J. Cunningham, W. Weibull, N. Cardozo, D. Iacopini
PS seismic data from the Snøhvit field are compared with seismic modelling to understand the effect of azimuthal separation and incidence angle on the imaging of faults and associated horizon discontinuities. In addition, the frequency content of seismic waves backscattered from faults is analysed. The study area consists of a horst structure delimited by a northern fault dipping NW and oblique to the east–west survey orientation, and a southern fault dipping SSW and subparallel to the survey. Due to the raypath asymmetry of PS reflections, the northern fault is imaged better by azimuthally partitioned W data that include receivers downdip of the fault, relative to the sources, than by E data where the receivers are updip from the sources. Partial stack data show a systematic increase in the PS fault-reflected amplitude and therefore quality of fault imaging with increasing incidence angle. Fault images are dominated by internal low-medium frequency shadows surrounded by medium-high frequencies haloes. Synthetic experiments suggest that this is due to the interaction of specular waves and diffractions, and the spectral contribution from the fault signal, which increases with fault zone complexity. These results highlight the impact of survey geometry and processing workflows on fault imaging. Supplementary material: model description, processed sections and videos are available at https://doi.org/10.6084/m9.figshare.c.5727552
{"title":"Investigating the PS seismic imaging of faults using seismic modelling and data from the Snøhvit field, Barents Sea","authors":"J. Cunningham, W. Weibull, N. Cardozo, D. Iacopini","doi":"10.1144/petgeo2020-044","DOIUrl":"https://doi.org/10.1144/petgeo2020-044","url":null,"abstract":"PS seismic data from the Snøhvit field are compared with seismic modelling to understand the effect of azimuthal separation and incidence angle on the imaging of faults and associated horizon discontinuities. In addition, the frequency content of seismic waves backscattered from faults is analysed. The study area consists of a horst structure delimited by a northern fault dipping NW and oblique to the east–west survey orientation, and a southern fault dipping SSW and subparallel to the survey. Due to the raypath asymmetry of PS reflections, the northern fault is imaged better by azimuthally partitioned W data that include receivers downdip of the fault, relative to the sources, than by E data where the receivers are updip from the sources. Partial stack data show a systematic increase in the PS fault-reflected amplitude and therefore quality of fault imaging with increasing incidence angle. Fault images are dominated by internal low-medium frequency shadows surrounded by medium-high frequencies haloes. Synthetic experiments suggest that this is due to the interaction of specular waves and diffractions, and the spectral contribution from the fault signal, which increases with fault zone complexity. These results highlight the impact of survey geometry and processing workflows on fault imaging. Supplementary material: model description, processed sections and videos are available at https://doi.org/10.6084/m9.figshare.c.5727552","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-12-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42027946","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
We demonstrate how modelling decisions for a giant carbonate reservoir with a thick transition zone in the Middle East, most notably the approach to reservoir rock typing and modelling the initial fluid saturations, impact the hydrocarbon distributions and oil-in-place estimates in the reservoir. Rather than anchoring our model around a single base case with an upside and downside, we apply a comprehensive 3D multiple deterministic scenario workflow to compare-and-contrast how modelling decisions and geological uncertainties influence the volumetric estimates. We carry out a detailed analysis which shows that the variations in STOIIP estimates can be as high as 28% depending on the preferred modelling decision, which could potentially mask the impact of other geological uncertainties. These models were validated through repeated and randomised blind tests. We hence present a quantitative approach that helps us to assess if the static models are consistent in terms of the integration of geological and petrophysical data. Ultimately, the decision which of the different modelling options should be applied does not only influence STOIIP estimates, but also subsequent history matching & forecasts.
{"title":"Impact of modelling decisions and rock typing schemes on oil in place estimates in a giant carbonate reservoir in the Middle East","authors":"Mohamed AlBreiki, S. Geiger, P. Corbett","doi":"10.1144/petgeo2021-028","DOIUrl":"https://doi.org/10.1144/petgeo2021-028","url":null,"abstract":"We demonstrate how modelling decisions for a giant carbonate reservoir with a thick transition zone in the Middle East, most notably the approach to reservoir rock typing and modelling the initial fluid saturations, impact the hydrocarbon distributions and oil-in-place estimates in the reservoir. Rather than anchoring our model around a single base case with an upside and downside, we apply a comprehensive 3D multiple deterministic scenario workflow to compare-and-contrast how modelling decisions and geological uncertainties influence the volumetric estimates. We carry out a detailed analysis which shows that the variations in STOIIP estimates can be as high as 28% depending on the preferred modelling decision, which could potentially mask the impact of other geological uncertainties. These models were validated through repeated and randomised blind tests. We hence present a quantitative approach that helps us to assess if the static models are consistent in terms of the integration of geological and petrophysical data. Ultimately, the decision which of the different modelling options should be applied does not only influence STOIIP estimates, but also subsequent history matching & forecasts.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47539060","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The exploration history of the large Eastern Mediterranean Basin, which encompasses the Nile Delta, Levantine, Herodotus and Eratosthenes provinces, has seen several phases of rejuvenation since exploration started in the 1950s, with new plays opened repeatedly after the basin was considered mature by the industry. The 584 exploration wells drilled to date have discovered more than 23 Bboe recoverable reserves/resources, mostly gas. The first discovery was the Abu Madi Field, in 1967, which opened the Messinian clastic play. Over time, other plays and sub-plays were opened, including the Serravallian–Tortonian, the Plio–Pleistocene, the Oligo–Miocene in the Levantine, the intra-Oligocene and the Cretaceous carbonates. The exceptional variety of plays, with different trapping styles, reservoir and seal facies patterns has few equivalents worldwide and makes the region a valuable training ground for explorers. The geological variety is not the only reason for such a complex and episodic exploration history: commercial (gas market) and geopolitical issues have also had an impact on the activity in parts of the basin. The largest discoveries have been made in the last 10 years (Tamar, Leviathan, Zohr) and, despite the intense exploration activity, parts of the basin remain underexplored. The company with the longest and most successful play opening history in the basin is Eni. Today, most major oil companies are active in the basin, which even after 70 years is still considered one of the world's exploration hotspots.
{"title":"The rejuvenation of hydrocarbon exploration in the Eastern Mediterranean","authors":"F. Lottaroli, L. Meciani","doi":"10.1144/petgeo2021-018","DOIUrl":"https://doi.org/10.1144/petgeo2021-018","url":null,"abstract":"The exploration history of the large Eastern Mediterranean Basin, which encompasses the Nile Delta, Levantine, Herodotus and Eratosthenes provinces, has seen several phases of rejuvenation since exploration started in the 1950s, with new plays opened repeatedly after the basin was considered mature by the industry. The 584 exploration wells drilled to date have discovered more than 23 Bboe recoverable reserves/resources, mostly gas. The first discovery was the Abu Madi Field, in 1967, which opened the Messinian clastic play. Over time, other plays and sub-plays were opened, including the Serravallian–Tortonian, the Plio–Pleistocene, the Oligo–Miocene in the Levantine, the intra-Oligocene and the Cretaceous carbonates. The exceptional variety of plays, with different trapping styles, reservoir and seal facies patterns has few equivalents worldwide and makes the region a valuable training ground for explorers. The geological variety is not the only reason for such a complex and episodic exploration history: commercial (gas market) and geopolitical issues have also had an impact on the activity in parts of the basin. The largest discoveries have been made in the last 10 years (Tamar, Leviathan, Zohr) and, despite the intense exploration activity, parts of the basin remain underexplored. The company with the longest and most successful play opening history in the basin is Eni. Today, most major oil companies are active in the basin, which even after 70 years is still considered one of the world's exploration hotspots.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-11-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46434580","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dissolving CO2 into water or brine produces a denser fluid than the CO2-free equivalent at all salinity, temperature and pressure conditions relevant to sedimentary basins. Negative buoyancy of CO2 solutions opens the possibility of utilizing negative-relief trapping configurations for CO2 sequestration, as opposed to structural highs conventionally sought for positively buoyant fluids, such as hydrocarbons or pure CO2. Exploring sedimentary basins for negative buoyancy traps can readily utilize hydrocarbon exploration datasets and techniques. Some major systemic differences when exploring for negative as opposed to positive buoyancy traps are examined here. Trap spatial scale is a consideration due to the inherent long-wavelength synformal geometry of basins. Antiforms are areally restricted relative to synforms, which may be embedded within larger-scale synformal closure at length scales right up to that of the basin itself. Multiscale synformal structures vary with basin type and may not be fully identified due to truncation effects arising from data-coverage limitations. Similar to hydrocarbon exploration, CO2 trap exploration must consider potential sequestration volumes in an uncertainty and risk framework. Charge risk is unnecessary in sequestration projects; however, the multiscale nature of synformal traps should be considered when estimating the range of storage volumes. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"Negatively buoyant CO2 solution sequestration in synformal traps","authors":"S. Stewart","doi":"10.1144/petgeo2021-074","DOIUrl":"https://doi.org/10.1144/petgeo2021-074","url":null,"abstract":"Dissolving CO2 into water or brine produces a denser fluid than the CO2-free equivalent at all salinity, temperature and pressure conditions relevant to sedimentary basins. Negative buoyancy of CO2 solutions opens the possibility of utilizing negative-relief trapping configurations for CO2 sequestration, as opposed to structural highs conventionally sought for positively buoyant fluids, such as hydrocarbons or pure CO2. Exploring sedimentary basins for negative buoyancy traps can readily utilize hydrocarbon exploration datasets and techniques. Some major systemic differences when exploring for negative as opposed to positive buoyancy traps are examined here. Trap spatial scale is a consideration due to the inherent long-wavelength synformal geometry of basins. Antiforms are areally restricted relative to synforms, which may be embedded within larger-scale synformal closure at length scales right up to that of the basin itself. Multiscale synformal structures vary with basin type and may not be fully identified due to truncation effects arising from data-coverage limitations. Similar to hydrocarbon exploration, CO2 trap exploration must consider potential sequestration volumes in an uncertainty and risk framework. Charge risk is unnecessary in sequestration projects; however, the multiscale nature of synformal traps should be considered when estimating the range of storage volumes. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-11-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46095952","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sirawitch Nantanoi, G. Rodríguez-Pradilla, J. Verdon
The Bowland Shale Formation is one of the most promising targets for unconventional exploration in the United Kingdom, with estimated resources large enough to supply the country's entire natural gas consumption for 50 years. However, development of the Bowland Shale has stalled due to concerns over hydraulic-fracturing-induced seismicity. Only three wells have been drilled and hydraulic-fractured to date in the Bowland Shale, and all three have produced levels of seismicity of sufficient magnitude to be felt at the surface. Susceptibility to induced seismicity will be determined by the presence of critically stressed faults. However, such faults can go undetected in conventional interpretation of 2D or 3D seismic surveys if they are shorter than the resolution retrievable from a seismic survey, or if they have low (and in some cases even zero) vertical displacement. In such cases, the faults that cause induced seismicity may only be visible via microseismic observations once they are reactivated. To better identify fault planes from 3D seismic images, and their reactivation potential due to hydraulic fracturing, a high-resolution fault-detection attribute was tested in a 3D seismic survey that was acquired over the Preston New Road site, where two shale-gas wells were hydraulic-fractured in the Bowland Shale in 2018 and 2019, obtaining fault planes with lengths between 400 and 1500 m. Fault slip potential was then estimated by integrating the obtained faults with the formation's stress and pore pressure conditions (with the Bowland shale also being significantly overpressured), and several critically stressed faults were identified near the previously hydraulic fractured wells. However, the faults that induced the largest seismic events in the Preston New Road site, of c. 200 m in length for seismic events of magnitudes below 3.0 (as imaged with a multicomponent, downhole microseismic monitoring array deployed during the hydraulic-fracturing stimulations), could not be identified in the 3D seismic survey, which only mapped fault planes larger than 400 m in length.
Bowland页岩地层是英国非常规油气勘探最有前途的目标之一，据估计其储量足以满足英国50年的天然气消费量。然而，由于担心水力压裂引起的地震活动，Bowland页岩的开发已经停滞。到目前为止，Bowland页岩只有三口井进行了钻井和水力压裂，这三口井都产生了足以在地面感受到的地震活动水平。对诱发地震活动的敏感性将取决于是否存在临界应力断层。然而，如果断层的分辨率小于地震测量的分辨率，或者断层的垂直位移很小(在某些情况下甚至为零)，那么在2D或3D地震测量的常规解释中可能无法检测到这些断层。在这种情况下，引起诱发地震活动的断层只有在重新激活后才能通过微地震观测看到。为了更好地从三维地震图像中识别断层面，以及它们因水力压裂而重新激活的可能性，在2018年和2019年在Bowland页岩的两口页岩气井进行水力压裂的Preston New Road现场进行的三维地震调查中，测试了高分辨率断层检测属性，获得了长度在400至1500 m之间的断层面。然后通过将获得的断层与地层应力和孔隙压力条件(Bowland页岩也存在明显的超压)相结合来估计断层滑动的可能性，并在之前的水力压裂井附近识别出几个临界应力断层。然而，在Preston New Road地块，对于3.0级以下的地震事件，诱发最大地震事件的断层长度约为200 m(在水力压裂增产过程中使用了多分量井下微地震监测阵列进行成像)，在3D地震调查中无法识别，只能绘制长度大于400 m的断层面。
{"title":"3D seismic interpretation and fault slip potential analysis from hydraulic fracturing in the Bowland Shale, UK","authors":"Sirawitch Nantanoi, G. Rodríguez-Pradilla, J. Verdon","doi":"10.1144/petgeo2021-057","DOIUrl":"https://doi.org/10.1144/petgeo2021-057","url":null,"abstract":"The Bowland Shale Formation is one of the most promising targets for unconventional exploration in the United Kingdom, with estimated resources large enough to supply the country's entire natural gas consumption for 50 years. However, development of the Bowland Shale has stalled due to concerns over hydraulic-fracturing-induced seismicity. Only three wells have been drilled and hydraulic-fractured to date in the Bowland Shale, and all three have produced levels of seismicity of sufficient magnitude to be felt at the surface. Susceptibility to induced seismicity will be determined by the presence of critically stressed faults. However, such faults can go undetected in conventional interpretation of 2D or 3D seismic surveys if they are shorter than the resolution retrievable from a seismic survey, or if they have low (and in some cases even zero) vertical displacement. In such cases, the faults that cause induced seismicity may only be visible via microseismic observations once they are reactivated. To better identify fault planes from 3D seismic images, and their reactivation potential due to hydraulic fracturing, a high-resolution fault-detection attribute was tested in a 3D seismic survey that was acquired over the Preston New Road site, where two shale-gas wells were hydraulic-fractured in the Bowland Shale in 2018 and 2019, obtaining fault planes with lengths between 400 and 1500 m. Fault slip potential was then estimated by integrating the obtained faults with the formation's stress and pore pressure conditions (with the Bowland shale also being significantly overpressured), and several critically stressed faults were identified near the previously hydraulic fractured wells. However, the faults that induced the largest seismic events in the Preston New Road site, of c. 200 m in length for seismic events of magnitudes below 3.0 (as imaged with a multicomponent, downhole microseismic monitoring array deployed during the hydraulic-fracturing stimulations), could not be identified in the 3D seismic survey, which only mapped fault planes larger than 400 m in length.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-11-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45872873","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
G. Proietti, M. Cvetkovic, B. Saftić, A. Conti, V. Romano, S. Bigi
One of the most innovative and effective technologies developed in recent decades for reducing carbon dioxide emissions to the atmosphere is carbon capture and storage (CCS). It consists of capture, transport and injection of CO2 produced by energy production plants or other industries. The injection takes place in deep geological formations with the suitable geometrical and petrophysical characteristics to trap CO2 permanently in the subsurface, which is called geological storage. In the development process of a potential geological storage site, correct capacity estimation of the injectable volumes of CO2 is one of the most important aspects. There are various approaches to estimate CO2 storage capacities for potential traps, including geometrical equations, dynamic modelling, numerical modelling and 3D modelling. In this work, the generation of 3D petrophysical models and equations for calculation of the storage volumes are used to estimate the effective storage capacity of four potential saline aquifers in the Adriatic Sea offshore. The results show how different saline aquifers, with different lithologies at favourable depths, can host a reasonable amount of CO2, which will require further and more detailed feasibility studies for each of these structures. A detailed analysis is carried out for each saline aquifer identified, varying the parameters of each structure identified and adapting them for a realistic estimate of potential geological storage capacity. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"3D modelling and capacity estimation of potential targets for CO2 storage in the Adriatic Sea, Italy","authors":"G. Proietti, M. Cvetkovic, B. Saftić, A. Conti, V. Romano, S. Bigi","doi":"10.1144/petgeo2020-117","DOIUrl":"https://doi.org/10.1144/petgeo2020-117","url":null,"abstract":"One of the most innovative and effective technologies developed in recent decades for reducing carbon dioxide emissions to the atmosphere is carbon capture and storage (CCS). It consists of capture, transport and injection of CO2 produced by energy production plants or other industries. The injection takes place in deep geological formations with the suitable geometrical and petrophysical characteristics to trap CO2 permanently in the subsurface, which is called geological storage. In the development process of a potential geological storage site, correct capacity estimation of the injectable volumes of CO2 is one of the most important aspects. There are various approaches to estimate CO2 storage capacities for potential traps, including geometrical equations, dynamic modelling, numerical modelling and 3D modelling. In this work, the generation of 3D petrophysical models and equations for calculation of the storage volumes are used to estimate the effective storage capacity of four potential saline aquifers in the Adriatic Sea offshore. The results show how different saline aquifers, with different lithologies at favourable depths, can host a reasonable amount of CO2, which will require further and more detailed feasibility studies for each of these structures. A detailed analysis is carried out for each saline aquifer identified, varying the parameters of each structure identified and adapting them for a realistic estimate of potential geological storage capacity. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41288930","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Tsopela, A. Bere, M. Dutko, J. Kato, S. Niranjan, Benjamin G. Jennette, S. Hsu, G. Dasari
With the increasing demand for CO2 storage in the subsurface, it is important to recognize that candidate formations may present complex stress conditions and material characteristics. Consequently, modelling of CO2 injection requires the selection of the most appropriate constitutive material model for the best possible representation of the material response. The authors focus on modelling the geomechanical behaviour of the reservoir material, coupled with a multiphase flow solution of CO2 injection into a saline-saturated medium. It is proposed that the SR3 critical-state material model is used, which considers a direct link between strength–volume–permeability that evolves during the simulation; furthermore, the material is considered to yield prior to reaching a peak strength in agreement with experimental observations. Verification of the material model against established laboratory tests is conducted, including multiphase flow accounting for relative permeabilities and fluid densities. Multiphase flow coupled to advanced geomechanics provides a holistic approach to modelling CO2 injection into sandstone reservoirs. The resulting injection pressures, CO2 migration extent and patterns, formation dilation, and strength reduction are compared for a range of in situ porosities and incremental material enhancements. This work aims to demonstrate a numerical modelling framework to aid in the understanding of geomechanical responses to CO2 injection for safe and efficient deployment, and is particularly applicable to CO2 sequestration in less favourable aquifers with a relatively low permeability, receiving CO2 from a limited number of injection wells at high flow rates. The proposed framework can also enable additional features to be incorporated into the model such as faults and detailed overburden representation. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"CO2 injection and storage in porous rocks: coupled geomechanical yielding below failure threshold and permeability evolution","authors":"A. Tsopela, A. Bere, M. Dutko, J. Kato, S. Niranjan, Benjamin G. Jennette, S. Hsu, G. Dasari","doi":"10.1144/petgeo2020-124","DOIUrl":"https://doi.org/10.1144/petgeo2020-124","url":null,"abstract":"With the increasing demand for CO2 storage in the subsurface, it is important to recognize that candidate formations may present complex stress conditions and material characteristics. Consequently, modelling of CO2 injection requires the selection of the most appropriate constitutive material model for the best possible representation of the material response. The authors focus on modelling the geomechanical behaviour of the reservoir material, coupled with a multiphase flow solution of CO2 injection into a saline-saturated medium. It is proposed that the SR3 critical-state material model is used, which considers a direct link between strength–volume–permeability that evolves during the simulation; furthermore, the material is considered to yield prior to reaching a peak strength in agreement with experimental observations. Verification of the material model against established laboratory tests is conducted, including multiphase flow accounting for relative permeabilities and fluid densities. Multiphase flow coupled to advanced geomechanics provides a holistic approach to modelling CO2 injection into sandstone reservoirs. The resulting injection pressures, CO2 migration extent and patterns, formation dilation, and strength reduction are compared for a range of in situ porosities and incremental material enhancements. This work aims to demonstrate a numerical modelling framework to aid in the understanding of geomechanical responses to CO2 injection for safe and efficient deployment, and is particularly applicable to CO2 sequestration in less favourable aquifers with a relatively low permeability, receiving CO2 from a limited number of injection wells at high flow rates. The proposed framework can also enable additional features to be incorporated into the model such as faults and detailed overburden representation. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-09-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41457767","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Egya, P. Corbett, S. Geiger, J. Norgard, S. Hegndal-Andersen
This paper successfully applied the geoengineering workflow for integrated well-test analysis to characterize fluid flow in a newly discovered fractured reservoir in the Barents Sea. A reservoir model containing fractures and matrix was built and calibrated using this workflow to match complex pressure transients measured in the field. We outline different geological scenarios that could potentially reproduce the pressure response observed in the field, highlighting the challenge of non-uniqueness when analysing well-test data. However, integrating other field data into the analysis allowed us to narrow the range of uncertainty, enabling the most plausible geological scenario to be taken forward for more detailed reservoir characterization and history matching. The results provide new insights into the reservoir geology and the key flow processes that generate the pressure response observed in the field. This paper demonstrates that the geoengineering workflow used here can be applied to better characterize naturally fractured reservoirs. We also provide reference solutions for interpreting well tests in fractured reservoirs where troughs in the pressure derivative are recognizable in the data.
{"title":"Calibration of naturally fractured reservoir models using integrated well-test analysis – an illustration with field data from the Barents Sea","authors":"D. Egya, P. Corbett, S. Geiger, J. Norgard, S. Hegndal-Andersen","doi":"10.1144/petgeo2020-042","DOIUrl":"https://doi.org/10.1144/petgeo2020-042","url":null,"abstract":"This paper successfully applied the geoengineering workflow for integrated well-test analysis to characterize fluid flow in a newly discovered fractured reservoir in the Barents Sea. A reservoir model containing fractures and matrix was built and calibrated using this workflow to match complex pressure transients measured in the field. We outline different geological scenarios that could potentially reproduce the pressure response observed in the field, highlighting the challenge of non-uniqueness when analysing well-test data. However, integrating other field data into the analysis allowed us to narrow the range of uncertainty, enabling the most plausible geological scenario to be taken forward for more detailed reservoir characterization and history matching. The results provide new insights into the reservoir geology and the key flow processes that generate the pressure response observed in the field. This paper demonstrates that the geoengineering workflow used here can be applied to better characterize naturally fractured reservoirs. We also provide reference solutions for interpreting well tests in fractured reservoirs where troughs in the pressure derivative are recognizable in the data.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42124188","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Azadeh Pourmalek, A. Newell, S. Shariatipour, A. Wood
Three different outcrops are selected in this study, each representing a shallow-marine system with varying heterogeneity provided by siliciclastic–carbonate mixing that may form a small or large stratigraphic trap. The impact of these styles of mixed facies on CO2 storage is relatively poorly known. This study demonstrates the significance of these systems for safe CO2 geological storage, as stratigraphic traps are likely to be a significant feature of many future storage sites. The three 3D models are based on: (1) the Grayburg Formation (USA), which displays spatial permeability linked to variations in the mixture of siliciclastic–carbonate sediments; (2) the Lorca Basin outcrop (Spain), which demonstrates the interfingering of clastic and carbonate facies; and (3) the Bridport Sand Formation outcrop (UK), which is an example of a layered reservoir and has thin carbonate-cemented horizons. This study demonstrates that facies interplay and associated sediment heterogeneity have a varying effect on fluid flow, storage capacity and security. In the Grayburg Formation, storage security and capacity are not controlled by heterogeneity alone but are influenced mainly by the permeability of each facies (i.e. permeability contrast), the degree of heterogeneity and the relative permeability characteristic of the system. In the case of the Lorca Basin, heterogeneity through interfingering of the carbonate and clastic facies improved the storage security regardless of their permeability. For the Bridport Sand Formation, the existence of extended sheets of cemented carbonate contributed to storage security but not storage capacity, which depends on the continuity of the sheets. These mixed systems especially minimize the large buoyancy forces that act on the top seal and reduce the reliance of the storage security on the overlying cap rock. They also increase the contact area between the injected CO2 and brine, thereby promoting the CO2 dissolution processes. Overall, reservoir systems with mixed carbonate–siliciclastic facies contribute to improving the safe and effective storage of CO2. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"The impact of heterogeneous mixed siliciclastic–carbonate systems on CO2 geological storage","authors":"Azadeh Pourmalek, A. Newell, S. Shariatipour, A. Wood","doi":"10.1144/petgeo2020-086","DOIUrl":"https://doi.org/10.1144/petgeo2020-086","url":null,"abstract":"Three different outcrops are selected in this study, each representing a shallow-marine system with varying heterogeneity provided by siliciclastic–carbonate mixing that may form a small or large stratigraphic trap. The impact of these styles of mixed facies on CO2 storage is relatively poorly known. This study demonstrates the significance of these systems for safe CO2 geological storage, as stratigraphic traps are likely to be a significant feature of many future storage sites. The three 3D models are based on: (1) the Grayburg Formation (USA), which displays spatial permeability linked to variations in the mixture of siliciclastic–carbonate sediments; (2) the Lorca Basin outcrop (Spain), which demonstrates the interfingering of clastic and carbonate facies; and (3) the Bridport Sand Formation outcrop (UK), which is an example of a layered reservoir and has thin carbonate-cemented horizons. This study demonstrates that facies interplay and associated sediment heterogeneity have a varying effect on fluid flow, storage capacity and security. In the Grayburg Formation, storage security and capacity are not controlled by heterogeneity alone but are influenced mainly by the permeability of each facies (i.e. permeability contrast), the degree of heterogeneity and the relative permeability characteristic of the system. In the case of the Lorca Basin, heterogeneity through interfingering of the carbonate and clastic facies improved the storage security regardless of their permeability. For the Bridport Sand Formation, the existence of extended sheets of cemented carbonate contributed to storage security but not storage capacity, which depends on the continuity of the sheets. These mixed systems especially minimize the large buoyancy forces that act on the top seal and reduce the reliance of the storage security on the overlying cap rock. They also increase the contact area between the injected CO2 and brine, thereby promoting the CO2 dissolution processes. Overall, reservoir systems with mixed carbonate–siliciclastic facies contribute to improving the safe and effective storage of CO2. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-07-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41678487","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Bredesen, M. Lorentzen, L. Nielsen, K. Mosegaard
A quantitative seismic interpretation study is presented for the Lower Cretaceous Tuxen reservoir in the Valdemar Field, which is associated with heterogeneous and complex geology. Our objective is to better outline the reservoir quality variations of the Tuxen reservoir across the Valdemar Field. Seismic pre-stack data and well logs from two appraisal wells form the basis of this study. The workflow used includes seismic and rock physics forward modelling, attribute analysis, a coloured inversion, and a Bayesian pre-stack inversion for litho-fluid classification. Based on log data, the rock physics properties of the Tuxen interval reveal that the seismic signal is more governed by porosity than water-saturation changes at near-offset (or small angle). The coloured and Bayesian inversion results were generally consistent with well-log observations at the reservoir level and conformed to interpreted horizons. Although the available data have some limitations and the geological setting is complex, the results implied more promising reservoir quality in some areas than others. Hence, the results may offer useful information for delineating the best reservoir zones for further field development and selecting appropriate production strategies.
{"title":"Quantitative seismic interpretation of the Lower Cretaceous reservoirs in the Valdemar Field, Danish North Sea","authors":"K. Bredesen, M. Lorentzen, L. Nielsen, K. Mosegaard","doi":"10.1144/petgeo2021-016","DOIUrl":"https://doi.org/10.1144/petgeo2021-016","url":null,"abstract":"A quantitative seismic interpretation study is presented for the Lower Cretaceous Tuxen reservoir in the Valdemar Field, which is associated with heterogeneous and complex geology. Our objective is to better outline the reservoir quality variations of the Tuxen reservoir across the Valdemar Field. Seismic pre-stack data and well logs from two appraisal wells form the basis of this study. The workflow used includes seismic and rock physics forward modelling, attribute analysis, a coloured inversion, and a Bayesian pre-stack inversion for litho-fluid classification. Based on log data, the rock physics properties of the Tuxen interval reveal that the seismic signal is more governed by porosity than water-saturation changes at near-offset (or small angle). The coloured and Bayesian inversion results were generally consistent with well-log observations at the reservoir level and conformed to interpreted horizons. Although the available data have some limitations and the geological setting is complex, the results implied more promising reservoir quality in some areas than others. Hence, the results may offer useful information for delineating the best reservoir zones for further field development and selecting appropriate production strategies.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2021-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42064807","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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