Guoqing Liu, T. Zhou, Fengxia Li, Yuanzhao Li, C. Ehlig-Economides
It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture-contact area. However, at present, there is no efficient approach to estimate the fracture surface area for each fracture stage. In this paper, we propose a method to calculate the fracture surface area on the basis of the falloff data after each stage of the main hydraulic-fracture treatment. The created hydraulic fracture closes freely before its surfaces hit the proppant pack, and this process can be recognized in the pressure falloff data and its diagnostic plots. The pressure-decline rate during fracture closure is mainly caused by the fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, with the known leakoff coefficient(s) and fracture-closure stress(es), the total-fracture surface area can be calculated for all stages to meet the requirement of the fluid-leakoff rate. The wellbore-storage effect, friction dissipation, and tip extension dominate the early pressure falloff data. Whereas the transient pressure dominated by friction losses typically lasts approximately 1 minute, the tip extension might end after approximately 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture-closure trend. The fracture-closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late-time unit slope. The behavior of the late unit slope depends on the pressure-decline rate, or correspondingly, to the fluid-leakoff rate. Therefore, the total-fracture surface area can be estimated using hydraulic-fracture design input values for the formation-leakoff coefficient and fracture-closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures—effectively all fracture surfaces contributing to the fluid leakoff. We applied the approach to all stages in a horizontal well that exhibit the fracture-closure behavior. The approach shows some promise as a potential way to estimate fracture surface areas that could allow an early estimate of the expected well performance.
{"title":"Fracture Surface Area Estimation from Hydraulic-Fracture Treatment Pressure Falloff Data","authors":"Guoqing Liu, T. Zhou, Fengxia Li, Yuanzhao Li, C. Ehlig-Economides","doi":"10.2118/199895-pa","DOIUrl":"https://doi.org/10.2118/199895-pa","url":null,"abstract":"\u0000 It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture-contact area. However, at present, there is no efficient approach to estimate the fracture surface area for each fracture stage. In this paper, we propose a method to calculate the fracture surface area on the basis of the falloff data after each stage of the main hydraulic-fracture treatment.\u0000 The created hydraulic fracture closes freely before its surfaces hit the proppant pack, and this process can be recognized in the pressure falloff data and its diagnostic plots. The pressure-decline rate during fracture closure is mainly caused by the fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, with the known leakoff coefficient(s) and fracture-closure stress(es), the total-fracture surface area can be calculated for all stages to meet the requirement of the fluid-leakoff rate.\u0000 The wellbore-storage effect, friction dissipation, and tip extension dominate the early pressure falloff data. Whereas the transient pressure dominated by friction losses typically lasts approximately 1 minute, the tip extension might end after approximately 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture-closure trend. The fracture-closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late-time unit slope. The behavior of the late unit slope depends on the pressure-decline rate, or correspondingly, to the fluid-leakoff rate. Therefore, the total-fracture surface area can be estimated using hydraulic-fracture design input values for the formation-leakoff coefficient and fracture-closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures—effectively all fracture surfaces contributing to the fluid leakoff.\u0000 We applied the approach to all stages in a horizontal well that exhibit the fracture-closure behavior. The approach shows some promise as a potential way to estimate fracture surface areas that could allow an early estimate of the expected well performance.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"438-451"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199895-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42383442","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}
One of the critical issues that occur in many oil and gas wells is the failure of the cement sheath because of debonding from the casing string or from the formation. This results in the formation of microannuli, which can become pathways for fluid migration. Cement shrinkage during setting is regarded as one of the main causes of the formation of microannuli. In this paper, a new class of polymer-based expandable additives in the form of fibers is incorporated into the cement to compensate for shrinkage and thereby help prevent the formation of microannuli in oil and gas wells. The proposed fiber additives are made from shape-memory polymers (SMPs) and expand when exposed to temperatures above a specific value that is, by design, below the downhole temperature of the cemented zone. Fiber expansion occurs after the placement of the cement slurry but before its setting to avoid the inducement of any microfractures. As a result of the expansion of the cement paste, flow channels and fluid migration may significantly decrease while preserving the mechanical properties required for the mechanical integrity of the cement sheath. The bridging effect of fibers across individual microcracks helps control the propagation and coalescence of small fractures. Considering the inert property of the proposed additive, the water-cement ratio and its chemical properties do not need to be revisited. The measured increase in cement ductility makes the cement system more resistant to cracking. The cement expansion, fluid loss, gel strength, compressive strength, ductility, and tensile strength of the samples containing these fibers are examined using destructive and nondestructive methods, as reported here. The proposed class of expandable additives can help operators reach sustainable well integrity by increasing the contact stress at the cement–casing and the cement–formation interfaces to prevent fluid migration and the propagation of cracks.
{"title":"Smart Expandable Fiber Additive To Prevent Formation of Microannuli","authors":"L. Santos, A. D. Taleghani, Guoqiang Li","doi":"10.2118/201100-pa","DOIUrl":"https://doi.org/10.2118/201100-pa","url":null,"abstract":"\u0000 One of the critical issues that occur in many oil and gas wells is the failure of the cement sheath because of debonding from the casing string or from the formation. This results in the formation of microannuli, which can become pathways for fluid migration. Cement shrinkage during setting is regarded as one of the main causes of the formation of microannuli. In this paper, a new class of polymer-based expandable additives in the form of fibers is incorporated into the cement to compensate for shrinkage and thereby help prevent the formation of microannuli in oil and gas wells. The proposed fiber additives are made from shape-memory polymers (SMPs) and expand when exposed to temperatures above a specific value that is, by design, below the downhole temperature of the cemented zone. Fiber expansion occurs after the placement of the cement slurry but before its setting to avoid the inducement of any microfractures. As a result of the expansion of the cement paste, flow channels and fluid migration may significantly decrease while preserving the mechanical properties required for the mechanical integrity of the cement sheath. The bridging effect of fibers across individual microcracks helps control the propagation and coalescence of small fractures. Considering the inert property of the proposed additive, the water-cement ratio and its chemical properties do not need to be revisited. The measured increase in cement ductility makes the cement system more resistant to cracking. The cement expansion, fluid loss, gel strength, compressive strength, ductility, and tensile strength of the samples containing these fibers are examined using destructive and nondestructive methods, as reported here. The proposed class of expandable additives can help operators reach sustainable well integrity by increasing the contact stress at the cement–casing and the cement–formation interfaces to prevent fluid migration and the propagation of cracks.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"490-502"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201100-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43985885","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}
Xunsheng Du, Yuchen Jin, Xuqing Wu, Yu Liu, Xianping Wu, Omar Awan, Joey Roth, K. C. See, Nicolas Tognini, Jiefu Chen, Zhu Han
A real-time deep-learning model is proposed to classify the volume of cuttings from a shale shaker on an offshore drilling rig by analyzing the real-time monitoring video stream. Compared with the traditional video-analytics method, which is time-consuming, the proposed model is able to implement a real-time classification and achieve remarkable accuracy. Our approach is composed of three modules: a multithread engine for decoding/encoding real-time video stream. The video streaming is provided by a modularized service named Rig-Site Virtual Presence, which enables aggregating, storing, transrating/transcoding, streaming, and visualization of video data from the rig; an automatic region-of-interest (ROI) selector. A deep-learning-based object-detection approach is implemented to help the classification model find the region containing the cutting flow; and a convolutional-neural-network-based classification model, which is pretrained with videos collected from previous drilling operations. Normalization and principal-component analyses (PCAs) are conducted before every video frame is fed into the classification model. The classification model classifies each frame into four labels (Extra Heavy, Heavy, Light, and None) in real time. The overall workflow has been tested on a video stream directed from an offshore drilling rig. The video stream has a bitrate of 137 Kbps, approximately 6 frames/sec (fps), and a frame size of 720 × 486. The training process is conducted on an Nvidia GeForce 1070 graphics processing unit (GPU). The testing process (classification inference) runs with only an i5-8500 central processing unit (CPU). Because of the multithreads processing and proper adaptation on the classification model, we are able to handle the entire workflow in real time. This allows us to receive a real-time video stream and display the classification results with encoded frames on the user-side screen at the same time. We use the confusion matrix as the metric to evaluate the performance of our model. Compared with results manually labeled by engineers, our model can achieve highly accurate results in real time without dropping frames.
{"title":"Classifying Cutting Volume at Shale Shakers in Real-Time Via Video Streaming Using Deep-Learning Techniques","authors":"Xunsheng Du, Yuchen Jin, Xuqing Wu, Yu Liu, Xianping Wu, Omar Awan, Joey Roth, K. C. See, Nicolas Tognini, Jiefu Chen, Zhu Han","doi":"10.2118/194084-pa","DOIUrl":"https://doi.org/10.2118/194084-pa","url":null,"abstract":"\u0000 A real-time deep-learning model is proposed to classify the volume of cuttings from a shale shaker on an offshore drilling rig by analyzing the real-time monitoring video stream. Compared with the traditional video-analytics method, which is time-consuming, the proposed model is able to implement a real-time classification and achieve remarkable accuracy. Our approach is composed of three modules: a multithread engine for decoding/encoding real-time video stream. The video streaming is provided by a modularized service named Rig-Site Virtual Presence, which enables aggregating, storing, transrating/transcoding, streaming, and visualization of video data from the rig; an automatic region-of-interest (ROI) selector. A deep-learning-based object-detection approach is implemented to help the classification model find the region containing the cutting flow; and a convolutional-neural-network-based classification model, which is pretrained with videos collected from previous drilling operations. Normalization and principal-component analyses (PCAs) are conducted before every video frame is fed into the classification model. The classification model classifies each frame into four labels (Extra Heavy, Heavy, Light, and None) in real time. The overall workflow has been tested on a video stream directed from an offshore drilling rig. The video stream has a bitrate of 137 Kbps, approximately 6 frames/sec (fps), and a frame size of 720 × 486. The training process is conducted on an Nvidia GeForce 1070 graphics processing unit (GPU). The testing process (classification inference) runs with only an i5-8500 central processing unit (CPU). Because of the multithreads processing and proper adaptation on the classification model, we are able to handle the entire workflow in real time. This allows us to receive a real-time video stream and display the classification results with encoded frames on the user-side screen at the same time. We use the confusion matrix as the metric to evaluate the performance of our model. Compared with results manually labeled by engineers, our model can achieve highly accurate results in real time without dropping frames.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"317-328"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/194084-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43750901","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}
To prevent or minimize problems associated with water coning in horizontal oil producers, inflow control devices (ICDs) are installed along the wellbore to better equalize the toe-to-heel flux. Nozzle-based ICDs are popular because they are easy to model accurately, virtually viscosity independent, and easy to install at the wellsite with many settings. Nozzles can be installed either in the wall of the base-pipe (radial orientation) or in the annulus between the base-pipe and housing (axial orientation). The advantages of the former are smaller maximum-running outer diameter (OD) and no need for a leak-tight, pressure-rated housing. One disadvantage is the high exit velocity that raises concern of erosion or erosion-corrosion of the base-pipe. To overcome this disadvantage, a new nozzle has been developed with a novel geometry that reduces the exit velocity approximately tenfold compared with a conventional nozzle for the same pressure drop and flow rate. Computational fluid dynamics (CFD) was used to first fine tune the design to meet strict erosion-corrosion prevention requirements on the wall shear-stress downstream of the nozzle for both production and (acid) injection directions, and then to develop flow-performance curves for four different nozzle “sizes” that vary in their choking ability, thereby allowing many different settings per joint at the wellsite. Full-scale prototype manufacturing and flow-loop testing were then performed to validate the CFD flow-performance predictions and to demonstrate mechanical integrity and erosion resistance for high-rate production and injection. The results, as presented herein, demonstrate a robust and commercially viable ICD design that has predictable flow performance using CFD, minimizes erosion and erosion-corrosion in either direction, minimizes running OD, simplifies the housing design, and allows easy installation at the wellsite with 34 settings per joint. Also discussed are two new advantages over other ICDs that were not anticipated in the original development.
{"title":"A Systematic Approach to the Design and Development of a New ICD to Minimize Erosion and Erosion-Corrosion","authors":"A. Dikshit, G. Woiceshyn, L. Hagel","doi":"10.2118/197601-pa","DOIUrl":"https://doi.org/10.2118/197601-pa","url":null,"abstract":"\u0000 To prevent or minimize problems associated with water coning in horizontal oil producers, inflow control devices (ICDs) are installed along the wellbore to better equalize the toe-to-heel flux. Nozzle-based ICDs are popular because they are easy to model accurately, virtually viscosity independent, and easy to install at the wellsite with many settings. Nozzles can be installed either in the wall of the base-pipe (radial orientation) or in the annulus between the base-pipe and housing (axial orientation). The advantages of the former are smaller maximum-running outer diameter (OD) and no need for a leak-tight, pressure-rated housing. One disadvantage is the high exit velocity that raises concern of erosion or erosion-corrosion of the base-pipe.\u0000 To overcome this disadvantage, a new nozzle has been developed with a novel geometry that reduces the exit velocity approximately tenfold compared with a conventional nozzle for the same pressure drop and flow rate. Computational fluid dynamics (CFD) was used to first fine tune the design to meet strict erosion-corrosion prevention requirements on the wall shear-stress downstream of the nozzle for both production and (acid) injection directions, and then to develop flow-performance curves for four different nozzle “sizes” that vary in their choking ability, thereby allowing many different settings per joint at the wellsite.\u0000 Full-scale prototype manufacturing and flow-loop testing were then performed to validate the CFD flow-performance predictions and to demonstrate mechanical integrity and erosion resistance for high-rate production and injection. The results, as presented herein, demonstrate a robust and commercially viable ICD design that has predictable flow performance using CFD, minimizes erosion and erosion-corrosion in either direction, minimizes running OD, simplifies the housing design, and allows easy installation at the wellsite with 34 settings per joint. Also discussed are two new advantages over other ICDs that were not anticipated in the original development.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"414-427"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/197601-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42822359","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}
Yuchang Shen, Dingzhou Cao, Kate Ruddy, Luis Felipe Teixeira de Moraes
This paper provides the technical details of developing models to enable automated stage-wise analyses to be implemented within the real-time completion (RTC) analytics system. The models—two of which use machine learning (ML), including the convolutional neural network (CNN) technique (LeCun et al. 1990) and the U-Net architecture (Ronneberger et al. 2015)—detect the hydraulic fracture stage start and end, identify the ball seat operation, and categorize periods of pump rate. These tasks are performed on the basis of the two reliably available measurements of slurry rate and wellhead pressure, which enable the models to run automatically in real time, and also lay the foundation for further hydraulic fracturing advanced analyses. The presented solution provides real-time automated interpretations of hydraulic fracture events, enabling auto-generation of key performance indicator (KPI) reports, dispelling the need for manual labeling, and eliminating human bias and errors. It replaces the manual tasks in the RTC workflow/data pipeline and paves the way for a fully automated RTC system.
本文提供了开发模型的技术细节，以便在实时完井(RTC)分析系统中实现自动阶段分析。这些模型——其中两个使用机器学习(ML)，包括卷积神经网络(CNN)技术(LeCun et al. 1990)和U-Net架构(Ronneberger et al. 2015)——检测水力压裂阶段的开始和结束，识别球座的操作，并对泵速周期进行分类。这些任务是在泥浆速率和井口压力这两个可靠的测量数据的基础上完成的，这使得模型能够实时自动运行，也为进一步的水力压裂高级分析奠定了基础。该解决方案提供了水力压裂事件的实时自动解释，能够自动生成关键性能指标(KPI)报告，消除了人工标记的需要，并消除了人为偏差和错误。它取代了RTC工作流/数据管道中的手动任务，并为全自动RTC系统铺平了道路。
{"title":"Near Real-Time Hydraulic Fracturing Event Recognition Using Deep Learning Methods","authors":"Yuchang Shen, Dingzhou Cao, Kate Ruddy, Luis Felipe Teixeira de Moraes","doi":"10.2118/199738-pa","DOIUrl":"https://doi.org/10.2118/199738-pa","url":null,"abstract":"\u0000 This paper provides the technical details of developing models to enable automated stage-wise analyses to be implemented within the real-time completion (RTC) analytics system. The models—two of which use machine learning (ML), including the convolutional neural network (CNN) technique (LeCun et al. 1990) and the U-Net architecture (Ronneberger et al. 2015)—detect the hydraulic fracture stage start and end, identify the ball seat operation, and categorize periods of pump rate. These tasks are performed on the basis of the two reliably available measurements of slurry rate and wellhead pressure, which enable the models to run automatically in real time, and also lay the foundation for further hydraulic fracturing advanced analyses. The presented solution provides real-time automated interpretations of hydraulic fracture events, enabling auto-generation of key performance indicator (KPI) reports, dispelling the need for manual labeling, and eliminating human bias and errors. It replaces the manual tasks in the RTC workflow/data pipeline and paves the way for a fully automated RTC system.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"478-489"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199738-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45736035","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}
We propose a novel cement additive made of graphite nanoplatelets (GNPs) for improved hydraulic isolation and durability of oil and gas wells. The primary role of the cement sheath, which is zonal isolation, can be significantly affected by the permeability of set cement (hardened cement slurry). On one hand, it is the inherent microstructural defects of cement, including pores and microcracks, that results in the intrinsic permeability of cement, and on the other hand, cracking, micro-annuli, or other flow paths developed through the disturbed cement by connecting the pre-existing microstructural defects determine the equivalent permeability of set cement. The purpose of this research is containing or at least minimizing the intrinsic and developed flow paths through the cementitious matrix with the help of surface-modified GNPs. GNPs possess high surface area to volume ratios. In this study, we focus on the effect of surface-modified GNPs on the overall mechanical properties of both cement slurry and hardened cement slurry affecting the permeability of cement. We present two dispersion methods on the basis of physical and chemical treatments of the surface properties of GNPs. The efficiency of proposed methods on the overall properties of the cement is examined before and after its setting. To mimic downhole conditions, cement slurries are cured at 3,000 psi and 190°F for 24 hours. Also, some experiments were repeated under the pressure and temperature conditions up to 5,160 psi and 126°F, respectively, to examine pumpability and behavior of cement slurry at bottomhole conditions. To examine the role of spatial distribution of GNPs on the hardened cement nanocomposite, samples with different concentrations of GNPs were tested. We investigated the effect of modified GNPs on the unconfined compressive strength (UCS), shear bond strength, thickening time, rheological characteristics, and the free fluid content. We measured zero free fluid at room temperature for different concentrations of GNPs, demonstrating uniform dispersion of nanoparticles within the cement matrix. On the other hand, the squeeze of water out of the lower parts of the cement slurry and its upward migration can develop preferential paths for oil and gas migration. Therefore, eliminating the above-mentioned water separation can enhance cement sealing properties. We found that an optimum 0.2 vol% concentration of acid-functionalized GNPs improves the compressive and the shear bond strength of the prepared cement by approximately 42 and 175% as compared to the plain cement, respectively.
{"title":"Surface-Modified Graphite Nanoplatelets To Enhance Cement Sheath Durability","authors":"M. Tabatabaei, A. D. Taleghani, N. Alem","doi":"10.2118/199897-pa","DOIUrl":"https://doi.org/10.2118/199897-pa","url":null,"abstract":"\u0000 We propose a novel cement additive made of graphite nanoplatelets (GNPs) for improved hydraulic isolation and durability of oil and gas wells. The primary role of the cement sheath, which is zonal isolation, can be significantly affected by the permeability of set cement (hardened cement slurry). On one hand, it is the inherent microstructural defects of cement, including pores and microcracks, that results in the intrinsic permeability of cement, and on the other hand, cracking, micro-annuli, or other flow paths developed through the disturbed cement by connecting the pre-existing microstructural defects determine the equivalent permeability of set cement. The purpose of this research is containing or at least minimizing the intrinsic and developed flow paths through the cementitious matrix with the help of surface-modified GNPs. GNPs possess high surface area to volume ratios. In this study, we focus on the effect of surface-modified GNPs on the overall mechanical properties of both cement slurry and hardened cement slurry affecting the permeability of cement. We present two dispersion methods on the basis of physical and chemical treatments of the surface properties of GNPs. The efficiency of proposed methods on the overall properties of the cement is examined before and after its setting. To mimic downhole conditions, cement slurries are cured at 3,000 psi and 190°F for 24 hours. Also, some experiments were repeated under the pressure and temperature conditions up to 5,160 psi and 126°F, respectively, to examine pumpability and behavior of cement slurry at bottomhole conditions. To examine the role of spatial distribution of GNPs on the hardened cement nanocomposite, samples with different concentrations of GNPs were tested. We investigated the effect of modified GNPs on the unconfined compressive strength (UCS), shear bond strength, thickening time, rheological characteristics, and the free fluid content. We measured zero free fluid at room temperature for different concentrations of GNPs, demonstrating uniform dispersion of nanoparticles within the cement matrix. On the other hand, the squeeze of water out of the lower parts of the cement slurry and its upward migration can develop preferential paths for oil and gas migration. Therefore, eliminating the above-mentioned water separation can enhance cement sealing properties. We found that an optimum 0.2 vol% concentration of acid-functionalized GNPs improves the compressive and the shear bond strength of the prepared cement by approximately 42 and 175% as compared to the plain cement, respectively.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"452-464"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199897-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47747004","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}
Proppant diagenesis occurs when minerals form on the proppant surface and/or around the embedment crater at high-temperature and/or high-stress conditions (Weaver et al. 2005). It has been used recently to explain low fracture conductivity in the field as well as the long-term downward trend of laboratory-measured American Petroleum Institute conductivity data (Liang et al. 2015). However, researchers disagree about the source of such overgrowth minerals and the involvement of proppant in the process. In addition, the diagenesis process has not been investigated in the case of carbonate-rich shale formations. Therefore, the objectives of this paper are to experimentally investigate the proppant diagenesis process during hydraulic fracturing of the Eagle Ford Shale Formation and to determine the role of the proppant in the process. Diagenesis was studied after aging a mixture of proppant and formation samples in deionized water for 3 weeks at 325°F and 300 psia. Outcrop cores of the Eagle Ford Shale Formation were crushed and sieved to 50/100 US-mesh size. The ceramic, sand, and resin-coated-sand (RCS) proppants of 20/40 US-mesh size were tested. The proppant surface was studied for mineral overgrowth and/or dissolution before and after aging using scanning electron microscope (SEM) with energy-dispersive X-ray spectroscopy (EDS). The concentration of the cations leached into the solution was measured by analyzing the supernatant samples using inductively coupled plasma (ICP)/optical-emission spectroscopy, while the sulfate-ion concentration was measured using a spectrophotometer. The proppants and the Eagle Ford Shale Formation samples were analyzed after aging separately at the same conditions to explain the sources of the leached ions and the observed overgrowth and/or precipitated minerals. The Eagle Ford Shale was found to be the source of calcium sulfate and calcium zeolite precipitates because of dissolution/precipitation reactions with water. Only the ceramic proppant was found to induce an additional mineral overgrowth of iron calcium zeolite on its surface. Conversely, the sand and RCS proppants did not encounter any precipitates/overgrowth minerals. These proppants only changed the elemental composition of the precipitated zeolite from the formation/fluid interaction, showing increased silicon and decreased calcium and aluminum concentrations. The proppant dissolution was observed with all types of proppants, as indicated by the presence of silicon ions in the solution after aging. A thermodynamic modeling study was conducted and confirmed the possibility of formation of the observed precipitate and overgrowth minerals at the equilibrium state of the rock and proppant mixture in water. Finally, the breaking and peeling of the phenol formaldehyde resin from the RCS proppant particles at static conditions was observed for the first time (to the best of the authors’ knowledge) using the SEM technique. The study contributes to the unde
{"title":"Proppant Diagenesis in Carbonate-Rich Eagle Ford Shale Fractures","authors":"A. Elsarawy, H. Nasr-El-Din","doi":"10.2118/200481-pa","DOIUrl":"https://doi.org/10.2118/200481-pa","url":null,"abstract":"\u0000 Proppant diagenesis occurs when minerals form on the proppant surface and/or around the embedment crater at high-temperature and/or high-stress conditions (Weaver et al. 2005). It has been used recently to explain low fracture conductivity in the field as well as the long-term downward trend of laboratory-measured American Petroleum Institute conductivity data (Liang et al. 2015). However, researchers disagree about the source of such overgrowth minerals and the involvement of proppant in the process. In addition, the diagenesis process has not been investigated in the case of carbonate-rich shale formations. Therefore, the objectives of this paper are to experimentally investigate the proppant diagenesis process during hydraulic fracturing of the Eagle Ford Shale Formation and to determine the role of the proppant in the process.\u0000 Diagenesis was studied after aging a mixture of proppant and formation samples in deionized water for 3 weeks at 325°F and 300 psia. Outcrop cores of the Eagle Ford Shale Formation were crushed and sieved to 50/100 US-mesh size. The ceramic, sand, and resin-coated-sand (RCS) proppants of 20/40 US-mesh size were tested. The proppant surface was studied for mineral overgrowth and/or dissolution before and after aging using scanning electron microscope (SEM) with energy-dispersive X-ray spectroscopy (EDS). The concentration of the cations leached into the solution was measured by analyzing the supernatant samples using inductively coupled plasma (ICP)/optical-emission spectroscopy, while the sulfate-ion concentration was measured using a spectrophotometer. The proppants and the Eagle Ford Shale Formation samples were analyzed after aging separately at the same conditions to explain the sources of the leached ions and the observed overgrowth and/or precipitated minerals.\u0000 The Eagle Ford Shale was found to be the source of calcium sulfate and calcium zeolite precipitates because of dissolution/precipitation reactions with water. Only the ceramic proppant was found to induce an additional mineral overgrowth of iron calcium zeolite on its surface. Conversely, the sand and RCS proppants did not encounter any precipitates/overgrowth minerals. These proppants only changed the elemental composition of the precipitated zeolite from the formation/fluid interaction, showing increased silicon and decreased calcium and aluminum concentrations. The proppant dissolution was observed with all types of proppants, as indicated by the presence of silicon ions in the solution after aging. A thermodynamic modeling study was conducted and confirmed the possibility of formation of the observed precipitate and overgrowth minerals at the equilibrium state of the rock and proppant mixture in water. Finally, the breaking and peeling of the phenol formaldehyde resin from the RCS proppant particles at static conditions was observed for the first time (to the best of the authors’ knowledge) using the SEM technique.\u0000 The study contributes to the unde","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"465-477"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200481-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43429591","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}
Vahidoddin Fattahpour, Morteza Roostaei, S. A. Hosseini, M. Soroush, Kelly Berner, Mahdi Mahmoudi, Ahmed Al-hadhrami, A. Ghalambor
Most of the test protocols developed to evaluate sand-screen designs were based on scaled-screen test coupons. There have been discussions regarding the reliability of such tests on scaled test coupons. This paper presents the results of tests on wire-wrapped screen (WWS) and slotted liner (SL) test coupons for typical onshore Canada McMurray formation sand. A unique sand control evaluation apparatus has been designed and built to accommodate all common stand-alone screens that are 3.5 in. in diameter and 12 in. in height. This setup provides the capability to have a radial measurement of pressure across the sandpack and screen for three-phase flow. Certain challenges during testing such as establishing uniform radial flow and measuring the differential pressure are outlined. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow directions, flow rates, and flow regimes. It was possible to establish uniform radial flow in both high- and low-permeability sandpacks. However, the establishment of radial flow in sandpacks with very high permeability was challenging. The pressure measurement at different points in the radial direction around the screen indicated a uniform radial flow. Results of the tests on a representative particle size distribution (PSD) from the McMurray Formation on the WWS and SL test coupons with commonly used specifications in the industry (aperture sizes of 0.012, 0.014, and 0.016 in. for WWS and 0.012, 0.016, 0.018, and 0.020 in. for SL) have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to previous tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and SL. Accumulation of fines close to the screen causes significant pore plugging when conservative aperture sizes were used for both WWS and SL. In contrast, using the test coupon with a larger aperture size than the industry practice resulted in excessive sanding. The experiments under linear flow seem more conservative because their results show more produced sand and smaller retained permeability in comparison to the testing under radial flow. This work discusses the significance, procedure, challenges, and early results of physical modeling of stand-alone screens in thermal operation. It also provides insight into the fluid flow, fines migration, clogging, and bridging in the vicinity of sand screens.
{"title":"Experiments with Stand-Alone Sand-Screen Specimens for Thermal Projects","authors":"Vahidoddin Fattahpour, Morteza Roostaei, S. A. Hosseini, M. Soroush, Kelly Berner, Mahdi Mahmoudi, Ahmed Al-hadhrami, A. Ghalambor","doi":"10.2118/199239-PA","DOIUrl":"https://doi.org/10.2118/199239-PA","url":null,"abstract":"\u0000 Most of the test protocols developed to evaluate sand-screen designs were based on scaled-screen test coupons. There have been discussions regarding the reliability of such tests on scaled test coupons. This paper presents the results of tests on wire-wrapped screen (WWS) and slotted liner (SL) test coupons for typical onshore Canada McMurray formation sand.\u0000 A unique sand control evaluation apparatus has been designed and built to accommodate all common stand-alone screens that are 3.5 in. in diameter and 12 in. in height. This setup provides the capability to have a radial measurement of pressure across the sandpack and screen for three-phase flow. Certain challenges during testing such as establishing uniform radial flow and measuring the differential pressure are outlined. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow directions, flow rates, and flow regimes.\u0000 It was possible to establish uniform radial flow in both high- and low-permeability sandpacks. However, the establishment of radial flow in sandpacks with very high permeability was challenging. The pressure measurement at different points in the radial direction around the screen indicated a uniform radial flow. Results of the tests on a representative particle size distribution (PSD) from the McMurray Formation on the WWS and SL test coupons with commonly used specifications in the industry (aperture sizes of 0.012, 0.014, and 0.016 in. for WWS and 0.012, 0.016, 0.018, and 0.020 in. for SL) have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to previous tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and SL. Accumulation of fines close to the screen causes significant pore plugging when conservative aperture sizes were used for both WWS and SL. In contrast, using the test coupon with a larger aperture size than the industry practice resulted in excessive sanding. The experiments under linear flow seem more conservative because their results show more produced sand and smaller retained permeability in comparison to the testing under radial flow.\u0000 This work discusses the significance, procedure, challenges, and early results of physical modeling of stand-alone screens in thermal operation. It also provides insight into the fluid flow, fines migration, clogging, and bridging in the vicinity of sand screens.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199239-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49214937","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}
Reamers are an integral part of deepwater Gulf of Mexico (GOM) drilling and their performance significantly impacts the economics of well construction. This paper presents a novel programmatic approach to model rate of penetration (ROP) for reamers and improve drilling efficiency. Three field implementations demonstrate value added by the reamer drilling optimization (RDO) methodology. Facilitated by user interface panels, the RDO workflow consists of surface and downhole drilling data filtering and visualization, detection of rock formation boundaries, frictional torque (FTRQ) and aggressiveness estimation, ROP modeling with analytical equations and machine learning (ML) algorithms [regression, random forests, support vector machines (SVMs), and neural networks], and optimization of drilling parameters. ROP model coefficients and bit and reamer aggressiveness are dependent on lithology and computed from offset well data. Subsequently, when planning a nearby well, bottomhole assembly (BHA) designs are evaluated on the basis of drilling performance and weight and torque distributions between cutting structures to avoid early reamer wear and dysfunctions. Geometric programming establishes optimal drilling parameter roadmaps according to operational limits, downhole tool ratings, rig equipment power constraints, and adequate hole cleaning. Separate ROP models are trained for reamer-controlled and bit-controlled ROP zones, defined by the proportion of surface weight on bit (WOB) applied at the reamer, in every rock formation. This novel concept enables ROP prediction with the appropriate model for each well segment depending on which cutting structure limits drilling speed. In the first of the three RDO applications with field data from deepwater GOM wells, optimal bit-reamer distances are determined by analyzing reamer weight load in uniform salt sections. Next, ROP modeling for the addition or removal of a reamer from the BHA is used in contrasting well designs to conceivably alleviate a USD 16 million casing inventory surplus. Finally, active optimization constraints are investigated to reveal drilling performance limiters, justifying equipment upgrades for a future deepwater GOM well. The proposed innovative workflow and methodology apply to any drilling optimization scenario. They benefit the practicing engineer interested in drilling performance optimization by providing insights on how different cutting structure sizes affect ROP behavior and ultimately aiding in the selection of appropriate bit and reamer diameters and optimal operational parameters.
{"title":"Enhancing Reamer Drilling Performance in Deepwater Gulf of Mexico Wells","authors":"Cesar Soares, M. Armenta, Neilkunal Panchal","doi":"10.2118/200480-pa","DOIUrl":"https://doi.org/10.2118/200480-pa","url":null,"abstract":"\u0000 Reamers are an integral part of deepwater Gulf of Mexico (GOM) drilling and their performance significantly impacts the economics of well construction. This paper presents a novel programmatic approach to model rate of penetration (ROP) for reamers and improve drilling efficiency. Three field implementations demonstrate value added by the reamer drilling optimization (RDO) methodology.\u0000 Facilitated by user interface panels, the RDO workflow consists of surface and downhole drilling data filtering and visualization, detection of rock formation boundaries, frictional torque (FTRQ) and aggressiveness estimation, ROP modeling with analytical equations and machine learning (ML) algorithms [regression, random forests, support vector machines (SVMs), and neural networks], and optimization of drilling parameters. ROP model coefficients and bit and reamer aggressiveness are dependent on lithology and computed from offset well data. Subsequently, when planning a nearby well, bottomhole assembly (BHA) designs are evaluated on the basis of drilling performance and weight and torque distributions between cutting structures to avoid early reamer wear and dysfunctions. Geometric programming establishes optimal drilling parameter roadmaps according to operational limits, downhole tool ratings, rig equipment power constraints, and adequate hole cleaning.\u0000 Separate ROP models are trained for reamer-controlled and bit-controlled ROP zones, defined by the proportion of surface weight on bit (WOB) applied at the reamer, in every rock formation. This novel concept enables ROP prediction with the appropriate model for each well segment depending on which cutting structure limits drilling speed. In the first of the three RDO applications with field data from deepwater GOM wells, optimal bit-reamer distances are determined by analyzing reamer weight load in uniform salt sections. Next, ROP modeling for the addition or removal of a reamer from the BHA is used in contrasting well designs to conceivably alleviate a USD 16 million casing inventory surplus. Finally, active optimization constraints are investigated to reveal drilling performance limiters, justifying equipment upgrades for a future deepwater GOM well.\u0000 The proposed innovative workflow and methodology apply to any drilling optimization scenario. They benefit the practicing engineer interested in drilling performance optimization by providing insights on how different cutting structure sizes affect ROP behavior and ultimately aiding in the selection of appropriate bit and reamer diameters and optimal operational parameters.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"35 1","pages":"329-356"},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200480-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41714434","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}
This paper presents the application of reliability-based approaches to the survival design of critical wells, in particular deepwater and high-pressure/high-temperature (HPHT) wells. First, the concept of survival design is discussed. As in other structural design disciplines, a distinction is made between operating (service) loads and survival loads. In essence, survival loads are extreme magnitude loads with low probability of occurrence, but with potentially severe consequences if failure occurs. Survival scenarios falling into this category in critical wells are presented. It is shown that the current practice of using standard working stress design (WSD) approaches for survival scenarios, even with reduced design factors, fails to quantify the risk of failure and can lead to design practices and outcomes that are not risk consistent or optimal. Reliability-based design (RBD) explicitly quantifies the risk of failure of a given design. This paper describes RBD and the prevalence of its use in other structural design codes and shows how it can be used for survival design in critical wells. It is argued that a probabilistic approach in which a deterministic load at its extreme survival magnitude is compared with stochastic strength (from data on strength parameters) is a rational approach to survival load design. Regardless of how low the probability of occurrence of the load is at its survival magnitude, well integrity is demonstrated by assuming that such a load occurs. The method can be implemented by constructing resistance distributions using limit state equations such as the Klever-Stewart rupture limit, and the Klever-Tamano collapse limit equations (API TR 5C3/ISO/TR 10400). Statistical strength parameter data can be obtained from API TR 5C3 (ISO/TR 10400), manufacturer reports, or direct material and dimensional measurements. Statistical approaches to constructing such distributions are presented. The deterministic survival load is then compared with this resistance distribution, and a probability of failure is calculated. This probability of failure then becomes the basis for design. The goal in survival design is to demonstrate survival rather than continued operability. On the basis of this, acceptable probabilities of failure for typical survival loads are recommended and contextualized with other design codes. Particular attention is given to worst case discharge (WCD) and well containment loads, which have become design-dictating survival loads in many deepwater well designs and are driving design choices of tubulars and connections. The applicability of this approach to connection selection and brittle failure is also demonstrated. A deepwater well example is presented to illustrate using the approach. It is shown that designing to an acceptable probability of failure leads to more robust and risk-consistent designs in critical wells. Furthermore, such an approach allows designers to focus on the specific design or well cons
{"title":"A Reliability-Based Approach for Survival Design in Deepwater and High-Pressure/High-Temperature Wells","authors":"P. Suryanarayana, D. Lewis","doi":"10.2118/178907-pa","DOIUrl":"https://doi.org/10.2118/178907-pa","url":null,"abstract":"\u0000 This paper presents the application of reliability-based approaches to the survival design of critical wells, in particular deepwater and high-pressure/high-temperature (HPHT) wells. First, the concept of survival design is discussed. As in other structural design disciplines, a distinction is made between operating (service) loads and survival loads. In essence, survival loads are extreme magnitude loads with low probability of occurrence, but with potentially severe consequences if failure occurs. Survival scenarios falling into this category in critical wells are presented. It is shown that the current practice of using standard working stress design (WSD) approaches for survival scenarios, even with reduced design factors, fails to quantify the risk of failure and can lead to design practices and outcomes that are not risk consistent or optimal.\u0000 Reliability-based design (RBD) explicitly quantifies the risk of failure of a given design. This paper describes RBD and the prevalence of its use in other structural design codes and shows how it can be used for survival design in critical wells. It is argued that a probabilistic approach in which a deterministic load at its extreme survival magnitude is compared with stochastic strength (from data on strength parameters) is a rational approach to survival load design. Regardless of how low the probability of occurrence of the load is at its survival magnitude, well integrity is demonstrated by assuming that such a load occurs. The method can be implemented by constructing resistance distributions using limit state equations such as the Klever-Stewart rupture limit, and the Klever-Tamano collapse limit equations (API TR 5C3/ISO/TR 10400). Statistical strength parameter data can be obtained from API TR 5C3 (ISO/TR 10400), manufacturer reports, or direct material and dimensional measurements. Statistical approaches to constructing such distributions are presented. The deterministic survival load is then compared with this resistance distribution, and a probability of failure is calculated. This probability of failure then becomes the basis for design.\u0000 The goal in survival design is to demonstrate survival rather than continued operability. On the basis of this, acceptable probabilities of failure for typical survival loads are recommended and contextualized with other design codes. Particular attention is given to worst case discharge (WCD) and well containment loads, which have become design-dictating survival loads in many deepwater well designs and are driving design choices of tubulars and connections. The applicability of this approach to connection selection and brittle failure is also demonstrated. A deepwater well example is presented to illustrate using the approach. It is shown that designing to an acceptable probability of failure leads to more robust and risk-consistent designs in critical wells. Furthermore, such an approach allows designers to focus on the specific design or well cons","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/10.2118/178907-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42118501","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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