisted of one CT string with multiple stations of unloading and orifice valves, spaced out at depths engineered to maximize each well’s productivity. In addition to a GL valve, each station included two CT external connectors and one self-aligning connector, which enabled efficient and safe connection between both CT ends during the deployment of the CTGL station.\u0000 Additionally, specific CT pressure control equipment and wellhead adapters were used to secure and hang the CT string in the production tree and provide connection with the gas injection facilities at the surface. The first installation was conducted in a vertical well originally completed 4 1/2-in. monobore, deploying 1 1/2-in. CT string with four CTGL stations. The second installation was performed with 1 1/4-in. CT and five CTGL stations in a well originally completed with 7-in. liner and 2 7/8-in. production tubing. The wells were commissioned using existing surface infrastructure and were unloaded smoothly until the production stabilized at optimum rates near 420 B/D and 325 B/D respectively.\u0000 This innovative artificial lift technique represents an effective and economical solution to restart production in mature fields where conventional artificial lift methods challenge well economics. This approach greatly rests on a thorough candidate selection process. The design and installation of two new CTGL systems was a first in the Middle East region and helped identify numerous best practices and lessons learned, which will speed up implementation of the methodology in other parts of the world.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116026602","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}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19928-abstract
M. Cárdenas, Amir Galaby, O. Cengiz, Mustafa Al-Rubaye, Melvin John, D. Ponomareva, M. Antonov
Obtaining a good cement bond is a continuous challenge, especially if the well being cemented is a high-pressure exploration gas well, and it is one of the very few gas wells drilled in the country. Poor adherence to the casing and the formation, channeling due to gas migration and microannulus are some of the main risks that could result in a poor cement job. Achieving zonal isolation and a good cement sheath protecting the 7-inch liner turned out to be an objective missed for the first two wells of the campaign, compromising the long-term supply of gas to the South region of Iraq. To solve the situation, it was necessary to implement something more than a mere cementing additive; it required a multifactor analysis with an experienced multidisciplinary team. A set of good drilling practices, proper drilling fluids, proven cementing techniques and new technology slurries were combined to improve the precious results. To obtain a sound cement quality log, the well engineering department teamed up with cementing experts, drilling fluids specialists, liner hanger company representatives and operations personnel. With effective meetings, proper risk assessment and visible leadership, the team generated a series of initiatives that included: drilling hydraulics optimization, mud weight selection, drilling practices re-definition, liner hanger procedure adjustments and cementing slurry design. As a result, the borehole caliper was significantly improved, the liner hanger allowed full rotation while cementing, cement returns were observed above the liner top after the job, no evidence of gas migration was observed and the CBL-VDL-USIT log showed a remarkable improvement in the two jobs where the engineering initiatives were applied. Being able to achieve a positive proof on cementing integrity, one of the most important acceptance criteria for the National Oil Company (NOC) regulation entity, enhanced the trust on the technical experts of the engineering team to deliver solutions of complex problems.
{"title":"A Holistic Approach to Achieve a Successful Liner Cement in Gas Bearing Early Cretaceous Formations in South Iraq","authors":"M. Cárdenas, Amir Galaby, O. Cengiz, Mustafa Al-Rubaye, Melvin John, D. Ponomareva, M. Antonov","doi":"10.2523/iptc-19928-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19928-abstract","url":null,"abstract":"\u0000 Obtaining a good cement bond is a continuous challenge, especially if the well being cemented is a high-pressure exploration gas well, and it is one of the very few gas wells drilled in the country. Poor adherence to the casing and the formation, channeling due to gas migration and microannulus are some of the main risks that could result in a poor cement job. Achieving zonal isolation and a good cement sheath protecting the 7-inch liner turned out to be an objective missed for the first two wells of the campaign, compromising the long-term supply of gas to the South region of Iraq. To solve the situation, it was necessary to implement something more than a mere cementing additive; it required a multifactor analysis with an experienced multidisciplinary team. A set of good drilling practices, proper drilling fluids, proven cementing techniques and new technology slurries were combined to improve the precious results.\u0000 To obtain a sound cement quality log, the well engineering department teamed up with cementing experts, drilling fluids specialists, liner hanger company representatives and operations personnel. With effective meetings, proper risk assessment and visible leadership, the team generated a series of initiatives that included: drilling hydraulics optimization, mud weight selection, drilling practices re-definition, liner hanger procedure adjustments and cementing slurry design.\u0000 As a result, the borehole caliper was significantly improved, the liner hanger allowed full rotation while cementing, cement returns were observed above the liner top after the job, no evidence of gas migration was observed and the CBL-VDL-USIT log showed a remarkable improvement in the two jobs where the engineering initiatives were applied.\u0000 Being able to achieve a positive proof on cementing integrity, one of the most important acceptance criteria for the National Oil Company (NOC) regulation entity, enhanced the trust on the technical experts of the engineering team to deliver solutions of complex problems.","PeriodicalId":393755,"journal":{"name":"Day 1 Mon, January 13, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124030718","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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