The aim of this work is the development of a fast and reliable method for geomechanical parameters evaluation while drilling using surface logging data. Geomechanical parameters are usually evaluated from cores or sonic logs, which are typically expensive and sometimes difficult to obtain. A novel approach is here proposed, where machine learning algorithms are used to calculate the Young's Modulus from drilling parameters and the gamma ray log. The proposed method combines typical mud logging drilling data (ROP, RPM, Torque, Flow measurements, WOB and SPP), XRF data and well log data (Sonic logs, Bulk Density, Gamma Ray) with several machine learning techniques. The models were trained and tested on data coming from three wells drilled in the same basin in Kuwait, in the same geological units but in different reservoirs. Sonic logs and bulk density are used to evaluate the geomechanical parameters (e.g. Young's Modulus) and to train the model. The training phase and the hyperparameter tuning were performed using data coming from a single well. The model was then tested against previously unseen data coming from the other two wells. The trained model is able to predict the Young's modulus in the test wells with a root mean squared error around 12 GPa. The example here provided demonstrates that a model trained with drilling parameters and gamma ray coming from one well is able to predict the Young Modulus of different wells in the same basin. These outcomes highlight the potentiality of this procedure and point out several implications for the reservoir characterization. Indeed, once the model has been trained, it is possible to predict the Young's Modulus in different wells of the same basin using only surface logging data.
{"title":"Predict Geomechanical Parameters with Machine Learning Combining Drilling Data and Gamma Ray","authors":"M. Martinelli, I. Colombo, E. Russo","doi":"10.2118/204688-ms","DOIUrl":"https://doi.org/10.2118/204688-ms","url":null,"abstract":"\u0000 The aim of this work is the development of a fast and reliable method for geomechanical parameters evaluation while drilling using surface logging data. Geomechanical parameters are usually evaluated from cores or sonic logs, which are typically expensive and sometimes difficult to obtain. A novel approach is here proposed, where machine learning algorithms are used to calculate the Young's Modulus from drilling parameters and the gamma ray log. The proposed method combines typical mud logging drilling data (ROP, RPM, Torque, Flow measurements, WOB and SPP), XRF data and well log data (Sonic logs, Bulk Density, Gamma Ray) with several machine learning techniques. The models were trained and tested on data coming from three wells drilled in the same basin in Kuwait, in the same geological units but in different reservoirs. Sonic logs and bulk density are used to evaluate the geomechanical parameters (e.g. Young's Modulus) and to train the model. The training phase and the hyperparameter tuning were performed using data coming from a single well. The model was then tested against previously unseen data coming from the other two wells.\u0000 The trained model is able to predict the Young's modulus in the test wells with a root mean squared error around 12 GPa. The example here provided demonstrates that a model trained with drilling parameters and gamma ray coming from one well is able to predict the Young Modulus of different wells in the same basin. These outcomes highlight the potentiality of this procedure and point out several implications for the reservoir characterization. Indeed, once the model has been trained, it is possible to predict the Young's Modulus in different wells of the same basin using only surface logging data.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82603101","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. Batarseh, S. Mutairi, D. P. San Roman Alerigi, Abdullah Al Harith
The objective of this work is to provide an overview of high power laser program since it is inception and to provide the strategy to make it reality. An overview of the past two decades, current and future plan to deploy the technology in the field. Laser attracted the oil and gas industry as an innovative non-damaging technology and alternatives to current practices. The lab success conducted over the past 20 years performing experiments on thousands of representative rock samples proved the key parameter for successful laser operation in the field. The technology is not only a non-damaging but also improves flow properties and communication between the wellbore and the hydrocarbon bearing formation. For the past two decades, researchers attempted to deploy high power laser technology for several downhole applications due to its unique properties such as accuracy, precision, and power. The power of the earlier laser generation was insufficient to penetrate subsurface formations. Recent advancement in the high power laser technology generates new and evolved systems that are more compact, efficient, and cost effective for downhole applications. Thousands of rocks have been exposed to high power lasers radiations for several downhole applications such as perforation, drilling and heating. The success of the technology demonstrated that in all rock types, the flow properties were enhanced regardless of their compressive strength and hardness. Laser also has unique futures such as the precision in controlling and orienting the energy in any direction regardless of the reservoir stress orientation and magnitude. The beam is generated at the surface and delivered downhole via fiber optics cable, it can be targeted directly to the pay zone to enable production from challenging zones that cannot and could not be achieved with current technology. The technology provides small footprint and environmentally friendly technology, it provides waterless technology as an alternative to water base fracturing technology.
{"title":"Laser Technology for Downhole Applications; Past, Present and Future","authors":"S. Batarseh, S. Mutairi, D. P. San Roman Alerigi, Abdullah Al Harith","doi":"10.2118/204661-ms","DOIUrl":"https://doi.org/10.2118/204661-ms","url":null,"abstract":"\u0000 The objective of this work is to provide an overview of high power laser program since it is inception and to provide the strategy to make it reality. An overview of the past two decades, current and future plan to deploy the technology in the field.\u0000 Laser attracted the oil and gas industry as an innovative non-damaging technology and alternatives to current practices. The lab success conducted over the past 20 years performing experiments on thousands of representative rock samples proved the key parameter for successful laser operation in the field. The technology is not only a non-damaging but also improves flow properties and communication between the wellbore and the hydrocarbon bearing formation.\u0000 For the past two decades, researchers attempted to deploy high power laser technology for several downhole applications due to its unique properties such as accuracy, precision, and power. The power of the earlier laser generation was insufficient to penetrate subsurface formations. Recent advancement in the high power laser technology generates new and evolved systems that are more compact, efficient, and cost effective for downhole applications.\u0000 Thousands of rocks have been exposed to high power lasers radiations for several downhole applications such as perforation, drilling and heating. The success of the technology demonstrated that in all rock types, the flow properties were enhanced regardless of their compressive strength and hardness. Laser also has unique futures such as the precision in controlling and orienting the energy in any direction regardless of the reservoir stress orientation and magnitude. The beam is generated at the surface and delivered downhole via fiber optics cable, it can be targeted directly to the pay zone to enable production from challenging zones that cannot and could not be achieved with current technology. The technology provides small footprint and environmentally friendly technology, it provides waterless technology as an alternative to water base fracturing technology.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85209058","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}
Fracture characterization, including permeability and deformation due to fluid flow, plays an essential role in hydrocarbon production during the development of naturally fractured reservoirs. The conventional way of characterization of the fracture is experimental, and modeling approaches. In this study, a conceptual model will be developed based on the structural style to study the fracture distributions, the influence of the fluid flow and geomechanics in the fracture conductivity, investigate the stress regime in the study area. Understanding the fracture properties will be conducted by studying the fracture properties from the core sample, image log interpretation. 3D geomechanical models will be constructed to evaluate the fluid flow properties; the models consider the crossflow coefficient and the compression coefficient. According to the model results, the fracture permeability decreases with increasing effective stress. The degree of decline is related to the crossflow coefficient and the compression coefficient. Most of these reservoirs are mainly composed of two porosity systems for fluid flow: the matrix component and fractures. Therefore, fluid flow path distribution within a naturally fractured reservoir depends on several features related to the rock matrix and fracture systems' properties. The main element that could help us identify the fluid flow paths is the critical stress analysis, which considers the in-situ stress regime model (in terms of magnitude and direction) and the spatial distributions of natural fractures fluid flow path. The critical stress requires calculating the normal and shear stress in each fracture plane to evaluate the conditions for critical and non-critical fractures. Based on this classification, some fractures can dominate the fluid-flow paths. To perform the critical stress analysis, fracture characterization and stress analysis were described using a 3D stress tensor model capturing the in-situ stress direction and magnitude applied to a discrete fracture model, identifying the fluid flow paths along the fractured reservoir. The results show that in-situ stress rotation observed in the breakouts or drilling induce tensile fractures (DITFs) interpreted from borehole images. The stress regime changes are probably attributed to some influence of deeply seated faults under the studied sequence. the flow of water-oil ratio through intact rock and fractures with/without imbibition was modeled based on the material balance based on preset conceptual reservoir parameters to investigate the water-oil ratio flow gradients
{"title":"Characterization of Critically Stressed Fractures Using Fluid-Flow Models for Naturally Fractured Reservoirs","authors":"O. Hamid, Reza Sanee, Gbenga Folorunso Oluyemi","doi":"10.2118/204903-ms","DOIUrl":"https://doi.org/10.2118/204903-ms","url":null,"abstract":"\u0000 Fracture characterization, including permeability and deformation due to fluid flow, plays an essential role in hydrocarbon production during the development of naturally fractured reservoirs. The conventional way of characterization of the fracture is experimental, and modeling approaches. In this study, a conceptual model will be developed based on the structural style to study the fracture distributions, the influence of the fluid flow and geomechanics in the fracture conductivity, investigate the stress regime in the study area.\u0000 Understanding the fracture properties will be conducted by studying the fracture properties from the core sample, image log interpretation. 3D geomechanical models will be constructed to evaluate the fluid flow properties; the models consider the crossflow coefficient and the compression coefficient. According to the model results, the fracture permeability decreases with increasing effective stress. The degree of decline is related to the crossflow coefficient and the compression coefficient. Most of these reservoirs are mainly composed of two porosity systems for fluid flow: the matrix component and fractures. Therefore, fluid flow path distribution within a naturally fractured reservoir depends on several features related to the rock matrix and fracture systems' properties.\u0000 The main element that could help us identify the fluid flow paths is the critical stress analysis, which considers the in-situ stress regime model (in terms of magnitude and direction) and the spatial distributions of natural fractures fluid flow path. The critical stress requires calculating the normal and shear stress in each fracture plane to evaluate the conditions for critical and non-critical fractures. Based on this classification, some fractures can dominate the fluid-flow paths.\u0000 To perform the critical stress analysis, fracture characterization and stress analysis were described using a 3D stress tensor model capturing the in-situ stress direction and magnitude applied to a discrete fracture model, identifying the fluid flow paths along the fractured reservoir.\u0000 The results show that in-situ stress rotation observed in the breakouts or drilling induce tensile fractures (DITFs) interpreted from borehole images.\u0000 The stress regime changes are probably attributed to some influence of deeply seated faults under the studied sequence. the flow of water-oil ratio through intact rock and fractures with/without imbibition was modeled based on the material balance based on preset conceptual reservoir parameters to investigate the water-oil ratio flow gradients","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88440510","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 maturation of many oilfields, further well abandonments will occur in the years to come. There are issues about improper well abandonment that can have far-reaching effects for responsible companies or entities. At this time in the US, where most of the operation is operated by non-government entities, sometimes the sovereign state may end up covering the cost of well abandonment when the operator is not financially capable in managing such costs. That will be a burden to the public taxpayers. In this paper, we review an important aspect of the well abandonment practices and at present, based on a reservoir modeling approach, more clearance on the potential formation of free gas that can be a cause of concern. We also discuss the integrity issues of the sealing process. We point out how the development of cracks caused by many factors, including geomechanical effects or slow deterioration of the cement seal, in the long run, may result in generating escape paths for the evolved hydrocarbon gases.
{"title":"Reservoir Engineering and Geomechanical Aspects of Well Plugging and Abandonment","authors":"Q. Qi, Khoja Ghaliah, I. Ershaghi","doi":"10.2118/204710-ms","DOIUrl":"https://doi.org/10.2118/204710-ms","url":null,"abstract":"\u0000 With the maturation of many oilfields, further well abandonments will occur in the years to come. There are issues about improper well abandonment that can have far-reaching effects for responsible companies or entities. At this time in the US, where most of the operation is operated by non-government entities, sometimes the sovereign state may end up covering the cost of well abandonment when the operator is not financially capable in managing such costs. That will be a burden to the public taxpayers. In this paper, we review an important aspect of the well abandonment practices and at present, based on a reservoir modeling approach, more clearance on the potential formation of free gas that can be a cause of concern. We also discuss the integrity issues of the sealing process. We point out how the development of cracks caused by many factors, including geomechanical effects or slow deterioration of the cement seal, in the long run, may result in generating escape paths for the evolved hydrocarbon gases.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87561654","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. Desouky, Zeeshan Tariq, Murtada Al jawad, Hamed Alhoori, M. Mahmoud, A. Abdulraheem
Propped hydraulic fracturing is a stimulation technique used in tight formations to create conductive fractures. To predict the fractured well productivity, the conductivity of those propped fractures should be estimated. It is common to measure the conductivity of propped fractures in the laboratory under controlled conditions. Nonetheless, it is costly and time-consuming which encouraged developing many empirical and analytical propped fracture conductivity models. Previous empirical models, however, were based on limited datasets producing questionable correlations. We propose herein new empirical models based on an extensive data set utilizing machine learning (ML) methods. In this study, an artificial neural network (ANN) was utilized. A dataset comprised of 351 data points of propped hydraulic fracture experiments on different shale types with different mineralogy under various confining stresses was collected and studied. Several statistical and data science approaches such as box and whisker plots, correlation crossplots, and Z-score techniques were used to remove the outliers and extreme data points. The performance of the developed model was evaluated using powerful metrics such as correlation coefficient and root mean squared error. After several executions and function evaluations, an ANN was found to be the best technique to predict propped fracture conductivity for different mineralogy. The proposed ANN models resulted in less than 7% error between actual and predicted values. In this study, in addition to the development of an optimized ANN model, explicit empirical correlations are also extracted from the weights and biases of the fine-tuned model. The proposed model of propped fracture conductivity was then compared with the commonly available correlations. The results revealed that the proposed mineralogy based propped fracture conductivity models made the predictions with a high correlation coefficient of 94%. This work clearly shows the potential of computer-based ML techniques in the determination of mineralogy based propped fracture conductivity. The proposed empirical correlation can be implemented without requiring any ML-based software.
{"title":"Development of Machine Learning Based Propped Fracture Conductivity Correlations in Shale Formations","authors":"M. Desouky, Zeeshan Tariq, Murtada Al jawad, Hamed Alhoori, M. Mahmoud, A. Abdulraheem","doi":"10.2118/204606-ms","DOIUrl":"https://doi.org/10.2118/204606-ms","url":null,"abstract":"\u0000 Propped hydraulic fracturing is a stimulation technique used in tight formations to create conductive fractures. To predict the fractured well productivity, the conductivity of those propped fractures should be estimated. It is common to measure the conductivity of propped fractures in the laboratory under controlled conditions. Nonetheless, it is costly and time-consuming which encouraged developing many empirical and analytical propped fracture conductivity models. Previous empirical models, however, were based on limited datasets producing questionable correlations. We propose herein new empirical models based on an extensive data set utilizing machine learning (ML) methods.\u0000 In this study, an artificial neural network (ANN) was utilized. A dataset comprised of 351 data points of propped hydraulic fracture experiments on different shale types with different mineralogy under various confining stresses was collected and studied. Several statistical and data science approaches such as box and whisker plots, correlation crossplots, and Z-score techniques were used to remove the outliers and extreme data points. The performance of the developed model was evaluated using powerful metrics such as correlation coefficient and root mean squared error.\u0000 After several executions and function evaluations, an ANN was found to be the best technique to predict propped fracture conductivity for different mineralogy. The proposed ANN models resulted in less than 7% error between actual and predicted values. In this study, in addition to the development of an optimized ANN model, explicit empirical correlations are also extracted from the weights and biases of the fine-tuned model. The proposed model of propped fracture conductivity was then compared with the commonly available correlations. The results revealed that the proposed mineralogy based propped fracture conductivity models made the predictions with a high correlation coefficient of 94%.\u0000 This work clearly shows the potential of computer-based ML techniques in the determination of mineralogy based propped fracture conductivity. The proposed empirical correlation can be implemented without requiring any ML-based software.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91020289","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}
N. Leseur, A. Mendez, M. Baig, Pierre-Olivier Goiran
A practical example of a theory-guided data science case study is presented to evaluate the potential of the Diyab formation, an Upper Jurassic interval, source rock of some of the largest reservoirs in the Arabian Peninsula. A workflow base on a three-step approach combining the physics of logging tool response and a probabilistic machine-learning algorithm was undertaken to evaluate four wells of the prospect. At first, a core-calibrated multi-mineral model was established on a concept well for which an extensive suite of logs and core measurements had been acquired. To transfer the knowledge gained from the latter physics-driven interpretation onto the other data-scarce wells, the relationship between the output rock and fluid volumes and their input log responses was then learned by means of a Gaussian Process Regression (GPR). Finally, once trained on the key well, the latter probabilistic algorithm was deployed on the three remaining wells to predict reservoir properties, quantify resource potential and estimate volumetric-related uncertainties. The physics-informed machine-learning approach introduced in this work was found to provide results which matches with the majority of the available core data, while discrepancies could generally be explained by the occurrence of laminations which thickness are under the resolution of nuclear logs. Overall, the GPR approach seems to enable an efficient transfer of knowledge from data-rich key wells to other data-scarce wells. As opposed to a more conventional formation evaluation process which is carried out more independently from the key well, the present approach ensures that the final petrophysical interpretation reflects and benefits from the insights and the physics-driven coherency achieved at key well location.
{"title":"Theory-Guided Data Science, A Petrophysical Case Study from the Diyab Formation","authors":"N. Leseur, A. Mendez, M. Baig, Pierre-Olivier Goiran","doi":"10.2118/204532-ms","DOIUrl":"https://doi.org/10.2118/204532-ms","url":null,"abstract":"\u0000 A practical example of a theory-guided data science case study is presented to evaluate the potential of the Diyab formation, an Upper Jurassic interval, source rock of some of the largest reservoirs in the Arabian Peninsula.\u0000 A workflow base on a three-step approach combining the physics of logging tool response and a probabilistic machine-learning algorithm was undertaken to evaluate four wells of the prospect. At first, a core-calibrated multi-mineral model was established on a concept well for which an extensive suite of logs and core measurements had been acquired. To transfer the knowledge gained from the latter physics-driven interpretation onto the other data-scarce wells, the relationship between the output rock and fluid volumes and their input log responses was then learned by means of a Gaussian Process Regression (GPR). Finally, once trained on the key well, the latter probabilistic algorithm was deployed on the three remaining wells to predict reservoir properties, quantify resource potential and estimate volumetric-related uncertainties. The physics-informed machine-learning approach introduced in this work was found to provide results which matches with the majority of the available core data, while discrepancies could generally be explained by the occurrence of laminations which thickness are under the resolution of nuclear logs.\u0000 Overall, the GPR approach seems to enable an efficient transfer of knowledge from data-rich key wells to other data-scarce wells. As opposed to a more conventional formation evaluation process which is carried out more independently from the key well, the present approach ensures that the final petrophysical interpretation reflects and benefits from the insights and the physics-driven coherency achieved at key well location.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86891910","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}
Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved. Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of "plugging large pore and leave the small one open", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed. Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced. Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.
{"title":"Study on the Oil Displacement Effect and Application of Soft Microgel Flooding Technology","authors":"Jian Zhang, Zhe Sun, Xiujun Wang, Xiaodong Kang","doi":"10.2118/204764-ms","DOIUrl":"https://doi.org/10.2118/204764-ms","url":null,"abstract":"\u0000 Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved.\u0000 Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of \"plugging large pore and leave the small one open\", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed.\u0000 Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced.\u0000 Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"317 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76989428","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}
Hong Chang, De Qiang Yi, Yang Lv, Ming Zhao, Pengyun Cao, Lin Zhang, Rui Hou, Yiliang Di, Jie Chen, Lu Zhang, Haoyan Li, Yunlong Fu, Yuan Liu, W. Wang
Effective stage-to-stage isolation is typically accomplished by setting a bridge plug in a properly cemented casing between stages. This isolation plays a vital role in a horizontal well multistage fracturing completion. Failure of isolation not only impacts the well productivity but also wastes fracturing materials. The challenges isolation failure poses for stimulation effectiveness include both detection and remediation. First, there has been historically no reliable and cost-effective solution to detect stage-to-stage isolation onsite. One may only start to realize this problem when inconsistent production is observed. Second, existing remedial actions are seldom satisfying in case of an isolation failure. Most commonly, a new plug is set to replace the failed one. However, because the perforation clusters of an unstimulated stage may create irregularities in well inside diameter (ID) (e.g., casing deformation or burr), there is a risk that the plug will be damaged or become stuck when it passes the perforation area. Also, when the plug passes a perforation cluster, the perforations start to take in the pump-down fluid, which can increase the difficulty of the pump-down job. A novel remedial action uses high-frequency pressure monitoring (HFPM) and diversion to solve both challenges. The stage isolation integrity is evaluated in quasi-real time by analyzing the water hammer after the pump shutdown. In the case of a plug failure, large-particle fracture diversion materials and techniques can establish temporary wellbore isolation through a quick and simple delivery process. To close the cycle, the effect of the diversion can be evaluated by HFPM, which can reveal the fluid entry point of the treatment fluid after diversion. The technique was applied to two cases in Ordos basin in which wellbore isolation failure interrupted the operation. The problem identification, development of the solution workflow, and observation from treatment analysis are discussed. In both cases, the stage-to-stage isolation was recovered, and the drilled sand body was successfully stimulated without involving costly and time-consuming well intervention. The stimulation operation of the entire well was successfully resumed in a timely manner.
{"title":"Outside the Box: Innovative Application of Diversion as a Replacement for Bridge Plug","authors":"Hong Chang, De Qiang Yi, Yang Lv, Ming Zhao, Pengyun Cao, Lin Zhang, Rui Hou, Yiliang Di, Jie Chen, Lu Zhang, Haoyan Li, Yunlong Fu, Yuan Liu, W. Wang","doi":"10.2118/204601-ms","DOIUrl":"https://doi.org/10.2118/204601-ms","url":null,"abstract":"\u0000 Effective stage-to-stage isolation is typically accomplished by setting a bridge plug in a properly cemented casing between stages. This isolation plays a vital role in a horizontal well multistage fracturing completion. Failure of isolation not only impacts the well productivity but also wastes fracturing materials.\u0000 The challenges isolation failure poses for stimulation effectiveness include both detection and remediation. First, there has been historically no reliable and cost-effective solution to detect stage-to-stage isolation onsite. One may only start to realize this problem when inconsistent production is observed. Second, existing remedial actions are seldom satisfying in case of an isolation failure. Most commonly, a new plug is set to replace the failed one. However, because the perforation clusters of an unstimulated stage may create irregularities in well inside diameter (ID) (e.g., casing deformation or burr), there is a risk that the plug will be damaged or become stuck when it passes the perforation area. Also, when the plug passes a perforation cluster, the perforations start to take in the pump-down fluid, which can increase the difficulty of the pump-down job.\u0000 A novel remedial action uses high-frequency pressure monitoring (HFPM) and diversion to solve both challenges. The stage isolation integrity is evaluated in quasi-real time by analyzing the water hammer after the pump shutdown. In the case of a plug failure, large-particle fracture diversion materials and techniques can establish temporary wellbore isolation through a quick and simple delivery process. To close the cycle, the effect of the diversion can be evaluated by HFPM, which can reveal the fluid entry point of the treatment fluid after diversion.\u0000 The technique was applied to two cases in Ordos basin in which wellbore isolation failure interrupted the operation. The problem identification, development of the solution workflow, and observation from treatment analysis are discussed. In both cases, the stage-to-stage isolation was recovered, and the drilled sand body was successfully stimulated without involving costly and time-consuming well intervention. The stimulation operation of the entire well was successfully resumed in a timely manner.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"107 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74978923","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}
Qianhui Wu, J. Ge, L. Ding, Kaipeng Wei, Yuelong Liu, Xu-ling Deng
The wide existence of fractures makes conformance control by polymer gels more challenging in water-flooded oil reservoirs. Selection of an applicable gel system and design of an intelligent approach for gel treatment are key components for a successful field application. Moreover, selecting the candidate wells and determining the injection volume of gel are also critical to the success of gel treatments. A gel system with adjustable polymer concentrations was applied for conformance control in fractured tight sandstone reservoir, and notably, less than 5% of syneresis was detected after aging for one year at reservoir condition. The viscosity and the gelation time of this gel system can be adjusted according to the targeted reservoir conditions. The pilot test was conducted in Huabei oilfield (China), and the oil recovery after water flooding was only about 20% original oil in place (OOIP). With further exploitation of the oil field, the majority of the reservoir has suffered from poor sweep efficiency and extremely high water cuts. To characterize the distribution of fractures, the seismic coherence cube was utilized. In addition, the pressure transient test, interwell tracer test and the injection-production data were used collaboratively to determine the volume of fractures in the reservoir. The option of gel formulation and the determination of operational parameters are mainly based on the wellhead pressure. According to the seismic coherence cube, the zone of candidate well group shows a weak coherence state, indicating that numerous fractures exist. Furthermore, there is good continuity between the candidate injection well and the production well. According to the pressure transient test, the volume of re-open fracture is about 1730.9 m3, while the volume of micro-fracture is about 4839.4 m3. Comparably, based on the interwell tracer test, the estimated volume of fractures is approximately 3219.7 m3. Consequently, the designed volume of gel for treatment is 1500.0 m3 in total. The properties of gel slugs were carefully designed, which was tailored to the specific wellbore conditions and formation characteristics. Three months after the gel treatment, the average oil production was increased from 0.36 t/d to 0.9 t/d, and the water cut was decreased from 95.77% to 88.7%. The improved oil production was still benefited from this gel treatment after one year. This study provides a comprehensive approach, from optimization of gel formulation, followed by selection of candidate wells, to calculation of the injected volume, to design the viable operational parameters, for gel treatment field application in fractured reservoirs. It shows that, besides a gel system with superior properties, a suitable injected volume of gel may enhance the chance of success for gel treatments.
{"title":"A Successful Field Application of Polymer Gel for Water Shutoff in a Fractured Tight Sandstone Reservoir","authors":"Qianhui Wu, J. Ge, L. Ding, Kaipeng Wei, Yuelong Liu, Xu-ling Deng","doi":"10.2118/204741-ms","DOIUrl":"https://doi.org/10.2118/204741-ms","url":null,"abstract":"\u0000 The wide existence of fractures makes conformance control by polymer gels more challenging in water-flooded oil reservoirs. Selection of an applicable gel system and design of an intelligent approach for gel treatment are key components for a successful field application. Moreover, selecting the candidate wells and determining the injection volume of gel are also critical to the success of gel treatments.\u0000 A gel system with adjustable polymer concentrations was applied for conformance control in fractured tight sandstone reservoir, and notably, less than 5% of syneresis was detected after aging for one year at reservoir condition. The viscosity and the gelation time of this gel system can be adjusted according to the targeted reservoir conditions. The pilot test was conducted in Huabei oilfield (China), and the oil recovery after water flooding was only about 20% original oil in place (OOIP). With further exploitation of the oil field, the majority of the reservoir has suffered from poor sweep efficiency and extremely high water cuts. To characterize the distribution of fractures, the seismic coherence cube was utilized. In addition, the pressure transient test, interwell tracer test and the injection-production data were used collaboratively to determine the volume of fractures in the reservoir. The option of gel formulation and the determination of operational parameters are mainly based on the wellhead pressure.\u0000 According to the seismic coherence cube, the zone of candidate well group shows a weak coherence state, indicating that numerous fractures exist. Furthermore, there is good continuity between the candidate injection well and the production well. According to the pressure transient test, the volume of re-open fracture is about 1730.9 m3, while the volume of micro-fracture is about 4839.4 m3. Comparably, based on the interwell tracer test, the estimated volume of fractures is approximately 3219.7 m3. Consequently, the designed volume of gel for treatment is 1500.0 m3 in total. The properties of gel slugs were carefully designed, which was tailored to the specific wellbore conditions and formation characteristics. Three months after the gel treatment, the average oil production was increased from 0.36 t/d to 0.9 t/d, and the water cut was decreased from 95.77% to 88.7%. The improved oil production was still benefited from this gel treatment after one year.\u0000 This study provides a comprehensive approach, from optimization of gel formulation, followed by selection of candidate wells, to calculation of the injected volume, to design the viable operational parameters, for gel treatment field application in fractured reservoirs. It shows that, besides a gel system with superior properties, a suitable injected volume of gel may enhance the chance of success for gel treatments.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77703657","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}
Muneer Al Noumani, Younis Al Masoudi, M.M. Al Mamari, Yaqdhan Khalfan Al Rawahi, Mohammed Al Yaarubi, Safa Al Nabhani, I. Cameron, David Knox, Roberto Peralta, Emmanuel Thérond
For many years, the oil and gas industry has deployed techniques which enhance formation strength via the successful propping and plugging of induced fractures. Induced fracture sizes have been successfully treated using this method up to the 600 – 1,100-micron range. Static wellbore strengthening techniques are commonly deployed to cover 1,000 micron and all fracture size risks underneath. The deployment of wellbore strengthening techniques has historically been confined to permeable formations. In most cases, wellbore strengthening has been deployed to operationally challenging sand fracture gradients or, where boundaries are pushed, lower ranges of permeability, such as silts. The subject of wellbore strengthening in shales or carbonates to this day, remains a challenge for the industry, with very few documented success stories or evidence of sustained ability to enhance fracture gradient across a drilling campaign. This paper covers the history of lost circulation events which have been reported in the Khazzan/Ghazeer field in the carbonate Habshan formation. It also describes the design changes which were introduced to strengthen the rock and enable circulation/returns, during liner cementation. The design work built on experience applying wellbore strengthening techniques in carbonates in the Norwegian sector of the North Sea. This work is also summarized in this paper. The Habshan carbonate formation in Oman presents a lost circulation challenge through an ‘induced’ fracture risk. Since the beginning of the drilling campaign in the Khazzan/Ghazeer field, the Habshan formation has repeatedly experienced induced mud losses during well activities such as liner running, mud conditioning with liner on bottom and cementing, when the formation is exposed to higher pressures, less so during drilling. The Habshan challenge in Oman has led to regular, significant lost circulation events during cement placement, adding operational cost and more importantly, presenting difficulties around meeting zonal isolation objectives. Through previous field experience in Norway, a set of criteria was developed to qualify a standard pill approach to carbonate strengthening. The currently deployed strategy is designed to address both the risk of induced fracture by propping and plugging (wellbore strengthening) and provide some ability to seal natural fractures which are often encountered with carbonates, or similarly flawed rocks. The strategy deployed aims to cover these two risks with a blanket approach to lost circulation risk in carbonates. The success of this approach is demonstrated using well performance data from a total of 43 wells drilled before and after the introduction of the wellbore strengthening strategy. As it was initially assumed that wellbore strengthening could not be applied to carbonate formations, other techniques had been tried to prevent lost circulation. Those techniques provided mixed results. Since the implementation of wellb
{"title":"Application of Wellbore Strengthening Techniques in Carbonate Formation Solves Lost Circulation Challenges During Liner Running and Cementing","authors":"Muneer Al Noumani, Younis Al Masoudi, M.M. Al Mamari, Yaqdhan Khalfan Al Rawahi, Mohammed Al Yaarubi, Safa Al Nabhani, I. Cameron, David Knox, Roberto Peralta, Emmanuel Thérond","doi":"10.2118/204594-ms","DOIUrl":"https://doi.org/10.2118/204594-ms","url":null,"abstract":"\u0000 For many years, the oil and gas industry has deployed techniques which enhance formation strength via the successful propping and plugging of induced fractures. Induced fracture sizes have been successfully treated using this method up to the 600 – 1,100-micron range. Static wellbore strengthening techniques are commonly deployed to cover 1,000 micron and all fracture size risks underneath.\u0000 The deployment of wellbore strengthening techniques has historically been confined to permeable formations. In most cases, wellbore strengthening has been deployed to operationally challenging sand fracture gradients or, where boundaries are pushed, lower ranges of permeability, such as silts. The subject of wellbore strengthening in shales or carbonates to this day, remains a challenge for the industry, with very few documented success stories or evidence of sustained ability to enhance fracture gradient across a drilling campaign.\u0000 This paper covers the history of lost circulation events which have been reported in the Khazzan/Ghazeer field in the carbonate Habshan formation. It also describes the design changes which were introduced to strengthen the rock and enable circulation/returns, during liner cementation. The design work built on experience applying wellbore strengthening techniques in carbonates in the Norwegian sector of the North Sea. This work is also summarized in this paper.\u0000 The Habshan carbonate formation in Oman presents a lost circulation challenge through an ‘induced’ fracture risk. Since the beginning of the drilling campaign in the Khazzan/Ghazeer field, the Habshan formation has repeatedly experienced induced mud losses during well activities such as liner running, mud conditioning with liner on bottom and cementing, when the formation is exposed to higher pressures, less so during drilling. The Habshan challenge in Oman has led to regular, significant lost circulation events during cement placement, adding operational cost and more importantly, presenting difficulties around meeting zonal isolation objectives.\u0000 Through previous field experience in Norway, a set of criteria was developed to qualify a standard pill approach to carbonate strengthening. The currently deployed strategy is designed to address both the risk of induced fracture by propping and plugging (wellbore strengthening) and provide some ability to seal natural fractures which are often encountered with carbonates, or similarly flawed rocks. The strategy deployed aims to cover these two risks with a blanket approach to lost circulation risk in carbonates.\u0000 The success of this approach is demonstrated using well performance data from a total of 43 wells drilled before and after the introduction of the wellbore strengthening strategy.\u0000 As it was initially assumed that wellbore strengthening could not be applied to carbonate formations, other techniques had been tried to prevent lost circulation. Those techniques provided mixed results.\u0000 Since the implementation of wellb","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"237 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78533750","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：