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}
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}
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}
A. Khitrenko, A.M. Minkhatova, V. Orlov, D. Kotunov, Salavat Khalilov
Western Siberia is a unique petroleum basin with exclusive geological objects. Those objects allow us to test various methods of sequence stratigraphy, systematization and evaluation approaches for reservoir characterization of deep-water sediments. Different methods have potential to decrease geological uncertainty and predict distribution and architecture of deep-water sandstone reservoir. There are many different parameters that could be achieved through analysis of clinoform complex. Trajectories of shelf break, volume of sediment supply and topography of basin influence on architecture of deep-water reservoir. Based on general principles of sequence stratigraphy, three main trajectories changes shelf break might be identified: transgression, normal regression and forced regression. And each of them has its own distinctive characteristics of deepwater reservoir. However, to properly assess the architecture of deepwater reservoir and potential of it, numerical characteristics are necessary. In our paper, previously described parameters were analyzed for identification perspective areas of Achimov formation in Western Siberia and estimation of geological uncertainty for unexplored areas. In 1996 Helland-Hansen W., Martinsen O.J. [5] described different types of shoreline trajectory. In 2002 Steel R.J., Olsen T. [11] adopted types of shoreline trajectory for identification of truncation termination. O. Catuneanu (2009) [1] summarize all information with implementation basis of sequence stratigraphy. Over the past decade, many geoscientists have used previously published researches to determine relationship between geometric structures of clinoforms and architecture of deep-water sediments and its reservoir quality. Significant amount of publications has allowed to form theoretical framework for the undersanding sedimentation process and geometrical configuration of clinoforms. However, there is still no relationship between sequence stratigraphy framework of clinoroms and reservoir quality and its uncertainty, which is necessary for new area evaluation.
{"title":"The Influence of Main Factors on Deepwater Sediments","authors":"A. Khitrenko, A.M. Minkhatova, V. Orlov, D. Kotunov, Salavat Khalilov","doi":"10.2118/204865-ms","DOIUrl":"https://doi.org/10.2118/204865-ms","url":null,"abstract":"\u0000 Western Siberia is a unique petroleum basin with exclusive geological objects. Those objects allow us to test various methods of sequence stratigraphy, systematization and evaluation approaches for reservoir characterization of deep-water sediments. Different methods have potential to decrease geological uncertainty and predict distribution and architecture of deep-water sandstone reservoir. There are many different parameters that could be achieved through analysis of clinoform complex. Trajectories of shelf break, volume of sediment supply and topography of basin influence on architecture of deep-water reservoir.\u0000 Based on general principles of sequence stratigraphy, three main trajectories changes shelf break might be identified: transgression, normal regression and forced regression. And each of them has its own distinctive characteristics of deepwater reservoir. However, to properly assess the architecture of deepwater reservoir and potential of it, numerical characteristics are necessary. In our paper, previously described parameters were analyzed for identification perspective areas of Achimov formation in Western Siberia and estimation of geological uncertainty for unexplored areas.\u0000 In 1996 Helland-Hansen W., Martinsen O.J. [5] described different types of shoreline trajectory. In 2002 Steel R.J., Olsen T. [11] adopted types of shoreline trajectory for identification of truncation termination. O. Catuneanu (2009) [1] summarize all information with implementation basis of sequence stratigraphy. Over the past decade, many geoscientists have used previously published researches to determine relationship between geometric structures of clinoforms and architecture of deep-water sediments and its reservoir quality. Significant amount of publications has allowed to form theoretical framework for the undersanding sedimentation process and geometrical configuration of clinoforms. However, there is still no relationship between sequence stratigraphy framework of clinoroms and reservoir quality and its uncertainty, which is necessary for new area evaluation.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"19 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83429463","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}
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}
Mohamed Ameen, Eslam Atwa, Y. Youssif, Emad Abdel Hakim, M. Farouk, S. Ghadiry, K. Saleh, Aly Morad
For more than 40 years, pulsed neutron spectroscopy has been primarily used in reservoir management to determine hydrocarbon saturation profiles, tracking reservoir depletion, and planning workover activities to diagnose production problems such as water influx. Legacy pulsed neutron tools used to provide this information for more than four decades, but they were challenged when a mixed lithology reservoir is encountered, complex completions, unknown borehole conditions, and poor cement integrity in cased boreholes. This paper presents two successful field examples and applications using the advanced slim pulsed neutron spectroscopy to precisely determine multiphase contacts in a complex geological structure, provide current hydrocarbon saturation independent of the quality of cement behind the casing, and identifying bypassed hydrocarbon. This was of paramount importance in understanding current reservoir fluid distribution to reveal the true potential of this offshore brownfield located in the Gulf of Suez, Egypt. An integrated approach and candidate well selection were done that resulted in selecting two candidate wells that had poor cement quality behind casing, heterogeneous carbonate reservoir with mixed lithology, and uncertain fluid contacts in a complex reservoir structure. These combined borehole and reservoir conditions resemble challenges for capturing this crucial information with high confidence using the legacy pulsed neutron tool, and therefore required an advanced technology that can overcome these challenges using a single logging mode at twice the logging speed of any current pulsed neutron technology available in the industry. Based on the results, a workover campaign was implemented in this mature field to increase overall oil production with very efficient cost control, especially with this unprecedented time the O&G industry is going through. An integrated approach was set that resulted in the selection of two wells for the saturation determination logging tool deployment. Detailed high-resolution mineralogy, self-compensated total porosity and sigma, fluid type identification, and multiphase fluid saturation was obtained with high precision behind cased borehole independent of cement integrity and borehole fluid reinvasion. The results provided crucial information as an input to the integrated reservoir engineering approach which revealed around a 100-m net oil interval which was previously overlooked due to relatively low resistivity. Besides, fluids contacts were evaluated that confirmed the development of a secondary gas cap and the water encroachment direction. This technology can be further applied to more brownfields provided the right candidate selection is done to understand the potentiality of the field which would increase the recovery factor of the brownfields that represent almost more than 65% of the oil and gas fields around the world.
{"title":"Exploiting Slim Pulsed Neutron Spectroscopy for Unlocking Reservoir Potential in Brownfields: Two Examples from Gulf of Suez Offshore Field in Egypt","authors":"Mohamed Ameen, Eslam Atwa, Y. Youssif, Emad Abdel Hakim, M. Farouk, S. Ghadiry, K. Saleh, Aly Morad","doi":"10.2118/204751-ms","DOIUrl":"https://doi.org/10.2118/204751-ms","url":null,"abstract":"\u0000 For more than 40 years, pulsed neutron spectroscopy has been primarily used in reservoir management to determine hydrocarbon saturation profiles, tracking reservoir depletion, and planning workover activities to diagnose production problems such as water influx. Legacy pulsed neutron tools used to provide this information for more than four decades, but they were challenged when a mixed lithology reservoir is encountered, complex completions, unknown borehole conditions, and poor cement integrity in cased boreholes.\u0000 This paper presents two successful field examples and applications using the advanced slim pulsed neutron spectroscopy to precisely determine multiphase contacts in a complex geological structure, provide current hydrocarbon saturation independent of the quality of cement behind the casing, and identifying bypassed hydrocarbon. This was of paramount importance in understanding current reservoir fluid distribution to reveal the true potential of this offshore brownfield located in the Gulf of Suez, Egypt.\u0000 An integrated approach and candidate well selection were done that resulted in selecting two candidate wells that had poor cement quality behind casing, heterogeneous carbonate reservoir with mixed lithology, and uncertain fluid contacts in a complex reservoir structure. These combined borehole and reservoir conditions resemble challenges for capturing this crucial information with high confidence using the legacy pulsed neutron tool, and therefore required an advanced technology that can overcome these challenges using a single logging mode at twice the logging speed of any current pulsed neutron technology available in the industry.\u0000 Based on the results, a workover campaign was implemented in this mature field to increase overall oil production with very efficient cost control, especially with this unprecedented time the O&G industry is going through. An integrated approach was set that resulted in the selection of two wells for the saturation determination logging tool deployment.\u0000 Detailed high-resolution mineralogy, self-compensated total porosity and sigma, fluid type identification, and multiphase fluid saturation was obtained with high precision behind cased borehole independent of cement integrity and borehole fluid reinvasion. The results provided crucial information as an input to the integrated reservoir engineering approach which revealed around a 100-m net oil interval which was previously overlooked due to relatively low resistivity. Besides, fluids contacts were evaluated that confirmed the development of a secondary gas cap and the water encroachment direction. This technology can be further applied to more brownfields provided the right candidate selection is done to understand the potentiality of the field which would increase the recovery factor of the brownfields that represent almost more than 65% of the oil and gas fields around the world.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88772421","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}
J. R. Cherdasa, T. Ariadji, B. Sapiie, Ucok W. R. Siagian
East Natuna is well known for its huge natural gas reserves with a very high CO2 content. The appearance of CO2 content in an oil and gas field is always considered as waste material and will severely affect the economic value of the field. The higher the content, the more costly the process, both technically and environmentally. In this research, the newly proposed reservoir management approach called CSSU (Carbon Sequestration Storage and Utilization) method is trying to change the paradigm of CO2 from waste material into economic materials. The novelty of this research is the combined optimization of deterministic and stochastic methods with the Particle Swarm Optimization (PSO) algorithm to answer complex and non-linear problems in the CSSU (Carbon Sequestration Storage and Utilization) method. The CSSU method is an integration of geological, geophysical, reservoir engineering and engineering economics with the determination of technical and economic optimization of the use of CO2 produced as working fluid in a power generation system that has been conditioned through an injection-production system in geological formations. The CSSU research area is located in a sedimentary basin that has a giant gas field with 70% CO2 content. The Volumetric Storage Capacity for CO2 injection process in research area is 1,749.14 BCF or 94.01 MMTon which being calculated based on static modeling considering geological, geophysical and petrophysical aspects. A combination of Compositional, Geomechanics and Thermal reservoir simulation model had been conducted to determines the Storage Injection capacity and later to prove the CSSU method in which CO2 fluids will be utilized as working fluid, 1 case was built using 2 Injection Wells and 1 CO2 fluid Production Well. The simulation results show with 1 production well the total of CO2 fluid injected from 2 Injection wells can almost double the injection total capacity up to 1,150 BCF. The utilization of supercritical CO2 fluid as working fluid can produce 55 – 133.5 MMBTU/Day or 0.67 - 1.63 MW from 1 production well for 25 years timeframe. The CSSU method is optimized by deterministic and stochastic methods using the Particle Swarm Optimization (PSO) algorithm by looking the technical and economical aspects. The technical optimization aspect is being analyzed by electricity production versus well counts. The economical optimization is being analyzed by operational expenditure saving versus well counts and electricity produced versus NPV 10%. From both aspects the 4 injector wells case and NPV 200.00 MM US$ gives the most optimum result within technically and economically. The CSSU economic model proved with CSSU scheme the economical value is being increased by 57 MMUS$ after operating cost efficiency due to the electricity savings, 92 MMUS$ due to Carbon Trading which resulting the NPV 10% is 172.77 MMUS$.
{"title":"Reservoir Management Optimization Model Employing Combination Deterministic and Probabilistic Approach for Carbon Sequestration Storage and Utilization: A Case Study from East Natuna","authors":"J. R. Cherdasa, T. Ariadji, B. Sapiie, Ucok W. R. Siagian","doi":"10.2118/204761-ms","DOIUrl":"https://doi.org/10.2118/204761-ms","url":null,"abstract":"\u0000 East Natuna is well known for its huge natural gas reserves with a very high CO2 content. The appearance of CO2 content in an oil and gas field is always considered as waste material and will severely affect the economic value of the field. The higher the content, the more costly the process, both technically and environmentally. In this research, the newly proposed reservoir management approach called CSSU (Carbon Sequestration Storage and Utilization) method is trying to change the paradigm of CO2 from waste material into economic materials.\u0000 The novelty of this research is the combined optimization of deterministic and stochastic methods with the Particle Swarm Optimization (PSO) algorithm to answer complex and non-linear problems in the CSSU (Carbon Sequestration Storage and Utilization) method. The CSSU method is an integration of geological, geophysical, reservoir engineering and engineering economics with the determination of technical and economic optimization of the use of CO2 produced as working fluid in a power generation system that has been conditioned through an injection-production system in geological formations.\u0000 The CSSU research area is located in a sedimentary basin that has a giant gas field with 70% CO2 content. The Volumetric Storage Capacity for CO2 injection process in research area is 1,749.14 BCF or 94.01 MMTon which being calculated based on static modeling considering geological, geophysical and petrophysical aspects.\u0000 A combination of Compositional, Geomechanics and Thermal reservoir simulation model had been conducted to determines the Storage Injection capacity and later to prove the CSSU method in which CO2 fluids will be utilized as working fluid, 1 case was built using 2 Injection Wells and 1 CO2 fluid Production Well. The simulation results show with 1 production well the total of CO2 fluid injected from 2 Injection wells can almost double the injection total capacity up to 1,150 BCF. The utilization of supercritical CO2 fluid as working fluid can produce 55 – 133.5 MMBTU/Day or 0.67 - 1.63 MW from 1 production well for 25 years timeframe.\u0000 The CSSU method is optimized by deterministic and stochastic methods using the Particle Swarm Optimization (PSO) algorithm by looking the technical and economical aspects. The technical optimization aspect is being analyzed by electricity production versus well counts. The economical optimization is being analyzed by operational expenditure saving versus well counts and electricity produced versus NPV 10%. From both aspects the 4 injector wells case and NPV 200.00 MM US$ gives the most optimum result within technically and economically. The CSSU economic model proved with CSSU scheme the economical value is being increased by 57 MMUS$ after operating cost efficiency due to the electricity savings, 92 MMUS$ due to Carbon Trading which resulting the NPV 10% is 172.77 MMUS$.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88344944","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. Elsayed, H. Kwak, A. El-Husseiny, Mohamed Mahmoud
Tortuosity, in general characterizes the geometric complexity of porous media. It is considered as one of the key factors in characterizing the heterogonous structure of porous media and has significant implications for macroscopic transport flow properties. There are four widely used definitions of tortuosity, that are relevant to different fields from hydrology to chemical and petroleum engineering, which are: geometric, hydraulic, electrical, and diffusional. Recent work showed that hydraulic, electrical and diffusional tortuosity values are roughly equal to each other in glass beads. Nevertheless, the relationship between the different definitions of Tortuosity in natural rocks is not well understood yet. Understanding the relationship between the different Tortuosity definitions in rocks can help to establish a workflow that allows us to estimate other types from the available technique. Therefore, the objective of this study is to investigate the relationship between the different tortuosity definitions in natural rocks. A major focus of this work is to utilize Nuclear Magnetic Resonance (NMR) technology to estimate Tortuosity. Such technique has been traditionally used to obtain diffusional tortuosity which can be defined as the ratio of the free fluid self-diffusion coefficient to the restricted fluid self-diffusion coefficient inside the porous media. In this study, the following techniques were used to quantify hydraulic, electrical, and diffusional tortuosity respectively on the same rock sample: (1) Microcomputed Tomography 3D imaging (2) Four-Electrodes resistivity measurements (3) Pulsed-Field Gradient Nuclear Magnetic Resonance (PFG NMR). PFG NMR is very powerful, non-invasive technique employed to measure the self-diffusion coefficient for free and confined fluids. The measurements were done based on two carbonate rock core plugs characterized by variable porosity, permeability and texture complexity. Results show that PFG NMR can be applied directionally to quantify the pore network anisotropy created by fractures. For both samples, hydraulic tortuosity was found to have the lowest magnitude compared to geometric, electrical and diffusional tortuosity. This could be explained by the more heterogeneous microstructure of carbonate rocks. NMR technique has however advantages over the other electrical and imaging techniques for tortuosity characterization: it is faster, non-destructive and can be applied in well bore environment (in situ). We therefore conclude that NMR can provide a tool for estimating not only diffusional tortuosity but also for indirectly obtaining hydraulic and electrical tortuosity.
{"title":"The Measurement of Tortuosity of Porous Media Using Imaging, Electrical Measurements, and Pulsed Field Gradient NMR","authors":"M. Elsayed, H. Kwak, A. El-Husseiny, Mohamed Mahmoud","doi":"10.2118/204629-ms","DOIUrl":"https://doi.org/10.2118/204629-ms","url":null,"abstract":"\u0000 Tortuosity, in general characterizes the geometric complexity of porous media. It is considered as one of the key factors in characterizing the heterogonous structure of porous media and has significant implications for macroscopic transport flow properties. There are four widely used definitions of tortuosity, that are relevant to different fields from hydrology to chemical and petroleum engineering, which are: geometric, hydraulic, electrical, and diffusional. Recent work showed that hydraulic, electrical and diffusional tortuosity values are roughly equal to each other in glass beads. Nevertheless, the relationship between the different definitions of Tortuosity in natural rocks is not well understood yet. Understanding the relationship between the different Tortuosity definitions in rocks can help to establish a workflow that allows us to estimate other types from the available technique. Therefore, the objective of this study is to investigate the relationship between the different tortuosity definitions in natural rocks. A major focus of this work is to utilize Nuclear Magnetic Resonance (NMR) technology to estimate Tortuosity. Such technique has been traditionally used to obtain diffusional tortuosity which can be defined as the ratio of the free fluid self-diffusion coefficient to the restricted fluid self-diffusion coefficient inside the porous media.\u0000 In this study, the following techniques were used to quantify hydraulic, electrical, and diffusional tortuosity respectively on the same rock sample: (1) Microcomputed Tomography 3D imaging (2) Four-Electrodes resistivity measurements (3) Pulsed-Field Gradient Nuclear Magnetic Resonance (PFG NMR). PFG NMR is very powerful, non-invasive technique employed to measure the self-diffusion coefficient for free and confined fluids. The measurements were done based on two carbonate rock core plugs characterized by variable porosity, permeability and texture complexity.\u0000 Results show that PFG NMR can be applied directionally to quantify the pore network anisotropy created by fractures. For both samples, hydraulic tortuosity was found to have the lowest magnitude compared to geometric, electrical and diffusional tortuosity. This could be explained by the more heterogeneous microstructure of carbonate rocks. NMR technique has however advantages over the other electrical and imaging techniques for tortuosity characterization: it is faster, non-destructive and can be applied in well bore environment (in situ). We therefore conclude that NMR can provide a tool for estimating not only diffusional tortuosity but also for indirectly obtaining hydraulic and electrical tortuosity.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89140373","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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