Binzhen Bai, Yijin Zeng, Xinbian Lu, Hongning Zhang, Zhifa Wang, Long Wang, Haobo Zhou, Eduardo David Gramajo Silva, Rached Rached Maurice
There was nearly 1.7 billion tons proved reserve in SINOPEC Shunbei oilfield, which is the deepest (>8000m) fault controlled marine carbonate oilfield in the world with high-temperature (>170 °C) and high -pressure (>140MPa). The formation geological conditions are complicated, high rock strength, easy leakage and collapse, multiple pressure systems co-exist in the slim borehole, which caused a series of directional drilling technical problems such as difficulty in controlling the tool surface, PDM build-up capacity prediction and so on. Therefore, the related research for ultra-deep direction drilling technology were carried out aiming at solving the directional drilling problem for Shunbei oilfield. Firstly, the optimized wellbore structure scheme design method was proposed, in which the geological characteristics, borehole size and the directional efficiency were considered. And then a double augmented well profile designed model was established based on optimizing the production casing size, through which the directional efficiency and the drilling rate of a trip were increased significantly, and the nonproductive time can be greatly reduced easily. Secondly, an ultra-deep directional well torque transmission prediction model was established based on the mechanical analysis of ultra-deep drilling string and based which a rapid tool face control method was formed. Furthermore, an innovative build-up rate prediction method was established based on both big Data analysis and balanced tendency build-up rate prediction method, and the accuracy is more than 90%. Moreover, the PDM rubber seal, stator and rotor dimensions are optimized to achieve high power output within a certain high temperature range to prolong the service life according to the wellbore temperature field. Finally, the optimization of high temperature MWD instrument and matching process technology was proposed, such as surface assisted cooling, borehole size enlarging and high displacement cooling technology effectively improve the reliability. The series of ultra-deep directional drilling technology has been applied in Shunbei oilfield. The field application results show that the average ROP of directional section is increased by more than 30%, directional efficiency is greatly improved, and the directional drilling cycle is shortened by more than 20%. Nearly 40 ultra-deep directional wells above 8000m have been constructed, setting more than 10 new Asia records of petroleum engineering onshore directional well. There are two innovations in this paper. The first is to put forward the design method of wellbore profile with the shortest drilling time as the goal, which can save 1-2 trips and improve the directional efficiency by more than 20%. The second is to introduce the prediction method of build-up rate based on borehole tendency angle, which improves the prediction accuracy of build-up rate by 28% in Shunbei ultra deep directional well.
{"title":"The Key Technologies of Ultra-Deep Hpht Horizontal Wells and Its Application in Shunbei Oilfield of SINOPEC","authors":"Binzhen Bai, Yijin Zeng, Xinbian Lu, Hongning Zhang, Zhifa Wang, Long Wang, Haobo Zhou, Eduardo David Gramajo Silva, Rached Rached Maurice","doi":"10.2523/iptc-22141-ms","DOIUrl":"https://doi.org/10.2523/iptc-22141-ms","url":null,"abstract":"\u0000 There was nearly 1.7 billion tons proved reserve in SINOPEC Shunbei oilfield, which is the deepest (>8000m) fault controlled marine carbonate oilfield in the world with high-temperature (>170 °C) and high -pressure (>140MPa). The formation geological conditions are complicated, high rock strength, easy leakage and collapse, multiple pressure systems co-exist in the slim borehole, which caused a series of directional drilling technical problems such as difficulty in controlling the tool surface, PDM build-up capacity prediction and so on. Therefore, the related research for ultra-deep direction drilling technology were carried out aiming at solving the directional drilling problem for Shunbei oilfield.\u0000 Firstly, the optimized wellbore structure scheme design method was proposed, in which the geological characteristics, borehole size and the directional efficiency were considered. And then a double augmented well profile designed model was established based on optimizing the production casing size, through which the directional efficiency and the drilling rate of a trip were increased significantly, and the nonproductive time can be greatly reduced easily. Secondly, an ultra-deep directional well torque transmission prediction model was established based on the mechanical analysis of ultra-deep drilling string and based which a rapid tool face control method was formed. Furthermore, an innovative build-up rate prediction method was established based on both big Data analysis and balanced tendency build-up rate prediction method, and the accuracy is more than 90%. Moreover, the PDM rubber seal, stator and rotor dimensions are optimized to achieve high power output within a certain high temperature range to prolong the service life according to the wellbore temperature field. Finally, the optimization of high temperature MWD instrument and matching process technology was proposed, such as surface assisted cooling, borehole size enlarging and high displacement cooling technology effectively improve the reliability.\u0000 The series of ultra-deep directional drilling technology has been applied in Shunbei oilfield. The field application results show that the average ROP of directional section is increased by more than 30%, directional efficiency is greatly improved, and the directional drilling cycle is shortened by more than 20%. Nearly 40 ultra-deep directional wells above 8000m have been constructed, setting more than 10 new Asia records of petroleum engineering onshore directional well.\u0000 There are two innovations in this paper. The first is to put forward the design method of wellbore profile with the shortest drilling time as the goal, which can save 1-2 trips and improve the directional efficiency by more than 20%. The second is to introduce the prediction method of build-up rate based on borehole tendency angle, which improves the prediction accuracy of build-up rate by 28% in Shunbei ultra deep directional well.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81113070","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}
B. Al-Baloul, S. Mittal, David Spencer, Naseema Al-Ramadan
Geoscientists are bound to have a degree of bias based on their own knowledge, experience, perception, adversity to risk, education, or pre-conceived beliefs. Such subjectivity may lead to a prejudice in making a decision unless this is properly recognized and corrected. As such, this may result in a distorted view of the likelihood on a decision to ‘drill-or-drop,’ if these pre-drill probability predictions are not rationalized. It is therefore extremely important to improve probability assessments by undertaking different approaches, such as setting up detailed and consistent protocols, company-wide standardization or by applying specific elicitation methods. A statistical analysis was undertaken using pre- and post-drill Geological Chance of Success (gCOS) and P-mean volume of the prospects that were drilled vis-a-vis prospects yet to be drilled. The reason for this is to identify the range of the pessimistic and/or optimistic evaluations by the risk reviewers. The purpose then becomes to derive a more stringent and authentic method by which such high deviations in risk estimations, and consistency with the methodology for prospective resource estimations, could be minimized with any potential biases removed. A historical database from the company's assets, spanning over a decade (2010-2020), was used for the statistical analysis. The results suggest that the risk reviewer's bias, lack of close analogues and paucity of direct evidence of perspectivity, resulted in non-realistic and over/under estimation of gCOS and prospective resources. Being able to understand and quantify the risks and uncertainties, and knowing how to manage them effectively, contributes to well-founded business decisions, protects the value of projects and assets, and maximizes the value of company project portfolios. A systematic risk and peer review processes was then evolved by KUFPEC to constrain these biased subjective deviations from real objective estimations and to minimize the risk of the overestimation / underestimation of risking and hydrocarbon volume for a given prospect.
{"title":"Eradicating Biases and Establishing Consistency in Geological Chance of Success","authors":"B. Al-Baloul, S. Mittal, David Spencer, Naseema Al-Ramadan","doi":"10.2523/iptc-22594-ms","DOIUrl":"https://doi.org/10.2523/iptc-22594-ms","url":null,"abstract":"\u0000 Geoscientists are bound to have a degree of bias based on their own knowledge, experience, perception, adversity to risk, education, or pre-conceived beliefs. Such subjectivity may lead to a prejudice in making a decision unless this is properly recognized and corrected. As such, this may result in a distorted view of the likelihood on a decision to ‘drill-or-drop,’ if these pre-drill probability predictions are not rationalized. It is therefore extremely important to improve probability assessments by undertaking different approaches, such as setting up detailed and consistent protocols, company-wide standardization or by applying specific elicitation methods.\u0000 A statistical analysis was undertaken using pre- and post-drill Geological Chance of Success (gCOS) and P-mean volume of the prospects that were drilled vis-a-vis prospects yet to be drilled. The reason for this is to identify the range of the pessimistic and/or optimistic evaluations by the risk reviewers. The purpose then becomes to derive a more stringent and authentic method by which such high deviations in risk estimations, and consistency with the methodology for prospective resource estimations, could be minimized with any potential biases removed. A historical database from the company's assets, spanning over a decade (2010-2020), was used for the statistical analysis.\u0000 The results suggest that the risk reviewer's bias, lack of close analogues and paucity of direct evidence of perspectivity, resulted in non-realistic and over/under estimation of gCOS and prospective resources. Being able to understand and quantify the risks and uncertainties, and knowing how to manage them effectively, contributes to well-founded business decisions, protects the value of projects and assets, and maximizes the value of company project portfolios. A systematic risk and peer review processes was then evolved by KUFPEC to constrain these biased subjective deviations from real objective estimations and to minimize the risk of the overestimation / underestimation of risking and hydrocarbon volume for a given prospect.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84323308","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}
Carbonate rocks have a very complex pore system due to the presence of interparticle and intra-particle porosities. This makes the acquisition and analysis of the petrophysical data, and the characterization of carbonate rocks a big challenge. Neutron porosity log and sonic porosity logs are usually considered as less accurate compared to the NMR porosity. Neutron-density porosity depends on parameters related to rock matrix which cause the inaccurate estimation of the porosity in special cases suchlike dolomitized and fractured zone. Whereas NMR porosity is based on the amount of hydrogen nuclei in the pore spaces and is independent of the rock minerals and is related to the pore spaces only. In this study, different machine learning algorithms are used to predict the Nuclear Magnetic Resonance (NMR) porosity. Conventional well logs such as Gamma ray, neutron porosity, deep and shallow resistivity logs, sonic traveltime, and photoelectric logs were used as an input parameter while NMR porosity log was set as an output parameter. More than 3500 data points were collected from several wells drilled in a giant carbonate reservoir of the middle eastern oil reservoir. Extensive data exploratory techniques were used to perform the data quality checks and remove the outliers and extreme values. Machine learning techniques such as random forest, deep neural networks, functional networks, and adaptive decision trees were explored and trained. The tuning of hyper parameters was performed using grid search and evolutionary algorithms approach. To optimize further the results of machine learning models, k-fold cross validation criterion was used. The evaluation of machine learning models was assessed by average absolute percentage error (AAPE), root mean square error (RMSE), and coefficient of correlation (R). The results showed that deep neural network performed better than the other investigated machine learning techniques based on lowest errors and highest R. The results showed that the proposed model predicted the NMR porosity with an accuracy of 94% when related to the actual values. In this study in addition to the development of optimized DNN model, an explicit empirical correlation is also extracted from the optimized model. The validation of the proposed model was performed by testing the model on other wells, the data of other wells were not used in the training. This work clearly shows that computer-based machine learning techniques can determine NMR porosity with a high precision and the developed correlation works extremely well in prediction mode.
{"title":"A Data Driven Machine Learning Approach to Predict the Nuclear Magnetic Resonance Porosity of the Carbonate Reservoir","authors":"Ayyaz Ayyaz Mustafa, Zeeshan Zeeshan Tariq, Mohamed Mohamed Mahmoud, A. Abdulraheem","doi":"10.2523/iptc-22081-ms","DOIUrl":"https://doi.org/10.2523/iptc-22081-ms","url":null,"abstract":"\u0000 Carbonate rocks have a very complex pore system due to the presence of interparticle and intra-particle porosities. This makes the acquisition and analysis of the petrophysical data, and the characterization of carbonate rocks a big challenge. Neutron porosity log and sonic porosity logs are usually considered as less accurate compared to the NMR porosity. Neutron-density porosity depends on parameters related to rock matrix which cause the inaccurate estimation of the porosity in special cases suchlike dolomitized and fractured zone. Whereas NMR porosity is based on the amount of hydrogen nuclei in the pore spaces and is independent of the rock minerals and is related to the pore spaces only.\u0000 In this study, different machine learning algorithms are used to predict the Nuclear Magnetic Resonance (NMR) porosity. Conventional well logs such as Gamma ray, neutron porosity, deep and shallow resistivity logs, sonic traveltime, and photoelectric logs were used as an input parameter while NMR porosity log was set as an output parameter. More than 3500 data points were collected from several wells drilled in a giant carbonate reservoir of the middle eastern oil reservoir. Extensive data exploratory techniques were used to perform the data quality checks and remove the outliers and extreme values. Machine learning techniques such as random forest, deep neural networks, functional networks, and adaptive decision trees were explored and trained. The tuning of hyper parameters was performed using grid search and evolutionary algorithms approach. To optimize further the results of machine learning models, k-fold cross validation criterion was used. The evaluation of machine learning models was assessed by average absolute percentage error (AAPE), root mean square error (RMSE), and coefficient of correlation (R).\u0000 The results showed that deep neural network performed better than the other investigated machine learning techniques based on lowest errors and highest R. The results showed that the proposed model predicted the NMR porosity with an accuracy of 94% when related to the actual values. In this study in addition to the development of optimized DNN model, an explicit empirical correlation is also extracted from the optimized model. The validation of the proposed model was performed by testing the model on other wells, the data of other wells were not used in the training.\u0000 This work clearly shows that computer-based machine learning techniques can determine NMR porosity with a high precision and the developed correlation works extremely well in prediction mode.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85285532","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}
With the increased demand for drilling deeper wells in harsh environments involving corrosive, briny waters and more corrosive crudes, completion engineers increasingly adopt more resilient materials for well casings than conventional carbon steel. These materials include alloyed steels, where ferrous steel is mixed with other non-ferrous materials, such as chromium and nickel, for increased strength and durability. Alloyed steel has a lower magnetic permeability than carbon steel and, therefore, generates weaker electromagnetic signatures when logged with electromagnetic pipe inspection tools. This paper demonstrates the performance of an array multi-frequency electromagnetic pipe inspection tool in scenarios involving alloyed completions using a simulated mockup test with known defects. The types of defects considered are circumferential with different combinations of overlapping and non-overlapping defects on well casings. The pipe inspection tool uses the eddy current principle and includes two transmitters and eight receivers. It operates in continuous wave mode at multiple frequencies. Optimized transmitter-receiver spacing configurations and multi-frequency operation provide sufficiently diverse information to help assess metal loss in individual pipes for a wide range of configurations, including those with alloyed completions. The tool uses a sophisticated workflow of data-processing and inversion algorithms to decouple individual thickness information from the measured data. A mockup test was designed to replicate typical alloyed completions used in deep water wells to assess tool performance in different scenarios. The mockup comprises an alloyed tubing and two outer casings, which are standard ferromagnetic steel pipes, with seven combinations of defects on the casings. The tool response is synthetically simulated using a finite element electromagnetic solver and the synthetic data are inverted for metal loss on each one of the pipes. The estimated metal loss for each defect was compared to the actual metal loss to assess the accuracy of the tool. It will be shown that in order to obtain high accuracy of metal loss estimation, the electromagnetic material properties of the pipes, including that of the alloyed tubing, must be estimated with sufficient accuracy. The information provided by this tool will enable regular inspection of deepwater wells for corrosion and other integrity issues with minimal downtime and intervention cost.
{"title":"Demonstrating the Performance of a Multi-Tubular Corrosion Inspection Tool in Alloyed Completions","authors":"A. Fouda, J. Dai","doi":"10.2523/iptc-22376-ms","DOIUrl":"https://doi.org/10.2523/iptc-22376-ms","url":null,"abstract":"\u0000 With the increased demand for drilling deeper wells in harsh environments involving corrosive, briny waters and more corrosive crudes, completion engineers increasingly adopt more resilient materials for well casings than conventional carbon steel. These materials include alloyed steels, where ferrous steel is mixed with other non-ferrous materials, such as chromium and nickel, for increased strength and durability. Alloyed steel has a lower magnetic permeability than carbon steel and, therefore, generates weaker electromagnetic signatures when logged with electromagnetic pipe inspection tools. This paper demonstrates the performance of an array multi-frequency electromagnetic pipe inspection tool in scenarios involving alloyed completions using a simulated mockup test with known defects. The types of defects considered are circumferential with different combinations of overlapping and non-overlapping defects on well casings.\u0000 The pipe inspection tool uses the eddy current principle and includes two transmitters and eight receivers. It operates in continuous wave mode at multiple frequencies. Optimized transmitter-receiver spacing configurations and multi-frequency operation provide sufficiently diverse information to help assess metal loss in individual pipes for a wide range of configurations, including those with alloyed completions. The tool uses a sophisticated workflow of data-processing and inversion algorithms to decouple individual thickness information from the measured data.\u0000 A mockup test was designed to replicate typical alloyed completions used in deep water wells to assess tool performance in different scenarios. The mockup comprises an alloyed tubing and two outer casings, which are standard ferromagnetic steel pipes, with seven combinations of defects on the casings. The tool response is synthetically simulated using a finite element electromagnetic solver and the synthetic data are inverted for metal loss on each one of the pipes. The estimated metal loss for each defect was compared to the actual metal loss to assess the accuracy of the tool. It will be shown that in order to obtain high accuracy of metal loss estimation, the electromagnetic material properties of the pipes, including that of the alloyed tubing, must be estimated with sufficient accuracy. The information provided by this tool will enable regular inspection of deepwater wells for corrosion and other integrity issues with minimal downtime and intervention cost.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91233565","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}
A. Fathy, M. Arif, Md. Motiur Rahman, Mujahid Ali, S. Iglauer, N. Mathew
Wetting characteristics of shale/oil/brine systems at reservoir conditions are important for understanding fluid distribution, flow within shale microstructure, and flow back of fracturing fluid. However, shale wettability demonstrates complexity from core to nanoscale due to microstructure heterogeneity. Shale is believed to exbibit mixed wettability such that the organic matter is hydrophobic or oil-wet and the inorganic mineral is hydrophilic or water-wet. Moreover, the application of nanofluids (e.g., silica) as chemical enhanced oil recovery (CEOR) agents has gained growing interest justified by their promising potential. Thus, to elucidate the complex wetting behavior of shale/oil/brine systems before and after exposure to nanofluids, it is essential to consider the influence of broad mineralogy, TOC (Total Organic Carbon), and aging time of shale surfaces in nanofluids. In this paper, a new physicochemical approach coupled with imaging analysis is proposed to emphasize the interactions of shale/decane/brine systems (before and after aging in nanofluids) for precise shale wettability characterization. Here, the wettability of three US shale oil rocks (Eagle Ford, Wolf Camp, and Mancos) was assessed at ambient and HPHT conditions via advancing and receding contact angle measurements followed by wettability assessment post-aging in different nanofluid concentrations (0.1 wt. % to 5 wt. %). Further, the physicochemical features that influence wettability e.g., surface chemistry, mineral composition, TOC, and kerogen maturity have been investigated. These factors have been assessed via sets of physicochemical measurements such as FTIR (Fourier-Transform Infrared Spectroscopy), XRD (X-Ray Diffraction) analysis, SEM (Scanning Electron Microscopy), and AFM (Atomic Force Microscopy) imaging. Furthermore, the varying thermophysical conditions of pressure and temperature are also investigated. The results revealed significant variations in shale initial wettability with Mancos being weakly water-wet while Eagle Ford and Wolf Camp were moderately oil-wet. Moreover, increasing pressure (from 1 MPa to 20 MPa) shifted the wettability of shale rock surfaces towards relatively more oil-wet witnessed by an increase in advancing and receding contact angles. However, no noticeable trend was observed for contact angle variation with temperature. The original wetting behavior of shales is then related to their functional groups and mineralogy. Additionally, shale surfaces witnessed a shift towards a more water-wet state after aging in silica nanofluids at different concentrations. Therefore, this paper provides a new approach for examining the complex shale wettability behavior that relies on a combination of HPHT conditions, physicochemical analysis, and image analysis. Importantly, the results suggest that nanofluid can alter shale wettability towards a more water-wet state – thus showing potential for application as a flowback additive in fracturing or
{"title":"Wettability of Shale/Oil/Brine Systems: A New Physicochemical and Imaging Approach","authors":"A. Fathy, M. Arif, Md. Motiur Rahman, Mujahid Ali, S. Iglauer, N. Mathew","doi":"10.2523/iptc-22177-ms","DOIUrl":"https://doi.org/10.2523/iptc-22177-ms","url":null,"abstract":"\u0000 Wetting characteristics of shale/oil/brine systems at reservoir conditions are important for understanding fluid distribution, flow within shale microstructure, and flow back of fracturing fluid. However, shale wettability demonstrates complexity from core to nanoscale due to microstructure heterogeneity. Shale is believed to exbibit mixed wettability such that the organic matter is hydrophobic or oil-wet and the inorganic mineral is hydrophilic or water-wet. Moreover, the application of nanofluids (e.g., silica) as chemical enhanced oil recovery (CEOR) agents has gained growing interest justified by their promising potential. Thus, to elucidate the complex wetting behavior of shale/oil/brine systems before and after exposure to nanofluids, it is essential to consider the influence of broad mineralogy, TOC (Total Organic Carbon), and aging time of shale surfaces in nanofluids.\u0000 In this paper, a new physicochemical approach coupled with imaging analysis is proposed to emphasize the interactions of shale/decane/brine systems (before and after aging in nanofluids) for precise shale wettability characterization. Here, the wettability of three US shale oil rocks (Eagle Ford, Wolf Camp, and Mancos) was assessed at ambient and HPHT conditions via advancing and receding contact angle measurements followed by wettability assessment post-aging in different nanofluid concentrations (0.1 wt. % to 5 wt. %). Further, the physicochemical features that influence wettability e.g., surface chemistry, mineral composition, TOC, and kerogen maturity have been investigated. These factors have been assessed via sets of physicochemical measurements such as FTIR (Fourier-Transform Infrared Spectroscopy), XRD (X-Ray Diffraction) analysis, SEM (Scanning Electron Microscopy), and AFM (Atomic Force Microscopy) imaging. Furthermore, the varying thermophysical conditions of pressure and temperature are also investigated.\u0000 The results revealed significant variations in shale initial wettability with Mancos being weakly water-wet while Eagle Ford and Wolf Camp were moderately oil-wet. Moreover, increasing pressure (from 1 MPa to 20 MPa) shifted the wettability of shale rock surfaces towards relatively more oil-wet witnessed by an increase in advancing and receding contact angles. However, no noticeable trend was observed for contact angle variation with temperature. The original wetting behavior of shales is then related to their functional groups and mineralogy. Additionally, shale surfaces witnessed a shift towards a more water-wet state after aging in silica nanofluids at different concentrations.\u0000 Therefore, this paper provides a new approach for examining the complex shale wettability behavior that relies on a combination of HPHT conditions, physicochemical analysis, and image analysis. Importantly, the results suggest that nanofluid can alter shale wettability towards a more water-wet state – thus showing potential for application as a flowback additive in fracturing or ","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77812578","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}
In this paper we propose a method of seismic facies labeling. Seismic facies labeling task consists of assigning specific geological rock types to the pixels in the seismic cube. In our research we use open-source fully annotated 3D geological model of the Netherlands F3 Block. The dataset is divided into training and test cubes. We use the former to train a state-of-the-art deep learning neural network, adding a 3D conditional random field (CRF) layer as a postprocessing step. We apply the pseudo-labeling technique, where the labels of the test dataset are predicted and added to the training set to get more accurate final prediction. To diversify the training dataset, we also apply different types of augmentations, including a domain specific image warping technique. Using the trained network, we predict the facies labels on the test dataset and compute various metrics. The results suggest superior network performance over the existing baseline model.
{"title":"Automatic Neural Network-Based Seismic Facies Classification Using Pseudo-Labels","authors":"Ekaterina V. Tolstaya, A. Egorov","doi":"10.2523/iptc-22084-ms","DOIUrl":"https://doi.org/10.2523/iptc-22084-ms","url":null,"abstract":"\u0000 In this paper we propose a method of seismic facies labeling. Seismic facies labeling task consists of assigning specific geological rock types to the pixels in the seismic cube. In our research we use open-source fully annotated 3D geological model of the Netherlands F3 Block. The dataset is divided into training and test cubes. We use the former to train a state-of-the-art deep learning neural network, adding a 3D conditional random field (CRF) layer as a postprocessing step. We apply the pseudo-labeling technique, where the labels of the test dataset are predicted and added to the training set to get more accurate final prediction. To diversify the training dataset, we also apply different types of augmentations, including a domain specific image warping technique. Using the trained network, we predict the facies labels on the test dataset and compute various metrics. The results suggest superior network performance over the existing baseline model.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79803627","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}
Yunyan Gan, Li Chen, Jinqing Zhang, O. Mullins, Zhenghe Yan, Ji Tian, Xiaofei Gao, Weihua Chen, Haizhang Yang, J. Hao
In South China Sea, about one half of the producing oilfields contain a type of strange and enigmatic oil. First, these waxy crude oils contain almost no solution gas, with bubble points of few atmospheres only. The formation has never been uplifted to very shallow depths to be degassed to that low-level of solution gas. Second, these crude oils also lack of other lighter alkane components up to C12, which, in any event, cannot be removed by a degas process. These crude oils are also not biodegraded with the full complement of n-alkanes heavier than C12, so the lighter n-alkanes have not been removed by this process. There is no credible explanation of these crude oils from maturity considerations either. This kind of reservoir fluid has long been known, however, has not been understood in terms its mechanism of formation. Petroleum system modeling in corresponding basins has not been accurate with regard to these reservoir fluid properties; thereby yielding significant uncertainty in both basin modeling and understanding the oil. This paper introduces a newly identified reservoir forming mechanism, for the first time, to account for these seemingly discordant fluid properties. Central to this new mechanism is "Wax-Out Cryo Trapping". When a crude oil in migration encounters its Wax Appearance Temperature (WAT) along the migration path, the wax can crystallize out of the oil yielding a large, localized wax deposit with associated trapped liquids. It is indeed trapped by the temperature. The mobile, dewaxed fluid phase can continue in migration up either becoming trapped in a separate conventional reservoir or lost via a seep. After continued subsidence, the formation holding the solid wax can heat above WAT thereby remobilizing this formerly frozen oil. This waxy oil can then proceed in migration, possibly along a migration path altered by subsidence. This waxy oil can then fill traps associated with the migration path and remain trapped until present day. The Wax-Out Cryo Trapping process is acting as a compositional fractionator spatially separating the initial waxy oil into its light liquid and gas fractions in one fraction and its waxy and occluded heavier liquids in the other fraction. It is routine to have crude oils undergo the phase transition of gas evolution in migration, but in that case, both phases migrate together. In the Wax-Out Cryo Trapping, there is a solid liquid phase transition with spatial separation based on very different mobilities of solid wax and the dewaxed fluid phase. The paper summarizes the distribution of the waxy "zero-GOR" crude oil in South China Sea and the source rock characteristics. It describes a systematic approach to identify the wax-out process and to rule out other possibilities. This analysis integrated many fluid properties, including PVT, GC, GOR, WAT, and thermal maturity, with hydrocarbon migration and formation bury history from basin modeling. The understanding of this process opens a new wi
{"title":"A Novel Reservoir Forming Mechanism with Wax-Out Cryo Trapping","authors":"Yunyan Gan, Li Chen, Jinqing Zhang, O. Mullins, Zhenghe Yan, Ji Tian, Xiaofei Gao, Weihua Chen, Haizhang Yang, J. Hao","doi":"10.2523/iptc-21918-ms","DOIUrl":"https://doi.org/10.2523/iptc-21918-ms","url":null,"abstract":"\u0000 In South China Sea, about one half of the producing oilfields contain a type of strange and enigmatic oil. First, these waxy crude oils contain almost no solution gas, with bubble points of few atmospheres only. The formation has never been uplifted to very shallow depths to be degassed to that low-level of solution gas. Second, these crude oils also lack of other lighter alkane components up to C12, which, in any event, cannot be removed by a degas process. These crude oils are also not biodegraded with the full complement of n-alkanes heavier than C12, so the lighter n-alkanes have not been removed by this process. There is no credible explanation of these crude oils from maturity considerations either. This kind of reservoir fluid has long been known, however, has not been understood in terms its mechanism of formation. Petroleum system modeling in corresponding basins has not been accurate with regard to these reservoir fluid properties; thereby yielding significant uncertainty in both basin modeling and understanding the oil.\u0000 This paper introduces a newly identified reservoir forming mechanism, for the first time, to account for these seemingly discordant fluid properties. Central to this new mechanism is \"Wax-Out Cryo Trapping\". When a crude oil in migration encounters its Wax Appearance Temperature (WAT) along the migration path, the wax can crystallize out of the oil yielding a large, localized wax deposit with associated trapped liquids. It is indeed trapped by the temperature. The mobile, dewaxed fluid phase can continue in migration up either becoming trapped in a separate conventional reservoir or lost via a seep. After continued subsidence, the formation holding the solid wax can heat above WAT thereby remobilizing this formerly frozen oil. This waxy oil can then proceed in migration, possibly along a migration path altered by subsidence. This waxy oil can then fill traps associated with the migration path and remain trapped until present day. The Wax-Out Cryo Trapping process is acting as a compositional fractionator spatially separating the initial waxy oil into its light liquid and gas fractions in one fraction and its waxy and occluded heavier liquids in the other fraction. It is routine to have crude oils undergo the phase transition of gas evolution in migration, but in that case, both phases migrate together. In the Wax-Out Cryo Trapping, there is a solid liquid phase transition with spatial separation based on very different mobilities of solid wax and the dewaxed fluid phase.\u0000 The paper summarizes the distribution of the waxy \"zero-GOR\" crude oil in South China Sea and the source rock characteristics. It describes a systematic approach to identify the wax-out process and to rule out other possibilities. This analysis integrated many fluid properties, including PVT, GC, GOR, WAT, and thermal maturity, with hydrocarbon migration and formation bury history from basin modeling. The understanding of this process opens a new wi","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"2009 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82591896","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}
In heavily fractured carbonate reservoirs, wells often suffer heavy losses while running lower completion. To avoid any unexpected flow-back, continuous pumping is required. Failure to do this will result in flow-back of the reservoir fluid into the completion string and could reach the surface, leading to a major well control risk. Integrated Pressure Activated Valve (PAV) with Autonomous Inflow Control Valve (AICV) offers a unique solution to manage well control risks, allowing safe deployment of lower completion in such challengeable situations. The PAV module is mounted in series between the screen and AICV housing and will be a part of a lower completion. PAV-AICV system remains closed while RIH, ensuring no fluid can flow through it in either direction. Once the completion reaches the target depth and other pressure-activated completion tools are set/tested, then the PAV is triggered by applying the design pressure in the tubing. PAV will open once activated pressure is reached, and open when the pressure is released, establishing the flow path between the reservoir and tubing via AICV. The qualification test of the AICV-PAV integrated system involves multiple functions and pressure tests. The test results prove the reliability and robustness of the PAV to get activated at the design pressure window. This paper will describe in detail the operating principle along with the testing results of the AICV-PAV system. During the deployment of completion, the AICV-PAV system acts as a well barrier between the reservoir and the completions system and prevents reservoir fluid to enter the completion string. This will result in reducing the well-control risk significantly while deploying the completion string, especially in a fractured or faulted reservoir. Furthermore, this system allows all formation treatment fluids to be fully circulated through the end of the completion string, thus eliminating the requirement of an inner string. Furthermore, it also allows setting liner hanger packer and hydraulically set mechanical packers. This will result in saving rig time in running extra runs and further reducing cost/risks as well as increasing operational efficiency. Once the PAV module is open, it stays in an open position and normal AICV functionality is established. The system is field ready and will be deployed for a major operator in the Middle East. PAV module incorporated with AICV provides pressure integrity in the liner for lower completion installation. This ensures an optimized lower completion installation in challenging situations, especially with well control issues. This paper will describe the newly developed AICV-PAV system operating principle, functionality and discuss in detail the various testing results.
{"title":"Integrated Pressure Activated Valve with Autonomous Inflow Control Valve Technology Minimizes the Deployment Risks in Challenging Well Control Conditions","authors":"M. Abd el-Fattah, C. Nomme, Bjørnar Werswick","doi":"10.2523/iptc-22079-ms","DOIUrl":"https://doi.org/10.2523/iptc-22079-ms","url":null,"abstract":"In heavily fractured carbonate reservoirs, wells often suffer heavy losses while running lower completion. To avoid any unexpected flow-back, continuous pumping is required. Failure to do this will result in flow-back of the reservoir fluid into the completion string and could reach the surface, leading to a major well control risk. Integrated Pressure Activated Valve (PAV) with Autonomous Inflow Control Valve (AICV) offers a unique solution to manage well control risks, allowing safe deployment of lower completion in such challengeable situations.\u0000 The PAV module is mounted in series between the screen and AICV housing and will be a part of a lower completion. PAV-AICV system remains closed while RIH, ensuring no fluid can flow through it in either direction. Once the completion reaches the target depth and other pressure-activated completion tools are set/tested, then the PAV is triggered by applying the design pressure in the tubing. PAV will open once activated pressure is reached, and open when the pressure is released, establishing the flow path between the reservoir and tubing via AICV.\u0000 The qualification test of the AICV-PAV integrated system involves multiple functions and pressure tests. The test results prove the reliability and robustness of the PAV to get activated at the design pressure window. This paper will describe in detail the operating principle along with the testing results of the AICV-PAV system. During the deployment of completion, the AICV-PAV system acts as a well barrier between the reservoir and the completions system and prevents reservoir fluid to enter the completion string. This will result in reducing the well-control risk significantly while deploying the completion string, especially in a fractured or faulted reservoir. Furthermore, this system allows all formation treatment fluids to be fully circulated through the end of the completion string, thus eliminating the requirement of an inner string. Furthermore, it also allows setting liner hanger packer and hydraulically set mechanical packers. This will result in saving rig time in running extra runs and further reducing cost/risks as well as increasing operational efficiency. Once the PAV module is open, it stays in an open position and normal AICV functionality is established. The system is field ready and will be deployed for a major operator in the Middle East.\u0000 PAV module incorporated with AICV provides pressure integrity in the liner for lower completion installation. This ensures an optimized lower completion installation in challenging situations, especially with well control issues. This paper will describe the newly developed AICV-PAV system operating principle, functionality and discuss in detail the various testing results.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81868862","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}
In carbonate acidizing, highly conductive wormholes are created. The process of wormhole formation comprises two major periods: induction and wormholing. The induction period is the time from the first injection of the stimulation fluid to wormhole initiation. The volume of stimulation fluid injected during the induction phase can be more than 30% of the total volume required for the stimulation operation. Minimizing the induction period can significantly reduce the cost and time of matrix acidizing operations. Several series of core-flow experiments are conducted under the same experimental conditions, namely temperature, pressure and flow rate to investigate the effects of changes made to the geometry of the injection face of the core during acid injection. Induced holes, sometimes called notches, of various depths and locations were created into the injection face of Indiana limestone cores to evaluate their impact on the wormholing with 15% wt. HCl. The pore volume to breakthrough (PVBT) of injected acid is obtained with the notched cores are compared with ones recorded with a regular plain core (baseline). The experimental results show that inducing hole in the core can significantly reduce the PVBT of injected acid compared to regular cores. The depth and location of the notch both affect the volume of injected acid as well as the optimal flow rate at which the breackthrough in achived. Shallower notches induced in an optimal location can save about 25% volume of the injected acid while deeper ones can help to reduce the injected acid up to 50%. Moreover, notches can localize the wormhole initiation point. Based on several repeated experimental results, the creation of notch prior to acid injection can optimize a matrix acidizing treatment by reducing the wornmhole induction period and therefore reducing the volume of acid required to achieve equivalent stimulation performance. It also enables more selective treatment placement. The creation of notches in the formation method has been applied to hydraulic fracturing because it generates weak points and reduces the pressure required to fracture the formation, Kayamov et al. 2019, Aidagulov et al. 2016, and 2015. However, this proposed method is the first application in matrix acidizing treatments that demonstrates the impact of face geometry on wormhole generation.
{"title":"Optimizing Carbonate Acid Stimulation by Minimizing Acid Injection Volume with Selective Treatment Placement","authors":"Ziad Sidaoui, M. Abbad","doi":"10.2523/iptc-22489-ea","DOIUrl":"https://doi.org/10.2523/iptc-22489-ea","url":null,"abstract":"\u0000 In carbonate acidizing, highly conductive wormholes are created. The process of wormhole formation comprises two major periods: induction and wormholing. The induction period is the time from the first injection of the stimulation fluid to wormhole initiation. The volume of stimulation fluid injected during the induction phase can be more than 30% of the total volume required for the stimulation operation. Minimizing the induction period can significantly reduce the cost and time of matrix acidizing operations.\u0000 Several series of core-flow experiments are conducted under the same experimental conditions, namely temperature, pressure and flow rate to investigate the effects of changes made to the geometry of the injection face of the core during acid injection. Induced holes, sometimes called notches, of various depths and locations were created into the injection face of Indiana limestone cores to evaluate their impact on the wormholing with 15% wt. HCl. The pore volume to breakthrough (PVBT) of injected acid is obtained with the notched cores are compared with ones recorded with a regular plain core (baseline).\u0000 The experimental results show that inducing hole in the core can significantly reduce the PVBT of injected acid compared to regular cores. The depth and location of the notch both affect the volume of injected acid as well as the optimal flow rate at which the breackthrough in achived. Shallower notches induced in an optimal location can save about 25% volume of the injected acid while deeper ones can help to reduce the injected acid up to 50%.\u0000 Moreover, notches can localize the wormhole initiation point. Based on several repeated experimental results, the creation of notch prior to acid injection can optimize a matrix acidizing treatment by reducing the wornmhole induction period and therefore reducing the volume of acid required to achieve equivalent stimulation performance. It also enables more selective treatment placement.\u0000 The creation of notches in the formation method has been applied to hydraulic fracturing because it generates weak points and reduces the pressure required to fracture the formation, Kayamov et al. 2019, Aidagulov et al. 2016, and 2015. However, this proposed method is the first application in matrix acidizing treatments that demonstrates the impact of face geometry on wormhole generation.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87484437","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 details a new rigless technique combining water shut-off operation and adding more inflow ports (perfs) in horizontal oil wells completed with inflow control devices (ICDs). The water production is reduced by mechanical isolation of the ICDs producing high water, while well productivity after water shut-off is enhanced by adding ports across dry oil (0% water cut) and/or excellent oil potential compartments. The paper provides workflow for identifying water shut-off compartments and methods to create new ports. Electric-line conveyed tubing sidewall milling tool was found the safe-solution to add ports along non-cemented blank pipe of the ICD completion. Once an ICD well is identified for a water shut-off, production logging is conducted to identify the production phase and water cut across all ICDs compartments. Well modeling using PLT log results is constructed to evaluate shutting off the identified high water cut compartments as well as evaluate oil production by the remaining ICDs and gains by adding ports. Depending on water entries locations, water shut-off in ICD wells can be performed using bridge plugs or expandable clads. As the well productivity is reduced by isolating some compartments for water shut-off, adding ports in the remaining compartments releases ICD flow restrictions and enhance the productivity. These ports are orders of magnitude bigger than the ICDs and allow unrestricted flow from the excellent oil potential compartments. This integrated process was successfully implemented in two horizontal oil wells with ICDs. Same intervention operations were conducted for both wells, watered out compartments were isolated and new ports were machined along compartments identified for excellent oil potential. The water cut has dropped by (27-36%) with sustained oil gains more than twice compared to pre-job performance. Such rigless combined operations are proven to be an effective solution to improve well performance at least cost. Setting plug minimizes water production, while adding inflow ports increase oil production rate. A review of the published literature indicates that this is the first instance of this integrated solution. While there are several papers about the benefits of ICDs, there are no papers covering the processes presented in this paper. The processes and methods presented could be a reference for rigless well intervention for ICD wells to reduce water production while increasing oil production rate.
{"title":"New Concept of Adding Inflow Points Across ICDs in Horizontal Wells to Improve Oil Production Performance","authors":"Ahmed A. Al Sulaiman, S. Jacob","doi":"10.2523/iptc-22688-ms","DOIUrl":"https://doi.org/10.2523/iptc-22688-ms","url":null,"abstract":"\u0000 This paper details a new rigless technique combining water shut-off operation and adding more inflow ports (perfs) in horizontal oil wells completed with inflow control devices (ICDs). The water production is reduced by mechanical isolation of the ICDs producing high water, while well productivity after water shut-off is enhanced by adding ports across dry oil (0% water cut) and/or excellent oil potential compartments. The paper provides workflow for identifying water shut-off compartments and methods to create new ports. Electric-line conveyed tubing sidewall milling tool was found the safe-solution to add ports along non-cemented blank pipe of the ICD completion.\u0000 Once an ICD well is identified for a water shut-off, production logging is conducted to identify the production phase and water cut across all ICDs compartments. Well modeling using PLT log results is constructed to evaluate shutting off the identified high water cut compartments as well as evaluate oil production by the remaining ICDs and gains by adding ports. Depending on water entries locations, water shut-off in ICD wells can be performed using bridge plugs or expandable clads. As the well productivity is reduced by isolating some compartments for water shut-off, adding ports in the remaining compartments releases ICD flow restrictions and enhance the productivity. These ports are orders of magnitude bigger than the ICDs and allow unrestricted flow from the excellent oil potential compartments.\u0000 This integrated process was successfully implemented in two horizontal oil wells with ICDs. Same intervention operations were conducted for both wells, watered out compartments were isolated and new ports were machined along compartments identified for excellent oil potential. The water cut has dropped by (27-36%) with sustained oil gains more than twice compared to pre-job performance. Such rigless combined operations are proven to be an effective solution to improve well performance at least cost. Setting plug minimizes water production, while adding inflow ports increase oil production rate.\u0000 A review of the published literature indicates that this is the first instance of this integrated solution. While there are several papers about the benefits of ICDs, there are no papers covering the processes presented in this paper. The processes and methods presented could be a reference for rigless well intervention for ICD wells to reduce water production while increasing oil production rate.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74983773","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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