Phase change, a major factor that restricts the development of gas hydrate, is likely to cause blockage in well completion section (sieve section – wellbore lifting section), thus resulting in the engineering losses. In view of the defects in the previous studies on the confluence mechanism of completion section of gas hydrate pressure drop method mining under openhole completion technology, the flow of gas hydrate in the well completion section was simplified as the Main-Branch pipe confluence model in this paper. Firstly, a physical model was established. On the basis of the energy conservation law and the Peng-Robinson equation, the temperature and pressure coupling model was also derived. Then, the Fluent software was used to simulate the temperature gradient and pressure gradient changes in the Main-Branch model. The gas hydrate phase diagram and P-T environment under different velocity were obtained. Finally, the contrast analysis between theoretical model and numerical simulation was carried out and the established model was verified. Through the study of this paper, it is possible to prevent blockage of the well completion section by means of depressurization, which can provide theoretical guidance for the control of pressure drop when gas hydrate is extracted by depressurization. It is important for the exploitation and continuous production of gas hydrate in the later stage.
{"title":"Study on the Phase Equilibrium of Gas Hydrate Based on Main-Branch Pipe Confluence Model","authors":"S. Deng, Yali Liu, Xia Wei, L. Tao, Yanfeng He","doi":"10.2523/IPTC-19167-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19167-MS","url":null,"abstract":"\u0000 Phase change, a major factor that restricts the development of gas hydrate, is likely to cause blockage in well completion section (sieve section – wellbore lifting section), thus resulting in the engineering losses. In view of the defects in the previous studies on the confluence mechanism of completion section of gas hydrate pressure drop method mining under openhole completion technology, the flow of gas hydrate in the well completion section was simplified as the Main-Branch pipe confluence model in this paper. Firstly, a physical model was established. On the basis of the energy conservation law and the Peng-Robinson equation, the temperature and pressure coupling model was also derived. Then, the Fluent software was used to simulate the temperature gradient and pressure gradient changes in the Main-Branch model. The gas hydrate phase diagram and P-T environment under different velocity were obtained. Finally, the contrast analysis between theoretical model and numerical simulation was carried out and the established model was verified. Through the study of this paper, it is possible to prevent blockage of the well completion section by means of depressurization, which can provide theoretical guidance for the control of pressure drop when gas hydrate is extracted by depressurization. It is important for the exploitation and continuous production of gas hydrate in the later stage.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89664185","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}
Changzhao Chen, Xingchun Li, Baichun Wu, Zhang Kunfeng, Quanwei Song
The world has seen a peak in unconventional gas development in recent years. Based on the practice of unconventional gas field development domestic in China and abroad, it is risky that the reinjection water may contaminate groundwater in local or adjacent areas during reinjected fluid migration. Ensuring environmental safety of the reinjection is a multi-disciplinary system project. This paper carries out the analysis and shares the experience of China's practice based on the actual cases from the following aspects. 1) The screening of the well location and the formation of the reinjection. 2) The drilling and cementing construction of the reinjection well, which considers the factors such as cementing quality and cement height and casing material. 3) The estimation of the total reinjection capacity, and the factors such as porosity and permeability of the geologic trap and reservoir fracture pressure is considered. 4) The monitoring of well and migration of reinjection fluids. Further environmental risk study of produced water reinjection is presented in this paper, on both sandstone formation of tight sand gas field and carbonate karst formation of shale gas field in China's typical unconventional gas development areas, using laboratory geochemistry experiments and large area geophysical test to obtain seismic data.
{"title":"Environmental Impact Study and Experience Sharing of Produced Water Reinjection from Unconventional Gas Development","authors":"Changzhao Chen, Xingchun Li, Baichun Wu, Zhang Kunfeng, Quanwei Song","doi":"10.2523/IPTC-19119-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19119-MS","url":null,"abstract":"\u0000 The world has seen a peak in unconventional gas development in recent years. Based on the practice of unconventional gas field development domestic in China and abroad, it is risky that the reinjection water may contaminate groundwater in local or adjacent areas during reinjected fluid migration. Ensuring environmental safety of the reinjection is a multi-disciplinary system project. This paper carries out the analysis and shares the experience of China's practice based on the actual cases from the following aspects. 1) The screening of the well location and the formation of the reinjection. 2) The drilling and cementing construction of the reinjection well, which considers the factors such as cementing quality and cement height and casing material. 3) The estimation of the total reinjection capacity, and the factors such as porosity and permeability of the geologic trap and reservoir fracture pressure is considered. 4) The monitoring of well and migration of reinjection fluids. Further environmental risk study of produced water reinjection is presented in this paper, on both sandstone formation of tight sand gas field and carbonate karst formation of shale gas field in China's typical unconventional gas development areas, using laboratory geochemistry experiments and large area geophysical test to obtain seismic data.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86123159","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}
Plugging natural fractures with lost control materials (LCMs) is the common method to prevent foramtion damage and control fluids loss in In naturally fractured reservoir. The plugging zone strenfth stability is critically important for maintaining long-term plugging quality. Surface friction coefficient (SFC) is proposed as an important parameter for the selection of LCMs based on based on granular matter mechanics and the instability of plugging zone. The force chain network with specific geometry is the basis of the plugging zone strength and supporting external load. The likelihood of shear failure can be increased by decline of SFC. And high strength of force chain can not be formed and it can relatively easy to be broken even if a small shear is applied. Effects of LCMs particle size distribution, circulation abrasion, LCMs combination, working fluids infiltration, and high temperature aging on friction behaviors are analyzed for LCMs with high SFC selection. Results show that the average SFC shows a decreasing trend with the particle size reduction and the difficulty of particle dislocation decreases with the particle size reduction. For deep naturally fractured reservoirs, particle size will degradate due to long-term drilling fluid circulation in the wellbore, thus affecting the plugging effect of drill-in fluid. The mixture of elastic material and fiber into rigid material increases the SFC and elastic material contributes most to the increasing the SFC. The SFC decreases under the condition of fluids infiltration, and the SFC show a higher decline in oil-based condition. The high-temperature aging makes the edge of the organic rigid material more smooth, which reduces its SFC.
{"title":"Experimental Study on Surface Frictional Behavior of Materials for Lost Circulation Control in Deep Naturally Fractured Reservoir","authors":"Chengyuan Xu, Xiaopeng Yan, Yili Kang, Lijun You, Zhang Jingyi, Chong Lin, Haoran Jing","doi":"10.2523/IPTC-19486-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19486-MS","url":null,"abstract":"\u0000 Plugging natural fractures with lost control materials (LCMs) is the common method to prevent foramtion damage and control fluids loss in In naturally fractured reservoir. The plugging zone strenfth stability is critically important for maintaining long-term plugging quality. Surface friction coefficient (SFC) is proposed as an important parameter for the selection of LCMs based on based on granular matter mechanics and the instability of plugging zone. The force chain network with specific geometry is the basis of the plugging zone strength and supporting external load. The likelihood of shear failure can be increased by decline of SFC. And high strength of force chain can not be formed and it can relatively easy to be broken even if a small shear is applied. Effects of LCMs particle size distribution, circulation abrasion, LCMs combination, working fluids infiltration, and high temperature aging on friction behaviors are analyzed for LCMs with high SFC selection. Results show that the average SFC shows a decreasing trend with the particle size reduction and the difficulty of particle dislocation decreases with the particle size reduction. For deep naturally fractured reservoirs, particle size will degradate due to long-term drilling fluid circulation in the wellbore, thus affecting the plugging effect of drill-in fluid. The mixture of elastic material and fiber into rigid material increases the SFC and elastic material contributes most to the increasing the SFC. The SFC decreases under the condition of fluids infiltration, and the SFC show a higher decline in oil-based condition. The high-temperature aging makes the edge of the organic rigid material more smooth, which reduces its SFC.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78531194","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}
Tight carbonate formations with extremely low porosity and permeability depend on well-designed completion and stimulation treatments to achieve economic production. Acid fracturing, a relative cost-effective choice compared with propped fracturing, is widely used for carbonate stimulation. However, many factors contribute to the acid etching created conductivity, which is a key parameter for the success of acid fracturing. From a petrophysical perspective, depth-by-depth rock mechanical properties, stress distribution as well as the heterogeneous petrophysical properties (e.g. porosity and permeability) are important local information affecting final fracture conductivity. In this paper, we conduct an integrated evaluation for multi-stage acid fracturing in a horizontal well in a deep, tight carbonate reservoir in Tarim field, China. We perform multi-mineral analysis and estimate volumetric concentrations of minerals, porosity, and fluid saturations with conventional well logs. Since shear wave sonic logs are not available for most of the wells, we estimate rock mechanical properties (Young's modulus and Poisson's ratio) using effective medium models including self-consistent approximation and differential effective medium theory. Corrections including the impact of fluids are developed using Gassmann's fluid substitution. Besides, we estimate depth by depth permeability with empirical correlations. Core measurements are used for cross-validating the well-log-based estimates of rock mechanical properties, porosity and permeability. Horizontal stress distribution and closure stress field are generated using poroelasticity stress model with estimated Young's modulus and Poisson's ratio as inputs. We also perform variogram analysis on well-log-based estimates of permeability and obtain its correlation length in both vertical and horizontal direction to quantify formation heterogeneity. The estimated rock mechanical properties, stress distribution, and petrophysical properties are used as inputs to 3D acid fracturing treatment modeling. The simulated fracture geometry, especially fracture height, is highly dependent on stress variation. The modeled acid transportation in fracture is strongly affected by permeability correlation lengths. The study result shows that the conductivity created by acid fracturing under local high closure stress is insufficient for successful acid stimulation treatments.
{"title":"Well Stimulation Evaluation in Horizontal Wells with Emphasis on Petrophysics and Rock Mechanics: A Case Study in Deep, Tight Carbonate Formation","authors":"Yuhai Zhou, Wenyu Zhang, D. Zhu","doi":"10.2523/IPTC-19118-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19118-MS","url":null,"abstract":"\u0000 Tight carbonate formations with extremely low porosity and permeability depend on well-designed completion and stimulation treatments to achieve economic production. Acid fracturing, a relative cost-effective choice compared with propped fracturing, is widely used for carbonate stimulation. However, many factors contribute to the acid etching created conductivity, which is a key parameter for the success of acid fracturing. From a petrophysical perspective, depth-by-depth rock mechanical properties, stress distribution as well as the heterogeneous petrophysical properties (e.g. porosity and permeability) are important local information affecting final fracture conductivity. In this paper, we conduct an integrated evaluation for multi-stage acid fracturing in a horizontal well in a deep, tight carbonate reservoir in Tarim field, China.\u0000 We perform multi-mineral analysis and estimate volumetric concentrations of minerals, porosity, and fluid saturations with conventional well logs. Since shear wave sonic logs are not available for most of the wells, we estimate rock mechanical properties (Young's modulus and Poisson's ratio) using effective medium models including self-consistent approximation and differential effective medium theory. Corrections including the impact of fluids are developed using Gassmann's fluid substitution. Besides, we estimate depth by depth permeability with empirical correlations. Core measurements are used for cross-validating the well-log-based estimates of rock mechanical properties, porosity and permeability. Horizontal stress distribution and closure stress field are generated using poroelasticity stress model with estimated Young's modulus and Poisson's ratio as inputs. We also perform variogram analysis on well-log-based estimates of permeability and obtain its correlation length in both vertical and horizontal direction to quantify formation heterogeneity.\u0000 The estimated rock mechanical properties, stress distribution, and petrophysical properties are used as inputs to 3D acid fracturing treatment modeling. The simulated fracture geometry, especially fracture height, is highly dependent on stress variation. The modeled acid transportation in fracture is strongly affected by permeability correlation lengths. The study result shows that the conductivity created by acid fracturing under local high closure stress is insufficient for successful acid stimulation treatments.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74634948","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}
Xin Chen, Suhong Zhang, J. Ou, Yufeng Ye, Lei Xu, Yingze Ma, Xiaodong Wei, Ke Yang, Gang Chen, Guofeng Zhou, Yaliang Xia, Xiao Yan, Zeren Zhang, Jingluan Liu, Xiao-ming Zhou
In order to improve the accuracy of reservoir prediction results, the conventional method usually include seismic inversion, and seismic attribute analysis. Due to the limitation of the vertical resolution of seismic data, it is hard to identify the thin reservoir by seismic attributes directly. In order to improve the prediction accuracy of reservoir, this paper show a new reservoir characterization technique based on geological seismic conditioning. The new method mainly includes five steps. The first step is sedimentary facies classification based on the geological seismic analysis, such as core data, thin section analysis, FMI logging, NMR logging and conventional logging. The second step is modern sedimentary model optimization and forward modelling. In order to establish a reasonable sedimentary facies model, a similar barrier island modern sedimentary model was chosen. To understand the geological significance of seismic data, two different dominant frequency were designed for forward modelling based on the sedimentary facies model and petrophysical analysis. The third step is seismic conditioning under the guide of sedimentary facies model forward modelling. The next step is seismic constraint stochastic inversion, and the last step is reservoir characterization and new well confirm. The application of this method in A oilfield shows that the techniques not only improved the identification ability of the reprocessing seismic data, but also improved the prediction accuracy of the reservoir characterization results. This new reservoir characterization technique can integrated multidisplinary information, such as modern sedimentary model, well data and seismic data, to establish a reasonable sedimentary model, to enhance the resolution of seismic data by conditioning, and get an reasonable reservoir characterization results based on the seismic inversion.
{"title":"A New Reservoir Prediction Method Based on Geological Seismic Conditioning for Complex Barrier Island and Its Application at H Oil Field","authors":"Xin Chen, Suhong Zhang, J. Ou, Yufeng Ye, Lei Xu, Yingze Ma, Xiaodong Wei, Ke Yang, Gang Chen, Guofeng Zhou, Yaliang Xia, Xiao Yan, Zeren Zhang, Jingluan Liu, Xiao-ming Zhou","doi":"10.2523/IPTC-19145-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19145-MS","url":null,"abstract":"\u0000 In order to improve the accuracy of reservoir prediction results, the conventional method usually include seismic inversion, and seismic attribute analysis. Due to the limitation of the vertical resolution of seismic data, it is hard to identify the thin reservoir by seismic attributes directly. In order to improve the prediction accuracy of reservoir, this paper show a new reservoir characterization technique based on geological seismic conditioning. The new method mainly includes five steps. The first step is sedimentary facies classification based on the geological seismic analysis, such as core data, thin section analysis, FMI logging, NMR logging and conventional logging. The second step is modern sedimentary model optimization and forward modelling. In order to establish a reasonable sedimentary facies model, a similar barrier island modern sedimentary model was chosen. To understand the geological significance of seismic data, two different dominant frequency were designed for forward modelling based on the sedimentary facies model and petrophysical analysis. The third step is seismic conditioning under the guide of sedimentary facies model forward modelling. The next step is seismic constraint stochastic inversion, and the last step is reservoir characterization and new well confirm. The application of this method in A oilfield shows that the techniques not only improved the identification ability of the reprocessing seismic data, but also improved the prediction accuracy of the reservoir characterization results. This new reservoir characterization technique can integrated multidisplinary information, such as modern sedimentary model, well data and seismic data, to establish a reasonable sedimentary model, to enhance the resolution of seismic data by conditioning, and get an reasonable reservoir characterization results based on the seismic inversion.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75354630","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}
S. Mulyani, Zammy Sarmiento, V. Chandra, R. Hendry, S. Nasution, R. Hidayat, Jhonny Jhonny, P. Sari, Dedi Juandi
Understanding the reservoir conditions through 3D subsurface modeling is the key to optimize the exploration stage in geothermal field. A calibrated reservoir model based on updated data can be very important for this process. The main challenge of reservoir characterization in a geothermal field is the lack of subsurface data, therefore surface data are useful for reservoir modeling. This study utilized Sorik Marapi geothermal field data as a reference for reservoir modeling. This field is one of the geothermal fields in Indonesia that has been recently drilled, with results indicating the existence of a high temperature-neutral acidity resource. Initial reservoir model has been built from the previous study to create conceptual 3D subsurface model which includes structural, lithology, resistivity, and temperature distribution from surface exploration data, including surface mapping, remote sensing image interpretation, the magnetotelluric method, and subsurface data from six wells data. The objective of this paper is to calibrate the initial reservoir model with information from an additional ten new wells data to improve delineation for updated reservoir area in the field. Software that allowed multidisciplinary data integration from surface to subsurface information was used for the calibration of the initial 3D model. The workflow to calibrate the model started with data loading and quality control, preparing the old 3D model and comparing it to new well data, analyzing the comparison, and updating the 3D model. Finally, the new delineation of reservoir zone can be determined. The result of this study is an updated 3D subsurface static model defining the vertical and lateral reservoir boundaries, as well as the prime resource areas, which would be the basis for designing future well targets, and parameters for a dynamic reservoir model. The same model can be expanded to construct the numerical model to match the natural state condition of the field and make forecasts of the future reservoir behavior at different operating conditions. The main properties of the updated 3D model are lithology and temperature, which are important in geothermal reservoir delineation.
{"title":"Calibrated Natural State Model in Sorik Marapi Geothermal Field, Indonesia","authors":"S. Mulyani, Zammy Sarmiento, V. Chandra, R. Hendry, S. Nasution, R. Hidayat, Jhonny Jhonny, P. Sari, Dedi Juandi","doi":"10.2523/IPTC-19221-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19221-MS","url":null,"abstract":"\u0000 Understanding the reservoir conditions through 3D subsurface modeling is the key to optimize the exploration stage in geothermal field. A calibrated reservoir model based on updated data can be very important for this process. The main challenge of reservoir characterization in a geothermal field is the lack of subsurface data, therefore surface data are useful for reservoir modeling. This study utilized Sorik Marapi geothermal field data as a reference for reservoir modeling. This field is one of the geothermal fields in Indonesia that has been recently drilled, with results indicating the existence of a high temperature-neutral acidity resource. Initial reservoir model has been built from the previous study to create conceptual 3D subsurface model which includes structural, lithology, resistivity, and temperature distribution from surface exploration data, including surface mapping, remote sensing image interpretation, the magnetotelluric method, and subsurface data from six wells data.\u0000 The objective of this paper is to calibrate the initial reservoir model with information from an additional ten new wells data to improve delineation for updated reservoir area in the field. Software that allowed multidisciplinary data integration from surface to subsurface information was used for the calibration of the initial 3D model. The workflow to calibrate the model started with data loading and quality control, preparing the old 3D model and comparing it to new well data, analyzing the comparison, and updating the 3D model. Finally, the new delineation of reservoir zone can be determined.\u0000 The result of this study is an updated 3D subsurface static model defining the vertical and lateral reservoir boundaries, as well as the prime resource areas, which would be the basis for designing future well targets, and parameters for a dynamic reservoir model. The same model can be expanded to construct the numerical model to match the natural state condition of the field and make forecasts of the future reservoir behavior at different operating conditions. The main properties of the updated 3D model are lithology and temperature, which are important in geothermal reservoir delineation.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81262249","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}
Mohamed Abd-El Mageed, M. Awad, A. Hussein, A. Osman, M. Siam, M. Al-Kaabi, A. Rafik
Egypt's Western Desert is known to be a highly complex and difficult drilling environment. Drilling in this area suffers from multiple geological risks related to formation dip and hardness, faulting, interbedding, and abrasive lithology. These conditions have typically caused drilling problems and costly delays in wells delivery. Combined with the geological difficulties, differences in the implemented drilling practices and operational procedures have led to inefficiencies and the loss of some knowledge transfer among different drilling activities and field operations. For a proof of concept in one of its fields, Khalda endorsed a drilling automation and operations benchmarking strategy to improve the well delivery time in one of its Western Desert fields. The strategy focused on on-bottom drilling activity as well as off-bottom practices and flat-time activities. One part of this strategy endorsed a real-time automated drilling optimization workflow for the on-bottom drilling activities whereby the implementation of a change-point algorithm dictates the optimum drilling parameters to obtain the best possible rate of penetration (ROP) within the rig and drilling assembly constraints and while operating within the safe drilling dynamics window for the assembly. This approach yields the optimum ROP and prevents any possible downhole equipment failure or premature bit damage. The other part of the strategy involved benchmarking the different rig activities while drilling or doing other mechanical operations to gauge the activity of the current well compared to the offset well. This highlights any inefficiencies that can be immediately overcome, areas of improvement, and key learnings for future optimization or implementation. This strategy was implemented in a deep gas development well in a challenging Western Desert field with known problematic offsets. The results showed a step change in well delivery whereby the well finished 3 days ahead of plan and 7 days ahead of the offset well. The real-time automation technique for drilling optimization managed to show 24% on-bottom ROP improvement in one section, enabled completing another section with a one run less than offset, and managed to mitigate the harsh drilling dynamics to prevent downhole equipment incidents. Also, the activities benchmarking helped to develop standard drilling practices that reduced inefficiencies in off-bottom drilling activities by 50% and managed to highlight key learnings and areas of development for future wells. These results helped in validating the proof of concept set at the beginning of this pilot.
{"title":"Real-Time Automated Drilling Optimization and Operations Benchmarking Services Deliver a Step Change in Khalda Western Desert Operations","authors":"Mohamed Abd-El Mageed, M. Awad, A. Hussein, A. Osman, M. Siam, M. Al-Kaabi, A. Rafik","doi":"10.2523/IPTC-19204-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19204-MS","url":null,"abstract":"\u0000 Egypt's Western Desert is known to be a highly complex and difficult drilling environment. Drilling in this area suffers from multiple geological risks related to formation dip and hardness, faulting, interbedding, and abrasive lithology. These conditions have typically caused drilling problems and costly delays in wells delivery. Combined with the geological difficulties, differences in the implemented drilling practices and operational procedures have led to inefficiencies and the loss of some knowledge transfer among different drilling activities and field operations.\u0000 For a proof of concept in one of its fields, Khalda endorsed a drilling automation and operations benchmarking strategy to improve the well delivery time in one of its Western Desert fields. The strategy focused on on-bottom drilling activity as well as off-bottom practices and flat-time activities. One part of this strategy endorsed a real-time automated drilling optimization workflow for the on-bottom drilling activities whereby the implementation of a change-point algorithm dictates the optimum drilling parameters to obtain the best possible rate of penetration (ROP) within the rig and drilling assembly constraints and while operating within the safe drilling dynamics window for the assembly. This approach yields the optimum ROP and prevents any possible downhole equipment failure or premature bit damage. The other part of the strategy involved benchmarking the different rig activities while drilling or doing other mechanical operations to gauge the activity of the current well compared to the offset well. This highlights any inefficiencies that can be immediately overcome, areas of improvement, and key learnings for future optimization or implementation.\u0000 This strategy was implemented in a deep gas development well in a challenging Western Desert field with known problematic offsets. The results showed a step change in well delivery whereby the well finished 3 days ahead of plan and 7 days ahead of the offset well. The real-time automation technique for drilling optimization managed to show 24% on-bottom ROP improvement in one section, enabled completing another section with a one run less than offset, and managed to mitigate the harsh drilling dynamics to prevent downhole equipment incidents. Also, the activities benchmarking helped to develop standard drilling practices that reduced inefficiencies in off-bottom drilling activities by 50% and managed to highlight key learnings and areas of development for future wells. These results helped in validating the proof of concept set at the beginning of this pilot.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81493890","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 drilling of shale gas development wells in the Sichuan Basin has been problematic, with stuck pipe and fluid loss events reported in many wells. These events hindered the development efforts as operators whose aim is to reduce drilling costs and increase drilling speed are faced with developing drilling strategies for more cost effective well delivery. As such, it becomes critical to understand the key mechanisms of borehole failures and fluid losses during drilling of the laterals so that proper mud weights and mud designs can be formulated to overcome the drilling challenges. To optimize the entire drilling process from different angles, an integrated approach is required to combine the knowledge and expertise from different disciplines. A robust geomechanical model and detailed diagnostics of the borehole instability related problems are key and form the basis for the drilling risk management. To build a robust geomechanical model, several representative areas in the Sichuan Shale Gas play were reviewed using a consistent approach. A general understanding of the in-situ stress conditions and rock mechanical properties of the Longmaxi Shale Gas reservoir was developed by combing data and knowledge in the different areas. Using the geomechanical model, a series of newly drilled horizontal wells was also reviewed so that the main causes of stuck pipes and fluid losses can be determined. Based on the geomechanical model and drilling experiences review, risks that could potentially cause non-productive time (NPT) during drilling of the planned wells were postulated and listed, and each risk was then assessed in detail so that a thorough understanding of the risk factors can be achieved from different drilling perspectives. Consequently, a multi-disciplinary mitigating solution was proposed in order to help with reducing the occurrence of any borehole instability-related problems. The integrated drilling optimization plan was executed successfully during the drilling of the horizontal wells in the Sichuan Basin. The increase in understanding of the geomechanical issues in the Sichuan Shale Gas drilling indicated that common trends in shale characteristics are present although it is widely accepted that shale types and stress conditions are different in each field. With the geomechanical models being calibrated from information in different areas, uncertainties are reduced and the robust models in turn provide solid foundations for risk identification and mitigation, leading to successful and economical drilling of the long laterals. However, it is a long and continuous learning process in order to apply this integrated approach effectively. To achieve continuous improvement, the geomechanical model and mitigating solutions need to be refined regularly following the drilling process while further information and knowledge are being acquired in the Sichuan Shale Gas area.
{"title":"Understanding the Geomechanical Challenges and Risk Mitigation in Sichuan Shale Gas Drilling, China","authors":"F. Gui, Shanshan Wang, S. Bordoloi, S. Ong","doi":"10.2523/IPTC-19387-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19387-MS","url":null,"abstract":"\u0000 The drilling of shale gas development wells in the Sichuan Basin has been problematic, with stuck pipe and fluid loss events reported in many wells. These events hindered the development efforts as operators whose aim is to reduce drilling costs and increase drilling speed are faced with developing drilling strategies for more cost effective well delivery. As such, it becomes critical to understand the key mechanisms of borehole failures and fluid losses during drilling of the laterals so that proper mud weights and mud designs can be formulated to overcome the drilling challenges.\u0000 To optimize the entire drilling process from different angles, an integrated approach is required to combine the knowledge and expertise from different disciplines. A robust geomechanical model and detailed diagnostics of the borehole instability related problems are key and form the basis for the drilling risk management. To build a robust geomechanical model, several representative areas in the Sichuan Shale Gas play were reviewed using a consistent approach. A general understanding of the in-situ stress conditions and rock mechanical properties of the Longmaxi Shale Gas reservoir was developed by combing data and knowledge in the different areas. Using the geomechanical model, a series of newly drilled horizontal wells was also reviewed so that the main causes of stuck pipes and fluid losses can be determined.\u0000 Based on the geomechanical model and drilling experiences review, risks that could potentially cause non-productive time (NPT) during drilling of the planned wells were postulated and listed, and each risk was then assessed in detail so that a thorough understanding of the risk factors can be achieved from different drilling perspectives. Consequently, a multi-disciplinary mitigating solution was proposed in order to help with reducing the occurrence of any borehole instability-related problems. The integrated drilling optimization plan was executed successfully during the drilling of the horizontal wells in the Sichuan Basin.\u0000 The increase in understanding of the geomechanical issues in the Sichuan Shale Gas drilling indicated that common trends in shale characteristics are present although it is widely accepted that shale types and stress conditions are different in each field. With the geomechanical models being calibrated from information in different areas, uncertainties are reduced and the robust models in turn provide solid foundations for risk identification and mitigation, leading to successful and economical drilling of the long laterals. However, it is a long and continuous learning process in order to apply this integrated approach effectively. To achieve continuous improvement, the geomechanical model and mitigating solutions need to be refined regularly following the drilling process while further information and knowledge are being acquired in the Sichuan Shale Gas area.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91021873","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 purpose of this paper is to highlight the similarity between Connected Reservoir Regions (CRR)map created using time-lapse pressure groups (Kayode et.al 2018)and other reservoir quality maps like Seismic Acoustic Impedance (SAI) map and petro-physical rock quality map. Time-lapse average reservoir pressure from producers and injectors spanning several years of field production were sorted into groups of similar pressure trends. Wells that show similar pressure trend were classified into same CRR, while wells that show different pressure trends were classified into different CRRs. Only wells operating within the same reservoir zone have been used in the pressure grouping in order to ensure that the observed pressure trend differences are only due to lateral variations of reservoir quality and not due to vertical zonation. A geo-modelling software was used to create connected reservoir regions map in which all wells within the same pressure group are identified with a unique colour code and polygons are drawn to delineate the spatial limits of wells within each pressure group. The CRR map thus obtained, was then compared with SAI map and permeability quality map. Similarity was observed between the CRR map, SAI map and petro-physical rock quality map. Areas indicated as poor quality (high impedance) on the SAI map and indicated as low permeability on petro-physical map were consistent with CRR regions that are characterized by high injection pressure and poor pressure support. Areas indicated as good quality (low impedance) on SAI map and high permeability on petro-physical rock quality map were consistent with CRR regions that are characterized by low injection pressure and excellent producer-injector communication. In addition, a particular well was sidetracked in order to improve reservoir sweep, this producer whose pressure had been historically fairly steady, experienced a sudden increase of time-lapse average reservoir pressure. When the pre and post sidetrack locations of this well were plotted on CRR map, the reason for the sudden pressure increase became obvious; well was sidetracked across CRR boundary, from a poor reservoir quality to a good reservoir quality CRR. In certain cases, oil and gas fields may not have seismic data, in other cases the resolution of the returned seismic signal may be weak. In such cases, CRR maps created using time-lapse average reservoir pressure groups could be used during geo-modelling,for controlling the distribution of 3-D properties away from well control points, instead of seismic acoustic impedance reservoir quality map.
{"title":"Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir","authors":"B. Kayode, M. Yaacob, Faisal Abdullah","doi":"10.2523/IPTC-19163-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19163-MS","url":null,"abstract":"\u0000 The purpose of this paper is to highlight the similarity between Connected Reservoir Regions (CRR)map created using time-lapse pressure groups (Kayode et.al 2018)and other reservoir quality maps like Seismic Acoustic Impedance (SAI) map and petro-physical rock quality map.\u0000 Time-lapse average reservoir pressure from producers and injectors spanning several years of field production were sorted into groups of similar pressure trends. Wells that show similar pressure trend were classified into same CRR, while wells that show different pressure trends were classified into different CRRs. Only wells operating within the same reservoir zone have been used in the pressure grouping in order to ensure that the observed pressure trend differences are only due to lateral variations of reservoir quality and not due to vertical zonation. A geo-modelling software was used to create connected reservoir regions map in which all wells within the same pressure group are identified with a unique colour code and polygons are drawn to delineate the spatial limits of wells within each pressure group. The CRR map thus obtained, was then compared with SAI map and permeability quality map.\u0000 Similarity was observed between the CRR map, SAI map and petro-physical rock quality map. Areas indicated as poor quality (high impedance) on the SAI map and indicated as low permeability on petro-physical map were consistent with CRR regions that are characterized by high injection pressure and poor pressure support. Areas indicated as good quality (low impedance) on SAI map and high permeability on petro-physical rock quality map were consistent with CRR regions that are characterized by low injection pressure and excellent producer-injector communication. In addition, a particular well was sidetracked in order to improve reservoir sweep, this producer whose pressure had been historically fairly steady, experienced a sudden increase of time-lapse average reservoir pressure. When the pre and post sidetrack locations of this well were plotted on CRR map, the reason for the sudden pressure increase became obvious; well was sidetracked across CRR boundary, from a poor reservoir quality to a good reservoir quality CRR.\u0000 In certain cases, oil and gas fields may not have seismic data, in other cases the resolution of the returned seismic signal may be weak. In such cases, CRR maps created using time-lapse average reservoir pressure groups could be used during geo-modelling,for controlling the distribution of 3-D properties away from well control points, instead of seismic acoustic impedance reservoir quality map.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87542180","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}
J. Scarborough, Leonardo Mega-Franca, Mohamed Farouk Ibrahim
Process upsets in high oil production facilities can hinder optimal plant performance and result in system shut-ins. Based on several successful demulsifier chemical trials, scientists and engineers have developed a guideline on how to optimize production throughout the chemical trial period. Factors such as chemical injection rate, export crude oil monitoring (basic sediment and water (BS&W) and salt), discharge water quality(from the water-oil separator (WOSEP)), and transformer voltage fluctuation (dehydrator and desalter) plays an important role in minimizing the system upset. Prior to chemical trial, scientists and engineers analyze the process system to understand individual vessel functions and limitations. Incumbent chemical program provides baselines and key performance indicators (KPIs) set minimum oil specifications before exporting oil to refineries. Demulsifier injection rates are reduced based on the chemical program optimization proposal until it reaches the dosage limit while maintaining stable process throughout the trial. Therefore, scientists and engineers may evaluate the demulsifier’s performance based on the KPIs set with no system upset. Fast fluid separation in the High Pressure Production Traps (HPPTs) is an important strategy in order to improve process system’s performance. High volume oil production systems typically have two HPPTs in parallel for initial water separation. Downstream of the HPPTs is the Low Pressure Production Trap (LPPT), which is mainly used for gas separation. Oil continues to the dehydrator to finish the dehydration to meet the pipeline BS&W requirement. The dehydrator is where the transformer is located for the electrostatic grid and high amounts of water separation can cause fluid levels to fluctuate and trip the transformers. Throughout several field trial experiences, demulsifier rates can be optimized (reduced) further when it shows increased water separation at HPPT vessels. Clear water from HPPTs discharge, valves in water leg HPPTs open more (%), stable voltage grid (dehydrator/desalter), and less than 0.2% BS&W with less than 10ptb salt recorded at the export oil gives a good indication that the process is stable. Thus reduced the risk for system upset. This paper summaries the best approach to optimize chemical rates in high volume oil production systems, analyzes qualitative and quantitative system checks to verify stable operations, and discusses potential risks involved when reaching lower limits of effective chemical rates.
{"title":"Minimise System Upsets in High Oil Production Facility throughout Demulsifier Chemical Trial","authors":"J. Scarborough, Leonardo Mega-Franca, Mohamed Farouk Ibrahim","doi":"10.2523/IPTC-19496-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19496-MS","url":null,"abstract":"\u0000 Process upsets in high oil production facilities can hinder optimal plant performance and result in system shut-ins. Based on several successful demulsifier chemical trials, scientists and engineers have developed a guideline on how to optimize production throughout the chemical trial period. Factors such as chemical injection rate, export crude oil monitoring (basic sediment and water (BS&W) and salt), discharge water quality(from the water-oil separator (WOSEP)), and transformer voltage fluctuation (dehydrator and desalter) plays an important role in minimizing the system upset.\u0000 Prior to chemical trial, scientists and engineers analyze the process system to understand individual vessel functions and limitations. Incumbent chemical program provides baselines and key performance indicators (KPIs) set minimum oil specifications before exporting oil to refineries. Demulsifier injection rates are reduced based on the chemical program optimization proposal until it reaches the dosage limit while maintaining stable process throughout the trial. Therefore, scientists and engineers may evaluate the demulsifier’s performance based on the KPIs set with no system upset. Fast fluid separation in the High Pressure Production Traps (HPPTs) is an important strategy in order to improve process system’s performance.\u0000 High volume oil production systems typically have two HPPTs in parallel for initial water separation. Downstream of the HPPTs is the Low Pressure Production Trap (LPPT), which is mainly used for gas separation. Oil continues to the dehydrator to finish the dehydration to meet the pipeline BS&W requirement. The dehydrator is where the transformer is located for the electrostatic grid and high amounts of water separation can cause fluid levels to fluctuate and trip the transformers.\u0000 Throughout several field trial experiences, demulsifier rates can be optimized (reduced) further when it shows increased water separation at HPPT vessels. Clear water from HPPTs discharge, valves in water leg HPPTs open more (%), stable voltage grid (dehydrator/desalter), and less than 0.2% BS&W with less than 10ptb salt recorded at the export oil gives a good indication that the process is stable. Thus reduced the risk for system upset.\u0000 This paper summaries the best approach to optimize chemical rates in high volume oil production systems, analyzes qualitative and quantitative system checks to verify stable operations, and discusses potential risks involved when reaching lower limits of effective chemical rates.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84407700","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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