P. Maraj, Ken Huber, D. Itter, J. Nelson, M. Rabinovich, Alex Youngmun, Yuriy Antonov, Luis Mejia, S. Martakov, Jhonatan H Pazos, Austin Small, N. Tropin
{"title":"Optimal Wellbore Placement of a Penta-Lateral Well in the Schrader Bluff Reservoir, North Slope, Alaska","authors":"P. Maraj, Ken Huber, D. Itter, J. Nelson, M. Rabinovich, Alex Youngmun, Yuriy Antonov, Luis Mejia, S. Martakov, Jhonatan H Pazos, Austin Small, N. Tropin","doi":"10.2118/204468-pa","DOIUrl":"https://doi.org/10.2118/204468-pa","url":null,"abstract":"","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48883111","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Habibi, Charles E. Fensky, M. Perri, Morteza Roostaei, Mahdi Mahmoudi, Vahidoddin Fattahpour, Hongbo Zeng, M. Sadrzadeh
Previous studies showed that different parameters influence the plugging of completion tools. These parameters include rock mineralogy, reservoir-fluid properties, and type of completion tools. Although different methods have been used for unplugging these tools, there is still debate regarding the performance of these methods on damage removal. In this study, we assessed the performance of high-power shock waves generated from an electrohydraulic-stimulation (EHS) tool on cleaning completion tools plugged during oil production. These devices were extracted from different wells in Canada, Europe, and the US. First, we quantified the extent of cleaning for the plugged slotted liners using the EHS tool at the laboratory scale. Next, we analyzed the mineral composition of the plugging materials removed after the treatment by conducting scanning electron microscopy (SEM) with energy dispersive X-ray spectroscopy (EDS), inductively coupled plasma mass spectroscopy (ICP-MS), colorimetric, and dry-combustion analyses. Finally, we reviewed the pulsing-stimulation-treatment results applied to several field case studies. The results of unplugging slotted liners at the laboratory scale showed that up to 28.5% of the plugged slots are cleaned after 120 pulses of shock waves. The mineral-characterization results showed that the main plugging materials are calcite, silicates, and iron-based components (corrosion products). The cleaning performance (CP) of the EHS tool increases by increasing the number of pulses and the output energy (OE) applied to the tool. The CP parameter is high at (i) high concentrations of carbonates, barium (Ba)-based components, and organic matter, and (ii) low concentrations of corrosion products and sulfates. The results of field case studies showed that the cleaning of the EHS tool is not limited to the sand-control devices and it can clean other tools that are less accessible for other techniques, such as subsurface safety valves. This paper provides a better understanding of the performance of shock waves on damage removal from plugged completion tools. The results could open new insight into the applications of shock waves for cleaning the completion tools.
{"title":"Unplugging Standalone Sand-Control Screens Using High-Power Shock Waves","authors":"A. Habibi, Charles E. Fensky, M. Perri, Morteza Roostaei, Mahdi Mahmoudi, Vahidoddin Fattahpour, Hongbo Zeng, M. Sadrzadeh","doi":"10.2118/199294-PA","DOIUrl":"https://doi.org/10.2118/199294-PA","url":null,"abstract":"\u0000 Previous studies showed that different parameters influence the plugging of completion tools. These parameters include rock mineralogy, reservoir-fluid properties, and type of completion tools. Although different methods have been used for unplugging these tools, there is still debate regarding the performance of these methods on damage removal. In this study, we assessed the performance of high-power shock waves generated from an electrohydraulic-stimulation (EHS) tool on cleaning completion tools plugged during oil production. These devices were extracted from different wells in Canada, Europe, and the US. First, we quantified the extent of cleaning for the plugged slotted liners using the EHS tool at the laboratory scale. Next, we analyzed the mineral composition of the plugging materials removed after the treatment by conducting scanning electron microscopy (SEM) with energy dispersive X-ray spectroscopy (EDS), inductively coupled plasma mass spectroscopy (ICP-MS), colorimetric, and dry-combustion analyses. Finally, we reviewed the pulsing-stimulation-treatment results applied to several field case studies. The results of unplugging slotted liners at the laboratory scale showed that up to 28.5% of the plugged slots are cleaned after 120 pulses of shock waves. The mineral-characterization results showed that the main plugging materials are calcite, silicates, and iron-based components (corrosion products). The cleaning performance (CP) of the EHS tool increases by increasing the number of pulses and the output energy (OE) applied to the tool. The CP parameter is high at (i) high concentrations of carbonates, barium (Ba)-based components, and organic matter, and (ii) low concentrations of corrosion products and sulfates. The results of field case studies showed that the cleaning of the EHS tool is not limited to the sand-control devices and it can clean other tools that are less accessible for other techniques, such as subsurface safety valves. This paper provides a better understanding of the performance of shock waves on damage removal from plugged completion tools. The results could open new insight into the applications of shock waves for cleaning the completion tools.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45998859","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Junbo He, Jiren Tang, Honglian Li, Jing Zhang, Qi Yao
In the process of shale coring, the gas adsorption will increase the flow resistance of gas inside the core, which will inevitably affect the accuracy of shale gas loss. To clarify the underlying effects of seepage flow and related factors during shale desorption, we conducted an experimental study on the influence of methane on seepage resistance of fractured shale and matrix shale under different adsorption pressures. Changes in reservoir fluid and deformation resulting from CH4 saturation adsorption resulted in changes in shale permeability. This study investigated six adsorption durations (2, 4, 6, 12, 18, and 24 hours) under adsorption pressures of 5, 9, and 13 MPa in shale samples. During each cycle, different injection pressures (2 to 6 MPa) were applied, and seepage resistance of shale samples was measured by the transient method. The results showed that the permeation resistance of the sample decreased significantly after adsorption of CH4 reached saturation and decreased with increasing CH4 adsorption duration. Compared with matrix shale samples, fractured shale samples were shown to have more suitable pore microcracks and higher CH4 affinity. Therefore, fractured samples were found to have higher permeability resistance and higher adsorption capacity compared to matrix shale. The permeability flow of a sample had a negative exponential relationship with confining pressure, and stress sensitivity increased with increasing CH4 adsorption time. The model representing gas loss indicated a positive correlation between change in impermeability and the flow of escaped gas on the core surface. A significant reduction in the impermeability of the core will result in a significant reduction in shale gas loss.
{"title":"Effects of Seepage on Gas Loss through Shale Desorption during Shale Core Removal","authors":"Junbo He, Jiren Tang, Honglian Li, Jing Zhang, Qi Yao","doi":"10.2118/204234-pa","DOIUrl":"https://doi.org/10.2118/204234-pa","url":null,"abstract":"\u0000 In the process of shale coring, the gas adsorption will increase the flow resistance of gas inside the core, which will inevitably affect the accuracy of shale gas loss. To clarify the underlying effects of seepage flow and related factors during shale desorption, we conducted an experimental study on the influence of methane on seepage resistance of fractured shale and matrix shale under different adsorption pressures. Changes in reservoir fluid and deformation resulting from CH4 saturation adsorption resulted in changes in shale permeability. This study investigated six adsorption durations (2, 4, 6, 12, 18, and 24 hours) under adsorption pressures of 5, 9, and 13 MPa in shale samples. During each cycle, different injection pressures (2 to 6 MPa) were applied, and seepage resistance of shale samples was measured by the transient method. The results showed that the permeation resistance of the sample decreased significantly after adsorption of CH4 reached saturation and decreased with increasing CH4 adsorption duration. Compared with matrix shale samples, fractured shale samples were shown to have more suitable pore microcracks and higher CH4 affinity. Therefore, fractured samples were found to have higher permeability resistance and higher adsorption capacity compared to matrix shale. The permeability flow of a sample had a negative exponential relationship with confining pressure, and stress sensitivity increased with increasing CH4 adsorption time. The model representing gas loss indicated a positive correlation between change in impermeability and the flow of escaped gas on the core surface. A significant reduction in the impermeability of the core will result in a significant reduction in shale gas loss.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45822683","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Cuttings transport, in connection with drilling fluid rheology, has been extensively studied in the literature. Despite this, contradictory results continue to be reported regarding the effect of yield stress on cuttings transport. This study uses the concepts of static and dynamic yield stresses to investigate the effects of yield stress on cuttings transport. A modified form of an existing rheological function is proposed to model static and dynamic yield stresses while incorporating flow history. Flow equations are based on the mixture approach and are numerically solved using computational fluid dynamics (CFD) methodology. Assuming that the liquid phase is homogenous and drill cuttings are noncolloidal, it is shown that the distinction between static and dynamic yield stresses diminishes as volumetric cuttings concentration increases. The Herschel-Bulkley function predicts infinite viscosity at the limit of zero shear rate and, hence, improved cuttings transport with increasing dynamic yield stress, whereas in line with the majority of experimental studies, the proposed rheological model shows that high dynamic yield stress is detrimental for cuttings transport. Comparing fluids with the same dynamic yield stress, the fluid with a larger difference between static and dynamic yield stresses has better cuttings carrying capacity. However, these results are only valid for simple yield stress fluids in which yield stress is dependent on shear rate only.
{"title":"Modeling Cuttings Transport without Drillpipe Rotation While Using the Concepts of Static and Dynamic Yield Stresses","authors":"Shiraz Gulraiz, K. Gray","doi":"10.2118/204466-pa","DOIUrl":"https://doi.org/10.2118/204466-pa","url":null,"abstract":"\u0000 Cuttings transport, in connection with drilling fluid rheology, has been extensively studied in the literature. Despite this, contradictory results continue to be reported regarding the effect of yield stress on cuttings transport. This study uses the concepts of static and dynamic yield stresses to investigate the effects of yield stress on cuttings transport. A modified form of an existing rheological function is proposed to model static and dynamic yield stresses while incorporating flow history. Flow equations are based on the mixture approach and are numerically solved using computational fluid dynamics (CFD) methodology. Assuming that the liquid phase is homogenous and drill cuttings are noncolloidal, it is shown that the distinction between static and dynamic yield stresses diminishes as volumetric cuttings concentration increases. The Herschel-Bulkley function predicts infinite viscosity at the limit of zero shear rate and, hence, improved cuttings transport with increasing dynamic yield stress, whereas in line with the majority of experimental studies, the proposed rheological model shows that high dynamic yield stress is detrimental for cuttings transport. Comparing fluids with the same dynamic yield stress, the fluid with a larger difference between static and dynamic yield stresses has better cuttings carrying capacity. However, these results are only valid for simple yield stress fluids in which yield stress is dependent on shear rate only.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45159165","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Currently, researchers and the industry believe that water invasion into a shale matrix should dominate the process of water soaking before flowback of hydraulic fracturing fluids. Based on laboratory observations with Tuscaloosa marine shale (TMS) cores, we postulate a hypothesis that cracks are formed in shale formations during and after hydraulic fracture stimulation and that they later contribute to improved well productivity. The formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures, reduce fracture width, and consequently lower well inflow performance. The trade-off between crack development and fracture closure allows for an optimum water-soaking time, which could potentially maximize well productivity. A mathematical model was developed to describe the dynamic propagation of cracks based on the capillary-viscous force balance. The effect of crack formation on the long-term well productivity was analyzed using a previously published mathematical model for well productivity. A combination of the crack propagation and the well productivity models for the first time provides a technique for predicting the optimum fluid soaking time before flowback of hydraulic fracturing fluids. Sensitivity analyses show that reducing the viscosity of fracturing fluid could potentially speed up the optimum water-soaking time, while lowering the water-shale interfacial tension (IFT) could potentially delay the optimum water-soaking time. Real-time shut-in pressure data can be used in the crack propagation model to “monitor” crack development and identify the optimum water-soaking time before the flowback of hydraulic fracturing fluids for maximizing well productivity and the gas/oil recovery factor.
{"title":"Crack Propagation Hypothesis and a Model To Calculate the Optimum Water-Soaking Period in Shale Gas/Oil Wells for Maximizing Well Productivity","authors":"B. Guo, R. Shaibu, Xuejun Hou","doi":"10.2118/201203-pa","DOIUrl":"https://doi.org/10.2118/201203-pa","url":null,"abstract":"\u0000 Currently, researchers and the industry believe that water invasion into a shale matrix should dominate the process of water soaking before flowback of hydraulic fracturing fluids. Based on laboratory observations with Tuscaloosa marine shale (TMS) cores, we postulate a hypothesis that cracks are formed in shale formations during and after hydraulic fracture stimulation and that they later contribute to improved well productivity. The formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures, reduce fracture width, and consequently lower well inflow performance. The trade-off between crack development and fracture closure allows for an optimum water-soaking time, which could potentially maximize well productivity. A mathematical model was developed to describe the dynamic propagation of cracks based on the capillary-viscous force balance. The effect of crack formation on the long-term well productivity was analyzed using a previously published mathematical model for well productivity. A combination of the crack propagation and the well productivity models for the first time provides a technique for predicting the optimum fluid soaking time before flowback of hydraulic fracturing fluids. Sensitivity analyses show that reducing the viscosity of fracturing fluid could potentially speed up the optimum water-soaking time, while lowering the water-shale interfacial tension (IFT) could potentially delay the optimum water-soaking time. Real-time shut-in pressure data can be used in the crack propagation model to “monitor” crack development and identify the optimum water-soaking time before the flowback of hydraulic fracturing fluids for maximizing well productivity and the gas/oil recovery factor.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201203-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44374859","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Dikshit, Amrendra Kumar, E. Anikanov, P. Petukhov, A. Rudic, G. Woiceshyn, B. Gadiyar, M. Parlar, Camilo Jurgensen
Sand control screens are installed with an internal string (wash pipe) as required which, among other functions, provides a circulation path. In long horizontal wells, running a wash pipe consumes considerable rig time and may limit the ability to reach target depth. In cases in which fluid losses are experienced after screen installation, isolating the open hole with a fluid-loss control valve can be prolonged. This paper describes a wash-pipe-free solution for screen installation using a check-valve inflow control device (CV-ICD). ICD screens are commonly used to delay/restrict the influx of unwanted fluids such as gas or water. The wash-pipe-free solution integrates a check valve with the ICD to prevent outflow through the screen during circulation and allows inflow through the screen when placed on production. This solution uses a check ball that seals against the ICD during circulation but falls back on a porous retainer plate during production. The check ball and retainer plate can be dissolved by spotting a reactive fluid inside the screen or made to erode over time with production. Laboratory testing yielded the following results: the ICD with the check ball was shown to seal up to 5,000 psi; the check ball and retainer plate can be dissolved by a reactive fluid, which can be tailored to bottomhole temperature and the required time of dissolution; and the pressure activation test demonstrated that the maximum differential pressure to seat the ball was less than 5 psi. This CV-ICD solution has been applied worldwide in more than 35 wells, most of which were targeted to avoid running a wash pipe. However, in two wells the technology was successfully used to set openhole packers with a 5,000-psi setting pressure. In this paper, we present the wash-pipe-free ICD screen installation with a dissolvable check valve and the capability of setting a hydraulic packer without a wash pipe or intervention in the open hole. The novel contribution presented herein is the ability to integrate a ball and cage to existing nozzle-based ICDs by using dissolvable material to achieve the preceding results in this application.
{"title":"Sand Screen with Check-Valve Inflow Control Devices","authors":"A. Dikshit, Amrendra Kumar, E. Anikanov, P. Petukhov, A. Rudic, G. Woiceshyn, B. Gadiyar, M. Parlar, Camilo Jurgensen","doi":"10.2118/201206-pa","DOIUrl":"https://doi.org/10.2118/201206-pa","url":null,"abstract":"\u0000 Sand control screens are installed with an internal string (wash pipe) as required which, among other functions, provides a circulation path. In long horizontal wells, running a wash pipe consumes considerable rig time and may limit the ability to reach target depth. In cases in which fluid losses are experienced after screen installation, isolating the open hole with a fluid-loss control valve can be prolonged. This paper describes a wash-pipe-free solution for screen installation using a check-valve inflow control device (CV-ICD).\u0000 ICD screens are commonly used to delay/restrict the influx of unwanted fluids such as gas or water. The wash-pipe-free solution integrates a check valve with the ICD to prevent outflow through the screen during circulation and allows inflow through the screen when placed on production. This solution uses a check ball that seals against the ICD during circulation but falls back on a porous retainer plate during production. The check ball and retainer plate can be dissolved by spotting a reactive fluid inside the screen or made to erode over time with production.\u0000 Laboratory testing yielded the following results: the ICD with the check ball was shown to seal up to 5,000 psi; the check ball and retainer plate can be dissolved by a reactive fluid, which can be tailored to bottomhole temperature and the required time of dissolution; and the pressure activation test demonstrated that the maximum differential pressure to seat the ball was less than 5 psi.\u0000 This CV-ICD solution has been applied worldwide in more than 35 wells, most of which were targeted to avoid running a wash pipe. However, in two wells the technology was successfully used to set openhole packers with a 5,000-psi setting pressure. In this paper, we present the wash-pipe-free ICD screen installation with a dissolvable check valve and the capability of setting a hydraulic packer without a wash pipe or intervention in the open hole. The novel contribution presented herein is the ability to integrate a ball and cage to existing nozzle-based ICDs by using dissolvable material to achieve the preceding results in this application.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201206-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67779847","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Zhong Xianyou, Cen Li, Zhao Yankun, Huang Tianwei, Jinjin Shi
At present, mud pulse transmission is widely used in underground wireless transmission. To extract more accurately the original drilling fluid pulse signals while drilling, in this paper, we developed an algorithm for optimal denoising shaping based on particle-swarm-optimized time-varying filtering empirical mode decomposition (TVFEMD). The performance of TVFEMD heavily depends on its parameters (i.e., B-spline order and bandwidth threshold). In the traditional TVFEMD method, the parameters are given in advance and may not be optimized, so it is difficult to achieve satisfactory decomposition results. To tackle this issue, the correlation coefficient was used as the objective function, and the particle-swarm-optimization algorithm was used to optimize the parameters of TVFEMD in this paper. First, the particle swarm optimization was used to search for the best combination of parameters. Then, the TVFEMD was applied to obtain a series of intrinsic mode functions (IMFs). Subsequently, the optimal denoising and shaping algorithm was used to determine the best reconstructed signal by low-pass filtering. Permutation entropy was taken as the evaluation index to obtain a reconstruction signal. Finally, the reconstructed signal was processed by square wave shaping to obtain accurate drilling fluid pulse signals. The approximation of the algorithm is 0.7581, and relevance is as high as 0.8535. The simulation signal and drilling fluid pulse signal analysis results showed that the proposed approach can extract the original pulse signal accurately.
{"title":"Measurement While Drilling Mud Pulse Signal Denoising and Extraction Approach Based on Particle-Swarm-Optimized Time-Varying Filtering Empirical Mode Decomposition","authors":"Zhong Xianyou, Cen Li, Zhao Yankun, Huang Tianwei, Jinjin Shi","doi":"10.2118/204454-pa","DOIUrl":"https://doi.org/10.2118/204454-pa","url":null,"abstract":"\u0000 At present, mud pulse transmission is widely used in underground wireless transmission. To extract more accurately the original drilling fluid pulse signals while drilling, in this paper, we developed an algorithm for optimal denoising shaping based on particle-swarm-optimized time-varying filtering empirical mode decomposition (TVFEMD). The performance of TVFEMD heavily depends on its parameters (i.e., B-spline order and bandwidth threshold). In the traditional TVFEMD method, the parameters are given in advance and may not be optimized, so it is difficult to achieve satisfactory decomposition results. To tackle this issue, the correlation coefficient was used as the objective function, and the particle-swarm-optimization algorithm was used to optimize the parameters of TVFEMD in this paper. First, the particle swarm optimization was used to search for the best combination of parameters. Then, the TVFEMD was applied to obtain a series of intrinsic mode functions (IMFs). Subsequently, the optimal denoising and shaping algorithm was used to determine the best reconstructed signal by low-pass filtering. Permutation entropy was taken as the evaluation index to obtain a reconstruction signal. Finally, the reconstructed signal was processed by square wave shaping to obtain accurate drilling fluid pulse signals. The approximation of the algorithm is 0.7581, and relevance is as high as 0.8535. The simulation signal and drilling fluid pulse signal analysis results showed that the proposed approach can extract the original pulse signal accurately.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43176806","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Nana, C. Uba, C. Johnson, Matthieu Lonca, Jamel Zghal
To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.
{"title":"West Africa Salt-Zone Cementing Best Practices: Laboratory Evaluation and 5-Year Field Application Review","authors":"D. Nana, C. Uba, C. Johnson, Matthieu Lonca, Jamel Zghal","doi":"10.2118/203444-ms","DOIUrl":"https://doi.org/10.2118/203444-ms","url":null,"abstract":"\u0000 To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success.\u0000 A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa.\u0000 This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt.\u0000 In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45375805","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this study, we perform several tests to develop a formula of glycerol-based drilling fluid that is suitable for shale formations with severe wellbore instability problems. Drilling fluids with varying combinations of nanosilica, glycerol, sodium carboxymethyl cellulose (Na-CMC), and xanthan gum (XG) in organic soil glycerol-based slurry are tested, and the effects of nanosilica on the swelling of shale samples and the lubricity of drilling fluids are also investigated to verify the feasibility of designed drilling fluids. The experimental investigations reveal that the values of apparent viscosity (AV), plastic viscosity (PV), and yield value (YP) of the optimal formulation meet the rheological parameters required for the drilling of shale formations. The AV and PV values of drilling fluid with 55:45 glycerol/water ratio are lower than those of drilling fluids with other glycerol/water ratios. A higher XG content means higher YP value in the experiment and 0.4% XG is suitable for the glycerol-based drilling fluid to prevent the collapse of the shale wellbore. There is a critical nanosilica content threshold (0.5%), and the filtration loss (FL) increases gradually when this threshold is exceeded due to the agglomeration of nanosilica. The nanosilica coated on clay particles in shales because of the formation of hydrogen bonds results in a decrease in permeability of shale formations. The swelling of shale through hydration is greatly reduced by 37% and the sticking coefficient of drilling fluid is reduced by 28% when 0.5% nanosilica is added. The addition of nanosilica to glycerol-based drilling fluid is significant to deal with the wellbore instability problems in troublesome shale formations.
{"title":"Application of Nanosilica in Glycerol-Based Drilling Fluid for Shale Formations","authors":"Chao Lyu, Shuqing Hao, Liang Yang","doi":"10.2118/204238-pa","DOIUrl":"https://doi.org/10.2118/204238-pa","url":null,"abstract":"\u0000 In this study, we perform several tests to develop a formula of glycerol-based drilling fluid that is suitable for shale formations with severe wellbore instability problems. Drilling fluids with varying combinations of nanosilica, glycerol, sodium carboxymethyl cellulose (Na-CMC), and xanthan gum (XG) in organic soil glycerol-based slurry are tested, and the effects of nanosilica on the swelling of shale samples and the lubricity of drilling fluids are also investigated to verify the feasibility of designed drilling fluids. The experimental investigations reveal that the values of apparent viscosity (AV), plastic viscosity (PV), and yield value (YP) of the optimal formulation meet the rheological parameters required for the drilling of shale formations. The AV and PV values of drilling fluid with 55:45 glycerol/water ratio are lower than those of drilling fluids with other glycerol/water ratios. A higher XG content means higher YP value in the experiment and 0.4% XG is suitable for the glycerol-based drilling fluid to prevent the collapse of the shale wellbore. There is a critical nanosilica content threshold (0.5%), and the filtration loss (FL) increases gradually when this threshold is exceeded due to the agglomeration of nanosilica. The nanosilica coated on clay particles in shales because of the formation of hydrogen bonds results in a decrease in permeability of shale formations. The swelling of shale through hydration is greatly reduced by 37% and the sticking coefficient of drilling fluid is reduced by 28% when 0.5% nanosilica is added. The addition of nanosilica to glycerol-based drilling fluid is significant to deal with the wellbore instability problems in troublesome shale formations.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45687902","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Predicting rate of penetration (ROP) has gained considerable interest in the drilling industry because it is the most-effective way to improve the efficiency of drilling and reduce the operating costs. One way to enhance the drilling performance is to optimize the drilling parameters using real-time data. The optimization of the drilling parameters stands on the fact that drilling parameters are interrelated; that is, corrections in one factor affect all the others, positively or negatively. Analysis of the available models in the literature showed that they did not take into account all factors, and therefore, they might underestimate the ROP. To improve the accuracy of predicting the bit efficiency, a new ROP model is developed to preplan and lower the drilling costs. This approach introduces three parts of the process that were developed to describe the challenge of predicting ROP: aggressiveness or drillability, hole cleaning, and cutters wear, which are interrelated to each other. The approach discusses each process individually, and then the influence of all three factors on ROP is assessed. Taking into account the drilling parameters and formation properties, ROP1 is estimated by use of a new equation. Then, lifting the produced cutting to the surface and evaluating how that affects the bit performance is proposed in the second part of the process (hole cleaning). Finally, wear index is introduced in the third part (wear condition) to predict the reduction of ROP2 caused by cutter/rock friction. The approach serves and could be considered as a baseline to identify all factors that can affect the bit performance. The developed model equations are applied to estimate ROP in three vertical oil wells with different bit sizes and lithology descriptions in Libya. The results indicate that the driven model provides an effective tool to predict the bit performance. The results are found in good agreement with the actual ROP values and achieve an enhancement of approximately 40% as compared to the previous models.
{"title":"Prediction of Penetration Rate for PDC Bits Using Indices of Rock Drillability, Cuttings Removal, and Bit Wear","authors":"A. Mazen, N. Rahmanian, I. Mujtaba, A. Hassanpour","doi":"10.2118/204231-pa","DOIUrl":"https://doi.org/10.2118/204231-pa","url":null,"abstract":"\u0000 Predicting rate of penetration (ROP) has gained considerable interest in the drilling industry because it is the most-effective way to improve the efficiency of drilling and reduce the operating costs. One way to enhance the drilling performance is to optimize the drilling parameters using real-time data. The optimization of the drilling parameters stands on the fact that drilling parameters are interrelated; that is, corrections in one factor affect all the others, positively or negatively.\u0000 Analysis of the available models in the literature showed that they did not take into account all factors, and therefore, they might underestimate the ROP. To improve the accuracy of predicting the bit efficiency, a new ROP model is developed to preplan and lower the drilling costs. This approach introduces three parts of the process that were developed to describe the challenge of predicting ROP: aggressiveness or drillability, hole cleaning, and cutters wear, which are interrelated to each other. The approach discusses each process individually, and then the influence of all three factors on ROP is assessed. Taking into account the drilling parameters and formation properties, ROP1 is estimated by use of a new equation. Then, lifting the produced cutting to the surface and evaluating how that affects the bit performance is proposed in the second part of the process (hole cleaning). Finally, wear index is introduced in the third part (wear condition) to predict the reduction of ROP2 caused by cutter/rock friction.\u0000 The approach serves and could be considered as a baseline to identify all factors that can affect the bit performance. The developed model equations are applied to estimate ROP in three vertical oil wells with different bit sizes and lithology descriptions in Libya. The results indicate that the driven model provides an effective tool to predict the bit performance. The results are found in good agreement with the actual ROP values and achieve an enhancement of approximately 40% as compared to the previous models.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/204231-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42977420","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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