Hua Zhang, T. Ramakrishnan, Elkady Youssef Magdy Abdou, Feng Yixuan, Q. Elias
As an alternative to cement, the feasibility of bismuth-tin (BiSn; contains 58 wt% Bi and 42 wt% Sn, abbreviations are not in stoichiometric ratio) as a low melting-point plug has been tested by Zhang et al. (2020) for rigless plug-and-abandonment (P&A) service of offshore wells. Similar to BiSn, bismuth-silver (BiAg; contains 97.5 wt% Bi and 2.5 wt% Ag, abbreviations are not in stoichiometric ratio) also exhibits desirable properties compared with Portland cement. However, because of its greater melting point, BiAg has potentially a wider application than BiSn, especially in deep formations. In the present study, we investigate the feasibility of BiAg alloy for P&A. The bond quality of the alloy-shale cores is evaluated through shear, tensile, push-out, and permeability tests, and compared with those of BiSn alloy-shale and cement-shale cores. To avoid phase change-induced shale damage at elevated temperature while setting BiAg plugs, water was first extracted with supercritical carbon dioxide (CO2). For shear and tensile tests with pinhole-anchored BiAg, the ultimate strength and modulus were measured as a function of anchor points at different temperatures (21, 80, and 110°C). For the push-out tests, shale samples of smooth, rough, and pinholed surfaces were prepared with the BiAg alloy plug. In general, we find that, without anchors, bond failure precedes shale failure. Results for cement-shale cores are also reported for comparison. We contrast the performance of BiAg and BiSn alloys at 21, 65, 80, and 110°C to determine the crossover temperature for deployment suitability.
{"title":"Comparative Evaluation of Bismuth-Silver and Bismuth-Tin Alloys for Plug and Abandonment","authors":"Hua Zhang, T. Ramakrishnan, Elkady Youssef Magdy Abdou, Feng Yixuan, Q. Elias","doi":"10.2118/202488-pa","DOIUrl":"https://doi.org/10.2118/202488-pa","url":null,"abstract":"\u0000 As an alternative to cement, the feasibility of bismuth-tin (BiSn; contains 58 wt% Bi and 42 wt% Sn, abbreviations are not in stoichiometric ratio) as a low melting-point plug has been tested by Zhang et al. (2020) for rigless plug-and-abandonment (P&A) service of offshore wells. Similar to BiSn, bismuth-silver (BiAg; contains 97.5 wt% Bi and 2.5 wt% Ag, abbreviations are not in stoichiometric ratio) also exhibits desirable properties compared with Portland cement. However, because of its greater melting point, BiAg has potentially a wider application than BiSn, especially in deep formations. In the present study, we investigate the feasibility of BiAg alloy for P&A. The bond quality of the alloy-shale cores is evaluated through shear, tensile, push-out, and permeability tests, and compared with those of BiSn alloy-shale and cement-shale cores. To avoid phase change-induced shale damage at elevated temperature while setting BiAg plugs, water was first extracted with supercritical carbon dioxide (CO2). For shear and tensile tests with pinhole-anchored BiAg, the ultimate strength and modulus were measured as a function of anchor points at different temperatures (21, 80, and 110°C). For the push-out tests, shale samples of smooth, rough, and pinholed surfaces were prepared with the BiAg alloy plug. In general, we find that, without anchors, bond failure precedes shale failure. Results for cement-shale cores are also reported for comparison. We contrast the performance of BiAg and BiSn alloys at 21, 65, 80, and 110°C to determine the crossover temperature for deployment suitability.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/202488-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47894642","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 paper, we present an accurate semiempirical rate of penetration (ROP) predictive model for polycrystalline diamond compact (PDC) bits. Our model is inspired by the model of Bourgoyne and Young (B&Y) and follows an exponential form with 10 different drilling functions to account for various factors affecting ROP in drilling operations. We extend the B&Y model to the PDC bits and discuss that a different predictive model should be obtained for each formation. On top of the factors included in the original B&Y model, our model accounts for parameters such as downhole motor, equivalent circulating density, mechanical weight on bit (WOB), and wellbore inclination. In particular, we incorporate the effect of equilibrium cuttings bed thickness and downhole cuttings concentration in the ROP model. The parameters of the model are obtained using multiple regression analysis with the field data. The importance of obtaining a formation-based ROP model is tested and verified with field data, and an algorithm to determine the parameters for new data is provided. The model can be incorporated in a framework to obtain an optimal well plan for a new well or for prescribing optimal operational parameters for well planning and real-time drilling operations. The prediction performance of the proposed model is also evaluated in various formations for several test wells across an offshore gas field. Our results indicate that the proposed model is able to predict the drilling ROP with an accuracy of more than 90%.
在本文中，我们提出了一个精确的聚晶金刚石压片(PDC)钻头的半经验钻速(ROP)预测模型。我们的模型受到Bourgoyne and Young (B&Y)模型的启发，并遵循10种不同钻井函数的指数形式，以考虑钻井作业中影响ROP的各种因素。我们将B&Y模型扩展到PDC钻头，并讨论了每个地层应该获得不同的预测模型。除了原始B&Y模型中包含的因素外，我们的模型还考虑了井下马达、等效循环密度、钻头机械重量(WOB)和井筒倾角等参数。特别是，我们在ROP模型中考虑了平衡岩屑层厚度和井下岩屑浓度的影响。利用实测数据进行多元回归分析，得到了模型参数。通过现场数据验证了获得基于地层的ROP模型的重要性，并提供了确定新数据参数的算法。该模型可以整合到一个框架中，以获得新井的最佳井计划，或为井计划和实时钻井作业规定最佳操作参数。本文还对该模型在海上气田不同地层的几口测试井的预测性能进行了评估。结果表明，该模型能够预测钻井机械钻速，精度超过90%。
{"title":"A Semiempirical Model for Rate of Penetration with Application to an Offshore Gas Field","authors":"D. Etesami, Mehrdad G. Shirangi, W. J. Zhang","doi":"10.2118/202481-PA","DOIUrl":"https://doi.org/10.2118/202481-PA","url":null,"abstract":"In this paper, we present an accurate semiempirical rate of penetration (ROP) predictive model for polycrystalline diamond compact (PDC) bits. Our model is inspired by the model of Bourgoyne and Young (B&Y) and follows an exponential form with 10 different drilling functions to account for various factors affecting ROP in drilling operations. We extend the B&Y model to the PDC bits and discuss that a different predictive model should be obtained for each formation. On top of the factors included in the original B&Y model, our model accounts for parameters such as downhole motor, equivalent circulating density, mechanical weight on bit (WOB), and wellbore inclination. In particular, we incorporate the effect of equilibrium cuttings bed thickness and downhole cuttings concentration in the ROP model. The parameters of the model are obtained using multiple regression analysis with the field data. The importance of obtaining a formation-based ROP model is tested and verified with field data, and an algorithm to determine the parameters for new data is provided. The model can be incorporated in a framework to obtain an optimal well plan for a new well or for prescribing optimal operational parameters for well planning and real-time drilling operations. The prediction performance of the proposed model is also evaluated in various formations for several test wells across an offshore gas field. Our results indicate that the proposed model is able to predict the drilling ROP with an accuracy of more than 90%.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/202481-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67779878","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}
M. Soroush, Morteza Roostaei, S. A. Hosseini, M. Mohammadtabar, P. Pourafshary, Mahdi Mahmoudi, A. Ghalambor, Vahidoddin Fattahpour
Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay-zone thickness, viscosity, particle-size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavy-oil reserves in shallow depths (less than 500-m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less-problematic conditions. Further investigation has shown that inflow-control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy-oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
{"title":"Challenges and Potentials for Sand and Flow Control and Management in the Sandstone Oil Fields of Kazakhstan: A Literature Review","authors":"M. Soroush, Morteza Roostaei, S. A. Hosseini, M. Mohammadtabar, P. Pourafshary, Mahdi Mahmoudi, A. Ghalambor, Vahidoddin Fattahpour","doi":"10.2118/199247-PA","DOIUrl":"https://doi.org/10.2118/199247-PA","url":null,"abstract":"\u0000 Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan.\u0000 We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay-zone thickness, viscosity, particle-size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves.\u0000 Weakly consolidated heavy-oil reserves in shallow depths (less than 500-m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less-problematic conditions. Further investigation has shown that inflow-control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding.\u0000 This paper provides a review on challenges and potentials for sand control and sand management in heavy-oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199247-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43600089","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}
Robustness of round and V-shaped polycrystalline diamond compact (PDC) cutters against mechanical and thermal load was evaluated. Forensic analysis was used to estimate the range of loads and depths of cut (DOC) that cause structural overload of PDC cutters. Finite-element analyses (FEAs) were calibrated against these data and used to estimate the integrity of cutters. Thermal-abrasive wear was tested with single cutter tests on Sierra White granite with and without cooling for multiple material grades. The axial and tangential impact resistances were evaluated with drop and front face impact tests. In addition, full-scale laboratory drilling tests were conducted in granite [unconfined compressive strength (UCS) = 28,000 psi] and quartzite (UCS = 56,000 psi). Finally, failures for round and V-shaped cutters were evaluated in field trials. The V-shaped cutters scored similar to baseline cutters in thermal-abrasive tests but lower in axial impact tests. They also failed at 13 to 18% lesser tangential load. By accounting for 16% reduction in contact area between the shaped cutter and load anvil, it was concluded that both cutter geometries fail essentially at the same stress. In all full-scale tests, round cutters failed before the shaped cutters. This was in contrast with drop tests and is attributed to the shaped cutter's cutting efficiency, resulting in lesser load on the cutters for the same rate of penetration (ROP). The results were compared with field runs in hard and interbedded application in Oklahoma and west Texas. The conclusion based on FEA, laboratory, and field data was that in most cases, this shaped cutter shows the same or better dull as its base grade.
{"title":"Investigation of PDC Cutter Structural Integrity in Hard Rocks","authors":"R. Rahmani, P. Pastusek, Geng Yun, T. Roberts","doi":"10.2118/199598-PA","DOIUrl":"https://doi.org/10.2118/199598-PA","url":null,"abstract":"\u0000 Robustness of round and V-shaped polycrystalline diamond compact (PDC) cutters against mechanical and thermal load was evaluated. Forensic analysis was used to estimate the range of loads and depths of cut (DOC) that cause structural overload of PDC cutters. Finite-element analyses (FEAs) were calibrated against these data and used to estimate the integrity of cutters. Thermal-abrasive wear was tested with single cutter tests on Sierra White granite with and without cooling for multiple material grades. The axial and tangential impact resistances were evaluated with drop and front face impact tests. In addition, full-scale laboratory drilling tests were conducted in granite [unconfined compressive strength (UCS) = 28,000 psi] and quartzite (UCS = 56,000 psi). Finally, failures for round and V-shaped cutters were evaluated in field trials.\u0000 The V-shaped cutters scored similar to baseline cutters in thermal-abrasive tests but lower in axial impact tests. They also failed at 13 to 18% lesser tangential load. By accounting for 16% reduction in contact area between the shaped cutter and load anvil, it was concluded that both cutter geometries fail essentially at the same stress. In all full-scale tests, round cutters failed before the shaped cutters. This was in contrast with drop tests and is attributed to the shaped cutter's cutting efficiency, resulting in lesser load on the cutters for the same rate of penetration (ROP). The results were compared with field runs in hard and interbedded application in Oklahoma and west Texas. The conclusion based on FEA, laboratory, and field data was that in most cases, this shaped cutter shows the same or better dull as its base grade.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42810812","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}
Shuang Zheng, Ripudaman Manchanda, Deepen P. Gala, M. Sharma
Mitigating the negative impact of fracture hits on production from parent and child wells is challenging. This work shows the impact of parent-well depletion and repressurization on child-well fracture propagation and parent-well productivity. The goal of this study is to develop a method to better manage production/injection in the parent well so that the performance of the child well can be improved by minimizing fracture interference and fracture hits. A fully integrated equation-of-state compositional hydraulic fracturing and reservoir simulator has been developed to seamlessly model fluid production/injection (water or gas) in the parent well and model propagation of multiple fractures from the child well. The effects of drawdown rate and production time is presented for a typical shale play for three different fluid types: black oil, volatile oil, and dry gas. The results show that different reservoir fluids and drawdown strategies for the parent wells result in different stress distributions in the depleted zone, and this affects fracture propagation in the child well. Different strategies were studied to repressurize the parent well by varying the injected fluids (gas vs. water), the volumes of the preload fluid, and so on. It was found that fracture hits can be avoided if the fluid injection strategy is designed appropriately. In some poorly designed preloading strategies, fracture hits are still observed. Last, the impact of preloading on the parent-well productivity was analyzed. When water was used for preloading, water blocking was observed in the reservoir, and it caused damage to the parent well. However, when gas was injected for preloading, the oil recovery from the parent well was observed to increase. Such simulations of parent–child well interactions provide much-needed quantification to predict and mitigate the damage caused by depletion, fracture interference, and fracture hits.
{"title":"Preloading Depleted Parent Wells To Avoid Fracture Hits: Some Important Design Considerations","authors":"Shuang Zheng, Ripudaman Manchanda, Deepen P. Gala, M. Sharma","doi":"10.2118/195912-pa","DOIUrl":"https://doi.org/10.2118/195912-pa","url":null,"abstract":"\u0000 Mitigating the negative impact of fracture hits on production from parent and child wells is challenging. This work shows the impact of parent-well depletion and repressurization on child-well fracture propagation and parent-well productivity. The goal of this study is to develop a method to better manage production/injection in the parent well so that the performance of the child well can be improved by minimizing fracture interference and fracture hits.\u0000 A fully integrated equation-of-state compositional hydraulic fracturing and reservoir simulator has been developed to seamlessly model fluid production/injection (water or gas) in the parent well and model propagation of multiple fractures from the child well. The effects of drawdown rate and production time is presented for a typical shale play for three different fluid types: black oil, volatile oil, and dry gas. The results show that different reservoir fluids and drawdown strategies for the parent wells result in different stress distributions in the depleted zone, and this affects fracture propagation in the child well. Different strategies were studied to repressurize the parent well by varying the injected fluids (gas vs. water), the volumes of the preload fluid, and so on. It was found that fracture hits can be avoided if the fluid injection strategy is designed appropriately. In some poorly designed preloading strategies, fracture hits are still observed. Last, the impact of preloading on the parent-well productivity was analyzed. When water was used for preloading, water blocking was observed in the reservoir, and it caused damage to the parent well. However, when gas was injected for preloading, the oil recovery from the parent well was observed to increase.\u0000 Such simulations of parent–child well interactions provide much-needed quantification to predict and mitigate the damage caused by depletion, fracture interference, and fracture hits.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/195912-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48572377","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}
Invasion of mud filtrate while drilling is considered one of the most common sources of formation damage. Minimizing formation damage, using appropriate drilling-fluid additives that can generate good-quality filter cake, provides one of the key elements for the success of the drilling operation. This study focuses on assessing the effect of using different types of nanoparticles (NPs) with calcium- (Ca-) bentonite on the formation-damage and filter-cake properties under downhole conditions. Four types of oxide NPs were added to a suspension of 7-wt% Ca-bentonite with deionized water: ferric oxide (Fe2O3), magnetic iron oxide (Fe3O4), zinc oxide (ZnO), and silica (SiO2) NPs. The NPs/Ca-bentonite suspensions were then used to conduct the filtration process at a differential pressure of 300 psi and a temperature of 250°F using a high-pressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press. Indiana limestone disks of 1-in. thickness were examined as the filter medium to simulate the formation in the filtration experiments. A computed tomography (CT) scan technique was used to characterize the deposited filter cake and evaluate the formation damage that was caused by using different fluid samples. The results of this study showed that the filtrate invasion is affected by the type of NPs, which is also affecting the disk porosity. Using 0.5-wt% Fe2O3 NPs with the 7-wt% Ca-bentonite fluid showed a greater potential to minimize the amount of damage. The average porosity of the disk was decreased by 1.0%. However, adding 0.5-wt% Fe3O4, SiO2, and ZnO NPs yielded a disk-porosity decrease of 4.7, 13.7, and 30%, respectively. The decrease in the disk porosity after filtration is directly proportional to the volume of the invaded filtrate. Compared with that of the base fluid, the best decrease in the filtrate invasion was achieved when adding 0.5 wt% Fe2O3 and Fe3O4 NPs by 42.5 and 23%, respectively. The results revealed that Fe2O3 and Fe3O4 NPs can build a better Ca-bentonite platelet structure and thus a good-quality filter cake. This is because of their positive surface charge and stability in suspensions, as demonstrated by zeta-potential measurements, which can minimize formation damage. Increasing the concentration of Fe3O4 NPs from 0.5% to 1.5 wt% showed an insignificant variation in the filtrate invasion, spurt loss, and filter cake permeability; however, an increase in the filter-cake thickness and amount of damage created was observed. The 1.5-wt% ZnO NPs showed better performance compared with the case having 0.5-wt% ZnO NPs, but in the meanwhile, it showed the lowest efficiency compared with the other types of NPs. This could be because of their surface charge and suspension instability. Results of this work are useful in evaluating the drilling applications using Ca-bentonite-based fluids modified with NPs as an alternative to the commonly used Na-bentonite. In addition, it might help in understanding the NPs/Ca-be
{"title":"Formation-Damage Assessment and Filter-Cake Characterization of Ca-Bentonite Fluids Enhanced with Nanoparticles","authors":"O. Mahmoud, H. Nasr-El-Din","doi":"10.2118/191155-pa","DOIUrl":"https://doi.org/10.2118/191155-pa","url":null,"abstract":"\u0000 Invasion of mud filtrate while drilling is considered one of the most common sources of formation damage. Minimizing formation damage, using appropriate drilling-fluid additives that can generate good-quality filter cake, provides one of the key elements for the success of the drilling operation. This study focuses on assessing the effect of using different types of nanoparticles (NPs) with calcium- (Ca-) bentonite on the formation-damage and filter-cake properties under downhole conditions.\u0000 Four types of oxide NPs were added to a suspension of 7-wt% Ca-bentonite with deionized water: ferric oxide (Fe2O3), magnetic iron oxide (Fe3O4), zinc oxide (ZnO), and silica (SiO2) NPs. The NPs/Ca-bentonite suspensions were then used to conduct the filtration process at a differential pressure of 300 psi and a temperature of 250°F using a high-pressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press. Indiana limestone disks of 1-in. thickness were examined as the filter medium to simulate the formation in the filtration experiments. A computed tomography (CT) scan technique was used to characterize the deposited filter cake and evaluate the formation damage that was caused by using different fluid samples.\u0000 The results of this study showed that the filtrate invasion is affected by the type of NPs, which is also affecting the disk porosity. Using 0.5-wt% Fe2O3 NPs with the 7-wt% Ca-bentonite fluid showed a greater potential to minimize the amount of damage. The average porosity of the disk was decreased by 1.0%. However, adding 0.5-wt% Fe3O4, SiO2, and ZnO NPs yielded a disk-porosity decrease of 4.7, 13.7, and 30%, respectively. The decrease in the disk porosity after filtration is directly proportional to the volume of the invaded filtrate. Compared with that of the base fluid, the best decrease in the filtrate invasion was achieved when adding 0.5 wt% Fe2O3 and Fe3O4 NPs by 42.5 and 23%, respectively. The results revealed that Fe2O3 and Fe3O4 NPs can build a better Ca-bentonite platelet structure and thus a good-quality filter cake. This is because of their positive surface charge and stability in suspensions, as demonstrated by zeta-potential measurements, which can minimize formation damage. Increasing the concentration of Fe3O4 NPs from 0.5% to 1.5 wt% showed an insignificant variation in the filtrate invasion, spurt loss, and filter cake permeability; however, an increase in the filter-cake thickness and amount of damage created was observed. The 1.5-wt% ZnO NPs showed better performance compared with the case having 0.5-wt% ZnO NPs, but in the meanwhile, it showed the lowest efficiency compared with the other types of NPs. This could be because of their surface charge and suspension instability.\u0000 Results of this work are useful in evaluating the drilling applications using Ca-bentonite-based fluids modified with NPs as an alternative to the commonly used Na-bentonite. In addition, it might help in understanding the NPs/Ca-be","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/191155-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46795037","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}
O. Alade, M. Mahmoud, Amjed Hassan, Mobeen Murtaza, Dhafer Al-Shehri, A. Al-Nakhli, M. Bataweel
A novel approach to exploit heat and pressure generated from the exothermic reactions of the aqueous solution of thermochemical reactants, in removing emulsion blockage induced by oil-based mud (OBM) has been investigated. The proposed technology essentially concerns raising the temperature and pressure of the formation above the kinetic stability of emulsions using thermochemical fluid (TCF). From the batch experiments, to assess the energetics of the thermochemical reaction, it was observed that the temperature of the system could be raised above 170°C at a pressure of 1,600 psi. The chemical can be effectively applied under different operating temperatures Tr = 20, 40, 55, and 100°C without significant effect on the heat and pressure generation. The specific energy per unit volume of the reaction is equivalent to ≈370 MJ/m3 within the operating conditions. OBM was prepared and used as the damaging fluid. A TCF was injected into the damaged core sample for cleaning. Permeability and porosity change of the treated core was tested using nuclear magnetic resonance (NMR) to monitor the efficiency of the TCF injection. Ultimately, injecting 1 pore volume (PV) of the TCF removed approximately 72% of the OBM-based emulsion from the core sample. In addition, permeability of the core sample increased from 120 to 800 md, while the porosity increased from 20 to 21.5% after treatment. Moreover, the pressure profile, observed during the flooding experiment, showed that no precipitation or damage was induced during the TCF flooding. Therefore, it is envisaged that the in-situ heat generation can mitigate the emulsion blockage problem and offer advantages over the existing methods considering environmental friendliness and damage removal efficiency.
{"title":"A Novel Method of Removing Emulsion Blockage after Drilling Operations Using Thermochemical Fluid","authors":"O. Alade, M. Mahmoud, Amjed Hassan, Mobeen Murtaza, Dhafer Al-Shehri, A. Al-Nakhli, M. Bataweel","doi":"10.2118/199315-pa","DOIUrl":"https://doi.org/10.2118/199315-pa","url":null,"abstract":"\u0000 A novel approach to exploit heat and pressure generated from the exothermic reactions of the aqueous solution of thermochemical reactants, in removing emulsion blockage induced by oil-based mud (OBM) has been investigated. The proposed technology essentially concerns raising the temperature and pressure of the formation above the kinetic stability of emulsions using thermochemical fluid (TCF). From the batch experiments, to assess the energetics of the thermochemical reaction, it was observed that the temperature of the system could be raised above 170°C at a pressure of 1,600 psi. The chemical can be effectively applied under different operating temperatures Tr = 20, 40, 55, and 100°C without significant effect on the heat and pressure generation. The specific energy per unit volume of the reaction is equivalent to ≈370 MJ/m3 within the operating conditions. OBM was prepared and used as the damaging fluid. A TCF was injected into the damaged core sample for cleaning. Permeability and porosity change of the treated core was tested using nuclear magnetic resonance (NMR) to monitor the efficiency of the TCF injection. Ultimately, injecting 1 pore volume (PV) of the TCF removed approximately 72% of the OBM-based emulsion from the core sample. In addition, permeability of the core sample increased from 120 to 800 md, while the porosity increased from 20 to 21.5% after treatment. Moreover, the pressure profile, observed during the flooding experiment, showed that no precipitation or damage was induced during the TCF flooding. Therefore, it is envisaged that the in-situ heat generation can mitigate the emulsion blockage problem and offer advantages over the existing methods considering environmental friendliness and damage removal efficiency.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199315-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45530634","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}
S. Tran, A. Habibi, H. Dehghanpour, Mike Hazelton, J. Rose
In this paper, we investigate the change in oil effective permeability (koeff) caused by fracturing-fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF-leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure koeff before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut-in duration, and plug properties on regained permeability values. We found that adding appropriate surfactants in FF not only significantly reduces koeff impairment caused by leakoff, but also improves koeff compared with the original baseline for a low-permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced koeff by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced koeff by only 10%. The observed improvement in regained koeff is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact-angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces koeff by 5 to 10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original koeff before the leakoff process. We observed 28.52 and 64.61% increase in koeff after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases koeff. Under such conditions, extending the shut-in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.
{"title":"Leakoff and Flowback Experiments on Tight Carbonate Core Plugs","authors":"S. Tran, A. Habibi, H. Dehghanpour, Mike Hazelton, J. Rose","doi":"10.2118/199252-PA","DOIUrl":"https://doi.org/10.2118/199252-PA","url":null,"abstract":"\u0000 In this paper, we investigate the change in oil effective permeability (koeff) caused by fracturing-fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF-leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure koeff before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut-in duration, and plug properties on regained permeability values.\u0000 We found that adding appropriate surfactants in FF not only significantly reduces koeff impairment caused by leakoff, but also improves koeff compared with the original baseline for a low-permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced koeff by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced koeff by only 10%. The observed improvement in regained koeff is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact-angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces koeff by 5 to 10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original koeff before the leakoff process. We observed 28.52 and 64.61% increase in koeff after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases koeff. Under such conditions, extending the shut-in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67776296","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}
Emmanuel Akita, Forrest Dyer, S. Drummond, Monica Elkins, P. Duggan, R. Ahmed, F. Florence
The use of drilling automation is accelerating, mostly in the area of rate of penetration (ROP) enhancement. Autonomous directional drilling is now a high focus area for automating drilling operations. The potential impact is immense because 93% of the active rigs in the US are drilling directional or horizontal wells. The 2018–2019 Drilling Systems Automation Technical Section (DSATS)-led international Drillbotics® Student Competition includes automated directional drilling. In this paper, we discuss the detailed design of the winning team. We present the surface equipment, downhole tools, data and control systems, and lessons learned. SPE DSATS organizes the annual Drillbotics competition for university teams to design and develop laboratory-scale drilling rigs. The competition requires each team to create unique downhole sensors to allow automated navigation to drill a directional hole. Student teams have developed new rig configurations to enable several steering methods that include a rotary steering system and small-scale downhole motors with a bent-sub. The most significant challenge was creating a functional downhole motor to fit within a 1.25-in. (3.18 cm) diameter wellbore. Besides technical issues, teams must demonstrate what they have learned about bit-rock interaction and the physics of steering. In addition, they must deal with budgets and funding, procurement and delivery delays, and overall project management. This required an integrated multidisciplinary approach and a major redesign of the rig components. The University of Oklahoma (OU) team made significant changes to its existing rig to drill directional holes. The design change was introduced to optimize the performance of the bottomhole assembly (BHA) and allow directional drilling. The criteria for selecting the BHA was hole size, BHA dynamics, a favorable condition for downhole sensors, precise control of drilling parameters, rig mobility, safety, time constraints, and economic practicality. The result is an autonomous drilling rig that drills a deviated hole toward a defined target through a 2 × 2 × 1-ft (60.96 × 60.96 × 30.48 cm) sandstone block (i.e., rock sample) without human intervention. The rig currently uses a combination of discrete and dynamic modeling from experimentally determined control parameters and closed-loop feedback for well-trajectory control. The novelty of our winning design is in the use of a small-scale cable-driven downhole motor with a bent-sub and quick-connect-type swivel system. This is intended to replicate the action of a mud motor within the limits of the borehole diameter. In this paper, we present details of the rig components, their specifications, and the problems faced during the design, development, and testing. We demonstrate how a laboratory-scale rig can be used to study drilling dysfunctions and challenges. Building a downhole tool to withstand vibrations, water intrusion, magnetic interference, and electromagnetic noise are
{"title":"Directional Drilling Automation Using a Laboratory-Scale Drilling Rig: SPE University Competition","authors":"Emmanuel Akita, Forrest Dyer, S. Drummond, Monica Elkins, P. Duggan, R. Ahmed, F. Florence","doi":"10.2118/199640-pa","DOIUrl":"https://doi.org/10.2118/199640-pa","url":null,"abstract":"\u0000 The use of drilling automation is accelerating, mostly in the area of rate of penetration (ROP) enhancement. Autonomous directional drilling is now a high focus area for automating drilling operations. The potential impact is immense because 93% of the active rigs in the US are drilling directional or horizontal wells. The 2018–2019 Drilling Systems Automation Technical Section (DSATS)-led international Drillbotics® Student Competition includes automated directional drilling. In this paper, we discuss the detailed design of the winning team. We present the surface equipment, downhole tools, data and control systems, and lessons learned.\u0000 SPE DSATS organizes the annual Drillbotics competition for university teams to design and develop laboratory-scale drilling rigs. The competition requires each team to create unique downhole sensors to allow automated navigation to drill a directional hole. Student teams have developed new rig configurations to enable several steering methods that include a rotary steering system and small-scale downhole motors with a bent-sub. The most significant challenge was creating a functional downhole motor to fit within a 1.25-in. (3.18 cm) diameter wellbore. Besides technical issues, teams must demonstrate what they have learned about bit-rock interaction and the physics of steering. In addition, they must deal with budgets and funding, procurement and delivery delays, and overall project management. This required an integrated multidisciplinary approach and a major redesign of the rig components.\u0000 The University of Oklahoma (OU) team made significant changes to its existing rig to drill directional holes. The design change was introduced to optimize the performance of the bottomhole assembly (BHA) and allow directional drilling. The criteria for selecting the BHA was hole size, BHA dynamics, a favorable condition for downhole sensors, precise control of drilling parameters, rig mobility, safety, time constraints, and economic practicality. The result is an autonomous drilling rig that drills a deviated hole toward a defined target through a 2 × 2 × 1-ft (60.96 × 60.96 × 30.48 cm) sandstone block (i.e., rock sample) without human intervention. The rig currently uses a combination of discrete and dynamic modeling from experimentally determined control parameters and closed-loop feedback for well-trajectory control.\u0000 The novelty of our winning design is in the use of a small-scale cable-driven downhole motor with a bent-sub and quick-connect-type swivel system. This is intended to replicate the action of a mud motor within the limits of the borehole diameter. In this paper, we present details of the rig components, their specifications, and the problems faced during the design, development, and testing. We demonstrate how a laboratory-scale rig can be used to study drilling dysfunctions and challenges. Building a downhole tool to withstand vibrations, water intrusion, magnetic interference, and electromagnetic noise are","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"36 1","pages":"1-10"},"PeriodicalIF":1.4,"publicationDate":"2020-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199640-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48242005","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}
Zeeshan Tariq, M. Kamal, M. Mahmoud, S. M. S. Hussain, A. Abdulraheem, Xianmin Zhou
During well completion operations, the wells are killed with specific fluids to control the well. These fluids can invade and damage the formation because of fluid/rock interactions. Fluids such as fresh water, brines, and weighted fluids (e.g., barite weighted, calcite weighted, and bentonite weighted) are used to control the formations during completion operations. These fluids can invade and interact with clays and damage the formation. In addition, these fluids may alter the near-wellbore wettability and make them more oil-wet, thereby affecting the production from these formations. In this work, polyoxyethylene quaternary ammonium gemini surfactants with different types of spacers are proposed as clay swelling additives in completion fluids to mitigate the formation damage in unconventional reservoirs. Adding the new surfactants will maintain the in-situ permeability and avoid the formation damage. The novel gemini surfactants are tested on unconventional tight sandstone formation enriched with high clay content to mitigate the formation damage during well completion. The process involved a complete stabilization of clays using gemini surfactants added in deionized water (DW). Coreflooding experiments were carried out on Scioto sandstone rock samples with an average porosity of 15.6% and average absolute permeability of 0.25 md. Several coreflooding experiments were carried out with different fluids, such as potassium chloride (KCl), sodium chloride (NaCl), and different classes of gemini surfactants. Coreflooding experiments were designed in a way that the cores were preflushed with the subjected fluid and then post-flooded with DW. Results showed that the cores saturated with KCl and NaCl solutions lost permeability significantly when flooded with water while gemini surfactant solutions maintained the same permeability even after being treated with DW. Conditioning with the KCl solution resulted in a 38% reduction of permeability and that with NaCl solution resulted in an 80% reduction of permeability when treated with DW. No significant change of permeability was found for the case of gemini surfactants. This indicates that the synthesized surfactants can be used for well completion operation without any side effects.
{"title":"Polyoxyethylene Quaternary Ammonium Gemini Surfactants as a Completion Fluid Additive to Mitigate Formation Damage","authors":"Zeeshan Tariq, M. Kamal, M. Mahmoud, S. M. S. Hussain, A. Abdulraheem, Xianmin Zhou","doi":"10.2118/201207-pa","DOIUrl":"https://doi.org/10.2118/201207-pa","url":null,"abstract":"\u0000 During well completion operations, the wells are killed with specific fluids to control the well. These fluids can invade and damage the formation because of fluid/rock interactions. Fluids such as fresh water, brines, and weighted fluids (e.g., barite weighted, calcite weighted, and bentonite weighted) are used to control the formations during completion operations. These fluids can invade and interact with clays and damage the formation. In addition, these fluids may alter the near-wellbore wettability and make them more oil-wet, thereby affecting the production from these formations. In this work, polyoxyethylene quaternary ammonium gemini surfactants with different types of spacers are proposed as clay swelling additives in completion fluids to mitigate the formation damage in unconventional reservoirs. Adding the new surfactants will maintain the in-situ permeability and avoid the formation damage. The novel gemini surfactants are tested on unconventional tight sandstone formation enriched with high clay content to mitigate the formation damage during well completion. The process involved a complete stabilization of clays using gemini surfactants added in deionized water (DW). Coreflooding experiments were carried out on Scioto sandstone rock samples with an average porosity of 15.6% and average absolute permeability of 0.25 md. Several coreflooding experiments were carried out with different fluids, such as potassium chloride (KCl), sodium chloride (NaCl), and different classes of gemini surfactants. Coreflooding experiments were designed in a way that the cores were preflushed with the subjected fluid and then post-flooded with DW. Results showed that the cores saturated with KCl and NaCl solutions lost permeability significantly when flooded with water while gemini surfactant solutions maintained the same permeability even after being treated with DW. Conditioning with the KCl solution resulted in a 38% reduction of permeability and that with NaCl solution resulted in an 80% reduction of permeability when treated with DW. No significant change of permeability was found for the case of gemini surfactants. This indicates that the synthesized surfactants can be used for well completion operation without any side effects.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201207-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46061183","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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