Ashley Johnson, A. Mäkinen, Syed Fahim, Y. Arevalo
Reducing our operating carbon dioxide emissions is a critical step in mitigating the impact of our well construction operations. In order to bring a quantifiable benefit, we need a starting point. We need to measure our current emissions and identify the main drivers for the footprint. We can then identify best practices to reduce the impact and quantify how changing our drilling systems can reduce the CO2 generation. Analysing the data available from two modern rigs we have measured the CO2 released for drilling different wells in different basins. We have also segmented the emissions by the rig systems using the power they consume. We show that the mud pumps are the biggest culprit for the CO2 release. The top drive draws less power; and while the draw works have a very high-power capacity, they only draw this for a very short period so overall their footprint is much less significant. In order to make this work relevant for more than a small number of high specification modern rigs, we have built and validated an emissions model. Whereby we can calculate the CO2 released from measurements of the surface drilling parameters. As such, in real time we can generate a carbon emissions log quantifying the footprint and the split to major systems on any rig where we have access to these surface data. Using the same model, integrated with our well planning processes, we can accurately predict the footprint from a particular well construction scenario and quantify the benefits which changes to the BHA, the drilling practices or the well design would bring. In the same manner, based solely on the surface drilling data, we can compare the environmental impact of all of our drilling operations at the same granularity we record the rig data. This lets us identify opportunities to reduce emissions and less efficient operations rapidly.
{"title":"Quantification of Our Carbon Footprint while Drilling","authors":"Ashley Johnson, A. Mäkinen, Syed Fahim, Y. Arevalo","doi":"10.2523/iptc-22528-ea","DOIUrl":"https://doi.org/10.2523/iptc-22528-ea","url":null,"abstract":"\u0000 Reducing our operating carbon dioxide emissions is a critical step in mitigating the impact of our well construction operations. In order to bring a quantifiable benefit, we need a starting point. We need to measure our current emissions and identify the main drivers for the footprint. We can then identify best practices to reduce the impact and quantify how changing our drilling systems can reduce the CO2 generation.\u0000 Analysing the data available from two modern rigs we have measured the CO2 released for drilling different wells in different basins. We have also segmented the emissions by the rig systems using the power they consume. We show that the mud pumps are the biggest culprit for the CO2 release. The top drive draws less power; and while the draw works have a very high-power capacity, they only draw this for a very short period so overall their footprint is much less significant.\u0000 In order to make this work relevant for more than a small number of high specification modern rigs, we have built and validated an emissions model. Whereby we can calculate the CO2 released from measurements of the surface drilling parameters. As such, in real time we can generate a carbon emissions log quantifying the footprint and the split to major systems on any rig where we have access to these surface data.\u0000 Using the same model, integrated with our well planning processes, we can accurately predict the footprint from a particular well construction scenario and quantify the benefits which changes to the BHA, the drilling practices or the well design would bring. In the same manner, based solely on the surface drilling data, we can compare the environmental impact of all of our drilling operations at the same granularity we record the rig data. This lets us identify opportunities to reduce emissions and less efficient operations rapidly.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73634850","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ya Tian, Fu-jian Zhou, M. Aljawad, R. Weijermars, Mingjiang Wu, Ben Li
This study proposes an innovative crushing rate evaluation method for micro-proppants by analyzing hydraulic crushing and steel crushing rates. The effectiveness of using micro-proppants to increase the drainage area of the micro-fractures network was also proved. Our results show that for micro-proppants, there occur two types of crushing evolution during the fracturing process. Under a load of 70 MPa, the hydraulic crushing rate is about 20%, while the steel crushing rate is more than 60%. The critical closure stress of micro-proppants is 50 MPa, which can be used to depths up to 4,200 m. Numerical simulation results showed that due to the presence of micro-proppants, the effectively propped area of the fracture network would sharply increase, accompanied by an over 40% increase in the initial hydrocarbon production rate. The later, steady production period will show a sustained increase of more than 20%.
{"title":"Laboratory Tests and Well Rate Models of Crushed Micro-Proppants to Improve Conductivity of Hydraulic Microfractures","authors":"Ya Tian, Fu-jian Zhou, M. Aljawad, R. Weijermars, Mingjiang Wu, Ben Li","doi":"10.2523/iptc-22209-ms","DOIUrl":"https://doi.org/10.2523/iptc-22209-ms","url":null,"abstract":"\u0000 This study proposes an innovative crushing rate evaluation method for micro-proppants by analyzing hydraulic crushing and steel crushing rates. The effectiveness of using micro-proppants to increase the drainage area of the micro-fractures network was also proved. Our results show that for micro-proppants, there occur two types of crushing evolution during the fracturing process. Under a load of 70 MPa, the hydraulic crushing rate is about 20%, while the steel crushing rate is more than 60%. The critical closure stress of micro-proppants is 50 MPa, which can be used to depths up to 4,200 m. Numerical simulation results showed that due to the presence of micro-proppants, the effectively propped area of the fracture network would sharply increase, accompanied by an over 40% increase in the initial hydrocarbon production rate. The later, steady production period will show a sustained increase of more than 20%.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73822872","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Vorobiev, Vladimir Vorobyev, S. Lukin, S. Zhigulskiy, I. Chebyshev
Biot's coefficient is one of the key parameters in estimating effective stresses, leading to understanding of the three stresses spatial distribution, namely vertical, minimum and maximum horizontal. Ultimately, these stresses shape up the behavior of a geomechanics model (either in 3D or in 1D). Thus, the robustness of any geomechanics model significantly depends on the precision of Biot's coefficient estimation. The proposed technique allows evaluating isotropic and anisotropic Biot's coefficients based on the log responses independent of the geological environment. The methodology is based on elastic moduli-minimization. In isotropic case, Bulk rock frame and Bulk rock grain moduli minimization produce the best fit to the measured Density, DTP and DTS. Then, isotropic Biot's coefficient can be computed directly. In the case of anisotropy, additional control on lamination is required. This can be achieved by comparing estimated laminated and dispersed clay volumes based on the anisotropic rock-physics model and derived from the Thomas-Stieber plot or any alternative lamination analysis technique. Anisotropy modeling allows to produce five independent VTI elastic moduli and as a result to compute anisotropic Biot's coefficient. The methodology has been tested in several fields: clastic (Western Siberia, Norwegian offshore, Argentina unconventional) and carbonates (Brazil, Middle East, North Sea chalks). It produces reliable results in all cases. This study shows good agreement of the Biot's coefficient computed from the proposed methodology with measurements of core-based Biot's coefficients. In practice, core-based Biot's coefficient measurements are rarely available and quite often done on a few samples, taken in the reservoir section only. The proposed methodology allows reliable estimates of Biot's coefficient for the entire wellbore section, where density and sonic logs are available. It utilizes a minimization technique instead of using geomechanics correlations. Thus, it is applicable for any rocks and geological settings and is not bounded to the area or formation compared to correlations specific to the particular formation. The novelty of the method is in the process of elastic-moduli minimization based on logs and allows direct extraction of the Biot's coefficient. Previous works were either concentrating on principles of the laboratory Biot's coefficient measurements or focusing on the correlations derived from core tests. Correlation derivation requires a significant number of core tests conducted for the same geological settings. However, the proposed methodology requires a few core samples for Q.C. purposes only.
{"title":"Evaluation of Biot's Coefficient Using Sonic Logs and Elastic Moduli Minimization","authors":"S. Vorobiev, Vladimir Vorobyev, S. Lukin, S. Zhigulskiy, I. Chebyshev","doi":"10.2523/iptc-22325-ms","DOIUrl":"https://doi.org/10.2523/iptc-22325-ms","url":null,"abstract":"\u0000 Biot's coefficient is one of the key parameters in estimating effective stresses, leading to understanding of the three stresses spatial distribution, namely vertical, minimum and maximum horizontal. Ultimately, these stresses shape up the behavior of a geomechanics model (either in 3D or in 1D). Thus, the robustness of any geomechanics model significantly depends on the precision of Biot's coefficient estimation. The proposed technique allows evaluating isotropic and anisotropic Biot's coefficients based on the log responses independent of the geological environment.\u0000 The methodology is based on elastic moduli-minimization. In isotropic case, Bulk rock frame and Bulk rock grain moduli minimization produce the best fit to the measured Density, DTP and DTS. Then, isotropic Biot's coefficient can be computed directly. In the case of anisotropy, additional control on lamination is required. This can be achieved by comparing estimated laminated and dispersed clay volumes based on the anisotropic rock-physics model and derived from the Thomas-Stieber plot or any alternative lamination analysis technique. Anisotropy modeling allows to produce five independent VTI elastic moduli and as a result to compute anisotropic Biot's coefficient.\u0000 The methodology has been tested in several fields: clastic (Western Siberia, Norwegian offshore, Argentina unconventional) and carbonates (Brazil, Middle East, North Sea chalks). It produces reliable results in all cases. This study shows good agreement of the Biot's coefficient computed from the proposed methodology with measurements of core-based Biot's coefficients. In practice, core-based Biot's coefficient measurements are rarely available and quite often done on a few samples, taken in the reservoir section only. The proposed methodology allows reliable estimates of Biot's coefficient for the entire wellbore section, where density and sonic logs are available. It utilizes a minimization technique instead of using geomechanics correlations. Thus, it is applicable for any rocks and geological settings and is not bounded to the area or formation compared to correlations specific to the particular formation.\u0000 The novelty of the method is in the process of elastic-moduli minimization based on logs and allows direct extraction of the Biot's coefficient. Previous works were either concentrating on principles of the laboratory Biot's coefficient measurements or focusing on the correlations derived from core tests. Correlation derivation requires a significant number of core tests conducted for the same geological settings. However, the proposed methodology requires a few core samples for Q.C. purposes only.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75493991","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper describes the use of a physical solvent, propylene carbonate, to remove CO2 from existing or new build-Hydrogen Plants (SMR, ATR, or POX) and recovery of that CO2 for carbon sequestration or EOR to produce Blue Hydrogen. The treatment unit is located downstream of the shift reactors and upstream of a conventional PSA. The captured CO2 stream will have sufficient CO2 purity for sequestion or other industrial uses. This paper presents CO2 removal levels, captured CO2 purity, total utilities consumption and other benefits of the process. The results will be compared to a conventional amine-based CO2 removal system.
{"title":"A Physical Solvent Approach to Blue Hydrogen","authors":"Mike Gilmartin, C. Graham, Ghaith Aljazzar","doi":"10.2523/iptc-22330-ea","DOIUrl":"https://doi.org/10.2523/iptc-22330-ea","url":null,"abstract":"\u0000 This paper describes the use of a physical solvent, propylene carbonate, to remove CO2 from existing or new build-Hydrogen Plants (SMR, ATR, or POX) and recovery of that CO2 for carbon sequestration or EOR to produce Blue Hydrogen. The treatment unit is located downstream of the shift reactors and upstream of a conventional PSA. The captured CO2 stream will have sufficient CO2 purity for sequestion or other industrial uses. This paper presents CO2 removal levels, captured CO2 purity, total utilities consumption and other benefits of the process. The results will be compared to a conventional amine-based CO2 removal system.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76572914","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. H. Badar, Syed Sadaqat S. Ali, Yasser Ghamdi, Muhammad Khan
Seismic interpretation is a key task and foundation for hydrocarbons exploration and field development. Seismic data provides coverage from basin to reservoir scale workflows for identifying regional structures, delineate prospects and calculate rock properties. In this paper we discuss the evolution of seismic structural and stratigraphic interpretation through key technological milestones. This covers a broad spectrum, from conventional 2D interpretation methodologies to processes that help us see below the quarter wavelength resolution. We have captured the workflows that are redefining seismic interpretation landscape. These include wavelet based interpretation, multi-attribute analysis, spectral decomposition, geobody extraction, cognitive interpretation, pre-stack interpretation and applications of machine learning to seismic interpretation. We also present advancements in the computing environment that provided a paradigm shift in interpretation workflows. We demonstrate how the conventional workflows migrate into interactive and iterative processes at user desktops with multi-domain data access and analysis. We also discuss the hardware enablers such as high end desktop central processing units (CPUs) powered with graphic processing units (GPUs) that were not possible a few years ago. The advancement in technology comes with increased expectation from geoscientists. The workflow that were once considered in specialist domain are now being practiced by early to mid-career professionals. This is made possible with huge strides both in hardware infrastructure powered by clusters and cloud and software technologies. The cognitive interpretation, big data analysis, artificial intelligence, machine and deep learning workflows are becoming embedded components of seismic interpretation. We observe the advancement in 6 key areas that are responsible in transforming the seismic interpretation. The computing technology to handle large datasets and process at much faster pace, visualization technology leading to cognitive interpretation, ability to integrate multidisciplinary and multiscale data, interpretive processing utilizing pre-stack data, global interpretation methods leading to relative geologic time model (RGT) allowing the efficient use of every sample of seismic cube and ability to integrate the machine and deep learning processes that augment seismic interpretation. We present examples of using these technologies to maximize the benefit from seismic interpretation. The future of geoscience data storage as common opensource data format and applying the AI at scale offered through deploying enterprise AI platform is also discussed. The advantages of adopting the modern workflows driven by technology are helping in developing a shared integrated earth modelling environment. This allows the multi-disciplinary teams to use pre and post stack seismic data, rock properties, reservoir models and real-time drilling updates to make informed de
{"title":"Seismic Interpretation Technologies Advancement and its Impact on Interactive and Iterative Interpretation Workflows","authors":"M. H. Badar, Syed Sadaqat S. Ali, Yasser Ghamdi, Muhammad Khan","doi":"10.2523/iptc-21920-ea","DOIUrl":"https://doi.org/10.2523/iptc-21920-ea","url":null,"abstract":"\u0000 Seismic interpretation is a key task and foundation for hydrocarbons exploration and field development. Seismic data provides coverage from basin to reservoir scale workflows for identifying regional structures, delineate prospects and calculate rock properties. In this paper we discuss the evolution of seismic structural and stratigraphic interpretation through key technological milestones. This covers a broad spectrum, from conventional 2D interpretation methodologies to processes that help us see below the quarter wavelength resolution.\u0000 We have captured the workflows that are redefining seismic interpretation landscape. These include wavelet based interpretation, multi-attribute analysis, spectral decomposition, geobody extraction, cognitive interpretation, pre-stack interpretation and applications of machine learning to seismic interpretation. We also present advancements in the computing environment that provided a paradigm shift in interpretation workflows. We demonstrate how the conventional workflows migrate into interactive and iterative processes at user desktops with multi-domain data access and analysis. We also discuss the hardware enablers such as high end desktop central processing units (CPUs) powered with graphic processing units (GPUs) that were not possible a few years ago.\u0000 The advancement in technology comes with increased expectation from geoscientists. The workflow that were once considered in specialist domain are now being practiced by early to mid-career professionals. This is made possible with huge strides both in hardware infrastructure powered by clusters and cloud and software technologies. The cognitive interpretation, big data analysis, artificial intelligence, machine and deep learning workflows are becoming embedded components of seismic interpretation. We observe the advancement in 6 key areas that are responsible in transforming the seismic interpretation. The computing technology to handle large datasets and process at much faster pace, visualization technology leading to cognitive interpretation, ability to integrate multidisciplinary and multiscale data, interpretive processing utilizing pre-stack data, global interpretation methods leading to relative geologic time model (RGT) allowing the efficient use of every sample of seismic cube and ability to integrate the machine and deep learning processes that augment seismic interpretation. We present examples of using these technologies to maximize the benefit from seismic interpretation. The future of geoscience data storage as common opensource data format and applying the AI at scale offered through deploying enterprise AI platform is also discussed.\u0000 The advantages of adopting the modern workflows driven by technology are helping in developing a shared integrated earth modelling environment. This allows the multi-disciplinary teams to use pre and post stack seismic data, rock properties, reservoir models and real-time drilling updates to make informed de","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78139742","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nasser M. Al-Hajri, S. Gilani, Mohammed C. Saloojee, Mohammed A. Atwi, Akram R. Barghouti
The digitally transformative Upstream Well Integrity Surveillance Excellence (U-WISE) software technology was built. U-WISE data driven processes provide a risk-based financial optimization model inspired by IR 4.0's big data analytics. The objective of U-WISE software technology is to continuously optimize financial resources related to the frequency of conducting well integrity surveys. The new technology balances the calculated well integrity risk with the associated financial impact for the entire integrity surveillance program. U-WISE software technology application constitute a paradigm shift in the well integrity surveillance portfolio of oilfield operators. The U-WISE software technology development was started by analyzing thousands of historical well integrity data. The big data analytics optimization schemes embedded in U-WISE software technology was initially developed based on a total of 38,104 case studies from different well and fluid types. U-WISE software technology runs artificial-intelligence based queries to collect health and defect data pertaining to integrity surveys. The data were conditioned for the analytics by recording health and defect time events. Then, the data were run through statistical schemes to obtain probability of health, defect, and overall probability of failure. The models’ product is a risk of failure percentage specific to a survey and well type, representative of all conditions. The risk of failure percentages are used to run surveillance optimization scenarios and quantify the financial impacts from such optimization. U-WISE software technology continues to perform the optimization on real-time data based on new field collected data. The overall combined optimization results from applying the U-WISE software technology are substantial annual savings. There are other tangible benefits to this optimization in availing more crude for production by reducing well shut-in time for integrity surveys. The revamped well integrity frequencies based on the IR 4.0 optimization furnished by U-WISE software technology serves as an industry benchmark for proficient and fiscally-responsible asset integrity monitoring. The reliability of wells integrity is now greatly improved with the updated procedures, technologies, and integrity standards set forth by the IR 4.0 based U-WISE software and resulting instruction manual. Wells’ production is now more efficient and sustained based on the optimized well surveillance shut-in times. Safety and integrity of the wells are now quantified and balanced via the new U-WISE software technology and kept at the required tolerable risk levels. Wells intact integrity strengthens environmental protection by reducing and eliminating undesirable well integrity events such as well downhole or surface leaks and the resulting aquifer and air contamination. Well integrity surveys were performed based on best oilfield practices. With the abundance of historical data, it became possible to
{"title":"The Digitally Transformative U-WISE Software Technology","authors":"Nasser M. Al-Hajri, S. Gilani, Mohammed C. Saloojee, Mohammed A. Atwi, Akram R. Barghouti","doi":"10.2523/iptc-22110-ms","DOIUrl":"https://doi.org/10.2523/iptc-22110-ms","url":null,"abstract":"\u0000 The digitally transformative Upstream Well Integrity Surveillance Excellence (U-WISE) software technology was built. U-WISE data driven processes provide a risk-based financial optimization model inspired by IR 4.0's big data analytics. The objective of U-WISE software technology is to continuously optimize financial resources related to the frequency of conducting well integrity surveys. The new technology balances the calculated well integrity risk with the associated financial impact for the entire integrity surveillance program. U-WISE software technology application constitute a paradigm shift in the well integrity surveillance portfolio of oilfield operators. The U-WISE software technology development was started by analyzing thousands of historical well integrity data. The big data analytics optimization schemes embedded in U-WISE software technology was initially developed based on a total of 38,104 case studies from different well and fluid types. U-WISE software technology runs artificial-intelligence based queries to collect health and defect data pertaining to integrity surveys. The data were conditioned for the analytics by recording health and defect time events. Then, the data were run through statistical schemes to obtain probability of health, defect, and overall probability of failure. The models’ product is a risk of failure percentage specific to a survey and well type, representative of all conditions. The risk of failure percentages are used to run surveillance optimization scenarios and quantify the financial impacts from such optimization. U-WISE software technology continues to perform the optimization on real-time data based on new field collected data. The overall combined optimization results from applying the U-WISE software technology are substantial annual savings. There are other tangible benefits to this optimization in availing more crude for production by reducing well shut-in time for integrity surveys. The revamped well integrity frequencies based on the IR 4.0 optimization furnished by U-WISE software technology serves as an industry benchmark for proficient and fiscally-responsible asset integrity monitoring. The reliability of wells integrity is now greatly improved with the updated procedures, technologies, and integrity standards set forth by the IR 4.0 based U-WISE software and resulting instruction manual. Wells’ production is now more efficient and sustained based on the optimized well surveillance shut-in times. Safety and integrity of the wells are now quantified and balanced via the new U-WISE software technology and kept at the required tolerable risk levels. Wells intact integrity strengthens environmental protection by reducing and eliminating undesirable well integrity events such as well downhole or surface leaks and the resulting aquifer and air contamination. Well integrity surveys were performed based on best oilfield practices. With the abundance of historical data, it became possible to ","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76663832","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abu Roash F Member (ARF) is a carbonate formation extended all over the Western Desert in Egypt, ARF has good lateral continuity in all western desert basins but has very poor connectivity and very low permeability. it can be considered as an example of unconventional reservoir. This work aims to evaluate the reservoir quality of Abu Roash "F" Member and compare with the unconventional play commercial developed all over the world. in this study, the key parameters to define reservoir quality; include mineralogy, porosity, water saturation, permeability, organic matter content, Kerogen type and thermal maturity has been investigated. More than 30 Rock-Eval pyrolysis samples from different fields where ARF at significantly different level has been used to evaluate and understand ARF geochemical reservoir quality. On the other side, core and well log data from different fields at different level has been inspected and integrated to evaluate ARF mineralogy, porosity, permeability, water saturation, and identify Potential sweet spots. The results of Rock-Eval analysis show that most of the investigated samples have the total organic carbon content (TOC) values between 1.6 and 6.63 wt% indicating good to very good source rocks and the pyrolysis Yield (PY) ranged from 6 to 20 indicating good to very good potential generation. Based on Tmax and Hydrogen index (HI), the deepest well samples have Tmax values in the range of 435 and 441°C and Hydrogen index (HI) values in the range of 311 to 570 indicating that the organic matter has reached the early to intermediate stages of thermal maturity with dominate kerogen type I-II. While the shallower well samples have Tmax values in the range of 421 and 430°C and Hydrogen index (HI) values in the range of 127 to 687 indicating that the organic matter immature with mixed kerogen type II-III. Petrophysical results supporting that ARF is a carbonate rock deposit under marine conditions and has mixed layer clay (montomonlionite, Kolonite and illite). Numerous techniques to estimate ARF permeability from wireline logs have been investigated, using the available core data porosity permeability relationship has been established. Moreover, the results of petrophysical analysis indicate that Lucia class 3 permeability has good math with core permeability. So, Lucia class 3 permeability can be used to estimate ARF permeability using the calculated effective porosity from well log data. Generally, the results of geochemical and petrophysical evaluation of this study show that ARF has very good reservoir quality comparing with the most of commercially developed unconventional resources all over the world. Moreover, the results show that ARF has a similarity with Eagle Ford Shale in terms of Age, mineralogy, pressure, depth, thickness, and TOC which reflect the potentiality of ARF commercial development.
Abu Roash F Member (ARF)是一套覆盖埃及西部沙漠的碳酸盐岩地层，在所有西部沙漠盆地中都具有良好的横向连续性，但连通性很差，渗透率很低。它可以看作是非常规油藏的一个例子。本文旨在评价Abu Roash“F”段储层质量，并与世界上已开发的非常规油层进行对比。在本研究中，定义储层质量的关键参数;包括矿物学、孔隙度、含水饱和度、渗透率、有机质含量、干酪根类型和热成熟度。利用30余份不同地区ARF水平差异较大的岩石热解样品，对ARF地球化学储层质量进行了评价和认识。另一方面，对不同油田不同级别的岩心和测井数据进行了检查和整合，以评估ARF的矿物学、孔隙度、渗透率、含水饱和度，并识别潜在的甜点。Rock-Eval分析结果表明，大部分样品的总有机碳含量(TOC)在1.6 ~ 6.63 wt%之间，表明烃源岩良好~极好，热解产率(PY)在6 ~ 20之间，表明生烃潜力良好~极好。基于Tmax和氢指数(HI)分析，最深井样品的Tmax值在435 ~ 441℃之间，氢指数(HI)值在311 ~ 570℃之间，表明有机质处于热成熟的早中期，以I-II型干酪根为主。浅井样品Tmax值在421 ~ 430℃之间，氢指数(HI)值在127 ~ 687之间，表明有机质发育不成熟，为ⅱ~ⅲ型混合干酪根。岩石物理结果支持ARF为海相条件下的碳酸盐岩矿床，具有混合层状粘土(蒙脱石、克隆石和伊利石)。利用现有的岩心数据，研究了许多通过电缆测井估计ARF渗透率的技术，并建立了孔隙度-渗透率关系。岩石物理分析结果表明，Lucia 3级渗透率与岩心渗透率具有良好的数学关系。因此，利用测井资料计算出的有效孔隙度，可以利用Lucia 3级渗透率来估算ARF渗透率。总体而言，本研究的地球化学和岩石物理评价结果表明，与世界上大多数商业开发的非常规资源相比，ARF具有很好的储层质量。结果表明，ARF与Eagle Ford页岩在年龄、矿物学、压力、深度、厚度、TOC等方面具有相似性，反映了ARF的商业开发潜力。
{"title":"Petrophysical Evaluation and Geochemical Characterization of Abu Roash F Member Abu Gharadig Basin, Western Desert, Egypt","authors":"Sayed Farrag, I. Mahmoud","doi":"10.2523/iptc-22187-ms","DOIUrl":"https://doi.org/10.2523/iptc-22187-ms","url":null,"abstract":"\u0000 Abu Roash F Member (ARF) is a carbonate formation extended all over the Western Desert in Egypt, ARF has good lateral continuity in all western desert basins but has very poor connectivity and very low permeability. it can be considered as an example of unconventional reservoir. This work aims to evaluate the reservoir quality of Abu Roash \"F\" Member and compare with the unconventional play commercial developed all over the world. in this study, the key parameters to define reservoir quality; include mineralogy, porosity, water saturation, permeability, organic matter content, Kerogen type and thermal maturity has been investigated. More than 30 Rock-Eval pyrolysis samples from different fields where ARF at significantly different level has been used to evaluate and understand ARF geochemical reservoir quality. On the other side, core and well log data from different fields at different level has been inspected and integrated to evaluate ARF mineralogy, porosity, permeability, water saturation, and identify Potential sweet spots. The results of Rock-Eval analysis show that most of the investigated samples have the total organic carbon content (TOC) values between 1.6 and 6.63 wt% indicating good to very good source rocks and the pyrolysis Yield (PY) ranged from 6 to 20 indicating good to very good potential generation. Based on Tmax and Hydrogen index (HI), the deepest well samples have Tmax values in the range of 435 and 441°C and Hydrogen index (HI) values in the range of 311 to 570 indicating that the organic matter has reached the early to intermediate stages of thermal maturity with dominate kerogen type I-II. While the shallower well samples have Tmax values in the range of 421 and 430°C and Hydrogen index (HI) values in the range of 127 to 687 indicating that the organic matter immature with mixed kerogen type II-III.\u0000 Petrophysical results supporting that ARF is a carbonate rock deposit under marine conditions and has mixed layer clay (montomonlionite, Kolonite and illite). Numerous techniques to estimate ARF permeability from wireline logs have been investigated, using the available core data porosity permeability relationship has been established. Moreover, the results of petrophysical analysis indicate that Lucia class 3 permeability has good math with core permeability. So, Lucia class 3 permeability can be used to estimate ARF permeability using the calculated effective porosity from well log data.\u0000 Generally, the results of geochemical and petrophysical evaluation of this study show that ARF has very good reservoir quality comparing with the most of commercially developed unconventional resources all over the world. Moreover, the results show that ARF has a similarity with Eagle Ford Shale in terms of Age, mineralogy, pressure, depth, thickness, and TOC which reflect the potentiality of ARF commercial development.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77882326","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Gelled acid systems based upon gelation of hydrochloric acid (HCl) are extensively used in both matrix acidizing and fracture acidizing treatments to prevent acidizing fluid leak-off. The gelled-up fluid system helps retard the acid reaction to allow deeper wormhole propagation. Conventional in-situ crosslinked gelled acid systems consist of a polyacrylamide polymer, a crosslinker (such as iron-based crosslinker), a chemical breaker, other additives, along with acid. However, these systems can lead to damaging the formation due to several reasons including unbroken polymer residue or scaling, resulting in lowering of hydrocarbon productivity. To mitigate these drawbacks, we have developed a self-breaking, formation damage-free, novel nanoparticles based gelled acid system to replace the polymer based gelled acid system. The new gelled acid system is based on, surface modified nanoparticles to make them compatible in acidic environment, a gelation activator, acidizing treatment additives along with HCl to overcome the challenges the conventional systems face. The new system can work with up to 28& of HCl up to 300°F with low viscosity at surface, making it easy to be pump. As the acid spends due to reaction with the formation the pH of the fluid transitions from acidic to basic pH. The gelation phenomenon of the new system is controlled by the increasing pH. As the pH increases beyond pH 1 gelation of the nanoparticles occurs thus gelling up the acidic fluid. As the pH further continues to rise beyond pH 4 the nanoparticles lose their capability to gel up and the fluid viscosity decreases to pre-gelation level, facilitating easy post treatment flow back. A systematic experimental protocol was followed to develop the new system that is documented in this paper. It is shown that the gelation properties are pH dependent phenomenon providing the critical control over the gelation time and avoiding any premature gelation during pumping the treatment. The effectiveness of the system by not damaging the formation was investigated using regain permeability studies. The new system showed excellent regain permeability. The obtained data confirmed several advantages of the new system over conventional polymer based gelled acid systems. Gelation experiments were performed to gather a better understanding of the gelation mechanism and also to get effective control on the gelation and break properties. The uniqueness about the new system is that, it is formation damage free without the need to use polymers or iron based cross-linkers that may lead to potential damage mechanisms.
{"title":"Surface Modified Nanoparticles Based Novel Gelled Acid System - A Unique Formation Damage Free Well Stimulation Technology","authors":"R. Kalgaonkar, Nour Baqader","doi":"10.2523/iptc-22443-ms","DOIUrl":"https://doi.org/10.2523/iptc-22443-ms","url":null,"abstract":"\u0000 Gelled acid systems based upon gelation of hydrochloric acid (HCl) are extensively used in both matrix acidizing and fracture acidizing treatments to prevent acidizing fluid leak-off. The gelled-up fluid system helps retard the acid reaction to allow deeper wormhole propagation. Conventional in-situ crosslinked gelled acid systems consist of a polyacrylamide polymer, a crosslinker (such as iron-based crosslinker), a chemical breaker, other additives, along with acid. However, these systems can lead to damaging the formation due to several reasons including unbroken polymer residue or scaling, resulting in lowering of hydrocarbon productivity. To mitigate these drawbacks, we have developed a self-breaking, formation damage-free, novel nanoparticles based gelled acid system to replace the polymer based gelled acid system. The new gelled acid system is based on, surface modified nanoparticles to make them compatible in acidic environment, a gelation activator, acidizing treatment additives along with HCl to overcome the challenges the conventional systems face. The new system can work with up to 28& of HCl up to 300°F with low viscosity at surface, making it easy to be pump. As the acid spends due to reaction with the formation the pH of the fluid transitions from acidic to basic pH. The gelation phenomenon of the new system is controlled by the increasing pH. As the pH increases beyond pH 1 gelation of the nanoparticles occurs thus gelling up the acidic fluid. As the pH further continues to rise beyond pH 4 the nanoparticles lose their capability to gel up and the fluid viscosity decreases to pre-gelation level, facilitating easy post treatment flow back.\u0000 A systematic experimental protocol was followed to develop the new system that is documented in this paper. It is shown that the gelation properties are pH dependent phenomenon providing the critical control over the gelation time and avoiding any premature gelation during pumping the treatment. The effectiveness of the system by not damaging the formation was investigated using regain permeability studies. The new system showed excellent regain permeability. The obtained data confirmed several advantages of the new system over conventional polymer based gelled acid systems. Gelation experiments were performed to gather a better understanding of the gelation mechanism and also to get effective control on the gelation and break properties.\u0000 The uniqueness about the new system is that, it is formation damage free without the need to use polymers or iron based cross-linkers that may lead to potential damage mechanisms.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73127479","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Verma, V. Muthamizhvendan, Sivakumar Ganesan, M. Sarode, Mohammad Syafiq, Amol Diware, Akshata Berry
This paper describes the use of managed pressure drilling (MPD) and managed pressure cementing (MPC) technology on a high-pressure high-temperature (HP/HT) well in North-Eastern onshore, India by Oil and Natural Gas Corporation Ltd. (ONGC), a leading exploration and production company in India in collaboration with Halliburton, one of the major oilfield service providers globally. The bottom-hole temperature recorded in this well is 151°C and bottom-hole pressure of over 15,000psi at target depth. The MPD technology was utilized for drilling the well for the first time in ONGC. The near wild cat well was successfully drilled and cemented to a depth of 4,840 mMD and made history by tapping into Lower Bhuban and Barail sands for the first time, while successfully drilling in uncertain pore pressure environments, managing gas and water kicks, coping with loss zones, and identifying production zones together with pore pressure estimation. The well posed many challenges including uncertain pore pressures, highly unstable formations, likelihood of differential sticking and high-pressures/high-temperatures. The operator had attempted to drill the well conventionally in the past which had to be abandoned due to technical complications owing to high pore pressure gas and water sands as well as high differential pressure. MPD uses a closed-loop system that adds an increased level of environmental protection and allows for the use of an automated early kick detection system for increased safety. The automated MPD system was incorporated for the two well sections (12-1/4" and 8-1/2" hole sections) to provide control, flexibility, and safety required to drill and mitigate these risks. This implementation allowed to drill 2,013 meters (6,604 feet) in an extremely challenging zone in stable and safe conditions. The well was drilled to a target depth of 4,840 meters (15,880 feet). Deployment of an extensive MPD surface control system (along with rotating control device, fully automated choke manifold and back-pressure pump) allowed drilling and cementing of the well in a safe and efficient manner without any breach to safety and service quality. The MPD technology enabled ONGC to reduce the mud weight while drilling the well by balancing the formation pressure with application of additional SBP from surface using MPD choke manifold. This helped ONGC tackle the narrow drilling window along with early-kick management in HP/HT environment. The well was drilled to target depth of 4,840 mMD, making it the deepest drilled and cased hole in Tripura, Asset India. Major formation information on Lower Bhuban and Barail sands was obtained along with ascertaining zones of interest by allowing early detection of formation changes and hydrocarbon zones. The formation was non-drillable through conventional approach and implementation of MPD technology made it possible. The operation was carried out with extensive remote support from team in global and region considering pa
本文介绍了印度石油天然气公司(ONGC)与哈里伯顿(全球主要油田服务提供商之一)合作，在印度东北部陆地的一口高压高温(HP/HT)井中使用控压钻井(MPD)和控压固井(MPC)技术。ONGC是印度领先的勘探和生产公司。该井记录的井底温度为151°C，目标深度的井底压力超过15,000psi。MPD技术在ONGC首次用于钻井。这口近野生猫井的钻井和固井深度达到4840 mMD，首次进入Lower Bhuban和Barail砂层，创造了历史，同时成功地在不确定的孔隙压力环境下钻井，控制气涌和水涌，应对漏失区域，并确定生产区域以及孔隙压力估算。该井面临许多挑战，包括不确定的孔隙压力、高度不稳定的地层、可能存在的差异粘滞以及高压/高温。过去，作业者曾尝试常规钻井，但由于高孔隙压力气砂和水砂以及高压差的技术复杂性，不得不放弃。MPD采用闭环系统，提高了环境保护水平，并允许使用自动早期井涌检测系统，以提高安全性。自动化MPD系统用于两个井段(12-1/4”和8-1/2”井段)，以提供钻井所需的控制、灵活性和安全性，并降低这些风险。该技术能够在稳定、安全的条件下，在极具挑战性的地层中钻进2013米(6604英尺)。该井的目标深度为4840米(15880英尺)。广泛的MPD地面控制系统(连同旋转控制装置、全自动阻流管汇和背压泵)的部署，使钻井和固井能够以安全、高效的方式进行，而不会影响安全性和服务质量。MPD技术使ONGC能够在钻井过程中通过MPD节流管汇从地面施加额外的SBP来平衡地层压力，从而降低泥浆重量。这有助于ONGC解决高温高压环境下狭窄的钻井窗口和早期井涌管理问题。该井的目标深度为4840 mMD，是Asset India Tripura地区钻、套管井最深的井。通过早期发现地层变化和油气带，获得了Lower Bhuban和Barail砂层的主要地层信息，并确定了感兴趣的区域。通过常规方法，该地层是不可钻的，而MPD技术的实施使其成为可能。考虑到大流行病的情况，该行动在全球和区域小组的广泛远程支持下进行。
{"title":"Case Study: First Ever Implementation of Managed Pressure Drilling to Drill Exploratory and Near Wildcat Well at Ongc Tripura Asset","authors":"R. Verma, V. Muthamizhvendan, Sivakumar Ganesan, M. Sarode, Mohammad Syafiq, Amol Diware, Akshata Berry","doi":"10.2523/iptc-22005-ms","DOIUrl":"https://doi.org/10.2523/iptc-22005-ms","url":null,"abstract":"\u0000 This paper describes the use of managed pressure drilling (MPD) and managed pressure cementing (MPC) technology on a high-pressure high-temperature (HP/HT) well in North-Eastern onshore, India by Oil and Natural Gas Corporation Ltd. (ONGC), a leading exploration and production company in India in collaboration with Halliburton, one of the major oilfield service providers globally. The bottom-hole temperature recorded in this well is 151°C and bottom-hole pressure of over 15,000psi at target depth. The MPD technology was utilized for drilling the well for the first time in ONGC. The near wild cat well was successfully drilled and cemented to a depth of 4,840 mMD and made history by tapping into Lower Bhuban and Barail sands for the first time, while successfully drilling in uncertain pore pressure environments, managing gas and water kicks, coping with loss zones, and identifying production zones together with pore pressure estimation.\u0000 The well posed many challenges including uncertain pore pressures, highly unstable formations, likelihood of differential sticking and high-pressures/high-temperatures. The operator had attempted to drill the well conventionally in the past which had to be abandoned due to technical complications owing to high pore pressure gas and water sands as well as high differential pressure. MPD uses a closed-loop system that adds an increased level of environmental protection and allows for the use of an automated early kick detection system for increased safety. The automated MPD system was incorporated for the two well sections (12-1/4\" and 8-1/2\" hole sections) to provide control, flexibility, and safety required to drill and mitigate these risks. This implementation allowed to drill 2,013 meters (6,604 feet) in an extremely challenging zone in stable and safe conditions. The well was drilled to a target depth of 4,840 meters (15,880 feet).\u0000 Deployment of an extensive MPD surface control system (along with rotating control device, fully automated choke manifold and back-pressure pump) allowed drilling and cementing of the well in a safe and efficient manner without any breach to safety and service quality. The MPD technology enabled ONGC to reduce the mud weight while drilling the well by balancing the formation pressure with application of additional SBP from surface using MPD choke manifold. This helped ONGC tackle the narrow drilling window along with early-kick management in HP/HT environment. The well was drilled to target depth of 4,840 mMD, making it the deepest drilled and cased hole in Tripura, Asset India. Major formation information on Lower Bhuban and Barail sands was obtained along with ascertaining zones of interest by allowing early detection of formation changes and hydrocarbon zones. The formation was non-drillable through conventional approach and implementation of MPD technology made it possible. The operation was carried out with extensive remote support from team in global and region considering pa","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79842138","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Haipeng Liang, Huiying Tang, Jianhua Qin, Yang Li, Liehui Zhang
Currently, the research on hydraulic fracture geometries is mainly focused on tight sandstone and shale. The investigations on the conglomerate tight reservoirs, e.g., Mahu Oilfield in Junggar Basin, China, is still lacking due to its uniqueness and late discovery time. The strong heterogeneity and the existence of gravels in conglomerate tight reservoirs put great challenges on the study of hydraulic fracture geometries. In this paper, a whole field cohesive zone model in finite element method is used to model the fracture nucleation and propagation in rock matrix (sand) and gravels in lab scale. The numerical model is validated against some published experimental results. Based on the analysis of numerical results, a mathematical model for quantitative characterization of fracture growth speed in conglomerate reservoir is proposed. This model is critical to connect the fracture propagation behaviors in lab-scale with the hundreds of meters field-scale hydraulic fractures. For the field scale fracturing simulations, the UFM (unconventional fracture model), which is based on boundary element method, has been widely used. Considering the similarity of crossing behaviors between hydraulic fracture-gravels and hydraulic fracture -natural fractures in conglomerate and shale respectively, a series of natural fractures are used to equivalent the impact of gravels in lab scale in the field scale simulations. The parameters of the equivalent natural fractures are determined according to the propagation model extracted from the lab-scale numerical simulations. The multi-scale research on fracture geometries and methods for field scale fracturing simulations for Mahu conglomerate reservoir could provide important guidance for the future design and optimizations of hydraulic fracturing.
{"title":"Multi-Scale Investigations on the Geometries of Hydraulic Fractures in Conglomerate Reservoirs","authors":"Haipeng Liang, Huiying Tang, Jianhua Qin, Yang Li, Liehui Zhang","doi":"10.2523/iptc-22275-ms","DOIUrl":"https://doi.org/10.2523/iptc-22275-ms","url":null,"abstract":"\u0000 Currently, the research on hydraulic fracture geometries is mainly focused on tight sandstone and shale. The investigations on the conglomerate tight reservoirs, e.g., Mahu Oilfield in Junggar Basin, China, is still lacking due to its uniqueness and late discovery time. The strong heterogeneity and the existence of gravels in conglomerate tight reservoirs put great challenges on the study of hydraulic fracture geometries. In this paper, a whole field cohesive zone model in finite element method is used to model the fracture nucleation and propagation in rock matrix (sand) and gravels in lab scale. The numerical model is validated against some published experimental results. Based on the analysis of numerical results, a mathematical model for quantitative characterization of fracture growth speed in conglomerate reservoir is proposed. This model is critical to connect the fracture propagation behaviors in lab-scale with the hundreds of meters field-scale hydraulic fractures. For the field scale fracturing simulations, the UFM (unconventional fracture model), which is based on boundary element method, has been widely used. Considering the similarity of crossing behaviors between hydraulic fracture-gravels and hydraulic fracture -natural fractures in conglomerate and shale respectively, a series of natural fractures are used to equivalent the impact of gravels in lab scale in the field scale simulations. The parameters of the equivalent natural fractures are determined according to the propagation model extracted from the lab-scale numerical simulations. The multi-scale research on fracture geometries and methods for field scale fracturing simulations for Mahu conglomerate reservoir could provide important guidance for the future design and optimizations of hydraulic fracturing.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80092918","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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