N. Zeitoum, Dr. Alexandre Campane Vidal, Dr. Eddy Muñoz Ruidiaz, R. V. de Almeida
Reservoir quality in carbonates is influenced by various factors, such as depositional environment, burial history, and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analyzed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographic and core plug descriptions, petrographic facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore size distribution, and groups with similar petrophysical properties using the Hydraulic Flow Unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); Shrub-Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contribution of inter-aggregate, interparticle, and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability, but the increase of cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4, and F5. From image analysis, small pores (1.5 x 10 -5 to 0.01 mm²) are the most frequent in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm² to a maximum of 19.62 mm²) are the main contributors, while F5 has a homogeneous contribution. Lastly, the data were grouped into 5 HFUs. HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3.
{"title":"Petrographic and Petrophysical Characterization of Pre-salt Aptian Carbonate Reservoirs from The Santos Basin, Brazil","authors":"N. Zeitoum, Dr. Alexandre Campane Vidal, Dr. Eddy Muñoz Ruidiaz, R. V. de Almeida","doi":"10.1144/petgeo2023-045","DOIUrl":"https://doi.org/10.1144/petgeo2023-045","url":null,"abstract":"\u0000 Reservoir quality in carbonates is influenced by various factors, such as depositional environment, burial history, and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analyzed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographic and core plug descriptions, petrographic facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore size distribution, and groups with similar petrophysical properties using the Hydraulic Flow Unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); Shrub-Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contribution of inter-aggregate, interparticle, and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability, but the increase of cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4, and F5. From image analysis, small pores (1.5 x 10\u0000 -5\u0000 to 0.01 mm²) are the most frequent in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm² to a maximum of 19.62 mm²) are the main contributors, while F5 has a homogeneous contribution. Lastly, the data were grouped into 5 HFUs. HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3.\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139385452","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}
E. Fathi, Ali Takbiri-Borujeni, F. Belyadi, M. F. Adenan
Optimizing unconventional field development requires simultaneous optimization of well spacing and completion design. However, the conventional practice of using cross plots and sensitivity analysis via Monte Carlo simulations (MCS) for independent optimization of well spacing and completion design has proved inadequate for unconventional reservoirs. This is due to the inability of cross plots to capture non-linear cross-correlations between parameters affecting hydrocarbon production, and the computational expense and difficulty of Monte Carlo simulations. Recently, automated machine learning (AutoML) workflows have been used to tackle complex problems. However, applying AutoML workflows to engineering problems presents unique challenges, as achieving high accuracy in forecasting the physics of the problem is crucial. To address this issue, a new physics-informed AutoML workflow based on the TPOT open-source tool developed that guarantees the physical plausibility of the optimum model while minimizing human bias and uncertainty. The workflow has been implemented in a Marcellus Shale reservoir with over 1,500 wells to determine the optimal well spacing and completion design parameters for both the field and each well. The results show that using a shorter stage length (SSL) and a higher sand-to-water ratio (SWR) is preferable for this field, as it can increase cumulative gas production by up to 8%. Additionally, it is observed that fifty-percentile cumulative gas predictions are in close agreement with actual field productions. Thematic collection: This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at: https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows
{"title":"Simultaneous Well Spacing and Completion Optimization Using Automated Machine Learning Approach. A Case Study of Marcellus Shale Reservoir in the North-Eastern United States","authors":"E. Fathi, Ali Takbiri-Borujeni, F. Belyadi, M. F. Adenan","doi":"10.1144/petgeo2023-077","DOIUrl":"https://doi.org/10.1144/petgeo2023-077","url":null,"abstract":"Optimizing unconventional field development requires simultaneous optimization of well spacing and completion design. However, the conventional practice of using cross plots and sensitivity analysis via Monte Carlo simulations (MCS) for independent optimization of well spacing and completion design has proved inadequate for unconventional reservoirs. This is due to the inability of cross plots to capture non-linear cross-correlations between parameters affecting hydrocarbon production, and the computational expense and difficulty of Monte Carlo simulations. Recently, automated machine learning (AutoML) workflows have been used to tackle complex problems. However, applying AutoML workflows to engineering problems presents unique challenges, as achieving high accuracy in forecasting the physics of the problem is crucial. To address this issue, a new physics-informed AutoML workflow based on the TPOT open-source tool developed that guarantees the physical plausibility of the optimum model while minimizing human bias and uncertainty. The workflow has been implemented in a Marcellus Shale reservoir with over 1,500 wells to determine the optimal well spacing and completion design parameters for both the field and each well. The results show that using a shorter stage length (SSL) and a higher sand-to-water ratio (SWR) is preferable for this field, as it can increase cumulative gas production by up to 8%. Additionally, it is observed that fifty-percentile cumulative gas predictions are in close agreement with actual field productions.\u0000 \u0000 Thematic collection:\u0000 This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at:\u0000 https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2024-01-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139387097","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 evaluation of seal in conventional stratigraphic and structural traps requires the characterisation of the capillary top seal to assess the capacity to hold a hydrocarbon column. Typically, this seal analysis addresses the static seal and does not consider the role that hydrodynamics (the flow of water into or out of the shale seal) may play in influencing the seal capacity. Although possessing extremely low permeability, shale seals are not perfect seals and water can move through them under an imposed hydraulic gradient. Likewise, water can flow through trapped hydrocarbon columns even though relative permeabilities can be very low (Teige et al., 2005). The impact of this flow on the capillary seal capacity can, in theory, be quite profound and should be considered in seal analysis workflows. This paper revisits the Manzocchi & Childs (2013) model for hydrodynamic effects on capillary seals and employs it directly in real-world trap analysis. The implementation of this model is described, and a workflow developed to incorporate the impact of hydrodynamics into column height prediction. The technique is applied to several known over-pressured fields from the Norwegian continental shelf to evaluate its applicability. Preliminary results from Monte Carlo modelling are promising and appear to offer some agreement between the observed column heights and the predicted hydrodynamic seal-controlled columns, dependant on the parameterisation used. Further testing is ongoing, but the methodology should be considered for routine application, particularly in exploration prospect evaluation. The impact of hydrodynamics on seal capacities should not be discounted. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
{"title":"Assessing the impact of hydrodynamics on capillary seal capacity: application of the Manzocchi & Childs model in trap analysis workflows","authors":"Neil T. Grant","doi":"10.1144/petgeo2023-016","DOIUrl":"https://doi.org/10.1144/petgeo2023-016","url":null,"abstract":"The evaluation of seal in conventional stratigraphic and structural traps requires the characterisation of the capillary top seal to assess the capacity to hold a hydrocarbon column. Typically, this seal analysis addresses the static seal and does not consider the role that hydrodynamics (the flow of water into or out of the shale seal) may play in influencing the seal capacity. Although possessing extremely low permeability, shale seals are not perfect seals and water can move through them under an imposed hydraulic gradient. Likewise, water can flow through trapped hydrocarbon columns even though relative permeabilities can be very low (Teige et al., 2005). The impact of this flow on the capillary seal capacity can, in theory, be quite profound and should be considered in seal analysis workflows. This paper revisits the Manzocchi & Childs (2013) model for hydrodynamic effects on capillary seals and employs it directly in real-world trap analysis. The implementation of this model is described, and a workflow developed to incorporate the impact of hydrodynamics into column height prediction. The technique is applied to several known over-pressured fields from the Norwegian continental shelf to evaluate its applicability. Preliminary results from Monte Carlo modelling are promising and appear to offer some agreement between the observed column heights and the predicted hydrodynamic seal-controlled columns, dependant on the parameterisation used. Further testing is ongoing, but the methodology should be considered for routine application, particularly in exploration prospect evaluation. The impact of hydrodynamics on seal capacities should not be discounted. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139254457","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 3D subsurface structural model was built in a zone of the greater Bay du Nord Area, Flemish Pass Basin, offshore Newfoundland and Labrador, to carry out a post-drilled, fault-seal analysis in a multi-rift, geological complex setting; aiming to test fault-seal predictions, calibrate computed static fault zone attributes and estimate hydrocarbon contact depths. Hydrocarbon exploration campaigns in the greater Bay du Nord Area have primarily targeted rotated fault blocks, which often exhibit structural segmentation and compartmentalisation. A comprehensive approach that combines empirical and deterministic methods for static fault-seal analysis has been implemented. This approach provides insights into open, base, and tight fault-seal scenarios, aiding prospect evaluation in this region. Notably, Shale Gouge Ratios (SGRs) within the range of 16% to 25% serve as a crucial indicator of the transition between fault-rock sealing and non-sealing fault segments. Furthermore, it is emphasised the critical role of hydrodynamics when calibrating or evaluating fault sealing properties. In areas like the Greater Bay du Nord region, characterised by complex geology, it is imperative to regularly update fault-seal models. These updates should align with the availability of new subsurface data, comprehensive analyses, and an improved understanding of the petroleum system. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
{"title":"Fault-Seal Analysis in the Greater Bay du Nord Area, Flemish Pass Basin, Offshore Newfoundland","authors":"Asdrúbal Bernal","doi":"10.1144/petgeo2023-019","DOIUrl":"https://doi.org/10.1144/petgeo2023-019","url":null,"abstract":"A 3D subsurface structural model was built in a zone of the greater Bay du Nord Area, Flemish Pass Basin, offshore Newfoundland and Labrador, to carry out a post-drilled, fault-seal analysis in a multi-rift, geological complex setting; aiming to test fault-seal predictions, calibrate computed static fault zone attributes and estimate hydrocarbon contact depths. Hydrocarbon exploration campaigns in the greater Bay du Nord Area have primarily targeted rotated fault blocks, which often exhibit structural segmentation and compartmentalisation. A comprehensive approach that combines empirical and deterministic methods for static fault-seal analysis has been implemented. This approach provides insights into open, base, and tight fault-seal scenarios, aiding prospect evaluation in this region. Notably, Shale Gouge Ratios (SGRs) within the range of 16% to 25% serve as a crucial indicator of the transition between fault-rock sealing and non-sealing fault segments. Furthermore, it is emphasised the critical role of hydrodynamics when calibrating or evaluating fault sealing properties. In areas like the Greater Bay du Nord region, characterised by complex geology, it is imperative to regularly update fault-seal models. These updates should align with the availability of new subsurface data, comprehensive analyses, and an improved understanding of the petroleum system. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-11-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139257709","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}
B. Khadem, Mohammad Reza Saberi, Michel Krief, Hossein Rezaei Abbasi
Although pore geometry plays an important role in carbonates rock physics modeling, few studies have been done on its analytic relationship with other pore space properties like pore space stiffness. We propose an analytical workflow based on the differential effective medium (DEM) to estimate the elastic properties of carbonate rocks. Then, the validity of our results is cross-checked with the Xu and Payne model on a real carbonate dataset. This workflow establishes a direct and quantitative link between the pore geometry of carbonate rock with its other pore space properties such as Biot's coefficient and pore space stiffness. This relationship can be, furthermore, utilized in defining rock physics templates (RPTs) to investigate the role of pore geometry on the rock elastic properties. Furthermore, we extended the Biot-Gassmann-Krief (BGK) model through our proposed workflow by establishing a theoretical framework to relate the main components of the BGK model to the pore geometry usually estimated in the laboratory or empirically. This can help to investigate the impact of fluid substitution on each of these main components. Our investigation suggests that the higher the Biot and Gassmann coefficients, the rock is more sensitive to fluid substitution. Moreover, this analytical workflow has been employed to examine the role of selecting different rotational spheroids (i.e., oblate and prolate) on the modeled velocities. Our results show that the modeled velocities depend on this selection in a way that prolate pores are less sensitive to the variations in their pore aspect ratio compared with the oblate pores.
{"title":"Investigating the analytical relationship between pore geometry and other pore space properties in carbonate rocks","authors":"B. Khadem, Mohammad Reza Saberi, Michel Krief, Hossein Rezaei Abbasi","doi":"10.1144/petgeo2023-028","DOIUrl":"https://doi.org/10.1144/petgeo2023-028","url":null,"abstract":"Although pore geometry plays an important role in carbonates rock physics modeling, few studies have been done on its analytic relationship with other pore space properties like pore space stiffness. We propose an analytical workflow based on the differential effective medium (DEM) to estimate the elastic properties of carbonate rocks. Then, the validity of our results is cross-checked with the Xu and Payne model on a real carbonate dataset. This workflow establishes a direct and quantitative link between the pore geometry of carbonate rock with its other pore space properties such as Biot's coefficient and pore space stiffness. This relationship can be, furthermore, utilized in defining rock physics templates (RPTs) to investigate the role of pore geometry on the rock elastic properties. Furthermore, we extended the Biot-Gassmann-Krief (BGK) model through our proposed workflow by establishing a theoretical framework to relate the main components of the BGK model to the pore geometry usually estimated in the laboratory or empirically. This can help to investigate the impact of fluid substitution on each of these main components. Our investigation suggests that the higher the Biot and Gassmann coefficients, the rock is more sensitive to fluid substitution. Moreover, this analytical workflow has been employed to examine the role of selecting different rotational spheroids (i.e., oblate and prolate) on the modeled velocities. Our results show that the modeled velocities depend on this selection in a way that prolate pores are less sensitive to the variations in their pore aspect ratio compared with the oblate pores.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-11-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139258009","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}
N.J. Mark, N. Schofield, D.A. Watson, S. Holford, S. Pugliese, D. Muirhead
Pervasive igneous intrusive complexes have been identified in many sedimentary basins which are prospective for petroleum exploration and production. Seismic reflection and well data from these basins has characterised many of these igneous intrusions as forming networks of interconnected sills and dykes, with distinctive morphologies and typically cross-cutting sedimentary host rocks. Intrusions have also been identified in close proximity to many oil & gas fields and exploration targets (e.g. Laggan-Tormore fields, Faroe Shetland Basin). It is therefore important to understand how igneous intrusions interact with sedimentary host rocks, specifically reservoir and source rock intervals, to determine the geological risk for petroleum exploration and production. The risks for petroleum exploration include low porosity and permeability within reservoirs, and overmaturity of source rocks, which are intruded. Additionally, reservoirs may be compartmentalised by low permeability igneous intrusions, inhibiting lateral and vertical migration of fluids. Based on a range of field studies and subsurface data, we demonstrate that sandstone porosity can be reduced by up to 20% (relative to background porosity) and the thermal maturity of organic rich claystones can be increased. The extent of host rock alteration away from igneous intrusions is highly variable and is commonly accompanied by mechanical compaction and fracturing of the host rock within the initial 10 to 20 cm of altered host rock. Reservoir quality and source rock maturity are key elements of the petroleum system and detrimental alteration of these intervals by igneous intrusions increases geological risk and should therefore be incorporated into any risk assessment of an exploration prospect or field development. Thematic collection: This article is part of the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin
{"title":"The Impact of Igneous Intrusions on Sedimentary Host Rocks: Insights from Field Outcrop and Subsurface Data","authors":"N.J. Mark, N. Schofield, D.A. Watson, S. Holford, S. Pugliese, D. Muirhead","doi":"10.1144/petgeo2022-086","DOIUrl":"https://doi.org/10.1144/petgeo2022-086","url":null,"abstract":"Pervasive igneous intrusive complexes have been identified in many sedimentary basins which are prospective for petroleum exploration and production. Seismic reflection and well data from these basins has characterised many of these igneous intrusions as forming networks of interconnected sills and dykes, with distinctive morphologies and typically cross-cutting sedimentary host rocks. Intrusions have also been identified in close proximity to many oil & gas fields and exploration targets (e.g. Laggan-Tormore fields, Faroe Shetland Basin). It is therefore important to understand how igneous intrusions interact with sedimentary host rocks, specifically reservoir and source rock intervals, to determine the geological risk for petroleum exploration and production. The risks for petroleum exploration include low porosity and permeability within reservoirs, and overmaturity of source rocks, which are intruded. Additionally, reservoirs may be compartmentalised by low permeability igneous intrusions, inhibiting lateral and vertical migration of fluids. Based on a range of field studies and subsurface data, we demonstrate that sandstone porosity can be reduced by up to 20% (relative to background porosity) and the thermal maturity of organic rich claystones can be increased. The extent of host rock alteration away from igneous intrusions is highly variable and is commonly accompanied by mechanical compaction and fracturing of the host rock within the initial 10 to 20 cm of altered host rock. Reservoir quality and source rock maturity are key elements of the petroleum system and detrimental alteration of these intervals by igneous intrusions increases geological risk and should therefore be incorporated into any risk assessment of an exploration prospect or field development. Thematic collection: This article is part of the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-11-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135634334","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}
Ruaridh Y. Smith, Pierre-Olivier Bruna, Ahmed Nasri, Giovanni Bertotti
Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences these networks have. Our study focusses on the Southern Chotts-Jeffara basin which hosts reservoirs within the Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proven a regional shortening phase occurring between the Permian and Jurassic forming open folds and a distributed fracture network. Analysis of late Palaeozoic and Mesozoic outcrops within the basin identify several sets of fractures (150/80; 212/86) and compressional structural features which support this shortening hypothesis. We integrate fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we find that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provides an insight in network characterisation within naturally fractured reservoirs of Tunisia and how certain structures form fluid pathways influence flow and production. Supplementary material: https://doi.org/10.6084/m9.figshare.c.6904499
{"title":"Fracture distribution along open folds in Southern Tunisia: Implications for naturally fractured reservoirs","authors":"Ruaridh Y. Smith, Pierre-Olivier Bruna, Ahmed Nasri, Giovanni Bertotti","doi":"10.1144/petgeo2023-039","DOIUrl":"https://doi.org/10.1144/petgeo2023-039","url":null,"abstract":"Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences these networks have. Our study focusses on the Southern Chotts-Jeffara basin which hosts reservoirs within the Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proven a regional shortening phase occurring between the Permian and Jurassic forming open folds and a distributed fracture network. Analysis of late Palaeozoic and Mesozoic outcrops within the basin identify several sets of fractures (150/80; 212/86) and compressional structural features which support this shortening hypothesis. We integrate fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we find that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provides an insight in network characterisation within naturally fractured reservoirs of Tunisia and how certain structures form fluid pathways influence flow and production. Supplementary material: https://doi.org/10.6084/m9.figshare.c.6904499","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-11-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135636997","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}
Pedro Benac, Desiree Liechoscki de Paula Faria, Alexandre Maul, Cleverson Guizan
Forward modelling of sedimentary systems is a method that simulates sedimentation processes over geological time to generate a set of facies distributed in a depositional space. The objective of using forward modelling in this work was to build a 3D facies model from which a synthetic seismic simulation was generated, and then to analyse the relation of seismic-stratigraphic interpretations with the knowledge of the a priori generated sedimentological model. This modelling methodology was applied in a pre-salt field in the Santos Basin, Brazilian offshore, focused on the Barra Velha Formation. The modelling parameters used were: (i) the initial surface of bathymetric depth; (ii) the lake-level variation; (iii) the subsidence map; and (iv) the deposition rates of the facies. Average-constant of acoustic impedance values were assigned to each facies and a synthetic seismic was obtained. With the facies and synthetic models available, it was possible to analyse: (i) the distribution of thicknesses and proportion of facies by region; (ii) the vertical stacking pattern and lateral facies variation; (iii) the Wheeler distance × time diagram; and (iv) the seismic reflector patterns through the seismic facies classification. Through these analyses it was possible to better understand the possibilities and limitations of seismic stratigraphy as an interpretation auxiliary tool in pre-salt carbonate environments.
{"title":"Synthetic seismic stratigraphic interpretation from a sedimentological forward model in a pre-salt field of the Santos Basin","authors":"Pedro Benac, Desiree Liechoscki de Paula Faria, Alexandre Maul, Cleverson Guizan","doi":"10.1144/petgeo2023-069","DOIUrl":"https://doi.org/10.1144/petgeo2023-069","url":null,"abstract":"Forward modelling of sedimentary systems is a method that simulates sedimentation processes over geological time to generate a set of facies distributed in a depositional space. The objective of using forward modelling in this work was to build a 3D facies model from which a synthetic seismic simulation was generated, and then to analyse the relation of seismic-stratigraphic interpretations with the knowledge of the a priori generated sedimentological model. This modelling methodology was applied in a pre-salt field in the Santos Basin, Brazilian offshore, focused on the Barra Velha Formation. The modelling parameters used were: (i) the initial surface of bathymetric depth; (ii) the lake-level variation; (iii) the subsidence map; and (iv) the deposition rates of the facies. Average-constant of acoustic impedance values were assigned to each facies and a synthetic seismic was obtained. With the facies and synthetic models available, it was possible to analyse: (i) the distribution of thicknesses and proportion of facies by region; (ii) the vertical stacking pattern and lateral facies variation; (iii) the Wheeler distance × time diagram; and (iv) the seismic reflector patterns through the seismic facies classification. Through these analyses it was possible to better understand the possibilities and limitations of seismic stratigraphy as an interpretation auxiliary tool in pre-salt carbonate environments.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135667263","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}
This research focuses on how ‘static’ properties of fracture networks can be studied by considering ‘dynamic’ flow simulation, while static properties such as clustering, connectivity, variation in aperture and, of course, anisotropy of fracture networks can be quantified using different geostatistical/data analysis techniques. The flow responses through such networks can be simulated to check if flow simulation can be used as a tool for evaluating its geometry. In order to achieve this, outcrop analogues of fractured reservoirs are converted into permeability structured grids implementing the fracture continuum (FC) concept. These FC models are flow simulated in a streamline simulator, TRACE3D. Results of the first experiment show that rather than the ‘fractal dimension’, the ‘lacunarity parameter’, which quantifies scale-dependent clustering of fractures, is a unique identifier of network geometry and acts as a proxy for fracture connectivity and an indicator of flow behaviour. The FC model further accommodates variability in fracture apertures and, thus, in a second experiment a set of models with a hierarchical aperture distribution was built and tested for their time-of-flight (TOF) and recovery curves, which showed that smaller fractures with narrow apertures do not significantly contribute to flow. In a third experiment considering anisotropy, it was observed that tightly clustered fractures along preferential directions can be identified from anisotropy in flow patterns. The results from these three experiments show that flow patterns in fracture networks can indicate the overall scale-dependent clustering, the anisotropy that arises from such clustering and that narrower fractures do not significantly alter the overall flow behaviour. Thematic collection: This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at: https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows
{"title":"Characterizing Fractured Reservoirs by Integrating Outcrop Analog Studies with Flow Simulations","authors":"Ajay K. Sahu, Ankur Roy","doi":"10.1144/petgeo2023-032","DOIUrl":"https://doi.org/10.1144/petgeo2023-032","url":null,"abstract":"This research focuses on how ‘static’ properties of fracture networks can be studied by considering ‘dynamic’ flow simulation, while static properties such as clustering, connectivity, variation in aperture and, of course, anisotropy of fracture networks can be quantified using different geostatistical/data analysis techniques. The flow responses through such networks can be simulated to check if flow simulation can be used as a tool for evaluating its geometry. In order to achieve this, outcrop analogues of fractured reservoirs are converted into permeability structured grids implementing the fracture continuum (FC) concept. These FC models are flow simulated in a streamline simulator, TRACE3D. Results of the first experiment show that rather than the ‘fractal dimension’, the ‘lacunarity parameter’, which quantifies scale-dependent clustering of fractures, is a unique identifier of network geometry and acts as a proxy for fracture connectivity and an indicator of flow behaviour. The FC model further accommodates variability in fracture apertures and, thus, in a second experiment a set of models with a hierarchical aperture distribution was built and tested for their time-of-flight (TOF) and recovery curves, which showed that smaller fractures with narrow apertures do not significantly contribute to flow. In a third experiment considering anisotropy, it was observed that tightly clustered fractures along preferential directions can be identified from anisotropy in flow patterns. The results from these three experiments show that flow patterns in fracture networks can indicate the overall scale-dependent clustering, the anisotropy that arises from such clustering and that narrower fractures do not significantly alter the overall flow behaviour. Thematic collection: This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at: https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135824024","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}
J.D. Fairhead, D. Marsden, N.M. Azli, I. Özsöz, D. Maxwell, O. Rose, C.M. Green
Extensive geophysical databases, covering the UK sector of the North Sea, have been used to gravity layer strip the sedimentary layers down to the base Zechstein so that the gravity response of the Carboniferous and deeper strata can be identified and structurally interpreted. To achieve this, the average bulk density grids for each layer were derived using Gardner's functions derived from well velocity and density logs. The resulting residual gravity response of each layer and the Moho response were then removed from the Free air gravity anomaly to generate the isostatic gravity response of the crust below the base Zechstein. This gravity response was used to re-evaluate the British Geological Survey (BGS) interpretation over the Mid North Sea High (MNSH) and was able to identify the same crustal structures. Using the Tilt derivative method, a positive gravity anomaly was found to parallel the Central Fracture Zone that forms a northern extension of the Dowsing fault zone. This anomaly can be traced north across the MNSH with offsets coinciding with the WSW-ENE basement lineaments. To the south, the southern North Sea basin is well defined by the stratigraphic layer depth and thickness maps as well as the residual gravity maps which identify the structures associated with the low-density Carboniferous Coal Measures.
{"title":"Gravity imaging of sub-Zechstein geological structures in the UK sector of the North Sea using the gravity layer stripping method","authors":"J.D. Fairhead, D. Marsden, N.M. Azli, I. Özsöz, D. Maxwell, O. Rose, C.M. Green","doi":"10.1144/petgeo2023-009","DOIUrl":"https://doi.org/10.1144/petgeo2023-009","url":null,"abstract":"Extensive geophysical databases, covering the UK sector of the North Sea, have been used to gravity layer strip the sedimentary layers down to the base Zechstein so that the gravity response of the Carboniferous and deeper strata can be identified and structurally interpreted. To achieve this, the average bulk density grids for each layer were derived using Gardner's functions derived from well velocity and density logs. The resulting residual gravity response of each layer and the Moho response were then removed from the Free air gravity anomaly to generate the isostatic gravity response of the crust below the base Zechstein. This gravity response was used to re-evaluate the British Geological Survey (BGS) interpretation over the Mid North Sea High (MNSH) and was able to identify the same crustal structures. Using the Tilt derivative method, a positive gravity anomaly was found to parallel the Central Fracture Zone that forms a northern extension of the Dowsing fault zone. This anomaly can be traced north across the MNSH with offsets coinciding with the WSW-ENE basement lineaments. To the south, the southern North Sea basin is well defined by the stratigraphic layer depth and thickness maps as well as the residual gravity maps which identify the structures associated with the low-density Carboniferous Coal Measures.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135015598","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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